(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 and Regency constituteconstitutes substantial portions of the collateral for the Parent Company’s outstanding senior notes; accordingly, financial statements of ETP and Regency 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 ETE Common Holdings, LLC, ETE GP Acquirer LLC, and Regency GP LP (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, Regency and/or the consolidated subsidiaries of ETP and Regency.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 and Regency.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: | March 2, 2015February 23, 2018 | By: | | /s/ Jamie WelchThomas E. Long | | | | | Jamie WelchThomas 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 | | March 2, 2015February 23, 2018 | John W. McReynolds | | (Principal Executive Officer) | | | | | | | | /s/ Jamie WelchThomas E. Long | | Director and Group Chief Financial Officer and Head of Business Development (Principal Financial and Accounting Officer) | | March 2, 2015February 23, 2018 | Jamie WelchThomas E. Long | | | | | | | | | /s/ Kelcy L. Warren | | Director and Chairman of the Board | | March 2, 2015February 23, 2018 | Kelcy L. Warren | | | | | | | | | | /s/ Richard D. Brannon | | Director | | February 23, 2018 | Richard D. Brannon | | | | | | | | | | /s/ Marshall S. McCrea, III | | Director | | March 2, 2015February 23, 2018 | Marshall S. McCrea, III | | | | | | | | | | /s/ Matthew S. Ramsey | | Director | | March 2, 2015February 23, 2018 | Matthew S. Ramsey | | | | | | | | | | /s/ K. Rick Turner | | Director | | March 2, 2015February 23, 2018 | K. Rick Turner | | | | | | | | | | /s/ William P. Williams | | Director | | March 2, 2015February 23, 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
| | | 2.1 | | General Partner Purchase Agreement, dated May 10, 2010, by and among Regency GP Acquirer, L.P., Energy Transfer Equity, L.P. and ETE GP Acquirer LLC (incorporated by reference to Exhibit 2.1 of Form 8-K/A, file No. 1-32740, filed May 13, 2010) | 2.2 | | Contribution Agreement, dated May 10, 2010, by and among Energy Transfer Equity, L.P., Regency Energy Partners LP and Regency Midcontinent Express LLC (incorporated by reference to Exhibit 2.3 of Form 8-K/A, file No. 1-32740, filed May 13, 2010) | 2.3 | | Agreement and Plan of Merger by and among Energy Transfer Equity, L.P., Sigma Acquisition Corporation and Southern Union Company, dated as of June 15, 2011, as Amended and Restated as of July 4, 2011 and July 19, 2011 (incorporated by reference to Exhibit 2.1 of Form 8-K, file No. 1-32740, filed July 5, 2011) | 2.3.1 | | Amendment No. 1, dated as of September 14, 2011, to Second Amended and Restated Agreement and Plan of Merger, dated as of July 19, 2011, by and among Energy Transfer Equity, L.P., Sigma Acquisition Corporation and Southern Union Company (incorporated by reference to Exhibit 2.1 of Form 8-K, file No. 1-32740, filed September 15, 2011) | 2.4 | | Support Agreement dated June 15, 2011 by and among Energy Transfer Equity, L.P., Sigma Acquisition Corporation, and certain stockholders of Southern Union Company (incorporated by reference to Exhibit 10.1 of Form 8-K, file No. 1-32740, filed July 5, 2011) | 2.5 | | Amended and Restated Agreement and Plan of Merger by and among Energy Transfer Partners, L.P., Citrus ETP Acquisition, L.L.C., Energy Transfer Equity, L.P., Southern Union Company, and CrossCountry Energy, LLC, dated as of July 19, 2011 (incorporated by reference to Exhibit 2.2 of Form 8-K, file No. 1-32740, filed July 20, 2011) | 2.5.1 | | Amendment No. 1, dated as of September 14, 2011, to Amended and Restated Agreement and Plan of Merger, dated as of July 19, 2011, by and between Energy Transfer Partners, L.P. and Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.2 of Form 8-K, file No. 1-32740, filed September 15, 2011) | 2.5.2 | | Amendment No. 2, dated as of March 23, 2012, to Amended and Restated Agreement and Plan of Merger by and among Energy Transfer Equity, L.P., Energy Transfer Partners, L.P., Citrus ETP Acquisition, L.L.C, Southern Union Company, and CrossCountry Energy, LLC, dated as of July 19, 2011 (incorporated by reference to Exhibit 2.1 of Form 8-K, file No. 1-32740, filed March 28, 2012) | 2.6 | | Agreement and Plan of Merger, dated as of April 29, 2012 by and among Energy Transfer Partners, L.P., Sam Acquisition Corporation, Energy Transfer Partners GP, L.P., Sunoco, Inc. 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. 1-32740, filed May 1, 2012) | 2.6.1 | | Amendment No. 1, dated as of June 15, 2012, to the Agreement and Plan of Merger, dated as of April 29, 2012, by and among Energy Transfer Partners, L.P., Sam Acquisition Corporation, Energy Transfer Partners GP, L.P., Sunoco, Inc., and, for certain limited purposes set forth therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.2 of Form 8-K, file No. 1-32740, filed June 20, 2012) | 2.7 | | Transaction Agreement, dated as of June 15, 2012, by and among Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., Heritage Holdings, Inc., Energy Transfer Equity, L.P., ETE Sigma Holdco, LLC and ETE Holdco Corporation (incorporated by reference to Exhibit 2.1 of Form 8-K, file No. 1-32740, filed June 20, 2012) | 2.8 | | 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) | 3.1 | | Certificate of Conversion of Energy Transfer Company, L.P. (incorporated by reference to Exhibit 3.1 of Form S-1, file No. 333-128097, filed September 2, 2005) | 3.2 | | 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) | 3.3 | | Third Amended Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 3.1 of Form 8-K, file No. 1-32740, filed February 14, 2006) | 3.3.1 | | Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 3.3.1 of Form 10-K, file No. 1-32740, filed November 29, 2006) | 3.3.2 | | Amendment No. 2 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 3.3.2 of Form 8-K, file No. 1-32740, filed November 13, 2007) | 3.3.3 | | Amendment No. 3 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 3.1 of Form 8-K, file No. 1-32740, filed June 2, 2010) |
| | | | Exhibit
Number
| | | 3.4 | | Certificate of Conversion of LE GP, LLC (incorporated by reference to Exhibit 3.4 of Form S-1, file No. 333-128097, filed September 2, 2005) | 3.5 | | Certificate of Formation of LE GP, LLC (incorporated by reference to Exhibit 3.5 of Form S-1, file No. 333-128097, filed September 2, 2005) | 3.6 | | Amended and Restated Limited Liability Company Agreement of LE GP, LLC (incorporated by reference to Exhibit 3.6.1 of Form 8-K, file No. 1-32740, filed May 8, 2007) | 3.6.1 | | Amendment No. 1 to Amended and Restated Limited Liability Company Agreement of LE GP, LLC (incorporated by reference to Exhibit 3.1 of Form 8-K, file No. 1-32740, filed December 23, 2009) | 3.7 | | Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P. (formerly named Heritage Propane Partners, L.P.) (incorporated by reference to Exhibit 3.1 of Form 8-K, file No. 1-11727, filed July 28, 2009) | 3.8 | | 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) | 3.9 | | Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners GP, L.P. (incorporated by reference to Exhibit 3.5 of Form 10-Q, file No. 1-11727, filed July 10, 2007) | 3.10 | | Fourth Amended and Restated Limited Liability Company Agreement of Energy Transfer Partners, L.L.C. (incorporated by reference to Exhibit 3.6 of Form 8-K, file No. 1-11727, filed August 10, 2010) | 3.11 | | Certificate of Formation of Energy Transfer Partners, L.L.C. (incorporated by reference to Exhibit 3.13 of Form S-1/A, file No. 333-128097, filed December 20, 2005) | 3.11.1 | | Certificate of Amendment of Energy Transfer Partners, L.L.C. (incorporated by reference to Exhibit 3.13.1 of Form S-1/A, file No. 333-128097, filed December 20, 2005) | 3.12 | | Restated Certificate of Limited Partnership of Energy Transfer Partners GP, L.P. (incorporated by reference to Exhibit 3.14 of Form S-1/A, file No. 333-128097, filed December 20, 2005) | 3.13 | | Second Amendment to Amended and Restated Limited Liability Company Agreement of Regency GP, L.L.C. (incorporated by reference to Exhibit 3.2 of Form 8-K, file No. 1-32740, filed August 10, 2010) | 3.7.1 | | Amendment No. 1, dated March 26, 2012, to the Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated July 28, 2009 (incorporated by reference to Exhibit 3.1 of Form 8-K, file No. 1-32740, filed March 28, 2012) | 3.9.1 | | Amendment No. 2, dated March 26, 2012, to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners GP, L.P., dated April 17, 2007 (incorporated by reference to Exhibit 3.2 of Form 8-K, file No. 1-32740, filed March 28, 2012) | 3.10.1 | | Amendment No. 1, dated March 26, 2012, to the Fourth Amended and Restated Agreement of Limited Liability Company Agreement of Energy Transfer Partners, L.L.C., dated August 10, 2010 (incorporated by reference to Exhibit 3.3 of Form 8-K, file No. 1-32740, filed March 28, 2012) | 3.7.2 | | Amendment No. 4, dated April 30, 2013, to the Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., as amended (incorporated by reference to Exhibit 3.1 of Form 8-K, file No. 1-32740, filed May 1, 2013) | 4.1 | | 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) | 4.2 | | 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) | 4.3 | | Second Supplemental Indenture dated as of February 24, 2005 to Indenture dated as of January 18, 2005 (incorporated by reference to Exhibit 10.45 of Form 10-Q, file No. 1-11727, filed April 11, 2005) | 4.4 | | Notation of Guarantee (incorporated by reference to Exhibit 10.46 of Form 10-Q, file No. 1-11727, filed April 11, 2005) | 4.5 | | Registration Rights Agreement dated January 18, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and the initial purchasers party thereto (incorporated by reference to Exhibit 4.3 of Form 8-K, file No. 1-11727, filed January 19, 2005) | 4.6 | | Joinder to Registration Rights Agreement dated February 24, 2005, among Energy Transfer Partners, L.P., the Subsidiary Guarantors and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 10.39.1 of Form 10-Q, file No. 1-11727, filed April 11, 2005) | 4.7 | | Third Supplemental Indenture dated July 29, 2005, to 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 August 2, 2005) |
| | | | Exhibit
Number
| | | 4.8 | | Registration Rights Agreement dated July 29, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors named therein, and the initial purchasers party thereto (incorporated by reference to Exhibit 4.2 of Form 8-K, file No. 1-11727, filed August 2, 2005) | 4.9 | | Form of Senior Indenture of Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 4.9 of Form S-3, file No. 333-136429, filed August 9, 2006) | 4.10 | | Form of Subordinated Indenture of Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 4.10 of Form S-3, file No. 333-136429, filed August 9, 2006) | 4.11 | | Fourth Supplemental Indenture dated as of June 29, 2006 to 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 4.13 of Form 10-K, file No. 1-11727, filed November 13, 2006) | 4.12 | | Fifth Supplemental Indenture dated as of October 23, 2006 to 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 October 25, 2006) | 4.13 | | Sixth Supplemental Indenture dated March 28, 2008, by and between Energy Transfer Partners, L.P., as issuer, 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) | 4.14 | | Seventh Supplemental Indenture dated December 23, 2008, by and between Energy Transfer Partners, L.P., as issuer, 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) | 4.15 | | Eighth Supplemental Indenture dated April 7, 2009, by and between Energy Transfer Partners, L.P., as issuer, 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) | 4.16 | | Energy Transfer Partners, L.P. 2008 Long-Term Incentive Plan (incorporated by reference to Exhibit A of Form DEF 14A, file No. 1-11727, filed November 21, 2008) | 4.17 | | Registration Rights Agreement by and among Energy Transfer Equity, L.P. and Regency GP Acquirer, L.P., dated as of May 26, 2010 (incorporated by reference to Exhibit 4.14 of Form 8-K, file No. 1-32740, filed June 2, 2010) | 4.18 | | 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) | 4.19 | | 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) | 4.20 | | Second Supplemental Indenture dated as of February 16, 2012, between Energy Transfer Equity, L.P., and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 of Form 8-K, file No. 1-32740, filed February 17, 2012) | 4.21 | | Third Supplemental Indenture dated April 24, 2012 to Indenture dated September 20, 2010 between Energy Transfer Equity, L.P. and US Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 of Form 10-Q, file No. 1-32740, filed August 8, 2012) | 4.22 | | Registration Rights Agreement, dated April 30, 2013, by and between Energy Transfer Partners, L.P. and Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 4.1 of Form 8-K, file No. 1-32740, filed May 1, 2013) | 4.23 | | 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) | 4.24 | | Fifth Supplemental Indenture dated May 28, 2014 (incorporated by reference to Exhibit 4.2 of Form 8-K, file No. 1-32470, filed May 28, 2014) | 4.25 | | Sixth Supplemental Indenture dated May 28, 2014 (incorporated by reference to Exhibit 4.3 of Form 8-K, file No. 1-32470, filed May 28, 2014) | 10.1 | | Purchase and Sale Agreement dated January 26, 2005, among HPL Storage, LP and AEP Energy Services Gas Holding Company II, L.L.C., as Sellers, and LaGrange Acquisition, L.P., as Buyer (incorporated by reference to Exhibit 10.1 of Form 8-K, file No. 1-11727, filed February 1, 2005) | 10.2 | | 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) |
| | | | Exhibit
Number
| | | 10.3.1 | + | 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) | 10.3.2 | + | Energy Transfer Partners, L.P. Second Amended and Restated 2008 Long Term Incentive Plan (incorporated by reference to Exhibit 10.1 of Form 10-K, file No. 1-11727, filed February 26, 2015) | 10.3.3 | + | 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) | 10.3.4 | + | 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) | 10.3.5 | + | 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) | 10.4 | | Registration Rights Agreement for Limited Partner Interests of Heritage Propane Partners, L.P. (incorporated by reference to Exhibit 4.1 of Form 8-K, file No. 1-11727, filed February 13, 2002) | 10.5 | | Unitholder Rights Agreement dated January 20, 2004, among Heritage Propane Partners, L.P., Heritage Holdings, Inc., TAAP LP and LaGrange Energy, L.P. (incorporated by reference to Exhibit 4.2 of Form 10-Q, file No. 1-11727, filed April 14, 2004) | 10.6 | | Registration Rights Agreement for Limited Partnership Units of LaGrange Energy, L.P. (incorporated by reference to Exhibit 10.47 of Form S-1, file No. 333-128097, filed October 13, 2005) | 10.7 | + | 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) | 10.8 | + | 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) | 10.9 | | 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) | 10.10 | | Contribution and Conveyance Agreement, dated November 1, 2006, between Energy Transfer Equity, L.P., and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 10.35 of Form 10-K, file No. 1-32740, filed November 29, 2006) | 10.11 | | Contribution, Assumption and Conveyance Agreement, dated November 1, 2006, between Energy Transfer Equity, L.P., and Energy Transfer Investments, L.P. (incorporated by reference to Exhibit 10.36 of Form 10-K, file No. 1-32740, filed November 29, 2006) | 10.12 | | Registration Rights Agreement, dated November 1, 2006, between Energy Transfer Partners, L.P. and Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 3.1.10 of Form 8-K, file No. 1-11727, filed November 3, 2006) | 10.13 | | 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) | 10.14 | | Purchase and Sale Agreement, dated as of September 14, 2006, among Energy Transfer Partners, L.P. and EFS-PA, LLC (a/k/a GE Energy Financial Services), CDPQ Investments (U.S.) Inc., Lake Bluff, Inc., Merrill Lynch Ventures, L.P. and Kings Road Holding I LLC (incorporated by reference to Exhibit 10.1 of Form 8-K, file No. 1-11727, filed September 18, 2006) | 10.15 | | 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) | 10.16 | | 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) | 10.17 | | 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) | 10.18 | + | 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) | 10.19 | | 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) |
| | | | Exhibit
Number
| | | 10.20 | | 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) | 10.21 | | 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 July 10, 2007) | 10.21.1 | | 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 July 10, 2007) | 10.22 | | 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 10.56 of Form 10-Q, file No. 1-11727, filed July 10, 2007) | 10.23 | | Second Amended and Restated Support Agreement, dated as of July 19, 2011, by and among, Energy Transfer Equity, L.P., Sigma Acquisition Corporation and certain stockholders of Southern Union Company (incorporated by reference to Exhibit 10.1 of Form 8-K, file No. 1-32740, filed July 20, 2011) | 10.24 | | 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. 1-32740, filed March 28, 2012) | 10.25 | | 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. 1-32740, filed March 28, 2012) | 10.26 | | 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) | 10.27 | | Purchase and Sale Agreement dated as of December 14, 2012 among Southern Union Company, Plaza Missouri Acquisition, Inc. and for certain limited purposes The Laclede Group, Inc. (incorporated by reference to Exhibit 10.1 of Form 8-K, file No. 1-32740, filed December 17, 2012) | 10.28 | | Purchase and Sale Agreement dated as of December 14, 2012 among Southern Union Company, Plaza Massachusetts Acquisition, Inc. and for certain limited purposes The Laclede Group, Inc. (incorporated by reference to Exhibit 10.2 of Form 8-K, file No. 1-32740, filed December 17, 2012) | 10.29 | | 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) | 10.30 | | 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) | 10.31 | | 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) | 10.32 | | 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) | 10.33 | | Senior Secured Term Loan 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 10.2 of Form 8-K, file No. 1-32740, filed December 2, 2013) | 10.34 | | 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) | 10.35 | | Class D Unit Agreement (incorporated by reference to Exhibit 10.1 of Form 8-K, file No. 1-32740, filed December 27, 2013) | 10.36 | | 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) | 10.37 | | Common Unit Purchase Agreement, dated June 4, 2014 (incorporated by reference to Exhibit 10.1 of Form 8-K, file No. 1-32740, filed June 5, 2014) | 10.38 | | Registration Rights Agreement, dated June 4, 2014 (incorporated by reference to Exhibit 10.2 of Form 8-K, file No. 1-32740, filed June 5, 2014) |
| | | | Exhibit
Number
| | | 10.39 | + | 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) | 10.40 | | 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) | 10.41 | | Energy Transfer Equity, L.P. 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) | 10.42 | | 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. 1-32470, filed December 29, 2014) | 10.43 | | Amendment and Incremental Commitment Agreement No. 3 dated as of 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) | 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 to Grant Thornton LLP related to Energy Transfer Partners, L.P. | 23.3* | | Consent of Grant Thornton LLP related to Regency Energy Partners LP. | 23.4* | | Consent of Grant Thornton LLP related to RIGS Haynesville Partnership Co. | 23.5* | | Consent of Ernst & Young LLP related to Sunoco Logistics Partners L.P. | 23.6* | | Consent of Ernst & Young LLP related to Susser Holdings Corporation. | 23.7* | | Consent of Ernst & Young LLP related to Sunoco LP. | 23.8* | | Consent of PricewaterhouseCoopers LLP related to Midcontinent Express Pipeline LLC. | 23.9* | | Consent of KMPG LLP related to the Midstream Assets of Eagle Rock Energy 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* | | Report of Independent Registered Public Accounting Firm — Ernst & Young LLP opinion on consolidated financial statements of Sunoco Logistics Partners LP. | 99.2* | | Report of Independent Registered Public Accounting Firm — Ernst & Young LLP opinion on consolidated financial statements of Susser Holdings Corporation. | 99.3* | | Report of Independent Registered Public Accounting Firm — Ernst & Young LLP opinion on consolidated financial statements of Sunoco LP. | 99.4 | | Audited financial statements of RIGS Haynesville Partnership Co. as of December 31, 2014 and 2013 and for the years ended December 31, 2014, 2013 and 2012 (incorporated by reference to Exhibit 99.2 of Regency Energy Partners LP Form 10-K, File No 1-35262, filed February 27, 2015) | 99.5 | | Audited financial statements of Midcontinent Express Pipeline LLC as of December 31, 2014 and 2013 and for the years ended December 31, 2014, 2013 and 2012 (incorporated by reference to Exhibit 99.3 of Regency Energy Partners LP Form 10-K, File No. 1-35262, filed February 27, 2015) | 99.6 | | Audited financial statements of the Midstream Assets of Eagle Rock Energy Partners, L.P. as of December 31, 2013 and December 21, 2012 and for the three years ended December 31, 2013 (incorporated by reference to Exhibit 99.5 of Regency Energy Partners LP Form 10-K, File No. 1-35262, filed February 26, 2015) | 99.7 | | 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, 2014 and December 31, 2013; (ii) our Consolidated Statements of Operations for the years ended December 31, 2014, 2013 and 2012; (iii) our Consolidated Statements of Comprehensive Income for years ended December 31, 2014, 2013 and 2012; (iv) our Consolidated Statement of Equity for the years ended December 31, 2014, 2013 and 2012; and (v) our Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012. |
| | | * | 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. Opinion 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, 20142017 and 2013, 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, 2014. These financial statements are2017, and the responsibility ofrelated notes (collectively referred to as the Partnership’s management. Our responsibility is to express an“financial statements”). In our opinion, on these financial statements based on our audits. We did not audit the financial statements of Sunoco LP and Susser Holdings Corporation, both consolidated subsidiaries, as of December 31, 2014 and for the period from September 1, 2014 to December 31, 2014, whose combined statements reflect total assets constituting 7 percent of consolidated total assets as of December 31, 2014, and total revenues of 5 percent of consolidated total revenues for the year then ended. Those statements were audited by other auditors, whose reports have been furnished to us, and our opinion, insofar as it relates to the amounts included for Sunoco LP and Susser Holdings Corporation, is based solely on the reports of the other auditors. We did not audit the financial statements of Sunoco Logistics Partners L.P., a consolidated subsidiary, for the period from October 5, 2012 to December 31, 2012, which statements reflect revenues of 19 percent of consolidated total revenues for the year ended December 31, 2012. Those statements were audited by other auditors, whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Sunoco Logistics Partners L.P. for the period from October 5, 2012 to December 31, 2012, is based solely on the report of the other auditors. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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 and the reports of the other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the reports of the other auditors, 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, 20142017 and 2013,2016, and the results of theirits operations and theirits cash flows for each of the three years in the period ended December 31, 20142017, 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, 2014,2017, 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 March 2, 2015February 23, 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 Dallas, Texas
March 2, 2015We have served as the Partnership’s auditor since 2004.
Dallas, Texas February 23, 2018
F - 2
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Dollars in millions) | | | | | | | | | | December 31, | | 2014 | | 2013 | ASSETS | | | | CURRENT ASSETS: | | | | Cash and cash equivalents | $ | 847 |
| | $ | 590 |
| Accounts receivable, net | 3,378 |
| | 3,658 |
| Accounts receivable from related companies | 35 |
| | 63 |
| Inventories | 1,467 |
| | 1,807 |
| Exchanges receivable | 44 |
| | 67 |
| Price risk management assets | 81 |
| | 39 |
| Other current assets | 301 |
| | 312 |
| Total current assets | 6,153 |
| | 6,536 |
| | | | | PROPERTY, PLANT AND EQUIPMENT | 45,018 |
| | 33,917 |
| ACCUMULATED DEPRECIATION AND DEPLETION | (4,726 | ) | | (3,235 | ) | | 40,292 |
| | 30,682 |
| | | | | ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES | 3,659 |
| | 4,014 |
| NON-CURRENT PRICE RISK MANAGEMENT ASSETS | 10 |
| | 18 |
| GOODWILL | 7,865 |
| | 5,894 |
| INTANGIBLE ASSETS, net | 5,582 |
| | 2,264 |
| OTHER NON-CURRENT ASSETS, net | 908 |
| | 922 |
| Total assets | $ | 64,469 |
| | $ | 50,330 |
|
| | | | | | | | | | December 31, | | 2017 | | 2016* | ASSETS | | | | Current assets: | | | | Cash and cash equivalents | $ | 336 |
| | $ | 467 |
| Accounts receivable, net | 4,504 |
| | 3,557 |
| Accounts receivable from related companies | 53 |
| | 47 |
| Inventories | 2,022 |
| | 2,055 |
| Income taxes receivable | 136 |
| | 128 |
| Derivative assets | 24 |
| | 21 |
| Other current assets | 295 |
| | 447 |
| Current assets held for sale | 3,313 |
| | 177 |
| Total current assets | 10,683 |
| | 6,899 |
| | | | | Property, plant and equipment | 71,177 |
| | 61,562 |
| Accumulated depreciation and depletion | (10,089 | ) | | (7,984 | ) | | 61,088 |
| | 53,578 |
| | | | | Advances to and investments in unconsolidated affiliates | 2,705 |
| | 3,040 |
| Other non-current assets, net | 886 |
| | 815 |
| Intangible assets, net | 6,116 |
| | 5,512 |
| Goodwill | 4,768 |
| | 5,670 |
| Non-current assets held for sale | — |
| | 3,411 |
| Total assets | $ | 86,246 |
| | $ | 78,925 |
|
* As adjusted. See Note 2.
The accompanying notes are an integral part of these consolidated financial statements.
F - 3
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Dollars in millions) | | | | | | | | | | December 31, | | 2014 | | 2013 | LIABILITIES AND EQUITY | | | | CURRENT LIABILITIES: | | | | Accounts payable | $ | 3,349 |
| | $ | 3,834 |
| Accounts payable to related companies | 19 |
| | 14 |
| Exchanges payable | 184 |
| | 284 |
| Price risk management liabilities | 21 |
| | 53 |
| Accrued and other current liabilities | 2,201 |
| | 1,678 |
| Current maturities of long-term debt | 1,008 |
| | 637 |
| Total current liabilities | 6,782 |
| | 6,500 |
| | | | | LONG-TERM DEBT, less current maturities | 29,653 |
| | 22,562 |
| DEFERRED INCOME TAXES | 4,325 |
| | 3,865 |
| NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES | 154 |
| | 73 |
| OTHER NON-CURRENT LIABILITIES | 1,193 |
| | 1,019 |
| | | | | COMMITMENTS AND CONTINGENCIES (Note 12) |
|
| |
|
| | | | | REDEEMABLE NONCONTROLLING INTERESTS | 15 |
| | — |
| PREFERRED UNITS OF SUBSIDIARY (Note 7) | 33 |
| | 32 |
| | | | | EQUITY: | | | | General Partner | (1 | ) | | (3 | ) | Limited Partners: | | | | Common Unitholders (538,766,899 and 559,923,300 units authorized, issued and outstanding as of December 31, 2014 and 2013, respectively) | 648 |
| | 1,066 |
| Class D Units (1,540,000 units authorized, issued and outstanding) | 22 |
| | 6 |
| Accumulated other comprehensive income (loss) | (5 | ) | | 9 |
| Total partners’ capital | 664 |
| | 1,078 |
| Noncontrolling interest | 21,650 |
| | 15,201 |
| Total equity | 22,314 |
| | 16,279 |
| Total liabilities and equity | $ | 64,469 |
| | $ | 50,330 |
|
| | | | | | | | | | December 31, | | 2017 | | 2016* | LIABILITIES AND EQUITY | | | | Current liabilities: | | | | Accounts payable | $ | 4,685 |
| | $ | 3,502 |
| Accounts payable to related companies | 31 |
| | 42 |
| Derivative liabilities | 111 |
| | 172 |
| Accrued and other current liabilities | 2,582 |
| | 2,367 |
| Current maturities of long-term debt | 413 |
| | 1,194 |
| Current liabilities held for sale | 75 |
| | — |
| Total current liabilities | 7,897 |
| | 7,277 |
| | | | | Long-term debt, less current maturities | 43,671 |
| | 42,608 |
| Long-term notes payable - related company | — |
| | 250 |
| Deferred income taxes | 3,315 |
| | 5,112 |
| Non-current derivative liabilities | 145 |
| | 76 |
| Other non-current liabilities | 1,217 |
| | 1,075 |
| Liabilities associated with assets held for sale | — |
| | 48 |
| | | | | Commitments and contingencies |
|
| |
|
| Preferred units of subsidiary (Note 7) | — |
| | 33 |
| Redeemable noncontrolling interests | 21 |
| | 15 |
| | | | | Equity: | | | | General Partner | (3 | ) | | (3 | ) | Limited Partners: | | | | 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 | (1,196 | ) | | (1,694 | ) | Noncontrolling interest | 31,176 |
| | 24,125 |
| Total equity | 29,980 |
| | 22,431 |
| Total liabilities and equity | $ | 86,246 |
| | $ | 78,925 |
|
* As adjusted. See Note 2.
The accompanying notes are an integral part of these consolidated financial statements.
F - 4
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (Dollars in millions, except per unit data) | | | | | | | | | | | | | | Years Ended December 31, | | 2014 | | 2013 | | 2012 | REVENUES: | | | | | | Natural gas sales | $ | 5,386 |
| | $ | 3,842 |
| | $ | 2,705 |
| NGL sales | 5,845 |
| | 3,618 |
| | 2,253 |
| Crude sales | 16,416 |
| | 15,477 |
| | 2,872 |
| Gathering, transportation and other fees | 3,733 |
| | 3,097 |
| | 2,386 |
| Refined product sales | 19,437 |
| | 18,479 |
| | 5,299 |
| Other | 4,874 |
| | 3,822 |
| | 1,449 |
| Total revenues | 55,691 |
| | 48,335 |
| | 16,964 |
| COSTS AND EXPENSES: | | | | | | Cost of products sold | 48,389 |
| | 42,554 |
| | 13,088 |
| Operating expenses | 2,127 |
| | 1,695 |
| | 1,118 |
| Depreciation, depletion and amortization | 1,724 |
| | 1,313 |
| | 871 |
| Selling, general and administrative | 611 |
| | 533 |
| | 527 |
| Goodwill impairments | 370 |
| | 689 |
| | — |
| Total costs and expenses | 53,221 |
| | 46,784 |
| | 15,604 |
| OPERATING INCOME | 2,470 |
| | 1,551 |
| | 1,360 |
| OTHER INCOME (EXPENSE): | | | | | | Interest expense, net of interest capitalized | (1,369 | ) | | (1,221 | ) | | (1,018 | ) | Bridge loan related fees | — |
| | — |
| | (62 | ) | Equity in earnings of unconsolidated affiliates | 332 |
| | 236 |
| | 212 |
| Gain on deconsolidation of Propane Business | — |
| | — |
| | 1,057 |
| Gain on sale of AmeriGas common units | 177 |
| | 87 |
| | — |
| Losses on extinguishments of debt | (25 | ) | | (162 | ) | | (123 | ) | Gains (losses) on interest rate derivatives | (157 | ) | | 53 |
| | (19 | ) | Non-operating environmental remediation | — |
| | (168 | ) | | — |
| Other, net | (11 | ) | | (1 | ) | | 30 |
| INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE | 1,417 |
| | 375 |
| | 1,437 |
| Income tax expense from continuing operations | 357 |
| | 93 |
| | 54 |
| INCOME FROM CONTINUING OPERATIONS | 1,060 |
| | 282 |
| | 1,383 |
| Income (loss) from discontinued operations | 64 |
| | 33 |
| | (109 | ) | NET INCOME | 1,124 |
| | 315 |
| | 1,274 |
| LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST | 491 |
| | 119 |
| | 970 |
| NET INCOME ATTRIBUTABLE TO PARTNERS | 633 |
| | 196 |
| | 304 |
| GENERAL PARTNER’S INTEREST IN NET INCOME | 2 |
| | — |
| | 2 |
| CLASS D UNITHOLDER’S INTEREST IN NET INCOME | 2 |
| | — |
| | — |
| LIMITED PARTNERS’ INTEREST IN NET INCOME | $ | 629 |
| | $ | 196 |
| | $ | 302 |
| INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT: | | | | | | Basic | $ | 1.15 |
| | $ | 0.33 |
| | $ | 0.59 |
| Diluted | $ | 1.14 |
| | $ | 0.33 |
| | $ | 0.59 |
| NET INCOME PER LIMITED PARTNER UNIT: | | | | | | Basic | $ | 1.16 |
| | $ | 0.35 |
| | $ | 0.57 |
| Diluted | $ | 1.15 |
| | $ | 0.35 |
| | $ | 0.57 |
|
The accompanying notes are an integral part of these consolidated financial statements. | | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016* | | 2015* | REVENUES: | | | | | | Natural gas sales | $ | 4,172 |
| | $ | 3,619 |
| | $ | 3,671 |
| NGL sales | 6,972 |
| | 4,841 |
| | 3,935 |
| Crude sales | 10,184 |
| | 6,766 |
| | 8,378 |
| Gathering, transportation and other fees | 4,435 |
| | 4,172 |
| | 4,200 |
| Refined product sales | 11,975 |
| | 10,097 |
| | 11,321 |
| Other | 2,785 |
| | 2,297 |
| | 4,591 |
| Total revenues | 40,523 |
| | 31,792 |
| | 36,096 |
| COSTS AND EXPENSES: | | | | | | Cost of products sold | 30,966 |
| | 23,693 |
| | 28,668 |
| Operating expenses | 2,644 |
| | 2,307 |
| | 2,303 |
| Depreciation, depletion and amortization | 2,554 |
| | 2,216 |
| | 1,951 |
| Selling, general and administrative | 607 |
| | 693 |
| | 548 |
| Impairment losses | 1,039 |
| | 1,040 |
| | 339 |
| Total costs and expenses | 37,810 |
| | 29,949 |
| | 33,809 |
| OPERATING INCOME | 2,713 |
| | 1,843 |
| | 2,287 |
| OTHER INCOME (EXPENSE): | | | | | | Interest expense, net | (1,922 | ) | | (1,804 | ) | | (1,622 | ) | Equity in earnings from unconsolidated affiliates | 144 |
| | 270 |
| | 276 |
| Impairment of investments in unconsolidated affiliates | (313 | ) | | (308 | ) | | — |
| Gains on acquisitions | — |
| | 83 |
| | — |
| Losses on extinguishments of debt | (89 | ) | | — |
| | (43 | ) | Losses on interest rate derivatives | (37 | ) | | (12 | ) | | (18 | ) | Other, net | 214 |
| | 132 |
| | 20 |
| 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 income taxes | (177 | ) | | (462 | ) | | 38 |
| NET INCOME | 2,366 |
| | — |
| | 1,061 |
| Less: Net income (loss) attributable to noncontrolling interest | 1,412 |
| | (995 | ) | | (128 | ) | NET INCOME ATTRIBUTABLE TO PARTNERS | 954 |
| | 995 |
| | 1,189 |
| General Partner’s interest in net income | 2 |
| | 3 |
| | 3 |
| Convertible Unitholders’ interest in net income | 37 |
| | 9 |
| | — |
| Class D Unitholder’s interest in net income | — |
| | — |
| | 3 |
| Limited Partners’ interest in net income | $ | 915 |
| | $ | 983 |
| | $ | 1,183 |
| INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT: | | | | | | Basic | $ | 0.86 |
| | $ | 0.95 |
| | $ | 1.11 |
| Diluted | $ | 0.84 |
| | $ | 0.93 |
| | $ | 1.11 |
| NET INCOME PER LIMITED PARTNER UNIT: | | | | | | Basic | $ | 0.85 |
| | $ | 0.94 |
| | $ | 1.11 |
| Diluted | $ | 0.83 |
| | $ | 0.92 |
| | $ | 1.11 |
|
F - 5* 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, | | 2014 | | 2013 | | 2012 | 2017 | | 2016* | | 2015* | Net income | $ | 1,124 |
| | $ | 315 |
| | $ | 1,274 |
| $ | 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 |
| | (4 | ) | | (17 | ) | | Change in value of derivative instruments accounted for as cash flow hedges | — |
| | (1 | ) | | 12 |
| | Change in value of available-for-sale securities | 1 |
| | 2 |
| | — |
| 6 |
| | 2 |
| | (3 | ) | Actuarial gain (loss) relating to pension and other postretirement benefits | (113 | ) | | 66 |
| | (10 | ) | (12 | ) | | (1 | ) | | 65 |
| Foreign currency translation adjustment | (2 | ) | | (1 | ) | | — |
| — |
| | (1 | ) | | (1 | ) | Change in other comprehensive income from unconsolidated affiliates | (6 | ) | | 17 |
| | (9 | ) | | Change in other comprehensive income (loss) from unconsolidated affiliates | | 1 |
| | 4 |
| | (1 | ) | | (117 | ) | | 79 |
| | (24 | ) | (5 | ) | | 4 |
| | 60 |
| Comprehensive income | 1,007 |
| | 394 |
| | 1,250 |
| 2,361 |
| | 4 |
| | 1,121 |
| Less: Comprehensive income attributable to noncontrolling interest | 388 |
| | 181 |
| | 959 |
| | Less: Comprehensive income (loss) attributable to noncontrolling interest | | 1,407 |
| | (991 | ) | | (68 | ) | Comprehensive income attributable to partners | $ | 619 |
| | $ | 213 |
| | $ | 291 |
| $ | 954 |
| | $ | 995 |
| | $ | 1,189 |
|
* As adjusted. See Note 2.
The accompanying notes are an integral part of these consolidated financial statements.
F - 6
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF EQUITY (Dollars in millions) | | | | | | | | | | | | | | | | | | | | | | | | | | General Partner | | Common Unitholders | | Class D Units | | Accumulated Other Comprehensive Income (Loss) | | Non- controlling Interest | | Total | Balance, December 31, 2011 | $ | — |
| | $ | 52 |
| | $ | — |
| | $ | 1 |
| | $ | 7,335 |
| | $ | 7,388 |
| Distributions to partners | (2 | ) | | (664 | ) | | — |
| | — |
| | — |
| | (666 | ) | Distributions to noncontrolling interest | — |
| | — |
| | — |
| | — |
| | (1,017 | ) | | (1,017 | ) | Units issued in Southern Union Merger (See Note 3) | — |
| | 2,354 |
| | — |
| | — |
| | — |
| | 2,354 |
| Subsidiary equity offerings, net of issue costs | — |
| | 33 |
| | — |
| | — |
| | 1,070 |
| | 1,103 |
| Subsidiary units issued in acquisition | — |
| | 47 |
| | — |
| | — |
| | 2,248 |
| | 2,295 |
| Non-cash compensation expense, net of units tendered by employees for tax withholdings | — |
| | 1 |
| | — |
| | — |
| | 31 |
| | 32 |
| Capital contributions received from noncontrolling interest | — |
| | — |
| | — |
| | — |
| | 42 |
| | 42 |
| ETP Holdco Transaction (see Note 3) | — |
| | — |
| | — |
| | — |
| | 3,580 |
| | 3,580 |
| Other, net | — |
| | — |
| | — |
| | — |
| | (11 | ) | | (11 | ) | Other comprehensive loss, net of tax | — |
| | — |
| | — |
| | (13 | ) | | (11 | ) | | (24 | ) | Net income | 2 |
| | 302 |
| | — |
| | — |
| | 970 |
| | 1,274 |
| Balance, December 31, 2012 | — |
| | 2,125 |
| | — |
| | (12 | ) | | 14,237 |
| | 16,350 |
| Distributions to partners | (2 | ) | | (731 | ) | | — |
| | — |
| | — |
| | (733 | ) | Distributions to noncontrolling interest | — |
| | — |
| | — |
| | — |
| | (1,428 | ) | | (1,428 | ) | Subsidiary equity offerings, net of issue costs | — |
| | 122 |
| | — |
| | — |
| | 1,637 |
| | 1,759 |
| Subsidiary units issued in acquisition | (1 | ) | | (506 | ) | | — |
| | — |
| | 507 |
| | — |
| Non-cash compensation expense, net of units tendered by employees for tax withholdings | — |
| | 1 |
| | 6 |
| | — |
| | 47 |
| | 54 |
| Capital contributions received from noncontrolling interest | — |
| | — |
| | — |
| | — |
| | 18 |
| | 18 |
| Other, net | — |
| | — |
| | — |
| | 4 |
| | (39 | ) | | (35 | ) | Conversion of Regency Preferred Units for Regency Common Units | — |
| | — |
| | — |
| | — |
| | 41 |
| | 41 |
| Deemed distribution related to SUGS Transaction | — |
| | (141 | ) | | — |
| | — |
| | — |
| | (141 | ) | Other comprehensive income, net of tax | — |
| | — |
| | — |
| | 17 |
| | 62 |
| | 79 |
| Net income | — |
| | 196 |
| | — |
| | — |
| | 119 |
| | 315 |
| 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 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | General Partner | | Common Unitholders | | Class D Units | | Series A Convertible Preferred Units | | Accumulated Other Comprehensive Income (Loss) | | Non- controlling Interest | | Total | Balance, December 31, 2014* | (1 | ) | | 648 |
| | 22 |
| | — |
| | (5 | ) | | 21,637 |
| | 22,301 |
| Distributions to partners | (3 | ) | | (1,084 | ) | | (3 | ) | | — |
| | — |
| | — |
| | (1,090 | ) | Distributions to noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | (2,335 | ) | | (2,335 | ) | Subsidiary units issued | (1 | ) | | (524 | ) | | (1 | ) | | — |
| | — |
| | 4,415 |
| | 3,889 |
| Conversion of Class D Units to ETE Common Units | — |
| | 7 |
| | (7 | ) | | — |
| | — |
| | — |
| | — |
| Non-cash compensation expense, net of units tendered by employees for tax withholdings | — |
| | — |
| | 8 |
| | — |
| | — |
| | 62 |
| | 70 |
| Capital contributions received from noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | 875 |
| | 875 |
| Units repurchased under buyback program | — |
| | (1,064 | ) | | — |
| | — |
| | — |
| | — |
| | (1,064 | ) | Acquisition and disposition of noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | (65 | ) | | (65 | ) | Other comprehensive income, net of tax | — |
| | — |
| | — |
| | — |
| | 5 |
| | 55 |
| | 60 |
| Other, net | — |
| | (118 | ) | | — |
| | — |
| | — |
| | (31 | ) | | (149 | ) | Net income (loss) | 3 |
| | 1,183 |
| | 3 |
| | — |
| | — |
| | (128 | ) | | 1,061 |
| Balance, December 31, 2015* | (2 | ) | | (952 | ) | | 22 |
| | — |
| | — |
| | 24,485 |
| | 23,553 |
| Distributions to partners | (3 | ) | | (1,019 | ) | | — |
| | — |
| | — |
| | — |
| | (1,022 | ) | Distributions to noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | (2,795 | ) | | (2,795 | ) | Distributions reinvested | — |
| | (173 | ) | | — |
| | 173 |
| | — |
| | — |
| | — |
| Subsidiary units issued for cash | — |
| | — |
| | — |
| | — |
| | — |
| | 2,559 |
| | 2,559 |
| Subsidiary units issued for acquisition | — |
| | — |
| | — |
| | — |
| | — |
| | 307 |
| | 307 |
| Issuance of common units | — |
| | 39 |
| |
|
| | (2 | ) | | — |
| | — |
| | 37 |
| Non-cash compensation expense, net of units tendered by employees for tax withholdings | — |
| | — |
| | (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 | ) |
The accompanying notes are an integral part of these consolidated financial statements.
F - 7 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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, | | 2014 | | 2013 | | 2012 | 2017 | | 2016* | | 2015* | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | OPERATING ACTIVITIES: | | | | | | | Net income | $ | 1,124 |
| | $ | 315 |
| | $ | 1,274 |
| $ | 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 | 1,724 |
| | 1,313 |
| | 871 |
| 2,554 |
| | 2,216 |
| | 1,951 |
| Deferred income taxes | (50 | ) | | 43 |
| | 51 |
| (1,871 | ) | | (177 | ) | | 239 |
| Amortization included in interest expense | (51 | ) | | (55 | ) | | (13 | ) | 24 |
| | 3 |
| | (21 | ) | Bridge loan related fees | — |
| | — |
| | 62 |
| | Non-cash compensation expense | 82 |
| | 61 |
| | 47 |
| | Goodwill impairment | 370 |
| | 689 |
| | — |
| | Gain on sale of AmeriGas common units | (177 | ) | | (87 | ) | | — |
| | Gain on deconsolidation of Propane Business | — |
| | — |
| | (1,057 | ) | | Gain on curtailment of other postretirement benefit plans | — |
| | — |
| | (15 | ) | | Unit-based compensation expense | | 99 |
| | 70 |
| | 91 |
| Impairment losses | | 1,039 |
| | 1,040 |
| | 339 |
| Gains on acquisitions | | — |
| | (83 | ) | | — |
| Losses on extinguishments of debt | 25 |
| | 162 |
| | 123 |
| 89 |
| | — |
| | 43 |
| (Gains) losses on disposal of assets | (1 | ) | | 2 |
| | 4 |
| | Impairment of investments in unconsolidated affiliates | | 313 |
| | 308 |
| | — |
| Losses on disposal of assets | | — |
| | — |
| | (6 | ) | Equity in earnings of unconsolidated affiliates | (332 | ) | | (236 | ) | | (212 | ) | (144 | ) | | (270 | ) | | (276 | ) | Distributions from unconsolidated affiliates | 291 |
| | 313 |
| | 208 |
| 297 |
| | 268 |
| | 409 |
| Inventory valuation adjustments | 473 |
| | (3 | ) | | 75 |
| (24 | ) | | (97 | ) | | 67 |
| Other non-cash | (72 | ) | | 51 |
| | 211 |
| (298 | ) | | (239 | ) | | (8 | ) | Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations (see Note 2) | (231 | ) | | (149 | ) | | (551 | ) | | Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | | (192 | ) | | (179 | ) | | (872 | ) | Net cash provided by operating activities | 3,175 |
| | 2,419 |
| | 1,078 |
| 4,429 |
| | 3,322 |
| | 2,979 |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | Cash paid for Southern Union Merger, net of cash received (See Note 3) | — |
| | — |
| | (2,972 | ) | | Cash paid for all other acquisitions | (2,367 | ) | | (405 | ) | | (10 | ) | | Cash proceeds from contribution and sale of propane operations | — |
| | — |
| | 1,443 |
| | Cash proceeds from the sale of AmeriGas common units | 814 |
| | 346 |
| | — |
| | Proceeds from the sale of discontinued operations | 77 |
| | 1,008 |
| | 207 |
| | Proceeds from the sale of other assets | 62 |
| | 89 |
| | 44 |
| | Capital expenditures (excluding allowance for equity funds used during construction) | (5,381 | ) | | (3,505 | ) | | (3,271 | ) | | 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 |
| Cash paid for acquisitions, net of cash received | | (303 | ) | | (1,398 | ) | | (777 | ) | Cash paid for acquisition of a noncontrolling interest | | — |
| | — |
| | (129 | ) | Capital expenditures, excluding allowance for equity funds used during construction | | (8,444 | ) | | (7,771 | ) | | (9,073 | ) | Contributions in aid of construction costs | 45 |
| | 52 |
| | 35 |
| 31 |
| | 71 |
| | 80 |
| Contributions to unconsolidated affiliates | (334 | ) | | (3 | ) | | (37 | ) | (268 | ) | | (68 | ) | | (45 | ) | Distributions from unconsolidated affiliates in excess of cumulative earnings | 136 |
| | 419 |
| | 189 |
| 135 |
| | 135 |
| | 128 |
| Proceeds from the sale of other assets | | 48 |
| | 35 |
| | 14 |
| Change in restricted cash | 172 |
| | (348 | ) | | 5 |
| — |
| | 14 |
| | 19 |
| Other | (19 | ) | | — |
| | 171 |
| (3 | ) | | — |
| | (16 | ) | Net cash used in investing activities | (6,795 | ) | | (2,347 | ) | | (4,196 | ) | (5,606 | ) | | (8,982 | ) | | (9,735 | ) | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | FINANCING ACTIVITIES: | | | | | | | Proceeds from borrowings | 18,375 |
| | 12,934 |
| | 12,870 |
| 31,608 |
| | 25,785 |
| | 26,455 |
| Repayments of long-term debt | (13,886 | ) | | (11,951 | ) | | (8,848 | ) | (31,268 | ) | | (19,076 | ) | | (19,828 | ) | Subsidiary equity offerings, net of issue costs | 3,057 |
| | 1,759 |
| | 1,103 |
| | Cash received from affiliate notes | | — |
| | 5,317 |
| | — |
| Cash paid on affiliate notes | | (255 | ) | | (5,051 | ) | | — |
| Units issued for cash | | 568 |
| | — |
| | — |
| Subsidiary units issued for cash | | 3,235 |
| | 2,559 |
| | 3,889 |
| Distributions to partners | (821 | ) | | (733 | ) | | (666 | ) | (1,010 | ) | | (1,022 | ) | | (1,090 | ) | Distributions to noncontrolling interests | (1,905 | ) | | (1,428 | ) | | (1,017 | ) | (2,961 | ) | | (2,766 | ) | | (2,335 | ) | Redemption of ETP Convertible Preferred Units | | (53 | ) | | — |
| | — |
| Debt issuance costs | (77 | ) | | (87 | ) | | (112 | ) | (131 | ) | | (52 | ) | | (75 | ) | Capital contributions received from noncontrolling interest | 139 |
| | 18 |
| | 42 |
| | Redemption of Preferred Units | — |
| | (340 | ) | | — |
| | Capital contributions from noncontrolling interest | | 1,214 |
| | 236 |
| | 841 |
| Units repurchased under buyback program | (1,000 | ) | | — |
| | — |
| — |
| | — |
| | (1,064 | ) | Other, net | (5 | ) | | (26 | ) | | (8 | ) | 6 |
| | (3 | ) | | (8 | ) | Net cash provided by financing activities | 3,877 |
| | 146 |
| | 3,364 |
| 953 |
| | 5,927 |
| | 6,785 |
| INCREASE IN CASH AND CASH EQUIVALENTS | 257 |
| | 218 |
| | 246 |
| | CASH AND CASH EQUIVALENTS, beginning of period | 590 |
| | 372 |
| | 126 |
| | CASH AND CASH EQUIVALENTS, end of period | $ | 847 |
| | $ | 590 |
| | $ | 372 |
| | DISCONTINUED OPERATIONS | | | | | | | Operating activities | | 136 |
| | 93 |
| | 90 |
| Investing activities | | (38 | ) | | (483 | ) | | (360 | ) |
The accompanying notes are an integral part of these consolidated financial statements.
F - 8 | | | | | | | | | | | | | 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, 2014, 20132017, 2016, and 2012,2015, 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. Management has evaluated subsequent events through Unless the date the financial statements were issued. As discussed in Note 9, in January 2014, the Partnership completed a two-for-one split of ETE Common Units. Allcontext requires otherwise, references to unit“we,” “us,” “our,” the “Partnership” and per unit amounts in the“ETE” mean Energy Transfer Equity, L.P. and its consolidated financial statementssubsidiaries, which include ETP, ETP GP, ETP LLC, Panhandle, Sunoco LP and in these notesLake Charles LNG. References to the consolidated financial statements have been adjusted to reflect the effect of the unit split for all periods presented.
At December 31, 2014, our equity interests in Regency and ETP consisted of 100% of the respective general partner interest and IDRs, as well as the following:
| | | | | | ETP | | Regency | Units held by wholly-owned subsidiaries: | | | | Common units | 30.8 | | 57.2 | ETP Class H units | 50.2 | | — | Units held by less than wholly-owned subsidiaries: | | | | Common units | — | | 31.4 | Regency Class F units | — | | 6.3 |
“Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.The consolidated financial statements of ETE presented herein include the results of operations of: the Parent Company; our controlled subsidiaries, ETP and Regency (see descriptionSunoco LP; consolidated subsidiaries of their respective operations below under “Business Operations”); ETP’s and Regency’s consolidatedour controlled subsidiaries and our wholly-owned subsidiaries that own the general partner interests and IDR interests in ETP and Regency;Sunoco LP; and
our wholly-owned subsidiary, Lake Charles LNG. Lake Charles LNG was acquired from ETP in February 2014. 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 2014 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. Unless the context requires otherwise, references Additionally, for prior periods herein, certain balances have been reclassified to “we,” “us,” “our,” the “Partnership”assets and “ETE” mean Energy Transfer Equity, L.P.liabilities held for sale and its consolidated subsidiaries, which include ETP, ETP GP, ETP LLC, ETE Common Holdings, LLC, Regency, Regency GP, Regency LLC, Panhandle (or Southern Union priorcertain revenues and expenses to its merger into Panhandle in January 2014), Sunoco, Inc., Sunoco Logistics, Sunoco LP, Susser and ETP Holdco. References to the “Parent Company” mean Energy Transfer Equity, L.P.discontinued operations. These reclassifications had no impact on a stand-alone basis.
In 2014, our consolidated subsidiaries, Trunkline LNG Company, LLC, Trunkline LNG Export, LLC and Susser Petroleum Partners LP, changed their names to Lake Charles LNG Company, LLC, Lake Charles LNG Export, LLC and Sunoco LP,
respectively. All references to these subsidiaries throughout this document reflect the new names of those subsidiaries, regardless of whether the disclosure relates to periodsnet income or events prior to the dates of the name changes.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 Regency.Sunoco 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 1817 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 are primarily conducted through our operating subsidiariesof the Parent Company; and the goodwill and property, plant and equipment fair value adjustments recorded as follows:a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P. ETP is a publicly traded partnership whose operations are conducted throughcomprise the following subsidiaries:following: ETC OLP, a Texas limited partnership primarily engaged in midstream and intrastate transportation and storage natural gas operations. ETC OLP owns and operates, through its wholly and majority-owned subsidiaries, natural gas gathering systems, intrastate natural gas pipeline systems and gas processing plants and is 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. ETC OLP’s intrastate transportation and storage operations primarily focus on transporting natural gas in Texas through its Oasis pipeline, ET Fuel System, East Texas pipeline and HPL System. ETC OLP’s midstream operations focus on the gathering, compression, treating, conditioning and processing of natural gas, primarily on or through its Southeast Texas System, Eagle Ford System, North Texas System and Northern Louisiana assets. ETC OLP also owns a 70% interest in Lone Star.
ET Interstate, a Delaware limited liability company with revenues consisting primarily of fees earned from natural gas transportation services and operational gas sales. ET Interstate is the parent company of:
Transwestern, a Delaware limited liability company engaged in interstate transportation of natural gas. Transwestern’s revenues consist primarily of fees earned from natural gas transportation services and operational gas sales.
ETC FEP, a Delaware limited liability company that directly owns a 50% interest in FEP, which owns 100% of the Fayetteville Express interstate natural gas pipeline.
ETC Tiger, a Delaware limited liability company engaged in interstate transportation of natural gas.
CrossCountry, a Delaware limited liability company that indirectly owns a 50% interest in Citrus Corp., which owns 100% of the FGT interstate natural gas pipeline.
ETC Compression, a Delaware limited liability company engaged in natural gas compression services and related equipment sales.
ETP Holdco, a Delaware limited liability company that indirectly owns Panhandle and Sunoco, Inc. Panhandle and Sunoco, Inc. operations are described as follows:
Panhandle owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the transportation and storage of natural gas in the United States. As discussed in Note 3, in January 2014, Panhandle consummated a merger with Southern Union, the indirect parent of Panhandle, and PEPL Holdings, the sole limited partner of Panhandle, pursuant to which each of Southern Union and PEPL Holdings were merged with and into Panhandle, with Panhandle surviving the merger.
Sunoco, Inc. owns and operates retail marketing assets, which sell gasoline and middle distillates at retail locations and operates convenience stores primarily on the east coast and in the midwest region of the United States. Effective June 1, 2014, ETP combined certain Sunoco, Inc. retail assets with another wholly-owned subsidiary of ETP to form a limited liability company owned by ETP and Sunoco, Inc.
Sunoco Logistics, a publicly traded Delaware limited partnership that owns and operates a logistics business, consisting of products, crude oil and NGL pipelines, terminalling and storage assets, and refined products, crude oil and NGL acquisition and marketing assets.
ETP owns an indirect 100% equity interest in Susser and the general partner interest, incentive distribution rights and a 42.8% limited partner interest in Sunoco LP. Susser operates convenience stores in Texas, New Mexico and Oklahoma. Sunoco LP distributes motor fuels to convenience stores and retail fuel outlets in Texas, New Mexico, Oklahoma, Kansas and Louisiana and other commercial customers. As discussed in Note 3, in October 2014, Sunoco LP acquired MACS from ETP.
Regency is a publicly traded partnership engaged in the gathering and processing, compression, treating and transportation of natural gas; the transportation, fractionation and storage of NGLs; the gathering, transportation and terminaling of oil (crude and/or condensate, a lighter oil) received from producers; the gathering and disposing of salt water; natural gas, and NGL marketing and trading; and the management of coal and natural resource properties in the United States. Regency providesfocusing 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 Granite Wash shales. Its assetsstorage natural gas operations that own and operate natural gas pipeline systems that are locatedengaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, Arkansas, West Virginia, Pennsylvania, Ohio, California, Mississippi, Alabama, New Mexico and the mid-continent region ofWest 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, which includes Kansas, ColoradoStates; and Oklahoma. Regency also holds a 30% controlling interest in Lone Star.Sunoco Logistics Partners 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, NGLs and refined products. Sunoco LP is engaged in the wholesale distribution of motor fuels to convenience stores, independent dealers, commercial customers, and 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. Subsequent to the Lake Charles LNG Transaction in February 2014, our reportable segments changed and currently reflect the following reportable business segments: Investment in ETP; Investment in Regency; Investment in Lake Charles LNG; and Corporate and Other.
| | 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, depletion 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 values and 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, Revenue from 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. The Partnership adopted ASU 2014-09 on January 1, 2018. The Partnership applied the cumulative catchup transition method and recognized the cumulative effect of the retrospective application of the standard. The effect of the retrospective application of the standard was not material. For future periods, ETP expects that the adoption of this standard will result in a change to revenues 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 accounting for noncash consideration in multiple of our reportable segments, as well as fuel usage and loss allowances. None of these changes is expected to have a material impact on net income. We have determined that the timing and/or amount of revenue that we recognize on certain contracts associated with Sunoco LP’s operations will be impacted by the adoption of the new standard. We currently estimate the cumulative catch-up effect to Sunoco LP’s retained earnings as of January 1, 2018 to be approximately $54 million. These adjustments are primarily related to the change in 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 in the first quarter of 2019 and 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, 2018, the Partnership 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. We do not anticipate a material impact to our financial position or results of operations as a result of the adoption of this standard. ASU 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’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance did 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 annual reportingfinancial statements issued for fiscal years, and interim periods within those fiscal
years, beginning after December 15, 2016, including interim periods within that reporting period,2018, with earlierearly adoption not permitted. ASU 2014-09 can be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. The Partnership is currently evaluating the impact if any, that adopting this new accounting standard will have on our revenue recognition policies. In April 2014, the FASB issued Accounting Standards Update No. 2014-08, Presentation of Financial Statements (Topic 205)consolidated financial statements and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (“ASU 2014-08”), which changed the requirements for reporting discontinued operations. Under
ASU 2014-08, a disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has or will have a major effect on an entity’s operations and financial results. ASU 2014-08 is effective for all disposals or classifications as held for sale of components of an entity that occur within fiscal years beginning after December 15, 2014, and early adoption is permitted. We expect to adopt this standard for the year ending December 31, 2015. ASU 2014-08 could have an impact on whether transactions will be reported in discontinued operations in the future, as well as the disclosures required when a component of an entity is disposed.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 partythird-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. ETP’s retail marketing operationsInvestment 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. 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. Sunoco LP may sell gasoline and diesel in addition to a broad mix of merchandise such as groceries, fast foods and beverages at its convenience stores. A portion of our gasoline and diesel sales aremotor fuel to wholesale customers on a consignmentcommission agent basis, in which we retainSunoco 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. We typically own the fuel dispensing equipmentSunoco LP derives other income from rental income, propane and underground storage tanks at consignment sites,lubricating oils and in some cases we own the entire siteother ancillary product and have entered into an operating lease whit the wholesale customer operating the site. In addition, our retail outlets deriveservice offerings. Sunoco LP derives other income from lottery ticket sales, money orders, prepaid phone cards and wireless services, ATM transactions, car washes, movie rentalrentals and other ancillary product and service offerings. Some of Sunoco Inc.’s retail outlets provide a variety of car care services. Revenues related to the sale of products are recognized when title passes, while service revenues are recordedLP records revenue on a net commission basis and are recognized when the product is sold and/or services are provided. Title passage generally occurs when products are shipped or delivered in accordance withrendered. Rental income from operating leases is recognized on a straight line basis over the termsterm of the respective sales agreements. In addition, revenues are not recognized until sales prices are fixed or determinable and collectability is reasonably assured. Investment in Regency
Regency earns revenue from (i) domestic sales of natural gas, NGLs and condensate, (ii) natural gas, NGL, condensate and salt water gathering, processing and transportation, (iii) contract compression and treating services and (iv) coal royalties. Revenue associated with sales of natural gas, NGLs and condensate are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery occurs. Revenue associated with transportation and processing fees are recognized when the service is provided. For contract compression and contract treating services, revenue is recognized when the service is performed. For gathering and processing services, Regency receives either fees or commodities from natural gas producers depending on the type of contract. Commodities received are in turn sold and recognized as revenue in accordance with the criteria outlined above. Under the percentage-of-proceeds contract type, Regency is paid for its services by keeping a percentage of the NGLs produced and a percentage of the residue gas resulting from processing the natural gas. Under the percentage-of-index contract type, Regency earns revenue by purchasing wellhead natural gas at a percentage of the index price and selling processed natural gas and NGLs at a price approximating the index price to third parties. Regency generally reports revenue gross in the consolidated statements of operations when it acts as the principal, takes title to the product, and incurs the risks and rewards of ownership. Revenue for fee-based arrangements is presented net, because Regency takes the role of an agent for the producers. Allowance for doubtful accounts is determined based on historical write-off experience and specific identification.
Regency recognizes coal royalties revenues on the basis of tons of coal sold by its lessees and the corresponding revenues from those sales. Regency does not have access to actual production and revenues information until 30 days following the month of production. Therefore, financial results include estimated revenues and accounts receivable for the month of production. Regency records any differences between the actual amounts ultimately received or paid and the original estimates
in the period they become finalized. Most lessees must make minimum monthly or annual payments that are generally recoverable over certain time periods. These minimum payments are recorded as deferred income. If the lessee recovers a minimum payment through production, the deferred income attributable to the minimum payment is recognized as coal royalties revenues. If a lessee fails to meet its minimum production for certain pre-determined time periods, the deferred income attributable to the minimum payment is recognized as minimum rental revenues, which is a component of other revenues on our consolidated statements of operations. Other liabilities on the balance sheet also include deferred unearned income from a coal services facility lease, which is recognized as other income as it is earned.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. In 1999, prior to its acquisition by Southern Union, Panhandle discontinued the application ofdoes 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, | | 2014 | | 2013 | | 2012 | 2017 | | 2016 | | 2015 | Accounts receivable | $ | 600 |
| | $ | (556 | ) | | $ | 267 |
| $ | (948 | ) | | $ | (1,126 | ) | | $ | 856 |
| Accounts receivable from related companies | 30 |
| | 64 |
| | (9 | ) | 24 |
| | 42 |
| | (5 | ) | Inventories | 51 |
| | (254 | ) | | (258 | ) | 58 |
| | (480 | ) | | (212 | ) | Exchanges receivable | 18 |
| | (8 | ) | | 14 |
| | Other current assets | 133 |
| | (81 | ) | | 597 |
| 38 |
| | 165 |
| | (225 | ) | Other non-current assets, net | (6 | ) | | (23 | ) | | (129 | ) | 84 |
| | (148 | ) | | 247 |
| Accounts payable | (850 | ) | | 541 |
| | (989 | ) | 712 |
| | 1,170 |
| | (1,070 | ) | Accounts payable to related companies | 5 |
| | (140 | ) | | 92 |
| (178 | ) | | (64 | ) | | 400 |
| Exchanges payable | (99 | ) | | 128 |
| | — |
| | Accrued and other current liabilities | (59 | ) | | 192 |
| | (159 | ) | (97 | ) | | 89 |
| | (697 | ) | Other non-current liabilities | (73 | ) | | 147 |
| | 26 |
| 106 |
| | 106 |
| | (241 | ) | Price risk management assets and liabilities, net | 19 |
| | (159 | ) | | (3 | ) | | Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | $ | (231 | ) | | $ | (149 | ) | | $ | (551 | ) | | Derivative assets and liabilities, net | | 9 |
| | 67 |
| | 75 |
| Net change in operating assets and liabilities, net of effects of acquisitions | | $ | (192 | ) | | $ | (179 | ) | | $ | (872 | ) |
Non-cash investing and financing activities and supplemental cash flow information were as follows: | | | | | | | | | | | | | | Years Ended December 31, | | 2014 | | 2013 | | 2012 | NON-CASH INVESTING ACTIVITIES: | | | | | | Accrued capital expenditures | $ | 643 |
| | $ | 226 |
| | $ | 420 |
| Net gains (losses) from subsidiary common unit transactions | $ | 744 |
| | $ | (384 | ) | | $ | 80 |
| AmeriGas limited partner interest received in Propane Contribution (see Note 4) | $ | — |
| | $ | — |
| | $ | 1,123 |
| NON-CASH FINANCING ACTIVITIES: | | | | | | Issuance of Common Units in connection with Southern Union Merger (see Note 3) | $ | — |
| | $ | — |
| | $ | 2,354 |
| Subsidiary issuance of common units in connection with certain acquisitions | $ | — |
| | $ | — |
| | $ | 2,295 |
| 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 |
| | $ | — |
| | $ | — |
| SUPPLEMENTAL CASH FLOW INFORMATION: | | | | | | Cash paid for interest, net of interest capitalized | $ | 1,416 |
| | $ | 1,256 |
| | $ | 997 |
| Cash paid for income taxes | $ | 345 |
| | $ | 58 |
| | $ | 23 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | NON-CASH INVESTING ACTIVITIES: | | | | | | Accrued capital expenditures | $ | 1,060 |
| | $ | 848 |
| | $ | 910 |
| Net gains (losses) from subsidiary common unit transactions | (56 | ) | | 16 |
| | (526 | ) | NON-CASH FINANCING ACTIVITIES: | | | | | | Issuance of Common Units in connection with the PennTex Acquisition | $ | — |
| | $ | 307 |
| | $ | — |
| Contribution of assets from noncontrolling interest | 988 |
| | — |
| | 34 |
| SUPPLEMENTAL CASH FLOW INFORMATION: | | | | | | Cash paid for interest, net of interest capitalized | $ | 1,914 |
| | $ | 1,922 |
| | $ | 1,800 |
| Cash paid for (refund of) income taxes | 50 |
| | (229 | ) | | 72 |
|
Accounts Receivable Our subsidiaries assess the credit risk of their customers. Certain of our subsidiaries deal with counterparties that are typically either investment grade or are otherwise secured with a letter of credit or other form of security (corporate guarantee prepayment, master setoff agreement or collateral).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 identification.customers with payment issues.
Inventories F - 15
Inventories2017.
Inventories consist principally of natural gas held in storage, NGLs and refined products, crude oil petroleum and chemical products. Natural gas held in storage isspare parts, 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 petroleum and chemical products is determined using the last-in, first out method. The cost of appliances, parts and fittings is determined by the first-in, first-out method. Inventories consisted of the following: | | | | | | | | | | December 31, | | 2014 | | 2013 | Natural gas and NGLs | $ | 392 |
| | $ | 577 |
| Crude oil | 364 |
| | 488 |
| Refined products | 392 |
| | 543 |
| Appliances, parts and fittings and other | 319 |
| | 199 |
| Total inventories | $ | 1,467 |
| | $ | 1,807 |
|
During the year ended December 31, 2014, the Partnership recorded write downs of $473 million on its crude oil, refined products and NGL inventories as a result of a decline in the market price of these products. The write-down was 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. Exchanges
Exchanges consist of natural gas and NGL delivery imbalances (over and under deliveries) with others. These amounts, which are valued at market prices or weighted average market prices pursuant to contractual imbalance agreements, turn over monthly and are recorded as exchanges receivable or exchanges payable on our consolidated balance sheets. These imbalances are generally settled by deliveries of natural gas or NGLs, but may be settled in cash, depending on contractual terms.
Other Current Assets Other current assets consisted of the following: | | | December 31, | December 31, | | 2014 | | 2013 | 2017 | | 2016 | Deposits paid to vendors | $ | 65 |
| | $ | 49 |
| $ | 64 |
| | $ | 74 |
| Deferred income taxes | 14 |
| | — |
| | Prepaid expenses and other | 222 |
| | 263 |
| 231 |
| | 373 |
| Total other current assets | $ | 301 |
| | $ | 312 |
| $ | 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.
We and our subsidiaries review property,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 its 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 its midstream operations. In 2015, ETP recorded a $110 million fixed asset impairment related to its 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 its 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, | | 2014 | | 2013 | 2017 | | 2016 | Land and improvements | $ | 1,307 |
| | $ | 881 |
| $ | 2,222 |
| | $ | 1,189 |
| Buildings and improvements (1 to 45 years) | 1,922 |
| | 939 |
| 2,786 |
| | 2,247 |
| Pipelines and equipment (5 to 83 years) | 27,149 |
| | 21,494 |
| 44,673 |
| | 36,570 |
| Natural gas and NGL storage facilities (5 to 46 years) | 1,214 |
| | 1,083 |
| 1,681 |
| | 1,451 |
| Bulk storage, equipment and facilities (2 to 83 years) | 4,010 |
| | 1,933 |
| 3,883 |
| | 3,701 |
| Tanks and other equipment (5 to 40 years) | 58 |
| | 1,697 |
| | Retail equipment (2 to 99 years) | 515 |
| | 450 |
| | Vehicles (1 to 25 years) | 203 |
| | 156 |
| 126 |
| | 217 |
| Right of way (20 to 83 years) | 2,451 |
| | 2,190 |
| 3,432 |
| | 3,349 |
| Furniture and fixtures (2 to 25 years) | 59 |
| | 51 |
| | Linepack | 119 |
| | 118 |
| | Pad gas | 44 |
| | 52 |
| | Natural resources | 454 |
| | — |
| 434 |
| | 434 |
| Other (1 to 30 years) | 999 |
| | 708 |
| | Other (1 to 40 years) | | 1,029 |
| | 2,285 |
| Construction work-in-process | 4,514 |
| | 2,165 |
| 10,911 |
| | 10,119 |
| | 45,018 |
| | 33,917 |
| 71,177 |
| | 61,562 |
| Less – Accumulated depreciation and depletion | (4,726 | ) | | (3,235 | ) | (10,089 | ) | | (7,984 | ) | Property, plant and equipment, net | $ | 40,292 |
| | $ | 30,682 |
| $ | 61,088 |
| | $ | 53,578 |
|
We recognized the following amounts of depreciation expense and capitalized interest expense for the periods presented: | | | | | | | | | | | | | | Years Ended December 31, | | 2014 | | 2013 | | 2012 | Depreciation expense | $ | 1,457 |
| | $ | 1,128 |
| | $ | 801 |
| Capitalized interest, excluding AFUDC | $ | 113 |
| | $ | 43 |
| | $ | 99 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | Depreciation and depletion expense | $ | 2,204 |
| | $ | 1,952 |
| | $ | 1,661 |
| Capitalized interest | 286 |
| | 201 |
| | 164 |
|
Depletion expense related to Regency’s natural resources operations was $11 million for the year ended December 31, 2014. Coal properties are depleted on an area-by-area basis at a rate based on the cost of the mineral properties and the number of tons of estimated proven and probable coal reserves contained therein. Proven and probable coal reserves have been estimated by Regency’s own geologists. Regency’s estimates of coal reserves are updated periodically and may result in adjustments to coal reserves and depletion rates that are recognized prospectively. From time to time, Regency carries out core-hole drilling activities on coal properties in order to ascertain the quality and quantity of the coal contained in those properties. These core-hole drilling activities are expensed as incurred. Regency depletes timber using a methodology consistent with the units-of-production method, which is based on the quantity of timber harvested. Regency determines depletion of oil and gas royalty interests by the units-of-production method and these amounts could change with revisions to estimated proved recoverable reserves.
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. Goodwill
Goodwill An impairment of an investment in an unconsolidated affiliate is tested for impairment annually or more frequently ifrecognized when circumstances indicate that goodwill might be impaired. Our annual impairment test is performed as of August 31 for reporting units within ETP’s intrastate transportation and storage and midstream operations and during the fourth quarter for reporting units within ETP’s interstate transportation and storage and liquids transportation and services operations and all others, including all of Regency’s reporting units and Lake Charles LNG.
Changesa decline in the carrying amountinvestment 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 goodwill were as follows:the following: | | | | | | | | | | | | | | | | | | | | | | Investment in ETP | | Investment in Regency | | Investment in Lake Charles LNG | | Corporate, Other and Eliminations | | Total | Balance, December 31, 2012 | $ | 5,606 |
| | $ | 1,127 |
| | $ | 873 |
| | $ | (1,172 | ) | | $ | 6,434 |
| Goodwill acquired | 156 |
| | — |
| | — |
| | — |
| | 156 |
| Deconsolidation of SUGS (1) | (337 | ) | | — |
| | — |
| | 337 |
| | — |
| Goodwill impairment | (689 | ) | | — |
| | (689 | ) | | 689 |
| | (689 | ) | Other | (7 | ) | | — |
| | — |
| | — |
| | (7 | ) | Balance, December 31, 2013 | 4,729 |
| | 1,127 |
| | 184 |
| | (146 | ) | | 5,894 |
| Goodwill acquired | 1,874 |
| | 449 |
| | — |
| | — |
| | 2,323 |
| Lake Charles LNG Transaction (2) | (184 | ) | | — |
| | — |
| | 184 |
| | — |
| Goodwill impairment | — |
| | (370 | ) | | — |
| | — |
| | (370 | ) | Other | — |
| | 17 |
| | — |
| | 1 |
| | 18 |
| Balance, December 31, 2014 | $ | 6,419 |
| | $ | 1,223 |
| | $ | 184 |
| | $ | 39 |
| | $ | 7,865 |
|
| | | | | | | | | | 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 |
|
| | (1)
| As discussed in Note 3, Regency completed its acquisition of SUGS on April 30, 2013 which was a transaction between entities under common control. Therefore, the investment in Regency segment amounts have been retrospectively adjusted to reflect SUGS beginning March 26, 2012. Therefore, the December 31, 2012 goodwill balance includes goodwill attributable to SUGS of $337 million in both segments that was correspondingly included in the elimination column. ETP deconsolidated SUGS on April 30, 2013. |
| | (2)
| As discussed in Note 3, ETP completed the transfer to ETE of Lake Charles LNG on February 19, 2014. Therefore, the December 31, 2012 and 2013 goodwill balances include goodwill attributable to Lake Charles LNG of $873 million and$184 million, respectively, in both the investment in ETP and investment in Lake Charles LNG segments that was correspondingly included in the elimination column. The transaction was effective January 1, 2014. |
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. We recorded a net increaseRestricted funds primarily consisted of restricted cash held in goodwill of $1.97 billion during the year ended December 31, 2014 primarily due to the Susser Merger and PVR Acquisition where we recorded goodwill of $1.73 billion and $370 million, respectively, offset by an impairment of $370 million. The additional goodwill recorded during the years ended December 31, 2014 and 2013 is not expected to be deductible for tax purposes.our wholly-owned captive insurance companies.
During the fourth quarter of 2014, a $370 million goodwill impairment was recorded related to Regency’s Permian Basin gathering and processing operations. The decline in estimated fair value of that reporting unit was primarily driven by the significant decline in commodity prices in the fourth quarter of 2014, and the resulting impact to future commodity prices as well as increases in future estimated operations and maintenance expenses. An assessment of these factors in the fourth quarter of 2014 led to a conclusion that the estimated fair value of Regency’s Permian reporting unit was less than its carrying amount.
During the fourth quarter of 2013, ETP performed a goodwill impairment test on its Lake Charles LNG reporting unit. In accordance with GAAP, ETP performed step one of the goodwill impairment test and determined that the estimated fair value of the Lake Charles LNG reporting unit was less than its carrying amount, primarily due to changes related to (i) the structure
and capitalization of the planned LNG export project at Lake Charles LNG’s Lake Charles facility, (ii) an analysis of current macroeconomic factors, including global natural gas prices and relative spreads, as of the date of our assessment, (iii) judgments regarding the prospect of obtaining regulatory approval for a proposed LNG export project and the uncertainty associated with the timing of such approvals, and (iv) changes in assumptions related to potential future revenues from the import facility and the proposed export facility. An assessment of these factors in the fourth quarter of 2013 led to a conclusion that the estimated fair value of the Lake Charles LNG reporting unit was less than its carrying amount. ETP then applied the second step in the goodwill impairment test, allocating the estimated fair value of the reporting unit among all of the assets and liabilities of the reporting unit in a hypothetical purchase price allocation. The assets and liabilities of the reporting unit had recently been measured at fair value in 2012 as a result of the acquisition of Southern Union, and those estimated fair values had been recorded at the reporting unit through the application of “push-down” accounting. For purposes of the hypothetical purchase price allocation used in the goodwill impairment test, ETP estimated the fair value of the assets and liabilities of the reporting unit in a manner similar to the original purchase price allocation. In allocating value to the property, plant and equipment, ETP used current replacement costs adjusted for assumed depreciation. ETP also included the estimated fair value of working capital and identifiable intangible assets in the reporting unit. ETP adjusted deferred income taxes based on these estimated fair values. Based on this hypothetical purchase price allocation, estimated goodwill was $184 million, which was less than the balance of $873 million that had originally been recorded by the reporting unit through “push-down” accounting in 2012. As a result, ETP recorded a goodwill impairment of $689 million during the fourth quarter of 2013.
No other goodwill impairments were identified or recorded for our reporting units.
Intangible Assets Intangible assets are stated at cost, net of amortization computed on the straight-line method. We eliminate from our consolidated balance sheetsThe 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, 2014 | | December 31, 2013 | 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) | $ | 5,144 |
| | $ | (485 | ) | | $ | 2,135 |
| | $ | (264 | ) | $ | 6,979 |
| | $ | (1,277 | ) | | $ | 6,050 |
| | $ | (971 | ) | Trade names (15 to 20 years) | 556 |
| | (15 | ) | | 66 |
| | (12 | ) | | Patents (9 years) | 48 |
| | (11 | ) | | 48 |
| | (6 | ) | | Other (1 to 15 years) | 36 |
| | (7 | ) | | 7 |
| | (4 | ) | | 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 | 5,784 |
| | (518 | ) | | 2,256 |
| | (286 | ) | 7,121 |
| | (1,342 | ) | | 6,189 |
| | (1,024 | ) | Non-amortizable intangible assets: | | | | | | | | | | | | | | | Trademarks | 316 |
| | — |
| | 294 |
| | — |
| 295 |
| | — |
| | 288 |
| | — |
| Other | | 42 |
| | — |
| | 59 |
| | — |
| Total intangible assets | $ | 6,100 |
| | $ | (518 | ) | | $ | 2,550 |
| | $ | (286 | ) | $ | 7,458 |
| | $ | (1,342 | ) | | $ | 6,536 |
| | $ | (1,024 | ) |
Aggregate amortization expense of intangibles assets was as follows: | | | | | | | | | | | | | | Years Ended December 31, | | 2014 | | 2013 | | 2012 | Reported in depreciation, depletion and amortization | $ | 219 |
| | $ | 120 |
| | $ | 70 |
|
| | | | | | | | | | | | | | 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: | | | 2015 | $ | 263 |
| | 2016 | 260 |
| | 2017 | 260 |
| | 2018 | 259 |
| $ | 341 |
| 2019 | 256 |
| 338 |
| 2020 | | 336 |
| 2021 | | 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.
Sunoco LP performed impairment tests on their indefinite-lived intangible assets during the fourth quarter of 2017 and recognized $13 million and $4 million impairment charge on their contractual rights and liquor licenses, included in Other Non-Current Assets, netin the table above, primarily due to decreases in projected future revenues and cash flows from the date the intangible asset was originally recorded. Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consistedIn 2015, ETP recorded $24 million of intangible asset impairments related to its 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 following:fourth quarter. Changes in the carrying amount of goodwill were as follows: | | | | | | | | | | December 31, | | 2014 | | 2013 | Unamortized financing costs (3 to 30 years) | $ | 203 |
| | $ | 167 |
| Regulatory assets | 85 |
| | 86 |
| Deferred charges | 220 |
| | 144 |
| Restricted funds | 177 |
| | 378 |
| Other | 223 |
| | 147 |
| Total other non-current assets, net | $ | 908 |
| | $ | 922 |
|
| | | | | | | | | | | | | | | | | | | | | | Investment in ETP | | Investment in Sunoco LP | | Investment in Lake Charles LNG | | Corporate, Other and Eliminations | | Total | Balance, December 31, 2015 | $ | 5,428 |
| | $ | 1,694 |
| | $ | 184 |
| | $ | (1,250 | ) | | $ | 6,056 |
| Goodwill acquired | 428 |
| | 81 |
| | — |
| | — |
| | 509 |
| Sunoco LP Exchange | (1,289 | ) | | — |
| | — |
| | 1,289 |
| | — |
| Goodwill impairment | (670 | ) | | (227 | ) | | — |
| | — |
| | (897 | ) | Other | — |
| | 2 |
| | — |
| | — |
| | 2 |
| Balance, December 31, 2016 | 3,897 |
| | 1,550 |
| | 184 |
| | 39 |
| | 5,670 |
| Goodwill acquired | 12 |
| | — |
| | — |
| | — |
| | 12 |
| Goodwill impairment | (793 | ) | | (102 | ) | | — |
| | — |
| | (895 | ) | Other | (1 | ) | | (18 | ) | | — |
| | — |
| | (19 | ) | Balance, December 31, 2017 | $ | 3,115 |
| | $ | 1,430 |
| | $ | 184 |
| | $ | 39 |
| | $ | 4,768 |
|
Restricted fundsGoodwill 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 consisteddue 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 restricted$387 million, of which $102 million was allocated to continuing operations,primarily due to changes in assumptions related to projected future revenues and cash heldflows from the dates the goodwill was originally recorded. During the fourth quarter of 2016, ETP recognized goodwill impairments of $638 million in its interstate transportation and storage operations and $32 million in its 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 $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 recognized goodwill impairments of $99 million in its interstate transportation and storage operations and $106 million in its NGL and refined products transportation and services operations primarily due to market declines in current and expected future commodity prices in the fourth quarter of 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 wholly-owned captive insurance companies.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, Sunoco Logistics and ETP’s retail marketing operations. discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as of December 31, 20142017 and 2013,2016, 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 schedule of AROs by segment recorded asDecember 31, 2017 and 2016, other non-current liabilities in ourETP’s consolidated balance sheets:sheets included AROs of $165 million and $170 million, respectively.
| | | | | | | | | | December 31, | | 2014 | | 2013 | Investment in ETP: | | | | Interstate transportation and storage operations | $ | 58 |
| | $ | 55 |
| Retail marketing operations | 87 |
| | 84 |
| Investment in Sunoco Logistics | 41 |
| | 41 |
| Investment in Regency | 2 |
| | — |
| | $ | 188 |
| | $ | 180 |
|
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. AsLong-lived assets related to AROs aggregated to $2 million and $14 million, and were reflected as property, plant and equipment on our consolidated balance sheets as of December 31, 2014, there were no2017 and 2016, respectively. In addition, the Partnership had $21 million and $13 million legally restricted funds for the purpose of settling AROs.AROs that was reflected as other non-current assets as of December 31, 2017 and 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, | | 2014 | | 2013 | 2017 | | 2016 | Interest payable | $ | 440 |
| | $ | 357 |
| $ | 552 |
| | $ | 545 |
| Customer advances and deposits | 103 |
| | 142 |
| 59 |
| | 72 |
| Accrued capital expenditures | 673 |
| | 260 |
| 1,006 |
| | 769 |
| Accrued wages and benefits | 233 |
| | 173 |
| 280 |
| | 254 |
| Taxes payable other than income taxes | 236 |
| | 211 |
| 108 |
| | 201 |
| Income taxes payable | 54 |
| | 4 |
| 180 |
| | — |
| Deferred income taxes | 99 |
| | 119 |
| | Exchanges payable | | 154 |
| | 208 |
| Other | 363 |
| | 412 |
| 243 |
| | 318 |
| Total accrued and other current liabilities | $ | 2,201 |
| | $ | 1,678 |
| $ | 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 ETP’s consolidated subsidiaries have the option to sell their interests to ETP. In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable interest on our 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. Price risk management assets and liabilities are recorded at 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, 20142017 was $31.68$45.62 billion and $30.66$44.08 billion, respectively. As of December 31, 20132016, the aggregate fair value and carrying amount of
our consolidated debt obligations was $23.97$45.05 billion and $23.20$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 the Preferred Units, the preferred units of a subsidiary and embedded derivatives in the preferred units of a subsidiary (the “RegencyETP Convertible Preferred Units”)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 toDuring the Regency 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. Atyear ended December 31, 2012,2017 and 2016, no transfers were made between any levels within the fair value of the Preferred Units was based predominantly on an income approach model and considered Level 3. The Preferred Units were redeemed on April 1, 2013.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, 20142017 and 20132016 based on inputs used to derive their fair values: | | | | | | | | | | | | | | | | | | Fair Value Measurements at December 31, 2014 | | Fair Value Total | | Level 1 | | Level 2 | | Level 3 | Assets: | | | | | | | | Interest rate derivatives | $ | 3 |
| | $ | — |
| | $ | 3 |
| | $ | — |
| Commodity derivatives: | | | | | | | | Condensate — Forward Swaps | 36 |
| | — |
| | 36 |
| | — |
| Natural Gas: | | | | | | | | Basis Swaps IFERC/NYMEX | 19 |
| | 19 |
| | — |
| | — |
| Swing Swaps IFERC | 26 |
| | 1 |
| | 25 |
| | — |
| Fixed Swaps/Futures | 566 |
| | 541 |
| | 25 |
| | — |
| Forward Physical Contracts | 1 |
| | — |
| | 1 |
| | — |
| Power: | | | | | | | | Forwards | 3 |
| | — |
| | 3 |
| | — |
| Futures | 4 |
| | 4 |
| | — |
| | — |
| Natural Gas Liquids — Forwards/Swaps | 69 |
| | 46 |
| | 23 |
| | — |
| Refined Products — Futures | 21 |
| | 21 |
| | — |
| | — |
| Total commodity derivatives | 745 |
| | 632 |
| | 113 |
| | — |
| Total assets | $ | 748 |
| | $ | 632 |
| | $ | 116 |
| | $ | — |
| Liabilities: | | | | | | | | Interest rate derivatives | $ | (155 | ) | | $ | — |
| | $ | (155 | ) | | $ | — |
| Embedded derivatives in the Regency Preferred Units | (16 | ) | | — |
| | — |
| | (16 | ) | Commodity derivatives: | | | | | | | | Natural Gas: | | | | | | | | Basis Swaps IFERC/NYMEX | (18 | ) | | (18 | ) | | — |
| | — |
| Swing Swaps IFERC | (25 | ) | | (2 | ) | | (23 | ) | | — |
| Fixed Swaps/Futures | (490 | ) | | (490 | ) | | — |
| | — |
| Power: | | | | | | | | Forwards | (4 | ) | | — |
| | (4 | ) | | — |
| Futures | (2 | ) | | (2 | ) | | — |
| | — |
| Natural Gas Liquids — Forwards/Swaps | (32 | ) | | (32 | ) | | — |
| | — |
| Refined Products — Futures | (7 | ) | | (7 | ) | | — |
| | — |
| Total commodity derivatives | (578 | ) | | (551 | ) | | (27 | ) | | — |
| Total liabilities | $ | (749 | ) | | $ | (551 | ) | | $ | (182 | ) | | $ | (16 | ) |
| | | | | | | | | | | | | | | | Fair Value Measurements at | | | | December 31, 2017 | | Fair Value Total | | Level 1 | | Level 2 | Assets: | | | | | | Commodity derivatives: | | | | | | Natural Gas: | | | | | | Basis Swaps IFERC/NYMEX | $ | 11 |
| | $ | 11 |
| | $ | — |
| Swing Swaps IFERC | 13 |
| | — |
| | 13 |
| Fixed Swaps/Futures | 70 |
| | 70 |
| | — |
| Forward Physical Swaps | 8 |
| | — |
| | 8 |
| Power — Forwards | 23 |
| | — |
| | 23 |
| Natural Gas Liquids — Forwards/Swaps | 193 |
| | 193 |
| | — |
| Refined Products – Futures | 1 |
| | 1 |
| | — |
| Crude – Futures | 2 |
| | 2 |
| | — |
| Total commodity derivatives | 321 |
| | 277 |
| | 44 |
| Other non-current assets | 21 |
| | 14 |
| | 7 |
| Total assets | $ | 342 |
| | $ | 291 |
| | $ | 51 |
| Liabilities: | | | | | | Interest rate derivatives | $ | (219 | ) | | $ | — |
| | $ | (219 | ) | Commodity derivatives: | | | | | | Natural Gas: | | | | | | Basis Swaps IFERC/NYMEX | (24 | ) | | (24 | ) | | — |
| Swing Swaps IFERC | (15 | ) | | (1 | ) | | (14 | ) | Fixed Swaps/Futures | (57 | ) | | (57 | ) | | — |
| Forward Physical Swaps | (2 | ) | | — |
| | (2 | ) | Power — Forwards | (22 | ) | | — |
| | (22 | ) | Natural Gas Liquids — Forwards/Swaps | (192 | ) | | (192 | ) | |
|
| Refined Products – Futures | (28 | ) | | (28 | ) | | — |
| Crude — Futures | (1 | ) | | (1 | ) | | — |
| Total commodity derivatives | (341 | ) | | (303 | ) | | (38 | ) | Total liabilities | $ | (560 | ) | | $ | (303 | ) | | $ | (257 | ) |
| | | | | | | | | | | | | | | | | | Fair Value Measurements at December 31, 2013 | | Fair Value Total | | Level 1 | | Level 2 | | Level 3 | Assets: | | | | | | | | Interest rate derivatives | $ | 47 |
| | $ | — |
| | $ | 47 |
| | $ | — |
| Commodity derivatives: | | | | | | | | Natural Gas: | | | | | | | | Basis Swaps IFERC/NYMEX | 5 |
| | 5 |
| | — |
| | — |
| Swing Swaps IFERC | 8 |
| | 1 |
| | 7 |
| | — |
| Fixed Swaps/Futures | 203 |
| | 201 |
| | 2 |
| | — |
| Natural Gas Liquids — Forwards/Swaps | 7 |
| | 5 |
| | 2 |
| | — |
| Power — Forwards | 3 |
| | — |
| | 3 |
| | — |
| Refined Products – Futures | 5 |
| | 5 |
| | — |
| | — |
| Total commodity derivatives | 231 |
| | 217 |
| | 14 |
| | — |
| Total assets | $ | 278 |
| | $ | 217 |
| | $ | 61 |
| | $ | — |
| Liabilities: | | | | | | | | Interest rate derivatives | $ | (95 | ) | | $ | — |
| | $ | (95 | ) | | $ | — |
| Embedded derivatives in the Regency Preferred Units | (19 | ) | | — |
| | — |
| | (19 | ) | Commodity derivatives: | | | | | | | | Condensate — Forward Swaps | (1 | ) | | — |
| | (1 | ) | | — |
| Natural Gas: | | | | | | | | Basis Swaps IFERC/NYMEX | (4 | ) | | (4 | ) | | — |
| | — |
| Swing Swaps IFERC | (6 | ) | | — |
| | (6 | ) | | — |
| Fixed Swaps/Futures | (206 | ) | | (201 | ) | | (5 | ) | | — |
| Forward Physical Contracts | (1 | ) | | — |
| | (1 | ) | | — |
| Natural Gas Liquids — Forwards/Swaps | (9 | ) | | (5 | ) | | (4 | ) | | — |
| Power — Forwards | (1 | ) | | — |
| | (1 | ) | | — |
| Refined Products – Futures | (5 | ) | | (5 | ) | | — |
| | — |
| Total commodity derivatives | (233 | ) | | (215 | ) | | (18 | ) | | — |
| Total liabilities | $ | (347 | ) | | $ | (215 | ) | | $ | (113 | ) | | $ | (19 | ) |
At December 31, 2013, the fair value of the Lake Charles LNG reporting unit was classified as Level 3 of the fair value hierarchy due to the significance of unobservable inputs developed using company-specific information. We used the income approach to measure the fair value of the Lake Charles LNG reporting unit. Under the income approach, we calculated the fair value based on the present value of the estimated future cash flows. The discount rate used, which was an unobservable input, was based on the weighted-average cost of capital adjusted for the relevant risk associated with business-specific characteristics and the uncertainty related to the business's ability to execute on the projected cash flows.
The following table presents the material unobservable inputs used to estimate the fair value of Regency’s Preferred Units and the embedded derivatives in Regency’s Preferred Units:
| | | | | | | Unobservable Input | | December 31, 2014 | Embedded derivatives in the Regency Preferred Units | Credit Spread | | 4.76 | % | | Volatility | | 35.80 | % |
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 Regency’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 Regency Preferred Units. Changes in Regency’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, 2014. There were no transfers between the fair value hierarchy levels during the years ended December 31, 2014 or 2013.
| | | | | Balance, December 31, 2013 | $ | (19 | ) | Net unrealized gains included in other income (expense) | 3 |
| Balance, December 31, 2014 | $ | (16 | ) |
| | | | | | | | | | | | | | | | | | | | 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 ETP’sSunoco LP’s retail marketing operationslocations where Sunoco LP holds the inventory were $2.46 billion, $2.22 billion$234 million, $243 million and $573$231 million for the years ended December 31, 2014, 20132017, 2016 and 2012,2015, 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, 2014, 20132017, 2016, and 2012,2015, 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 Susser and ETP Holdco, which owns Sunoco, Inc.Inland Corporation, Oasis Pipeline Company, Susser Petroleum Property Company, Aloha Petroleum and Panhandle.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 partythird-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“Gains (losses) on interest rate derivativesderivatives” 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 throughwithin AOCI in equity or, are reflectedfor entities applying regulatory accounting, as a regulatory asset or regulatory liability for regulated entities.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: |
Pending Transaction2018 Transactions
Regency MergerCDM Contribution Agreement
In January 2015,2018, ETP and Regency entered into a definitive mergercontribution agreement as amended on February 18, 2015 (the “Merger(“CDM Contribution Agreement”), with ETP GP, ETC Compression, LLC, USAC and ETE, pursuant to which, Regencyamong other things, ETP will mergecontribute 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 wholly-owned subsidiaryvalue of ETP,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 Regency continuing as the surviving entitya value of approximately $112 million and becoming a wholly-owned subsidiary of ETP (the “Regency Merger”). At the effective time of the Regency Merger (the “Effective Time”), each Regency common unit and Class F unit will be converted into the right to receive 0.4066 ETP Common Units, plus a number of additional ETP Common Units(iii) an amount in cash equal to $0.32 per Regency common unit divided by the lesser of (i) the volume weighted average price of$1.225 billion, subject to certain adjustments. The Class B Units that ETP Common Units for the five trading days ending on the third trading day immediately preceding the Effective Time and (ii) the closing price of ETP Common Units on the third trading day immediately preceding the Effective Time, rounded to the nearest ten thousandth of a unit. Each Regency series A preferred unitwill receive will be converted into the right to receive a preferred unit representing a limited partner interest in ETP, a new class of units in ETP to be established at the Effective Time. The transaction is subject to other customary closing conditions including approval by Regency’s unitholders. In addition, ETE, which owns the general partner and 100%partnership interests of USAC that will have substantially all of the incentive distribution rights and obligations of both Regency and ETP, has agreeda USAC Common Unit, except the Class B Units will not participate in distributions made prior to reduce the incentive distributions it receives from ETP by a totalone year anniversary of $320 million over a five year period. The IDR subsidythe 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 be $80 million in the first year post closing and $60 million per year for the following four years.automatically convert into one USAC Common Unit. The transaction is expected to close in the second quarterfirst half of 2015.
ETP and Regency are under common control of ETE; therefore, we expect2018, subject to account for the Regency Merger at historical cost as a reorganization of entities under common control. Accordingly, ETP’s consolidated financial statements will be retrospectively adjusted to reflect consolidation of Regency beginning May 26, 2010 (the date ETE acquired Regency’s general partner).
2014 Transactions
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.customary closing conditions.
In connection with the Susser Merger,CDM Contribution Agreement, ETP acquired an indirect 100% equity interestentered 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 Susser andUSA Compression GP, LLC, the general partner interestof 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 incentive distributionreal 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 Sunoco LP,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. PennTex Acquisition On November 1, 2016, ETP acquired certain interests in PennTex from various parties for total consideration of approximately 11$627 million Sunoco LP common and subordinatedin ETP units and Susser’scash. Through this transaction, ETP acquired a controlling financial interest in PennTex, whose assets complement ETP’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 itsmidstream footprint in northern Louisiana. As discussed in Note 8, ETP purchased PennTex’s remaining outstanding common stock discontinued trading on the NYSE.units in June 2017.
Summary of Assets Acquired and Liabilities Assumed We accounted for the Susser MergerPennTex 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. Our consolidated balance sheet as of December 31, 2014 reflected the preliminary The total purchase price allocations based on available information. Management is reviewing the valuation and confirming the results to determine the final purchase price allocation.
The following table summarizes the preliminary assets acquired and liabilities assumed recognizedwas allocated as of the merger date:follows:
| | | | Susser | | At November 1, 2016 | Total current assets | | $ | 446 |
| | $ | 34 |
| Property, plant and equipment | | 1,069 |
| | 393 |
| Goodwill(1) | | 1,734 |
| | 177 |
| Intangible assets | | 611 |
| | 446 |
| Other non-current assets | | 17 |
| | | | 3,877 |
| | 1,050 |
| | | | | | Total current liabilities | | 377 |
| | 6 |
| Long-term debt, less current maturities | | 564 |
| | 164 |
| Deferred income taxes | | 488 |
| | Other non-current liabilities | | 39 |
| | 17 |
| Noncontrolling interest | | 626 |
| | 236 |
| | | 2,094 |
| | 423 |
| Total consideration | | 1,783 |
| | 627 |
| Cash received | | 67 |
| | 21 |
| Total consideration, net of cash received | | $ | 1,716 |
| | $ | 606 |
|
| | (1) | None of the goodwill is expected to be deductible for tax purposes. |
The fair values of the assets acquired and liabilities assumed is being 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 for the Susser Merger, as the impact of this acquisition was not material in relation to our consolidated results of operations.
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.
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 9.
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). In connection with the Panhandle Merger, Panhandle also assumed PEPL Holdings’ guarantee of $600 million of Regency senior notes.
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. The PVR Acquisition enhances Regency’s geographic diversity with a strategic presence in the Marcellus and Utica shales in the Appalachian Basin and the Granite Wash in the Mid-Continent region. Regency accounted for the PVR 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. 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 | 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 |
|
The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.
Regency’s
Sunoco Logistics’ Vitol Acquisition In November 2016, Sunoco Logistics completed an acquisition from Vitol, Inc. (“Vitol”) of Eagle Rock’s Midstream Businessan 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’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”), which increased Sunoco 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. On July 1, 2014, Regency acquired Eagle Rock’s midstream business (the “Eagle Rock Midstream Acquisition”) for $1.3 billion, includingBakken Financing
In August 2016, ETP and Phillips 66 announced the assumption of $499 million of Eagle Rock’s 8.375% senior notes due 2019. The remaindercompletion of the purchase priceproject-level financing of the Bakken Pipeline. The $2.50 billion credit facility provided substantially all of the remaining capital necessary to complete the projects. As of December 31, 2017, $2.50 billion was funded by $400outstanding 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, 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 in Regency Common Units soldSunoco LP common units to Retail Holdings, a wholly-owned subsidiary of ETE, 8.2the 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, Regency Common Unitsincluding tax deductible goodwill of $53 million and intangible assets of $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 in 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 Eagle RockETP 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 borrowings under Regency’s revolving credit facility. Regency accounted for the Eagle Rock Midstream Acquisition using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognizedconverted on a one-for-one basis into Sunoco LP common units on the balance sheet at their fair valuesday 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 acquisition date. This acquisition complements Regency’s core gathering and processing business and further diversifies Regency’s geographic presencetransaction. Sunoco LP subsequently contributed its interests in the Mid-Continent region, east Texas and south Texas. Our consolidated statementSusser to one 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.its subsidiaries.
Regency’s evaluation
Effective July 1, 2015, ETE acquired 100% of the assigned fair values is ongoing. The table below represents a preliminary allocationmembership interests of Sunoco GP, the total purchase price: | | | | | Assets | At July 1, 2014 | Current assets | $ | 120 |
| Property, plant and equipment | 1,295 |
| Other non-current assets | 4 |
| Goodwill(1) | 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 |
|
| | (1)
| None of the goodwill is expected to be deductible for tax purposes. |
The fair valuesgeneral partner of the assets acquiredSunoco LP, and liabilities assumed is being determined using various valuation techniques, including the income and market approaches.
Regency’s Acquisition of Hoover Energy
On February 3, 2014, Regency completed its acquistion of certain subsidiaries of Hoover Energy for a total purchase price of $293 million, consisted of (i) 4.0 million Regency Common Units issued to Hoover Energy, (ii) $184 million in cash. and (iii) $2 million in asset retirement obligations assumed.
2013 Transactions
Sale of Southern Union’s Distribution Operations
In December 2012, Southern Union entered into a purchase and sale agreement with The Laclede Group, Inc., pursuant to which Laclede Missouri agreed to acquire the assets of Southern Union’s MGE division and Laclede Massachusetts agreed to acquire the assets of Southern Union NEG division (together, the “LDC Disposal Group”). Laclede Gas Company, a subsidiary of The Laclede Group, Inc., subsequently assumed all of Laclede Missouri’s rights and obligations under the purchase and sale agreement. In February 2013, The Laclede Group, Inc. entered into an agreement with Algonquin Power & Utilities Corp (“APUC”) that allowed a subsidiary of APUC to assume the rights of The Laclede Group, Inc. to purchase the assets of Southern Union’s NEG division.
In September 2013, Southern Union completed its sale of the assets of MGE for an aggregate purchase price of $975 million, subject to customary post-closing adjustments. In December 2013, Southern Union completed its sale of the assets of NEG for cash proceeds of $40 million, subject to customary post-closing adjustments, and the assumption of $20 million of debt.
The LDC Disposal Group’s operations have been classified as discontinued operations for all periods in the consolidated statements of operations.
The following table summarizes selected financial information related to Southern Union’s distribution operations in 2013 through MGE and NEG’s sale dates in September 2013 and December 2013, respectively, and for the period from March 26, 2012 to December 31, 2012:
| | | | | | | | | | Years Ended December 31, | | 2013 | | 2012 | Revenue from discontinued operations | $ | 415 |
| | $ | 324 |
| Net income of discontinued operations, excluding effect of taxes and overhead allocations | 65 |
| | 43 |
|
SUGS Contribution
On April 30, 2013, Southern Union completed its contribution to Regency of all of the issued and outstanding membership interest in Southern Union Gathering Company, LLC, and its subsidiaries, including SUGS (the “SUGS Contribution”). The general partner and IDRs of Regency areSunoco LP from ETP, and in exchange, ETP repurchased from ETE 31.5 million ETP common units owned by ETE. The consideration paid by Regency inIn connection with this transaction consistedETP’s 2014 acquisition of (i) the issuance of approximately 31.4Susser, ETE agreed to provide ETP a $35 million Regency common units to Southern Union, (ii) the issuance of approximately 6.3 million Regency Class F units to Southern Union, (iii) the distribution of $463 million in cash to Southern Union, net of closing adjustments, and (iv) the payment of $30 million in cash to a subsidiary of ETP. This transaction was between commonly controlled entities; therefore, the amounts recorded in the consolidated balance sheet annual IDR subsidy for the investment in Regency and the related deferred tax liabilities were based on the historical book value of SUGS. In addition, PEPL Holdings, provided a guarantee of collection with respect to the payment of the principal amounts of Regency’s debt related to the SUGS Contribution. The Regency Class F units have the same rights, terms and conditions as the Regency common units, except that Southern Union will not receive distributions on the Regency Class F units for the first eight consecutive quarters following10 years, which terminated upon the closing and the Regency Class F units will thereafter automatically convert into Regency common units on a one-for-one basis.
ETP’s Acquisition of ETE’s acquisition of Sunoco GP. In connection with the exchange and repurchase, ETE will provide ETP Holdco Interest
On April 30, 2013, ETP acquired ETE’s 60% interest in ETP Holdcoa $35 million annual IDR subsidy for approximately 49.5 million of newly issued ETP Common Units and $1.40 billion in cash, less $68 million of closing adjustments (the “ETP Holdco Acquisition”). As a result, ETP now owns 100% of ETP Holdco. ETE, which owns the general partner and IDRs of ETP, agreed to forego incentive distributions on the newly issued ETP units for each of the first eight consecutive quarterstwo years beginning with the quarter in which the closing of the transaction occurred and 50% of incentive distributions on the newly issuedended September 30, 2015.
Bakken Pipeline In March 2015, ETE transferred 46.2 million ETP common units, for the following eight consecutive quarters. ETP controlled ETP Holdco prior to this acquisition; therefore, the transaction did not constitute a change of control. 2012 Transactions
Southern Union Merger
On March 26, 2012, ETE completed its acquisition of Southern Union. Southern Union was the surviving entityETE’s 45% interest in the mergerBakken Pipeline project, and operated as a wholly-owned subsidiary of ETE until our contribution to ETP Holdco discussed below.
Under the terms of the merger agreement, Southern Union stockholders received a total of approximately 57$879 million ETE Common Units and a total of approximately $3.01 billion in cash. Effective with the closing of the transaction, Southern Union’s common stock was no longer publicly traded.
Citrus Acquisition
In connection with the Southern Union Merger on March 26, 2012, ETP completed its acquisition of CrossCountry, a subsidiary of Southern Union which owned an indirect 50% interest in Citrus, the owner of FGT. The total merger consideration was approximately $2.0 billion, consisting of approximately $1.9 billion in cash and approximately 2.2 million ETP Common Units. See Note 4 for more information regarding ETP’s equity method investment in Citrus.
Sunoco Merger
On October 5, 2012, ETP completed its merger with Sunoco, Inc. Under the terms of the merger agreement, Sunoco, Inc. shareholders received a total of approximately 55 million ETP Common Units and a total of approximately $2.6 billion in cash.
Sunoco, Inc. generates cash flow from a portfolio of retail outlets for the sale of gasoline and middle distillates in the east coast, midwest and southeast areas of the United States. Prior to October 5, 2012, Sunoco, Inc. also owned a 2% general partner interest, 100% of the IDRs, and 32% of the outstanding common units of Sunoco Logistics. As discussed below, on October 5, 2012, Sunoco, Inc.’s interests in Sunoco Logistics were transferred to ETP.
Prior to the Sunoco Merger, on September 8, 2012, Sunoco, Inc. completed the exit from its Northeast refining operations by contributing the refining assets at its Philadelphia refinery and various commercial contracts to PES, a joint venture with The Carlyle Group, L.P. (“The Carlyle Group”). Sunoco, Inc. also permanently idled the main refining processing units at its Marcus Hook refinery in June 2012. The Marcus Hook Industrial Complex continued to support operations at the Philadelphia refinery prior to commencement of the PES joint venture. Under the terms of the joint venture agreement, The Carlyle Group contributed cash in exchange for a 67% controlling interest in PES. In exchange for contributing its Philadelphia refinery assets and various commercial contracts to the joint venture, Sunoco, Inc. retained an approximately 33% non-operating noncontrolling interest. The fair value of Sunoco, Inc.’s retained interest in PES, which was $75 million on the date on which the joint venture was formed, was determined based on the equity contributions of The Carlyle Group. Sunoco, Inc. has indemnified PES for environmental liabilities related to the Philadelphia refinery that arose from the operation of such assets prior the formation of the joint venture. The Carlyle Group will oversee day-to-day operations of PES and the refinery. JPMorgan Chase provides working capital financing to PES in the form of an asset-backed loan, supply crude oil and other feedstocks to the refinery at the time of processing and purchase certain blendstocks and all finished refined products as they are processed. Sunoco, Inc. entered into a supply contract for gasoline and diesel produced at the refinery for its retail marketing business.
ETP incurred merger related costs related to the Sunoco Merger of $28 million during the year ended December 31, 2012. Sunoco, Inc.’s revenue included in our consolidated statement of operations was approximately $5.93 billion during October through December 2012. Sunoco, Inc.’s net loss included in our consolidated statement of operations was approximately $14 million during October through December 2012. Sunoco Logistics’ revenue included in our consolidated statement of operations was approximately $3.11 billion during October through December 2012. Sunoco Logistics’ net income included in our consolidated statement of operations was approximately $145 million during October through December 2012.
ETP Holdco Transaction
Immediately following the closing of the Sunoco Merger, ETE contributed its interest in Southern Union into ETP Holdco, an ETP-controlled entity, in exchange for a 60% equity interest in ETP Holdco. In conjunction with ETE’s contribution, ETP contributed its interest in Sunoco, Inc. to ETP Holdco and retained a 40% equity interest in ETP Holdco. Prior to the contribution of Sunoco, Inc. to ETP Holdco, Sunoco, Inc. contributed $2.0 billion of cash and its interests in Sunoco Logistics to ETP in exchange for 90.730.8 million newly issued ETP Class H Units that, when combined with the 50.2 million previously issued ETP Class H Units, generally entitled 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 provided 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 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 and 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 FB 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 Units”). The Class Funit was converted into the right to receive 0.6186 common units of ETP. ETP issued 258.3 million ETP common units to Regency unitholders, including 23.3 million units issued to ETP subsidiaries. Regency’s 1.9 million outstanding Series A Convertible Preferred Units were exchanged for Class Gconverted into corresponding new ETP Series A Convertible Preferred Units in 2013 as discussed in Note 9. Pursuant toon a stockholders agreement between ETE and ETP, ETP controlled ETP Holdco (prior to ETP’s acquisition of ETE’s 60% equity interest in ETP Holdco in 2013) and therefore, ETP consolidated ETP Holdco (including Sunoco, Inc. and Southern Union) in its financial statements subsequent to consummation ofone-for-one basis. In connection with the ETP Holdco Transaction. Under the terms of the ETP Holdco transaction agreement,Regency Merger, ETE agreed to relinquish its right to $210 million ofreduce the incentive distributions it receives from ETP that ETE would otherwise be entitled to receiveby a total of $320 million over 12 consecutive quarters beginning with the distribution paid on November 14, 2012.
Summary of Assets Acquired and Liabilities Assumed
We accounteda five-year period. The IDR subsidy was $80 million for the Southern Union Merger and Sunoco 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 as of the respective acquisition dates:
| | | | | | | | | | Sunoco, Inc.(1) | | Southern Union(2) | Current assets | $ | 7,312 |
| | $ | 556 |
| Property, plant and equipment | 6,686 |
| | 6,242 |
| Goodwill | 2,641 |
| | 2,497 |
| Intangible assets | 1,361 |
| | 55 |
| Investments in unconsolidated affiliates | 240 |
| | 2,023 |
| Note receivable | 821 |
| | — |
| Other assets | 128 |
| | 163 |
| | 19,189 |
| | 11,536 |
| | | | | Current liabilities | 4,424 |
| | 1,348 |
| Long-term debt obligations, less current maturities | 2,879 |
| | 3,120 |
| Deferred income taxes | 1,762 |
| | 1,419 |
| Other non-current liabilities | 769 |
| | 284 |
| Noncontrolling interest | 3,580 |
| | — |
| | 13,414 |
| | 6,171 |
| Total consideration | 5,775 |
| | 5,365 |
| Cash received | 2,714 |
| | 37 |
| Total consideration, net of cash received | $ | 3,061 |
| | $ | 5,328 |
|
| | (1)
| Includes amounts recorded with respect to Sunoco Logistics. |
| | (2)
| Includes ETP’s acquisition of Citrus. |
The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.
As a result of the Southern Union Merger, we recognized $38 million of merger-related costs during the year ended December 31, 2012. Southern Union’s revenue included in our consolidated statement2015 and will total $60 million per year for the following four years.
ETP has assumed all of operations was approximately $1.26 billion since the acquisition date to December 31, 2012. Southern Union’s net income included in our consolidated statementobligations of operations was approximately $39 million since the acquisition date to December 31, 2012. Propane Operations
On January 12, 2012, ETP contributed its propane operations, consistingRegency and Regency Energy Finance Corp., of HOLP and Titan to AmeriGas. ETP received approximately $1.46 billion in cash and approximately 29.6 million AmeriGas common units. AmeriGas assumed approximately $71 million of existing HOLP debt. In connection with the closing of this transaction, ETP entered into a support agreement with AmeriGas pursuant to which ETP is obligated to provide contingent, residual support of $1.50 billion of intercompany indebtedness owed by AmeriGas towas previously a finance subsidiary that in turn supports the repayment of $1.50 billion of senior notes issued by this AmeriGas finance subsidiary to finance the cash portion of the purchase price.co-obligor or parent guarantor.
Our consolidated financial statements did not reflect the Propane Business as discontinued operations due to ETP’s continuing involvement in this business through their investment in AmeriGas that was transferred to ETP as consideration for the transaction.
In June 2012, ETP sold the remainder of its retail propane operations, consisting of its cylinder exchange business, to a third party. In connection with the contribution agreement with AmeriGas, certain excess sales proceeds from the sale of the cylinder exchange business were remitted to AmeriGas, and ETP received net proceeds of approximately $43 million.
Sale of Canyon
In October 2012, ETP sold Canyon for approximately $207 million. The results of continuing operations of Canyon have been reclassified to loss from discontinued operations. A write down of the carrying amounts of the Canyon assets to their fair values was recorded for approximately $132 million during the year ended December 31, 2012.
Pro Forma Results of Operations
The following unaudited pro forma consolidated results of operations for the years ended December 31, 2014, 2013 and 2012 are presented as if Sunoco Merger and the ETP Holdco Transaction had been completed on January 1, 2012, and the PVR and Eagle Rock Midstream acquisitions had been completed on January 1, 2013, and assumes there were no other changes in operations.
| | | | | | | | | | | | | | Years Ended December 31, | | 2014 | | 2013 | | 2012 | Revenues | $ | 56,517 |
| | $ | 50,473 |
| | $ | 40,398 |
| Net income | 1,098 |
| | 252 |
| | 868 |
| Net income attributable to partners | 607 |
| | 133 |
| | 866 |
| Basic net income per Limited Partner unit | $ | 1.12 |
| | $ | 0.24 |
| | $ | 1.55 |
| Diluted net income per Limited Partner unit | $ | 1.11 |
| | $ | 0.24 |
| | $ | 1.55 |
|
The pro forma consolidated results of operations include adjustments to:
include the results of Southern Union and Sunoco, Inc. beginning January 1, 2012;
include the results of PVR and Eagle Rock midstream beginning January 1, 2013;
include the incremental expenses associated with the fair value adjustments recorded as a result of applying the acquisition method of accounting; and
•include incremental interest expense related to the financing of a proportionate share of the purchase price.
The pro forma information is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations.
| | 4. | ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES: |
AmeriGas
As discussed in Note 3, on January 12, 2012, ETP received approximately 29.6 million AmeriGas common units in connection with the contribution of its propane operations. In the year ended 2013, ETP sold 7.5 million AmeriGas common units for net proceeds of $346 million, and in the year ended 2014, ETP sold approximately 18.9 million AmeriGas common units for net proceeds of $814 million. Net proceeds from these sales were used to repay borrowings under the ETP Credit Facility and general partnership purposes. Subsequent to the sales, ETP’s remaining interest in AmeriGas common units consisted of 3.1 million units held by a wholly-owned captive insurance company.
Citrus On March 26, 2012, ETE consummated the acquisition of Southern Union and, concurrently with the closing of the Southern Union acquisition, CrossCountry, a subsidiary of Southern Union that indirectly owned a 50% interest in Citrus, merged with a subsidiary of ETP and, in connection therewith, ETP paid approximately $1.9 billion in cash and issued $105 million of ETP Common Units (the “Citrus Acquisition”) to a subsidiary of ETE. As a result of the consummation of the Citrus Acquisition, ETP owns CrossCountry, which in turn owns a 50% interest in Citrus. The other 50% interest in Citrus is owned by a subsidiary of Kinder Morgan, Inc.KMI. Citrus owns 100% of FGT, a natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula.
ETP recorded its investment in Citrus at $2.0 billion, which exceeded its proportionate share of Citrus’ equity by $1.03 billion, all of which is treated as equity method goodwill due to the application of regulatory accounting. The carrying amount of ETP’s investment in Citrus was $1.82 billion and $1.89 billion at December 31, 2014 and 2013, respectively, and was reflected in ETP’s interstate transportation and storage operations.
FEP ETP has a 50% interest in FEP a 50/50 joint venture with Kinder Morgan, Inc. FEPwhich owns the Fayetteville Express pipeline, 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. The carrying amount of ETP’sETP evaluated its investment in FEP was $130 million and $144 millionfor impairment as of December 31, 20142017, based on FASB Accounting Standards Codification 323, Investments - Equity Method and 2013, respectively,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 was reflected in ETP’s interstate transportation and storage operations.a customer re-contracting with a competitor. Midcontinent Express Pipeline LLC
MEP RegencyETP owns a 50% interest in MEP, which owns approximately 500 miles of natural gas pipelinespipeline that extendextends from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama. The carrying amount of Regency’sETP evaluated its investment in MEP was $695 million and $548 millionfor 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, 2014 and 2013, respectively, and was reflected in Regency’s natural gas transportation operations.2016.
RIGS Haynesville Partnership Co.HPC
RegencyETP 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. The carrying amount of Regency’sETP evaluated its investment in HPC was $422 million and $442 millionfor impairment as of December 31, 20142017, based on FASB Accounting Standards Codification 323, Investments - Equity Method and 2013, respectively,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 was reflectedcash flows driven by the bankruptcy of one of HPC’s major customers in Regency’s natural gas transportation operations.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% basisbasis) for all periods presented). presented: | | | December 31, | December 31, | | 2014 | | 2013 | 2017 | | 2016 | Current assets | $ | 889 |
| | $ | 1,028 |
| $ | 206 |
| | $ | 214 |
| Property, plant and equipment, net | 10,520 |
| | 10,778 |
| 8,336 |
| | 8,726 |
| Other assets | 2,687 |
| | 2,664 |
| 43 |
| | 181 |
| Total assets | $ | 14,096 |
| | $ | 14,470 |
| $ | 8,585 |
| | $ | 9,121 |
| | | | | | | | Current liabilities | $ | 1,983 |
| | $ | 1,039 |
| $ | 861 |
| | $ | 816 |
| Non-current liabilities | 7,359 |
| | 8,139 |
| 4,492 |
| | 4,940 |
| Equity | 4,754 |
| | 5,292 |
| 3,232 |
| | 3,365 |
| Total liabilities and equity | $ | 14,096 |
| | $ | 14,470 |
| $ | 8,585 |
| | $ | 9,121 |
|
| | | Years Ended December 31, | Years Ended December 31, | | 2014 | | 2013 | | 2012 | 2017 | | 2016 | | 2015 | Revenue | $ | 4,925 |
| | $ | 4,695 |
| | $ | 4,492 |
| $ | 1,358 |
| | $ | 1,164 |
| | $ | 1,385 |
| Operating income | 1,071 |
| | 1,197 |
| | 863 |
| 407 |
| | 714 |
| | 800 |
| Net income | 577 |
| | 699 |
| | 491 |
| 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 RegencySunoco LP that would have resulted assuming the incremental units related to ETP’s or Regency’sSunoco 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. The calculation below for the year ended December 31, 2012 for diluted net income per limited partner unit excludes the impact of any ETE Common Units that would be issued upon conversion of the Preferred Units, because inclusion would have been antidilutive. The Preferred Units were redeemed April 1, 2013 as discussed in Note 7.
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, | | 2014 | | 2013 | | 2012 | 2017 | | 2016 | | 2015 | Income from continuing operations | $ | 1,060 |
| | $ | 282 |
| | $ | 1,383 |
| $ | 2,543 |
| | $ | 462 |
| | $ | 1,023 |
| Less: Income from continuing operations attributable to noncontrolling interest | 434 |
| | 99 |
| | 1,070 |
| | Less: Income (loss) from continuing operations attributable to noncontrolling interest | | 1,583 |
| | (545 | ) | | (165 | ) | Income from continuing operations, net of noncontrolling interest | 626 |
| | 183 |
| | 313 |
| 960 |
| | 1,007 |
| | 1,188 |
| Less: General Partner’s interest in income from continuing operations | 2 |
| | — |
| | 1 |
| 2 |
| | 3 |
| | 3 |
| Less: Convertible Unitholders’ interest in net income from continuing operations | | 38 |
| | 8 |
| | — |
| Less: Class D Unitholder’s interest in income from continuing operations | 2 |
| | — |
| | — |
| — |
| | — |
| | 3 |
| Income from continuing operations available to Limited Partners | $ | 622 |
| | $ | 183 |
| | $ | 312 |
| $ | 920 |
| | $ | 996 |
| | $ | 1,182 |
| Basic Income from Continuing Operations per Limited Partner Unit: | | | | | | | | | | | Weighted average limited partner units | 544.3 |
| | 560.9 |
| | 533.4 |
| 1,078.2 |
| | 1,045.5 |
| | 1,062.8 |
| Basic income from continuing operations per Limited Partner unit | $ | 1.15 |
| | $ | 0.33 |
| | $ | 0.59 |
| $ | 0.86 |
| | $ | 0.95 |
| | $ | 1.11 |
| Basic income (loss) from discontinued operations per Limited Partner unit | $ | 0.01 |
| | $ | 0.02 |
| | $ | (0.02 | ) | $ | (0.01 | ) | | $ | (0.01 | ) | | $ | — |
| Diluted Income from Continuing Operations per Limited Partner Unit: | | | | | | | | | | | Income from continuing operations available to Limited Partners | $ | 622 |
| | $ | 183 |
| | $ | 312 |
| $ | 920 |
| | $ | 996 |
| | $ | 1,182 |
| Dilutive effect of equity-based compensation of subsidiaries and distributions to Class D Unitholder | (2 | ) | | — |
| | (1 | ) | | Dilutive effect of equity-based compensation of subsidiaries, distributions to Class D Unitholder and Convertible Units | | 38 |
| | 8 |
| | 3 |
| Diluted income from continuing operations available to Limited Partners | 620 |
| | 183 |
| | 311 |
| 958 |
| | 1,004 |
| | 1,185 |
| Weighted average limited partner units | 544.3 |
| | 560.9 |
| | 533.4 |
| 1,078.2 |
| | 1,045.5 |
| | 1,062.8 |
| Dilutive effect of unconverted unit awards | 1.1 |
| | — |
| | — |
| | Dilutive effect of unconverted unit awards and Convertible Units | | 72.6 |
| | 33.1 |
| | 1.6 |
| Weighted average limited partner units, assuming dilutive effect of unvested unit awards | 545.4 |
| | 560.9 |
| | 533.4 |
| 1,150.8 |
| | 1,078.6 |
| | 1,064.4 |
| Diluted income from continuing operations per Limited Partner unit | $ | 1.14 |
| | $ | 0.33 |
| | $ | 0.59 |
| $ | 0.84 |
| | $ | 0.93 |
| | $ | 1.11 |
| Diluted income (loss) from discontinued operations per Limited Partner unit | $ | 0.01 |
| | $ | 0.02 |
| | $ | (0.02 | ) | $ | (0.01 | ) | | $ | (0.01 | ) | | $ | — |
|
Our debt obligations consist of the following: | | | | | | | | | | December 31, | | 2014 | | 2013 | 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 |
| | 450 |
| ETE Senior Secured Term Loan, due December 2, 2019 | 1,400 |
| | 1,000 |
| ETE Senior Secured Revolving Credit Facility due December 18, 2018 | 940 |
| | 171 |
| Unamortized premiums, discounts and fair value adjustments, net | 3 |
| | (7 | ) | | 4,680 |
| | 2,801 |
| | | | | Subsidiary Indebtedness: | | | | ETP Debt | | | | 8.5% Senior Notes due April 15, 2014 | — |
| | 292 |
| 5.95% Senior Notes due February 1, 2015 | 750 |
| | 750 |
| 6.125% Senior Notes due February 15, 2017 | 400 |
| | 400 |
| 6.7% Senior Notes due July 1, 2018 | 600 |
| | 600 |
| 9.7% Senior Notes due March 15, 2019 | 400 |
| | 400 |
| 9.0% Senior Notes due April 15, 2019 | 450 |
| | 450 |
| 4.15% Senior Notes due October 1, 2020 | 700 |
| | 700 |
| 4.65% Senior Notes due June 1, 2021 | 800 |
| | 800 |
| 5.20% Senior Notes due February 1, 2022 | 1,000 |
| | 1,000 |
| 3.60% Senior Notes due February 1, 2023 | 800 |
| | 800 |
| 4.9% Senior Notes due February 1, 2024 | 350 |
| | 350 |
| 7.6% Senior Notes due February 1, 2024 | 277 |
| | 277 |
| 8.25% Senior Notes due November 15, 2029 | 267 |
| | 267 |
| 6.625% Senior Notes due October 15, 2036 | 400 |
| | 400 |
| 7.5% Senior Notes due July 1, 2038 | 550 |
| | 550 |
| 6.05% Senior Notes due June 1, 2041 | 700 |
| | 700 |
| 6.5% Senior Notes due February 1, 2042 | 1,000 |
| | 1,000 |
| 5.15% Senior Notes due February 1, 2043 | 450 |
| | 450 |
| 5.95% Senior Notes due October 1, 2043 | 450 |
| | 450 |
| Floating Rate Junior Subordinated Notes due November 1, 2066 | 546 |
| | 546 |
| ETP $2.5 billion Revolving Credit Facility due October 27, 2019 | 570 |
| | 65 |
| Unamortized premiums, discounts and fair value adjustments, net | (1 | ) | | (34 | ) | | 11,459 |
| | 11,213 |
| | | | | Panhandle Debt(1) | | | | 6.20% Senior Notes due November 1, 2017 | 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 14, 2029 | 33 |
| | 33 |
| Floating Rate Junior Subordinated Notes due November 1, 2066 | 54 |
| | 54 |
| Unamortized premiums, discounts and fair value adjustments, net | 99 |
| | 155 |
| | 1,184 |
| | 1,240 |
| | | | | Regency Debt | | | | 6.875% Senior Notes due December 1, 2018 | — |
| | 600 |
| 5.75% Senior Notes due September 1, 2020 | 400 |
| | 400 |
| 6.5% Senior Notes due July 15, 2021 | 500 |
| | 500 |
| 5.875% Senior Notes due March 1, 2022 | 900 |
| | — |
| 5.5% Senior Notes due April 15, 2023 | 700 |
| | 700 |
| 4.5% Senior Notes due November 1, 2023 | 600 |
| | 600 |
|
| | | | | | | | | | December 31, | | 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 |
| 5.50% Senior Notes due June 1, 2027 | 1,000 |
| | 1,000 |
| 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 |
| ETE Senior Secured Revolving Credit Facility due March 24, 2022 | 1,188 |
| | — |
| Unamortized premiums, discounts and fair value adjustments, net | (11 | ) | | (15 | ) | Deferred debt issuance costs | (34 | ) | | (30 | ) | | 6,700 |
| | 6,357 |
| | | | | Subsidiary Indebtedness: | | | | ETP Debt | | | | 6.125% Senior Notes due February 15, 2017 | — |
| | 400 |
| 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 |
| 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 |
| 4.15% Senior Notes due October 1, 2020 | 1,050 |
| | 1,050 |
| 4.40% Senior Notes due April 1, 2021 | 600 |
| | 600 |
| 6.50% Senior Notes due July 15, 2021 | — |
| | 500 |
| 4.65% Senior Notes due June 1, 2021 | 800 |
| | 800 |
| 5.20% Senior Notes due February 1, 2022 | 1,000 |
| | 1,000 |
| 4.65% Senior Notes due February 15, 2022 | 300 |
| | 300 |
| 5.875% Senior Notes due March 1, 2022 | 900 |
| | 900 |
| 5.00% Senior Notes due October 1, 2022 | 700 |
| | 700 |
| 3.45% Senior Notes due January 15, 2023 | 350 |
| | 350 |
| 3.60% Senior Notes due February 1, 2023 | 800 |
| | 800 |
| 5.50% Senior Notes due April 15, 2023 | — |
| | 700 |
| 4.50% Senior Notes due November 1, 2023 | 600 |
| | 600 |
| 4.90% Senior Notes due February 1, 2024 | 350 |
| | 350 |
| 7.60% Senior Notes due February 1, 2024 | 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 |
| 5.95% Senior Notes due December 1, 2025 | 400 |
| | 400 |
| 4.75% Senior Notes due January 15, 2026 | 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 |
| 4.90% Senior Notes due March 15, 2035 | 500 |
| | 500 |
| 6.625% Senior Notes due October 15, 2036 | 400 |
| | 400 |
| 7.50% Senior Notes due July 1, 2038 | 550 |
| | 550 |
| 6.85% Senior Notes due February 15, 2040 | 250 |
| | 250 |
| 6.05% Senior Notes due June 1, 2041 | 700 |
| | 700 |
| 6.50% Senior Notes due February 1, 2042 | 1,000 |
| | 1,000 |
| 6.10% Senior Notes due February 15, 2042 | 300 |
| | 300 |
|
| | | | | | | | | 8.375% Senior Notes due June 1, 2020 | 390 |
| | — |
| 6.5% Senior Notes due May 15, 2021 | 400 |
| | — |
| 8.375% Senior Notes due June 1, 2019 | 499 |
| | — |
| 5.0% Senior Notes due October 1, 2022 | 700 |
| | — |
| Regency $1.2 billion Revolving Credit Facility due November 25, 2019 | 1,504 |
| | 510 |
| Unamortized premiums, discounts and fair value adjustments, net | 48 |
| | — |
| | 6,641 |
| | 3,310 |
| | | | | Sunoco, Inc. Debt | | | | 4.875% Senior Notes due October 15, 2014 | — |
| | 250 |
| 9.625% Senior Notes due April 15, 2015 | 250 |
| | 250 |
| 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 | 35 |
| | 70 |
| | 750 |
| | 1,035 |
| | | | | Sunoco Logistics Debt | | | | 8.75% Senior Notes due February 15, 2014(2) | — |
| | 175 |
| 6.125% Senior Notes due May 15, 2016 | 175 |
| | 175 |
| 5.50% Senior Notes due February 15, 2020 | 250 |
| | 250 |
| 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 |
| | — |
| 6.85% Senior Notes due February 1, 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 |
| | — |
| 5.35% Senior Notes due May 15, 2045 | 800 |
| | — |
| Sunoco Logistics $35 million Revolving Credit Facility due April 30, 2015(3) | 35 |
| | 35 |
| Sunoco Logistics $1.50 billion Revolving Credit Facility due November 19, 2018 | 150 |
| | 200 |
| Unamortized premiums, discounts and fair value adjustments, net | 100 |
| | 118 |
| | 4,260 |
| | 2,503 |
| | | | | Sunoco LP Debt | | | | Sunoco LP $1.25 billion Revolving Credit Facility due September 25, 2019 | 683 |
| | — |
| | 683 |
| | — |
| | | | | Transwestern Debt | | | | 5.39% Senior Notes due November 17, 2014 | — |
| | 88 |
| 5.54% Senior Notes due November 17, 2016 | 125 |
| | 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 |
| 6.16% Senior Notes due May 24, 2037 | 75 |
| | 75 |
| Unamortized premiums, discounts and fair value adjustments, net | (1 | ) | | (1 | ) | | 781 |
| | 869 |
| | | | | Other | 223 |
| | 228 |
| | 30,661 |
| | 23,199 |
| Less: current maturities | 1,008 |
| | 637 |
| | $ | 29,653 |
| | $ | 22,562 |
|
| | | | | | | | | 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 |
| Deferred debt issuance costs | (1 | ) | | (1 | ) | | 574 |
| | 656 |
| | | | | Panhandle Debt | | | | 6.20% Senior Notes due November 1, 2017 | — |
| | 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 14, 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 |
| | | | | Sunoco LP Debt | | | | 5.50% Senior Notes due August 1, 2020 | 600 |
| | 600 |
| 6.375% Senior Notes due April 1, 2023 | 800 |
| | 800 |
| 6.25% Senior Notes due April 15, 2021 | 800 |
| | 800 |
| Sunoco LP $1.50 billion Revolving Credit Facility due September 25, 2019 | 765 |
| | 1,000 |
| Sunoco LP Term Loan due October 1, 2019 | 1,243 |
| | 1,243 |
| Lease-related obligations | 113 |
| | 118 |
| Deferred debt issuance costs | (34 | ) | | (47 | ) | | 4,287 |
| | 4,514 |
|
| | | | | | | | | | | | | Other | 8 |
| | 31 |
| 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) | In connection withAs of December 31, 2017 ETP’s management had the Panhandle Merger, Southern Union’s debt obligations were assumed by Panhandle.intent and ability to refinance the $650 million 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) | Sunoco Logistics’ 8.75% senior notes due February 15, 2014Borrowings under 364-day credit facilities were classified as long-term debt as Sunoco Logistics repaid these notes in February 2014 with borrowings under its $1.50 billion credit facility due November 2018. |
| | (3)
| The Sunoco Logistics $35 million credit facility outstanding amounts were classified as long-term debt 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 $283$197 million in unamortized premiums, and fair value adjustments and deferred debt issuance costs, net: | | 2015 | $ | 1,050 |
| | 2016 | 314 |
| | 2017 | 1,228 |
| | 2018 | 2,095 |
| $ | 1,705 |
| 2019 | 5,662 |
| 5,512 |
| 2020 | | 3,667 |
| 2021 | | 2,205 |
| 2022 | | 6,540 |
| Thereafter | 20,029 |
| 24,652 |
| Total | $ | 30,378 |
| $ | 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 and Regency constitute substantial portions of the collateral for the Parent Company’s outstanding senior notes; accordingly, financial statements of ETP and Regency 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 ETE Common Holdings, LLC, ETE GP Acquirer LLC, and Regency GP LP (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, Regency and/or the consolidated subsidiaries of ETP and Regency. 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 and Regency, as applicable: 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 $11.9$28.02 billion and $11.3$18.41 billion as of December 31, 20142017 and 2013,2016, 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, and Class H unitholders)unitholders, Class I unitholders and ETP Preferred Units) of $823 million, $(50)$1.08 billion, $(660) million and $1.11 billion$325 million for the years ended December 31, 2014, 20132017, 2016 and 2012,2015, respectively, would be reflected as income attributable to noncontrolling interest in ETP GP’s statements of operations. ETE Common Holdings, LLC (“ETE Common Holdings”) owns 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 owns 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. ETE Common Holdings does not own the general partner interests in ETP or Regency; therefore, the financial statements of ETE Common Holdings would only reflect equity method investments in ETP and Regency. The carrying values of ETE Common Holdings’ investments in ETP and Regency were $1.72 billion and $760 million, respectively, as of December 31, 2014 and $1.66 billion and zero, respectively, as of December 31, 2013. ETE Common Holdings’ equity in earnings (losses) from its investments in ETP and Regency were $292 million and $(9) million, respectively, for the year ended December 31, 2014 and $134 million and zero, respectively, for the period from April 26, 2013 (inception of ETE Common Holdings) to December 31, 2013.
ETE GP Acquirer LLC (“ETE GP Acquirer”) owns 100% of Regency GP, which owns 100% of the general partner interest in Regency. Neither ETE GP Acquirer nor Regency GP own limited partner interests in Regency; therefore, the limited partner interests in Regency, which had a carrying value of $8.7 billion and $4.0 billion as of December 31, 2014 and 2013, respectively, would be reflected as noncontrolling interests on ETE GP Acquirer’s and Regency GP’s balance sheets. Likewise, Regency’s income (loss) attributable to limited partners and preferred unitholders, which totaled $(188) million, $8 million and $23 million for the years ended December 31, 2014, 3013 and 2012, respectively, would be reflected as income attributable to noncontrolling interest in ETE GP Acquirer’s and Regency GP’s statements of operations.
ETP’s general partner interest Common Units and Class H Units areis reflected separately in ETP’s financial statements, and Regency’s general partner interest and Common Units are reflected separately in Regency’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 and Regency.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 $715 million as of December 31, 2014.
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 3.26% at December 31, 2014.
ETP Senior Notes 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 payableredeemable 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 April 2014,On January 23, 2018, Sunoco Logistics issued $300 millionLP completed a private offering of $2.2 billion of senior notes, comprised of $1.0 billion in aggregate principal amount of 4.25%4.875% senior notes due April 2024 and $7002023, $800 million in aggregate principal amount of 5.30%5.500% senior notes due April 2044.
In November 2014, Sunoco Logistics issued an additional $2002026 and $400 million under the April 2024 senior notes and $800 million aggregate principal amount of 5.35% senior notes due May 2045. Sunoco Logistics used the net proceeds from the offerings to pay borrowings under the Sunoco Logistics Credit Facility and for general partnership purposes.
Regency Senior Notes
The Regency senior notes are unsecured obligations of Regency and the obligation of Regency to repay the Regency senior notes is not guaranteed by us or any of Regency’s subsidiaries. The Regency senior notes effectively rank junior to all indebtedness and other liabilities of Regency’s existing and future subsidiaries. Interest is payable semi-annually.
In February 2014, Regency issued $900 millionin aggregate principal amount of 5.875% senior notes due March 1, 2022.
In March 2014, as part2028. Sunoco LP used the proceeds from the private offering, along with proceeds from the closing of the PVR Acquisition, Regency assumed the outstandingasset purchase agreement with 7-Eleven to: 1) redeem in full its existing senior notes as of PVR with anDecember 31, 2017, comprised of $800 million in aggregate notional amount of $1.2 billion. The PVR senior notes consisted of $300 million principal amount of 8.25% 6.250%senior notes due April 15, 2018, $4002021, $600 million in aggregate principal amount of 6.5%5.500% senior notes due May 15, 2021,2020, and $473$800 million in aggregate principal amount of 8.375%6.375% senior notes due June 1, 2020. 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 Sunoco LP Series A Preferred Units as mentioned above; and 5) repurchase 17,286,859 common units owned by ETP as mentioned above.
Sunoco LP Senior Notes In April 2014, Regency redeemed all of the $300 million principal amount of 8.25% senior notes due April 15, 2018 for $313 million in cash. In July 2014, Regency redeemed $83 million of the $473 million principal amount of 8.375% senior notes due June 1, 2020 for $91 million, including $8 million of accrued interest and redemption premium. In July 2014, Regency exchanged $4992016, Sunoco LP issued $800 million aggregate principal amount of 8.375% senior notes6.25% Senior Notes due 20192021. The net proceeds of Eagle Rock and Eagle Rock Energy Finance Corp. for 8.375% senior notes due 2019 issued by Regency and its wholly-owned subsidiary.
In July 2014, Regency issued $700$789 million aggregate principal amount of 5.0% senior notes that mature on October 1, 2022.
In December 2014, Regency redeemed allwere used to repay a portion of the outstanding $600 million senior notesborrowings under its term loan facility.
The 6.25% Senior Notes due 2018, for a total price2021 were redeemed on January 23, 2018. See Sunoco LP Private Offering of $621 million.Senior Notes above. Term Loans, and Credit Facilities and Commercial Paper ETE Term Loan Facility The Parent Company hasOn February 2, 2017, the Partnership entered into a Senior Secured Term Loan Agreement (the “ETE“Term Credit Agreement”) with Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party thereto. The Term Credit Agreement”), whichAgreement has a scheduled maturity date of DecemberFebruary 2, 2019,2024, 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 ETE Term Credit Agreement, the lendersTerm Lenders have provided senior secured financing in an aggregate principal amount of $1.0$2.2 billion (the “ETE Term“Term Loan Facility”). The Parent Company shallis not be 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 PartnershipParent Company is required to repayprepay the term loan in connection with dispositions of (a) incentive distribution rightsIDRs in (i) prior to the consummation of the Sunoco Logistics Merger, ETP , and (ii) upon and after the consummation of the Sunoco Logistics Merger, Sunoco Logistics ; or Regency, (b) general partnership interests in Regency or (c) equity interests of any Personperson which owns, directly or indirectly, incentive distribution rightsIDRs in (i) prior to the consummation of the Sunoco Logistics Merger, ETP, or Regency or general partnership interests in Regency,and (ii) upon and after the consummation of the Sunoco Logistics Merger, Sunoco Logistics, in each case, yieldingwith a percentage ranging from 50% to 75% of such net proceeds in excess of $50 million.$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 subject to certain exceptionsincluding (i) approximately 27.5 million common units representing limited partner interests in ETP owned by the Partnership; and permitted liens.(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 ETP. The ETE Term Loan Facility initially is not guaranteed by any of the Parent Company’sPartnership’s subsidiaries. Interest accrues on advances at a LIBOR rate or a base rate, plus an applicable margin based on the election of the Parent Company for each interest period.period, plus an applicable margin. The applicable margin for LIBOR rate loans is 2.50%2.75% and the applicable margin for base rate loans is 1.50%1.75%. In April 2014, Proceeds of the Parent Company amended its Senior Secured Term Loan Agreement (the “ETE Term Credit Agreement”) to increase the aggregate principal amount to $1.4 billion. The Parent Company used the proceeds from this $400 million increase to repay borrowings under its revolving credit facility and for general partnership purposes. No other significant changes were made to the terms of the ETE Term Credit Agreement including maturity datewere used to refinance amounts outstanding under the Parent Company’s existing term loan facilities and interest rate.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 hashad a revolver credit agreement (the “Revolving Credit Agreement”) which hashad a scheduled maturity date of December 2, 2018, with an option for the PartnershipParent 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 $600 million$1.50 billion at any one time outstanding, (the “ETE Revolving Credit Facility”), and the Parent Company has the option to request increases in the aggregate commitments provided that the aggregate commitments never exceed $1.0 billion. In February 2014, the Partnership increased the capacity on the ETE Revolving Credit Facilityby up to $800 million. In May 2014, the Parent Company amended its revolving credit facility to increase the capacity to $1.2 billion. In February 2015, the Parent Company amended its revolving credit facility to increase the capacity to $1.5 billion.
$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, plus an applicable margin based on the election of the Parent Company for each interest period.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 FacilityFacilities 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 CreditFive-Year Facility allows for borrowings ofcontains an accordion feature, under which the total aggregate commitments may be increased up to $2.5$6.0 billion and expires in October 2019. The indebtedness under the ETP Credit Facility is unsecured and not guaranteed by any of ETP’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 ETP’s other current and future unsecured debt.certain conditions. ETP uses the ETP Credit FacilityFacilities to provide temporary financing for ETP’sits growth projects, as well as for general partnership purposes. In February 2015, ETP amended its revolving credit facility to increase the capacity to $3.75 billion. As of December 31, 2014,2017, the ETP CreditFive-Year Facility had $570 million$2.29 billion outstanding, and theof which $2.01 billion was commercial paper. The amount available for future borrowings was $1.81$1.56 billion after taking into account letters of credit of $121$150 million. The weighted average interest rate on the total amount outstanding as of December 31, 20142017 was 1.66%2.48%. Regency Credit Facility
The Regency Credit Facility has aggregate revolving commitments of $2.0 billion, with a $500 million incremental facility. The maturity date of the Regency Credit Facility is November 25, 2019.
As of December 31, 2014, Regency had a balance of $1.50 billion outstanding under the Regency Credit Facility in revolving credit loans and approximately $23 million in letters of credit. The total amount available under the Regency Credit Facility, as of December 31, 2014, which is reduced by any letters of credit,2017, the ETP 364-Day Facility had $50 million outstanding, and the amount available for future borrowings was approximately $473$950 million. The weighted average interest rate on the total amount outstanding as of December 31, 20142017 was 2.17%5.00%. ETLP Credit Facility The outstanding balance of revolving loans under the RegencyETLP Credit Facility bears interest at LIBOR plus a margin or an alternate base rate. The alternate base rateallowed for borrowings of up to $3.75 billion and was used to calculate interest on base rate loans will be calculated usingprovide temporary financing for our growth projects, as well as for general partnership purposes. This facility was repaid and terminated concurrent with the greater of a base rate, a federal funds effective rate plus 0.50% and an adjusted one-month LIBOR rate plus 1.0%. The applicable margin ranges from 0.63% to 1.5% for base rate loans and 1.63% to 2.5% for Eurodollar loans. Regency pays (i) a commitment fee ranging between 0.3% and 0.45% per annum for the unused portionestablishment of the revolving loan commitments; (ii) a participation fee for each revolving lender participating in letters of credit ranging between 1.63% and 2.5% per annum of the average daily amount of such lender’s letter of credit exposure and; (iii) a fronting fee to the issuing bank of letters of credit equal to 0.2% per annum of the average daily amount of its letter of credit exposure. InETP Credit Facilities on December 2011, Regency amended its credit facility to allow for additional investments in its joint ventures.1, 2017.
Sunoco Logistics Credit Facilities Sunoco Logistics maintainsETP maintained a $1.50$2.50 billion unsecured revolving credit facilityagreement (the “Sunoco Logistics Credit Facility”) which. 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”), 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. In connection with the Sunoco Logistics Merger, the 364-Day Credit Facility was terminated and repaid in May 2017. Bakken Credit Facility In August 2016, Energy Transfer Partners, L.P., Sunoco Logistics and Phillips 66 completed project-level financing of the 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 November 2018. The Sunoco LogisticsAugust 2019 (the “Bakken Credit Facility contains an accordion feature, under which the total aggregate commitment may be extended to $2.25 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, each plus an applicable margin. The credit facility may be prepaid at any time.Facility”). As of December 31, 2014,2017, the Sunoco LogisticsBakken Credit Facility had $150 million$2.50 billion of outstanding borrowings. The weighted average interest rate on the total amount outstanding as of December 31, 2017 was 3.00%.
West Texas Gulf Pipe Line Company,PennTex Revolving Credit Facility
PennTex previously maintained a subsidiary$275 million revolving credit commitment (the “PennTex Revolving Credit Facility”). In August 2017, the PennTex Revolving Credit Facility was repaid and terminated. Sunoco LP Term Loan Sunoco LP has a term loan agreement which provides secured financing in an aggregate principal amount of up to $2.035 billion due 2019. 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 Logistics, has a $35 million revolving credit facility which expiresLP’s leverage ratio as set forth in April 2015. The facility is availableits previously delivered compliance certificates and the resulting failure to fund West Texas Gulf’s general corporate purposes including working capital and capital expenditures. Atpay incremental interest owed under the term loan. As of December 31, 2014, this credit facility had $35 million2017, 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 outstanding borrowings.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. In September 2014,January 2017, Sunoco LP entered into a $1.25 billionlimited waiver to its revolving credit agreement (the “Sunoco LP Credit Facility”),facility, under which matures in September 2019. The Sunoco LP Credit Facility can be increased from time to time uponthe agents and lenders party thereto waived and deemed remedied the miscalculations of Sunoco LP’s written request, subjectleverage ratio as set forth in its previously delivered compliance certificates and the resulting failure to certain conditions, up to an additional $250 million.pay
incremental interest owed under the revolving credit facility. As of December 31, 2014,2017, 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 Facility had $683 millionAgreement with the lenders party thereto and Bank of outstanding borrowings.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 ETE 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 ETE 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 (as defined) to Consolidated EBITDA (as defined in the agreements)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 credit agreement relating to the ETP Credit FacilityFacilities contains covenants that limit (subject to certain exceptions) the ETP’sPartnership’s and certain of the ETP’sPartnership’s subsidiaries’ ability to, among other things: incur indebtedness; grant liens; enter into mergers; dispose of assets; make certain investments; make Distributions (as defined in such credit agreement)the ETP Credit Facilities) during certain Defaults (as defined in such credit agreement)the ETP Credit Facilities) and during any Event of Default (as defined in such credit agreement)the ETP Credit Facilities); engage in business substantially different in nature than the business currently conducted by ETPthe 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 exceedunderlying credit agreements,
of 55.0 to 1, as of the end of each quarter, with a permitted increase which 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. Covenants RelatedFailure to Regency
The Regency senior notes containcomply with the various restrictive and affirmative covenants that limit, among other things, Regency’sof our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Operating Companies’ ability and the ability of certain of its subsidiaries, to:
to incur additional indebtedness; debt and/or our ability to pay distributions on, or repurchase or redeem equity interests;
make certain investments;
incur liens;
enter into certain types of transactions with affiliates; and
sell assets, consolidate or merge with or into other companies.
If the Regency senior notes achieve investment grade ratings by both Moody’s and S&P and no default or event of default has occurred and is continuing, Regency will no longer be subject to these covenants except that the lien covenant will continue to be applicable. ETP has advised Regency that it intends to provide an ETP guarantee with respect to the outstanding Regency senior notes upon the closing of the Regency Merger, and it is expected that this will result in the Regency senior notes being upgraded an investment grade rating by both Moody’s and SAP.
The Regency Credit Facility contains the following financial covenants:
Regency’s consolidated EBITDA ratio for any preceding four fiscal quarter period, as defined in the credit agreement governing the Regency Credit Facility, must not exceed 5.00 to 1.
Regency’s consolidated EBITDA to consolidated interest expense, as defined in the credit agreement governing the Regency Credit Facility, must be greater than 2.50 to 1.
Regency’s consolidated senior secured leverage ratio for any preceding four fiscal quarter period, as defined in the credit agreement governing the Regency Credit Facility, must not exceed 3.25 to 1.
The Regency Credit Facility also contains various covenants that limit, among other things, the ability of Regency and RGS to:
incur indebtedness;
grant liens;
enter into sale and leaseback transactions;
make certain investments, loans and advances;
dissolve or enter into a merger or consolidation;
enter into asset sales or make acquisitions;
enter into transactions with affiliates;
prepay other indebtedness or amend organizational documents or transaction documents (as defined in the credit agreement governing the Regency Credit Facility);
issue capital stock or create subsidiaries; or
engage in any business other than those businesses in which it was engaged at the time of the effectiveness of the Regency Credit Facility or reasonable extensions thereof.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 LogisticsBakken Credit Facility Sunoco Logistics’ $1.50 billion credit facilityThe Bakken Credit Facility contains variousstandard and customary covenants including 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 creationBakken Credit Facility which requires a minimum historic debt service coverage ratio (“DSCR”) of indebtedness and liens, and other covenants relatednot less than 1.20 to 1 (the “Minimum Historic DSCR”) with respect each 12-month period following the operation and conductcommercial in-service date of the business of Sunoco LogisticsDakota Access and its subsidiaries. The credit facility also limits Sunoco Logistics, on a rolling four-quarter basis,ETCO Project in order to a maximum total consolidated debt to consolidated Adjusted EBITDA ratio, as defined in the underlying credit agreement, 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 debt, excluding net unamortized fair value adjustments, to consolidated Adjusted EBITDA was 3.7 to 1 at December 31, 2014, as calculated in accordance with the credit agreements.make certain restricted payments thereunder. The West Texas Gulf Pipeline Company’s $35 million credit facility limits West Texas Gulf, on a rolling four-quarter basis, to a minimum fixed charge coverage ratio of 1.00 to 1. In addition, the credit facility limits West Texas Gulf to a maximum leverage ratio of 2.00 to 1. West Texas Gulf’s fixed charge coverage ratio and leverage ratio were 1.67 to 1 and 0.85 to 1, respectively, at December 31, 2014.
Covenants Related to Sunoco LP The Sunoco LP Credit Facility requiresFacilities 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 5.50(a) as of the last day of each fiscal quarter through December 31, 2017, 6.75 to 1. The maximum leverage ratio is1.0, (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 upwards adjustmentincreases to 6.0 to 1.0 in connection with certain specified acquisitions in excess of not more than 6.00 to 1 for a period not to exceed three fiscal quarters in$50 million, as permitted under the event Sunoco LP engages in an acquisition of assets, equity interests, operating lines or divisions by Sunoco LP, a subsidiary, an unrestricted subsidiary or a joint venture for a purchase price of not less than $50 million.Credit Facilities. Indebtedness under the Sunoco LP Credit FacilityFacilities is secured by a security interest in, among other things, all of the 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 Sunoco LP Credit FacilityFacilities 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, 2014.2017. | | 7. | REDEEMABLEETP CONVERTIBLE PREFERRED UNITS: |
ETE Preferred Units
In connection with ETE’s acquisition of Regency’s general partner in 2010, ETE issued 3,000,000 Preferred Units having an aggregate liquidation preference of $300 million. The ETP Convertible Preferred Units were issuedmandatorily 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 a private placement at a stated price of $100 per unit and wereour consolidated balance sheets. The ETP Convertible Preferred Units are entitled to a preferential quarterly cash distribution of $2.00 per Preferred Unit.
On April 1, 2013, ETE paid $300 million to redeem (the “Redemption”) all of its 3,000,000 outstanding Preferred Units. Prior to the Redemption, on March 28, 2013, ETE paid the holder of the Preferred Units $40 million in cash in exchange for the holder relinquishing its right to receive any premium in connection with a future redemption or conversion of the Preferred Units.
Prior to the April 1, 2013 Redemption, we recorded non-cash charges of approximately $9 million to increase the carrying value of the Preferred Units to the estimated fair value. During 2012, we recorded non-cash charges of approximately $8 million to increase the carrying value of the Preferred Units to the estimated fair value of $331 million.
Preferred Units of Subsidiary
Holders may elect to convert Regency Preferred Units to Regency Common Units at any time. In July 2013, certain holders of the Regency Preferred Units exercised their right to convert an aggregate 2,459,017 Series A Preferred Units into Regency Common Units. Concurrent with this transaction, a gain of $26 million was recognized in other income, net, related to the
embedded derivative and reclassified $41 million from the Regency Preferred Units into Regency Common Units. As of December 31, 2014, the remaining Regency Preferred Units were convertible into 2,064,805 Regency Common Units, and if outstanding, are mandatorily redeemable on September 2, 2029 for $35 million plus all accrued but unpaid distributions and interest thereon. The Regency Preferred Units received fixed quarterly cash distributions of $0.445 per unitETP Preferred Unit if outstanding on the record dates of Regency’sETP’s common unit distributions. Holders can elect to convert RegencyIn January 2017, ETP repurchased all of its 1.9 million outstanding ETP Convertible Preferred Units into Regency Common Units into common units at any timefor cash in accordance with the partnership agreement.aggregate amount of $53 million.
The following table provides a reconciliation of the beginning and ending balances of the Regency Preferred Units:
| | | | | | | | | | | Regency Preferred Units | | Amount | | Balance, January 1, 2013 | 4.4 |
| | $ | 73 |
| | Regency Preferred Units converted into Regency Common Units | (2.5 | ) | | (41 | ) | | Balance, December 31, 2013 | 1.9 |
| | $ | 32 |
| (1 | ) | Accretion to redemption value | N/A |
| | 1 |
| | Balance, December 31, 2014 | 1.9 |
| | 33 |
| |
| | (1)
| This amount will be accreted to $35 million plus any accrued but unpaid distributions and interest by deducting amounts from partners’ capital over the remaining periods until the mandatory redemption date of September 2, 2029. Accretion during 2013 was immaterial. |
| | 8. | REDEEMABLE NONCONTROLLING INTERESTS: |
The noncontrolling interest holders in one of Sunoco Logistics’ consolidated subsidiaries have the option to sell their interests to Sunoco Logistics. In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable interest on our consolidated balance sheet.
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, 2014,2017, there were issued and outstanding 538.8 million1.08 billion Common Units representing an aggregate 99.46%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, 20142017, 20132016 and 20122015 was as follows: | | | Years Ended December 31, | Years Ended December 31, | | 2014 | | 2013 | | 2012 | 2017 | | 2016 | | 2015 | Number of Common Units, beginning of period | 559.9 |
| | 559.9 |
| | 445.9 |
| 1,046.9 |
| | 1,044.8 |
| | 1,077.5 |
| Conversion of Class D Units to ETE Common Units | | — |
| | — |
| | 0.9 |
| Repurchase of common units under buyback program | (21.1 | ) | | — |
| | — |
| — |
| | — |
| | (33.6 | ) | Issuance of common units in connection with Southern Union Merger (See Note 3) | — |
| | — |
| | 114.0 |
| | Issuance of common units | | 32.2 |
| | 2.1 |
| | — |
| Number of Common Units, end of period | 538.8 |
| | 559.9 |
| | 559.9 |
| 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, | | 2017 | | 2016 | | 2015 | Number of Series A Convertible Preferred Units, beginning of period | 329.3 |
| | — |
| | — |
| Issuance of Series A Convertible Preferred Units | — |
| | 329.3 |
| | — |
| Number of Series A Convertible Preferred Units, end of period | 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 $450 million carrying value as of December 31, 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 23.7 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 “Unit Split”). The Unit Split was completed on January 27, 2014. The Unit Split was effected by a distribution of one ETE Common Unitcommon unit for each common unit outstanding and held by unitholders of record at the close of business on January 13, 2014.July 15, 2015. Repurchase Program In December 2013,February 2015, the Partnership announced a common unit repurchase program, whereby the Partnership may repurchase up to $1an 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 21.133.6 million ETE Common Units under this program through May 23, 2014,in 2015. No units were repurchased under this program in 2017 or 2016, and there was $936 million available to use under the program was completed. In February 2015, the Partnership announced a common unit repurchase program, whereby the Partnership may repurchase up to $2 billionas 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.December 31, 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 1,500,000 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 1,500,000 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 of 1,540,000issued 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 40,000 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, 30% of the Class D Units will convertconvertible to ETE common units on a one-for-one basis on March 31, 2015, and the remaining 70% will convertCommon Units, subject to ETE common units on a one-for-one basis on March 31, 2018, 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 allocatedcertain vesting requirements which were not 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.former executive’s termination in 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 The following table summarizes ETP’s public offerings of ETP Common Units, all of which have been registered under the Securities Act of 1933 (as amended):
| | | | | | | | | | | | | Date | | Number of ETP Common Units | | Price per ETP Unit | | Net Proceeds | July 2012 | | 15.5 |
| | $ | 44.57 |
| | $ | 671 |
| April 2013 | | 13.8 |
| | 48.05 |
| | 657 |
|
Proceeds from the offerings listed above were used to repay amounts outstanding under the ETP Credit Facility and/or to fund capital expenditures and capital contributions to joint ventures, and for general partnership purposes.
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 January 2013 andconnection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. equity distribution agreement was terminated. In May 2013,2017, ETP entered into an equity distribution agreements pursuant to which ETP may sell from time to time ETP Common Units havingagreement with an aggregate offering prices ofprice up to $200 million and $800 million, respectively. $1.00 billion.
During the year ended December 31, 2014,2017, ETP issued approximately 2.722.6 million units for $144$503 million, net of commissions of $2 million. No amounts of ETP Common Units remain available to be issued under the January 2013 and May 2013 equity distribution agreements. In May 2014 and November 2014, ETP entered into equity distribution agreements pursuant to which ETP may sell from time to time ETP Common Units having aggregate offering prices of up to $1.0 billion and $1.50 billion, respectively. During the year ended December 31, 2014, ETP issued approximately 18.8 million units for $1.08 billion, net of commissions of $11$5 million. As of December 31, 2014, approximately $1.41 billion2017, $752 million of ETPETP’s Common Units remained available to be issued under ETP’s currently effective equity distribution agreements.agreement.
ETP’s Equity Incentive Plan Activity As discussed in Note 10, 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, 2014, 20132017, 2016 and 2012,2015, aggregate distributions of approximately $155$228 million, $109$216 million, and $43$360 million, respectively, were reinvested under the DRIP resulting in the issuance in aggregate of approximately 6.125.5 million ETP Common Units. As of December 31, 2014,2017, a total of 7.320.8 million ETP 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$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 therefore are reflected by ETP as treasury units in its consolidated financial statements.
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, (otherother than ETP Holdco)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 50.05%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 50.05%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. Pending Transaction
In December 2014, The Class H units were cancelled in connection with the merger of ETP and ETE announced the final terms of a transaction, whereby ETE will transfer 30.8 million ETP Common Units, ETE’s 45% interest in the Bakken pipeline project, and $879 million in cash 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 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 will also issue 100 in April 2017.
ETP Class I Units as described below. In addition, ETE and ETP agreed to reduce the IDR subsidies that ETE previously agreed to provide to ETP, with such reductions occurring in 2015 and 2016. In connection with the transaction,Bakken Pipeline Transaction discussed in Note 3, in March 2015, ETP will also issueissued 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 ETP Class I Units in an amount equal to the excess of the distribution amount set forth in the ETPETP’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 “ETP Quarterly“Quarterly Distributions of Available Cash” inCash.” Subsequent to the column titled “Pro Forma forApril 2017 merger of ETP Class H and Sunoco Logistics, 100 Class I Units.”Units remain outstanding. Bakken Equity Sale of Common Units by Regency The following table summarizes Regency’s public offerings of Regency Common Units during the periods presented:
| | | | | | | | | | | | | Date | | Number of Regency Common Units | | Price per Regency Unit | | Net Proceeds | March 2012 | | 12.7 |
| | $ | 24.47 |
| | $ | 297 |
|
Proceeds were used to repay amounts outstanding under the Regency Credit Facility and/or fund capital expenditures and capital contributions to joint ventures, as well as for general partnership purposes.
Regency issued 4.0 million, 140.4 million and 8.2 million Regency Common UnitsIn February 2017, Bakken Holdings Company LLC, an entity in connection with the Hoover, PVR and Eagle Rock Midstream acquisitions, respectively.
In June 2014, Regencywhich ETP indirectly owns a 100% membership interest, sold 14.4 million Regency Common Units to 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 ETEDakota 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.
Class K Units On December 29, 2016, ETP issued to certain of its indirect subsidiaries, in exchange for approximately $400 million. Proceeds from the issuance were used to pay down borrowings on the Regency Credit Facility, to redeem certain Regency senior notes and for general partnership purposes. In July 2014, Regency sold an additional 16.5 million Regency Common Units to a wholly-owned subsidiary of ETE in connection with the Eagle Rock Midstream Acquisition for approximately $400 million. Proceeds from the issuance were used to fund a portion of the cash consideration paid to Eagle Rock in connection with the Eagle Rock Midstream Acquisition. Regency’s Equity Distribution Program
From time to time, Regency has sold Regency Common Units through an equity distribution agreement. Such sales of Regency Common Units are made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between uscontributions and the sales agent which is the counterparty to the equity distribution agreement.
In June 2012, Regency entered into an equity distribution agreement with Citigroup Global Markets Inc. under which Regency may offer and sell Regency Common Units,exchange of outstanding common units representing limited partner interests having an aggregate offering pricein ETP, Class K Units, each of upwhich is entitled to $200 milliona quarterly cash distribution of $0.67275 per Class K Unit prior to ETP making distributions of available cash to any class of units, excluding any cash available distributions or dividends or capital stock sales proceeds received by ETP from timeETP Holdco. If ETP is unable to time through Citi, as sales agent for Regency. Forpay the years endedClass 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, 2014 and 2013, Regency received net proceeds2017, a total of $34101.5 million and $149 million, respectively, from Regency CommonClass K Units issued pursuant to this equity distribution agreement. No amounts remain available to be issued under this agreement and it is no longer effective.were held by wholly-owned subsidiaries of ETP.
In May 2014, Regency entered into an equity distribution agreement with a group of banks and investment companies under which Regency may offer and sell Regency Common Units, representing limited partner interests, for an aggregate offering price of up to $400 million, from time to time through this group of institutions, as sales agent for Regency. For the year ended December 31, 2014, Regency received net proceeds of $395 million from Regency Common Units issued pursuant to this equity distribution agreement. No amounts remained available to be issued under this agreement and it is no longer effective.
In January 2015, Regency entered into an equity distribution agreement with a group of banks and investment companies (the “Managers”) under which Regency may offer and sell Regency Common Units for an aggregate offering price of up to $1 billion, from time to time through the Managers, as sales agent for Regency. Regency intends to use the net proceeds from the sale of Regency Common Units for general partnership purposes.
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 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. DuringIn connection with the year ended December 31, 2014, Sunoco Logistics received proceeds of $477 million, net of commissions of $5 million, fromMerger, the issuance of 10.3 million common units pursuant to theprevious Sunoco Logistics equity distribution agreement which were used for general partnership purposes.was terminated. ETP Series A and Series Preferred Units In November 2017, ETP issued 950,000 of its 6.250% Series A Preferred Units at a price of $1,000 per unit, and 550,000 of its 6.625% Series B Preferred Units at a price of $1,000 per unit. Additionally, Sunoco Logistics completedDistributions on the ETP Series A Preferred Units will accrue and be cumulative from and including the date of original 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 overnight public offeringannual floating rate of 7.7 millionthe 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 not previously owned by ETP for net proceeds$20.00 per common unit in cash. ETP now owns all of $362 million in September 2014. The net proceeds from this offering were used to repay outstanding borrowings under the $1.50 billion Sunoco Logistics Credit Facilityeconomic interests of PennTex, and for general partnership purposes.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 2014 and November 2014,2016, 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 an aggregateadditional 1.3 million units with total net proceeds of 9.1$33 million, net of commissions of $0.3 million. As of December 31, 2017, $295 million of Sunoco LP common units remained available to be issued under the currently effective equity distribution agreement. 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 underwritten public offering. Aggregateindirect 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 $405 million$213 million. The net proceeds from the offering were used to repay amounts outstanding balances under the $1.25 billion Sunoco LP Credit Facilityrevolving credit facility. Sunoco LP Series 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 purchase price of $300 million. The distribution rate of Sunoco LP Series 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.
The Parent Company owns the entire general partner interest in Regency through its ownership of Regency GP. Regency GP has the right, but not the obligation, to contribute a proportionate amount of capital to Regency to maintain its current general partner interest. Regency GP’s interest in Regency’s distributions is reduced if Regency issues additional units and Regency GP does not contribute a proportionate amount of capital to Regency 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 RegencySunoco 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 duringand paid with respect to our common units for the years ended December 31, 2014, 2013 and 2012periods presented were as follows: | | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | December 31, 2011 | | February 7, 2012 | | February 17, 2012 | | $ | 0.3125 |
| March 31, 2012 | | May 4, 2012 | | May 18, 2012 | | 0.3125 |
| June 30, 2012 | | August 6, 2012 | | August 17, 2012 | | 0.3125 |
| September 30, 2012 | | November 6, 2012 | | November 16, 2012 | | 0.3125 |
| December 31, 2012 | | February 7, 2013 | | February 19, 2013 | | 0.3175 |
| March 31, 2013 | | May 6, 2013 | | May 17, 2013 | | 0.3225 |
| June 30, 2013 | | August 5, 2013 | | August 19, 2013 | | 0.3275 |
| September 30, 2013 | | November 4, 2013 | | November 19, 2013 | | 0.3363 |
| December 31, 2013 | | February 7, 2014 | | February 19, 2014 | | 0.3463 |
| March 31, 2014 | | May 5, 2014 | | May 19, 2014 | | 0.3588 |
| June 30, 2014 | | August 4, 2014 | | August 19, 2014 | | 0.3800 |
| September 30, 2014 | | November 3, 2014 | | November 19, 2014 | | 0.4150 |
| December 31, 2014 | | February 6, 2015 | | February 19, 2015 | | 0.4500 |
|
ETP’s Quarterly Distributions of Available Cash
ETP’s Partnership Agreement requires that ETP distribute all of its Available Cash to its Unitholders and its General Partner within 45 days following 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, 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 Partner in its sole discretion to provide for the proper conduct 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 more 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:
| | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Distribution per ETP Common Unit | December 31, 2011 | | February 7, 2012 | | February 14, 2012 | | $ | 0.8938 |
| March 31, 2012 | | May 4, 2012 | | May 15, 2012 | | 0.8938 |
| June 30, 2012 | | August 6, 2012 | | August 14, 2012 | | 0.8938 |
| September 30, 2012 | | November 6, 2012 | | November 14, 2012 | | 0.8938 |
| December 31, 2012 | | February 7, 2013 | | February 14, 2013 | | 0.8938 |
| March 31, 2013 | | May 6, 2013 | | May 15, 2013 | | 0.8938 |
| June 30, 2013 | | August 5, 2013 | | August 14, 2013 | | 0.8938 |
| September 30, 2013 | | November 4, 2013 | | November 14, 2013 | | 0.9050 |
| 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 |
|
In connection with transactions between ETP and ETE, ETE has agreed to relinquish its right to certain incentive distributions in future periods. Following is a summary of the net reduction in total distributions that would potentially be made to ETE in future periods based on (i) the currently effective partnership agreement provisions, (ii) the assumed closing of the issuance of additional ETP Class H Units and ETP Class I Units, which is expected to occur in March 2015, and (iii) the assumed closing of the Regency Merger, which is expected to occur in the second quarter of 2015:
| | | | | | | | | | | | | | Years Ending December 31, | | Currently Effective | | Pro Forma for ETP Class H and Class I Units(1) | | Pro Forma for Regency Merger(2) | 2015 | | $ | 86 |
| | $ | 31 |
| | $ | 91 |
| 2016 | | 107 |
| | 77 |
| | 142 |
| 2017 | | 85 |
| | 85 |
| | 145 |
| 2018 | | 80 |
| | 80 |
| | 140 |
| 2019 | | 70 |
| | 70 |
| | 130 |
| 2020 | | 35 |
| | 35 |
| | 50 |
| 2021 | | 35 |
| | 35 |
| | 35 |
| 2022 | | 35 |
| | 35 |
| | 35 |
| 2023 | | 35 |
| | 35 |
| | 35 |
| 2024 | | 18 |
| | 18 |
| | 18 |
|
| | | | | | | | | 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) | Pro forma amounts reflectCertain 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 IDR subsidies, as adjusteddistribution for the pending issuancequarter ended March 31, 2016 and, in lieu of additional ETP Class H Units and ETP Class I Units discussed above, as well asreceiving 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 ETP Class I Units. The issuanceparticipating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $0.11 per Convertible Unit. See additional ETP Class H Units and ETP Class I Units is expected to close in March 2015. |
| | (2)
| Pro forma amounts reflect the IDR subsidies, as adjusted for (i) the pending issuance of additional ETP Class H Units and ETP Class I Units (as described in Note (1) above) and (ii) the pending Regency Merger. Amounts reflected above assume that the Regency Merger is closed subsequent to the record date for the first quarter of 2015 distribution payment and prior to the record date for the second quarter 2015 distribution payment.information below. |
The amounts reflected above includeOur distributions declared and paid with respect to our Convertible Unit during the relinquishment of $350 million in the aggregate of incentive distributions that would potentially be made to ETE over the first forty fiscal quarters commencing immediately after the consummation of the Susser Merger. Such relinquishments would cease upon the agreement of an exchange of the Sunoco LP general partner interestyears ended December 31, 2016 and the incentive distribution rights between ETE and ETP.2017 were as follows:
| | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | March 31, 2016 | | May 6, 2016 | | May 19, 2016 | | $ | 0.1100 |
| June 30, 2016 | | August 8, 2016 | | August 19, 2016 | | 0.1100 |
| September 30, 2016 | | November 7, 2016 | | November 18, 2016 | | 0.1100 |
| December 31, 2016 | | 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 |
|
Regency’sETP’s Quarterly Distributions of Available Cash
Regency’s Partnership Agreement requires that Regency distribute all of its Available Cash to its Unitholders and its General PartnerUnder ETP’s limited partnership agreement, within 45 days after the end of each quarter, to unitholders of record on the applicable record date, as determined by the general partner. The term Available Cash generally consists ofETP distributes all cash and cash equivalents on hand at the end of thatthe quarter, less the amount of cash reserves established by the general partner to: (i) provide for the properin its discretion. This is defined as “available cash” in ETP’s partnership agreement. The general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct of the Partnership’s business; (ii) comply with applicable law, any debt instruments or other agreements; or (iii) provide funds forETP’s business. ETP will make quarterly distributions to the extent 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 general partner interest, Class I units and a portion of the outstanding ETP common units. | | | | | | | | | | | | 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 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 General Partner for any one or morefollowing amounts of the next four quarters and plus, all cash on hand on that date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter for which the determination is being made.incentive distributions in future periods: | | | | | | | | Total Year | 2018 | | $ | 153 |
| 2019 | | 128 |
| Each year beyond 2019 | | 33 |
|
Distributions declared and paid by Regency duringETP to the years ended December 31, 2014, 2013Series A and 2012Series B preferred unitholders were as follows: | | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Distribution per Regency Common Unit | December 31, 2011 | | February 6, 2012 | | February 13, 2012 | | $ | 0.4600 |
| March 31, 2012 | | May 7, 2012 | | May 14, 2012 | | 0.4600 |
| June 30, 2012 | | August 6, 2012 | | August 14, 2012 | | 0.4600 |
| September 30, 2012 | | November 6, 2012 | | November 14, 2012 | | 0.4600 |
| December 31, 2012 | | February 7, 2013 | | February 14, 2013 | | 0.4600 |
| March 31, 2013 | | May 6, 2013 | | May 13, 2013 | | 0.4600 |
| June 30, 2013 | | August 5, 2013 | | August 14, 2013 | | 0.4650 |
| September 30, 2013 | | November 4, 2013 | | November 14, 2013 | | 0.4700 |
| December 31, 2013 | | February 7, 2014 | | February 14, 2014 | | 0.4750 |
| March 31, 2014 | | May 8, 2014 | | May 15, 2014 | | 0.4800 |
| June 30, 2014 | | August 7, 2014 | | August 14, 2014 | | 0.4900 |
| September 30, 2014 | | November 4, 2014 | | November 14, 2014 | | 0.5025 |
| December 31, 2014 | | February 6, 2015 | | February 13, 2015 | | 0.5025 |
|
| | | | | | | | | | | | | | | 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 |
|
In conjunction with Southern Union’s contributions of SUGS to Regency, ETE agreed to relinquish incentive distributions on the 31.4 million Regency Common Units issued for twenty-four months subsequent to the transaction closing.
Sunoco Logistics Quarterly Distributions of Available Cash
Distributions declared by Sunoco Logistics during the years ended December 31, 2014, 2013 and 2012 were as follows:
| | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Distribution per Sunoco Logistics Common Unit | December 31, 2012 | | February 8, 2013 | | February 14, 2013 | | $ | 0.2725 |
| March 31, 2013 | | May 9, 2013 | | May 15, 2013 | | 0.2863 |
| June 30, 2013 | | August 8, 2013 | | August 14, 2013 | | 0.3000 |
| September 30, 2013 | | November 8, 2013 | | November 14, 2013 | | 0.3150 |
| 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 |
|
Sunoco Logistics Unit Split
On May 5, 2014, Sunoco Logistics’ board of directors declared a two-for-one split of Sunoco Logistics common units. The unit split resulted in the issuance of one additional Sunoco Logistics common unit for every one unit owned as of the close of business on June 5, 2014. The unit split was effective June 12, 2014. All Sunoco Logistics unit and per unit information included in this report is presented on a post-split basis.
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 | | Distribution per Sunoco LP Common Unit | September 30, 2014 | | November 18, 2014 | | November 28, 2014 | | $ | 0.5457 |
| December 31, 2014 | | February 17, 2015 | | February 27, 2015 | | 0.6000 |
|
| | | | | | | | | 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, | | 2014 | | 2013 | 2017 | | 2016 | Available-for-sale securities | $ | 3 |
| | $ | 2 |
| $ | 8 |
| | $ | 2 |
| Foreign currency translation adjustment | (3 | ) | | (1 | ) | (5 | ) | | (5 | ) | Net losses on commodity related hedges | (1 | ) | | (4 | ) | | Actuarial gain (loss) related to pensions and other postretirement benefits | (57 | ) | | 56 |
| (5 | ) | | 7 |
| Investments in unconsolidated affiliates, net | 2 |
| | 8 |
| 5 |
| | 4 |
| Subtotal | (56 | ) | | 61 |
| 3 |
| | 8 |
| Amounts attributable to noncontrolling interest | 51 |
| | (52 | ) | (3 | ) | | (8 | ) | Total AOCI included in partners’ capital, net of tax | $ | (5 | ) | | $ | 9 |
| $ | — |
| | $ | — |
|
The table below sets forth the tax amounts included in the respective components of other comprehensive income (loss): | | | December 31, | December 31, | | 2014 | | 2013 | 2017 | | 2016 | Available-for-sale securities | $ | (1 | ) | | $ | (1 | ) | $ | (2 | ) | | $ | (2 | ) | Foreign currency translation adjustment | 2 |
| | 1 |
| 3 |
| | 3 |
| Actuarial gain relating to pension and other postretirement benefits | (37 | ) | | (39 | ) | | Actuarial loss relating to pension and other postretirement benefits | | 3 |
| | — |
| Total | $ | (36 | ) | | $ | (39 | ) | $ | 4 |
| | $ | 1 |
|
| | 10.9. | UNIT-BASED COMPENSATION PLANS: |
We, ETP and Sunoco Logistics and RegencyLP 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 6,000,00012.0 million units. As of December 31, 2014, 5,690,1012017, 10.8 million units remain available to be awarded under the plan. InDuring the year ended December 2013, 1,540,000 Class D Units were granted to an31, 2017, 1.2 million ETE employee, Jamie Welch. Under the terms of the Class D Unit Agreement, 30% of the Class D Units granted to Welch will convert to ETE common units on a one-for-one basis on March 31, 2015, and the remaining 70% will convert to ETE common units on a one-for-one basis on March 31, 2018, 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 allocated 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. See further discussion at Note 9 to our consolidated financial statements.
During 2014, no awards were granted to ETE employees and 3,687certain 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 2014,the year ended December 31, 2017 and 2016, a total of 30,0342,018 and 28,648 ETE Common Units vested, with a total fair value of $1.5 million$39 thousand and $205 thousand, respectively, as of the vesting date. As of December 31, 2014, excluding Class D units,2017, a total of 34,3401,251,002 restricted units granted to ETE employees and 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 2.13.5 years. As of December 31, 2014, a total of 1,540,000 Class D Units granted to Mr. Welch remain outstanding, for which we expect to recognize a total of $23 million in compensation over a weighted average period of 3.0 years. ETPSubsidiary Unit-Based Compensation Plans
Restricted Units
Each of ETP 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 specified timefive-year period, typically a five-year serviceand vesting requirement, with vesting based on continued employment as of each applicable vesting date. Upon vesting, ETP Common Units are issued. These unit awardsThe Subsidiary Unit Awards entitle the recipientsgrantees of the unit awards to receive with respect to each ETP Common Unit subject to such award that has not either vested or been forfeited, aan amount of cash payment equal to eachthe per unit cash distribution per ETP Common Unitdistributions made by ETP on its Common Units promptly following each such distribution by ETP to its Unitholders. We refer to these rights as “distribution equivalent rights.” Under ETP’s equity incentive plans, ETP’s non-employee directors each receive grants with a five-year service vesting requirement.the respective subsidiaries during the period the restricted unit is outstanding. The following table showssummarizes the activity of the ETP awards granted to employees and non-employee directors:Subsidiary Unit Awards: | | | Number of ETP Units | | Weighted Average Grant-Date Fair Value Per ETP Unit | ETP | | Sunoco LP | Unvested awards as of December 31, 2013 | 3.2 |
| | $ | 49.65 |
| | | | 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 | 1.0 |
| | 60.85 |
| 4.9 |
| | 17.69 |
| | 0.2 |
| | 28.31 |
| Awards vested | (0.5 | ) | | 48.12 |
| (2.3 | ) | | 34.22 |
| | (0.3 | ) | | 45.48 |
| Awards forfeited | (0.1 | ) | | 32.36 |
| (1.1 | ) | | 25.03 |
| | (0.2 | ) | | 34.71 |
| Unvested awards as of December 31, 2014 | 3.6 |
| | 53.83 |
| | Unvested awards as of December 31, 2017 | | 14.1 |
| | 23.18 |
| | 1.7 |
| | 31.89 |
|
During the years ended December 31, 2014, 2013 and 2012, the weighted average grant-date fair value per unit award granted was $60.85, $50.54 and $43.93, respectively. | | | | | | | | | | | | | 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 awardsSubsidiary Unit Awards vested for the years ended December 31, 2017, 2016, and 2015 was $26$40 million, $29$40 million, and $29$57 million, respectively, based on the market price of ETP Common Unitsthe respective subsidiaries’ common units as of the vesting date. As of December 31, 2014, a total of 3.62017, estimated compensation cost related to Subsidiary Unit Awards not yet recognized was $216 million, unit awards remain unvested, for which ETP expects to recognize a total of $128 million in compensation expense over aand the weighted average period of 2.0 years. Cash Restricted Units
ETP has also granted cash restricted units,over which vest 100% at the end of the third year of service. A cash restricted unit entitles the award recipientthis cost is expected to receive cash equal to the market value of one ETP Common Unit upon vesting. As of December 31, 2014, a total of 0.4 million unvested cash restricted units units were outstanding.
Based on the trading price of ETP Common Units at December 31, 2014, ETP expects to recognize $24 million of unit-based compensationbe recognized in expense related to non-vested cash restricted units over a period of 1.8is 2.8 years.
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 and unit options of Sunoco Logistics covering an additional 0.7 million Sunoco, Inc. common units. As of December 31, 2014, a total of 1.5 million Sunoco Logistics restricted units were outstanding for which Sunoco Logistics expects to recognize $33 million of expense over a weighted-average period of 2.9 years.
Regency Unit-Based Compensation Plans
Regency has the following awards outstanding as of December 31, 2014:
107,650 Regency Common Unit options, all of which are exercisable, with a weighted average exercise price of $22.68 per unit option; and
2,167,719 Regency Phantom Units, with a weighted average grant date fair value of $24.31 per Phantom Unit.
Regency expects to recognize $42 million of compensation expense related to the Regency Phantom Units over a period of 3.9 years.
Cash Restricted Units
Regency began granting cash restricted units in 2014. These awards are service condition (time-based) grants which vest 100% at the end of the third year of service. A cash restricted unit entitles the award recipient to receive cash equal to the market value of one Regency Common Unit upon vesting. Regency has 379,328 cash restricted units outstanding at December 31, 2014.
Based on the trading price of Regency Common Units at December 31, 2014, Regency expects to recognize $7 million of unit-based compensation expense related to non-vested cash restricted units over a period of 2.5 years.
As a partnership, we are not subject to U.S.United States federal income tax and most state income taxes. However, the partnershipPartnership 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, | | 2014 | | 2013 | | 2012 | 2017 | | 2016 | | 2015 | Current expense (benefit): | | | | | | | | | | | Federal | $ | 321 |
| | $ | 51 |
| | $ | (3 | ) | $ | 54 |
| | $ | (47 | ) | | $ | (308 | ) | State | 86 |
| | (1 | ) | | 6 |
| (16 | ) | | (34 | ) | | (54 | ) | Total | 407 |
| | 50 |
| | 3 |
| 38 |
| | (81 | ) | | (362 | ) | Deferred expense (benefit): | | | | | | | | | | | Federal | (53 | ) | | (14 | ) | | 41 |
| (2,055 | ) | | (189 | ) | | 268 |
| State | 3 |
| | 57 |
| | 10 |
| 184 |
| | 12 |
| | (29 | ) | Total | (50 | ) | | 43 |
| | 51 |
| (1,871 | ) | | (177 | ) | | 239 |
| Total income tax expense from continuing operations | $ | 357 |
| | $ | 93 |
| | $ | 54 |
| | Total income tax expense (benefit) from continuing operations | | $ | (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, 20142017, 2016 and 20132015 is as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2014 | | December 31, 2013 | | Corporate Subsidiaries(1) | | Partnership(2) | | Consolidated | | Corporate Subsidiaries(1) | | Partnership(2) | | Consolidated | Income tax expense (benefit) at U.S. statutory rate of 35 percent | $ | 212 |
| | $ | — |
| | $ | 212 |
| | $ | (172 | ) | | $ | — |
| | $ | (172 | ) | Increase (reduction) in income taxes resulting from: | | | | |
| | | | | | | Nondeductible goodwill | — |
| | — |
| | — |
| | 241 |
| | — |
| | 241 |
| Nondeductible goodwill included in the Lake Charles LNG Transaction | 105 |
| | — |
| | 105 |
| | — |
| | — |
| | — |
| Premium on debt retirement | (10 | ) | | — |
| | (10 | ) | | — |
| | — |
| | — |
| Foreign taxes | (8 | ) | | — |
| | (8 | ) | | — |
| | — |
| | — |
| State income taxes (net of federal income tax effects) | 9 |
| | 46 |
| | 55 |
| | 31 |
| | 10 |
| | 41 |
| Other | 3 |
| | — |
| | 3 |
| | (16 | ) | | (1 | ) | | (17 | ) | Income tax from continuing operations | $ | 311 |
| | $ | 46 |
| | $ | 357 |
| | $ | 84 |
| | $ | 9 |
| | $ | 93 |
|
| | | | | | | | | | | | | | 2017 | | 2016 | | 2015 | Income tax expense (benefit) at United States statutory rate of 35 percent | $ | 248 |
| | $ | 71 |
| | $ | 316 |
| Increase (reduction) in income taxes resulting from: | | | | | | Partnership earnings not subject to tax | (477 | ) | | (576 | ) | | (355 | ) | Goodwill impairment | 207 |
| | 278 |
| | — |
| State tax, net of federal tax benefit | 124 |
| | (10 | ) | | (29 | ) | Dividend received deduction | (14 | ) | | (15 | ) | | (22 | ) | Federal rate change | (1,812 | ) | | — |
| | — |
| Audit settlement | — |
| | — |
| | (7 | ) | Change in tax status of subsidiary | (124 | ) | | — |
| | — |
| Other | 15 |
| | (6 | ) | | (26 | ) | Income tax expense (benefit) from continuing operations | $ | (1,833 | ) | | $ | (258 | ) | | $ | (123 | ) |
| | | Includes ETP Holdco, Susser, Oasis Pipeline Company, Susser Petroleum Property Company LLC, Aloha Petroleum Ltd, Pueblo, Inland Corporation, Mid-Valley Pipeline Company and West Texas Gulf Pipeline Company. ETP Holdco, which was formed via the Sunoco Merger and the ETP Holdco Transaction (see Note 3), includes Sunoco, Inc. and Panhandle. ETE held a 60% interest in ETP Holdco until April 30, 2013. Subsequent to the ETP Holdco Acquisition (see Note 3) on April 30, 2013, ETP owns 100% of ETP Holdco.
|
| | (2)
| Includes ETE and its respective subsidiaries that are classified as pass-through entities for federal income tax purposes. |
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, | | 2014 | | 2013 | 2017 | | 2016 | Deferred income tax assets: | | | | | | | Net operating losses and alternative minimum tax credit | $ | 116 |
| | $ | 217 |
| $ | 683 |
| | $ | 472 |
| Pension and other postretirement benefits | 47 |
| | 57 |
| 21 |
| | 30 |
| Long term debt | 53 |
| | 108 |
| | Long-term debt | | 14 |
| | 32 |
| Other | 111 |
| | 104 |
| 191 |
| | 182 |
| Total deferred income tax assets | 327 |
| | 486 |
| 909 |
| | 716 |
| Valuation allowance | (84 | ) | | (74 | ) | (189 | ) | | (118 | ) | Net deferred income tax assets | 243 |
| | 412 |
| 720 |
| | 598 |
| | | | | | | | Deferred income tax liabilities: | | | | | | | Properties, plants and equipment | (1,583 | ) | | (1,624 | ) | | Inventory | (153 | ) | | (302 | ) | | Property, plant and equipment | | (1,036 | ) | | (1,633 | ) | Investments in unconsolidated affiliates | (2,530 | ) | | (2,245 | ) | (2,726 | ) | | (3,789 | ) | Trademarks | (355 | ) | | (180 | ) | (173 | ) | | (273 | ) | Other | (32 | ) | | (45 | ) | (100 | ) | | (15 | ) | Total deferred income tax liabilities | (4,653 | ) | | (4,396 | ) | (4,035 | ) | | (5,710 | ) | Net deferred income tax liability | (4,410 | ) | | (3,984 | ) | | Less: current portion of deferred income tax liabilities, net | (85 | ) | | (119 | ) | | Accumulated deferred income taxes | $ | (4,325 | ) | | $ | (3,865 | ) | | Net deferred income taxes | | $ | (3,315 | ) | | $ | (5,112 | ) |
The completion of the Southern Union Merger, Sunoco Merger, ETP Holdco Transaction and Susser Merger (see Note 3) significantly increased the deferred tax assets (liabilities). The table below provides a rollforward of the net deferred income tax liability as follows:
| | | December 31, | December 31, | | 2014 | | 2013 | 2017 | | 2016 | Net deferred income tax liability, beginning of year | $ | (3,984 | ) | | $ | (3,696 | ) | $ | (5,112 | ) | | $ | (4,590 | ) | Susser acquisition | (488 | ) | | — |
| | SUGS Contribution to Regency | — |
| | (115 | ) | | Tax provision (including discontinued operations) | 62 |
| | (124 | ) | | Goodwill associated with Sunoco Retail to Sunoco LP transaction (see Note 3) | | — |
| | (460 | ) | Net assets (excluding goodwill) associated with Sunoco Retail to Sunoco LP (see Note 3) | | — |
| | (243 | ) | Tax provision, including provision from discontinued operations | | 1,825 |
| | 201 |
| Other | — |
| | (49 | ) | (28 | ) | | (20 | ) | Net deferred income tax liability | $ | (4,410 | ) | | $ | (3,984 | ) | $ | (3,315 | ) | | $ | (5,112 | ) |
ETP Holdco Susser and certain other corporate subsidiaries have gross federal net operating loss carryforwardscarryforward tax benefits of $5$403 million, all of which will expire in 2032 and 2033.2031 through 2037. Our corporate subsidiaries had less than $1have $62 million of federal alternative minimum tax credits at December 31, 2014.2017, 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 $111$274 million, $217 million net of federal tax, which expire between 2014January 1, 2018 and 2033. The2037. A valuation allowance of $84$186 million is applicable to the state net operating loss carryforward benefits applicable to Sunoco, Inc. pre-acquisition periods.
The following table sets forth the changes in unrecognized tax benefits: | | | Years Ended December 31, | Years Ended December 31, | | 2014 | | 2013 | | 2012 | 2017 | | 2016 | | 2015 | Balance at beginning of year | $ | 429 |
| | $ | 27 |
| | $ | 2 |
| $ | 615 |
| | $ | 610 |
| | $ | 440 |
| Additions attributable to acquisitions | — |
| | — |
| | 28 |
| | Additions attributable to tax positions taken in the current year | 20 |
| | — |
| | — |
| — |
| | 8 |
| | 178 |
| Additions attributable to tax positions taken in prior years | (1 | ) | | 406 |
| | — |
| 28 |
| | 18 |
| | — |
| Settlements | (5 | ) | | — |
| | — |
| | Reduction attributable to tax positions taken in prior years | | (25 | ) | | (20 | ) | | — |
| Lapse of statute | (3 | ) | | (4 | ) | | (3 | ) | (9 | ) | | (1 | ) | | (8 | ) | Balance at end of year | $ | 440 |
| | $ | 429 |
| | $ | 27 |
| $ | 609 |
| | $ | 615 |
| | $ | 610 |
|
As of December 31, 2014,2017, we have $439$605 million ($425576 million after federal income tax benefits) related to tax positions which, if recognized, would impact our effective tax rate. We believe it Our policy is reasonably possible that its unrecognizedto accrue interest expense and penalties on income tax benefits may be reduced by $4 million ($2underpayments (overpayments) as a component of income tax expense. During 2017, we recognized interest and penalties of less than $3 million. At December 31, 2017, we have interest and penalties accrued of $9 million, net of federal tax) within the next twelve months due to settlement of certain positions.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 open statute years, Sunoco, Inc. has proposed tofiled amended returns with the IRS thatexcluding these government incentive payments be excluded 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 within its claims,litigation, it will receive tax refunds of approximately $372$530 million. However, due to the uncertainty surrounding the claims,litigation, a reserve of $372$530 million was established for the full amount of the claims.litigation. Due to the timing of the expected settlement of the claimslitigation and the related reserve, the receivable and the reserve for this issue have been netted in the consolidated balance sheet as of December 31, 2014.2017. Our policy isIn December 2015, the Pennsylvania Commonwealth Court determined in Nextel Communications v. Commonwealth (“Nextel”) that the Pennsylvania limitation on NOL carryforward deductions violated the uniformity clause of the Pennsylvania Constitution and struck the NOL limitation in its entirety. In October 2017, the Pennsylvania Supreme Court affirmed the decision with respect to accrue interest expensethe uniformity clause violation; however, the Court reversed with respect to the remedy and penalties oninstead 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. has recognized approximately $67 million ($53 million after federal income tax underpayments (overpayments)benefits) in tax benefit based on previously filed tax returns and certain previously filed protective claims as a componentrelates to its cases currently held pending the Nextel matter. However, based upon the Pennsylvania Supreme Court’s October 2017 decision, and because of uncertainty in the breadth of the application of the decision, we have reserved $27 million ($21 million after federal income tax expense. During 2014, we recognized interest and penalties of less than $1 million. At December 31, 2014, we have interest and penalties accrued of $6 million, net of tax.benefits) against the receivable.
In general, ETEETP and its subsidiaries are no longer subject to examination by the IRSInternal Revenue Service (“IRS”), and most state jurisdictions, for 20102013 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, and Southern Union and its subsidiaries are no longer subject to examination by the IRS for tax years prior to and 2004. Regency 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 2012.2013. However, the 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 statue,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. Southern Union is under examination for the tax years 2004 through 2009. As of December 31, 2014, the IRS has proposed only one adjustment for the years under examination. For the 2006 tax year, the IRS is challenging $545 million of the $690 million of deferred gain associated with a like kind exchange involving certain assets of its distribution operations and its gathering and processing operations. We have vigorously defended this tax position and believe we have reached a tentative settlement with the IRS which will not have a material impact on our consolidated financial position or results of operations. Regency is also under examination by the IRS for the 2007 and 2008 tax years. The IRS has proposed adjustments in both of these examinations which are under review at the Appeals level. We believe Regency will prevail against this challenge by the IRS. Accordingly, no unrecognized tax benefit has been recorded with respect to these tax positions. The proposed adjustments with respect to Regency would not have a material impact upon our financial statements. 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.
| | 12.11. | REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES: |
Contingent Matters Potentially Impacting the Partnership from Our Investment in Citrus
Florida Gas Pipeline Relocation Costs. The Florida Department of Transportation, Florida’s Turnpike Enterprise (“FDOT/FTE”) has various turnpike/State Road 91 widening projects that have impacted or may, over time, impact one or more of FGTs’ mainline pipelines located in FDOT/FTE rights-of-way. Certain FDOT/FTE projects have been or are the subject of
litigation in Broward County, Florida. On November 16, 2012, FDOT paid to FGT the sum of approximately $100 million, representing the amount of the judgment, plus interest, in a case tried in 2011.
On April 14, 2011, FGT filed suit against the FDOT/FTE and other defendants in Broward County, Florida seeking an injunction and damages as the result of the construction of a mechanically stabilized earth wall and other encroachments in FGT easements as part of FDOT/FTE’s I-595 project. On August 21, 2013, FGT and FDOT/FTE entered into a settlement agreement pursuant to which, among other things, FDOT/FTE paid FGT approximately $19 million in September 2013 in settlement of FGT’s claims with respect to the I-595 project. The settlement agreement also provided for agreed easement widths for FDOT/FTE right-of-way and for cost sharing between FGT and FDOT/FTE for any future relocations. Also in September 2013, FDOT/FTE paid FGT an additional approximate $1 million for costs related to the aforementioned turnpike/State Road 91 case tried in 2011.
FGT will continue to seek rate recovery in the future for these types of costs to the extent not reimbursed by the FDOT/FTE. There can be no assurance that FGT will be successful in obtaining complete reimbursement for any such relocation costs from the FDOT/FTE or from its customers or that the timing of such reimbursement will fully compensate FGT for its costs.
Contingent Residual Support Agreement —– AmeriGas In connection with the closing of the contribution of ETP’sits 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 ofETP no longer provides contingent residual support for any 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.notes. PEPL Holdings Guarantee of CollectionSunoco LP Notes
In connection with the SUGS Contribution, Regency issued $600previous 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 4.50%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 “Regency Debt”), the proceeds of which were used by Regency to fund the cash portionassignment of the consideration, as adjusted, and pay certain other expenses or disbursements directly related to the closing of the SUGS Contribution. In connection with the closing of the SUGS Contribution on April 30, 2013, Regency entered into an agreement with PEPL Holdings, a subsidiary of Southern Union, pursuant to which PEPL Holdings provided a guarantee of collection (on a nonrecourse basisSunoco LP’s senior notes, to Southern Union) to Regencyits subsidiary, ETC M-A Acquisition LLC (“ETC M-A”). On January 23, 2018, Sunoco LP redeemed the previously guaranteed senior notes and Regency Energy Finance Corp.issued the following notes for which ETC M-A has also guaranteed collection with respect to the payment of theprincipal amounts: $1.00 billion aggregate principal amount of the Regency Debt through maturity in 2023. In connection with the completion4.875%, senior notes due 2023; $800 million aggregate principal amount of the Panhandle Merger, in which PEPL Holdings was merged with5.50% senior notes due 2026; and into Panhandle, $400 million aggregate principal amount of 5.875% senior notes due 2028. Under the guarantee of collection, forETC M-A would have the Regency Debt was assumed by Panhandle. NGL Pipeline Regulation
Weobligation to pay the principal of each series of notes once all remedies, including in the context of bankruptcy proceedings, have interestsfirst been fully exhausted against Sunoco LP with respect to such payment obligation, and holders of the notes are still owed amounts in NGL pipelines located 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 indenture governing the notes.
FERC underAudit In March 2016, the Interstate Commerce Act (“ICA”)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 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.FERC’s annual reporting requirements. 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. Transwestern Rate Case
On October 1, 2014, Transwestern filed a general NGA Section 4 rate case pursuant to the 2011 settlement agreement with its shippers. On December 2, 2014, the FERC issued an order accepting and suspending the rates to be effective April 1, 2015, subject to refund, and setting a procedural schedule with a hearing scheduled in August 2015.
FGT Rate Case
On October 31, 2014, FGT filed a general NGA Section 4 rate case pursuant to a 2010 settlement agreement with its shippers. On November 28, 2014, the FERC issued an order accepting and suspending the rates to be effective May 1, 2015, subject to refund, and setting a procedural schedule with a hearing scheduled in late 2015.audit is ongoing.
Commitments In the normal course of business, ETP purchases, processes and Regency purchase, process and sellsells natural gas pursuant to long-term contracts and enterenters 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.
We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2058. 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, | | | 2014 | | 2013 | | 2012 | Rental expense(1) | | $ | 159 |
| | $ | 151 |
| | $ | 60 |
| Less: Sublease rental income | | (26 | ) | | (24 | ) | | (4 | ) | Rental expense, net | | $ | 133 |
| | $ | 127 |
| | $ | 56 |
|
| | (1)
| Includes contingent rentals totaling $24 million, $22 million and $6 million for the years ended December 31, 2014, 2013 and 2012, respectively. |
Future minimum lease commitments for such leases are:
| | | | | Years Ending December 31: | | 2015 | $ | 151 |
| 2016 | 129 |
| 2017 | 118 |
| 2018 | 108 |
| 2019 | 102 |
| Thereafter | 829 |
| Future minimum lease commitments | 1,437 |
| Less: Sublease rental income | (34 | ) | Net future minimum lease commitments | $ | 1,403 |
|
ETP and Regency’sETP’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 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, | | | 2017 | | 2016 | | 2015 | Rental expense(1) | | $ | 196 |
| | $ | 187 |
| | $ | 281 |
| Less: Sublease rental income | | (25 | ) | | (26 | ) | | (26 | ) | Rental expense, net | | $ | 171 |
| | $ | 161 |
| | $ | 255 |
|
| | (1) | Includes contingent rentals totaling $16 million, $18 million and $20 million for the years ended December 31, 2017, 2016 and 2015, respectively. |
Future minimum lease commitments for such leases are: | | | | | Years Ending December 31: | | 2018 | $ | 113 |
| 2019 | 100 |
| 2020 | 96 |
| 2021 | 83 |
| 2022 | 71 |
| Thereafter | 606 |
| Future minimum lease commitments | 1,069 |
| Less: Sublease rental income | (152 | ) | Net future minimum lease commitments | $ | 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 On July 25, 2016, the 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. After significant delay, the USACE also issued easements to allow the pipeline to cross land owned by the USACE adjacent to the Missouri River in two locations. Also in July, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia against the USACE that challenged the legality of the permits issued for the construction of the Dakota Access pipeline across those waterways and claimed 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 intervened in the case. The SRST soon added a request for an emergency temporary restraining order (“TRO”) to stop construction on the pipeline project. On September 9, 2016, the Court denied SRST’s motion for a preliminary injunction, rendering the TRO request moot. After the September 9, 2016 ruling, the Department of the Army, the DOJ, and the Department of the Interior released a joint statement that the USACE would not grant the easement for the land adjacent to Lake Oahe until the Department of the Army completed a review to determine whether it was necessary to reconsider the USACE’s decision under various federal statutes relevant to the pipeline approval. The SRST appealed the denial of the preliminary injunction to the 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, 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 statutes governing the use of government property. 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 February 2017, in 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 allowing the pipeline to cross Lake Oahe. Almost immediately, the Cheyenne River Sioux Tribe (“CRST”), which had intervened in the lawsuit in August 2016, moved for a preliminary injunction and 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 Court denied the TRO and preliminary injunction, and the CRST appealed and requested an injunction pending appeal in the district court 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 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 halt or suspend the operation of the pipeline, we cannot assure this outcome. 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”) 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 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. Lone Star is still quantifying the extent of its incurred and ongoing damages 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, is a defendantthe 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 are asserting 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 are seekingseek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees. As of December 31, 2014,2017, Sunoco, Inc. is a defendant in fiveseven cases, including casesone case each initiated by the States of Maryland, New Jersey, Vermont, 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 beNew Jersey. The Court approved the subjectJudicial Consent Order on December 5, 2017. Dismissal of the first trial phase in the New Jersey case and the initial Puerto Rico case. Insufficient information has been developed about the plaintiffs’ legal theories or the facts with respect to statewide natural resource damage claims to provide an analysis of the ultimate potential liability ofagainst Sunoco, Inc. and Sunoco, Inc. (R&M) is expected shortly. The Maryland complaint was filed in these matters. December 2017 but was not served until January 2018.
It is reasonably possible that a loss may be realized;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 Relating Following the January 26, 2015 announcement of the 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 PVR Merger Five putativeRegency Merger. All but one Regency Merger-related lawsuits have been dismissed. On June 10, 2015, Adrian Dieckman (“Dieckman”), a purported Regency unitholder, filed a class action lawsuits challenging the PVR Acquisition are currently pending. All of these cases name PVR, PVRcomplaint, Dieckman v. Regency GP and the current directors of PVR GP, as well as the Partnership and the General Partner (collectively, the “Regency Defendants”), as defendants. Each of the lawsuits has been brought by a purported unitholder of PVR, both individually and on behalf of a putative class consisting of public unitholders of PVR. The lawsuits generally allege, among other things, that the directors of PVR GP breached their fiduciary duties to unitholders of PVR, that PVR GP, PVR and the Regency Defendants aided and abetted the directors of PVR GP in the alleged breach of these fiduciary duties, and, as to the actions in federal court, that some or all of PVR, PVR GP, and the directors of PVR GP violated Section 14(a) of the Exchange Act and Rule 14a-9 promulgated thereunder and Section 20(a) of the Exchange Act. The lawsuits purport to seek, in general, (i) injunctive relief, (ii) disclosure of certain additional information concerning the transaction, (iii) in the event the merger is consummated, rescission or an award of rescissory damages, (iv) an award of plaintiffs’ costs and (v) the accounting for damages allegedly causes by the defendants to these actions, and, (iv) such further relief as the court deems just and proper. The styles of the pending cases are as follows: David Naiditch v. PVR Partners, L.P.,LP, et al. (Case, C.A. No. 9015-VCL)11130-CB, in the Court of Chancery of the State of Delaware); Charles Monatt v. PVR Partners, LP, et al. (Case No. 2013-10606)Delaware (the “Regency Merger Litigation”), on behalf of Regency’s common unitholders against Regency GP, LP; Regency GP LLC; ETE, ETP, ETP GP, and Saul Srour v. PVR Partners, L.P., et al. (Case No. 2013-011015), each pendingthe members of Regency’s board of directors (the “Regency Litigation Defendants”).
The Regency 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. On March 29, 2016, the Delaware Court of Chancery granted the Regency Litigation Defendants’ motion to dismiss the lawsuit in its entirety. Dieckman appealed. On January 20, 2017, the Delaware Supreme Court reversed the judgment of the Court of Common Pleas for Delaware County, Pennsylvania; Stephen Bushansky v. PVR Partners, L.P., et al. (C.A. No. 2:13-cv-06829-HB);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 Mark Hinnau v. PVR Partners, L.P., et al. (C.A. No. 2:13-cv-07496-HB), pending in the United States District Court for the Eastern District of Pennsylvania. a Motion to Stay Discovery on May 19, 2017. On January 28, 2014, the defendants entered into a Memorandum of Understanding (“MOU”) with Monatt, Srour, Bushansky, Naiditch and Hinnau pursuant to which defendants and the referenced plaintiffs agreed in principle to a settlement of their lawsuits (“Settled Lawsuits”), which will be memorialized in a separate settlement agreement, subject to customary conditions, including consummation of the PVR Acquisition, completion of certain confirmatory discovery, class certification and final approval byFebruary 20, 2018, the Court of Common Pleas for Delaware County, Pennsylvania. IfChancery issued an Order granting in part and denying in part the Court approvesmotions to dismiss, dismissing the settlement,claims against all defendants other than Regency GP, LP and Regency GP LLC. The Regency Litigation Defendants cannot predict the Settled Lawsuitsoutcome of the 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 dismissedrequired 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 prejudice and all defendants will be released from any and all claims relating to the Settled Lawsuits. The settlement will not affect any provisions of the merger agreement or the form or amount of consideration to be received by PVR unitholders in the PVR Acquisition. The defendants have denied and continue to deny any wrongdoing or liability with respect to the plaintiffs’ claims in the aforementioned litigation and have entered into the settlement to eliminate the uncertainty, burden, risk, expense, and distraction of further litigation.
Eagle Rock Shareholder Litigation
Three putative class action lawsuits challenging the Eagle Rock Midstream Acquisition are currently pending in federal district court in Houston, Texas. All cases name Eagle Rock and its current directors, as well as the Partnership and a subsidiary, as defendants. One of the lawsuits also names additional Eagle Rock entities as defendants. Each of the lawsuits has been brought by a purported unitholder of Eagle Rock (collectively, the “Plaintiffs”), both individually and on behalf of a putative class consisting of public unitholders of Eagle Rock. The Plaintiffs in each case seek to rescind the transaction, claiming, among other things, that it yields inadequate consideration, was tainted by conflict and constitutes breaches of common law fiduciary duties or contractually imposed duties to the shareholders. Plaintiffs also seek monetary damages and attorneys’ fees. Regency and its subsidiary are named as “aiders and abettors” of the allegedly wrongful actions of Eagle Rock and its board.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. appeal with the Court of Appeals. On July 18, 2017, the Court of Appeals issued its opinion and reversed 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 due February 26, 2018. Sunoco Logistics Merger Litigation Seven purported Energy Transfer Partners, L.P. common unitholders (the “ETP Unitholder Plaintiffs”) separately filed seven putative unitholder class action lawsuits against ETP, ETP GP, ETP LLC, the members of the ETP Board, and ETE (the “ETP-SXL Defendants”) in connection with the announcement of the Sunoco Logistics Merger. Two of these lawsuits were voluntarily dismissed in March 2017. The five remaining lawsuits were consolidated as In accordancere Energy Transfer Partners, L.P. Shareholder Litig., C.A. No. 1:17-cv-00044-CCC, in the United States District Court for the District of Delaware (the “Sunoco Logistics Merger Litigation”). The ETP Unitholder Plaintiffs allege causes of action challenging the merger and the proxy statement/prospectus filed in connection with GAAP,
no amountsas an award of costs and attorneys’ fees. On October 5, 2017, the ETP-SXL Defendants filed a Motion to Dismiss the ETP Unitholder Plaintiffs’ claims. Rather than respond to the 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 any such lawsuits might be. Nor can the ETP-SXL Defendants predict the amount of time and expense that would be required to resolve such lawsuits. The ETP-SXL Defendants believe the Sunoco Logistics Merger Litigation was without merit and intend to defend vigorously against any future lawsuits challenging the Sunoco Logistics Merger. Litigation Filed By or Against Williams On April 6, 2016, Williams 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 Williams Litigation”). Williams 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 Williams Litigation. The counterclaim asserts in general that Williams 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 Williams’ 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 Issuance against Mr. Warren in the District Court of Dallas County, Texas, which the Texas state court later dismissed based on the Merger Agreement’s forum-selection clause. On May 13, 2016, Williams 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 (collectively, “Defendants”). This lawsuit is styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., et al., C.A. No. 12337-VCG (the “Second Delaware Williams Litigation”). In general, Williams alleged that Defendants 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 concerning Section 721 of the Internal Revenue Code (“721 Opinion”), (b) breaching a representation and warranty in the Merger Agreement concerning Section 721 of the Internal Revenue Code, and (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. Williams 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. ETE filed an answer and counterclaim in the Second Delaware Williams Litigation. In addition to the counterclaims previously asserted, ETE asserted that Williams materially breached the Merger Agreement by, among other things, (a) modifying or qualifying the Williams 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 original verdictmerger, (c) failing to facilitate the financing of the merger, (d) failing to use its reasonable best efforts to consummate the 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 a two-day trial on June 20 and 21, 2016, the JulyCourt 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 Williams’ requests for injunctive relief. The 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, styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., No. 330, 2016. Williams filed an amended complaint on September 16, 2016 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 Defendants breached an additional representation and warranty in the Merger Agreement. Defendants filed amended counterclaims and affirmative defenses on September 23, 2016 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, 2014 final judgment2016, Williams filed a motion to dismiss Defendants’ amended counterclaims and to strike certain of Defendants’ affirmative defenses. Following briefing by the parties on Williams’ motion, the Delaware Court of Chancery held oral arguments on November 30, 2016. On March 23, 2017, the Delaware Supreme Court affirmed the Court of Chancery’s Opinion and Order on the June 2016 trial 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 recordedrequired to resolve these lawsuits. Defendants believe that Williams’ claims are without merit and 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 our financial statements until the appeal processDelaware 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 (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. On August 29, 2016, the Issuance Plaintiffs filed a consolidated amended complaint, and in addition to the injunctive relief described above, seek class-wide damages allegedly resulting from the Issuance. 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 completed.currently set for February 19-21, 2018. The Issuance 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 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, 20142017 and 2013,2016, accruals of approximately $37$33 million and $46$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, 20142017 or 20132016 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein. Attorney General of the Commonwealth of Massachusetts v New England Gas Company
On July 7, 2011, the Massachusetts Attorney General (“AG”) filed a regulatory complaint with the Massachusetts Department of Public Utilities (“MDPU”) against New England Gas Company with respect to certain environmental cost recoveries. The AG is seeking a refund to New England Gas Company customers for alleged “excessive and imprudently incurred costs” related to legal fees associated with Southern Union’s environmental response activities. In the complaint, the AG requests that the MDPU initiate an investigation into the New England Gas Company’s collection and reconciliation of recoverable environmental costs including: (i) the prudence of any and all legal fees, totaling approximately $19 million, that were charged by the Kasowitz, Benson, Torres & Friedman firm and passed through the recovery mechanism since 2005, the year when a partner in the firm, the Southern Union former Vice Chairman, President and Chief Operating Officer, joined Southern Union’s management team; (ii) the prudence of any and all legal fees that were charged by the Bishop, London & Dodds firm and passed through the recovery mechanism since 2005, the period during which a member of the firm served as Southern Union’s Chief Ethics Officer; and (iii) the propriety and allocation of certain legal fees charged that were passed through the recovery mechanism that the AG contends only qualify for a lesser, 50%, level of recovery. Southern Union has filed its answer denying the allegations and moved to dismiss the complaint, in part on a theory of collateral estoppel. The hearing officer has deferred consideration of Southern Union’s motion to dismiss. The AG’s motion to be reimbursed expert and consultant costs by Southern Union of up to $150,000 was granted. By tariff, these costs are recoverable through rates charged to New England Gas Company customers. The hearing officer previously stayed discovery pending resolution of a dispute concerning the applicability of attorney-client privilege to legal billing invoices. The MDPU issued an interlocutory order on June 24, 2013 that lifted the stay, and discovery has resumed. Panhandle (as successor to Southern Union) believes it has complied with all applicable requirements regarding its filings for cost recovery and has not recorded any accrued liability; however, Panhandle will continue to assess its potential exposure for such cost recoveries as the matter progresses.
Air Quality Control
SUGS is currently negotiating settlements to certain enforcement actions by the NMED and the TCEQ. The TCEQ recently initiated a state-wide emissions inventory for the sulfur dioxide emissions from sites with reported emissions of 10 tons per year or more. If this data demonstrates that any source or group of sources may cause or contribute to a violation of the National Ambient Air Quality Standards, they must be sufficiently controlled to ensure timely attainment of the standard. This may potentially affect three SUGS recovery units in Texas. It is unclear at this time how the NMED will address the sulfur dioxide standard.
Compliance Orders from the New Mexico Environmental Department
SUGS has been in discussions with the NMED concerning allegations of violations of New Mexico air regulations related to the Jal #3 and Jal #4 facilities. Hearings on the compliance orders were delayed until March 2014 to allow the parties to pursue substantive settlement discussions. SUGS has meritorious defenses to the NMED claims and can offer significant mitigating factors to the claimed violations. SUGS has recorded a liability of less than $1 million related to the claims and will continue to assess its potential exposure to the allegations as the matter progresses.
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. Although we believeHistorically, our environmental compliance costs have not had a material adverse effect on our results of operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the business of transporting, storing, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products. As a result,but there can be no assurance that significantsuch costs and liabilities will not be incurred.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, includeincluding 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, 2014,2017, Sunoco, Inc. had been named as a PRP at approximatelapproximaty 51ely 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, | | 2014 | | 2013 | 2017 | | 2016 | Current | $ | 41 |
| | $ | 47 |
| $ | 35 |
| | $ | 26 |
| Non-current | 360 |
| | 356 |
| 337 |
| | 318 |
| Total environmental liabilities | $ | 401 |
| | $ | 403 |
| $ | 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, 20142017 and 2013,2016, the Partnership recorded $48$32 million and $41$43 million, respectively, of expenditures related to environmental cleanup programs. On June 29, 2011,December 2, 2010, Sunoco, Inc. entered an Asset Sale and Purchase Agreement to sell the U.S. Environmental Protection Agency finalizedToledo 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 rule under theFinding 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 revisedSunoco, Inc. operated the new source performance standardsrefinery. Specifically, EPA has claimed that the refinery flares were not operated in a manner consistent with good air pollution control practice for manufacturers, ownersminimizing emissions and/or in conformance with their design, and operatorsthat Sunoco, Inc. submitted semi-annual compliance reports in 2010 and 2011 and EPA that failed to include all of new, modifiedthe information required by the regulations. EPA has proposed penalties in excess of $200,000 to resolve the allegations and reconstructed stationary internal combustion engines.discussions continue between the parties. The rule became effective on August 29, 2011. The rule modifications may require ustiming or outcome of this matter cannot be reasonably determined at this time, however, we do not expect there to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment, if we replace equipmentbe a material impact to its results of operations, cash flows or expand existing facilities in the future. At this point, we are not able to predict the cost to comply with the rule’s requirements, because the rule applies only to changes we might make in the future.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, ETP experienced a release on its products pipeline in Wellington, Ohio. In connection with this release, the PHMSA issued a Corrective Action Order under which ETP is obligated to follow specific requirements in the investigation of the release and the repair and reactivation of the pipeline. This 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. ETP has also received a “No Further Action” approval from the Ohio EPA for all soil and groundwater remediation requirements. In May 2016, ETP received a proposed penalty from the EPA and DOJ 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, ETP 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 April 2016, the PHMSA issued a NOPV, PCO and Proposed Civil Penalty related to certain procedures carried out during construction of ETP’s Permian Express 2 pipeline system in Texas. The proposed penalties are in excess of $100,000. The 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 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 our crude oil pipeline near Wortham, Texas. The proposed penalties are 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 August 2017, the PHMSA issued a NOPV and a PCO in connection with alleged violations on ETP’s Nederland to Kilgore pipeline in Texas. The case remains open with PHMSA and the proposed penalties are in excess of $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 operations are in substantial compliance with thepast costs for OSHA requirements,required activities, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.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. | | 13.12. | PRICE RISK MANAGEMENTDERIVATIVE 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, our subsidiarieswe 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. Following is a description of price risk management activities by operating entity. ETP
ETP injectsWe use futures and holdsbasis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in itsour Bammel storage facility to take advantage of contango markets (i.e., when the price of natural gas is higher in the future than the current spot price). ETP uses financial derivatives tofacility. At hedge the natural gas held
in connection with these arbitrage opportunities. At the inception, of the hedge, ETP lockswe lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract to lock in the sale price. If ETP designates the related financial contract as a fair value hedge for accounting purposes, ETP values the hedged natural gas inventory at current spot market prices along with the financial derivative ETP uses to hedge it.contract. Changes in the spreadspreads between the forward natural gas prices designated as fair value hedges 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. Unrealized margins represent
We use futures, swaps and options to hedge the unrealized gains or losses from ETP’s derivative instruments using mark-to-market accounting, with changes in the fair valuesales price of our derivatives being recorded directly in earnings. These margins fluctuate based upon changes in the spreads between the physical spot price and forward natural gas prices. If the spread narrows between the physical and financial prices, ETP will record unrealized gains or lower unrealized losses. If the spread widens, ETP will record unrealized losses or lower unrealized gains. Typically, as ETP enters the winter months, the spread converges so that ETP recognizes in earnings the original locked-in spread through either mark-to-market adjustments or the physical withdraw of natural gas. ETP is also exposed to market risk on natural gas it retainswe retain for fees in itsour intrastate transportation and storage operations and operational gas sales on itsour interstate transportation and storage operations. ETP uses financial derivativesThese contracts are not designated as hedges for accounting purposes.
We use NGL and crude derivative swap contracts to hedge theforecasted sales price of this gas, including futures, swapsNGL and options. Certain contracts that qualify for hedge accounting are designated as cash flow hedges of the forecasted sale of natural gas. The change in value, to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statement of operations. ETP is also exposed to commodity price risk on NGLs and residue gas it retainscondensate equity volumes we retain for fees in itsour midstream operations whereby itsour 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 NGLs. ETP uses NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes. Certain contracts that qualify for hedge accounting are accounted for as cash flow hedges. The change in value, to the extent theNGL. These contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statement of operations.not designated as hedges for accounting purposes.
ETP may use derivatives in ETP’s liquids transportation and services operations to manage ETP’s storage facilities and the purchase and sale of purity NGLs.
Sunoco Logistics utilizes derivatives such asWe utilize 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 derivative contracts act as a hedging mechanism against the volatility of prices by allowing Sunoco Logistics to transfer this price risk to counterparties who are able and willing to bear it. Since the first quarter 2013, Sunoco Logistics has not designated any of its derivative contracts as hedges for accounting purposes. Therefore, all realized
We use futures and unrealized gains and losses from these derivative contracts are recognized in the consolidated statements of operations during the current period. ETP also uses derivatives to hedge a variety of price risks in its retail marketing operations. Futures and swaps are used 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. The derivatives usedcosts in ETP’sour retail marketing operations represent economic hedges; however, ETP has elected not to designate any of the hedges in these operations. Therefore, all realized and unrealized gains and losses from these derivativeThese contracts are recognized in the consolidated statements of operations during the current period.not designated as hedges for accounting purposes.
ETP’s trading activities include theWe use of financial commodity derivatives to take advantage of market opportunities. Theseopportunities in our trading activities are awhich complement to itsour transportation and storage operationsoperations’ and are netted in cost of products sold in theour consolidated statements of operations. Additionally, ETPWe also hashave trading and marketing activities related to power and natural gas in itsour all other operations which are also netted in cost of products sold. As a result of itsour trading activities and the use of derivative financial instruments in itsour transportation and storage operations, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. ETP attemptsWe attempt to manage this volatility through the use of daily position and profit and loss reports provided to itsour risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in ETP’sour commodity risk management policy.
The following table details ETP’sour outstanding commodity-related derivatives: | | | December 31, 2014 | | December 31, 2013 | 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 | (232,500 | ) | | 2015 | | 9,457,500 |
| | 2014-2019 | 1,078 |
| | 2018 | | (683 | ) | | 2017 | Basis Swaps IFERC/NYMEX (1) | (13,907,500 | ) | | 2015 - 2016 | | (487,500 | ) | | 2014-2017 | 48,510 |
| | 2018-2020 | | 2,243 |
| | 2017 | Swing Swaps | — |
| | — | | 1,937,500 |
| | 2014-2016 | | Options – Calls | 5,000,000 |
| | 2015 | | — |
| | — | | Options – Puts | | 13,000 |
| | 2018 | | — |
| | — | Power (Megawatt): | | | | | | | | | Forwards | 288,775 |
| | 2015 | | 351,050 |
| | 2014 | 435,960 |
| | 2018-2019 | | 391,880 |
| | 2017 - 2018 | Futures | (156,000 | ) | | 2015 | | (772,476 | ) | | 2014 | (25,760 | ) | | 2018 | | 109,564 |
| | 2017 - 2018 | Options — Puts | (72,000 | ) | | 2015 | | (52,800 | ) | | 2014 | (153,600 | ) | | 2018 | | (50,400 | ) | | 2017 | Options — Calls | 198,556 |
| | 2105 | | 103,200 |
| | 2014 | 137,600 |
| | 2018 | | 186,400 |
| | 2017 | Crude (Bbls) – Futures | — |
| | — | | 103,000 |
| | 2014 | | Crude (MBbls) – Futures | | — |
| | — | | (617 | ) | | 2017 | (Non-Trading) | | | | | | | | | Natural Gas (MMBtu): | | | | | | Natural Gas (BBtu): | | | | | | Basis Swaps IFERC/NYMEX | 57,500 |
| | 2015 | | 570,000 |
| | 2014 | 4,650 |
| | 2018-2020 | | 10,750 |
| | 2017 - 2018 | Swing Swaps IFERC | 46,150,000 |
| | 2015 | | (9,690,000 | ) | | 2014-2016 | 87,253 |
| | 2018-2019 | | (5,663 | ) | | 2017 | Fixed Swaps/Futures | (8,779,000 | ) | | 2015 - 2016 | | (8,195,000 | ) | | 2014-2015 | (4,390 | ) | | 2018-2019 | | (52,653 | ) | | 2017 - 2019 | Forward Physical Contracts | (9,116,777 | ) | | 2015 | | 5,668,559 |
| | 2014-2015 | (145,105 | ) | | 2018-2020 | | (22,492 | ) | | 2017 | Natural Gas Liquid (Bbls) – Forwards/Swaps | (2,179,400 | ) | | 2015 | | (1,133,600 | ) | | 2014 | | Refined Products (Bbls) – Futures | 13,745,755 |
| | 2015 | | (280,000 | ) | | 2014 | | 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 | | 1,870,000 |
| | 2018 | | 1,580,000 |
| | 2017 | Fair Value Hedging Derivatives | | | | | | | | | (Non-Trading) | | | | | | | | | Natural Gas (MMBtu): | | | | | | Natural Gas (BBtu): | | | | | | Basis Swaps IFERC/NYMEX | (39,287,500 | ) | | 2015 | | (7,352,500 | ) | | 2014 | (39,770 | ) | | 2018 | | (36,370 | ) | | 2017 | Fixed Swaps/Futures | (39,287,500 | ) | | 2015 | | (50,530,000 | ) | | 2014 | (39,770 | ) | | 2018 | | (36,370 | ) | | 2017 | Hedged Item — Inventory | 39,287,500 |
| | 2015 | | 50,530,000 |
| | 2014 | 39,770 |
| | 2018 | | 36,370 |
| | 2017 | Cash Flow Hedging Derivatives | | | | | | (Non-Trading) | | | | | | Natural Gas (MMBtu): | | | | | | Basis Swaps IFERC/NYMEX | — |
| | — | | (1,825,000 | ) | | 2014 | | Fixed Swaps/Futures | — |
| | — | | (12,775,000 | ) | | 2014 | | Natural Gas Liquid (Bbls) – Forwards/Swaps | — |
| | — | | (780,000 | ) | | 2014 | | Crude (Bbls) – Futures | — |
| | — | | (30,000 | ) | | 2014 | |
| | (1) | Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations. |
Regency
Regency is a net seller of NGLs, condensate and natural gas as a result of its gathering and processing operations. The prices of these commodities are impacted by changes in the supply and demand as well as market forces. Regency’s profitability and cash flow are affected by the inherent volatility of these commodities, which could adversely affect its ability to make distributions to its unitholders. Regency manages this commodity price exposure through an integrated strategy that includes management of its contract portfolio, matching sales prices of commodities with purchases, optimization of its portfolio by
monitoring basis and other price differentials in operating areas and the use of derivative contracts. In some cases, Regency may not be able to match pricing terms or to cover its risk to price exposure with financial hedges, and it may be exposed to commodity price risk.
Marketing & Trading. Regency conducts natural gas marketing and trading activities through its Logistics and Trading subsidiary. Regency engages in activities intended to capitalize on favorable price differentials between various receipt and delivery locations. Regency enters into both financial derivatives and physical contracts. These financial derivatives, primarily basis swaps, are transacted: (i) to economically hedge subscribed capacity exposed to market rate fluctuations and (ii) to mitigate the price risk related to other purchase and sales of natural gas. By entering into a basis swap, one pricing index is exchanged for another, effectively locking in the margin between the natural gas purchase and sale by removing index spread risk on the combined physical and financial transaction. Changes in the fair value of these financial and physical contracts are recorded as adjustments to natural gas sales and realized (unrealized) gain (loss) from derivatives, as appropriate.
Through its natural gas marketing activity, Regency has credit exposure to additional counterparties. Regency minimizes the credit risk associated with natural gas marketing by limiting its exposure to any single counterparty and monitoring the creditworthiness of its counterparties on an ongoing basis. In addition, Regency’s natural gas purchase and sale contracts, for certain counterparties, are subject to counterparty netting agreements governing settlement under such natural gas purchase and sales contracts, and when possible, Regency nets the open positions of each counterparty.
Regency is exposed to market risks associated with commodity prices, counterparty credit, and interest rates. Regency’s management and the board of directors of Regency GP have established comprehensive risk management policies and procedures to monitor and manage these market risks. Regency GP is responsible for delegation of transaction authority levels, and the Audit and Risk Committee of Regency GP is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits. Regency GP’s Audit and Risk Committee receives regular briefings on positions and exposures, credit exposures, and overall risk management in the context of market activities.
Regency’s Preferred Units (see Note 7) contain embedded derivatives which are required to be bifurcated and accounted for separately, such as the holders’ conversion option and Regency’s call option. These embedded derivatives are accounted for using mark-to-market accounting. Regency does not expect the embedded derivatives to affect its cash flows.
The following table details Regency’s outstanding commodity-related derivatives:
| | | | | | | | | | | | December 31, 2014 | | December 31, 2013 | | Notional Volume | | Maturity | | Notional Volume | | Maturity | Mark-to-Market Derivatives | | | | | | | | (Non-Trading) | | | | | | | | Natural Gas (MMBtu) — Fixed Swaps/Futures | (25,525,000 | ) | | 2015 | | (24,455,000 | ) | | 2014-2015 | Propane (Gallons) — Forwards/Swaps | (29,148,000 | ) | | 2015 | | (52,122,000 | ) | | 2014-2015 | NGLs (Barrels) — Forwards/Swaps | (292,000 | ) | | 2015 | | (438,000 | ) | | 2014 | WTI Crude Oil (Barrels) — Forwards/Swaps | (1,252,000 | ) | | 2015-2016 | | (521,000 | ) | | 2014 |
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, 2014 | | December 31, 2013 | | Term | | Type(1) | | December 31, 2017 | | December 31, 2016 | ETP | | July 2014(2) | | Forward-starting to pay a fixed rate of 4.25% and receive a floating rate | | $ | — |
| | $ | 400 |
| | July 2017(2) | | Forward-starting to pay a fixed rate of 3.90% and receive a floating rate | | $ | — |
| | $ | 500 |
| ETP | | July 2015(2) | | Forward-starting to pay a fixed rate of 3.38% and receive a floating rate | | 200 |
| | — |
| | July 2018(2) | | Forward-starting to pay a fixed rate of 3.76% and receive a floating rate | | 300 |
| | 200 |
| ETP | | July 2016(3) | | Forward-starting to pay a fixed rate of 3.80% and receive a floating rate | | 200 |
| | — |
| | July 2019(2) | | Forward-starting to pay a fixed rate of 3.64% and receive a floating rate | | 300 |
| | 200 |
| ETP | | July 2017(4) | | Forward-starting to pay a fixed rate of 3.84% and receive a floating rate | | 300 |
| | — |
| | July 2020(2) | | Forward-starting to pay a fixed rate of 3.52% and receive a floating rate | | 400 |
| | — |
| ETP | | July 2018(4) | | Forward-starting to pay a fixed rate of 4.00% and receive a floating rate | | 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 | | July 2019(4) | | Forward-starting to pay a fixed rate of 3.19% and receive a floating rate | | 300 |
| | — |
| | March 2019 | | Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% | | 300 |
| | 300 |
| ETP | | July 2018 | | Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70% | | — |
| | 600 |
| | ETP | | June 2021 | | Pay a floating rate plus a spread of 2.17% and receive a fixed rate of 4.65% | | — |
| | 400 |
| | ETP | | February 2023 | | Pay a floating rate plus a spread of 1.73% and receive a fixed rate of 3.60% | | 200 |
| | 400 |
| | Panhandle | | November 2021 | | Pay a fixed rate of 3.82% and receive a floating rate | | — |
| | 275 |
| |
| | (1) | Floating rates are based on 3-month LIBOR. |
| | (2) | Represents the effective date. These forward-starting swaps have a term of 10 years with a mandatory termination date the same as the effective date. |
| | (3)
| 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. |
| | (4)
| 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 ETP’sthe 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, ETPthe Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. ETPThe Partnership also implements the use ofuses industry standard commercial agreements which allow for the netting of positive and negative exposures associated with transactions executed under a single commercial agreement. Additionally, ETP utilizeswe utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties. ETP’sThe 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 midstream companies. ETP’sindependent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact itsour 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.
ETPThe 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 itsour pre-established
credit limit with the counterparty. Margin deposits are returned to ETPus on or about the settlement date for non-exchange traded derivatives, and ETP exchangeswe 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. Regency is exposed to credit risk from its derivative counterparties. Regency does not require collateral from these counterparties as it deals primarily with financial institutions when entering into financial derivatives, and enters into master netting agreements that allow for netting of swap contract receivables and payables in the event of default by either party. If Regency’s counterparties failed to perform under existing swap contracts, Regency’s maximum loss as of December 31, 2014 would be $82 million, which would be reduced by less than $1 million due to the netting feature. Regency has elected to present assets and liabilities under master netting agreements gross on the condensed consolidated balance sheets for it derivate contracts outside of its marketing and trading operations.
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, 2014 | | December 31, 2013 | | December 31, 2014 | | December 31, 2013 | December 31, 2017 | | December 31, 2016 | | December 31, 2017 | | December 31, 2016 | Derivatives designated as hedging instruments: | | | | | | | | | | | | | | | Commodity derivatives (margin deposits) | $ | 43 |
| | $ | 3 |
| | $ | — |
| | $ | (18 | ) | $ | 14 |
| | $ | — |
| | $ | (2 | ) | | $ | (4 | ) | | 43 |
| | 3 |
| | — |
| | (18 | ) | 14 |
| | — |
| | (2 | ) | | (4 | ) | Derivatives not designated as hedging instruments: | | | | | | | | | | | | | | | Commodity derivatives (margin deposits) | $ | 617 |
| | $ | 227 |
| | $ | (577 | ) | | $ | (209 | ) | 262 |
| | 338 |
| | (281 | ) | | (416 | ) | Commodity derivatives | 107 |
| | 43 |
| | (23 | ) | | (48 | ) | 45 |
| | 25 |
| | (58 | ) | | (58 | ) | Interest rate derivatives | 3 |
| | 47 |
| | (155 | ) | | (95 | ) | — |
| | — |
| | (219 | ) | | (193 | ) | Embedded derivatives in Regency Preferred Units | — |
| | — |
| | (16 | ) | | (19 | ) | | Embedded derivatives in ETP Convertible Preferred Units | | — |
| | — |
| | — |
| | (1 | ) | | 727 |
| | 317 |
| | (771 | ) | | (371 | ) | 307 |
| | 363 |
| | (558 | ) | | (668 | ) | Total derivatives | $ | 770 |
| | $ | 320 |
| | $ | (771 | ) | | $ | (389 | ) | $ | 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, 2014 | | December 31, 2013 | | December 31, 2014 | | December 31, 2013 | | Balance Sheet Location | | December 31, 2017 | | December 31, 2016 | | December 31, 2017 | | December 31, 2016 | Derivatives without offsetting agreements | | | Derivative assets (liabilities) | | $ | — |
| | $ | — |
| | $ | (219 | ) | | $ | (194 | ) | Derivatives in offsetting agreements: | Derivatives in offsetting agreements: | | | | | | | | | Derivatives in offsetting agreements: | | | | | | | | | OTC contracts | | Price risk management assets (liabilities) | | $ | 23 |
| | $ | 42 |
| | $ | (23 | ) | | $ | (38 | ) | | Derivative assets (liabilities) | | 45 |
| | 25 |
| | (58 | ) | | (58 | ) | Broker cleared derivative contracts | | Other current assets | | 674 |
| | 264 |
| | (574 | ) | | (318 | ) | | Other current assets (liabilities) | | 276 |
| | 338 |
| | (283 | ) | | (420 | ) | | | | 697 |
| | 306 |
| | (597 | ) | | (356 | ) | | | 321 |
| | 363 |
| | (560 | ) | | (672 | ) | Offsetting agreements: | Offsetting agreements: | | | | | | | | | Offsetting agreements: | | | | | | | | | Counterparty netting | | Price risk management assets (liabilities) | | (19 | ) | | (36 | ) | | 19 |
| | 36 |
| | Derivative assets (liabilities) | | (21 | ) | | (4 | ) | | 21 |
| | 4 |
| Payments on margin deposit | | Other current assets | | 5 |
| | (1 | ) | | (22 | ) | | 55 |
| | | | (14 | ) | | (37 | ) | | (3 | ) | | 91 |
| | Net derivatives with offsetting agreements | | 683 |
| | 269 |
| | (600 | ) | | (265 | ) | | Derivatives without offsetting agreements | | 87 |
| | 51 |
| | (171 | ) | | (124 | ) | | Total derivatives | | $ | 770 |
| | $ | 320 |
| | $ | (771 | ) | | $ | (389 | ) | | Counterparty netting | | | Other current assets (liabilities) | | (263 | ) | | (338 | ) | | 263 |
| | 338 |
| Total net derivatives | | Total net derivatives | | $ | 37 |
| | $ | 21 |
| | $ | (276 | ) | | $ | (330 | ) |
We disclose the non-exchange traded financial derivative instruments as price risk managementderivative 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: | | | Change in Value Recognized in OCI on Derivatives (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, | | 2014 | | 2013 | | 2012 | 2017 | | 2016 | | 2015 | Derivatives in cash flow hedging relationships: | | | | | | | Derivatives in fair value hedging relationships (including hedged item): | | | | | | | | Commodity derivatives | $ | — |
| | $ | (1 | ) | | $ | 8 |
| Cost of products sold | | $ | 26 |
| | $ | 14 |
| | $ | 21 |
| Total | $ | — |
| | $ | (1 | ) | | $ | 8 |
| | $ | 26 |
| | $ | 14 |
| | $ | 21 |
|
| | | | | | | | | | | | | | | | Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) | | Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) | | Years Ended December 31, | | 2014 | | 2013 | | 2012 | Derivatives in cash flow hedging relationships: | | | | | | | | Commodity derivatives | Cost of products sold | | $ | (3 | ) | | $ | 4 |
| | $ | 14 |
| Total | | | $ | (3 | ) | | $ | 4 |
| | $ | 14 |
|
| | | | | | | | | | | | | | | | 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 | | 5 |
| | (177 | ) | | 15 |
| Interest rate derivatives | Losses on interest rate derivatives | | (37 | ) | | (12 | ) | | (18 | ) | Embedded derivatives | Other, net | | 1 |
| | 4 |
| | 12 |
| Total | | | $ | — |
| | $ | (220 | ) | | $ | (2 | ) |
| | | | | | | | | | | | | | | | 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, | | 2014 | | 2013 | | 2012 | Derivatives in fair value hedging relationships (including hedged item): | | | | | | | | Commodity derivatives | Cost of products sold | | $ | (8 | ) | | $ | 8 |
| | $ | 54 |
| Total | | | $ | (8 | ) | | $ | 8 |
| | $ | 54 |
|
| | | | | | | | | | | | | | | | Location of Gain/(Loss) Recognized in Income on Derivatives | | Amount of Gain/(Loss) Recognized in Income on Derivatives | | | Years Ended December 31, | | | 2014 | | 2013 | | 2012 | Derivatives not designated as hedging instruments: | | | | | | | | Commodity derivatives – Trading | Cost of products sold | | $ | (6 | ) | | $ | (11 | ) | | $ | (7 | ) | Commodity derivatives – Non-trading | Cost of products sold | | 199 |
| | (21 | ) | | 26 |
| Commodity contracts – Non-trading | Deferred gas purchases | | — |
| | (3 | ) | | (26 | ) | Interest rate derivatives | Gains (losses) on interest rate derivatives | | (157 | ) | | 53 |
| | (19 | ) | Embedded derivatives | Other income | | 3 |
| | 6 |
| | 14 |
| Total | | | $ | 39 |
| | $ | 24 |
| | $ | (12 | ) |
| | 14.13. | RETIREMENT BENEFITS: |
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, RegencySunoco 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 $59$38 million, $47$44 million and $30$40 million to the 401(k) savings plan for the years ended December 31, 2014, 20132017, 2016, and 2012,2015, 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 were available tocovered substantially all of its employees, pendingemployees. 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 meeting certain age and service requirements.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 anticipates approval for the distribution of assets from the plan, pending approval from the Pension Benefit Guaranty Corporationpaid lump sums to eligible active and the IRS,terminated vested participants in the fourth quarter ofDecember 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$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, 2014 | | December 31, 2013 | 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 | $ | 632 |
| | $ | 61 |
| | $ | 223 |
| | $ | 1,117 |
| | $ | 78 |
| | $ | 296 |
| $ | 18 |
| | $ | 51 |
| | $ | 166 |
| | $ | 20 |
| | $ | 57 |
| | $ | 181 |
| Service cost | — |
| | — |
| | — |
| | 3 |
| | — |
| | — |
| | Interest cost | 28 |
| | 3 |
| | 5 |
| | 33 |
| | 2 |
| | 6 |
| 1 |
| | 1 |
| | 4 |
| | 1 |
| | 2 |
| | 4 |
| Amendments | — |
| | — |
| | 1 |
| | — |
| | — |
| | 2 |
| — |
| | — |
| | 7 |
| | — |
| | — |
| | — |
| Benefits paid, net | (45 | ) | | (9 | ) | | (28 | ) | | (99 | ) | | (16 | ) | | (26 | ) | (2 | ) | | (6 | ) | | (20 | ) | | (1 | ) | | (7 | ) | | (21 | ) | Actuarial (gain) loss and other | 130 |
| | 10 |
| | 2 |
| | (74 | ) | | (3 | ) | | (14 | ) | 2 |
| | 1 |
| | (1 | ) | | (2 | ) | | (1 | ) | | 2 |
| Settlements | (27 | ) | | — |
| | — |
| | (95 | ) | | — |
| | — |
| (18 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| Dispositions | — |
| | — |
| | — |
| | (253 | ) | | — |
| | (41 | ) | | Benefit obligation at end of period | $ | 718 |
| | $ | 65 |
| | $ | 203 |
| | $ | 632 |
| | $ | 61 |
| | $ | 223 |
| $ | 1 |
| | $ | 47 |
| | $ | 156 |
| | $ | 18 |
| | $ | 51 |
| | $ | 166 |
| | | | | | | | | | | | | | | | | | | | | | | | Change in plan assets: | | | | | | | | | | | | | | | | | | | | | | | Fair value of plan assets at beginning of period | 600 |
| | — |
| | 284 |
| | 906 |
| | — |
| | 312 |
| $ | 12 |
| | $ | — |
| | $ | 256 |
| | $ | 15 |
| | $ | — |
| | $ | 261 |
| Return on plan assets and other | 70 |
| | — |
| | 7 |
| | 43 |
| | — |
| | 17 |
| 3 |
| | — |
| | 11 |
| | (2 | ) | | — |
| | 6 |
| Employer contributions | — |
| | — |
| | 9 |
| | — |
| | — |
| | 8 |
| 6 |
| | — |
| | 10 |
| | — |
| | — |
| | 10 |
| Benefits paid, net | (45 | ) | | — |
| | (28 | ) | | (99 | ) | | — |
| | (26 | ) | (2 | ) | | — |
| | (20 | ) | | (1 | ) | | — |
| | (21 | ) | Settlements | (27 | ) | | — |
| | — |
| | (95 | ) | | — |
| | — |
| (18 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| Dispositions | — |
| | — |
| | — |
| | (155 | ) | | — |
| | (27 | ) | | Fair value of plan assets at end of period | $ | 598 |
| | $ | — |
| | $ | 272 |
| | $ | 600 |
| | $ | — |
| | $ | 284 |
| $ | 1 |
| | $ | — |
| | $ | 257 |
| | $ | 12 |
| | $ | — |
| | $ | 256 |
| | | | | | | | | | | | | | | | | | | | | | | | Amount underfunded (overfunded) at end of period | $ | 120 |
| | $ | 65 |
| | $ | (69 | ) | | $ | 32 |
| | $ | 61 |
| | $ | (61 | ) | $ | — |
| | $ | 47 |
| | $ | (101 | ) | | $ | 6 |
| | $ | 51 |
| | $ | (90 | ) | | | | | | | | | | | | | | | | | | | | | | | | Amounts recognized in the consolidated balance sheets consist of: | | | | | | | | | | | | | | | | | | | | | | | Non-current assets | $ | — |
| | $ | — |
| | $ | 96 |
| | $ | — |
| | $ | — |
| | $ | 86 |
| $ | — |
| | $ | — |
| | $ | 127 |
| | $ | — |
| | $ | — |
| | $ | 114 |
| Current liabilities | — |
| | (9 | ) | | (2 | ) | | — |
| | (9 | ) | | (2 | ) | — |
| | (8 | ) | | (2 | ) | | — |
| | (7 | ) | | (2 | ) | Non-current liabilities | (120 | ) | | (56 | ) | | (25 | ) | | (32 | ) | | (52 | ) | | (23 | ) | — |
| | (39 | ) | | (24 | ) | | (6 | ) | | (44 | ) | | (23 | ) | | $ | (120 | ) | | $ | (65 | ) | | $ | 69 |
| | $ | (32 | ) | | $ | (61 | ) | | $ | 61 |
| $ | — |
| | $ | (47 | ) | | $ | 101 |
| | $ | (6 | ) | | $ | (51 | ) | | $ | 89 |
| | | | | | | | | | | | | | | | | | | | | | | | Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of: | | | | | | | | | | | | | | | | | | | | | | | Net actuarial gain | $ | 18 |
| | $ | 7 |
| | $ | (21 | ) | | $ | (86 | ) | | $ | (4 | ) | | $ | (25 | ) | $ | — |
| | $ | 5 |
| | $ | (18 | ) | | $ | — |
| | $ | — |
| | $ | (13 | ) | Prior service cost | — |
| | — |
| | 18 |
| | — |
| | — |
| | 18 |
| — |
| | — |
| | 21 |
| | — |
| | — |
| | 15 |
| | $ | 18 |
| | $ | 7 |
| | $ | (3 | ) | | $ | (86 | ) | | $ | (4 | ) | | $ | (7 | ) | $ | — |
| | $ | 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, 2014 | | December 31, 2013 | 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 | $ | 718 |
| | $ | 65 |
| | N/A |
| | $ | 632 |
| | 61 |
| | N/A |
| $ | 1 |
| | $ | 47 |
| | N/A |
| | $ | 18 |
| | $ | 51 |
| | N/A |
| Accumulated benefit obligation | 718 |
| | 65 |
| | 203 |
| | 632 |
| | 61 |
| | $ | 223 |
| 1 |
| | 47 |
| | $ | 156 |
| | 18 |
| | 51 |
| | $ | 166 |
| Fair value of plan assets | 598 |
| | — |
| | 272 |
| | 600 |
| | — |
| | 284 |
| 1 |
| | — |
| | 257 |
| | 12 |
| | — |
| | 256 |
|
Components of Net Periodic Benefit Cost | | | December 31, 2014 | | December 31, 2013 | 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: | | | | | | | | | | | | | | | Service cost | $ | — |
| | $ | — |
| | $ | 3 |
| | $ | — |
| | Interest cost | 31 |
| | 5 |
| | 35 |
| | 6 |
| $ | 2 |
| | $ | 4 |
| | $ | 3 |
| | $ | 4 |
| Expected return on plan assets | (40 | ) | | (8 | ) | | (54 | ) | | (9 | ) | — |
| | (9 | ) | | (1 | ) | | (8 | ) | Prior service cost amortization | — |
| | 1 |
| | — |
| | 1 |
| — |
| | 2 |
| | — |
| | 1 |
| Actuarial loss amortization | (1 | ) | | (1 | ) | | 2 |
| | — |
| | Settlements | (4 | ) | | — |
| | (2 | ) | | — |
| | | (14 | ) | | (3 | ) | | (16 | ) | | (2 | ) | | Regulatory adjustment(1) | — |
| | — |
| | 5 |
| | — |
| | Net periodic benefit cost | $ | (14 | ) | | $ | (3 | ) | | $ | (11 | ) | | $ | (2 | ) | $ | 2 |
| | $ | (3 | ) | | $ | 2 |
| | $ | (3 | ) |
| | (1)
| Southern Union, the predecessor of Panhandle, historically recovered certain qualified pension benefit plan and other postretirement benefit plan costs through rates charged to utility customers in its distribution operation. Certain utility commissions require that the recovery of these costs be based on the Employee Retirement Income Security Act of 1974, as amended, or other utility commission specific guidelines. The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and amortized to expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission. |
Assumptions The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below: | | | December 31, 2014 | | December 31, 2013 | 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 | 3.62 | % | | 2.24 | % | | 4.65 | % | | 2.33 | % | 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, 2014 | | December 31, 2013 | 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 | 4.65 | % | | 3.02 | % | | 3.50 | % | | 2.68 | % | 3.52 | % | | 3.10 | % | | 3.60 | % | | 3.06 | % | Expected return on assets: | | | | | | | | | | | | | | | Tax exempt accounts | 7.50 | % | | 7.00 | % | | 7.50 | % | | 6.95 | % | 3.50 | % | | 7.00 | % | | 3.50 | % | | 7.00 | % | Taxable accounts | N/A |
| | 4.50 | % | | N/A |
| | 4.42 | % | 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, | | 2014 | | 2013 | 2017 | | 2016 | Health care cost trend rate | 7.09 | % | | 7.57 | % | 7.20 | % | | 6.73 | % | Rate to which the cost trend is assumed to decline (the ultimate trend rate) | 5.41 | % | | 5.42 | % | 4.99 | % | | 4.96 | % | Year that the rate reaches the ultimate trend rate | 2018 |
| | 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, 2014 Using Fair Value Hierarchy | | | | Fair Value Measurements at December 31, 2017 | | | Fair Value as of December 31, 2014 | | Level 1 | | Level 2 | | Level 3 | | Fair Value Total | | Level 1 | | Level 2 | | Level 3 | Asset Category: | | | | | | | | | | | | | | | | | Cash and cash equivalents | | $ | 25 |
| | $ | 25 |
| | $ | — |
| | $ | — |
| | Mutual funds (1) | | 110 |
| | — |
| | 110 |
| | — |
| | $ | 1 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| Fixed income securities | | 463 |
| | — |
| | 463 |
| | — |
| | Total | | $ | 598 |
| | $ | 25 |
| | $ | 573 |
| | $ | — |
| | $ | 1 |
| | $ | 1 |
| | $ | — |
| | $ | — |
|
| | (1) | Comprised of 100% equities as of December 31, 2014.2017. |
| | | | | | Fair Value Measurements at December 31, 2013 Using Fair Value Hierarchy | | | | Fair Value Measurements at December 31, 2016 | | | Fair Value as of December 31, 2013 | | Level 1 | | Level 2 | | Level 3 | | Fair Value Total | | Level 1 | | Level 2 | | Level 3 | Asset Category: | | | | | | | | | | | | | | | | | Cash and cash equivalents | | $ | 12 |
| | $ | 12 |
| | $ | — |
| | $ | — |
| | Mutual funds (1) | | 368 |
| | — |
| | 281 |
| | 87 |
| | $ | 12 |
| | $ | 12 |
| | $ | — |
| | $ | — |
| Fixed income securities | | 220 |
| | — |
| | 220 |
| | — |
| | Total | | $ | 600 |
| | $ | 12 |
| | $ | 501 |
| | $ | 87 |
| | $ | 12 |
| | $ | 12 |
| | $ | — |
| | $ | — |
|
| | (1) | Primarily comprisedComprised of approximately 41%100% equities 45% fixed income securities, and 14% in other investments as of December 31, 2013.2016. |
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, 2014 Using Fair Value Hierarchy | | | | Fair Value Measurements at December 31, 2017 | | | Fair Value as of December 31, 2014 | | Level 1 | | Level 2 | | Level 3 | | Fair Value Total | | Level 1 | | Level 2 | | Level 3 | Asset Category: | | | | | | | | | | | | | | | | | Cash and Cash Equivalents | | $ | 9 |
| | $ | 9 |
| | $ | — |
| | $ | — |
| | $ | 33 |
| | $ | 33 |
| | $ | — |
| | $ | — |
| Mutual funds (1) | | 138 |
| | 138 |
| | — |
| | — |
| | 154 |
| | 154 |
| | — |
| | — |
| Fixed income securities | | 125 |
| | — |
| | 125 |
| | — |
| | 70 |
| | — |
| | 70 |
| | — |
| Total | | $ | 272 |
| | $ | 147 |
| | $ | 125 |
| | $ | — |
| | $ | 257 |
| | $ | 187 |
| | $ | 70 |
| | $ | — |
|
| | (1) | Primarily comprised of approximately 53%38% equities, 41%61% fixed income securities 6%and 2% cash as of December 31, 2014.2017. |
| | | | | | Fair Value Measurements at December 31, 2013 Using Fair Value Hierarchy | | | | Fair Value Measurements at December 31, 2016 | | | Fair Value as of December 31, 2013 | | Level 1 | | Level 2 | | Level 3 | | Fair Value Total | | Level 1 | | Level 2 | | Level 3 | Asset Category: | | | | | | | | | | | | | | | | | Cash and Cash Equivalents | | $ | 10 |
| | $ | 10 |
| | $ | — |
| | $ | — |
| | $ | 23 |
| | $ | 23 |
| | $ | — |
| | $ | — |
| Mutual funds (1) | | 130 |
| | 112 |
| | 18 |
| | — |
| | 142 |
| | 142 |
| | — |
| | — |
| Fixed income securities | | 144 |
| | — |
| | 144 |
| | — |
| | 91 |
| | — |
| | 91 |
| | — |
| Total | | $ | 284 |
| | $ | 122 |
| | $ | 162 |
| | $ | — |
| | $ | 256 |
| | $ | 165 |
| | $ | 91 |
| | $ | — |
|
| | (1) | Primarily comprised of approximately 41%31% equities, 48%66% fixed income securities and 6%3% cash and 5% in other investments as of December 31, 2013.2016. |
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. See Note 2for information related to the framework used to measure the fair value of its pension and other postretirement plan assets. Contributions We expect to contribute approximately $129$8 million to pension plans and approximately $10 million to other postretirementpostretirement plans in 2015.2018. 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) | 2015 | | $ | 717 |
| | $ | 9 |
| | $ | 28 |
| 2016 | | — |
| | 8 |
| | 26 |
| 2017 | | — |
| | 7 |
| | 25 |
| 2018 | | — |
| | 7 |
| | 23 |
| 2019 | | — |
| | 6 |
| | 22 |
| 2020 – 2024 | | — |
| | 23 |
| | 65 |
|
| | | | | | | | | | Years | | Pension Benefits - Unfunded Plans (1) | | Other Postretirement Benefits (Gross, Before Medicare Part D) | 2018 | | $ | 8 |
| | $ | 24 |
| 2019 | | 6 |
| | 23 |
| 2020 | | 6 |
| | 21 |
| 2021 | | 5 |
| | 19 |
| 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.
| | 15.14. | 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 16).2016.
In addition, subsidiaries of ETE recorded sales with affiliates of $965$303 million, $1.44 billion$221 million and $189$290 million during the years ended December 31, 2014, 20132017, 2016 and 2012,2015, respectively. | | 16.15. | REPORTABLE SEGMENTS: |
AsSubsequent to ETE’s acquisition of a result of the Lake Charles LNG Transactioncontrolling interest in 2014,Sunoco LP, our reportable segments were re-evaluated and currentlyfinancial statements reflect the following reportable segments, which conduct their business exclusively in the United States, as follows:segments:
Investment in ETP, including the consolidated operations of ETP; Investment in Regency,Sunoco LP, including the consolidated operations of Regency;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. Related party transactions among our segments are generally based on transactions made at market-related rates. Consolidated revenues and expensesETP 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 all material intercompany transactions.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, losslosses on extinguishmentextinguishments of debt gain on deconsolidation 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 and amounts for less than wholly owned subsidiaries based on 100% of the subsidiaries’ results of operations. 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. Regency completed its acquisition of SUGS on April 30, 2013. Therefore, the investment in Regency segment amounts have been retrospectively adjusted to reflect SUGS beginning March 26, 2012.
Eliminations in the tables below include the following: ETP’s Segment Adjusted EBITDA reflects 100% of Lone Star, which is a consolidated subsidiary of ETP. Regency’s Segment Adjusted EBITDA includes its 30% investment in Lone Star. Therefore, 30% of the results of Lone Star are included in eliminations.
ETP’s Segment Adjusted EBITDA reflects the results of SUGS from March 26, 2012 to April 30, 2013. Since the SUGS Contribution was a transaction between entities under common control, Regency’s results have been recast to retrospectively consolidate SUGS beginning March 26, 2012. Therefore, the eliminations also include the results of SUGS from March 26, 2012 to April 30, 2013.
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 segmentsMACS, Sunoco LLC, Susser and Sunoco Retail LLC for the years ended December 31, 2013 and 2012 beginning March 26, 2012. Therefore, the results of Lake Charles LNGperiods during which those entities were included in eliminations for 2013the consolidated results of both ETP and 2012.
| | | | | | | | | | | | | | Years Ended December 31, | | 2014 | | 2013 | | 2012 | Revenues: | | | | | | Investment in ETP: | | | | | | Revenues from external customers | $ | 50,989 |
| | $ | 46,210 |
| | $ | 15,671 |
| Intersegment revenues | 169 |
| | 129 |
| | 31 |
| | 51,158 |
| | 46,339 |
| | 15,702 |
| Investment in Regency: | | | | | | Revenues from external customers | 4,597 |
| | 2,404 |
| | 1,986 |
| Intersegment revenues | 354 |
| | 117 |
| | 14 |
| | 4,951 |
| | 2,521 |
| | 2,000 |
| Investment in Lake Charles LNG: | | | | | | Revenues from external customers | 216 |
| | 216 |
| | 166 |
| |
|
| |
|
| |
|
| Adjustments and Eliminations: | (634 | ) | | (741 | ) | | (904 | ) | Total revenues | $ | 55,691 |
| | $ | 48,335 |
| | $ | 16,964 |
| | | | | | | Costs of products sold: | | | | | | Investment in ETP | $ | 45,540 |
| | $ | 41,204 |
| | $ | 12,266 |
| Investment in Regency | 3,452 |
| | 1,793 |
| | 1,387 |
| Adjustments and Eliminations | (603 | ) | | (443 | ) | | (565 | ) | Total costs of products sold | $ | 48,389 |
| | $ | 42,554 |
| | $ | 13,088 |
| | | | | | | Depreciation, depletion and amortization: | | | | | | Investment in ETP | 1,130 |
| | 1,032 |
| | 656 |
| Investment in Regency | 541 |
| | 287 |
| | 252 |
| Investment in Lake Charles LNG | 39 |
| | 39 |
| | 30 |
| Corporate and Other | 17 |
| | 16 |
| | 14 |
| Adjustments and Eliminations | (3 | ) | | (61 | ) | | (81 | ) | Total depreciation, depletion and amortization | $ | 1,724 |
| | $ | 1,313 |
| | $ | 871 |
|
Sunoco LP, as discussed above. | | | | | | | | | | | | | | Years Ended December 31, | | 2014 | | 2013 | | 2012 | Equity in earnings of unconsolidated affiliates: | | | | | | Investment in ETP | $ | 234 |
| | $ | 172 |
| | $ | 142 |
| Investment in Regency | 195 |
| | 135 |
| | 105 |
| Adjustments and Eliminations | (97 | ) | | (71 | ) | | (35 | ) | Total equity in earnings of unconsolidated affiliates | $ | 332 |
| | $ | 236 |
| | $ | 212 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2014 | | 2013 | | 2012 | Segment Adjusted EBITDA: | | | | | | Investment in ETP | $ | 4,829 |
| | $ | 3,953 |
| | $ | 2,744 |
| Investment in Regency | 1,172 |
| | 608 |
| | 517 |
| Investment in Lake Charles LNG | 195 |
| | 187 |
| | 135 |
| Corporate and Other | (97 | ) | | (43 | ) | | (52 | ) | Adjustments and Eliminations | (259 | ) | | (338 | ) | | (239 | ) | Total Segment Adjusted EBITDA | 5,840 |
| | 4,367 |
| | 3,105 |
| Depreciation, depletion and amortization | (1,724 | ) | | (1,313 | ) | | (871 | ) | Interest expense, net of interest capitalized | (1,369 | ) | | (1,221 | ) | | (1,018 | ) | Bridge loan related fees | — |
| | — |
| | (62 | ) | Gain on deconsolidation of Propane Business | — |
| | — |
| | 1,057 |
| Gain on sale of AmeriGas common units | 177 |
| | 87 |
| | — |
| Goodwill impairment | (370 | ) | | (689 | ) | | — |
| Gains (losses) on interest rate derivatives | (157 | ) | | 53 |
| | (19 | ) | Non-cash unit-based compensation expense | (82 | ) | | (61 | ) | | (47 | ) | Unrealized gains on commodity risk management activities | 116 |
| | 48 |
| | 10 |
| Losses on extinguishments of debt | (25 | ) | | (162 | ) | | (123 | ) | Inventory valuation adjustments | (473 | ) | | 3 |
| | (75 | ) | Adjusted EBITDA related to discontinued operations | (27 | ) | | (76 | ) | | (99 | ) | Adjusted EBITDA related to unconsolidated affiliates | (748 | ) | | (727 | ) | | (647 | ) | Equity in earnings of unconsolidated affiliates | 332 |
| | 236 |
| | 212 |
| Non-operating environmental remediation | — |
| | (168 | ) | | — |
| Other, net | (73 | ) | | (2 | ) | | 14 |
| Income from continuing operations before income tax expense | $ | 1,417 |
| | $ | 375 |
| | $ | 1,437 |
|
| | | | | | | | | | | | | | 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 |
|
| | | | | | | | | | | | | | December 31, | | 2014 | | 2013 | | 2012 | Total assets: | | | | | | Investment in ETP | $ | 48,221 |
| | $ | 43,702 |
| | $ | 43,230 |
| Investment in Regency | 17,103 |
| | 8,782 |
| | 8,123 |
| Investment in Lake Charles LNG | 1,210 |
| | 1,338 |
| | 1,917 |
| Corporate and Other | 1,153 |
| | 720 |
| | 707 |
| Adjustments and Eliminations | (3,218 | ) | | (4,212 | ) | | (5,073 | ) | Total | $ | 64,469 |
| | $ | 50,330 |
| | $ | 48,904 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | Equity in earnings of unconsolidated affiliates: | | | | | | Investment in ETP | $ | 156 |
| | $ | 59 |
| | $ | 469 |
| Adjustments and Eliminations | (12 | ) | | 211 |
| | (193 | ) | Total equity in earnings of unconsolidated affiliates | $ | 144 |
| | $ | 270 |
| | $ | 276 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2014 | | 2013 | | 2012 | Additions to property, plant and equipment, net of contributions in aid of construction costs (accrual basis): | | | | | | Investment in ETP | $ | 4,478 |
| | $ | 2,455 |
| | $ | 3,049 |
| Investment in Regency | 1,112 |
| | 1,011 |
| | 599 |
| Investment in Lake Charles LNG | 1 |
| | 2 |
| | 4 |
| Adjustments and Eliminations | (32 | ) | | (126 | ) | | (135 | ) | Total | $ | 5,559 |
| | $ | 3,342 |
| | $ | 3,517 |
|
| | | | | | | | | | | | | | December 31, | | 2014 | | 2013 | | 2012 | Advances to and investments in affiliates: | | | | | | Investment in ETP | $ | 3,840 |
| | $ | 4,436 |
| | $ | 3,502 |
| Investment in Regency | 2,418 |
| | 2,097 |
| | 2,214 |
| Adjustments and Eliminations | (2,599 | ) | | (2,519 | ) | | (979 | ) | Total | $ | 3,659 |
| | $ | 4,014 |
| | $ | 4,737 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | Segment Adjusted EBITDA: | | | | | | Investment in ETP | $ | 6,712 |
| | $ | 5,733 |
| | $ | 5,517 |
| Investment in Sunoco LP | 732 |
| | 665 |
| | 719 |
| Investment in Lake Charles LNG | 175 |
| | 179 |
| | 196 |
| Corporate and Other | (31 | ) | | (170 | ) | | (104 | ) | Adjustments and Eliminations | (268 | ) | | (272 | ) | | (590 | ) | Total Segment Adjusted EBITDA | 7,320 |
| | 6,135 |
| | 5,738 |
| Depreciation, depletion and amortization | (2,554 | ) | | (2,216 | ) | | (1,951 | ) | Interest expense, net of interest capitalized | (1,922 | ) | | (1,804 | ) | | (1,622 | ) | Gains on acquisitions | — |
| | 83 |
| | — |
| Impairment of investments in unconsolidated affiliates | (313 | ) | | (308 | ) | | — |
| Impairment losses | (1,039 | ) | | (1,040 | ) | | (339 | ) | Losses on interest rate derivatives | (37 | ) | | (12 | ) | | (18 | ) | Non-cash unit-based compensation expense | (99 | ) | | (70 | ) | | (91 | ) | Unrealized gains (losses) on commodity risk management activities | 59 |
| | (136 | ) | | (65 | ) | Losses on extinguishments of debt | (89 | ) | | — |
| | (43 | ) | Inventory valuation adjustments | 24 |
| | 97 |
| | (67 | ) | Adjusted EBITDA related to discontinued operations | (223 | ) | | (199 | ) | | (228 | ) | Adjusted EBITDA related to unconsolidated affiliates | (716 | ) | | (675 | ) | | (713 | ) | Equity in earnings of unconsolidated affiliates | 144 |
| | 270 |
| | 276 |
| Other, net | 155 |
| | 79 |
| | 23 |
| 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, | | 2017 | | 2016 | | 2015 | Total assets: | | | | | | Investment in ETP | $ | 77,965 |
| | $ | 70,105 |
| | $ | 65,128 |
| Investment in Sunoco LP | 8,344 |
| | 8,701 |
| | 8,842 |
| Investment in Lake Charles LNG | 1,646 |
| | 1,508 |
| | 1,369 |
| Corporate and Other | 598 |
| | 711 |
| | 638 |
| Adjustments and Eliminations | (2,307 | ) | | (2,100 | ) | | (4,833 | ) | Total | $ | 86,246 |
| | $ | 78,925 |
| | $ | 71,144 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | 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 | $ | 5,901 |
| | $ | 5,810 |
| | $ | 8,167 |
| Investment in Sunoco LP | 103 |
| | 119 |
| | 178 |
| Investment in Lake Charles LNG | 2 |
| | — |
| | 1 |
| Adjustments and Eliminations | — |
| | — |
| | (123 | ) | Total | $ | 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 Regency.Sunoco LP. Investment in ETP | | | Years Ended December 31, | Years Ended December 31, | | 2014 | | 2013 | | 2012 | 2017 | | 2016 | | 2015 | Intrastate Transportation and Storage | $ | 2,652 |
| | $ | 2,250 |
| | $ | 2,012 |
| $ | 2,891 |
| | $ | 2,155 |
| | $ | 1,912 |
| Interstate Transportation and Storage | 1,057 |
| | 1,270 |
| | 1,109 |
| 915 |
| | 946 |
| | 1,008 |
| Midstream | 1,210 |
| | 1,307 |
| | 1,757 |
| 2,510 |
| | 2,342 |
| | 2,607 |
| Liquids Transportation and Services | 3,790 |
| | 2,063 |
| | 619 |
| | Investment in Sunoco Logistics | 17,920 |
| | 16,480 |
| | 3,109 |
| | Retail Marketing | 22,484 |
| | 21,004 |
| | 5,926 |
| | 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 | 2,045 |
| | 1,965 |
| | 1,170 |
| 2,740 |
| | 2,872 |
| | 15,216 |
| Total revenues | 51,158 |
| | 46,339 |
| | 15,702 |
| 29,054 |
| | 21,827 |
| | 34,292 |
| Less: Intersegment revenues | 169 |
| | 129 |
| | 31 |
| 441 |
| | 209 |
| | 136 |
| Revenues from external customers | $ | 50,989 |
| | $ | 46,210 |
| | $ | 15,671 |
| $ | 28,613 |
| | $ | 21,618 |
| | $ | 34,156 |
|
Investment in RegencySunoco LP | | | | | | | | | | | | | | Years Ended December 31, | | 2014 | | 2013 | | 2012 | Gathering and Processing | $ | 4,570 |
| | $ | 2,287 |
| | $ | 1,797 |
| Contract Services | 307 |
| | 215 |
| | 183 |
| Natural Gas Transportation | — |
| | 1 |
| | 1 |
| Natural Resources | 58 |
| | — |
| | — |
| Corporate and others | 16 |
| | 18 |
| | 19 |
| Total revenues | 4,951 |
| | 2,521 |
| | 2,000 |
| Less: Intersegment revenues | 354 |
| | 117 |
| | 14 |
| Revenues from external customers | $ | 4,597 |
| | $ | 2,404 |
| | $ | 1,986 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | Retail operations | $ | 2,263 |
| | $ | 1,991 |
| | $ | 2,226 |
| Wholesale operations | 9,460 |
| | 7,995 |
| | 10,204 |
| Total revenues | 11,723 |
| | 9,986 |
| | 12,430 |
| Less: Intersegment revenues | 10 |
| | 9 |
| | 11 |
| Revenues from external customers | $ | 11,713 |
| | $ | 9,977 |
| | $ | 12,419 |
|
Investment in Lake Charles LNG Lake Charles LNG’s revenues of $216$197 million, $216$197 million and $166$216 million for the yearyears ended December 31, 2014, 20132017, 2016 and 2012,2015, respectively, were related to LNG terminalling.
| | 17.16. | 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 | 2014: | | | | | | | | | | | 2017: | | | | | | | | | | | Revenues | $ | 13,080 |
| | $ | 14,143 |
| | $ | 14,987 |
| | $ | 13,481 |
| | $ | 55,691 |
| $ | 9,660 |
| | $ | 9,427 |
| | $ | 9,984 |
| | $ | 11,452 |
| | $ | 40,523 |
| Gross margin | 1,638 |
| | 1,792 |
| | 1,972 |
| | 1,900 |
| | 7,302 |
| | Operating income | 710 |
| | 773 |
| | 822 |
| | 165 |
| | 2,470 |
| | Operating income (loss) | | 758 |
| | 746 |
| | 924 |
| | 285 |
| | 2,713 |
| Net income (loss) | 448 |
| | 500 |
| | 470 |
| | (294 | ) | | 1,124 |
| 319 |
| | 121 |
| | 758 |
| | 1,168 |
| | 2,366 |
| Limited Partners’ interest in net income | 167 |
| | 163 |
| | 188 |
| | 111 |
| | 629 |
| 232 |
| | 204 |
| | 240 |
| | 239 |
| | 915 |
| Basic net income per limited partner unit | $ | 0.30 |
| | $ | 0.30 |
| | $ | 0.35 |
| | $ | 0.21 |
| | $ | 1.16 |
| $ | 0.22 |
| | $ | 0.18 |
| | $ | 0.22 |
| | $ | 0.22 |
| | $ | 0.85 |
| Diluted net income per limited partner unit | $ | 0.30 |
| | $ | 0.30 |
| | $ | 0.35 |
| | $ | 0.21 |
| | $ | 1.15 |
| $ | 0.21 |
| | $ | 0.18 |
| | $ | 0.22 |
| | $ | 0.22 |
| | $ | 0.83 |
|
| | | | | | | | | | | | | | | | | | | | | | Quarters Ended | | | | March 31 | | June 30 | | September 30 | | December 31 | | Total Year | 2013: | | | | | | | | | | Revenues | $ | 11,179 |
| | $ | 12,063 |
| | $ | 12,486 |
| | $ | 12,607 |
| | $ | 48,335 |
| Gross margin | 1,372 |
| | 1,498 |
| | 1,422 |
| | 1,489 |
| | 5,781 |
| Operating income (loss) | 531 |
| | 644 |
| | 529 |
| | (153 | ) | | 1,551 |
| Net income (loss) | 322 |
| | 338 |
| | 356 |
| | (701 | ) | | 315 |
| Limited Partners’ interest in net income (loss) | 90 |
| | 127 |
| | 150 |
| | (171 | ) | | 196 |
| Basic net income (loss) per limited partner unit | $ | 0.16 |
| | $ | 0.23 |
| | $ | 0.27 |
| | $ | (0.31 | ) | | $ | 0.35 |
| Diluted net income (loss) per limited partner unit | $ | 0.16 |
| | $ | 0.23 |
| | $ | 0.27 |
| | $ | (0.31 | ) | | $ | 0.35 |
|
| | | | | | | | | | | | | | | | | | | | | | Quarters Ended | | | | March 31* | | June 30* | | September 30* | | December 31* | | Total Year* | 2016: | | | | | | | | | | Revenues | $ | 6,447 |
| | $ | 7,866 |
| | $ | 8,156 |
| | $ | 9,323 |
| | $ | 31,792 |
| Operating income | 680 |
| | 814 |
| | 624 |
| | (275 | ) | | 1,843 |
| Net income (loss) | 320 |
| | 417 |
| | (3 | ) | | (734 | ) | | — |
| Limited Partners’ interest in net income | 311 |
| | 239 |
| | 207 |
| | 226 |
| | 983 |
| Basic net income per limited partner unit | $ | 0.30 |
| | $ | 0.23 |
| | $ | 0.20 |
| | $ | 0.22 |
| | $ | 0.94 |
| Diluted net income per limited partner unit | $ | 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, 20142017 and 2016 reflected the unfavorable impactsrecognition of $456 millionimpairment losses of $1.04 billion and $1.04 billion, respectively. Impairment losses in 2017 were primarily related to non-cash inventory valuation adjustments primarily in ETP’s investment in Sunoco Logisticsinterstate transportation and retail marketingstorage operations, NGL and refined products operations and Regency’s recognition of a goodwill impairment of $370 million.other operations as well as Sunoco LP’s retail operations. Impairment losses in 2016 were primarily related to ETP’s interstate transportation and storage operations and midstream operations as well as Sunoco LP’s retail operations. The three months ended December 31, 20132017 and December 31, 2016 reflected ETP’sthe recognition of a goodwillnon-cash impairment of $689 million.
| | 18.17. | 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, | | 2014 | | 2013 | 2017 | | 2016 | ASSETS | | | | | | | CURRENT ASSETS: | | | | | | | Cash and cash equivalents | $ | 2 |
| | $ | 8 |
| $ | 1 |
| | $ | 2 |
| Accounts receivable from related companies | 14 |
| | 5 |
| 65 |
| | 55 |
| Other current assets | 1 |
| | — |
| 1 |
| | — |
| Total current assets | 17 |
| | 13 |
| 67 |
| | 57 |
| PROPERTY, PLANT AND EQUIPMENT, net | | 27 |
| | 36 |
| ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES | 5,390 |
| | 3,841 |
| 6,082 |
| | 5,088 |
| INTANGIBLE ASSETS, net | 10 |
| | 14 |
| — |
| | 1 |
| GOODWILL | 9 |
| | 9 |
| 9 |
| | 9 |
| OTHER NON-CURRENT ASSETS, net | 46 |
| | 41 |
| 8 |
| | 10 |
| Total assets | $ | 5,472 |
| | $ | 3,918 |
| $ | 6,193 |
| | $ | 5,201 |
| LIABILITIES AND PARTNERS’ CAPITAL | | | | | | | CURRENT LIABILITIES: | | | | | | | Accounts payable | | $ | — |
| | $ | 1 |
| Accounts payable to related companies | $ | 11 |
| | $ | 11 |
| — |
| | 22 |
| Interest payable | 58 |
| | 24 |
| 66 |
| | 66 |
| Accrued and other current liabilities | 3 |
| | 3 |
| 4 |
| | 3 |
| Total current liabilities | 72 |
| | 38 |
| 70 |
| | 92 |
| LONG-TERM DEBT, less current maturities | 4,680 |
| | 2,801 |
| 6,700 |
| | 6,358 |
| NOTE PAYABLE TO AFFILIATE | 54 |
| | — |
| 617 |
| | 443 |
| OTHER NON-CURRENT LIABILITIES | 2 |
| | 1 |
| 2 |
| | 2 |
| | | | | | | | COMMITMENTS AND CONTINGENCIES |
| |
|
| |
| | | | | | | | PARTNERS’ CAPITAL: | | | | | PARTNERS’ DEFICIT: | | | | | General Partner | (1 | ) | | (3 | ) | (3 | ) | | (3 | ) | Limited Partners: | | | | | | | Limited Partners – Common Unitholders (538,766,899 and 559,923,300 units authorized, issued and outstanding at December 31, 2014 and 2013, respectively) | 648 |
| | 1,066 |
| | Class D Units (1,540,000 units authorized, issued and outstanding) | 22 |
| | 6 |
| | Accumulated other comprehensive income (loss) | (5 | ) | | 9 |
| | Total partners’ capital | 664 |
| | 1,078 |
| | Total liabilities and partners’ capital | $ | 5,472 |
| | $ | 3,918 |
| | 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 | | (1,196 | ) | | (1,694 | ) | Total liabilities and partners’ deficit | | $ | 6,193 |
| | $ | 5,201 |
|
STATEMENTS OF OPERATIONS | | | Years Ended December 31, | Years Ended December 31, | | 2014 | | 2013 | | 2012 | 2017 | | 2016 | | 2015 | SELLING, GENERAL AND ADMINISTRATIVE EXPENSES | $ | (111 | ) | | $ | (56 | ) | | $ | (53 | ) | $ | (31 | ) | | $ | (185 | ) | | $ | (112 | ) | OTHER INCOME (EXPENSE): | | | | | | | | | | | Interest expense, net of interest capitalized | (205 | ) | | (210 | ) | | (235 | ) | (347 | ) | | (327 | ) | | (294 | ) | Bridge loan related fees | — |
| | — |
| | (62 | ) | | Equity in earnings of unconsolidated affiliates | 955 |
| | 617 |
| | 666 |
| 1,381 |
| | 1,511 |
| | 1,601 |
| Gains (losses) on interest rate derivatives | — |
| | 9 |
| | (15 | ) | | Loss on extinguishment of debt | — |
| | (157 | ) | | — |
| (47 | ) | | — |
| | — |
| Other, net | (5 | ) | | (8 | ) | | (4 | ) | (2 | ) | | (4 | ) | | (5 | ) | INCOME BEFORE INCOME TAXES | 634 |
| | 195 |
| | 297 |
| 954 |
| | 995 |
| | 1,190 |
| Income tax expense (benefit) | 1 |
| | (1 | ) | | (7 | ) | | Income tax expense | | — |
| | — |
| | 1 |
| NET INCOME | 633 |
| | 196 |
| | 304 |
| 954 |
| | 995 |
| | 1,189 |
| GENERAL PARTNER’S INTEREST IN NET INCOME | 2 |
| | — |
| | 2 |
| | CLASS D UNITHOLDER’S INTEREST IN NET INCOME | 2 |
| | — |
| | — |
| | LIMITED PARTNERS’ INTEREST IN NET INCOME | $ | 629 |
| | $ | 196 |
| | $ | 302 |
| | General Partner’s interest in net income | | 2 |
| | 3 |
| | 3 |
| Convertible Unitholders’ interest in income | | 37 |
| | 9 |
| | — |
| Class D Unitholder’s interest in net income | | — |
| | — |
| | 3 |
| Limited Partners’ interest in net income | | $ | 915 |
| | $ | 983 |
| | $ | 1,183 |
|
STATEMENTS OF CASH FLOWS | | | Years Ended December 31, | Years Ended December 31, | | 2014 | | 2013 | | 2012 | 2017 | | 2016 | | 2015 | NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES | $ | 816 |
| | $ | 768 |
| | $ | 555 |
| $ | 831 |
| | $ | 918 |
| | $ | 1,103 |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | Cash paid for acquisitions | — |
| | — |
| | (1,113 | ) | | Proceeds from ETP Holdco Transaction | — |
| | 1,332 |
| | — |
| | Cash paid for Bakken Pipeline Transaction | | — |
| | — |
| | (817 | ) | Contributions to unconsolidated affiliates | (118 | ) | | (8 | ) | | (487 | ) | (861 | ) | | (70 | ) | | — |
| Purchase of additional interest in Regency | (800 | ) | | — |
| | — |
| | Note payable to affiliate | 54 |
| | — |
| | — |
| | Note receivable from affiliate | — |
| | — |
| | (221 | ) | | Payments received on note receivable from affiliate | — |
| | 166 |
| | 55 |
| | Net cash provided by (used in) investing activities | (864 | ) | | 1,490 |
| | (1,766 | ) | | Capital expenditures | | (1 | ) | | (16 | ) | | (19 | ) | Contributions in aid of construction costs | | 7 |
| | — |
| | — |
| Net cash used in investing activities | | (855 | ) | | (86 | ) | | (836 | ) | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | Proceeds from borrowings | 3,020 |
| | 2,080 |
| | 2,108 |
| 2,219 |
| | 225 |
| | 3,672 |
| Principal payments on debt | (1,142 | ) | | (3,235 | ) | | (162 | ) | (1,881 | ) | | (210 | ) | | (1,985 | ) | Distributions to partners | (821 | ) | | (733 | ) | | (666 | ) | (1,010 | ) | | (1,022 | ) | | (1,090 | ) | Redemption of Preferred Units | — |
| | (340 | ) | | — |
| | Proceeds from affiliate | | 174 |
| | 176 |
| | 210 |
| Common Units issued for cash | | 568 |
| | — |
| | — |
| Units repurchased under buyback program | (1,000 | ) | | — |
| | — |
| — |
| | — |
| | (1,064 | ) | Debt issuance costs | (15 | ) | | (31 | ) | | (78 | ) | (47 | ) | | — |
| | (11 | ) | Net cash provided by (used in) financing activities | 42 |
| | (2,259 | ) | | 1,202 |
| 23 |
| | (831 | ) | | (268 | ) | DECREASE IN CASH AND CASH EQUIVALENTS | (6 | ) | | (1 | ) | | (9 | ) | | INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | | (1 | ) | | 1 |
| | (1 | ) | CASH AND CASH EQUIVALENTS, beginning of period | 8 |
| | 9 |
| | 18 |
| 2 |
| | 1 |
| | 2 |
| CASH AND CASH EQUIVALENTS, end of period | $ | 2 |
| | $ | 8 |
| | $ | 9 |
| $ | 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 | 2. Regency Energy Partners LP Financial Statements | S - 75 | | | | |
| | 1. | ENERGY TRANSFER PARTNERS, L.P. FINANCIAL STATEMENTS |
INDEX TO FINANCIAL STATEMENTS | | | | Page | Report of Independent Registered Public Accounting Firm
| S -6- 3 | Consolidated Balance Sheets – December 31, 20142017 and 20132016 | S - 74 | Consolidated Statements of Operations – Years Ended December 31, 2014, 20132017, 2016 and 20122015 | S - 96 | Consolidated Statements of Comprehensive Income – Years Ended December 31, 2014, 20132017, 2016 and 20122015 | S - 107 | Consolidated Statements of Equity – Years Ended December 31, 2014, 20132017, 2016 and 20122015 | S - 118 | Consolidated Statements of Cash Flows – Years Ended December 31, 2014, 20132017, 2016 and 20122015 | S - 1210 | Notes to Consolidated Financial Statements | S - 14 | | | | 12 |
Definitions
The following is a list of certain acronyms and terms generally used in the energy industry and throughout this document:
| | | | | | /d | | per day | | | | | | AmeriGas | | AmeriGas Partners, L.P. | | | | | | AOCI | | accumulated other comprehensive income (loss) | | | | | | AROs | | asset retirement obligations | | | | | | Bbls | | barrels | | | | | | Bcf | | billion cubic feet | | | | | | Btu | | British thermal unit, an energy measurement used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy used | | | | | | Capacity | | capacity of a pipeline, processing plant or storage facility refers to the maximum capacity under normal operating conditions and, with respect to pipeline transportation capacity, is subject to multiple factors (including natural gas injections and withdrawals at various delivery points along the pipeline and the utilization of compression) which may reduce the throughput capacity from specified capacity levels | | | | | | Citrus | | Citrus, LLC | | | | | | CrossCountry | | CrossCountry Energy, LLC | | | | | | DOE | | U.S. Department of Energy | | | | | | DOT | | U.S. Department of Transportation | | | | | | EPA | | U.S. Environmental Protection Agency | | | | | | ET Crude Oil | | Energy Transfer Crude Oil Company, LLC, a joint venture owned 60% by ETE and 40% by ETP | | | | | | ETC Compression | | ETC Compression, LLC | | | | | | ETC FEP | | ETC Fayetteville Express Pipeline, LLC | | | | | | ETC OLP | | La Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company | | | | | | ETC Tiger | | ETC Tiger Pipeline, LLC | | | | | | ETE | | Energy Transfer Equity, L.P., a publicly traded partnership and the owner of ETP LLC | | | | | | ETE Holdings | | ETE Common Holdings, LLC, a wholly-owned subsidiary of ETE | | | | | | ET Interstate | | Energy Transfer Interstate Holdings, LLC | | | | | | ETP Credit Facility | | ETP’s $2.5 billion revolving credit facility | | | | | | ETP GP | | Energy Transfer Partners GP, L.P., the general partner of ETP | | | | | | ETP Holdco | | ETP Holdco Corporation
| | | | | | ETP LLC | | Energy Transfer Partners, L.L.C., the general partner of ETP GP | | | | | | Exchange Act | | Securities Exchange Act of 1934 | | | | | | FEP | | Fayetteville Express Pipeline LLC | | | | | | FERC | | Federal Energy Regulatory Commission | | | | | | FGT | | Florida Gas Transmission Company, LLC | | | | | | GAAP | | accounting principles generally accepted in the United States of America | | | | | | HOLP | | Heritage Operating, L.P. | | | | |
| | | | | | IDRs | | incentive distribution rights | | | | | | Lake Charles LNG | | Lake Charles LNG Company, LLC (previously named Trunkline LNG Company, LLC), a subsidiary of ETE | | | | | | LCL | | Lake Charles LNG Export Company, LLC, a subsidiary of ETP and ETE | | | | | | LIBOR | | London Interbank Offered Rate | | | | | | LNG | | Liquefied natural gas | | | | | | Lone Star | | Lone Star NGL LLC | | | | | | LPG | | liquefied petroleum gas | | | | | | MACS | | Mid-Atlantic Convenience Stores, LLC | | | | | | MGE | | Missouri Gas Energy | | | | | | MMBtu | | million British thermal units | | | | | | MMcf | | million cubic feet | | | | | | MTBE | | methyl tertiary butyl ether | | | | | | NEG | | New England Gas Company | | | | | | NGL | | natural gas liquid, such as propane, butane and natural gasoline | | | | | | NYMEX | | New York Mercantile Exchange | | | | | | NYSE | | New York Stock Exchange | | | | | | OSHA | | federal Occupational Safety and Health Act | | | | | | OTC | | over-the-counter | | | | | | Panhandle | | Panhandle Eastern Pipe Line Company, LP and its subsidiaries | | | | | | PCBs | | polychlorinated biphenyls | | | | | | PEPL Holdings | | PEPL Holdings, LLC | | | | | | PES | | Philadelphia Energy Solutions | | | | | | PHMSA | | Pipeline Hazardous Materials Safety Administration | | | | | | Regency | | Regency Energy Partners LP, a subsidiary of ETE | | | | | | Retail Holdings | | ETP Retail Holdings, a joint venture between subsidiaries of ETC OLP and Sunoco, Inc. | | | | | | Sea Robin | | Sea Robin Pipeline Company, LLC, a subsidiary of Panhandle | | | | | | SEC | | Securities and Exchange Commission | | | | | | Southern Union | | Southern Union Company | | | | | | Southwest Gas | | Pan Gas Storage, LLC (d.b.a. Southwest Gas) | | | | | | SUGS | | Southern Union Gas Services |
| | | | | | | | | | Sunoco Logistics | | Sunoco Logistics Partners L.P. | | | | | | Sunoco Partners | | Sunoco Partners LLC, the general partner of Sunoco Logistics | | | | | | Susser | | Susser Holdings Corporation | | | | | | Titan | | Titan Energy Partners, L.P. | | | | | | Transwestern | | Transwestern Pipeline Company, LLC | | | | | | TRRC | | Texas Railroad Commission | | | | | | Trunkline | | Trunkline Gas Company, LLC, a subsidiary of Panhandle |
Adjusted EBITDA is a term used throughout this document, which we define as earnings before interest, taxes, depreciation, 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 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). Adjusted EBITDA reflects amounts for less than wholly-owned subsidiaries based on 100% of the subsidiaries’ results of operations and for unconsolidated affiliates based on the Partnership’s proportionate ownership.
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, 20142017 and 2013, 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, 2014. These financial statements are2017, and the responsibility ofrelated notes (collectively referred to as the Partnership’s management. Our responsibility is to express an“financial statements”). In our opinion, on these financial statements based on our audits. We did not audit the financial statements of Sunoco LP and Susser Holdings Corporation, both consolidated subsidiaries, as of December 31, 2014 and for the period from September 1, 2014 to December 31, 2014, whose combined statements reflect total assets constituting 11 percent of consolidated total assets as of December 31, 2014, and total revenues of 5 percent of consolidated total revenues for the year then ended. Those statements were audited by other auditors, whose reports have been furnished to us, and our opinion, insofar as it relates to the amounts included for Sunoco LP and Susser Holdings Corporation, is based solely on the reports of the other auditors. We did not audit the financial statements of Sunoco Logistics Partners L.P., a consolidated subsidiary, for the period from October 5, 2012 to December 31, 2012, which statements reflect revenues of 20 percent of consolidated total revenues for the year ended December 31, 2012. Those statements were audited by other auditors, whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Sunoco Logistics Partners L.P. for the period from October 5, 2012 to December 31, 2012, is based solely on the report of the other auditors. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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 and the reports of the other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the reports of the other auditors, 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, 20142017 and 2013,2016, and the results of theirits operations and theirits cash flows for each of the three years in the period ended December 31, 20142017, 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, 2014,2017, 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 March 2, 2015 (notFebruary 23, 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 March 2, 2015February 23, 2018
ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Dollars in millions) | | | | | | | | | | December 31, | | 2014 | | 2013 | ASSETS | | | | CURRENT ASSETS: | | | | Cash and cash equivalents | $ | 639 |
| | $ | 549 |
| Accounts receivable, net | 2,879 |
| | 3,359 |
| Accounts receivable from related companies | 210 |
| | 165 |
| Inventories | 1,389 |
| | 1,765 |
| Exchanges receivable | 44 |
| | 56 |
| Price risk management assets | 7 |
| | 35 |
| Other current assets | 271 |
| | 310 |
| Total current assets | 5,439 |
| | 6,239 |
| | | | | PROPERTY, PLANT AND EQUIPMENT | 33,200 |
| | 28,430 |
| ACCUMULATED DEPRECIATION | (3,457 | ) | | (2,483 | ) | | 29,743 |
| | 25,947 |
| | | | | ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES | 3,840 |
| | 4,436 |
| NON-CURRENT PRICE RISK MANAGEMENT ASSETS | — |
| | 17 |
| GOODWILL | 6,419 |
| | 4,729 |
| INTANGIBLE ASSETS, net | 2,087 |
| | 1,568 |
| OTHER NON-CURRENT ASSETS, net | 693 |
| | 766 |
| Total assets | $ | 48,221 |
| | $ | 43,702 |
|
| | | | | | | | | | December 31, | | 2017 | | 2016* | ASSETS | | | | Current assets: | | | | Cash and cash equivalents | $ | 306 |
| | $ | 360 |
| Accounts receivable, net | 3,946 |
| | 3,002 |
| Accounts receivable from related companies | 318 |
| | 209 |
| Inventories | 1,589 |
| | 1,626 |
| Income taxes receivable | 135 |
| | 128 |
| Derivative assets | 24 |
| | 20 |
| Other current assets | 210 |
| | 298 |
| Total current assets | 6,528 |
| | 5,643 |
| | | | | Property, plant and equipment | 67,699 |
| | 58,220 |
| Accumulated depreciation and depletion | (9,262 | ) | | (7,303 | ) | | 58,437 |
| | 50,917 |
| | | | | Advances to and investments in unconsolidated affiliates | 3,816 |
| | 4,280 |
| Other non-current assets, net | 758 |
| | 672 |
| Intangible assets, net | 5,311 |
| | 4,696 |
| Goodwill | 3,115 |
| | 3,897 |
| Total assets | $ | 77,965 |
| | $ | 70,105 |
|
* As adjusted. See Note 2.
ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Dollars in millions) | | | | | | | | | | December 31, | | 2014 | | 2013 | LIABILITIES AND EQUITY | | | | CURRENT LIABILITIES: | | | | Accounts payable | $ | 2,992 |
| | $ | 3,627 |
| Accounts payable to related companies | 62 |
| | 45 |
| Exchanges payable | 183 |
| | 285 |
| Price risk management liabilities | 21 |
| | 45 |
| Accrued and other current liabilities | 1,774 |
| | 1,428 |
| Current maturities of long-term debt | 1,008 |
| | 637 |
| Total current liabilities | 6,040 |
| | 6,067 |
| | | | | LONG-TERM DEBT, less current maturities | 18,332 |
| | 16,451 |
| NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES | 138 |
| | 54 |
| DEFERRED INCOME TAXES | 4,226 |
| | 3,762 |
| OTHER NON-CURRENT LIABILITIES | 1,206 |
| | 1,080 |
| | | | | COMMITMENTS AND CONTINGENCIES (Note 11) | | | | REDEEMABLE NONCONTROLLING INTERESTS | 15 |
| | — |
| | | | | EQUITY: | | | | General Partner | 184 |
| | 171 |
| Limited Partners: | | | | Common Unitholders (355,510,227 and 333,826,372 units authorized, issued and outstanding as of December 31, 2014 and 2013, respectively) | 10,430 |
| | 9,797 |
| 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 (50,160,000 units authorized, issued and outstanding) | 1,512 |
| | 1,511 |
| Accumulated other comprehensive income (loss) | (56 | ) | | 61 |
| Total partners’ capital | 12,070 |
| | 11,540 |
| Noncontrolling interest | 6,194 |
| | 4,748 |
| Total equity | 18,264 |
| | 16,288 |
| Total liabilities and equity | $ | 48,221 |
| | $ | 43,702 |
|
| | | | | | | | | | December 31, | | 2017 | | 2016* | LIABILITIES AND EQUITY | | | | Current liabilities: | | | | Accounts payable | $ | 4,126 |
| | $ | 2,900 |
| Accounts payable to related companies | 209 |
| | 43 |
| Derivative liabilities | 109 |
| | 166 |
| Accrued and other current liabilities | 2,143 |
| | 1,905 |
| Current maturities of long-term debt | 407 |
| | 1,189 |
| Total current liabilities | 6,994 |
| | 6,203 |
| | | | | Long-term debt, less current maturities | 32,687 |
| | 31,741 |
| Long-term notes payable – related company | — |
| | 250 |
| Non-current derivative liabilities | 145 |
| | 76 |
| Deferred income taxes | 2,883 |
| | 4,394 |
| Other non-current liabilities | 1,084 |
| | 952 |
| | | | | Commitments and contingencies |
| |
|
| Legacy ETP Preferred Units | — |
| | 33 |
| Redeemable noncontrolling interests | 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 | 244 |
| | 206 |
| Accumulated other comprehensive income | 3 |
| | 8 |
| Total partners’ capital | 28,269 |
| | 18,621 |
| Noncontrolling interest | 5,882 |
| | 7,820 |
| Total equity | 34,151 |
| | 26,441 |
| Total liabilities and equity | $ | 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, | | 2014 | | 2013 | | 2012 | REVENUES: | | | | | | Natural gas sales | $ | 3,561 |
| | $ | 3,165 |
| | $ | 2,387 |
| NGL sales | 4,293 |
| | 2,817 |
| | 1,718 |
| Crude sales | 16,416 |
| | 15,477 |
| | 2,872 |
| Gathering, transportation and other fees | 2,553 |
| | 2,590 |
| | 2,007 |
| Refined product sales | 19,437 |
| | 18,479 |
| | 5,299 |
| Other | 4,898 |
| | 3,811 |
| | 1,419 |
| Total revenues | 51,158 |
| | 46,339 |
| | 15,702 |
| COSTS AND EXPENSES: | | | | | | Cost of products sold | 45,540 |
| | 41,204 |
| | 12,266 |
| Operating expenses | 1,636 |
| | 1,441 |
| | 953 |
| Depreciation and amortization | 1,130 |
| | 1,032 |
| | 656 |
| Selling, general and administrative | 377 |
| | 432 |
| | 433 |
| Goodwill impairment | — |
| | 689 |
| | — |
| Total costs and expenses | 48,683 |
| | 44,798 |
| | 14,308 |
| OPERATING INCOME | 2,475 |
| | 1,541 |
| | 1,394 |
| OTHER INCOME (EXPENSE): | | | | | | Interest expense, net of interest capitalized | (860 | ) | | (849 | ) | | (665 | ) | Equity in earnings of unconsolidated affiliates | 234 |
| | 172 |
| | 142 |
| Gain on deconsolidation of Propane Business | — |
| | — |
| | 1,057 |
| Gain on sale of AmeriGas common units | 177 |
| | 87 |
| | — |
| Loss on extinguishment of debt | — |
| | — |
| | (115 | ) | Gains (losses) on interest rate derivatives | (157 | ) | | 44 |
| | (4 | ) | Non-operating environmental remediation | — |
| | (168 | ) | | — |
| Other, net | (25 | ) | | 5 |
| | 11 |
| INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE | 1,844 |
| | 832 |
| | 1,820 |
| Income tax expense from continuing operations | 355 |
| | 97 |
| | 63 |
| INCOME FROM CONTINUING OPERATIONS | 1,489 |
| | 735 |
| | 1,757 |
| Income (loss) from discontinued operations | 64 |
| | 33 |
| | (109 | ) | NET INCOME | 1,553 |
| | 768 |
| | 1,648 |
| LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST | 217 |
| | 312 |
| | 79 |
| NET INCOME ATTRIBUTABLE TO PARTNERS | 1,336 |
| | 456 |
| | 1,569 |
| GENERAL PARTNER’S INTEREST IN NET INCOME | 513 |
| | 506 |
| | 461 |
| CLASS H UNITHOLDER’S INTEREST IN NET INCOME | 217 |
| | 48 |
| | — |
| COMMON UNITHOLDERS’ INTEREST IN NET INCOME (LOSS) | $ | 606 |
| | $ | (98 | ) | | $ | 1,108 |
| INCOME (LOSS) FROM CONTINUING OPERATIONS PER COMMON UNIT: | | | | | | Basic | $ | 1.58 |
| | $ | (0.23 | ) | | $ | 4.93 |
| Diluted | $ | 1.58 |
| | $ | (0.23 | ) | | $ | 4.91 |
| NET INCOME (LOSS) PER COMMON UNIT: | | | | | | Basic | $ | 1.77 |
| | $ | (0.18 | ) | | $ | 4.43 |
| Diluted | $ | 1.77 |
| | $ | (0.18 | ) | | $ | 4.42 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016* | | 2015* | REVENUES: | | | | | | Natural gas sales | $ | 4,172 |
| | $ | 3,619 |
| | $ | 3,671 |
| NGL sales | 6,972 |
| | 4,841 |
| | 3,936 |
| Crude sales | 10,184 |
| | 6,766 |
| | 8,378 |
| Gathering, transportation and other fees | 4,265 |
| | 4,003 |
| | 3,997 |
| Refined product sales (see Note 3) | 1,515 |
| | 1,047 |
| | 9,958 |
| Other (see Note 3) | 1,946 |
| | 1,551 |
| | 4,352 |
| Total revenues | 29,054 |
| | 21,827 |
| | 34,292 |
| COSTS AND EXPENSES: | | | | | | Cost of products sold (see Note 3) | 20,801 |
| | 15,080 |
| | 26,714 |
| Operating expenses (see Note 3) | 2,170 |
| | 1,839 |
| | 2,608 |
| Depreciation, depletion and amortization | 2,332 |
| | 1,986 |
| | 1,929 |
| Selling, general and administrative (see Note 3) | 434 |
| | 348 |
| | 475 |
| Impairment losses | 920 |
| | 813 |
| | 339 |
| Total costs and expenses | 26,657 |
| | 20,066 |
| | 32,065 |
| OPERATING INCOME | 2,397 |
| | 1,761 |
| | 2,227 |
| OTHER INCOME (EXPENSE): | | | | | | Interest expense, net | (1,365 | ) | | (1,317 | ) | | (1,291 | ) | Equity in earnings from unconsolidated affiliates | 156 |
| | 59 |
| | 469 |
| Impairment of investments in unconsolidated affiliates | (313 | ) | | (308 | ) | | — |
| Gains on acquisitions | — |
| | 83 |
| | — |
| Losses on extinguishments of debt | (42 | ) | | — |
| | (43 | ) | Losses on interest rate derivatives | (37 | ) | | (12 | ) | | (18 | ) | Other, net | 209 |
| | 131 |
| | 22 |
| INCOME BEFORE INCOME TAX BENEFIT | 1,005 |
| | 397 |
| | 1,366 |
| Income tax benefit | (1,496 | ) | | (186 | ) | | (123 | ) | NET INCOME | 2,501 |
| | 583 |
| | 1,489 |
| Less: Net income attributable to noncontrolling interest | 420 |
| | 295 |
| | 134 |
| Less: Net loss attributable to predecessor | — |
| | — |
| | (34 | ) | NET INCOME ATTRIBUTABLE TO PARTNERS | 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 | ) | NET INCOME (LOSS) PER COMMON UNIT: | | | | | | Basic | $ | 0.94 |
| | $ | (1.38 | ) | | $ | (0.07 | ) | Diluted | $ | 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, | | 2014 | | 2013 | | 2012 | 2017 | | 2016* | | 2015* | Net income | $ | 1,553 |
| | $ | 768 |
| | $ | 1,648 |
| $ | 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 |
| | (4 | ) | | (14 | ) | | Change in value of derivative instruments accounted for as cash flow hedges | — |
| | (1 | ) | | 8 |
| | Change in value of available-for-sale securities | 1 |
| | 2 |
| | — |
| 6 |
| | 2 |
| | (3 | ) | Actuarial gain (loss) relating to pension and other postretirement benefits | (113 | ) | | 66 |
| | (10 | ) | (12 | ) | | (1 | ) | | 65 |
| Foreign currency translation adjustment | (2 | ) | | (1 | ) | | — |
| — |
| | (1 | ) | | (1 | ) | Change in other comprehensive income from unconsolidated affiliates | (6 | ) | | 17 |
| | (9 | ) | | Change in other comprehensive income (loss) from unconsolidated affiliates | | 1 |
| | 4 |
| | (1 | ) | | (117 | ) | | 79 |
| | (25 | ) | (5 | ) | | 4 |
| | 60 |
| Comprehensive income | 1,436 |
| | 847 |
| | 1,623 |
| 2,496 |
| | 587 |
| | 1,549 |
| Less: Comprehensive income attributable to noncontrolling interest | 217 |
| | 312 |
| | 74 |
| 420 |
| | 295 |
| | 134 |
| Less: Comprehensive loss attributable to predecessor | | — |
| | — |
| | (34 | ) | Comprehensive income attributable to partners | $ | 1,219 |
| | $ | 535 |
| | $ | 1,549 |
| $ | 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 | | Accumulated Other Comprehensive Income (Loss) | | Noncontrolling Interest | | 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, 2011 | $ | 182 |
| | $ | 5,533 |
| | $ | — |
| | $ | 6 |
| | $ | 629 |
| | $ | 6,350 |
| | Distributions to partners | (454 | ) | | (889 | ) | | — |
| | — |
| | — |
| | (1,343 | ) | | Distributions to noncontrolling interest | — |
| | — |
| | — |
| | — |
| | (233 | ) | | (233 | ) | | Units issued for cash | — |
| | 791 |
| | — |
| | — |
| | — |
| | 791 |
| | Capital contributions from noncontrolling interest | — |
| | — |
| | — |
| | — |
| | 343 |
| | 343 |
| | Sunoco Merger (see Note 3) | — |
| | 2,288 |
| | — |
| | — |
| | 3,580 |
| | 5,868 |
| | ETP Holdco Transaction (see Note 3) | — |
| | 165 |
| | — |
| | — |
| | 3,748 |
| | 3,913 |
| | Issuance of units in other acquisitions (excluding Sunoco, Inc.) | — |
| | 7 |
| | — |
| | — |
| | — |
| | 7 |
| | Other comprehensive loss, net of tax | — |
| | — |
| | — |
| | (19 | ) | | (6 | ) | | (25 | ) | | Other, net | (1 | ) | | 23 |
| | — |
| | — |
| | (9 | ) | | 13 |
| | Net income | 461 |
| | 1,108 |
| | — |
| | — |
| | 79 |
| | 1,648 |
| | Balance, December 31, 2012 | 188 |
| | 9,026 |
| | — |
| | (13 | ) | | 8,131 |
| | 17,332 |
| | Distributions to partners | (523 | ) | | (1,228 | ) | | (51 | ) | | — |
| | — |
| | (1,802 | ) | | Distributions to noncontrolling interest | — |
| | — |
| | — |
| | — |
| | (382 | ) | | (382 | ) | | Units issued for cash | — |
| | 1,611 |
| | — |
| | — |
| | — |
| | 1,611 |
| | Issuance of Class H Units (see Note 8) | — |
| | (1,514 | ) | | 1,514 |
| | — |
| | — |
| | — |
| | Capital contributions from noncontrolling interest | — |
| | — |
| | — |
| | — |
| | 137 |
| | 137 |
| | ETP Holdco Acquisition and SUGS Contribution (see Note 3) | — |
| | 2,013 |
| | — |
| | (5 | ) | | (3,448 | ) | | (1,440 | ) | | Other comprehensive income, net of tax | — |
| | — |
| | — |
| | 79 |
| | — |
| | 79 |
| | Other, net | — |
| | (13 | ) | | — |
| | — |
| | (2 | ) | | (15 | ) | | Net income (loss) | 506 |
| | (98 | ) | | 48 |
| | — |
| | 312 |
| | 768 |
| | Balance, December 31, 2013 | 171 |
| | 9,797 |
| | 1,511 |
| | 61 |
| | 4,748 |
| | 16,288 |
| | Balance, December 31, 2014* | | $ | — |
| | $ | — |
| | $ | 10,427 |
| | $ | 1,512 |
| | $ | — |
| | $ | 184 |
| | $ | (56 | ) | | $ | 5,143 |
| | $ | 8,088 |
| | $ | 25,298 |
| Distributions to partners | (500 | ) | | (1,252 | ) | | (212 | ) | | — |
| | — |
| | (1,964 | ) | — |
| | — |
| | (1,863 | ) | | (247 | ) | | (80 | ) | | (944 | ) | | — |
| | — |
| | — |
| | (3,134 | ) | Distributions to noncontrolling interest | — |
| | — |
| | — |
| | — |
| | (362 | ) | | (362 | ) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (338 | ) | | — |
| | (338 | ) | Units issued for cash | — |
| | 1,382 |
| | — |
| | — |
| | — |
| | 1,382 |
| — |
| | — |
| | 1,428 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1,428 |
| Subsidiary units issued for cash | 1 |
| | 174 |
| | — |
| | — |
| | 1,069 |
| | 1,244 |
| — |
| | — |
| | 298 |
| | — |
| | — |
| | 2 |
| | — |
| | 1,219 |
| | — |
| | 1,519 |
| Capital contributions from noncontrolling interest | — |
| | — |
| | — |
| | — |
| | 161 |
| | 161 |
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 875 |
| | — |
| | 875 |
| Lake Charles LNG Transaction (see Note 3) | — |
| | (1,167 | ) | | — |
| | — |
| | — |
| | (1,167 | ) | | Susser Merger (see Note 3) | — |
| | 908 |
| | — |
| | — |
| | 626 |
| | 1,534 |
| | Sunoco Logistics acquisition of a noncontrolling interest | (1 | ) | | (79 | ) | | — |
| | — |
| | (245 | ) | | (325 | ) | | Other comprehensive loss, net of tax | — |
| | — |
| | — |
| | (117 | ) | | — |
| | (117 | ) | | Bakken Pipeline Transaction | | — |
| | — |
| | (999 | ) | | 1,946 |
| | — |
| | — |
| | — |
| | 72 |
| | — |
| | 1,019 |
| Sunoco LP Exchange Transaction | | — |
| | — |
| | (52 | ) | | — |
| | — |
| | — |
| | — |
| | (940 | ) | | — |
| | (992 | ) | Susser Exchange Transaction | | — |
| | — |
| | (68 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (68 | ) | Acquisition and disposition of noncontrolling interest | | — |
| | — |
| | (26 | ) | | — |
| | — |
| | — |
| | — |
| | (39 | ) | | — |
| | (65 | ) | Predecessor distributions to partners | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (202 | ) | | (202 | ) | Predecessor units issued for cash | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 34 |
| | 34 |
| Regency Merger | | — |
| | — |
| | 7,890 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (7,890 | ) | | — |
| Other comprehensive income, net of tax | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 60 |
| | — |
| | — |
| | 60 |
| Other, net | — |
| | 61 |
| | (4 | ) | | — |
| | (20 | ) | | 37 |
| — |
| | — |
| | 23 |
| | — |
| | — |
| | — |
| | — |
| | 36 |
| | 4 |
| | 63 |
| Net income | 513 |
| | 606 |
| | 217 |
| | — |
| | 217 |
| | 1,553 |
| | Balance, December 31, 2014 | $ | 184 |
| | $ | 10,430 |
| | $ | 1,512 |
| | $ | (56 | ) | | $ | 6,194 |
| | $ | 18,264 |
| | 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 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Capital contributions from noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 236 |
| | — |
| | 236 |
| Sunoco, Inc. retail business to Sunoco LP transaction | — |
| | — |
| | (405 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (405 | ) | PennTex Acquisition | — |
| | — |
| | 307 |
| | — |
| | — |
| | — |
| | — |
| | 236 |
| | — |
| | 543 |
| Other comprehensive income, net of tax | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 4 |
| | — |
| | — |
| | 4 |
| Other, net | — |
| | — |
| | 10 |
| | — |
| | — |
| | — |
| | — |
| | 21 |
| | — |
| | 31 |
| Net income (loss) | — |
| | — |
| | (1,019 | ) | | 351 |
| | 8 |
| | 948 |
| | — |
| | 295 |
| | — |
| | 583 |
| 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 |
|
ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in millions) | | | | | | | | | | | | | | Years Ended December 31, | | 2014 | | 2013 | | 2012 | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | Net income | $ | 1,553 |
| | $ | 768 |
| | $ | 1,648 |
| Reconciliation of net income to net cash provided by operating activities: | | | | | | Depreciation and amortization | 1,130 |
| | 1,032 |
| | 656 |
| Deferred income taxes | (47 | ) | | 48 |
| | 62 |
| Amortization included in interest expense | (61 | ) | | (80 | ) | | (35 | ) | Inventory valuation adjustments | 473 |
| | (3 | ) | | 75 |
| Non-cash compensation expense | 58 |
| | 47 |
| | 42 |
| Goodwill impairment | — |
| | 689 |
| | — |
| Gain on sale of AmeriGas common units | (177 | ) | | (87 | ) | | — |
| Gain on deconsolidation of Propane Business | — |
| | — |
| | (1,057 | ) | Gain on curtailment of other postretirement benefits | — |
| | — |
| | (15 | ) | Loss on extinguishment of debt | — |
| | — |
| | 115 |
| Write-down of assets included in loss from discontinued operations | — |
| | — |
| | 132 |
| Distributions on unvested awards | (16 | ) | | (12 | ) | | (8 | ) | Equity in earnings of unconsolidated affiliates | (234 | ) | | (172 | ) | | (142 | ) | Distributions from unconsolidated affiliates | 203 |
| | 247 |
| | 132 |
| Other non-cash | (60 | ) | | 42 |
| | 68 |
| Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations (see Note 2) | (264 | ) | | (146 | ) | | (475 | ) | Net cash provided by operating activities | 2,558 |
| | 2,373 |
| | 1,198 |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | Cash paid for Susser Merger, net of cash received (see Note 3) | (808 | ) | | — |
| | — |
| Cash paid for acquisition of a noncontrolling interest | (325 | ) | | — |
| | — |
| Cash paid for ETP Holdco Acquisition (See Note 3) | — |
| | (1,332 | ) | | — |
| Cash paid for Citrus Merger | — |
| | — |
| | (1,895 | ) | Cash proceeds from the sale of AmeriGas common units | 814 |
| | 346 |
| | — |
| Cash proceeds from SUGS Contribution (See Note 3) | — |
| | 504 |
| | — |
| Cash proceeds from contribution and sale of propane operations | — |
| | — |
| | 1,443 |
| Cash (paid) received from all other acquisitions | (429 | ) | | (405 | ) | | 531 |
| Capital expenditures (excluding allowance for equity funds used during construction) | (4,158 | ) | | (2,575 | ) | | (2,840 | ) | Contributions in aid of construction costs | 45 |
| | 52 |
| | 35 |
| Contributions to unconsolidated affiliates | (170 | ) | | (1 | ) | | (30 | ) | Distributions from unconsolidated affiliates in excess of cumulative earnings | 151 |
| | 217 |
| | 130 |
| Proceeds from sale of discontinued operations | 77 |
| | 1,008 |
| | 207 |
| Proceeds from the sale of assets | 50 |
| | 53 |
| | 18 |
| Change in restricted cash | 172 |
| | (348 | ) | | 5 |
| Other | (17 | ) | | 21 |
| | 111 |
| Net cash used in investing activities | (4,598 | ) | | (2,460 | ) | | (2,285 | ) | | | | | | |
| | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016* | | 2015* | OPERATING ACTIVITIES: | | | | | | Net income | $ | 2,501 |
| | $ | 583 |
| | $ | 1,489 |
| Reconciliation of net income to net cash provided by operating activities: | | | | | | Depreciation, depletion and amortization | 2,332 |
| | 1,986 |
| | 1,929 |
| Deferred income taxes | (1,531 | ) | | (169 | ) | | 202 |
| Amortization included in interest expense | 2 |
| | (20 | ) | | (36 | ) | Inventory valuation adjustments | — |
| | — |
| | (58 | ) | Unit-based compensation expense | 74 |
| | 80 |
| | 79 |
| Impairment losses | 920 |
| | 813 |
| | 339 |
| Gains on acquisitions | — |
| | (83 | ) | | — |
| Losses on extinguishments of debt | 42 |
| | — |
| | 43 |
| Impairment of investments in unconsolidated affiliates | 313 |
| | 308 |
| | — |
| Distributions on unvested awards | (31 | ) | | (25 | ) | | (16 | ) | Equity in earnings of unconsolidated affiliates | (156 | ) | | (59 | ) | | (469 | ) | Distributions from unconsolidated affiliates | 440 |
| | 406 |
| | 440 |
| Other non-cash | (261 | ) | | (271 | ) | | (22 | ) | Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | (160 | ) | | (246 | ) | | (1,173 | ) | Net cash provided by operating activities | 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 |
| | — |
| Proceeds from Bakken Pipeline Transaction | — |
| | — |
| | 980 |
| Proceeds from Susser Exchange Transaction | — |
| | — |
| | 967 |
| Proceeds from sale of noncontrolling interest | — |
| | — |
| | 64 |
| Cash paid for acquisition of PennTex noncontrolling interest | (280 | ) | | — |
| | — |
| Cash paid for Vitol Acquisition, net of cash received | — |
| | (769 | ) | | — |
| Cash paid for PennTex Acquisition, net of cash received | — |
| | (299 | ) | | — |
| Cash transferred to ETE in connection with the Sunoco LP Exchange | — |
| | — |
| | (114 | ) | Cash paid for acquisition of a noncontrolling interest | — |
| | — |
| | (129 | ) | Cash paid for all other acquisitions | (264 | ) | | (159 | ) | | (675 | ) | Capital expenditures, excluding allowance for equity funds used during construction | (8,335 | ) | | (7,550 | ) | | (9,098 | ) | Contributions in aid of construction costs | 24 |
| | 71 |
| | 80 |
| Contributions to unconsolidated affiliates | (268 | ) | | (59 | ) | | (45 | ) | Distributions from unconsolidated affiliates in excess of cumulative earnings | 136 |
| | 135 |
| | 124 |
| Proceeds from the sale of assets | 35 |
| | 25 |
| | 23 |
| Change in restricted cash | — |
| | 14 |
| | 19 |
| Other | 1 |
| | 1 |
| | (16 | ) | Net cash used in investing activities | (5,473 | ) | | (6,390 | ) | | (7,820 | ) | | | | | | |
| | | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | Proceeds from borrowings | 9,909 |
| | 8,001 |
| | 8,208 |
| Repayments of long-term debt | (8,223 | ) | | (7,016 | ) | | (6,598 | ) | Proceeds from borrowings from affiliates | — |
| | — |
| | 221 |
| Repayments of borrowings from affiliates | — |
| | (166 | ) | | (55 | ) | Net proceeds from issuance of Common Units | 1,382 |
| | 1,611 |
| | 791 |
| Subsidiary equity offerings, net of issuance costs | 1,244 |
| | — |
| | — |
| Capital contributions received from noncontrolling interest | 174 |
| | 147 |
| | 320 |
| Distributions to partners | (1,964 | ) | | (1,802 | ) | | (1,343 | ) | Distributions to noncontrolling interest | (362 | ) | | (382 | ) | | (233 | ) | Debt issuance costs | (30 | ) | | (32 | ) | | (20 | ) | Other | — |
| | (36 | ) | | — |
| Net cash provided by financing activities | 2,130 |
| | 325 |
| | 1,291 |
| INCREASE IN CASH AND CASH EQUIVALENTS | 90 |
| | 238 |
| | 204 |
| CASH AND CASH EQUIVALENTS, beginning of period | 549 |
| | 311 |
| | 107 |
| CASH AND CASH EQUIVALENTS, end of period | $ | 639 |
| | $ | 549 |
| | $ | 311 |
|
| | | | | | | | | | | | | FINANCING ACTIVITIES: | | | | | | Proceeds from borrowings | 26,736 |
| | 19,916 |
| | 22,462 |
| Repayments of long-term debt | (26,494 | ) | | (15,799 | ) | | (17,843 | ) | 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 |
| Predecessor units issued for cash | — |
| | — |
| | 34 |
| Capital contributions from noncontrolling interest | 1,214 |
| | 236 |
| | 841 |
| Distributions to partners | (3,468 | ) | | (3,542 | ) | | (3,134 | ) | Predecessor distributions to partners | — |
| | — |
| | (202 | ) | Distributions to noncontrolling interest | (430 | ) | | (481 | ) | | (338 | ) | Redemption of Legacy ETP Preferred Units | (53 | ) | | — |
| | — |
| Debt issuance costs | (83 | ) | | (22 | ) | | (63 | ) | Other | 5 |
| | 2 |
| | — |
| Net cash provided by financing activities | 934 |
| | 2,920 |
| | 4,937 |
| Decrease in cash and cash equivalents | (54 | ) | | (167 | ) | | (136 | ) | Cash and cash equivalents, beginning of period | 360 |
| | 527 |
| | 663 |
| Cash and cash equivalents, end of period | $ | 306 |
| | $ | 360 |
| | $ | 527 |
|
* As adjusted. See Note 2.
S - 13
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 ORGANIZATION:BASIS OF PRESENTATION: |
Organization. The consolidated financial statements and notes theretopresented herein contain the results of Energy Transfer Partners, L.P., and its subsidiaries (the “Partnership,” “we”“we,” “us,” “our” or “ETP”) presented herein. 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 years endedpre-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 Partners 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, NGLs and refined products. Basis of Presentation. December 31, 2014, 2013 and 2012,The consolidated financial statements of the Partnership have been prepared in accordance with GAAP and pursuantinclude the accounts of all controlled subsidiaries after the elimination of all intercompany accounts and transactions. Certain prior year amounts have been conformed to the rules and regulations of the SEC. We consolidate all majority-owned subsidiaries and subsidiaries we control, even if we do not have a majority ownership. All significant intercompany transactions and accounts are eliminated in consolidation.current year presentation. These reclassifications had no impact on net income or total equity. Management has evaluated subsequent events through the date the financial statements were issued. We also ownFor 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, we apply proportionate consolidation for ourthese undivided interests in these assets. Certain prior period amounts have been reclassified to conform to the 2014 presentation. These reclassifications had no impact on net income or total equity.
We are 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. The consolidated financial statements of the Partnership presented herein include our operating subsidiaries described below.
Our consolidated subsidiary, Susser Petroleum Partners LP, changed its name in October 2014 to Sunoco LP. Additionally, Trunkline LNG Company, LLC, a consolidated subsidiary of ETE, changed its name in September 2014 to Lake Charles LNG Company, LLC. All references to these entities throughout this document reflect the new name of these entities, regardless of whether the disclosure relates to periods or events prior to the dates of the name changes.
Business Operations
Our activities are primarily conducted through our operating subsidiaries (collectively, the “Operating Companies”) as follows:
ETC OLP, a Texas limited partnership primarily engaged in midstream and intrastate transportation and storage natural gas operations. ETC OLP owns and operates, through its wholly and majority-owned subsidiaries, natural gas gathering systems, intrastate natural gas pipeline systems and gas processing plants and is 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. ETC OLP’s intrastate transportation and storage operations primarily focus on transporting natural gas in Texas through our Oasis pipeline, ET Fuel System, East Texas pipeline and HPL System. ETC OLP’s midstream operations focus on the gathering, compression, treating, conditioning and processing of natural gas, primarily on or through our Southeast Texas System, Eagle Ford System, North Texas System and Northern Louisiana assets. ETC OLP also owns a 70% interest in Lone Star.
ET Interstate, a Delaware limited liability company with revenues consisting primarily of fees earned from natural gas transportation services and operational gas sales. ET Interstate is the parent company of:
Transwestern, a Delaware limited liability company engaged in interstate transportation of natural gas. Transwestern’s revenues consist primarily of fees earned from natural gas transportation services and operational gas sales.
ETC FEP, a Delaware limited liability company that directly owns a 50% interest in FEP, which owns 100% of the Fayetteville Express interstate natural gas pipeline.
ETC Tiger, a Delaware limited liability company engaged in interstate transportation of natural gas.
CrossCountry, a Delaware limited liability company that indirectly owns a 50% interest in Citrus, which owns 100% of the FGT interstate natural gas pipeline.
ETC Compression, a Delaware limited liability company engaged in natural gas compression services and related equipment sales.
ETP Holdco, a Delaware limited liability company that indirectly owns Panhandle and Sunoco, Inc. Panhandle and Sunoco, Inc. operations are described as follows:
Panhandle owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the transportation and storage of natural gas in the United States. As discussed in Note 3, in January 2014, Panhandle consummated a merger with Southern Union, the indirect parent of Panhandle, and PEPL Holdings, the sole limited partner of Panhandle, pursuant to which each of Southern Union and PEPL Holdings were merged with and into Panhandle, with Panhandle surviving the merger.
Sunoco, Inc. owns and operates retail marketing assets, which sell gasoline and middle distillates at retail locations and operates convenience stores primarily on the east coast and in the midwest region of the United States. Effective June 1, 2014, the Partnership combined certain Sunoco, Inc. retail assets with another wholly-owned subsidiary of ETP to form a limited liability company owned by ETP and Sunoco, Inc.
Sunoco Logistics, a publicly traded Delaware limited partnership that owns and operates a logistics business, consisting of products, crude oil and NGL pipelines, terminalling and storage assets, and refined products, crude oil and NGL acquisition and marketing assets.
ETP owns an indirect 100% equity interest in Susser and the general partner interest, incentive distribution rights and a 42.8% limited partner interest in Sunoco LP. Susser operates convenience stores in Texas, New Mexico and Oklahoma. Sunoco LP distributes motor fuels to convenience stores and retail fuel outlets in Texas, New Mexico, Oklahoma, Kansas and Louisiana and other commercial customers. As discussed in Note 3, in October 2014, Sunoco LP acquired MACS from ETP. These operations are reported within the retail marketing segment.
Our financial statements reflect the following reportable business segments:
intrastate transportation and storage;
interstate transportation and storage;
midstream;
liquids transportation and services;
investment in Sunoco Logistics;
retail marketing; and
all other.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, Revenue from 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.
For future periods, we expect that the adoption of this standard will result in a change to revenues with offsetting changes to costs associated primarily with the designation 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 accounting for noncash consideration in multiple of our reportable segments, as well as fuel usage and loss allowances. None of these changes is expected to have a material impact on net income. ASU 2014-092016-02 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 in the first quarter of 2019 and 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, 2018, the Partnership 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. We do not anticipate a material impact to our financial position or results of operations as a result of the adoption of this standard. ASU 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’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance did 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 annual reportingfinancial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, including interim periods within that reporting period,2018, with earlierearly adoption not permitted. ASU 2014-09 can be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. The Partnership is currently evaluating the impact if any, that adopting this new accounting standard will have on our revenue recognition policies. In April 2014, the FASB issued Accounting Standards Update No. 2014-08, Presentation of Financial Statements (Topic 205)consolidated financial statements and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (“ASU 2014-08”), which changed the requirements for reporting discontinued operations. Under ASU 2014-08, a disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has or will have a major effect on an entity’s operations and financial results. ASU 2014-08 is effective for all disposals or classifications as held for sale of components of an entity that occur within fiscal years beginning after December 15, 2014, and early adoption is permitted. We expect to adopt this standard for the year ending December 31, 2015. ASU 2014-08 could have an impact on whether transactions will be reported in discontinued operations in the future, as well as the disclosures required when a component of an entity is disposed.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 partythird-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. Our retail marketing segment sells gasoline and diesel in addition to a broad mix of merchandise such as groceries, fast foods and beverages at its convenience stores. A portion of our gasoline and diesel sales are to wholesale customers on a consignment basis, in which we retain 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. We typically own the fuel dispensing equipment and underground storage tanks at consignment sites, and in some cases we own the entire site and have entered into an operating lease with the wholesale customer operating the site. In addition, our retail outlets derive other income from lottery ticket sales, money orders, prepaid phone cards and wireless services, ATM transactions, car washes, movie rental and other ancillary product and service offerings. Some of Sunoco, Inc.’s retail outlets provide a variety of car care services. Revenues related to the sale of products are recognized when title passes, while service revenues are recorded on a net commission basis and are recognized when services are provided. Title passage generally occurs when products are shipped or delivered in accordance with the terms of the respective sales agreements. In addition, revenues are not recognized until sales prices are fixed or determinable and collectability is reasonably assured.
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. In 1999, prior to its acquisition by Southern Union, Panhandle discontinued the application ofdoes 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 acquisitions)effects of acquisitions and deconsolidations) included in cash flows from operating activities is comprised as follows: | | | Years Ended December 31, | Years Ended December 31, | | 2014 | | 2013 | | 2012 | 2017 | | 2016 | | 2015 | Accounts receivable | $ | 547 |
| | $ | (458 | ) | | $ | 300 |
| $ | (950 | ) | | $ | (919 | ) | | $ | 819 |
| Accounts receivable from related companies | (45 | ) | | (17 | ) | | (50 | ) | 67 |
| | 30 |
| | (243 | ) | Inventories | 79 |
| | (256 | ) | | (253 | ) | 37 |
| | (497 | ) | | (157 | ) | Exchanges receivable | 6 |
| | (24 | ) | | 11 |
| | Other current assets | 120 |
| | (56 | ) | | 571 |
| 39 |
| | 83 |
| | (178 | ) | Other non-current assets, net | (6 | ) | | (22 | ) | | (53 | ) | (94 | ) | | (78 | ) | | 188 |
| Accounts payable | (804 | ) | | 525 |
| | (979 | ) | 758 |
| | 972 |
| | (1,215 | ) | Accounts payable to related companies | 20 |
| | (122 | ) | | 100 |
| (3 | ) | | 29 |
| | (160 | ) | Exchanges payable | (100 | ) | | 131 |
| | — |
| | Accrued and other current liabilities | (118 | ) | | 152 |
| | (151 | ) | (47 | ) | | 39 |
| | (83 | ) | Other non-current liabilities | (75 | ) | | 151 |
| | 25 |
| 24 |
| | 33 |
| | (219 | ) | Price risk management assets and liabilities, net | 112 |
| | (150 | ) | | 4 |
| 9 |
| | 62 |
| | 75 |
| Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | $ | (264 | ) | | $ | (146 | ) | | $ | (475 | ) | $ | (160 | ) | | $ | (246 | ) | | $ | (1,173 | ) |
Non-cash investing and financing activities and supplemental cash flow information are as follows: | | | | | | | | | | | | | | Years Ended December 31, | | 2014 | | 2013 | | 2012 | NON-CASH INVESTING ACTIVITIES: | | | | | | Accrued capital expenditures | $ | 541 |
| | $ | 167 |
| | $ | 359 |
| Net gains from subsidiary common unit issuances | $ | 175 |
| | $ | — |
| | $ | — |
| Regency common and Class F units received in exchange for contribution of SUGS | $ | — |
| | $ | 961 |
| | $ | — |
| AmeriGas limited partner interest received in exchange for contribution of Propane Business | $ | — |
| | $ | — |
| | $ | 1,123 |
| NON-CASH FINANCING ACTIVITIES: | | | | | | Issuance of Common Units in connection with the Susser Merger (see Note 3) | $ | 908 |
| | $ | — |
| | $ | — |
| Redemption of Common Units in connection with the Lake Charles LNG Transaction (see Note 3) | $ | 1,167 |
| | $ | — |
| | $ | — |
| Issuance of Common Units in connection with the ETP Holdco Acquisition | $ | — |
| | $ | 2,464 |
| | $ | — |
| Issuance of Class H Units | $ | — |
| | $ | 1,514 |
| | $ | — |
| Issuance of Common Units in connection with other acquisitions | $ | — |
| | $ | — |
| | $ | 2,295 |
| Contributions receivable related to noncontrolling interest | $ | — |
| | $ | 13 |
| | $ | 23 |
| SUPPLEMENTAL CASH FLOW INFORMATION: | | | | | | Cash paid for interest, net of interest capitalized | $ | 929 |
| | $ | 903 |
| | $ | 678 |
| Cash paid for income taxes | $ | 343 |
| | $ | 57 |
| | $ | 22 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | NON-CASH INVESTING ACTIVITIES: | | | | | | Accrued capital expenditures | $ | 1,059 |
| | $ | 822 |
| | $ | 896 |
| Sunoco LP limited partner interest received in exchange for contribution of the Sunoco, Inc. retail business to Sunoco LP | — |
| | 194 |
| | — |
| Net gains from subsidiary common unit transactions | — |
| | 37 |
| | 300 |
| NON-CASH FINANCING ACTIVITIES: | | | | | | Issuance of Common Units in connection with the PennTex Acquisition | $ | — |
| | $ | 307 |
| | $ | — |
| Issuance of Common Units in connection with the Regency Merger | — |
| | — |
| | 9,250 |
| Issuance of Class H Units in connection with the Bakken Pipeline Transaction | — |
| | — |
| | 1,946 |
| Contribution of assets from noncontrolling interest | 988 |
| | — |
| | 34 |
| Redemption of Common Units in connection with the Bakken Pipeline Transaction | — |
| | — |
| | 999 |
| Redemption of Common Units in connection with the Sunoco LP Exchange | — |
| | — |
| | 52 |
| SUPPLEMENTAL CASH FLOW INFORMATION: | | | | | | Cash paid for interest, net of interest capitalized | $ | 1,329 |
| | $ | 1,411 |
| | $ | 1,467 |
| Cash paid for (refund of) income taxes | 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 forto 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 We have a diverse portfolio of customers; however, because of the midstream and transportation services we provide, many of our customers are putengaged in place with counterparties where appropriatethe exploration and production segment. We manage trade credit risk to mitigate risk. Bad debt expense relatedcredit losses and exposure to these receivables is recognized atuncollectible 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 time an account is deemed uncollectible. Our investment in Sunoco Logistics segment extends credit terms to certain customers after reviewform 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.
Our interstate transportation and storage operations have a concentration of customers in the electric and gas utility industries, municipalities, as well as natural gas producers. This concentration of customers may impact our overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. From time to time, specifically identified customers having perceived credit risk are required to provide prepaymentsprepayment, or other forms of collateral. Management believes that the portfolio of receivables, which includes regulated electric utilities, regulated local distribution companies and municipalities, is subject to minimal credit risk. Our interstate transportation and storage operationssecurity. We establish an allowance for doubtful accounts on trade receivables based on the expected ultimate recovery of these receivables and considerconsiders 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.
Our retail marketing segment extends credit to customers after a review of various credit indicators. Depending on the type of customer and its risk profile, security Increases in the formallowance are recorded as a component of a cash deposit, letter of creditoperating expenses; reductions in the allowance are recorded when receivables are subsequently collected or mortgages may be required. Management records reserves for bad debt by computing a proportion of average write-off activity overwritten-off. Past due receivable balances are written-off when our efforts have been unsuccessful in collecting the past five years in comparison to the outstanding balance in accounts receivable. This proportion is then applied to the accounts receivable balance at the end of the reporting period to calculate a current estimate of what is uncollectible. The allowance computation may then be adjusted to reflect input provided by the credit department and business line managers who may have specific knowledge of
uncollectible items. The credit department and business line managers make the decision to write off an account, based on understanding of the potential collectability.amount due.
We enter into netting arrangements with counterparties of derivative contractsto 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 petroleum and chemical products. Natural gas held in storage isspare parts, 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 petroleum and chemical products is determined using the last-in, first out method. The cost of appliances, parts and fittings is determined by the first-in, first-out method.
Inventories consisted of the following: | | | | | | | | | | December 31, | | 2014 | | 2013 | Natural gas and NGLs | $ | 369 |
| | $ | 573 |
| Crude oil | 364 |
| | 488 |
| Refined products | 392 |
| | 543 |
| Appliances, parts and fittings, and other | 264 |
| | 161 |
| Total inventories | $ | 1,389 |
| | $ | 1,765 |
|
During the year ended December 31, 2014, the Partnership recorded write-downs of $473 million on its crude oil, refined products and NGL inventories as a result of a decline in the market price of these products. The write-down was 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. Exchanges
Exchanges consist of natural gas and NGL delivery imbalances (over and under deliveries) with others. These amounts, which are valued at market prices or weighted average market prices pursuant to contractual imbalance agreements, turn over monthly and are recorded as exchanges receivable or exchanges payable on our consolidated balance sheets. These imbalances are generally settled by deliveries of natural gas or NGLs, but may be settled in cash, depending on contractual terms.
Other Current Assets Other current assets consisted of the following: | | | December 31, | December 31, | | 2014 | | 2013 | 2017 | | 2016 | Deposits paid to vendors | $ | 65 |
| | $ | 49 |
| $ | 64 |
| | $ | 74 |
| Deferred income taxes | 14 |
| | — |
| | Prepaid expenses and other | 192 |
| | 261 |
| 146 |
| | 224 |
| Total other current assets | $ | 271 |
| | $ | 310 |
| $ | 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. We review property,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 NGL 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, | | 2014 | | 2013 | 2017 | | 2016 | Land and improvements | $ | 1,173 |
| | $ | 878 |
| $ | 1,706 |
| | $ | 676 |
| Buildings and improvements (1 to 45 years) | 1,868 |
| | 900 |
| 1,960 |
| | 1,617 |
| Pipelines and equipment (5 to 83 years) | 19,274 |
| | 16,966 |
| 44,050 |
| | 36,356 |
| Natural gas and NGL storage facilities (5 to 46 years) | 1,215 |
| | 1,083 |
| 1,681 |
| | 1,452 |
| Bulk storage, equipment and facilities (2 to 83 years) | 2,583 |
| | 1,933 |
| 3,036 |
| | 3,701 |
| Tanks and other equipment (5 to 40 years) | 35 |
| | 1,685 |
| | Retail equipment (2 to 99 years) | 515 |
| | 450 |
| | Vehicles (1 to 25 years) | 158 |
| | 124 |
| 124 |
| | 217 |
| Right of way (20 to 83 years) | 2,059 |
| | 1,901 |
| 3,424 |
| | 3,349 |
| Furniture and fixtures (2 to 25 years) | 53 |
| | 48 |
| | Linepack | 117 |
| | 116 |
| | Pad gas | 44 |
| | 52 |
| | Other (1 to 30 years) | 919 |
| | 626 |
| | Natural resources | | 434 |
| | 434 |
| Other (1 to 40 years) | | 534 |
| | 484 |
| Construction work-in-process | 3,187 |
| | 1,668 |
| 10,750 |
| | 9,934 |
| | 33,200 |
| | 28,430 |
| 67,699 |
| | 58,220 |
| Less – Accumulated depreciation | (3,457 | ) | | (2,483 | ) | | Less – Accumulated depreciation and depletion | | (9,262 | ) | | (7,303 | ) | Property, plant and equipment, net | $ | 29,743 |
| | $ | 25,947 |
| $ | 58,437 |
| | $ | 50,917 |
|
We recognized the following amounts of depreciation expense for the periods presented: | | | | | | | | | | | | | | Years Ended December 31, | | 2014 | | 2013 | | 2012 | Depreciation expense | $ | 1,026 |
| | $ | 944 |
| | $ | 615 |
| Capitalized interest, excluding AFUDC | $ | 99 |
| | $ | 43 |
| | $ | 99 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | Depreciation and depletion expense | $ | 2,060 |
| | $ | 1,793 |
| | $ | 1,713 |
| 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. Goodwill
Goodwill An impairment of an investment in an unconsolidated affiliate is tested for impairment annually or more frequently ifrecognized when circumstances indicate that goodwill might be impaired. Our annual impairment test is performed as of August 31 for subsidiaries in our intrastate transportation and storage and midstream segments and during the fourth quarter for subsidiaries in our interstate transportation and storage, liquids
transportation and services, and retail marketing segments and all others. We recorded goodwill impairments for the periods presented in these consolidated financial statements.
Changesa decline in the carrying amountinvestment 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 goodwill were as follows:the following: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Intrastate Transportation and Storage | | Interstate Transportation and Storage | | Midstream | | Liquids Transportation and Services | | Investment in Sunoco Logistics | | Retail Marketing | | All Other | | Total | Balance, December 31, 2012 | $ | 10 |
| | $ | 1,884 |
| | $ | 375 |
| | $ | 432 |
| | $ | 1,368 |
| | $ | 1,272 |
| | $ | 265 |
| | $ | 5,606 |
| Goodwill acquired | — |
| | — |
| | — |
| | — |
| | — |
| | 156 |
| | — |
| | 156 |
| Goodwill disposed | — |
| | — |
| | (337 | ) | | — |
| | — |
| | — |
| | — |
| | (337 | ) | Goodwill impairment | — |
| | (689 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (689 | ) | Other | — |
| | — |
| | (2 | ) | | — |
| | (22 | ) | | 17 |
| | — |
| | (7 | ) | Balance, December 31, 2013 | 10 |
| | 1,195 |
| | 36 |
| | 432 |
| | 1,346 |
| | 1,445 |
| | 265 |
| | 4,729 |
| Goodwill acquired | — |
| | — |
| | — |
| | — |
| | 12 |
| | 1,862 |
| | — |
| | 1,874 |
| Goodwill disposed | — |
| | (184 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (184 | ) | Balance, December 31, 2014 | $ | 10 |
| | $ | 1,011 |
| | $ | 36 |
| | $ | 432 |
| | $ | 1,358 |
| | $ | 3,307 |
| | $ | 265 |
| | $ | 6,419 |
|
| | | | | | | | | | December 31, | | 2017 | | 2016 | Regulatory assets | $ | 85 |
| | $ | 86 |
| Deferred charges | 210 |
| | 217 |
| Restricted funds | 192 |
| | 190 |
| Long-term affiliated receivable | 85 |
| | 90 |
| Other | 186 |
| | 89 |
| Total other non-current assets, net | $ | 758 |
| | $ | 672 |
|
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. We recorded a net increase in goodwill of $1.69 billion during the year ended December 31, 2014 primarily due to $1.73 billion(1)Includes unamortized financing costs related to the Susser Merger.Partnership’s revolving credit facilities.
During the fourth quarterRestricted funds primarily consisted of 2013, we performed a goodwill impairment test onrestricted cash held in our Lake Charles LNG reporting unit. In accordance with GAAP, we performed step one of the goodwill impairment test and determined that the estimated fair value of the Lake Charles LNG reporting unit was less than its carrying amount primarily due to changes related to (i) the structure and capitalization of the planned LNG export project at Lake Charles LNG’s Lake Charles facility, (ii) an analysis of current macroeconomic factors, including global natural gas prices and relative spreads, as of the date of our assessment, (iii) judgments regarding the prospect of obtaining regulatory approval for a proposed LNG export project and the uncertainty associated with the timing of such approvals, and (iv) changes in assumptions related to potential future revenues from the import facility and the proposed export facility. An assessment of these factors in the fourth quarter of 2013 led to a conclusion that the estimated fair value of the Lake Charles LNG reporting unit was less than its carrying amount. We then applied the second step in the goodwill impairment test, allocating the estimated fair value of the reporting unit among all of the assets and liabilities of the reporting unit in a hypothetical purchase price allocation. The assets and liabilities of the reporting unit had recently been measured at fair value in 2012 as a result of the acquisition of Southern Union, and those estimated fair values had been recorded at the reporting unit through the application of “push-down” accounting. For purposes of the hypothetical purchase price allocation used in the goodwill impairment test, we estimated the fair value of the assets and liabilities of the reporting unit in a manner similar to the original purchase price allocation. In allocating value to the property, plant and equipment, we used current replacement costs adjusted for assumed depreciation. We also included the estimated fair value of working capital and identifiable intangible assets in the reporting unit. We adjusted deferred income taxes based on these estimated fair values. Based on this hypothetical purchase price allocation, estimated goodwill was $184 million, which was less than the balance of $873 million that had originally been recorded by the reporting unit through “push-down” accounting in 2012. As a result, we recorded a goodwill impairment of $689 million during the fourth quarter of 2013.wholly-owned captive insurance companies.
No other goodwill impairments were identified or recorded for our reporting units.
Intangible Assets Intangible assets are stated at cost, net of amortization computed on the straight-line method. We eliminate from our balance sheetThe 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, 2014 | | December 31, 2013 | | Gross Carrying Amount | | Accumulated Amortization | | Gross Carrying Amount | | Accumulated Amortization | Amortizable intangible assets: | | | | | | | | Customer relationships, contracts and agreements (3 to 46 years) | $ | 1,482 |
| | $ | (267 | ) | | $ | 1,393 |
| | $ | (164 | ) | Patents (9 years) | 48 |
| | (11 | ) | | 48 |
| | (6 | ) | Trade Names (15 years) | 490 |
| | — |
| | — |
| | — |
| Other (1 to 15 years) | 36 |
| | (7 | ) | | 4 |
| | (1 | ) | Total amortizable intangible assets | $ | 2,056 |
| | $ | (285 | ) | | $ | 1,445 |
| | $ | (171 | ) | Non-amortizable intangible assets: | | | | | | | | Trademarks | 316 |
| | — |
| | 294 |
| | — |
| Total intangible assets | $ | 2,372 |
| | $ | (285 | ) | | $ | 1,739 |
| | $ | (171 | ) |
| | | | | | | | | | | | | | | | | | December 31, 2017 | | December 31, 2016 | | Gross Carrying Amount | | Accumulated Amortization | | Gross Carrying Amount | | Accumulated Amortization | Amortizable intangible assets: | | | | | | | | Customer relationships, contracts and agreements (3 to 46 years) | $ | 6,250 |
| | $ | (1,003 | ) | | $ | 5,362 |
| | $ | (737 | ) | Patents (10 years) | 48 |
| | (26 | ) | | 48 |
| | (21 | ) | Trade Names (20 years) | 66 |
| | (25 | ) | | 66 |
| | (22 | ) | Other (5 to 20 years) | 1 |
| | — |
| | 2 |
| | (2 | ) | Total intangible assets | $ | 6,365 |
| | $ | (1,054 | ) | | $ | 5,478 |
| | $ | (782 | ) |
Aggregate amortization expense of intangible assets was as follows: | | | | | | | | | | | | | | Years Ended December 31, | | 2014 | | 2013 | | 2012 | Reported in depreciation and amortization | $ | 104 |
| | $ | 88 |
| | $ | 36 |
|
| | | | | | | | | | | | | | 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: | | | 2015 | $ | 128 |
| | 2016 | 125 |
| | 2017 | 125 |
| | 2018 | 124 |
| $ | 280 |
| 2019 | 121 |
| 278 |
| 2020 | | 278 |
| 2021 | | 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. Other Non-Current Assets, netIn 2015, we recorded $24 million of intangible asset impairments related to the NGL and refined products transportation and services segment primarily due to an expected decrease in future cash flows.
Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consistedGoodwill
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 the following:goodwill were as follows: | | | | | | | | | | December 31, | | 2014 | | 2013 | Unamortized financing costs (3 to 30 years) | $ | 63 |
| | $ | 70 |
| Regulatory assets | 85 |
| | 86 |
| Deferred charges | 220 |
| | 144 |
| Restricted funds | 177 |
| | 378 |
| Other | 148 |
| | 88 |
| Total other non-current assets, net | $ | 693 |
| | $ | 766 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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, 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 | — |
| | (262 | ) | | — |
| | (79 | ) | | — |
| | (452 | ) | | (793 | ) | Other | — |
| | — |
| | (1 | ) | | — |
| | — |
| | — |
| | (1 | ) | Balance, December 31, 2017 | $ | 10 |
| | $ | 12 |
| | $ | 870 |
| | $ | 693 |
| | $ | 1,167 |
| | $ | 363 |
| | $ | 3,115 |
|
Restricted fundsGoodwill 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 consisteddue 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 restricted2016, 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 heldflows 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 $99 million in the interstate transportation and storage segment and $106 million in the NGL and refined products transportation and services segment primarily due to market declines in current and expected future commodity prices in the fourth quarter of 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 wholly-owned captive insurance companies.
Tableimpairment assessments are reasonable and based on available market information, but variations in any of Contentsthe 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, Sunoco Logistics and our retail marketing operations, discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as of December 31, 20142017 and 2013,2016, 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 sheet:sheets included AROs of $165 million and $170 million, respectively.
| | | | | | | | | | December 31, | | 2014 | | 2013 | Interstate transportation and storage | $ | 58 |
| | $ | 55 |
| Investment in Sunoco Logistics | 41 |
| | 41 |
| Retail marketing | 87 |
| | 84 |
| | $ | 186 |
| | $ | 180 |
|
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. AsLong-lived assets related to AROs aggregated $2 million and $14 million, and were reflected as property, plant and equipment on our balance sheet as of December 31, 2014, there were no2017 and 2016, respectively. In addition, the Partnership had $21 million and $13 million legally restricted funds for the purpose of settling AROs.
Accrued and Other Current Liabilities Accrued and other current liabilities consisted of the following: | | | December 31, | December 31, | | 2014 | | 2013 | 2017 | | 2016 | Interest payable | $ | 301 |
| | $ | 294 |
| $ | 443 |
| | $ | 440 |
| Customer advances and deposits | 82 |
| | 126 |
| 59 |
| | 56 |
| Accrued capital expenditures | 536 |
| | 166 |
| 1,006 |
| | 749 |
| Accrued wages and benefits | 196 |
| | 155 |
| 208 |
| | 212 |
| Taxes payable other than income taxes | 236 |
| | 214 |
| 108 |
| | 63 |
| Income taxes payable | 50 |
| | 3 |
| | Deferred income taxes | 99 |
| | 119 |
| | Exchanges payable | | 154 |
| | 208 |
| Other | 274 |
| | 351 |
| 165 |
| | 177 |
| Total accrued and other current liabilities | $ | 1,774 |
| | $ | 1,428 |
| $ | 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 our consolidated subsidiaries has the option to sell its interests to 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. Price risk management assets and liabilities are recorded at 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, 20142017 was $20.40$34.28 billion and $19.34$33.09 billion, respectively. As of December 31, 2013,2016, the aggregate fair value and carrying amount of our debt obligations was $17.69$33.85 billion and $17.09$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, and 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. During the periodyear ended December 31, 2014,2017, 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, 20142017 and 20132016 based on inputs used to derive their fair values: | | | Fair Value Total | | Fair Value Measurements at December 31, 2014 | Fair Value Total | | Fair Value Measurements at December 31, 2017 | Level 1 | | Level 2 | Level 1 | | Level 2 | Assets: | | | | | | | | | | | Interest rate derivatives | $ | 3 |
| | $ | — |
| | $ | 3 |
| | Commodity derivatives: |
|
| | | | | | | | | | Natural Gas: |
| | | | | | | | | | Basis Swaps IFERC/NYMEX | 19 |
| | 19 |
| | — |
| $ | 11 |
| | $ | 11 |
| | $ | — |
| Swing Swaps IFERC | 26 |
| | 1 |
| | 25 |
| 13 |
| | — |
| | 13 |
| Fixed Swaps/Futures | 541 |
| | 541 |
| | — |
| 70 |
| | 70 |
| | — |
| Forward Physical Swaps | 1 |
| | — |
| | 1 |
| 8 |
| | — |
| | 8 |
| Power: |
|
| | | | | | | | | | Forwards | 3 |
| | — |
| | 3 |
| 23 |
| | — |
| | 23 |
| Futures | 4 |
| | 4 |
| | — |
| | Natural Gas Liquids – Forwards/Swaps | 46 |
| | 46 |
| | — |
| 193 |
| | 193 |
| | — |
| Refined Products – Futures | 21 |
| | 21 |
| | — |
| | Crude – Futures | | 2 |
| | 2 |
| | — |
| Total commodity derivatives | 661 |
| | 632 |
| | 29 |
| 320 |
| | 276 |
| | 44 |
| Other non-current assets | | 21 |
| | 14 |
| | 7 |
| Total assets | $ | 664 |
| | $ | 632 |
| | $ | 32 |
| $ | 341 |
| | $ | 290 |
| | $ | 51 |
| Liabilities: |
|
| |
| |
|
| | | | | | Interest rate derivatives | $ | (155 | ) | | $ | — |
| | $ | (155 | ) | $ | (219 | ) | | $ | — |
| | $ | (219 | ) | Commodity derivatives: | | | | | | | | | | | Natural Gas: |
|
| | | | | | | | | | Basis Swaps IFERC/NYMEX | (18 | ) | | (18 | ) | | — |
| (24 | ) | | (24 | ) | | — |
| Swing Swaps IFERC | (25 | ) | | (2 | ) | | (23 | ) | (15 | ) | | (1 | ) | | (14 | ) | Fixed Swaps/Futures | (490 | ) | | (490 | ) | | — |
| (57 | ) | | (57 | ) | | — |
| Power: |
|
| | | | | | Forwards | (4 | ) | | — |
| | (4 | ) | | Futures | (2 | ) | | (2 | ) | | — |
| | Forward Physical Swaps | | (2 | ) | | — |
| | (2 | ) | Power – Forwards | | (22 | ) | | — |
| | (22 | ) | Natural Gas Liquids – Forwards/Swaps | (32 | ) | | (32 | ) | | — |
| (192 | ) | | (192 | ) | | — |
| Refined Products – Futures | (7 | ) | | (7 | ) | | — |
| (25 | ) | | (25 | ) | | — |
| Crude – Futures | | (1 | ) | | (1 | ) | | — |
| Total commodity derivatives | (578 | ) | | (551 | ) | | (27 | ) | (338 | ) | | (300 | ) | | (38 | ) | Total liabilities | $ | (733 | ) | | $ | (551 | ) | | $ | (182 | ) | $ | (557 | ) | | $ | (300 | ) | | $ | (257 | ) |
| | | Fair Value Total | | Fair Value Measurements at December 31, 2013 | Fair Value Total | | Fair Value Measurements at December 31, 2016 | | Level 1 | | Level 2 | Level 1 | | Level 2 | | Level 3 | Assets: | | | | | | | | | | | | | Interest rate derivatives | $ | 47 |
| | $ | — |
| | $ | 47 |
| | Commodity derivatives: | | | | | | | Natural Gas: | | | | | | | Basis Swaps IFERC/NYMEX | 5 |
| | 5 |
| | — |
| | Swing Swaps IFERC | 8 |
| | 1 |
| | 7 |
| | Fixed Swaps/Futures | 201 |
| | 201 |
| | — |
| | Power: | | | | | | | Forwards | 3 |
| | — |
| | 3 |
| | Natural Gas Liquids – Forwards/Swaps | 5 |
| | 5 |
| | — |
| | Refined Products – Futures | 5 |
| | 5 |
| | — |
| | Total commodity derivatives | 227 |
| | 217 |
| | 10 |
| | Total assets | $ | 274 |
| | $ | 217 |
| | $ | 57 |
| | Liabilities: | | | | | | | Interest rate derivatives | $ | (95 | ) | | $ | — |
| | $ | (95 | ) | | Commodity derivatives: | | | | | | | | | | | | | Natural Gas: | | | | | | | | | | | | | Basis Swaps IFERC/NYMEX | (4 | ) | | (4 | ) | | — |
| $ | 14 |
| | $ | 14 |
| | $ | — |
| | $ | — |
| Swing Swaps IFERC | (6 | ) | | — |
| | (6 | ) | 2 |
| | — |
| | 2 |
| | — |
| Fixed Swaps/Futures | (201 | ) | | (201 | ) | | — |
| 96 |
| | 96 |
| | — |
| | — |
| Forward Physical Swaps | (1 | ) | | — |
| | (1 | ) | 1 |
| | — |
| | 1 |
| | — |
| Power: | | | | | | | | | | | | | Forwards | (1 | ) | | — |
| | (1 | ) | 4 |
| | — |
| | 4 |
| | — |
| Futures | | 1 |
| | 1 |
| | — |
| | — |
| Options – Calls | | 1 |
| | 1 |
| | — |
| | — |
| Natural Gas Liquids – Forwards/Swaps | (5 | ) | | (5 | ) | | — |
| 233 |
| | 233 |
| | — |
| | — |
| Refined Products – Futures | (5 | ) | | (5 | ) | | — |
| 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 | (223 | ) | | (215 | ) | | (8 | ) | (472 | ) | | (464 | ) | | (8 | ) | | — |
| Total liabilities | $ | (318 | ) | | $ | (215 | ) | | $ | (103 | ) | $ | (666 | ) | | $ | (464 | ) | | $ | (201 | ) | | $ | (1 | ) |
At December 31, 2013, the fair value of the Lake Charles LNG reporting unit was classified as Level 3 of the fair value hierarchy due to the significance of unobservable inputs developed using company-specific information. We used the income approach to measure the fair value of the Lake Charles LNG reporting unit. Under the income approach, we calculated the fair value based on the present value of the estimated future cash flows. The discount rate used, which was an unobservable input, was based on the weighted-average cost of capital adjusted for the relevant risk associated with business-specific characteristics and the uncertainty related to the business's ability to execute on the projected cash flows.
ContributionsCommon Units
The change in Aid of Construction CostsETE Common Units during the years ended December 31, 2017, 2016 and 2015 was as follows: | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | Number of Common Units, beginning of period | 1,046.9 |
| | 1,044.8 |
| | 1,077.5 |
| Conversion of Class D Units to ETE Common Units | — |
| | — |
| | 0.9 |
| Repurchase of common units under buyback program | — |
| | — |
| | (33.6 | ) | Issuance of common units | 32.2 |
| | 2.1 |
| | — |
| Number of Common Units, end of period | 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, | | 2017 | | 2016 | | 2015 | Number of Series A Convertible Preferred Units, beginning of period | 329.3 |
| | — |
| | — |
| Issuance of Series A Convertible Preferred Units | — |
| | 329.3 |
| | — |
| Number of Series A Convertible Preferred Units, end of period | 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 of our capital projects, third parties are obligatedcommon unitholders (“Electing Unitholders”) who elected to reimburse us for all orparticipate in a plan to forgo a portion of project expenditures. The majoritytheir 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 arrangementsparticipating 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 associatedexpected 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 pipeline constructionrespect 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 production well tie-ins. Contributionsany 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 aidthe carrying amount of construction costs (“CIAC”)the Convertible Units until the conversion into common units at the end of the plan period. The Convertible Units had $450 million carrying value as of December 31, 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 23.7 million newly issued ETP common units for approximately $568 million. Common Unit Split On July 27, 2015, ETE completed a two-for-one split of the Partnership’s outstanding common units 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 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, 2017. Class D Units In 2013, the Partnership issued 3,080,000 Class D Units of ETE pursuant to an agreement with a former executive. The Class D Units were convertible to ETE Common Units, subject to certain vesting requirements which were not met prior to the former executive’s termination in 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 netted against our project costsmade 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 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 $1.00 billion.
During the year ended December 31, 2017, ETP issued 22.6 million units for $503 million, net of commissions of $5 million. As of December 31, 2017, $752 million of ETP’s Common Units remained available to be issued under ETP’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 received,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 any CIACbeneficial owners of ETP Common Units a voluntary means by which exceeds our total project costs, is recognized as other incomethey can increase the number of ETP Common Units they own by reinvesting the quarterly cash distributions they would otherwise receive in the periodpurchase 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 and 2015, aggregate distributions of $228 million, $216 million, and $360 million, respectively, were reinvested under the DRIP resulting in which it is realized.
As of December 31, 2017, a total of 20.8 million Common Units remain available to be issued under the existing registration statement. ShippingAugust 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 Handling Costsfor general partnership purposes. Shipping and handling costsETP Class E Units
There are included in costcurrently 8.9 million ETP Class E Units outstanding, all of products sold, except for shipping and handling costs related to fuel consumed for compression and treating which are includedcurrently 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 Class E Unitholders, up to $1.41 per unit per year. As the Class E Units are owned by a wholly-owned subsidiary, the cash distributions on those units are eliminated in operating expenses.ETP’s consolidated financial statements. Although no plans are currently in place, management may evaluate whether to retire the ETP Class E Units at a future date. CostsETP Class G Units
There are currently 90.7 million ETP Class G Units outstanding, all of which are held by wholly-owned subsidiaries of ETP. The ETP Class G Units generally do not have any voting rights. The ETP Class G Units are entitled to aggregate cash distributions equal to 35% of the total amount of cash generated by ETP and Expenses Costsits subsidiaries, other than ETP Holdco, and available for distribution, up to a maximum of products sold include actual cost$3.75 per ETP Class G Unit per year. Allocations of fuel sold, adjusteddepreciation and amortization to the ETP Class G Units 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 authoritiestax purposes are based on a predetermined percentage and are not contingent on whether ETP has net basis except for our retail marketing segment in which consumer excise taxes on sales of refined products and merchandiseincome or loss. These units are included in both revenues and costs and expensesreflected as treasury units in the consolidated statementsfinancial statements.
ETP Class H Units 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 were 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. The Class H units were cancelled in connection with the merger of ETP and Sunoco Logistics in April 2017.
ETP Class I Units In connection with the 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 ended 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 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. 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, 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, 2017, a total of 101.5 million Class K Units were held by wholly-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 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 Sunoco Logistics Merger, the previous Sunoco Logistics equity distribution agreement was terminated. ETP Series A and Series Preferred Units In November 2017, ETP issued 950,000 of its 6.250% Series A Preferred Units at a price of $1,000 per unit, and 550,000 of 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 date of original 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 not previously owned by ETP for $20.00 per common unit in cash. ETP now owns all of the 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, 2017, $295 million of Sunoco LP common units remained available to be issued under the currently effective equity distribution agreement. 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. Sunoco LP Series 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 purchase price of $300 million. The distribution rate of Sunoco LP Series 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 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 for the periods presented were as follows: | | | | | | | | | 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 additional information below. |
Our distributions declared and paid with respect to our Convertible Unit during the years ended December 31, 2016 and 2017 were as follows: | | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | March 31, 2016 | | May 6, 2016 | | May 19, 2016 | | $ | 0.1100 |
| June 30, 2016 | | August 8, 2016 | | August 19, 2016 | | 0.1100 |
| September 30, 2016 | | November 7, 2016 | | November 18, 2016 | | 0.1100 |
| December 31, 2016 | | 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 limited partnership agreement, within 45 days after the end of each quarter, ETP distributes all cash on hand at the end of the quarter, less reserves established by the general partner in its discretion. This is defined as “available cash” in ETP’s partnership agreement. The general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct ETP’s business. ETP will make quarterly distributions to the extent 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 general partner interest, Class I units and a portion of the outstanding ETP common units. | | | | | | | | | | | | 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 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 no effectprevious transactions, we have agreed to relinquish its right to the following amounts of incentive distributions in future periods: | | | | | | | | Total Year | 2018 | | $ | 153 |
| 2019 | | 128 |
| Each year beyond 2019 | | 33 |
|
Distributions declared and paid by ETP to the Series A and Series B preferred unitholders were as follows: | | | | | | | | | | | | | | | 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 for the periods presented were as follows: | | | | | | | | | 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, | | 2017 | | 2016 | Available-for-sale securities | $ | 8 |
| | $ | 2 |
| Foreign currency translation adjustment | (5 | ) | | (5 | ) | Actuarial gain (loss) related to pensions and other postretirement benefits | (5 | ) | | 7 |
| Investments in unconsolidated affiliates, net | 5 |
| | 4 |
| Subtotal | 3 |
| | 8 |
| Amounts attributable to noncontrolling interest | (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). Excise taxes collected: | | | | | | | | | | December 31, | | 2017 | | 2016 | Available-for-sale securities | $ | (2 | ) | | $ | (2 | ) | Foreign currency translation adjustment | 3 |
| | 3 |
| Actuarial loss relating to pension and other postretirement benefits | 3 |
| | — |
| Total | $ | 4 |
| | $ | 1 |
|
| | 9. | UNIT-BASED COMPENSATION PLANS: |
We, ETP 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 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 12.0 million units. As of December 31, 2017, 10.8 million units remain available to be awarded under the plan. During the year ended December 31, 2017, 1.2 million ETE unit awards were granted to ETE employees and certain 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, 2017 and 2016, a total of 2,018 and 28,648 ETE Common Units vested, with a total fair value of $39 thousand and $205 thousand, respectively, as of the vesting date. As of December 31, 2017, a total of 1,251,002 restricted units remain outstanding, for which we expect to recognize a total of $21 million in compensation over a weighted average period of 3.5 years. Subsidiary Unit-Based Compensation Plans Each of ETP 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 our retail marketing segment were $2.46 billion, $2.22 billion and $573 millionthe respective subsidiaries during the period the restricted unit is outstanding. The following table summarizes the activity of the Subsidiary Unit Awards: | | | | | | | | | | | | | | | | 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, 2014, 20132017, 2016, and 2012, respectively.2015 was $40 million, $40 million, and $57 million, respectively, based on the market price of the respective subsidiaries’ common units as of the vesting date. As of December 31, 2017, estimated compensation cost related to Subsidiary Unit Awards not yet recognized was $216 million, and the weighted average period over which this cost is expected to be recognized in expense is 2.8 years. Income Taxes
ETP isAs a publicly traded limited partnership, and iswe are not taxable forsubject to United States federal income tax and most state income tax purposes. As a result, our earnings or losses, totaxes. However, 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, 2014, 2013 and 2012, our qualifying income met the statutory requirement.
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, | | 2017 | | 2016 | | 2015 | Current expense (benefit): | | | | | | Federal | $ | 54 |
| | $ | (47 | ) | | $ | (308 | ) | State | (16 | ) | | (34 | ) | | (54 | ) | Total | 38 |
| | (81 | ) | | (362 | ) | Deferred expense (benefit): | | | | | | Federal | (2,055 | ) | | (189 | ) | | 268 |
| State | 184 |
| | 12 |
| | (29 | ) | Total | (1,871 | ) | | (177 | ) | | 239 |
| Total income tax expense (benefit) from continuing operations | $ | (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 United States federal and most state income taxes at the partnership level. A reconciliation of income tax expense (benefit) at the United States statutory rate to the income tax expense (benefit) attributable to continuing operations for the years ended December 31, 2017, 2016 and 2015 is as follows: | | | | | | | | | | | | | | 2017 | | 2016 | | 2015 | Income tax expense (benefit) at United States statutory rate of 35 percent | $ | 248 |
| | $ | 71 |
| | $ | 316 |
| Increase (reduction) in income taxes resulting from: | | | | | | Partnership earnings not subject to tax | (477 | ) | | (576 | ) | | (355 | ) | Goodwill impairment | 207 |
| | 278 |
| | — |
| State tax, net of federal tax benefit | 124 |
| | (10 | ) | | (29 | ) | Dividend received deduction | (14 | ) | | (15 | ) | | (22 | ) | Federal rate change | (1,812 | ) | | — |
| | — |
| Audit settlement | — |
| | — |
| | (7 | ) | Change in tax status of subsidiary | (124 | ) | | — |
| | — |
| Other | 15 |
| | (6 | ) | | (26 | ) | Income tax expense (benefit) from continuing operations | $ | (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, | | 2017 | | 2016 | Deferred income tax assets: | | | | Net operating losses and alternative minimum tax credit | $ | 683 |
| | $ | 472 |
| Pension and other postretirement benefits | 21 |
| | 30 |
| Long-term debt | 14 |
| | 32 |
| Other | 191 |
| | 182 |
| Total deferred income tax assets | 909 |
| | 716 |
| Valuation allowance | (189 | ) | | (118 | ) | Net deferred income tax assets | 720 |
| | 598 |
| | | | | Deferred income tax liabilities: | | | | Property, plant and equipment | (1,036 | ) | | (1,633 | ) | Investments in unconsolidated affiliates | (2,726 | ) | | (3,789 | ) | Trademarks | (173 | ) | | (273 | ) | Other | (100 | ) | | (15 | ) | Total deferred income tax liabilities | (4,035 | ) | | (5,710 | ) | 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, | | 2017 | | 2016 | Net deferred income tax liability, beginning of year | $ | (5,112 | ) | | $ | (4,590 | ) | Goodwill associated with Sunoco Retail to Sunoco LP transaction (see Note 3) | — |
| | (460 | ) | Net assets (excluding goodwill) associated with Sunoco Retail to Sunoco LP (see Note 3) | — |
| | (243 | ) | Tax provision, including provision from discontinued operations | 1,825 |
| | 201 |
| Other | (28 | ) | | (20 | ) | Net deferred income tax liability | $ | (3,315 | ) | | $ | (5,112 | ) |
ETP Holdco and certain other corporate subsidiaries have federal net operating loss carryforward tax benefits of $403 million, all of which will expire in 2031 through 2037. Our corporate subsidiaries have $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 $274 million, $217 million net of federal tax, which expire between January 1, 2018 and 2037. A valuation allowance of $186 million is applicable to the state net operating loss carryforward benefits applicable to significant restriction on their use in the Commonwealth of 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, | | 2017 | | 2016 | | 2015 | Balance at beginning of year | $ | 615 |
| | $ | 610 |
| | $ | 440 |
| Additions attributable to tax positions taken in the current year | — |
| | 8 |
| | 178 |
| Additions attributable to tax positions taken in prior years | 28 |
| | 18 |
| | — |
| Reduction attributable to tax positions taken in prior years | (25 | ) | | (20 | ) | | — |
| Lapse of statute | (9 | ) | | (1 | ) | | (8 | ) | Balance at end of year | $ | 609 |
| | $ | 615 |
| | $ | 610 |
|
As of December 31, 2017, we have $605 million ($576 million after federal income tax benefits) related to tax positions which, if recognized, would impact our effective tax rate. Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During 2017, we recognized interest and penalties of less than $3 million. At December 31, 2017, we have interest and penalties accrued of $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, 2017. In December 2015, the Pennsylvania Commonwealth Court determined in Nextel Communications v. Commonwealth (“Nextel”) that the Pennsylvania limitation on NOL carryforward deductions violated the uniformity clause of the Pennsylvania Constitution and struck the NOL limitation in its entirety. In October 2017, the Pennsylvania Supreme Court affirmed the decision 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. has recognized approximately $67 million ($53 million after federal income tax benefits) in tax benefit based on previously filed tax returns and certain previously filed protective claims as relates to its cases currently held pending the Nextel matter. However, based upon the Pennsylvania Supreme Court’s October 2017 decision, and because of uncertainty in the breadth of the application of the decision, we have reserved $27 million ($21 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 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 taxes. Thesetax 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 subsidiaries include Susserfederal 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 previously provided contingent residual support of certain debt obligations of AmeriGas. AmeriGas has subsequently repaid the remainder of the related obligations and ETP no longer provides contingent residual support for any AmeriGas 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 (“ETC M-A”). On 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: $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 the obligation to pay the principal of each series of notes once all remedies, including in the 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 respect of the principal of such notes. ETC M-A will not otherwise be subject to the covenants of the indenture governing the 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 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, | | | 2017 | | 2016 | | 2015 | Rental expense(1) | | $ | 196 |
| | $ | 187 |
| | $ | 281 |
| Less: Sublease rental income | | (25 | ) | | (26 | ) | | (26 | ) | Rental expense, net | | $ | 171 |
| | $ | 161 |
| | $ | 255 |
|
| | (1) | Includes contingent rentals totaling $16 million, $18 million and $20 million for the years ended December 31, 2017, 2016 and 2015, respectively. |
Future minimum lease commitments for such leases are: | | | | | Years Ending December 31: | | 2018 | $ | 113 |
| 2019 | 100 |
| 2020 | 96 |
| 2021 | 83 |
| 2022 | 71 |
| Thereafter | 606 |
| Future minimum lease commitments | 1,069 |
| Less: Sublease rental income | (152 | ) | Net future minimum lease commitments | $ | 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 On July 25, 2016, the 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. After significant delay, the USACE also issued easements to allow the pipeline to cross land owned by the USACE adjacent to the Missouri River in two locations. Also in July, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia against the USACE that challenged the legality of the permits issued for the construction of the Dakota Access pipeline across those waterways and claimed 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 intervened in the case. The SRST soon added a request for an emergency temporary restraining order (“TRO”) to stop construction on the pipeline project. On September 9, 2016, the Court denied SRST’s motion for a preliminary injunction, rendering the TRO request moot. After the September 9, 2016 ruling, the Department of the Army, the DOJ, and the Department of the Interior released a joint statement that the USACE would not grant the easement for the land adjacent to Lake Oahe until the Department of the Army completed a review to determine whether it was necessary to reconsider the USACE’s decision under various federal statutes relevant to the pipeline approval. The SRST appealed the denial of the preliminary injunction to the 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, 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 statutes governing the use of government property. 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 February 2017, in 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 allowing the pipeline to cross Lake Oahe. Almost immediately, the Cheyenne River Sioux Tribe (“CRST”), which had intervened in the lawsuit in August 2016, moved for a preliminary injunction and 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 Court denied the TRO and preliminary injunction, and the CRST appealed and requested an injunction pending appeal in the district court 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 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 halt or suspend the operation of the pipeline, we cannot assure this outcome. 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”) 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 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. Lone Star is still quantifying the extent of its incurred and ongoing damages 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 members of the petroleum industry, are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices. The plaintiffs 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, 2017, Sunoco, Inc. is a defendant in seven cases, including one case each initiated by the States of Maryland, New Jersey, Vermont, Rhode Island, one by the Commonwealth of Pennsylvania and two by the Commonwealth of Puerto Rico. The more recent Puerto Rico action is 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 which owns Corporation, and Sunoco Partners Marketing & Terminals, L.P. Four of these cases are pending in a multidistrict litigation proceeding in a New York federal court; one is
pending in federal court in Rhode Island, one is pending in state court in Vermont, and one is pending in state court in Maryland. Sunoco, Inc. and Panhandle.Sunoco, Inc. (R&M) have reached a settlement with the State of New Jersey. The PartnershipCourt approved the Judicial Consent Order on December 5, 2017. Dismissal of the case against Sunoco, Inc. and 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. An 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 such adverse determination occurs, but 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-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. On June 10, 2015, Adrian Dieckman (“Dieckman”), a purported Regency unitholder, filed a class action complaint, Dieckman v. Regency GP LP, et al., C.A. No. 11130-CB, in the Court of Chancery of the State of 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 Regency 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. On March 29, 2016, the Delaware Court of Chancery granted the Regency Litigation Defendants’ motion to dismiss the lawsuit in its corporate subsidiaries accountentirety. Dieckman appealed. On January 20, 2017, the Delaware Supreme Court reversed 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 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 filed a notice of appeal with the Court of Appeals. On July 18, 2017, the Court of Appeals issued its opinion and reversed the trial court’s judgment. ETP’s motion for income taxesrehearing to the Court of Appeals was denied. ETP filed a petition for review with the Texas Supreme Court. Enterprise’s response is due February 26, 2018. Sunoco Logistics Merger Litigation Seven purported Energy Transfer Partners, L.P. common unitholders (the “ETP Unitholder Plaintiffs”) separately filed seven putative unitholder class action lawsuits against ETP, ETP GP, ETP LLC, the members of the ETP Board, and ETE (the “ETP-SXL Defendants”) in connection with the announcement of the Sunoco Logistics Merger. Two of these lawsuits were voluntarily dismissed in March 2017. The five remaining lawsuits were consolidated as In re Energy Transfer Partners, L.P. Shareholder Litig., C.A. No. 1:17-cv-00044-CCC, in the United States District Court for the District of Delaware (the “Sunoco Logistics Merger Litigation”). The ETP Unitholder Plaintiffs allege causes of action challenging the merger and the proxy statement/prospectus filed in connection with the Sunoco Logistics Merger (the “ETP-SXL Merger Proxy”). The ETP Unitholder Plaintiffs sought rescission of the Sunoco Logistics Merger or rescissory damages for ETP unitholders, as well
as an award of costs and attorneys’ fees. On October 5, 2017, the ETP-SXL Defendants filed a Motion to Dismiss the ETP Unitholder Plaintiffs’ claims. Rather than respond to the 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 any such lawsuits might be. Nor can the ETP-SXL Defendants predict the amount of time and expense that would be required to resolve such lawsuits. The ETP-SXL Defendants believe the Sunoco Logistics Merger Litigation was without merit and intend to defend vigorously against any future lawsuits challenging the Sunoco Logistics Merger. Litigation Filed By or Against Williams On April 6, 2016, Williams 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 Williams Litigation”). Williams 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 Williams Litigation. The counterclaim asserts in general that Williams materially breached its obligations under the assetMerger Agreement by (a) blocking ETE’s attempts to complete a public offering of the Convertible Units, including, among other things, by declining to allow Williams’ independent registered public accounting firm to provide the auditor consent required to be included in the registration statement for a public offering and liability method.(b) bringing a lawsuit concerning the Issuance against Mr. Warren in the District Court of Dallas County, Texas, which the Texas state court later dismissed based on the Merger Agreement’s forum-selection clause. UnderOn May 13, 2016, Williams 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 (collectively, “Defendants”). This lawsuit is styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., et al., C.A. No. 12337-VCG (the “Second Delaware Williams Litigation”). In general, Williams alleged that Defendants 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 concerning Section 721 of the Internal Revenue Code (“721 Opinion”), (b) breaching a representation and warranty in the Merger Agreement concerning Section 721 of the Internal Revenue Code, and (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. Williams 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.
ETE filed an answer and counterclaim in the Second Delaware Williams Litigation. In addition to the counterclaims previously asserted, ETE asserted that Williams materially breached the Merger Agreement by, among other things, (a) modifying or qualifying the Williams 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, (c) failing to facilitate the financing of the merger, (d) failing to use its reasonable best efforts to consummate the 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 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 Williams’ requests for injunctive relief. The 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, styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., No. 330, 2016. Williams filed an amended complaint on September 16, 2016 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 Defendants breached an additional representation and warranty in the Merger Agreement. Defendants filed amended counterclaims and affirmative defenses on September 23, 2016 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 Defendants’ amended counterclaims and to strike certain of Defendants’ affirmative defenses. Following briefing by the parties on Williams’ motion, the Delaware Court of Chancery held oral arguments on November 30, 2016. On March 23, 2017, the Delaware Supreme Court affirmed the Court of Chancery’s Opinion and Order on the June 2016 trial 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 method, deferred tax assetsfiling; nor can Defendants predict the amount of time and expense that will be required to resolve these lawsuits. Defendants believe that Williams’ claims are without merit and 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 (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. On August 29, 2016, the Issuance Plaintiffs filed a consolidated amended complaint, and in addition to the injunctive relief described above, seek class-wide damages allegedly resulting from the Issuance. 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 Issuance 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 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, 2017 and 2016, accruals of approximately $33 million and $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, 2017 or 2016 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein. 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 recognized 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 estimated future tax consequences attributablethree releases along with a demand for injunctive relief, and Louisiana Department of Environmental Quality proposed a state penalty of approximately $1 million to differences betweenresolve the financial statement carrying amountsCaddo 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 existingEnvironmental 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. 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 liabilitiesother formerly owned sites. Sunoco, Inc. is potentially subject to joint and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effectseveral liability for the yearcosts of remediation at sites at which it has been identified as a “potentially responsible party” (“PRP”). As of December 31, 2017, Sunoco, Inc. had been named as a PRP at approximately 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 which those temporary differencesthe 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 recoveredrecoverable through tariffs or settled. rates are recorded as regulatory assets on our consolidated balance sheets. 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 totable below reflects 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 areaccrued 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 only after determiningstatements.
| | | | | | | | | | December 31, | | 2017 | | 2016 | Current | $ | 35 |
| | $ | 26 |
| Non-current | 337 |
| | 318 |
| Total environmental liabilities | $ | 372 |
| | $ | 344 |
|
In 2013, we established a more-likely-than-not probabilitywholly-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 uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change,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 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 andaccrue losses offset related resultsattributable to unasserted claims based 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 derivativesdiscounted estimates that are used to develop the premiums paid to the captive insurance company.
During the years ended December 31, 2017 and 2016, the Partnership recorded $32 million and $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 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, ETP experienced a release on its products pipeline in Wellington, Ohio. In connection with this release, the PHMSA issued a Corrective Action Order under which ETP is obligated to follow specific requirements in the investigation of the release and the repair and reactivation of the pipeline. This 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. ETP has also received a “No Further Action” approval from the Ohio EPA for all soil and groundwater remediation requirements. In May 2016, ETP received a proposed penalty from the EPA and DOJ 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, ETP 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 April 2016, the PHMSA issued a NOPV, PCO and Proposed Civil Penalty related to certain procedures carried out during construction of ETP’s Permian Express 2 pipeline system in Texas. The proposed penalties are in excess of $100,000. The 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 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 our crude oil pipeline near Wortham, Texas. The proposed penalties are 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 August 2017, the PHMSA issued a NOPV and a PCO in connection with alleged violations on ETP’s Nederland to Kilgore pipeline in Texas. The case remains open with PHMSA and the proposed penalties are in excess of $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, Occupational Safety and Health Administration’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our hedging transactions are highly effective in offsetting changes in cash flows. If we determineoperations 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 derivativematerial adverse effect on our results of operations but there is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changesassurance 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 derivative in net incomeproceeds based on an index price for the period.residue gas and NGL. These contracts are not designated as hedges for accounting purposes. If we designateWe utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and 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 hedging relationship as a fair value hedge, we record the changesderivatives to take advantage of market opportunities in fair value of the hedged asset or liabilityour trading activities which complement our transportation and storage operations’ and are netted 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 isWe 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 operatinghave trading and marketing 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 remainpower and natural gas 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 recordedour all other operations which are also netted in cost of products sold in the consolidated statements of operations.
We managesold. As a portionresult 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,trading activities and the fair value is recordeduse of derivative financial instruments in other non-current liabilities on our consolidated balance sheets.
Pensionstransportation and Other Postretirement Benefit Plans
Employers are requiredstorage operations, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to recognize in their balance sheetsperiod. We attempt to manage this volatility through the overfunded or underfunded statususe of defined benefit pensiondaily position and other postretirement plans, measured as the difference between the fair valueprofit and loss reports provided to our risk oversight committee, which includes members of the plan assetssenior management, and the benefit obligation (the projected benefit obligation for pension planslimits 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 change in the funded status of the plan in the year in which the change occurs through AOCI in equity or are reflected as a regulatory asset or regulatory liability for regulated subsidiaries.
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. Federal income tax purposes and are not comparable to the partners’ capital balances reflected under GAAPauthorizations set forth 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: |
Pending Transactioncommodity risk management policy.
Regency Merger
In January 2015, ETP and Regency entered into a definitive merger agreement, as amended on February 18, 2015 (the “Merger Agreement”), pursuant to which Regency will merge with a wholly-owned subsidiary of ETP, with Regency continuing as the surviving entity and becoming a wholly-owned subsidiary of ETP (the “Regency Merger”). At the effective time of the Regency Merger (the “Effective Time”), each Regency common unit and Class F unit will be converted into the right to receive 0.4066 ETP Common Units, plus a number of additional ETP Common Units equal to $0.32 per Regency common unit divided by the lesser of (i) the volume weighted average price of ETP Common Units for the five trading days ending on the third trading day immediately preceding the Effective Time and (ii) the closing price of ETP Common Units on the third trading day immediately preceding the Effective Time, rounded to the nearest ten thousandth of a unit. Each Regency series A preferred unit will be converted into the right to receive a preferred unit representing a limited partner interest in ETP, a new class of units in ETP to be established at the Effective Time. The transaction is subject to other customary closing conditions including approval by Regency’s unitholders.
In addition, ETE, which owns the general partner and 100% of the incentive distribution rights of both Regency and ETP, has agreed to reduce the incentive distributions it receives from ETP by a total of $320 million over a five year period. The IDR subsidy will be $80 million in the first year post closing and $60 million per year for the following four years. The transaction is expected to close in the second quarter of 2015.
ETP and Regency are under common control of ETE; therefore, we expect to account for the Regency Merger at historical cost as a reorganization of entities under common control. Accordingly, ETP’s consolidated financial statements will be retrospectively adjusted to reflect consolidation of Regency beginning May 26, 2010 (the date ETE acquired Regency’s general partner).
2014 Transactions
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. Our consolidated balance sheet as of December 31, 2014 reflected the preliminary purchase price allocations based on available information. Management is reviewing the valuation and confirming the results to determine the final purchase price allocation.
The following table summarizes the preliminary assets acquired and liabilities assumed recognized as of the merger date:details our outstanding commodity-related derivatives: | | | | | | | | 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 is being 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.
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.
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), and ETP (2.2 million Common Units). In connection with the Panhandle Merger, Panhandle also assumed PEPL Holdings’ guarantee of $600 million of Regency senior notes.
2013 Transactions
Sale of Southern Union’s Distribution Operations
In December 2012, Southern Union entered into a purchase and sale agreement with The Laclede Group, Inc., pursuant to which Laclede Missouri agreed to acquire the assets of Southern Union’s MGE division and Laclede Massachusetts agreed to acquire the assets of Southern Union’s NEG division (together, the “LDC Disposal Group”). Laclede Gas Company, a subsidiary of The Laclede Group, Inc., subsequently assumed all of Laclede Missouri’s rights and obligations under the purchase and sale agreement. In February 2013, The Laclede Group, Inc. entered into an agreement with Algonquin Power & Utilities Corp (“APUC”) that allowed a subsidiary of APUC to assume the rights of The Laclede Group, Inc. to purchase the assets of Southern Union’s NEG division.
In September 2013, Southern Union completed its sale of the assets of MGE for an aggregate purchase price of $975 million, subject to customary post-closing adjustments. In December 2013, Southern Union completed its sale of the assets of NEG for cash proceeds of $40 million, subject to customary post-closing adjustments, and the assumption of $20 million of debt.
The LDC Disposal Group’s operations have been classified as discontinued operations for all periods in the consolidated statements of operations.
The following table summarizes selected financial information related to Southern Union’s distribution operations in 2013 through MGE and NEG’s sale dates in September 2013 and December 2013, respectively, and for the period from March 26, 2012 to December 31, 2012:
| | | | | | | | | | Years Ended December 31, | | 2013 | | 2012 | Revenue from discontinued operations | $ | 415 |
| | $ | 324 |
| Net income of discontinued operations, excluding effect of taxes and overhead allocations | 65 |
| | 43 |
|
SUGS Contribution
On April 30, 2013, Southern Union completed its contribution to Regency of all of the issued and outstanding membership interest in Southern Union Gathering Company, LLC, and its subsidiaries, including SUGS (the “SUGS Contribution”). The general partner and IDRs of Regency are owned by ETE. The consideration paid by Regency in connection with this transaction consisted of (i) the issuance of approximately 31.4 million Regency common units to Southern Union, (ii) the issuance of approximately 6.3 million Regency Class F units to Southern Union, (iii) the distribution of $463 million in cash to Southern Union, net of closing adjustments, and (iv) the payment of $30 million in cash to a subsidiary of ETP. This transaction was between commonly controlled entities; therefore, the amounts recorded in the consolidated balance sheet for the investment in Regency and the related deferred tax liabilities were based on the historical book value of SUGS. In addition, PEPL Holdings provided a guarantee of collection with respect to the payment of the principal amounts of Regency’s debt related to the SUGS Contribution. The Regency Class F units have the same rights, terms and conditions as the Regency common units, except that Southern Union will not receive distributions on the Regency Class F units for the first eight consecutive quarters following the closing, and the Regency Class F units will thereafter automatically convert into Regency common units on a one-for-one basis. The Partnership has not presented SUGS as discontinued operations due to the Partnership’s
continuing involvement with SUGS through affiliate relationships, as well as the direct investment in Regency common and Class F units received, which has been accounted for using the equity method.
Acquisition of ETE’s ETP Holdco Interest
On April 30, 2013, ETP acquired ETE’s 60% interest in ETP Holdco for approximately 49.5 million of newly issued ETP Common Units and $1.40 billion in cash, less $68 million of closing adjustments (the “ETP Holdco Acquisition”). As a result, ETP now owns 100% of ETP Holdco. ETE, which owns the general partner and IDRs of ETP, agreed to forego incentive distributions on the newly issued ETP units for each of the first eight consecutive quarters beginning with the quarter in which the closing of the transaction occurred and 50% of incentive distributions on the newly issued ETP units for the following eight consecutive quarters. ETP controlled ETP Holdco prior to this acquisition; therefore, the transaction did not constitute a change of control.
2012 Transactions
Southern Union Merger
On March 26, 2012, ETE completed its acquisition of Southern Union. Southern Union was the surviving entity in the merger and operated as a wholly-owned subsidiary of ETE. See below for discussion of ETP Holdco Transaction and ETE’s contribution of Southern Union to ETP Holdco.
Under the terms of the merger agreement, Southern Union stockholders received a total of 57 million ETE Common Units and a total of approximately $3.01 billion in cash. Effective with the closing of the transaction, Southern Union’s common stock was no longer publicly traded.
Citrus Acquisition
In connection with the Southern Union Merger on March 26, 2012, we completed our acquisition of CrossCountry, a subsidiary of Southern Union which owned an indirect 50% interest in Citrus, the owner of FGT. The total merger consideration was approximately $2.0 billion, consisting of approximately $1.9 billion in cash and approximately 2.2 million ETP Common Units. See Note 4 for more information regarding our equity method investment in Citrus.
Sunoco Merger
On October 5, 2012, ETP completed its merger with Sunoco, Inc. Under the terms of the merger agreement, Sunoco, Inc. shareholders received 55 million ETP Common Units and a total of approximately $2.6 billion in cash.
Sunoco, Inc. generates cash flow from a portfolio of retail outlets for the sale of gasoline and middle distillates in the east coast, midwest and southeast areas of the United States. Prior to October 5, 2012, Sunoco, Inc. also owned a 2% general partner interest, 100% of the IDRs, and 32% of the outstanding common units of Sunoco Logistics. As discussed below, on October 5, 2012, Sunoco, Inc.’s interests in Sunoco Logistics were transferred to the Partnership.
Prior to the Sunoco Merger, on September 8, 2012, Sunoco, Inc. completed the exit from its Northeast refining operations by contributing the refining assets at its Philadelphia refinery and various commercial contracts to PES, a joint venture with The Carlyle Group. Sunoco, Inc. also permanently idled the main refining processing units at its Marcus Hook refinery in June 2012. The Marcus Hook Industrial Complex continued to support operations at the Philadelphia refinery prior to commencement of the PES joint venture. Under the terms of the joint venture agreement, The Carlyle Group contributed cash in exchange for a 67% controlling interest in PES. In exchange for contributing its Philadelphia refinery assets and various commercial contracts to the joint venture, Sunoco, Inc. retained an approximate 33% non-operating noncontrolling interest. The fair value of Sunoco, Inc.’s retained interest in PES, which was $75 million on the date on which the joint venture was formed, was determined based on the equity contributions of The Carlyle Group. Sunoco, Inc. has indemnified PES for environmental liabilities related to the Philadelphia refinery that arose from the operation of such assets prior the formation of the joint venture. The Carlyle Group will oversee day-to-day operations of PES and the refinery. JPMorgan Chase provides working capital financing to PES in the form of an asset-backed loan, supply crude oil and other feedstocks to the refinery at the time of processing and purchase certain blendstocks and all finished refined products as they are processed. Sunoco, Inc. entered into a supply contract for gasoline and diesel produced at the refinery for its retail marketing business.
ETP incurred merger related costs related to the Sunoco Merger of $28 million during the year ended December 31, 2012. Sunoco, Inc.’s revenue included in our consolidated statement of operations was approximately $5.93 billion during October through December 2012. Sunoco, Inc.’s net loss included in our consolidated statement of operations was approximately $14 million during October through December 2012. Sunoco Logistics’ revenue included in our consolidated statement of
operations was approximately $3.11 billion during October through December 2012. Sunoco Logistics’ net income included in our consolidated statement of operations was approximately $145 million during October through December 2012.
ETP Holdco Transaction
Immediately following the closing of the Sunoco Merger in 2012, ETE contributed its interest in Southern Union into ETP Holdco, an ETP-controlled entity, in exchange for a 60% equity interest in ETP Holdco. In conjunction with ETE’s contribution, ETP contributed its interest in Sunoco, Inc. to ETP Holdco and retained a 40% equity interest in ETP Holdco. Prior to the contribution of Sunoco, Inc. to ETP Holdco, Sunoco, Inc. contributed $2.0 billion of cash and its interests in Sunoco Logistics to ETP in exchange for 90.7 million Class F Units representing limited partner interests in ETP (“Class F Units”). The Class F Units were exchanged for Class G Units in 2013 as discussed in Note 8. Pursuant to a stockholders agreement between ETE and ETP, ETP controlled ETP Holdco (prior to ETP’s acquisition of ETE’s 60% equity interest in ETP Holdco in 2013) and therefore, ETP consolidated ETP Holdco (including Sunoco, Inc. and Southern Union) in its financial statements subsequent to consummation of the ETP Holdco Transaction.
Under the terms of the ETP Holdco transaction agreement, ETE agreed to relinquish its right to $210 million of incentive distributions from ETP that ETE would otherwise be entitled to receive over 12 consecutive quarters beginning with the distribution paid on November 14, 2012.
In accordance with GAAP, we have accounted for the ETP Holdco Transaction, whereby ETP obtained control of Southern Union, as a reorganization of entities under common control. Accordingly, ETP’s consolidated financial statements have been retrospectively adjusted to reflect consolidation of Southern Union into ETP beginning March 26, 2012 (the date ETE acquired Southern Union). This change only impacted interim periods in 2012, and no prior annual amounts have been adjusted.
Summary of Assets Acquired and Liabilities Assumed
We accounted for the Sunoco 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. Upon consummation of the ETP Holdco Transaction, we applied the accounting guidance for transactions between entities under common control. In doing so, we recorded the values of assets and liabilities that had been recorded by ETE as reflected below.
The following table summarizes the assets acquired and liabilities assumed as of the respective acquisition dates:
| | | | | | | | | | Sunoco, Inc.(1) | | Southern Union(2) | Current assets | $ | 7,312 |
| | $ | 556 |
| Property, plant and equipment | 6,686 |
| | 6,242 |
| Goodwill | 2,641 |
| | 2,497 |
| Intangible assets | 1,361 |
| | 55 |
| Investments in unconsolidated affiliates | 240 |
| | 2,023 |
| Note receivable | 821 |
| | — |
| Other assets | 128 |
| | 163 |
| | 19,189 |
| | 11,536 |
| | | | | Current liabilities | 4,424 |
| | 1,348 |
| Long-term debt obligations, less current maturities | 2,879 |
| | 3,120 |
| Deferred income taxes | 1,762 |
| | 1,419 |
| Other non-current liabilities | 769 |
| | 284 |
| Noncontrolling interest | 3,580 |
| | — |
| | 13,414 |
| | 6,171 |
| Total consideration | 5,775 |
| | 5,365 |
| Cash received | 2,714 |
| | 37 |
| Total consideration, net of cash received | $ | 3,061 |
| | $ | 5,328 |
|
| | | | | | | | | | | | December 31, 2017 | | December 31, 2016 | | Notional Volume | | Maturity | | Notional Volume | | Maturity | Mark-to-Market Derivatives | | | | | | | | (Trading) | | | | | | | | Natural Gas (BBtu): | | | | | | | | Fixed Swaps/Futures | 1,078 |
| | 2018 | | (683 | ) | | 2017 | Basis Swaps IFERC/NYMEX (1) | 48,510 |
| | 2018-2020 | | 2,243 |
| | 2017 | Options – Puts | 13,000 |
| | 2018 | | — |
| | — | Power (Megawatt): | | | | | | | | Forwards | 435,960 |
| | 2018-2019 | | 391,880 |
| | 2017 - 2018 | Futures | (25,760 | ) | | 2018 | | 109,564 |
| | 2017 - 2018 | Options — Puts | (153,600 | ) | | 2018 | | (50,400 | ) | | 2017 | Options — Calls | 137,600 |
| | 2018 | | 186,400 |
| | 2017 | Crude (MBbls) – Futures | — |
| | — | | (617 | ) | | 2017 | (Non-Trading) | | | | | | | | Natural Gas (BBtu): | | | | | | | | Basis Swaps IFERC/NYMEX | 4,650 |
| | 2018-2020 | | 10,750 |
| | 2017 - 2018 | Swing Swaps IFERC | 87,253 |
| | 2018-2019 | | (5,663 | ) | | 2017 | Fixed Swaps/Futures | (4,390 | ) | | 2018-2019 | | (52,653 | ) | | 2017 - 2019 | Forward Physical Contracts | (145,105 | ) | | 2018-2020 | | (22,492 | ) | | 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 | 1,870,000 |
| | 2018 | | 1,580,000 |
| | 2017 | Fair Value Hedging Derivatives | | | | | | | | (Non-Trading) | | | | | | | | Natural Gas (BBtu): | | | | | | | | Basis Swaps IFERC/NYMEX | (39,770 | ) | | 2018 | | (36,370 | ) | | 2017 | Fixed Swaps/Futures | (39,770 | ) | | 2018 | | (36,370 | ) | | 2017 | Hedged Item — Inventory | 39,770 |
| | 2018 | | 36,370 |
| | 2017 |
| | (1) | Includes aggregate amounts recorded with respectfor open positions related to Sunoco Logistics. |
| | (2)
| Includes ETP’s acquisition of Citrus.Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations. |
The fair valuesInterest 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 assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches. Asrate on a result of the ETP Holdco Transaction, we recognized $38 million of merger-related costs during the year ended December 31, 2012 related to Southern Union. Southern Union’s revenue included in our consolidated statement of operations was approximately $1.26 billion since the acquisition date to December 31, 2012. Southern Union’s net income included in our consolidated statement of operations was approximately $39 million since the acquisition date to December 31, 2012.
Propane Operations
On January 12, 2012, we contributed our propane operations, consisting of HOLP and Titan (collectively, the “Propane Business”) to AmeriGas. We received approximately $1.46 billion in cash and approximately 29.6 million AmeriGas common units. AmeriGas assumed approximately $71 million of existing HOLP debt. In connection with the closing of this transaction, we entered into a support agreement with AmeriGas pursuant to which we are obligated to provide contingent, residual support of $1.50 billion of intercompany indebtedness owed by AmeriGas to a finance subsidiary that in turn supports the repayment of $1.50 billion of senior notes issued by this AmeriGas finance subsidiary to finance the cash portion of the purchase price.our anticipated debt issuances.
Our consolidated financial statements did not reflect the Propane Business as discontinued operations due to our continuing involvement in this business through our investment in AmeriGas that was transferred as consideration for the transaction.
In June 2012, we sold the remainder of our retail propane operations, consisting of our cylinder exchange business, to a third party. In connection with the contribution agreement with AmeriGas, certain excess sales proceeds from the sale of the cylinder exchange business were remitted to AmeriGas, and we received net proceeds of approximately $43 million.
Sale of Canyon
In October 2012, we sold Canyon for approximately $207 million. The results of continuing operations of Canyon have been reclassified to loss from discontinued operations and the prior year amounts have been restated to present Canyon’s operations as discontinued operations. A write down of the carrying amounts of the Canyon assets to their fair values was recorded for approximately $132 million during the year ended December 31, 2012. Canyon was previously included in our midstream segment.
Pro Forma Results of Operations
The following unaudited pro forma consolidated resultstable summarizes our interest rate swaps outstanding, none of operationswhich are designated as hedges for the year ended December 31, 2012 are presented as if the Sunoco Merger and the ETP Holdco Transaction had been completed on January 1, 2012:accounting purposes: | | | | | | | | Year Ended December 31, 2012 | Revenues | | $ | 39,136 |
| Net income | | 1,133 |
| Net income attributable to partners | | 788 |
| Basic net income per Limited Partner unit | | $ | 1.33 |
| Diluted net income per Limited Partner unit | | $ | 1.33 |
|
The pro forma consolidated results of operations include adjustments to:
include the results of Southern Union and Sunoco, Inc. beginning January 1, 2012;
include the incremental expenses associated with the fair value adjustments recorded as a result of applying the acquisition method of accounting;
include incremental interest expense related to the financing of ETP’s proportionate share of the purchase price; and
reflect noncontrolling interest related to ETE’s 60% interest in ETP Holdco during the periods.
The pro forma information is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations.
| | 4. | ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES: |
Regency
On April 30, 2013, Southern Union completed its contribution to Regency of all of the issued and outstanding membership interest in Southern Union Gathering Company, LLC, and its subsidiaries, including SUGS (see Note 3). The consideration paid by Regency in connection with this transaction included approximately 31.4 million Regency common units, approximately 6.3 million Regency Class F units, the distribution of $463 million in cash to Southern Union, net of closing adjustments, and the payment of $30 million in cash to a subsidiary of ETP. This direct investment in Regency common and Class F units received has been accounted for using the equity method.
The carrying amount of our investment in Regency was $1.34 billion and $1.41 billion as of December 31, 2014 and 2013, respectively, and was reflected in our all other segment.
Citrus
On March 26, 2012, ETE consummated the acquisition of Southern Union and, concurrently with the closing of the Southern Union acquisition, CrossCountry, a subsidiary of Southern Union that indirectly owned a 50% interest in Citrus, merged with a subsidiary of ETP and, in connection therewith, ETP paid approximately $1.9 billion in cash and issued $105 million of ETP Common Units (the “Citrus Acquisition”) to a subsidiary of ETE. As a result of the consummation of the Citrus Acquisition, ETP owns CrossCountry, which in turn owns a 50% interest in Citrus. The other 50% interest in Citrus is owned by a subsidiary of Kinder Morgan, Inc. Citrus owns 100% of FGT, a natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula.
We recorded our investment in Citrus at $2.0 billion, which exceeded our proportionate share of Citrus’ equity by $1.03 billion, all of which is treated as equity method goodwill due to the application of regulatory accounting. The carrying amount of our investment in Citrus was $1.82 billion and $1.89 billion as of December 31, 2014 and 2013, respectively, and was reflected in our interstate transportation and storage segment.
AmeriGas
As discussed in Note 3, on January 12, 2012, we received approximately 29.6 million AmeriGas common units in connection with the contribution of our propane operations. In the year ended 2013, we sold 7.5 million AmeriGas common units for net proceeds of $346 million, and in the year ended 2014 we sold approximately 18.9 million AmeriGas common units for net proceeds of $814 million. Net proceeds from these sales were used to repay borrowings under the ETP Credit Facility and general partnership purposes. Subsequent to the sales, the Partnership’s remaining interest in AmeriGas common units consisted of 3.1 million units held by a wholly-owned captive insurance company.
FEP
We have a 50% interest in FEP, a 50/50 joint venture with KMP. FEP owns the Fayetteville Express pipeline, 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. The carrying amount of our investment in FEP was $130 million and $144 million as of December 31, 2014 and 2013, respectively, and was reflected in our interstate transportation and storage segment.
Summarized Financial Information
The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, FEP, AmeriGas, Citrus and Regency (on a 100% basis) for all periods presented:
| | | | | | | | | | December 31, | | 2014 | | 2013 | Current assets | $ | 1,514 |
| | $ | 1,372 |
| Property, plant and equipment, net | 16,967 |
| | 12,320 |
| Other assets | 9,708 |
| | 6,478 |
| Total assets | $ | 28,189 |
| | $ | 20,170 |
| | | | | Current liabilities | $ | 2,324 |
| | $ | 1,455 |
| Non-current liabilities | 13,206 |
| | 10,286 |
| Equity | 12,659 |
| | 8,429 |
| Total liabilities and equity | $ | 28,189 |
| | $ | 20,170 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2014 | | 2013 | | 2012 | Revenue | $ | 9,467 |
| | $ | 6,806 |
| | $ | 4,057 |
| Operating income | 841 |
| | 1,043 |
| | 635 |
| Net income | 279 |
| | 574 |
| | 338 |
|
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 PER LIMITED PARTNER UNIT: |
A reconciliation of income from continuing operations and weighted average units used in computing basic and diluted income from continuing operations per unit is as follows:
| | | | | | | | | | | | | | Years Ended December 31, | | 2014 | | 2013 | | 2012 | Income from continuing operations | $ | 1,489 |
| | $ | 735 |
| | $ | 1,757 |
| Less: Income from continuing operations attributable to noncontrolling interest | 217 |
| | 296 |
| | 62 |
| Income from continuing operations, net of noncontrolling interest | 1,272 |
| | 439 |
| | 1,695 |
| General Partner’s interest in income from continuing operations | 513 |
| | 505 |
| | 463 |
| Class H Unitholder’s interest in income from continuing operations | 217 |
| | — |
| | — |
| Common Unitholders’ interest in income (loss) from continuing operations | 542 |
| | (66 | ) | | 1,232 |
| Additional earnings allocated (to) from General Partner | (4 | ) | | (2 | ) | | 1 |
| Distributions on employee unit awards, net of allocation to General Partner | (13 | ) | | (10 | ) | | (9 | ) | Income (loss) from continuing operations available to Common Unitholders | $ | 525 |
| | $ | (78 | ) | | $ | 1,224 |
| Weighted average Common Units – basic | 331.5 |
| | 343.4 |
| | 248.3 |
| Basic income (loss) from continuing operations per Common Unit | $ | 1.58 |
| | $ | (0.23 | ) | | $ | 4.93 |
| Dilutive effect of unvested Unit Awards | 1.3 |
| | — |
| | 0.7 |
| Weighted average Common Units, assuming dilutive effect of unvested Unit Awards | 332.8 |
| | 343.4 |
| | 249.0 |
| Diluted income (loss) from continuing operations per Common Unit | $ | 1.58 |
| | $ | (0.23 | ) | | $ | 4.91 |
| Basic income (loss) from discontinued operations per Common Unit | $ | 0.19 |
| | $ | 0.05 |
| | $ | (0.50 | ) | Diluted income (loss) from discontinued operations per Common Unit | $ | 0.19 |
| | $ | 0.05 |
| | $ | (0.50 | ) |
Our debt obligations consist of the following:
| | | | | | | | | | December 31, | | 2014 | | 2013 | ETP Debt | | | | 8.5% Senior Notes due April 15, 2014 | $ | — |
| | $ | 292 |
| 5.95% Senior Notes due February 1, 2015 | 750 |
| | 750 |
| 6.125% Senior Notes due February 15, 2017 | 400 |
| | 400 |
| 6.7% Senior Notes due July 1, 2018 | 600 |
| | 600 |
| 9.7% Senior Notes due March 15, 2019 | 400 |
| | 400 |
| 9.0% Senior Notes due April 15, 2019 | 450 |
| | 450 |
| 4.15% Senior Notes due October 1, 2020 | 700 |
| | 700 |
| 4.65% Senior Notes due June 1, 2021 | 800 |
| | 800 |
| 5.20% Senior Notes due February 1, 2022 | 1,000 |
| | 1,000 |
| 3.60% Senior Notes due February 1, 2023 | 800 |
| | 800 |
| 4.9% Senior Notes due February 1, 2024 | 350 |
| | 350 |
| 7.6% Senior Notes due February 1, 2024 | 277 |
| | 277 |
| 8.25% Senior Notes due November 15, 2029 | 267 |
| | 267 |
| 6.625% Senior Notes due October 15, 2036 | 400 |
| | 400 |
| 7.5% Senior Notes due July 1, 2038 | 550 |
| | 550 |
|
| | | | | | | | | 6.05% Senior Notes due June 1, 2041 | 700 |
| | 700 |
| 6.50% Senior Notes due February 1, 2042 | 1,000 |
| | 1,000 |
| 5.15% Senior Notes due February 1, 2043 | 450 |
| | 450 |
| 5.95% Senior Notes due October 1, 2043 | 450 |
| | 450 |
| Floating Rate Junior Subordinated Notes due November 1, 2066 | 546 |
| | 546 |
| ETP $2.5 billion Revolving Credit Facility due October 27, 2019 | 570 |
| | 65 |
| Unamortized premiums, discounts and fair value adjustments, net | (1 | ) | | (34 | ) | | 11,459 |
| | 11,213 |
| | | | | Transwestern Debt | | | | 5.39% Senior Notes due November 17, 2014 | — |
| | 88 |
| 5.54% Senior Notes due November 17, 2016 | 125 |
| | 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 |
| 6.16% Senior Notes due May 24, 2037 | 75 |
| | 75 |
| Unamortized premiums, discounts and fair value adjustments, net | (1 | ) | | (1 | ) | | 781 |
| | 869 |
| | | | | Panhandle Debt(1) | | | | 6.20% Senior Notes due November 1, 2017 | 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 14, 2029 | 33 |
| | 33 |
| Floating Rate Junior Subordinated Notes due November 1, 2066 | 54 |
| | 54 |
| Unamortized premiums, discounts and fair value adjustments, net | 99 |
| | 155 |
| | 1,184 |
| | 1,240 |
| | | | | Sunoco, Inc. Debt | | | | 4.875% Senior Notes due October 15, 2014 | — |
| | 250 |
| 9.625% Senior Notes due April 15, 2015 | 250 |
| | 250 |
| 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 | 35 |
| | 70 |
| | 750 |
| | 1,035 |
| | | | | Sunoco Logistics Debt | | | | 8.75% Senior Notes due February 15, 2014(2) | — |
| | 175 |
| 6.125% Senior Notes due May 15, 2016 | 175 |
| | 175 |
| 5.50% Senior Notes due February 15, 2020 | 250 |
| | 250 |
| 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 |
| | — |
| 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 |
| | — |
|
| | | | | | | | | 5.35% Senior Notes due May 15, 2045 | 800 |
| | — |
| Sunoco Logistics $35 million Revolving Credit Facility due April 30, 2015(3) | 35 |
| | 35 |
| Sunoco Logistics $1.50 billion Revolving Credit Facility due November 19, 2018 | 150 |
| | 200 |
| Unamortized premiums, discounts and fair value adjustments, net | 100 |
| | 118 |
| | 4,260 |
| | 2,503 |
| | | | | Sunoco LP Debt | | | | Sunoco LP $1.25 billion Revolving Credit Facility due September 25, 2019 | 683 |
| | — |
| | 683 |
| | — |
| | | | | Other | 223 |
| | 228 |
| | 19,340 |
| | 17,088 |
| Less: current maturities | 1,008 |
| | 637 |
| | $ | 18,332 |
| | $ | 16,451 |
|
| | | | | | | | | | | | | | | | | | | | Notional Amount Outstanding | Entity | | Term | | Type(1) | | December 31, 2017 | | December 31, 2016 | ETP | | July 2017(2) | | Forward-starting to pay a fixed rate of 3.90% and receive a floating rate | | $ | — |
| | $ | 500 |
| ETP | | July 2018(2) | | Forward-starting to pay a fixed rate of 3.76% and receive a floating rate | | 300 |
| | 200 |
| ETP | | July 2019(2) | | Forward-starting to pay a fixed rate of 3.64% and receive a floating rate | | 300 |
| | 200 |
| ETP | | 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 |
| ETP | | March 2019 | | Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% | | 300 |
| | 300 |
|
| | (1) | In connection with the Panhandle Merger, Southern Union’s debt obligations were assumed by Panhandle.Floating rates are based on 3-month LIBOR. |
| | (2) | Sunoco Logistics’ 8.75% senior notes due February 15, 2014 were classifiedRepresents the effective date. These forward-starting swaps have a term of 30 years with a mandatory termination date the same as long-term debt as Sunoco Logistics repaid these notes in February 2014 with borrowings under its $1.50 billion credit facility due November 2018.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 | | Asset Derivatives | | Liability Derivatives | | December 31, 2017 | | December 31, 2016 | | December 31, 2017 | | December 31, 2016 | Derivatives designated as hedging instruments: | | | | | | | | Commodity derivatives (margin deposits) | $ | 14 |
| | $ | — |
| | $ | (2 | ) | | $ | (4 | ) | | 14 |
| | — |
| | (2 | ) | | (4 | ) | Derivatives not designated as hedging instruments: | | | | | | | | Commodity derivatives (margin deposits) | 262 |
| | 338 |
| | (281 | ) | | (416 | ) | Commodity derivatives | 45 |
| | 25 |
| | (58 | ) | | (58 | ) | Interest rate derivatives | — |
| | — |
| | (219 | ) | | (193 | ) | Embedded derivatives in ETP Convertible Preferred Units | — |
| | — |
| | — |
| | (1 | ) | | 307 |
| | 363 |
| | (558 | ) | | (668 | ) | Total derivatives | $ | 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 | | | Balance Sheet Location | | December 31, 2017 | | December 31, 2016 | | December 31, 2017 | | December 31, 2016 | Derivatives without offsetting agreements | | Derivative assets (liabilities) | | $ | — |
| | $ | — |
| | $ | (219 | ) | | $ | (194 | ) | Derivatives in offsetting agreements: | | | | | | | | | OTC contracts | | Derivative assets (liabilities) | | 45 |
| | 25 |
| | (58 | ) | | (58 | ) | Broker cleared derivative contracts | | Other current assets (liabilities) | | 276 |
| | 338 |
| | (283 | ) | | (420 | ) | | | 321 |
| | 363 |
| | (560 | ) | | (672 | ) | Offsetting agreements: | | | | | | | | | Counterparty netting | | Derivative assets (liabilities) | | (21 | ) | | (4 | ) | | 21 |
| | 4 |
| Counterparty netting | | Other current assets (liabilities) | | (263 | ) | | (338 | ) | | 263 |
| | 338 |
| 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) 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, | | 2017 | | 2016 | | 2015 | Derivatives in fair value hedging relationships (including hedged item): | | | | | | | | Commodity derivatives | Cost of products sold | | $ | 26 |
| | $ | 14 |
| | $ | 21 |
| Total | | | $ | 26 |
| | $ | 14 |
| | $ | 21 |
|
| | | | | | | | | | | | | | | | 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 | | 5 |
| | (177 | ) | | 15 |
| Interest rate derivatives | Losses on interest rate derivatives | | (37 | ) | | (12 | ) | | (18 | ) | Embedded derivatives | Other, net | | 1 |
| | 4 |
| | 12 |
| Total | | | $ | — |
| | $ | (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 and $40 million to the 401(k) savings plan for the years ended December 31, 2017, 2016, and 2015, 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, 2017 | | December 31, 2016 | | Pension Benefits | | | | Pension 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 | $ | 18 |
| | $ | 51 |
| | $ | 166 |
| | $ | 20 |
| | $ | 57 |
| | $ | 181 |
| Interest cost | 1 |
| | 1 |
| | 4 |
| | 1 |
| | 2 |
| | 4 |
| Amendments | — |
| | — |
| | 7 |
| | — |
| | — |
| | — |
| Benefits paid, net | (2 | ) | | (6 | ) | | (20 | ) | | (1 | ) | | (7 | ) | | (21 | ) | Actuarial (gain) loss and other | 2 |
| | 1 |
| | (1 | ) | | (2 | ) | | (1 | ) | | 2 |
| Settlements | (18 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| Benefit obligation at end of period | $ | 1 |
| | $ | 47 |
| | $ | 156 |
| | $ | 18 |
| | $ | 51 |
| | $ | 166 |
| | | | | | | | | | | | | Change in plan assets: | | | | | | | | | | | | Fair value of plan assets at beginning of period | $ | 12 |
| | $ | — |
| | $ | 256 |
| | $ | 15 |
| | $ | — |
| | $ | 261 |
| Return on plan assets and other | 3 |
| | — |
| | 11 |
| | (2 | ) | | — |
| | 6 |
| Employer contributions | 6 |
| | — |
| | 10 |
| | — |
| | — |
| | 10 |
| Benefits paid, net | (2 | ) | | — |
| | (20 | ) | | (1 | ) | | — |
| | (21 | ) | Settlements | (18 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| Fair value of plan assets at end of period | $ | 1 |
| | $ | — |
| | $ | 257 |
| | $ | 12 |
| | $ | — |
| | $ | 256 |
| | | | | | | | | | | | | Amount underfunded (overfunded) at end of period | $ | — |
| | $ | 47 |
| | $ | (101 | ) | | $ | 6 |
| | $ | 51 |
| | $ | (90 | ) | | | | | | | | | | | | | Amounts recognized in the consolidated balance sheets consist of: | | | | | | | | | | | | Non-current assets | $ | — |
| | $ | — |
| | $ | 127 |
| | $ | — |
| | $ | — |
| | $ | 114 |
| Current liabilities | — |
| | (8 | ) | | (2 | ) | | — |
| | (7 | ) | | (2 | ) | Non-current liabilities | — |
| | (39 | ) | | (24 | ) | | (6 | ) | | (44 | ) | | (23 | ) | | $ | — |
| | $ | (47 | ) | | $ | 101 |
| | $ | (6 | ) | | $ | (51 | ) | | $ | 89 |
| | | | | | | | | | | | | Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of: | | | | | | | | | | | | Net actuarial gain | $ | — |
| | $ | 5 |
| | $ | (18 | ) | | $ | — |
| | $ | — |
| | $ | (13 | ) | Prior service cost | — |
| | — |
| | 21 |
| | — |
| | — |
| | 15 |
| | $ | — |
| | $ | 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, 2017 | | December 31, 2016 | | Pension Benefits | | | | Pension Benefits | | | | Funded Plans | | Unfunded Plans | | Other Postretirement Benefits | | Funded Plans | | Unfunded Plans | | Other Postretirement Benefits | Projected benefit obligation | $ | 1 |
| | $ | 47 |
| | N/A |
| | $ | 18 |
| | $ | 51 |
| | N/A |
| Accumulated benefit obligation | 1 |
| | 47 |
| | $ | 156 |
| | 18 |
| | 51 |
| | $ | 166 |
| Fair value of plan assets | 1 |
| | — |
| | 257 |
| | 12 |
| | — |
| | 256 |
|
Components of Net Periodic Benefit Cost | | | | | | | | | | | | | | | | | | December 31, 2017 | | December 31, 2016 | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Net Periodic Benefit Cost: | | | | | | | | Interest cost | $ | 2 |
| | $ | 4 |
| | $ | 3 |
| | $ | 4 |
| Expected return on plan assets | — |
| | (9 | ) | | (1 | ) | | (8 | ) | Prior service cost amortization | — |
| | 2 |
| | — |
| | 1 |
| Net periodic benefit cost | $ | 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, 2017 | | December 31, 2016 | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Discount rate | 3.27 | % | | 2.34 | % | | 3.65 | % | | 2.34 | % | Rate of compensation increase | 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, 2017 | | December 31, 2016 | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Discount rate | 3.52 | % | | 3.10 | % | | 3.60 | % | | 3.06 | % | Expected return on assets: | | | | | | | | Tax exempt accounts | 3.50 | % | | 7.00 | % | | 3.50 | % | | 7.00 | % | Taxable accounts | N/A |
| | 4.50 | % | | N/A |
| | 4.50 | % | Rate of compensation increase | 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, | | 2017 | | 2016 | Health care cost trend rate | 7.20 | % | | 6.73 | % | Rate to which the cost trend is assumed to decline (the ultimate trend rate) | 4.99 | % | | 4.96 | % | Year that the rate reaches the ultimate trend rate | 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%. 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 |
| | $ | — |
| | $ | — |
|
| | (3)(1)
| Comprised of 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) | The Sunoco Logistics $35 million credit facility outstanding amounts were classifiedComprised of 100% equities as long-term debtof December 31, 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, 2017 | | | Fair Value Total | | Level 1 | | Level 2 | | Level 3 | Asset Category: | | | | | | | | | Cash and Cash Equivalents | | $ | 33 |
| | $ | 33 |
| | $ | — |
| | $ | — |
| Mutual funds (1) | | 154 |
| | 154 |
| | — |
| | — |
| Fixed income securities | | 70 |
| | — |
| | 70 |
| | — |
| Total | | $ | 257 |
| | $ | 187 |
| | $ | 70 |
| | $ | — |
|
| | (1) | Primarily comprised of approximately 38% equities, 61% fixed income securities and 2% cash as Sunoco Logistics has the abilityof 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) | | 142 |
| | 142 |
| | — |
| | — |
| Fixed income securities | | 91 |
| | — |
| | 91 |
| | — |
| Total | | $ | 256 |
| | $ | 165 |
| | $ | 91 |
| | $ | — |
|
| | (1) | Primarily comprised of approximately 31% equities, 66% fixed income securities and intent to refinance such borrowings on a long-term basis.3% cash as of December 31, 2016. |
The following table reflectsLevel 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 $8 million to pension plans and $10 million to other postretirement plans in 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 maturities of long-term debt forservice, as appropriate, in each of the next five years and thereafter. These amounts exclude $232 million in unamortized net premiums and fair value adjustments:the aggregate for the five years thereafter are shown in the table below: | | | | | | 2015 | | $ | 1,050 |
| 2016 | | 314 |
| 2017 | | 1,228 |
| 2018 | | 1,155 |
| 2019 | | 2,259 |
| Thereafter | | 13,102 |
| Total | | $ | 19,108 |
|
| | | | | | | | | | Years | | Pension Benefits - Unfunded Plans (1) | | Other Postretirement Benefits (Gross, Before Medicare Part D) | 2018 | | $ | 8 |
| | $ | 24 |
| 2019 | | 6 |
| | 23 |
| 2020 | | 6 |
| | 21 |
| 2021 | | 5 |
| | 19 |
| 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, ETP 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 previously paid ETP to provide services on its behalf and on behalf of other subsidiaries of ETE, which included the reimbursement of various operating and general and administrative expenses incurred by ETP on behalf of ETE and its subsidiaries. These agreements expired in 2016. In addition, subsidiaries of ETE recorded sales with affiliates of $303 million, $221 million and $290 million during the years ended December 31, 2017, 2016 and 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 as Co-Obligorcompleted 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 Inc. DebtLP 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: 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, | | 2017 | | 2016 | | 2015 | Equity in earnings of unconsolidated affiliates: | | | | | | Investment in ETP | $ | 156 |
| | $ | 59 |
| | $ | 469 |
| Adjustments and Eliminations | (12 | ) | | 211 |
| | (193 | ) | Total equity in earnings of unconsolidated affiliates | $ | 144 |
| | $ | 270 |
| | $ | 276 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | Segment Adjusted EBITDA: | | | | | | Investment in ETP | $ | 6,712 |
| | $ | 5,733 |
| | $ | 5,517 |
| Investment in Sunoco LP | 732 |
| | 665 |
| | 719 |
| Investment in Lake Charles LNG | 175 |
| | 179 |
| | 196 |
| Corporate and Other | (31 | ) | | (170 | ) | | (104 | ) | Adjustments and Eliminations | (268 | ) | | (272 | ) | | (590 | ) | Total Segment Adjusted EBITDA | 7,320 |
| | 6,135 |
| | 5,738 |
| Depreciation, depletion and amortization | (2,554 | ) | | (2,216 | ) | | (1,951 | ) | Interest expense, net of interest capitalized | (1,922 | ) | | (1,804 | ) | | (1,622 | ) | Gains on acquisitions | — |
| | 83 |
| | — |
| Impairment of investments in unconsolidated affiliates | (313 | ) | | (308 | ) | | — |
| Impairment losses | (1,039 | ) | | (1,040 | ) | | (339 | ) | Losses on interest rate derivatives | (37 | ) | | (12 | ) | | (18 | ) | Non-cash unit-based compensation expense | (99 | ) | | (70 | ) | | (91 | ) | Unrealized gains (losses) on commodity risk management activities | 59 |
| | (136 | ) | | (65 | ) | Losses on extinguishments of debt | (89 | ) | | — |
| | (43 | ) | Inventory valuation adjustments | 24 |
| | 97 |
| | (67 | ) | Adjusted EBITDA related to discontinued operations | (223 | ) | | (199 | ) | | (228 | ) | Adjusted EBITDA related to unconsolidated affiliates | (716 | ) | | (675 | ) | | (713 | ) | Equity in earnings of unconsolidated affiliates | 144 |
| | 270 |
| | 276 |
| Other, net | 155 |
| | 79 |
| | 23 |
| 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, | | 2017 | | 2016 | | 2015 | Total assets: | | | | | | Investment in ETP | $ | 77,965 |
| | $ | 70,105 |
| | $ | 65,128 |
| Investment in Sunoco LP | 8,344 |
| | 8,701 |
| | 8,842 |
| Investment in Lake Charles LNG | 1,646 |
| | 1,508 |
| | 1,369 |
| Corporate and Other | 598 |
| | 711 |
| | 638 |
| Adjustments and Eliminations | (2,307 | ) | | (2,100 | ) | | (4,833 | ) | Total | $ | 86,246 |
| | $ | 78,925 |
| | $ | 71,144 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | 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 | $ | 5,901 |
| | $ | 5,810 |
| | $ | 8,167 |
| Investment in Sunoco LP | 103 |
| | 119 |
| | 178 |
| Investment in Lake Charles LNG | 2 |
| | — |
| | 1 |
| Adjustments and Eliminations | — |
| | — |
| | (123 | ) | Total | $ | 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, | | 2017 | | 2016 | | 2015 | Intrastate Transportation and Storage | $ | 2,891 |
| | $ | 2,155 |
| | $ | 1,912 |
| Interstate Transportation and Storage | 915 |
| | 946 |
| | 1,008 |
| Midstream | 2,510 |
| | 2,342 |
| | 2,607 |
| 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 | 2,740 |
| | 2,872 |
| | 15,216 |
| Total revenues | 29,054 |
| | 21,827 |
| | 34,292 |
| Less: Intersegment revenues | 441 |
| | 209 |
| | 136 |
| Revenues from external customers | $ | 28,613 |
| | $ | 21,618 |
| | $ | 34,156 |
|
Investment in Sunoco LP | | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | Retail operations | $ | 2,263 |
| | $ | 1,991 |
| | $ | 2,226 |
| Wholesale operations | 9,460 |
| | 7,995 |
| | 10,204 |
| Total revenues | 11,723 |
| | 9,986 |
| | 12,430 |
| Less: Intersegment revenues | 10 |
| | 9 |
| | 11 |
| Revenues from external customers | $ | 11,713 |
| | $ | 9,977 |
| | $ | 12,419 |
|
Investment in Lake Charles LNG Lake Charles LNG’s revenues of $197 million, $197 million and $216 million for the years ended December 31, 2017, 2016 and 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 | | | | March 31* | | June 30* | | September 30* | | December 31 | | Total Year | 2017: | | | | | | | | | | Revenues | $ | 9,660 |
| | $ | 9,427 |
| | $ | 9,984 |
| | $ | 11,452 |
| | $ | 40,523 |
| Operating income (loss) | 758 |
| | 746 |
| | 924 |
| | 285 |
| | 2,713 |
| Net income (loss) | 319 |
| | 121 |
| | 758 |
| | 1,168 |
| | 2,366 |
| Limited Partners’ interest in net income | 232 |
| | 204 |
| | 240 |
| | 239 |
| | 915 |
| Basic net income per limited partner unit | $ | 0.22 |
| | $ | 0.18 |
| | $ | 0.22 |
| | $ | 0.22 |
| | $ | 0.85 |
| Diluted net income per limited partner unit | $ | 0.21 |
| | $ | 0.18 |
| | $ | 0.22 |
| | $ | 0.22 |
| | $ | 0.83 |
|
| | | | | | | | | | | | | | | | | | | | | | Quarters Ended | | | | March 31* | | June 30* | | September 30* | | December 31* | | Total Year* | 2016: | | | | | | | | | | Revenues | $ | 6,447 |
| | $ | 7,866 |
| | $ | 8,156 |
| | $ | 9,323 |
| | $ | 31,792 |
| Operating income | 680 |
| | 814 |
| | 624 |
| | (275 | ) | | 1,843 |
| Net income (loss) | 320 |
| | 417 |
| | (3 | ) | | (734 | ) | | — |
| Limited Partners’ interest in net income | 311 |
| | 239 |
| | 207 |
| | 226 |
| | 983 |
| Basic net income per limited partner unit | $ | 0.30 |
| | $ | 0.23 |
| | $ | 0.20 |
| | $ | 0.22 |
| | $ | 0.94 |
| Diluted net income per limited partner unit | $ | 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, 2017 and 2016 reflected the recognition of impairment losses of $1.04 billion and $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 ETP’s interstate transportation and storage operations and midstream operations as well as Sunoco LP’s retail operations. The three months ended December 31, 2017 and December 31, 2016 reflected the recognition of a non-cash impairment of ETP’s investments in subsidiaries of $313 million and $308 million, respectively, in its 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, | | 2017 | | 2016 | ASSETS | | | | CURRENT ASSETS: | | | | Cash and cash equivalents | $ | 1 |
| | $ | 2 |
| Accounts receivable from related companies | 65 |
| | 55 |
| Other current assets | 1 |
| | — |
| Total current assets | 67 |
| | 57 |
| PROPERTY, PLANT AND EQUIPMENT, net | 27 |
| | 36 |
| ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES | 6,082 |
| | 5,088 |
| INTANGIBLE ASSETS, net | — |
| | 1 |
| GOODWILL | 9 |
| | 9 |
| OTHER NON-CURRENT ASSETS, net | 8 |
| | 10 |
| Total assets | $ | 6,193 |
| | $ | 5,201 |
| LIABILITIES AND PARTNERS’ CAPITAL | | | | CURRENT LIABILITIES: | | | | Accounts payable | $ | — |
| | $ | 1 |
| Accounts payable to related companies | — |
| | 22 |
| Interest payable | 66 |
| | 66 |
| Accrued and other current liabilities | 4 |
| | 3 |
| Total current liabilities | 70 |
| | 92 |
| LONG-TERM DEBT, less current maturities | 6,700 |
| | 6,358 |
| NOTE PAYABLE TO AFFILIATE | 617 |
| | 443 |
| OTHER NON-CURRENT LIABILITIES | 2 |
| | 2 |
| | | | | COMMITMENTS AND CONTINGENCIES |
| |
| | | | | PARTNERS’ DEFICIT: | | | | General Partner | (3 | ) | | (3 | ) | Limited Partners: | | | | 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 | (1,196 | ) | | (1,694 | ) | Total liabilities and partners’ deficit | $ | 6,193 |
| | $ | 5,201 |
|
STATEMENTS OF OPERATIONS | | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | SELLING, GENERAL AND ADMINISTRATIVE EXPENSES | $ | (31 | ) | | $ | (185 | ) | | $ | (112 | ) | OTHER INCOME (EXPENSE): | | | | | | Interest expense, net of interest capitalized | (347 | ) | | (327 | ) | | (294 | ) | Equity in earnings of unconsolidated affiliates | 1,381 |
| | 1,511 |
| | 1,601 |
| Loss on extinguishment of debt | (47 | ) | | — |
| | — |
| Other, net | (2 | ) | | (4 | ) | | (5 | ) | INCOME BEFORE INCOME TAXES | 954 |
| | 995 |
| | 1,190 |
| Income tax expense | — |
| | — |
| | 1 |
| NET INCOME | 954 |
| | 995 |
| | 1,189 |
| General Partner’s interest in net income | 2 |
| | 3 |
| | 3 |
| Convertible Unitholders’ interest in income | 37 |
| | 9 |
| | — |
| Class D Unitholder’s interest in net income | — |
| | — |
| | 3 |
| Limited Partners’ interest in net income | $ | 915 |
| | $ | 983 |
| | $ | 1,183 |
|
STATEMENTS OF CASH FLOWS | | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES | $ | 831 |
| | $ | 918 |
| | $ | 1,103 |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | Cash paid for Bakken Pipeline Transaction | — |
| | — |
| | (817 | ) | Contributions to unconsolidated affiliates | (861 | ) | | (70 | ) | | — |
| Capital expenditures | (1 | ) | | (16 | ) | | (19 | ) | Contributions in aid of construction costs | 7 |
| | — |
| | — |
| Net cash used in investing activities | (855 | ) | | (86 | ) | | (836 | ) | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | Proceeds from borrowings | 2,219 |
| | 225 |
| | 3,672 |
| Principal payments on debt | (1,881 | ) | | (210 | ) | | (1,985 | ) | Distributions to partners | (1,010 | ) | | (1,022 | ) | | (1,090 | ) | Proceeds from affiliate | 174 |
| | 176 |
| | 210 |
| Common Units issued for cash | 568 |
| | — |
| | — |
| Units repurchased under buyback program | — |
| | — |
| | (1,064 | ) | Debt issuance costs | (47 | ) | | — |
| | (11 | ) | Net cash provided by (used in) financing activities | 23 |
| | (831 | ) | | (268 | ) | INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | (1 | ) | | 1 |
| | (1 | ) | CASH AND CASH EQUIVALENTS, beginning of period | 2 |
| | 1 |
| | 2 |
| CASH AND CASH EQUIVALENTS, end of period | $ | 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, 2017 and 2016 | S - 4 | Consolidated Statements of Operations – Years Ended December 31, 2017, 2016 and 2015 | S - 6 | Consolidated Statements of Comprehensive Income – Years Ended December 31, 2017, 2016 and 2015 | S - 7 | Consolidated Statements of Equity – Years Ended December 31, 2017, 2016 and 2015 | S - 8 | Consolidated Statements of Cash Flows – Years Ended December 31, 2017, 2016 and 2015 | S - 10 | Notes to Consolidated Financial Statements | S - 12 |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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, 2017 and 2016, the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, 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, 2017, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 23, 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 23, 2018
ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Dollars in millions) | | | | | | | | | | December 31, | | 2017 | | 2016* | ASSETS | | | | Current assets: | | | | Cash and cash equivalents | $ | 306 |
| | $ | 360 |
| Accounts receivable, net | 3,946 |
| | 3,002 |
| Accounts receivable from related companies | 318 |
| | 209 |
| Inventories | 1,589 |
| | 1,626 |
| Income taxes receivable | 135 |
| | 128 |
| Derivative assets | 24 |
| | 20 |
| Other current assets | 210 |
| | 298 |
| Total current assets | 6,528 |
| | 5,643 |
| | | | | Property, plant and equipment | 67,699 |
| | 58,220 |
| Accumulated depreciation and depletion | (9,262 | ) | | (7,303 | ) | | 58,437 |
| | 50,917 |
| | | | | Advances to and investments in unconsolidated affiliates | 3,816 |
| | 4,280 |
| Other non-current assets, net | 758 |
| | 672 |
| Intangible assets, net | 5,311 |
| | 4,696 |
| Goodwill | 3,115 |
| | 3,897 |
| Total assets | $ | 77,965 |
| | $ | 70,105 |
|
* As adjusted. See Note 2.
ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Dollars in millions) | | | | | | | | | | December 31, | | 2017 | | 2016* | LIABILITIES AND EQUITY | | | | Current liabilities: | | | | Accounts payable | $ | 4,126 |
| | $ | 2,900 |
| Accounts payable to related companies | 209 |
| | 43 |
| Derivative liabilities | 109 |
| | 166 |
| Accrued and other current liabilities | 2,143 |
| | 1,905 |
| Current maturities of long-term debt | 407 |
| | 1,189 |
| Total current liabilities | 6,994 |
| | 6,203 |
| | | | | Long-term debt, less current maturities | 32,687 |
| | 31,741 |
| Long-term notes payable – related company | — |
| | 250 |
| Non-current derivative liabilities | 145 |
| | 76 |
| Deferred income taxes | 2,883 |
| | 4,394 |
| Other non-current liabilities | 1,084 |
| | 952 |
| | | | | Commitments and contingencies |
| |
|
| Legacy ETP Preferred Units | — |
| | 33 |
| Redeemable noncontrolling interests | 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 | 244 |
| | 206 |
| Accumulated other comprehensive income | 3 |
| | 8 |
| Total partners’ capital | 28,269 |
| | 18,621 |
| Noncontrolling interest | 5,882 |
| | 7,820 |
| Total equity | 34,151 |
| | 26,441 |
| Total liabilities and equity | $ | 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, | | 2017 | | 2016* | | 2015* | REVENUES: | | | | | | Natural gas sales | $ | 4,172 |
| | $ | 3,619 |
| | $ | 3,671 |
| NGL sales | 6,972 |
| | 4,841 |
| | 3,936 |
| Crude sales | 10,184 |
| | 6,766 |
| | 8,378 |
| Gathering, transportation and other fees | 4,265 |
| | 4,003 |
| | 3,997 |
| Refined product sales (see Note 3) | 1,515 |
| | 1,047 |
| | 9,958 |
| Other (see Note 3) | 1,946 |
| | 1,551 |
| | 4,352 |
| Total revenues | 29,054 |
| | 21,827 |
| | 34,292 |
| COSTS AND EXPENSES: | | | | | | Cost of products sold (see Note 3) | 20,801 |
| | 15,080 |
| | 26,714 |
| Operating expenses (see Note 3) | 2,170 |
| | 1,839 |
| | 2,608 |
| Depreciation, depletion and amortization | 2,332 |
| | 1,986 |
| | 1,929 |
| Selling, general and administrative (see Note 3) | 434 |
| | 348 |
| | 475 |
| Impairment losses | 920 |
| | 813 |
| | 339 |
| Total costs and expenses | 26,657 |
| | 20,066 |
| | 32,065 |
| OPERATING INCOME | 2,397 |
| | 1,761 |
| | 2,227 |
| OTHER INCOME (EXPENSE): | | | | | | Interest expense, net | (1,365 | ) | | (1,317 | ) | | (1,291 | ) | Equity in earnings from unconsolidated affiliates | 156 |
| | 59 |
| | 469 |
| Impairment of investments in unconsolidated affiliates | (313 | ) | | (308 | ) | | — |
| Gains on acquisitions | — |
| | 83 |
| | — |
| Losses on extinguishments of debt | (42 | ) | | — |
| | (43 | ) | Losses on interest rate derivatives | (37 | ) | | (12 | ) | | (18 | ) | Other, net | 209 |
| | 131 |
| | 22 |
| INCOME BEFORE INCOME TAX BENEFIT | 1,005 |
| | 397 |
| | 1,366 |
| Income tax benefit | (1,496 | ) | | (186 | ) | | (123 | ) | NET INCOME | 2,501 |
| | 583 |
| | 1,489 |
| Less: Net income attributable to noncontrolling interest | 420 |
| | 295 |
| | 134 |
| Less: Net loss attributable to predecessor | — |
| | — |
| | (34 | ) | NET INCOME ATTRIBUTABLE TO PARTNERS | 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 | ) | NET INCOME (LOSS) PER COMMON UNIT: | | | | | | Basic | $ | 0.94 |
| | $ | (1.38 | ) | | $ | (0.07 | ) | Diluted | $ | 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, | | 2017 | | 2016* | | 2015* | Net income | $ | 2,501 |
| | $ | 583 |
| | $ | 1,489 |
| Other comprehensive income (loss), net of tax: | | | | | | Change in value of available-for-sale securities | 6 |
| | 2 |
| | (3 | ) | Actuarial gain (loss) relating to pension and other postretirement benefits | (12 | ) | | (1 | ) | | 65 |
| Foreign currency translation adjustment | — |
| | (1 | ) | | (1 | ) | Change in other comprehensive income (loss) from unconsolidated affiliates | 1 |
| | 4 |
| | (1 | ) | | (5 | ) | | 4 |
| | 60 |
| Comprehensive income | 2,496 |
| | 587 |
| | 1,549 |
| Less: Comprehensive income attributable to noncontrolling interest | 420 |
| | 295 |
| | 134 |
| Less: Comprehensive loss attributable to predecessor | — |
| | — |
| | (34 | ) | Comprehensive income attributable to partners | $ | 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 | | | | | | | | | | | | 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, 2014* | $ | — |
| | $ | — |
| | $ | 10,427 |
| | $ | 1,512 |
| | $ | — |
| | $ | 184 |
| | $ | (56 | ) | | $ | 5,143 |
| | $ | 8,088 |
| | $ | 25,298 |
| Distributions to partners | — |
| | — |
| | (1,863 | ) | | (247 | ) | | (80 | ) | | (944 | ) | | — |
| | — |
| | — |
| | (3,134 | ) | Distributions to noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (338 | ) | | — |
| | (338 | ) | Units issued for cash | — |
| | — |
| | 1,428 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1,428 |
| Subsidiary units issued for cash | — |
| | — |
| | 298 |
| | — |
| | — |
| | 2 |
| | — |
| | 1,219 |
| | — |
| | 1,519 |
| Capital contributions from noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 875 |
| | — |
| | 875 |
| Bakken Pipeline Transaction | — |
| | — |
| | (999 | ) | | 1,946 |
| | — |
| | — |
| | — |
| | 72 |
| | — |
| | 1,019 |
| Sunoco LP Exchange Transaction | — |
| | — |
| | (52 | ) | | — |
| | — |
| | — |
| | — |
| | (940 | ) | | — |
| | (992 | ) | Susser Exchange Transaction | — |
| | — |
| | (68 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (68 | ) | Acquisition and disposition of noncontrolling interest | — |
| | — |
| | (26 | ) | | — |
| | — |
| | — |
| | — |
| | (39 | ) | | — |
| | (65 | ) | Predecessor distributions to partners | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (202 | ) | | (202 | ) | Predecessor units issued for cash | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 34 |
| | 34 |
| Regency Merger | — |
| | — |
| | 7,890 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (7,890 | ) | | — |
| Other comprehensive income, net of tax | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 60 |
| | — |
| | — |
| | 60 |
| Other, net | — |
| | — |
| | 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 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Capital contributions from noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 236 |
| | — |
| | 236 |
| Sunoco, Inc. retail business to Sunoco LP transaction | — |
| | — |
| | (405 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (405 | ) | PennTex Acquisition | — |
| | — |
| | 307 |
| | — |
| | — |
| | — |
| | — |
| | 236 |
| | — |
| | 543 |
| Other comprehensive income, net of tax | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 4 |
| | — |
| | — |
| | 4 |
| Other, net | — |
| | — |
| | 10 |
| | — |
| | — |
| | — |
| | — |
| | 21 |
| | — |
| | 31 |
| Net income (loss) | — |
| | — |
| | (1,019 | ) | | 351 |
| | 8 |
| | 948 |
| | — |
| | 295 |
| | — |
| | 583 |
| 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, | | 2017 | | 2016* | | 2015* | OPERATING ACTIVITIES: | | | | | | Net income | $ | 2,501 |
| | $ | 583 |
| | $ | 1,489 |
| Reconciliation of net income to net cash provided by operating activities: | | | | | | Depreciation, depletion and amortization | 2,332 |
| | 1,986 |
| | 1,929 |
| Deferred income taxes | (1,531 | ) | | (169 | ) | | 202 |
| Amortization included in interest expense | 2 |
| | (20 | ) | | (36 | ) | Inventory valuation adjustments | — |
| | — |
| | (58 | ) | Unit-based compensation expense | 74 |
| | 80 |
| | 79 |
| Impairment losses | 920 |
| | 813 |
| | 339 |
| Gains on acquisitions | — |
| | (83 | ) | | — |
| Losses on extinguishments of debt | 42 |
| | — |
| | 43 |
| Impairment of investments in unconsolidated affiliates | 313 |
| | 308 |
| | — |
| Distributions on unvested awards | (31 | ) | | (25 | ) | | (16 | ) | Equity in earnings of unconsolidated affiliates | (156 | ) | | (59 | ) | | (469 | ) | Distributions from unconsolidated affiliates | 440 |
| | 406 |
| | 440 |
| Other non-cash | (261 | ) | | (271 | ) | | (22 | ) | Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | (160 | ) | | (246 | ) | | (1,173 | ) | Net cash provided by operating activities | 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 |
| | — |
| Proceeds from Bakken Pipeline Transaction | — |
| | — |
| | 980 |
| Proceeds from Susser Exchange Transaction | — |
| | — |
| | 967 |
| Proceeds from sale of noncontrolling interest | — |
| | — |
| | 64 |
| Cash paid for acquisition of PennTex noncontrolling interest | (280 | ) | | — |
| | — |
| Cash paid for Vitol Acquisition, net of cash received | — |
| | (769 | ) | | — |
| Cash paid for PennTex Acquisition, net of cash received | — |
| | (299 | ) | | — |
| Cash transferred to ETE in connection with the Sunoco LP Exchange | — |
| | — |
| | (114 | ) | Cash paid for acquisition of a noncontrolling interest | — |
| | — |
| | (129 | ) | Cash paid for all other acquisitions | (264 | ) | | (159 | ) | | (675 | ) | Capital expenditures, excluding allowance for equity funds used during construction | (8,335 | ) | | (7,550 | ) | | (9,098 | ) | Contributions in aid of construction costs | 24 |
| | 71 |
| | 80 |
| Contributions to unconsolidated affiliates | (268 | ) | | (59 | ) | | (45 | ) | Distributions from unconsolidated affiliates in excess of cumulative earnings | 136 |
| | 135 |
| | 124 |
| Proceeds from the sale of assets | 35 |
| | 25 |
| | 23 |
| Change in restricted cash | — |
| | 14 |
| | 19 |
| Other | 1 |
| | 1 |
| | (16 | ) | Net cash used in investing activities | (5,473 | ) | | (6,390 | ) | | (7,820 | ) | | | | | | |
| | | | | | | | | | | | | FINANCING ACTIVITIES: | | | | | | Proceeds from borrowings | 26,736 |
| | 19,916 |
| | 22,462 |
| Repayments of long-term debt | (26,494 | ) | | (15,799 | ) | | (17,843 | ) | 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 |
| Predecessor units issued for cash | — |
| | — |
| | 34 |
| Capital contributions from noncontrolling interest | 1,214 |
| | 236 |
| | 841 |
| Distributions to partners | (3,468 | ) | | (3,542 | ) | | (3,134 | ) | Predecessor distributions to partners | — |
| | — |
| | (202 | ) | Distributions to noncontrolling interest | (430 | ) | | (481 | ) | | (338 | ) | Redemption of Legacy ETP Preferred Units | (53 | ) | | — |
| | — |
| Debt issuance costs | (83 | ) | | (22 | ) | | (63 | ) | Other | 5 |
| | 2 |
| | — |
| Net cash provided by financing activities | 934 |
| | 2,920 |
| | 4,937 |
| Decrease in cash and cash equivalents | (54 | ) | | (167 | ) | | (136 | ) | Cash and cash equivalents, beginning of period | 360 |
| | 527 |
| | 663 |
| Cash and cash equivalents, end of period | $ | 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 ETP Holdco Transaction, ETP became a co-obligor on approximately $965 millionSunoco Logistics Partners L.P. changed its name to “Energy Transfer Partners, L.P.” For purposes of aggregate principal amount of Sunoco, Inc.’s existing senior notes and debentures. The balance of these notes was $715 million as of December 31, 2014.maintaining clarity, the following references are used herein: ETP Senior Notes
The ETP senior notes were registered underReferences to “ETLP” refer to Energy Transfer, LP subsequent to the Securities Act of 1933 (as amended). The Partnership may redeem some or allclose of the ETP senior notes at any time, or from timemerger;
References to time, pursuant“Sunoco Logistics” refer to the termsentity named Sunoco Logistics Partners L.P. prior to the close of the indenturemerger; and related indenture supplements related References to “ETP” refer to the ETP senior notes. The balance is payable upon maturity. Interest onconsolidated entity named Energy Transfer Partners, L.P. subsequent to the ETP senior notes is paid semi-annually. The ETP senior notes are unsecured obligationsclose 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. As 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 notes are payable 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 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 3.26% at December 31, 2014.
Sunoco Logistics Senior Notes Offerings
In April 2014, Sunoco Logistics issued $300 million aggregate principal amount of 4.25% senior notes due April 2024 and $700 million aggregate principal amount of 5.30% senior notes due April 2044.
In November 2014, Sunoco Logistics issued $200 million aggregate principal amount of 4.25% senior notes due April 2024 and $800 million aggregate principal amount of 5.35% senior notes due May 2045. Sunoco Logistics used the net proceeds from the offerings to pay outstanding borrowings under the Sunoco Logistics Credit Facility and for general partnership purposes.
Credit Facilities
ETP Credit Facility
The ETP Credit Facility allows for borrowings of up to $2.5 billion and expires in October 2019. The indebtedness under the ETP Credit Facility is unsecured and 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 Facility to provide temporary financing for our growth projects, as well as for general partnership purposes. In February 2015, ETP amended its revolving credit facility to increase the capacity to $3.75 billion.
As of December 31, 2014, the ETP Credit Facility had $570 million outstanding, and the amount available for future borrowings was $1.81 billion after taking into account letters of credit of $121 million. The weighted average interest rate on the total amount outstanding as of December 31, 2014 was 1.66%.
Sunoco Logistics Credit Facilities
Sunoco Logistics maintains a $1.50 billion unsecured credit facility (the “Sunoco Logistics Credit Facility”) which matures in November 2018. The Sunoco Logistics Credit Facility contains an accordion feature, under which the total aggregate commitment may be extended to $2.25 billion under certain conditions.merger.
The Sunoco Logistics Credit Facility is availableMerger resulted in Energy Transfer Partners, L.P. being treated as the surviving consolidated entity from an accounting perspective, while Sunoco Logistics (prior to fund Sunoco Logistics’ working capital requirements,changing its name to finance acquisitions“Energy Transfer Partners, L.P.”) was the surviving consolidated entity from a legal and capital projects,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 pay distributionsthe merger and for general partnership purposes. name changes). The Sunoco Logistics Credit Facility bears interest at LIBORMerger 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 Base Rate, each plus an applicable margin. The credit facility may be prepaid at any time. As of December 31, 2014,periods prior to the Sunoco Logistics Credit Facility had $150 million of outstanding borrowings. West Texas Gulf Pipe Line Company, a subsidiary ofMerger, the Sunoco Logistics maintainslimited 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 $35 million revolving credit facility which expirescontrolling interest in April 2015. The facility is available to fund West Texas Gulf’s general corporate purposes including working capital and capital expenditures. At December 31, 2014, this credit facility had $35 million of outstanding borrowings. Sunoco LP Credit Facility In September 2014, Sunoco LP entered into a $1.25 billion revolving credit agreement (the “Sunoco LP Credit Facility”)Logistics Partners Operations L.P., which maturesowns 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, NGLs and refined products.
Basis of Presentation. The consolidated financial statements of the Partnership have been prepared in September 2019. The Sunoco LP Credit Facility can be increased from time to time upon Sunoco LP’s written request, subject to certain conditions, up to an additional $250 million. Asaccordance with GAAP and include the accounts of December 31, 2014,all controlled subsidiaries after the Sunoco LP Credit Facility had $683 millionelimination of outstanding borrowings. Covenants Related to Our Credit Agreements
Covenants Related to ETP
The agreements relatingall intercompany accounts and transactions. Certain prior year amounts have been conformed to the ETP senior notes contain restrictive covenants customary for an issuer with an investment-grade rating fromcurrent year presentation. These reclassifications had no impact on net income or total equity. Management evaluated subsequent events through the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions.
The credit agreement relating todate the ETP Credit Facility contains covenants that limit (subject tofinancial statements were issued.
For prior periods reported herein, certain exceptions) the Partnership’s and certain of the Partnership’s subsidiaries’ ability to, among other things: incur indebtedness;
grant liens;
enter into mergers;
dispose of assets;
make certain investments;
make Distributions (as defined in such credit agreement) during certain Defaults (as defined in such credit agreement) and during any Event of Default (as defined in such credit agreement);
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 credit agreement relating to the ETP Credit Facility also contains a financial covenant that provides that the Leverage Ratio, as defined in the ETP Credit Facility, shall not exceed 5.0 to 1 as of the end of each quarter, with a permitted increase to 5.5 to 1 during a Specified Acquisition Period, as defined in the ETP Credit Facility.
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
Sunoco Logistics’ $1.50 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 legacy Sunoco Logistics have been reclassified from cost of products sold to operating expenses; these transactions include sales between operating subsidiaries and its subsidiaries. The credit facility also limits Sunoco Logistics,their marketing affiliates. These reclassifications had no impact on a rolling four-quarter basis, to a maximumnet income or total consolidated debt to consolidated Adjusted EBITDA ratio, as defined in the underlying credit agreement, 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 debt, excluding net unamortized
fair value adjustments, to consolidated Adjusted EBITDA was 3.7 to 1 at December 31, 2014, as calculated in accordance with the credit agreements.equity.
The West Texas Gulf Pipeline Company’s $35 million credit facility limits West Texas Gulf, onPartnership 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 rolling four-quarter basis, to a minimum fixed charge coverage ratio of 1.00 to 1. In addition, the credit facility limits West Texas Gulf to a maximum leverage ratio of 2.00 to 1. West Texas Gulf’s fixed charge coverage ratio and leverage ratio were 1.67 to 1 and 0.85 to 1, respectively, at December 31, 2014. Covenants Related to Sunoco LP
The Sunoco LP Credit Facility requires Sunoco LP to maintain a leverage ratio of not more than 5.50 to 1. The maximum leverage ratio is subject to upwards adjustment of not more than 6.00 to 1 for a period not to exceed three fiscal quarters in the event Sunoco LP engages in an acquisition of assets, equity interests, operating lines or divisions by Sunoco LP, a subsidiary, an unrestricted subsidiary or apartnership, 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 purchase price of not less than $50 million. Indebtedness under the Sunoco LP Credit Facility is secured by a security interest in, among other things, all of the 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 securityresult, these undivided interests securing the Sunoco LP Credit Facility will be released.
We were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2014.are consolidated proportionately.
| | 7.2. | REDEEMABLE NONCONTROLLING INTERESTS: 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. Recent Accounting Pronouncements ASU 2014-09 In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from 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.
The Partnership adopted ASU 2014-09 on January 1, 2018. The Partnership applied the cumulative catchup transition method and recognized the cumulative effect of the retrospective application of the standard. The effect of the retrospective application of the standard was not material. For future periods, we expect that the adoption of this standard will result in a change to revenues with offsetting changes to costs associated primarily with the designation 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 accounting for noncash consideration in multiple of our reportable segments, as well as fuel usage and loss allowances. None of these changes is expected to have a material impact on 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 in the first quarter of 2019 and 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, 2018, the Partnership 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. We do not anticipate a material impact to our financial position or results of operations as a result of the adoption of this standard. ASU 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’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance did 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, 2018, with early adoption permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and 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. 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 segment 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, | | 2017 | | 2016 | | 2015 | Accounts receivable | $ | (950 | ) | | $ | (919 | ) | | $ | 819 |
| Accounts receivable from related companies | 67 |
| | 30 |
| | (243 | ) | Inventories | 37 |
| | (497 | ) | | (157 | ) | Other current assets | 39 |
| | 83 |
| | (178 | ) | Other non-current assets, net | (94 | ) | | (78 | ) | | 188 |
| Accounts payable | 758 |
| | 972 |
| | (1,215 | ) | Accounts payable to related companies | (3 | ) | | 29 |
| | (160 | ) | Accrued and other current liabilities | (47 | ) | | 39 |
| | (83 | ) | Other non-current liabilities | 24 |
| | 33 |
| | (219 | ) | Price risk management assets and liabilities, net | 9 |
| | 62 |
| | 75 |
| Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | $ | (160 | ) | | $ | (246 | ) | | $ | (1,173 | ) |
Non-cash investing and financing activities and supplemental cash flow information are as follows: | | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | NON-CASH INVESTING ACTIVITIES: | | | | | | Accrued capital expenditures | $ | 1,059 |
| | $ | 822 |
| | $ | 896 |
| Sunoco LP limited partner interest received in exchange for contribution of the Sunoco, Inc. retail business to Sunoco LP | — |
| | 194 |
| | — |
| Net gains from subsidiary common unit transactions | — |
| | 37 |
| | 300 |
| NON-CASH FINANCING ACTIVITIES: | | | | | | Issuance of Common Units in connection with the PennTex Acquisition | $ | — |
| | $ | 307 |
| | $ | — |
| Issuance of Common Units in connection with the Regency Merger | — |
| | — |
| | 9,250 |
| Issuance of Class H Units in connection with the Bakken Pipeline Transaction | — |
| | — |
| | 1,946 |
| Contribution of assets from noncontrolling interest | 988 |
| | — |
| | 34 |
| Redemption of Common Units in connection with the Bakken Pipeline Transaction | — |
| | — |
| | 999 |
| Redemption of Common Units in connection with the Sunoco LP Exchange | — |
| | — |
| | 52 |
| SUPPLEMENTAL CASH FLOW INFORMATION: | | | | | | Cash paid for interest, net of interest capitalized | $ | 1,329 |
| | $ | 1,411 |
| | $ | 1,467 |
| Cash paid for (refund of) income taxes | 50 |
| | (229 | ) | | 71 |
|
Accounts Receivable Our 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. We have a diverse portfolio of 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 and spare parts, all of which are valued at the lower of cost or net realizable value utilizing the weighted-average cost method.
Inventories consisted of the following: | | | | | | | | | | 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, | | 2017 | | 2016 | Deposits paid to vendors | $ | 64 |
| | $ | 74 |
| Prepaid expenses and other | 146 |
| | 224 |
| Total other current assets | $ | 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 NGL 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, | | 2017 | | 2016 | Land and improvements | $ | 1,706 |
| | $ | 676 |
| Buildings and improvements (1 to 45 years) | 1,960 |
| | 1,617 |
| Pipelines and equipment (5 to 83 years) | 44,050 |
| | 36,356 |
| Natural gas and NGL storage facilities (5 to 46 years) | 1,681 |
| | 1,452 |
| Bulk storage, equipment and facilities (2 to 83 years) | 3,036 |
| | 3,701 |
| Vehicles (1 to 25 years) | 124 |
| | 217 |
| Right of way (20 to 83 years) | 3,424 |
| | 3,349 |
| Natural resources | 434 |
| | 434 |
| Other (1 to 40 years) | 534 |
| | 484 |
| Construction work-in-process | 10,750 |
| | 9,934 |
| | 67,699 |
| | 58,220 |
| Less – Accumulated depreciation and depletion | (9,262 | ) | | (7,303 | ) | Property, plant and equipment, net | $ | 58,437 |
| | $ | 50,917 |
|
We recognized the following amounts for the periods presented: | | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | Depreciation and depletion expense | $ | 2,060 |
| | $ | 1,793 |
| | $ | 1,713 |
| 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, | | 2017 | | 2016 | Regulatory assets | $ | 85 |
| | $ | 86 |
| Deferred charges | 210 |
| | 217 |
| Restricted funds | 192 |
| | 190 |
| Long-term affiliated receivable | 85 |
| | 90 |
| Other | 186 |
| | 89 |
| Total other non-current assets, net | $ | 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, 2017 | | December 31, 2016 | | Gross Carrying Amount | | Accumulated Amortization | | Gross Carrying Amount | | Accumulated Amortization | Amortizable intangible assets: | | | | | | | | Customer relationships, contracts and agreements (3 to 46 years) | $ | 6,250 |
| | $ | (1,003 | ) | | $ | 5,362 |
| | $ | (737 | ) | Patents (10 years) | 48 |
| | (26 | ) | | 48 |
| | (21 | ) | Trade Names (20 years) | 66 |
| | (25 | ) | | 66 |
| | (22 | ) | Other (5 to 20 years) | 1 |
| | — |
| | 2 |
| | (2 | ) | Total intangible assets | $ | 6,365 |
| | $ | (1,054 | ) | | $ | 5,478 |
| | $ | (782 | ) |
Aggregate amortization expense of intangible assets was as follows: | | | | | | | | | | | | | | 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: | | 2018 | $ | 280 |
| 2019 | 278 |
| 2020 | 278 |
| 2021 | 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 NGL 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 | | NGL and Refined Products Transportation and Services | | Crude Oil Transportation and Services | | All Other | | Total | 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 | — |
| | (262 | ) | | — |
| | (79 | ) | | — |
| | (452 | ) | | (793 | ) | Other | — |
| | — |
| | (1 | ) | | — |
| | — |
| | — |
| | (1 | ) | 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 $99 million in the interstate transportation and storage segment and $106 million in the NGL and refined products transportation and services segment primarily due to market declines in current and expected future commodity prices in the fourth quarter of 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 discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as of December 31, 2017 and 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. We 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. As of December 31, 2017 and 2016, other non-current liabilities in the Partnership’s consolidated balance 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 $2 million and $14 million, and were reflected as property, plant and equipment on our balance sheet as of December 31, 2017 and 2016, respectively. In addition, the Partnership had $21 million and $13 million legally restricted funds for the purpose of settling AROs that was reflected as other non-current assets as of December 31, 2017 and 2016, respectively. Accrued and Other Current Liabilities Accrued and other current liabilities consisted of the following: | | | | | | | | | | December 31, | | 2017 | | 2016 | Interest payable | $ | 443 |
| | $ | 440 |
| Customer advances and deposits | 59 |
| | 56 |
| Accrued capital expenditures | 1,006 |
| | 749 |
| Accrued wages and benefits | 208 |
| | 212 |
| Taxes payable other than income taxes | 108 |
| | 63 |
| Exchanges payable | 154 |
| | 208 |
| Other | 165 |
| | 177 |
| Total accrued and other current liabilities | $ | 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 sheetsheet. 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, 2014.2017 was $34.28 billion and $33.09 billion, respectively. As of December 31, 2016, the aggregate fair value and carrying amount of our debt obligations was $33.85 billion and $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. Limited Partner interestsWe have commodity derivatives, interest rate derivatives and embedded derivatives in our preferred units that are representedaccounted 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 Common, Class E Units, Class G Unitsusing the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and Class H Units that entitleliabilities. We consider the holders thereofvaluation 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 rights and privileges specifiedlevel of activity of these contracts on the exchange in which they trade. We consider the Partnership Agreement. Asvaluation 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. During the year ended December 31, 2014, there2017, no transfers were issuedmade between any levels within the fair value hierarchy.
The following tables summarize the fair value of our financial assets and outstanding 355.5 million Common Units representing an aggregate 99.3% Limited Partner interest in us. A totalliabilities measured and recorded at fair value on a recurring basis as of 8.9 million Class E UnitsDecember 31, 2017 and 90.7 million Class G Units are outstanding and are reported as treasury units, which units are entitled2016 based on inputs used to receive distributions in accordance withderive their terms. A total of 50.2 million Class H Units are also outstanding representing Limited Partner interests owned by ETE Holdings (see “Class H Units” below).fair values: 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. | | | | | | | | | | | | | | Fair Value Total | | Fair Value Measurements at December 31, 2017 | | Level 1 | | Level 2 | Assets: | | | | | | Commodity derivatives: | | | | | | Natural Gas: | | | | | | Basis Swaps IFERC/NYMEX | $ | 11 |
| | $ | 11 |
| | $ | — |
| Swing Swaps IFERC | 13 |
| | — |
| | 13 |
| Fixed Swaps/Futures | 70 |
| | 70 |
| | — |
| Forward Physical Swaps | 8 |
| | — |
| | 8 |
| Power: | | | | | | Forwards | 23 |
| | — |
| | 23 |
| Natural Gas Liquids – Forwards/Swaps | 193 |
| | 193 |
| | — |
| Crude – Futures | 2 |
| | 2 |
| | — |
| Total commodity derivatives | 320 |
| | 276 |
| | 44 |
| Other non-current assets | 21 |
| | 14 |
| | 7 |
| Total assets | $ | 341 |
| | $ | 290 |
| | $ | 51 |
| Liabilities: | | | | | | Interest rate derivatives | $ | (219 | ) | | $ | — |
| | $ | (219 | ) | Commodity derivatives: | | | | | | Natural Gas: | | | | | | Basis Swaps IFERC/NYMEX | (24 | ) | | (24 | ) | | — |
| Swing Swaps IFERC | (15 | ) | | (1 | ) | | (14 | ) | Fixed Swaps/Futures | (57 | ) | | (57 | ) | | — |
| Forward Physical Swaps | (2 | ) | | — |
| | (2 | ) | Power – Forwards | (22 | ) | | — |
| | (22 | ) | Natural Gas Liquids – Forwards/Swaps | (192 | ) | | (192 | ) | | — |
| Refined Products – Futures | (25 | ) | | (25 | ) | | — |
| Crude – Futures | (1 | ) | | (1 | ) | | — |
| Total commodity derivatives | (338 | ) | | (300 | ) | | (38 | ) | Total liabilities | $ | (557 | ) | | $ | (300 | ) | | $ | (257 | ) |
Table of Contents | | | | | | | | | | | | | | | | | | 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 | ) |
Common Units The change in Common Units was as follows: | | | | | | | | | | | Years Ended December 31, | | 2014 | | 2013 | | 2012 | Number of Common Units, beginning of period | 333.8 |
| | 301.5 |
| | 225.5 |
| Common Units issued in connection with the Susser Merger (see Note 3) | 15.8 |
| | — |
| | — |
| Common Units redeemed in connection with the Lake Charles LNG Transaction (see Note 3) | (18.7 | ) | | — |
| | — |
| Common Units issued in connection with public offerings | — |
| | 13.8 |
| | 15.5 |
| Common Units issued in connection with certain acquisitions | — |
| | 49.5 |
| | 57.4 |
| Common Units redeemed for Class H Units | — |
| | (50.2 | ) | | — |
| Common Units issued in connection with the Distribution Reinvestment Plan | 2.8 |
| | 2.3 |
| | 1.0 |
| Common Units issued in connection with Equity Distribution Agreements | 21.4 |
| | 16.9 |
| | 1.6 |
| Repurchases of Common Units in open-market transactions | — |
| | (0.4 | ) | | — |
| Issuance of Common Units under equity incentive plans | 0.4 |
| | 0.4 |
| | 0.5 |
| Number of Common Units, end of period | 355.5 |
| | 333.8 |
| | 301.5 |
|
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.”
Public Offerings
The following table summarizes our public offerings ofETE Common Units during the periods presented, all of which have been registered under the Securities Act of 1933 (as amended):years ended December 31, 2017, 2016 and 2015 was as follows:
| | | | | | | | | | | | | Date | | Number of Common Units | | Price per Unit | | Net Proceeds | July 2012 | | 15.5 |
| | $ | 44.57 |
| | $ | 671 |
| April 2013 | | 13.8 |
| | 48.05 |
| | 657 |
|
| | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | Number of Common Units, beginning of period | 1,046.9 |
| | 1,044.8 |
| | 1,077.5 |
| Conversion of Class D Units to ETE Common Units | — |
| | — |
| | 0.9 |
| Repurchase of common units under buyback program | — |
| | — |
| | (33.6 | ) | Issuance of common units | 32.2 |
| | 2.1 |
| | — |
| Number of Common Units, end of period | 1,079.1 |
| | 1,046.9 |
| | 1,044.8 |
|
Proceeds fromETE Equity Distribution Agreement
In March 2017, the offerings listed above werePartnership 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, | | 2017 | | 2016 | | 2015 | Number of Series A Convertible Preferred Units, beginning of period | 329.3 |
| | — |
| | — |
| Issuance of Series A Convertible Preferred Units | — |
| | 329.3 |
| | — |
| Number of Series A Convertible Preferred Units, end of period | 329.3 |
| | 329.3 |
| | — |
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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 $450 million carrying value as of December 31, 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 repay amountspurchase 23.7 million newly issued ETP common units for approximately $568 million. Common Unit Split On July 27, 2015, ETE completed a two-for-one split of the Partnership’s outstanding common units 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 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 ETP Credit Facility and/orprogram as of December 31, 2017. Class D Units In 2013, the Partnership issued 3,080,000 Class D Units of ETE pursuant to fundan agreement with a former executive. The Class D Units were convertible to ETE Common Units, subject to certain vesting requirements which were not met prior to the former executive’s termination in 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 expenditures and capital contributionstransaction. 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 joint ventures, and for general partnership purposes.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, we haveETP 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 January 2013 andconnection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. equity distribution agreement was terminated. In May 2013, we2017, ETP entered into an equity distribution agreements pursuant to which we may sell from time to time Common Units havingagreement with an aggregate offering prices ofprice up to $200 million and $800 million, respectively. $1.00 billion.
During the year ended December 31, 2014, we2017, ETP issued approximately 2.722.6 million units for $144$503 million, net of commissions of $2 million. No amounts of our Common Units remain available to be issued under our January 2013 and May 2013 equity distribution agreements. In May 2014 and November 2014, we entered into equity distribution agreements pursuant to which we may sell from time to time Common Units having aggregate offering prices of up to $1.0 billion and $1.50 billion, respectively. During the year
ended December 31, 2014, we issued approximately 18.8 million units for $1.08 billion, net of commissions of $11$5 million. As of December 31, 2014, approximately $1.41 billion2017, $752 million of ourETP’s Common Units remained available to be issued under ourETP’s currently effective equity distribution agreements.agreement.
ETP’s Equity Incentive Plan Activity As discussed in Note 9, we issueETP issues ETP Common Units to employees and directors upon vesting of awards granted under ourETP’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 the PartnershipETP to satisfy tax-withholding obligations.
ETP’s Distribution Reinvestment Program OurETP’s Distribution Reinvestment Plan (the “DRIP”) provides ETP’s Unitholders of record and beneficial owners of ourETP 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, 2014, 20132017, 2016 and 2012,2015, aggregate distributions of approximately $155$228 million, $109$216 million, and $43$360 million, respectively, were reinvested under the DRIP resulting in the issuance in aggregate of approximately 6.125.5 million Common Units. As of December 31, 2014,2017, a total of 7.320.8 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 There 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 Class E Unitholders, up to $1.41$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 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 ETP Class G Units There are currently 90.7 million ETP Class G Units outstanding, all of the 8.9 million Class E Units outstandingwhich are held by a subsidiary and are reported as treasury units. wholly-owned subsidiaries of ETP. The ETP 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 ETP Class FG Units wereare entitled to aggregate cash distributions equal to 35% of the total amount of cash generated by usETP and ourits 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 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 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. These units are held by a subsidiary and therefore are reflected as treasury units in the 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 50.05%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 50.05%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.
Pending Transaction
In December 2014, ETP and ETE announced the final terms of a transaction, whereby ETE will transfer 30.8 million ETP Common Units, ETE’s 45% interest in the Bakken pipeline project, and $879 million in cash 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 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, in April 2017.
ETP will also issue 100 Class I Units as described below. In addition, ETE and ETP agreed to reduce the IDR subsidies that ETE previously agreed to provide to ETP, with such reductions occurring in 2015 and 2016. In connection with the transaction,Bakken Pipeline Transaction discussed in Note 3, in March 2015, ETP will also issueissued 100 ETP Class I Units. The ETP Class I Units will beare 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 ourETP’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” inCash.” Subsequent to the column titled “Pro Forma for Class HApril 2017 merger of ETP and Sunoco Logistics, 100 Class I Units.”Units remain outstanding. SalesBakken 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 CommonDakota 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. 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, excluding any cash available distributions or dividends or capital stock sales proceeds received by Subsidiaries WithETP from ETP Holdco. If ETP is unable to pay the Class K Unit quarterly distribution with respect to our investments in Sunoco Logisticsany quarter, the accrued and Sunoco LP, we account for the difference between the carrying amountunpaid distributions will accumulate until paid and any accumulated balance will accrue 1.5% per annum until paid. As of our investment in 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, 2014, we recognized increases in partners’ capital2017, a total of $113 million.101.5 million Class K Units were held by wholly-owned subsidiaries of ETP.
As a result of Sunoco LP’s issuances of common units during the year ended December 31, 2014, we recognized increases in partners’ capital of $62 million.
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 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. DuringIn connection with theyear ended ended December 31, 2014, Sunoco Logistics received proceeds of $477 million, net of commissions of $5 million, fromMerger, the issuance of 10.3 million common units pursuant to theprevious Sunoco Logistics equity distribution agreement which were used for general partnership purposes.was terminated. ETP Series A and Series Preferred Units In November 2017, ETP issued 950,000 of its 6.250% Series A Preferred Units at a price of $1,000 per unit, and 550,000 of its 6.625% Series B Preferred Units at a price of $1,000 per unit. Additionally, Sunoco Logistics completedDistributions on the ETP Series A Preferred Units will accrue and be cumulative from and including the date of original 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 overnight public offeringannual floating rate of 7.7 millionthe 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 not previously owned by ETP for net proceeds$20.00 per common unit in cash. ETP now owns all of $362 million in September 2014. The net proceeds from this offering were used to repay outstanding borrowings under the $1.50 billion Sunoco Logistics Credit Facilityeconomic interests of PennTex, and for general partnership purposes.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 2014 and November 2014,2016, 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 an aggregateadditional 1.3 million units with total net proceeds of 9.1$33 million, net of commissions of $0.3 million. As of December 31, 2017, $295 million of Sunoco LP common units remained available to be issued under the currently effective equity distribution agreement. 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 underwritten public offering. Aggregateindirect 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 $405 million$213 million. The net proceeds from the offering were used to repay amounts outstanding balances under the $1.25 billion Sunoco LP Credit Facilityrevolving credit facility. Sunoco LP Series 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 purchase price of $300 million. The distribution rate of Sunoco LP Series 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 fora 1% call premium plus accrued and unpaid quarterly distributions. Contributions to Subsidiaries The Parent Company indirectly owns the entire general partnership purposes.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 TheOur distribution policy is consistent with the terms of our Partnership Agreement, which requires that we distribute all of our Available Cashavailable 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 Unitholderscommon units for the periods presented were as follows: | | | | | | | | | 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 |
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| | (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 additional information below. |
Our distributions declared and paid with respect to our General PartnerConvertible Unit during the years ended December 31, 2016 and 2017 were as follows: | | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | March 31, 2016 | | May 6, 2016 | | May 19, 2016 | | $ | 0.1100 |
| June 30, 2016 | | August 8, 2016 | | August 19, 2016 | | 0.1100 |
| September 30, 2016 | | November 7, 2016 | | November 18, 2016 | | 0.1100 |
| December 31, 2016 | | 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 |
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ETP’s Quarterly Distributions of Available Cash Under ETP’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,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 the General Partnergeneral partner in its solediscretion. This is defined as “available cash” in ETP’s partnership agreement. The general partner has broad discretion to provide for the properestablish cash reserves that it determines are necessary or appropriate to properly conduct of our business, to comply with applicable laws or any debt instrument or other agreement, or to provide funds for futureETP’s business. ETP 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 definedincentive distribution rights receive increasing percentages, up to 48 percent, of the cash distributed in our Partnership Agreement.
Ourthat amount. These distributions are referred to as “incentive distributions.”
As the holder of Available Cash from operating surplus, excludingEnergy 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 our General Partner and Limited Partner interests are based on their respective interests as of the distribution record date. Incentive distributions allocated to our General Partner arebe paid by ETP will be determined based on the amount byhistorical 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 general partner interest, Class I units and a portion of the outstanding ETP common units. | | | | | | | | | | | | 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 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 Unitholders exceed certain specified target levels,units declared and paid by ETP and Sunoco Logistics during the pre-merger periods were as set forthfollows: | | | | | | | | | | 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 |
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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 |
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In connection with previous transactions, we have agreed to relinquish its right to the following amounts of incentive distributions in our Partnership Agreement.future periods: | | | | | | | | Total Year | 2018 | | $ | 153 |
| 2019 | | 128 |
| Each year beyond 2019 | | 33 |
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Distributions declared duringand paid by ETP to the Series A and Series B preferred unitholders were as follows: | | | | | | | | | | | | | | | 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 for the periods presented were as follows: | | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | December 31, 2011 | | February 7, 2012 | | February 14, 2012 | | $ | 0.8938 |
| March 31, 2012 | | May 4, 2012 | | May 15, 2012 | | 0.8938 |
| June 30, 2012 | | August 6, 2012 | | August 14, 2012 | | 0.8938 |
| September 30, 2012 | | November 6, 2012 | | November 14, 2012 | | 0.8938 |
| December 31, 2012 | | February 7, 2013 | | February 14, 2013 | | 0.8938 |
| March 31, 2013 | | May 6, 2013 | | May 15, 2013 | | 0.8938 |
| June 30, 2013 | | August 5, 2013 | | August 14, 2013 | | 0.8938 |
| September 30, 2013 | | November 4, 2013 | | November 14, 2013 | | 0.9050 |
| 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 |
|
In connection with transactions between ETP and ETE, ETE has agreed to relinquish its right to certain incentive distributions in future periods. Following is a summary of the net reduction in total distributions that would potentially be made to ETE in future periods based on (i) the currently effective partnership agreement provisions, (ii) the assumed closing of the issuance of additional Class H Units and Class I Units, which is expected to occur in March 2015, and (iii) the assumed closing of the Regency Merger, which is expected to occur in the second quarter of 2015:
| | | | | | | | | | | | | | Years Ending December 31, | | Currently Effective | | Pro Forma for Class H and Class I Units(1) | | Pro Forma for Regency Merger(2) | 2015 | | $ | 86 |
| | $ | 31 |
| | $ | 91 |
| 2016 | | 107 |
| | 77 |
| | 142 |
| 2017 | | 85 |
| | 85 |
| | 145 |
| 2018 | | 80 |
| | 80 |
| | 140 |
| 2019 | | 70 |
| | 70 |
| | 130 |
| 2020 | | 35 |
| | 35 |
| | 50 |
| 2021 | | 35 |
| | 35 |
| | 35 |
| 2022 | | 35 |
| | 35 |
| | 35 |
| 2023 | | 35 |
| | 35 |
| | 35 |
| 2024 | | 18 |
| | 18 |
| | 18 |
|
| | | | | | | | | (1) Quarter Ended | Pro forma amounts reflect the IDR subsidies, as adjusted for the pending issuance of additional Class H Units and Class I Units discussed above, as well as distributions on the Class I Units. The issuance of additional Class H Units and Class I Units is expected to close in March 2015. |
| Record Date | | Payment Date | | Rate | (2) December 31, 2014 | Pro forma amounts reflect the IDR subsidies, as adjusted for (i) the pending issuance of additional Class H Units and Class I Units (as described in Note (1) above) and (ii) the pending Regency Merger. Amounts reflected above assume that the Regency Merger is closed subsequent to the record date for the first quarter of | February 17, 2015 distribution payment and prior to the record date for the second quarter | | February 27, 2015 distribution payment. | | 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 |
|
The amounts reflected above include the relinquishment of $350 million in the aggregate of incentive distributions that would potentially be made to ETE over the first forty fiscal quarters commencing immediately after the consummation of the Susser
Merger. Such relinquishments would cease upon the agreement of an exchange of the Sunoco LP general partner interest and the incentive distribution rights between ETE and ETP.
Sunoco Logistics Quarterly Distributions of Available Cash
Distributions declared during the periods presented were as follows:
| | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | December 31, 2012 | | February 8, 2013 | | February 14, 2013 | | $ | 0.2725 |
| March 31, 2013 | | May 9, 2013 | | May 15, 2013 | | 0.2863 |
| June 30, 2013 | | August 8, 2013 | | August 14, 2013 | | 0.3000 |
| September 30, 2013 | | November 8, 2013 | | November 14, 2013 | | 0.3150 |
| 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 |
|
Sunoco Logistics Unit Split
On May 5, 2014, Sunoco Logistics’ board of directors declared a two-for-one split of Sunoco Logistics common units. The unit split resulted in the issuance of one additional Sunoco Logistics common unit for every one unit owned as of the close of business on June 5, 2014. The unit split was effective June 12, 2014. All Sunoco Logistics unit and per unit information included in this report is presented on a post-split basis.
Sunoco LP Quarterly Distributions of Available Cash
Distributions declared by Sunoco LP subsequent to our acquisition on August 29, 2014 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 |
|
Accumulated Other Comprehensive Income (Loss) The following table presents the components of AOCI, net of tax: | | | December 31, | December 31, | | 2014 | | 2013 | 2017 | | 2016 | Available-for-sale securities | $ | 3 |
| | $ | 2 |
| $ | 8 |
| | $ | 2 |
| Foreign currency translation adjustment | (3 | ) | | (1 | ) | (5 | ) | | (5 | ) | Net loss on commodity related hedges | (1 | ) | | (4 | ) | | Actuarial gain (loss) related to pensions and other postretirement benefits | (57 | ) | | 56 |
| (5 | ) | | 7 |
| Investments in unconsolidated affiliates, net | 2 |
| | 8 |
| 5 |
| | 4 |
| Total AOCI, net of tax | $ | (56 | ) | | $ | 61 |
| | Subtotal | | 3 |
| | 8 |
| Amounts attributable to noncontrolling interest | | (3 | ) | | (8 | ) | Total AOCI included in partners’ capital, net of tax | | $ | — |
| | $ | — |
|
The tablestable below setsets forth the tax amounts included in the respective components of other comprehensive income (loss): | | | | | | | | | | December 31, | | 2017 | | 2016 | Available-for-sale securities | $ | (2 | ) | | $ | (2 | ) | Foreign currency translation adjustment | 3 |
| | 3 |
| Actuarial loss relating to pension and other postretirement benefits | 3 |
| | — |
| Total | $ | 4 |
| | $ | 1 |
|
| | 9. | UNIT-BASED COMPENSATION PLANS: |
We, ETP 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 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 12.0 million units. As of December 31, 2017, 10.8 million units remain available to be awarded under the plan. During the year ended December 31, 2017, 1.2 million ETE unit awards were granted to ETE employees and certain 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, 2017 and 2016, a total of 2,018 and 28,648 ETE Common Units vested, with a total fair value of $39 thousand and $205 thousand, respectively, as of the vesting date. As of December 31, 2017, a total of 1,251,002 restricted units remain outstanding, for which we expect to recognize a total of $21 million in compensation over a weighted average period of 3.5 years. Subsidiary Unit-Based Compensation Plans Each of ETP 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 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, and 2015 was $40 million, $40 million, and $57 million, respectively, based on the market price of the respective subsidiaries’ common units as of the vesting date. As of December 31, 2017, estimated compensation cost related to Subsidiary Unit Awards not yet recognized was $216 million, and the weighted average period over which this cost is expected to be recognized in expense is 2.8 years.
As a partnership, we are not subject to 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, | | 2017 | | 2016 | | 2015 | Current expense (benefit): | | | | | | Federal | $ | 54 |
| | $ | (47 | ) | | $ | (308 | ) | State | (16 | ) | | (34 | ) | | (54 | ) | Total | 38 |
| | (81 | ) | | (362 | ) | Deferred expense (benefit): | | | | | | Federal | (2,055 | ) | | (189 | ) | | 268 |
| State | 184 |
| | 12 |
| | (29 | ) | Total | (1,871 | ) | | (177 | ) | | 239 |
| Total income tax expense (benefit) from continuing operations | $ | (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 United States federal and most state income taxes at the partnership level. A reconciliation of income tax expense (benefit) at the United States statutory rate to the income tax expense (benefit) attributable to continuing operations for the years ended December 31, 2017, 2016 and 2015 is as follows: | | | | | | | | | | | | | | 2017 | | 2016 | | 2015 | Income tax expense (benefit) at United States statutory rate of 35 percent | $ | 248 |
| | $ | 71 |
| | $ | 316 |
| Increase (reduction) in income taxes resulting from: | | | | | | Partnership earnings not subject to tax | (477 | ) | | (576 | ) | | (355 | ) | Goodwill impairment | 207 |
| | 278 |
| | — |
| State tax, net of federal tax benefit | 124 |
| | (10 | ) | | (29 | ) | Dividend received deduction | (14 | ) | | (15 | ) | | (22 | ) | Federal rate change | (1,812 | ) | | — |
| | — |
| Audit settlement | — |
| | — |
| | (7 | ) | Change in tax status of subsidiary | (124 | ) | | — |
| | — |
| Other | 15 |
| | (6 | ) | | (26 | ) | Income tax expense (benefit) from continuing operations | $ | (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, | | 2017 | | 2016 | Deferred income tax assets: | | | | Net operating losses and alternative minimum tax credit | $ | 683 |
| | $ | 472 |
| Pension and other postretirement benefits | 21 |
| | 30 |
| Long-term debt | 14 |
| | 32 |
| Other | 191 |
| | 182 |
| Total deferred income tax assets | 909 |
| | 716 |
| Valuation allowance | (189 | ) | | (118 | ) | Net deferred income tax assets | 720 |
| | 598 |
| | | | | Deferred income tax liabilities: | | | | Property, plant and equipment | (1,036 | ) | | (1,633 | ) | Investments in unconsolidated affiliates | (2,726 | ) | | (3,789 | ) | Trademarks | (173 | ) | | (273 | ) | Other | (100 | ) | | (15 | ) | Total deferred income tax liabilities | (4,035 | ) | | (5,710 | ) | 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, | | 2017 | | 2016 | Net deferred income tax liability, beginning of year | $ | (5,112 | ) | | $ | (4,590 | ) | Goodwill associated with Sunoco Retail to Sunoco LP transaction (see Note 3) | — |
| | (460 | ) | Net assets (excluding goodwill) associated with Sunoco Retail to Sunoco LP (see Note 3) | — |
| | (243 | ) | Tax provision, including provision from discontinued operations | 1,825 |
| | 201 |
| Other | (28 | ) | | (20 | ) | Net deferred income tax liability | $ | (3,315 | ) | | $ | (5,112 | ) |
ETP Holdco and certain other corporate subsidiaries have federal net operating loss carryforward tax benefits of $403 million, all of which will expire in 2031 through 2037. Our corporate subsidiaries have $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 $274 million, $217 million net of federal tax, which expire between January 1, 2018 and 2037. A valuation allowance of $186 million is applicable to the state net operating loss carryforward benefits applicable to significant restriction on their use in the Commonwealth of 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, | | 2017 | | 2016 | | 2015 | Balance at beginning of year | $ | 615 |
| | $ | 610 |
| | $ | 440 |
| Additions attributable to tax positions taken in the current year | — |
| | 8 |
| | 178 |
| Additions attributable to tax positions taken in prior years | 28 |
| | 18 |
| | — |
| Reduction attributable to tax positions taken in prior years | (25 | ) | | (20 | ) | | — |
| Lapse of statute | (9 | ) | | (1 | ) | | (8 | ) | Balance at end of year | $ | 609 |
| | $ | 615 |
| | $ | 610 |
|
As of December 31, 2017, we have $605 million ($576 million after federal income tax benefits) related to tax positions which, if recognized, would impact our effective tax rate. Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During 2017, we recognized interest and penalties of less than $3 million. At December 31, 2017, we have interest and penalties accrued of $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, 2017. In December 2015, the Pennsylvania Commonwealth Court determined in Nextel Communications v. Commonwealth (“Nextel”) that the Pennsylvania limitation on NOL carryforward deductions violated the uniformity clause of the Pennsylvania Constitution and struck the NOL limitation in its entirety. In October 2017, the Pennsylvania Supreme Court affirmed the decision 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. has recognized approximately $67 million ($53 million after federal income tax benefits) in tax benefit based on previously filed tax returns and certain previously filed protective claims as relates to its cases currently held pending the Nextel matter. However, based upon the Pennsylvania Supreme Court’s October 2017 decision, and because of uncertainty in the breadth of the application of the decision, we have reserved $27 million ($21 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 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 previously provided contingent residual support of certain debt obligations of AmeriGas. AmeriGas has subsequently repaid the remainder of the related obligations and ETP no longer provides contingent residual support for any AmeriGas 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 (“ETC M-A”). On 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: $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 the obligation to pay the principal of each series of notes once all remedies, including in the 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 respect of the principal of such notes. ETC M-A will not otherwise be subject to the covenants of the indenture governing the 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 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, | | | 2017 | | 2016 | | 2015 | Rental expense(1) | | $ | 196 |
| | $ | 187 |
| | $ | 281 |
| Less: Sublease rental income | | (25 | ) | | (26 | ) | | (26 | ) | Rental expense, net | | $ | 171 |
| | $ | 161 |
| | $ | 255 |
|
| | (1) | Includes contingent rentals totaling $16 million, $18 million and $20 million for the years ended December 31, 2017, 2016 and 2015, respectively. |
Future minimum lease commitments for such leases are: | | | | | Years Ending December 31: | | 2018 | $ | 113 |
| 2019 | 100 |
| 2020 | 96 |
| 2021 | 83 |
| 2022 | 71 |
| Thereafter | 606 |
| Future minimum lease commitments | 1,069 |
| Less: Sublease rental income | (152 | ) | Net future minimum lease commitments | $ | 917 |
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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 On July 25, 2016, the 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. After significant delay, the USACE also issued easements to allow the pipeline to cross land owned by the USACE adjacent to the Missouri River in two locations. Also in July, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia against the USACE that challenged the legality of the permits issued for the construction of the Dakota Access pipeline across those waterways and claimed 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 intervened in the case. The SRST soon added a request for an emergency temporary restraining order (“TRO”) to stop construction on the pipeline project. On September 9, 2016, the Court denied SRST’s motion for a preliminary injunction, rendering the TRO request moot. After the September 9, 2016 ruling, the Department of the Army, the DOJ, and the Department of the Interior released a joint statement that the USACE would not grant the easement for the land adjacent to Lake Oahe until the Department of the Army completed a review to determine whether it was necessary to reconsider the USACE’s decision under various federal statutes relevant to the pipeline approval. The SRST appealed the denial of the preliminary injunction to the 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, 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 statutes governing the use of government property. 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 February 2017, in 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 allowing the pipeline to cross Lake Oahe. Almost immediately, the Cheyenne River Sioux Tribe (“CRST”), which had intervened in the lawsuit in August 2016, moved for a preliminary injunction and 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 Court denied the TRO and preliminary injunction, and the CRST appealed and requested an injunction pending appeal in the district court 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 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 halt or suspend the operation of the pipeline, we cannot assure this outcome. 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”) 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 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. Lone Star is still quantifying the extent of its incurred and ongoing damages 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 members of the petroleum industry, are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices. The plaintiffs 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, 2017, Sunoco, Inc. is a defendant in seven cases, including one case each initiated by the States of Maryland, New Jersey, Vermont, Rhode Island, one by the Commonwealth of Pennsylvania and two by the Commonwealth of Puerto Rico. The more recent Puerto Rico action is 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 pending in a multidistrict litigation proceeding in a New York federal court; one is
pending in federal court in Rhode Island, one is pending in state court in Vermont, and one is pending in state court in Maryland. Sunoco, Inc. and Sunoco, Inc. (R&M) have reached a settlement with the State of New Jersey. The Court approved the Judicial Consent Order on December 5, 2017. Dismissal of the case against Sunoco, Inc. and 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. An 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 such adverse determination occurs, but 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-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. On June 10, 2015, Adrian Dieckman (“Dieckman”), a purported Regency unitholder, filed a class action complaint, Dieckman v. Regency GP LP, et al., C.A. No. 11130-CB, in the Court of Chancery of the State of 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 Regency 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. On March 29, 2016, the Delaware Court of Chancery granted the Regency Litigation Defendants’ motion to dismiss the lawsuit in its entirety. Dieckman appealed. On January 20, 2017, the Delaware Supreme Court reversed 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 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 filed a notice of appeal with the Court of Appeals. On July 18, 2017, the Court of Appeals issued its opinion and reversed 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 due February 26, 2018. Sunoco Logistics Merger Litigation Seven purported Energy Transfer Partners, L.P. common unitholders (the “ETP Unitholder Plaintiffs”) separately filed seven putative unitholder class action lawsuits against ETP, ETP GP, ETP LLC, the members of the ETP Board, and ETE (the “ETP-SXL Defendants”) in connection with the announcement of the Sunoco Logistics Merger. Two of these lawsuits were voluntarily dismissed in March 2017. The five remaining lawsuits were consolidated as In re Energy Transfer Partners, L.P. Shareholder Litig., C.A. No. 1:17-cv-00044-CCC, in the United States District Court for the District of Delaware (the “Sunoco Logistics Merger Litigation”). The ETP Unitholder Plaintiffs allege causes of action challenging the merger and the proxy statement/prospectus filed in connection with the Sunoco Logistics Merger (the “ETP-SXL Merger Proxy”). The ETP Unitholder Plaintiffs sought rescission of the Sunoco Logistics Merger or rescissory damages for ETP unitholders, as well
as an award of costs and attorneys’ fees. On October 5, 2017, the ETP-SXL Defendants filed a Motion to Dismiss the ETP Unitholder Plaintiffs’ claims. Rather than respond to the 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 any such lawsuits might be. Nor can the ETP-SXL Defendants predict the amount of time and expense that would be required to resolve such lawsuits. The ETP-SXL Defendants believe the Sunoco Logistics Merger Litigation was without merit and intend to defend vigorously against any future lawsuits challenging the Sunoco Logistics Merger. Litigation Filed By or Against Williams On April 6, 2016, Williams 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 Williams Litigation”). Williams 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 Williams Litigation. The counterclaim asserts in general that Williams 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 Williams’ 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 Issuance against Mr. Warren in the District Court of Dallas County, Texas, which the Texas state court later dismissed based on the Merger Agreement’s forum-selection clause. On May 13, 2016, Williams 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 (collectively, “Defendants”). This lawsuit is styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., et al., C.A. No. 12337-VCG (the “Second Delaware Williams Litigation”). In general, Williams alleged that Defendants 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 concerning Section 721 of the Internal Revenue Code (“721 Opinion”), (b) breaching a representation and warranty in the Merger Agreement concerning Section 721 of the Internal Revenue Code, and (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. Williams 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. ETE filed an answer and counterclaim in the Second Delaware Williams Litigation. In addition to the counterclaims previously asserted, ETE asserted that Williams materially breached the Merger Agreement by, among other things, (a) modifying or qualifying the Williams 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, (c) failing to facilitate the financing of the merger, (d) failing to use its reasonable best efforts to consummate the 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 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 Williams’ requests for injunctive relief. The 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, styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., No. 330, 2016. Williams filed an amended complaint on September 16, 2016 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 Defendants breached an additional representation and warranty in the Merger Agreement. Defendants filed amended counterclaims and affirmative defenses on September 23, 2016 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 Defendants’ amended counterclaims and to strike certain of Defendants’ affirmative defenses. Following briefing by the parties on Williams’ motion, the Delaware Court of Chancery held oral arguments on November 30, 2016. On March 23, 2017, the Delaware Supreme Court affirmed the Court of Chancery’s Opinion and Order on the June 2016 trial 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 without merit and 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 (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. On August 29, 2016, the Issuance Plaintiffs filed a consolidated amended complaint, and in addition to the injunctive relief described above, seek class-wide damages allegedly resulting from the Issuance. 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 Issuance 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 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, 2017 and 2016, accruals of approximately $33 million and $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, 2017 or 2016 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein. 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. 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, 2017, Sunoco, Inc. had been named as a PRP at approximately 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, | | 2017 | | 2016 | Current | $ | 35 |
| | $ | 26 |
| Non-current | 337 |
| | 318 |
| Total environmental liabilities | $ | 372 |
| | $ | 344 |
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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, 2017 and 2016, the Partnership recorded $32 million and $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 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, ETP experienced a release on its products pipeline in Wellington, Ohio. In connection with this release, the PHMSA issued a Corrective Action Order under which ETP is obligated to follow specific requirements in the investigation of the release and the repair and reactivation of the pipeline. This 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. ETP has also received a “No Further Action” approval from the Ohio EPA for all soil and groundwater remediation requirements. In May 2016, ETP received a proposed penalty from the EPA and DOJ 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, ETP 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 April 2016, the PHMSA issued a NOPV, PCO and Proposed Civil Penalty related to certain procedures carried out during construction of ETP’s Permian Express 2 pipeline system in Texas. The proposed penalties are in excess of $100,000. The 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 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 our crude oil pipeline near Wortham, Texas. The proposed penalties are 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 August 2017, the PHMSA issued a NOPV and a PCO in connection with alleged violations on ETP’s Nederland to Kilgore pipeline in Texas. The case remains open with PHMSA and the proposed penalties are in excess of $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, Occupational 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 utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and 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, 2017 | | December 31, 2016 | | Notional Volume | | Maturity | | Notional Volume | | Maturity | Mark-to-Market Derivatives | | | | | | | | (Trading) | | | | | | | | Natural Gas (BBtu): | | | | | | | | Fixed Swaps/Futures | 1,078 |
| | 2018 | | (683 | ) | | 2017 | Basis Swaps IFERC/NYMEX (1) | 48,510 |
| | 2018-2020 | | 2,243 |
| | 2017 | Options – Puts | 13,000 |
| | 2018 | | — |
| | — | Power (Megawatt): | | | | | | | | Forwards | 435,960 |
| | 2018-2019 | | 391,880 |
| | 2017 - 2018 | Futures | (25,760 | ) | | 2018 | | 109,564 |
| | 2017 - 2018 | Options — Puts | (153,600 | ) | | 2018 | | (50,400 | ) | | 2017 | Options — Calls | 137,600 |
| | 2018 | | 186,400 |
| | 2017 | Crude (MBbls) – Futures | — |
| | — | | (617 | ) | | 2017 | (Non-Trading) | | | | | | | | Natural Gas (BBtu): | | | | | | | | Basis Swaps IFERC/NYMEX | 4,650 |
| | 2018-2020 | | 10,750 |
| | 2017 - 2018 | Swing Swaps IFERC | 87,253 |
| | 2018-2019 | | (5,663 | ) | | 2017 | Fixed Swaps/Futures | (4,390 | ) | | 2018-2019 | | (52,653 | ) | | 2017 - 2019 | Forward Physical Contracts | (145,105 | ) | | 2018-2020 | | (22,492 | ) | | 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 | 1,870,000 |
| | 2018 | | 1,580,000 |
| | 2017 | Fair Value Hedging Derivatives | | | | | | | | (Non-Trading) | | | | | | | | Natural Gas (BBtu): | | | | | | | | Basis Swaps IFERC/NYMEX | (39,770 | ) | | 2018 | | (36,370 | ) | | 2017 | Fixed Swaps/Futures | (39,770 | ) | | 2018 | | (36,370 | ) | | 2017 | Hedged Item — Inventory | 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 | Entity | | Term | | Type(1) | | December 31, 2017 | | December 31, 2016 | ETP | | July 2017(2) | | Forward-starting to pay a fixed rate of 3.90% and receive a floating rate | | $ | — |
| | $ | 500 |
| ETP | | July 2018(2) | | Forward-starting to pay a fixed rate of 3.76% and receive a floating rate | | 300 |
| | 200 |
| ETP | | July 2019(2) | | Forward-starting to pay a fixed rate of 3.64% and receive a floating rate | | 300 |
| | 200 |
| ETP | | 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 |
| ETP | | 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 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. 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 | | Asset Derivatives | | Liability Derivatives | | December 31, 2017 | | December 31, 2016 | | December 31, 2017 | | December 31, 2016 | Derivatives designated as hedging instruments: | | | | | | | | Commodity derivatives (margin deposits) | $ | 14 |
| | $ | — |
| | $ | (2 | ) | | $ | (4 | ) | | 14 |
| | — |
| | (2 | ) | | (4 | ) | Derivatives not designated as hedging instruments: | | | | | | | | Commodity derivatives (margin deposits) | 262 |
| | 338 |
| | (281 | ) | | (416 | ) | Commodity derivatives | 45 |
| | 25 |
| | (58 | ) | | (58 | ) | Interest rate derivatives | — |
| | — |
| | (219 | ) | | (193 | ) | Embedded derivatives in ETP Convertible Preferred Units | — |
| | — |
| | — |
| | (1 | ) | | 307 |
| | 363 |
| | (558 | ) | | (668 | ) | Total derivatives | $ | 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 | | | Balance Sheet Location | | December 31, 2017 | | December 31, 2016 | | December 31, 2017 | | December 31, 2016 | Derivatives without offsetting agreements | | Derivative assets (liabilities) | | $ | — |
| | $ | — |
| | $ | (219 | ) | | $ | (194 | ) | Derivatives in offsetting agreements: | | | | | | | | | OTC contracts | | Derivative assets (liabilities) | | 45 |
| | 25 |
| | (58 | ) | | (58 | ) | Broker cleared derivative contracts | | Other current assets (liabilities) | | 276 |
| | 338 |
| | (283 | ) | | (420 | ) | | | 321 |
| | 363 |
| | (560 | ) | | (672 | ) | Offsetting agreements: | | | | | | | | | Counterparty netting | | Derivative assets (liabilities) | | (21 | ) | | (4 | ) | | 21 |
| | 4 |
| Counterparty netting | | Other current assets (liabilities) | | (263 | ) | | (338 | ) | | 263 |
| | 338 |
| 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) 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, | | 2017 | | 2016 | | 2015 | Derivatives in fair value hedging relationships (including hedged item): | | | | | | | | Commodity derivatives | Cost of products sold | | $ | 26 |
| | $ | 14 |
| | $ | 21 |
| Total | | | $ | 26 |
| | $ | 14 |
| | $ | 21 |
|
| | | | | | | | | | | | | | | | 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 | | 5 |
| | (177 | ) | | 15 |
| Interest rate derivatives | Losses on interest rate derivatives | | (37 | ) | | (12 | ) | | (18 | ) | Embedded derivatives | Other, net | | 1 |
| | 4 |
| | 12 |
| Total | | | $ | — |
| | $ | (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 and $40 million to the 401(k) savings plan for the years ended December 31, 2017, 2016, and 2015, 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, 2017 | | December 31, 2016 | | Pension Benefits | | | | Pension 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 | $ | 18 |
| | $ | 51 |
| | $ | 166 |
| | $ | 20 |
| | $ | 57 |
| | $ | 181 |
| Interest cost | 1 |
| | 1 |
| | 4 |
| | 1 |
| | 2 |
| | 4 |
| Amendments | — |
| | — |
| | 7 |
| | — |
| | — |
| | — |
| Benefits paid, net | (2 | ) | | (6 | ) | | (20 | ) | | (1 | ) | | (7 | ) | | (21 | ) | Actuarial (gain) loss and other | 2 |
| | 1 |
| | (1 | ) | | (2 | ) | | (1 | ) | | 2 |
| Settlements | (18 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| Benefit obligation at end of period | $ | 1 |
| | $ | 47 |
| | $ | 156 |
| | $ | 18 |
| | $ | 51 |
| | $ | 166 |
| | | | | | | | | | | | | Change in plan assets: | | | | | | | | | | | | Fair value of plan assets at beginning of period | $ | 12 |
| | $ | — |
| | $ | 256 |
| | $ | 15 |
| | $ | — |
| | $ | 261 |
| Return on plan assets and other | 3 |
| | — |
| | 11 |
| | (2 | ) | | — |
| | 6 |
| Employer contributions | 6 |
| | — |
| | 10 |
| | — |
| | — |
| | 10 |
| Benefits paid, net | (2 | ) | | — |
| | (20 | ) | | (1 | ) | | — |
| | (21 | ) | Settlements | (18 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| Fair value of plan assets at end of period | $ | 1 |
| | $ | — |
| | $ | 257 |
| | $ | 12 |
| | $ | — |
| | $ | 256 |
| | | | | | | | | | | | | Amount underfunded (overfunded) at end of period | $ | — |
| | $ | 47 |
| | $ | (101 | ) | | $ | 6 |
| | $ | 51 |
| | $ | (90 | ) | | | | | | | | | | | | | Amounts recognized in the consolidated balance sheets consist of: | | | | | | | | | | | | Non-current assets | $ | — |
| | $ | — |
| | $ | 127 |
| | $ | — |
| | $ | — |
| | $ | 114 |
| Current liabilities | — |
| | (8 | ) | | (2 | ) | | — |
| | (7 | ) | | (2 | ) | Non-current liabilities | — |
| | (39 | ) | | (24 | ) | | (6 | ) | | (44 | ) | | (23 | ) | | $ | — |
| | $ | (47 | ) | | $ | 101 |
| | $ | (6 | ) | | $ | (51 | ) | | $ | 89 |
| | | | | | | | | | | | | Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of: | | | | | | | | | | | | Net actuarial gain | $ | — |
| | $ | 5 |
| | $ | (18 | ) | | $ | — |
| | $ | — |
| | $ | (13 | ) | Prior service cost | — |
| | — |
| | 21 |
| | — |
| | — |
| | 15 |
| | $ | — |
| | $ | 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, 2017 | | December 31, 2016 | | Pension Benefits | | | | Pension Benefits | | | | Funded Plans | | Unfunded Plans | | Other Postretirement Benefits | | Funded Plans | | Unfunded Plans | | Other Postretirement Benefits | Projected benefit obligation | $ | 1 |
| | $ | 47 |
| | N/A |
| | $ | 18 |
| | $ | 51 |
| | N/A |
| Accumulated benefit obligation | 1 |
| | 47 |
| | $ | 156 |
| | 18 |
| | 51 |
| | $ | 166 |
| Fair value of plan assets | 1 |
| | — |
| | 257 |
| | 12 |
| | — |
| | 256 |
|
Components of Net Periodic Benefit Cost | | | | | | | | | | | | | | | | | | December 31, 2017 | | December 31, 2016 | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Net Periodic Benefit Cost: | | | | | | | | Interest cost | $ | 2 |
| | $ | 4 |
| | $ | 3 |
| | $ | 4 |
| Expected return on plan assets | — |
| | (9 | ) | | (1 | ) | | (8 | ) | Prior service cost amortization | — |
| | 2 |
| | — |
| | 1 |
| Net periodic benefit cost | $ | 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, 2017 | | December 31, 2016 | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Discount rate | 3.27 | % | | 2.34 | % | | 3.65 | % | | 2.34 | % | Rate of compensation increase | 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, 2017 | | December 31, 2016 | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Discount rate | 3.52 | % | | 3.10 | % | | 3.60 | % | | 3.06 | % | Expected return on assets: | | | | | | | | Tax exempt accounts | 3.50 | % | | 7.00 | % | | 3.50 | % | | 7.00 | % | Taxable accounts | N/A |
| | 4.50 | % | | N/A |
| | 4.50 | % | Rate of compensation increase | 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, | | 2017 | | 2016 | Health care cost trend rate | 7.20 | % | | 6.73 | % | Rate to which the cost trend is assumed to decline (the ultimate trend rate) | 4.99 | % | | 4.96 | % | Year that the rate reaches the ultimate trend rate | 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%. 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 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 100% equities as of December 31, 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, 2017 | | | Fair Value Total | | Level 1 | | Level 2 | | Level 3 | Asset Category: | | | | | | | | | Cash and Cash Equivalents | | $ | 33 |
| | $ | 33 |
| | $ | — |
| | $ | — |
| Mutual funds (1) | | 154 |
| | 154 |
| | — |
| | — |
| Fixed income securities | | 70 |
| | — |
| | 70 |
| | — |
| Total | | $ | 257 |
| | $ | 187 |
| | $ | 70 |
| | $ | — |
|
| | (1) | Primarily comprised of approximately 38% equities, 61% fixed income securities and 2% 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) | | 142 |
| | 142 |
| | — |
| | — |
| Fixed income securities | | 91 |
| | — |
| | 91 |
| | — |
| Total | | $ | 256 |
| | $ | 165 |
| | $ | 91 |
| | $ | — |
|
| | (1) | Primarily comprised of approximately 31% equities, 66% fixed income securities and 3% cash as of December 31, 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 $8 million to pension plans and $10 million to other postretirement plans in 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: | | | | | | | | | | Years | | Pension Benefits - Unfunded Plans (1) | | Other Postretirement Benefits (Gross, Before Medicare Part D) | 2018 | | $ | 8 |
| | $ | 24 |
| 2019 | | 6 |
| | 23 |
| 2020 | | 6 |
| | 21 |
| 2021 | | 5 |
| | 19 |
| 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, ETP 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 previously paid ETP to provide services on its behalf and on behalf of other subsidiaries of ETE, which included the reimbursement of various operating and general and administrative expenses incurred by ETP on behalf of ETE and its subsidiaries. These agreements expired in 2016. In addition, subsidiaries of ETE recorded sales with affiliates of $303 million, $221 million and $290 million during the years ended December 31, 2017, 2016 and 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: 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, | | 2017 | | 2016 | | 2015 | Equity in earnings of unconsolidated affiliates: | | | | | | Investment in ETP | $ | 156 |
| | $ | 59 |
| | $ | 469 |
| Adjustments and Eliminations | (12 | ) | | 211 |
| | (193 | ) | Total equity in earnings of unconsolidated affiliates | $ | 144 |
| | $ | 270 |
| | $ | 276 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | Segment Adjusted EBITDA: | | | | | | Investment in ETP | $ | 6,712 |
| | $ | 5,733 |
| | $ | 5,517 |
| Investment in Sunoco LP | 732 |
| | 665 |
| | 719 |
| Investment in Lake Charles LNG | 175 |
| | 179 |
| | 196 |
| Corporate and Other | (31 | ) | | (170 | ) | | (104 | ) | Adjustments and Eliminations | (268 | ) | | (272 | ) | | (590 | ) | Total Segment Adjusted EBITDA | 7,320 |
| | 6,135 |
| | 5,738 |
| Depreciation, depletion and amortization | (2,554 | ) | | (2,216 | ) | | (1,951 | ) | Interest expense, net of interest capitalized | (1,922 | ) | | (1,804 | ) | | (1,622 | ) | Gains on acquisitions | — |
| | 83 |
| | — |
| Impairment of investments in unconsolidated affiliates | (313 | ) | | (308 | ) | | — |
| Impairment losses | (1,039 | ) | | (1,040 | ) | | (339 | ) | Losses on interest rate derivatives | (37 | ) | | (12 | ) | | (18 | ) | Non-cash unit-based compensation expense | (99 | ) | | (70 | ) | | (91 | ) | Unrealized gains (losses) on commodity risk management activities | 59 |
| | (136 | ) | | (65 | ) | Losses on extinguishments of debt | (89 | ) | | — |
| | (43 | ) | Inventory valuation adjustments | 24 |
| | 97 |
| | (67 | ) | Adjusted EBITDA related to discontinued operations | (223 | ) | | (199 | ) | | (228 | ) | Adjusted EBITDA related to unconsolidated affiliates | (716 | ) | | (675 | ) | | (713 | ) | Equity in earnings of unconsolidated affiliates | 144 |
| | 270 |
| | 276 |
| Other, net | 155 |
| | 79 |
| | 23 |
| 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, | | 2017 | | 2016 | | 2015 | Total assets: | | | | | | Investment in ETP | $ | 77,965 |
| | $ | 70,105 |
| | $ | 65,128 |
| Investment in Sunoco LP | 8,344 |
| | 8,701 |
| | 8,842 |
| Investment in Lake Charles LNG | 1,646 |
| | 1,508 |
| | 1,369 |
| Corporate and Other | 598 |
| | 711 |
| | 638 |
| Adjustments and Eliminations | (2,307 | ) | | (2,100 | ) | | (4,833 | ) | Total | $ | 86,246 |
| | $ | 78,925 |
| | $ | 71,144 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | 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 | $ | 5,901 |
| | $ | 5,810 |
| | $ | 8,167 |
| Investment in Sunoco LP | 103 |
| | 119 |
| | 178 |
| Investment in Lake Charles LNG | 2 |
| | — |
| | 1 |
| Adjustments and Eliminations | — |
| | — |
| | (123 | ) | Total | $ | 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, | | 2017 | | 2016 | | 2015 | Intrastate Transportation and Storage | $ | 2,891 |
| | $ | 2,155 |
| | $ | 1,912 |
| Interstate Transportation and Storage | 915 |
| | 946 |
| | 1,008 |
| Midstream | 2,510 |
| | 2,342 |
| | 2,607 |
| 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 | 2,740 |
| | 2,872 |
| | 15,216 |
| Total revenues | 29,054 |
| | 21,827 |
| | 34,292 |
| Less: Intersegment revenues | 441 |
| | 209 |
| | 136 |
| Revenues from external customers | $ | 28,613 |
| | $ | 21,618 |
| | $ | 34,156 |
|
Investment in Sunoco LP | | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | Retail operations | $ | 2,263 |
| | $ | 1,991 |
| | $ | 2,226 |
| Wholesale operations | 9,460 |
| | 7,995 |
| | 10,204 |
| Total revenues | 11,723 |
| | 9,986 |
| | 12,430 |
| Less: Intersegment revenues | 10 |
| | 9 |
| | 11 |
| Revenues from external customers | $ | 11,713 |
| | $ | 9,977 |
| | $ | 12,419 |
|
Investment in Lake Charles LNG Lake Charles LNG’s revenues of $197 million, $197 million and $216 million for the years ended December 31, 2017, 2016 and 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 | | | | March 31* | | June 30* | | September 30* | | December 31 | | Total Year | 2017: | | | | | | | | | | Revenues | $ | 9,660 |
| | $ | 9,427 |
| | $ | 9,984 |
| | $ | 11,452 |
| | $ | 40,523 |
| Operating income (loss) | 758 |
| | 746 |
| | 924 |
| | 285 |
| | 2,713 |
| Net income (loss) | 319 |
| | 121 |
| | 758 |
| | 1,168 |
| | 2,366 |
| Limited Partners’ interest in net income | 232 |
| | 204 |
| | 240 |
| | 239 |
| | 915 |
| Basic net income per limited partner unit | $ | 0.22 |
| | $ | 0.18 |
| | $ | 0.22 |
| | $ | 0.22 |
| | $ | 0.85 |
| Diluted net income per limited partner unit | $ | 0.21 |
| | $ | 0.18 |
| | $ | 0.22 |
| | $ | 0.22 |
| | $ | 0.83 |
|
| | | | | | | | | | | | | | | | | | | | | | Quarters Ended | | | | March 31* | | June 30* | | September 30* | | December 31* | | Total Year* | 2016: | | | | | | | | | | Revenues | $ | 6,447 |
| | $ | 7,866 |
| | $ | 8,156 |
| | $ | 9,323 |
| | $ | 31,792 |
| Operating income | 680 |
| | 814 |
| | 624 |
| | (275 | ) | | 1,843 |
| Net income (loss) | 320 |
| | 417 |
| | (3 | ) | | (734 | ) | | — |
| Limited Partners’ interest in net income | 311 |
| | 239 |
| | 207 |
| | 226 |
| | 983 |
| Basic net income per limited partner unit | $ | 0.30 |
| | $ | 0.23 |
| | $ | 0.20 |
| | $ | 0.22 |
| | $ | 0.94 |
| Diluted net income per limited partner unit | $ | 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, 2017 and 2016 reflected the recognition of impairment losses of $1.04 billion and $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 ETP’s interstate transportation and storage operations and midstream operations as well as Sunoco LP’s retail operations. The three months ended December 31, 2017 and December 31, 2016 reflected the recognition of a non-cash impairment of ETP’s investments in subsidiaries of $313 million and $308 million, respectively, in its 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, | | 2017 | | 2016 | ASSETS | | | | CURRENT ASSETS: | | | | Cash and cash equivalents | $ | 1 |
| | $ | 2 |
| Accounts receivable from related companies | 65 |
| | 55 |
| Other current assets | 1 |
| | — |
| Total current assets | 67 |
| | 57 |
| PROPERTY, PLANT AND EQUIPMENT, net | 27 |
| | 36 |
| ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES | 6,082 |
| | 5,088 |
| INTANGIBLE ASSETS, net | — |
| | 1 |
| GOODWILL | 9 |
| | 9 |
| OTHER NON-CURRENT ASSETS, net | 8 |
| | 10 |
| Total assets | $ | 6,193 |
| | $ | 5,201 |
| LIABILITIES AND PARTNERS’ CAPITAL | | | | CURRENT LIABILITIES: | | | | Accounts payable | $ | — |
| | $ | 1 |
| Accounts payable to related companies | — |
| | 22 |
| Interest payable | 66 |
| | 66 |
| Accrued and other current liabilities | 4 |
| | 3 |
| Total current liabilities | 70 |
| | 92 |
| LONG-TERM DEBT, less current maturities | 6,700 |
| | 6,358 |
| NOTE PAYABLE TO AFFILIATE | 617 |
| | 443 |
| OTHER NON-CURRENT LIABILITIES | 2 |
| | 2 |
| | | | | COMMITMENTS AND CONTINGENCIES |
| |
| | | | | PARTNERS’ DEFICIT: | | | | General Partner | (3 | ) | | (3 | ) | Limited Partners: | | | | 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 | (1,196 | ) | | (1,694 | ) | Total liabilities and partners’ deficit | $ | 6,193 |
| | $ | 5,201 |
|
STATEMENTS OF OPERATIONS | | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | SELLING, GENERAL AND ADMINISTRATIVE EXPENSES | $ | (31 | ) | | $ | (185 | ) | | $ | (112 | ) | OTHER INCOME (EXPENSE): | | | | | | Interest expense, net of interest capitalized | (347 | ) | | (327 | ) | | (294 | ) | Equity in earnings of unconsolidated affiliates | 1,381 |
| | 1,511 |
| | 1,601 |
| Loss on extinguishment of debt | (47 | ) | | — |
| | — |
| Other, net | (2 | ) | | (4 | ) | | (5 | ) | INCOME BEFORE INCOME TAXES | 954 |
| | 995 |
| | 1,190 |
| Income tax expense | — |
| | — |
| | 1 |
| NET INCOME | 954 |
| | 995 |
| | 1,189 |
| General Partner’s interest in net income | 2 |
| | 3 |
| | 3 |
| Convertible Unitholders’ interest in income | 37 |
| | 9 |
| | — |
| Class D Unitholder’s interest in net income | — |
| | — |
| | 3 |
| Limited Partners’ interest in net income | $ | 915 |
| | $ | 983 |
| | $ | 1,183 |
|
STATEMENTS OF CASH FLOWS | | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES | $ | 831 |
| | $ | 918 |
| | $ | 1,103 |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | Cash paid for Bakken Pipeline Transaction | — |
| | — |
| | (817 | ) | Contributions to unconsolidated affiliates | (861 | ) | | (70 | ) | | — |
| Capital expenditures | (1 | ) | | (16 | ) | | (19 | ) | Contributions in aid of construction costs | 7 |
| | — |
| | — |
| Net cash used in investing activities | (855 | ) | | (86 | ) | | (836 | ) | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | Proceeds from borrowings | 2,219 |
| | 225 |
| | 3,672 |
| Principal payments on debt | (1,881 | ) | | (210 | ) | | (1,985 | ) | Distributions to partners | (1,010 | ) | | (1,022 | ) | | (1,090 | ) | Proceeds from affiliate | 174 |
| | 176 |
| | 210 |
| Common Units issued for cash | 568 |
| | — |
| | — |
| Units repurchased under buyback program | — |
| | — |
| | (1,064 | ) | Debt issuance costs | (47 | ) | | — |
| | (11 | ) | Net cash provided by (used in) financing activities | 23 |
| | (831 | ) | | (268 | ) | INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | (1 | ) | | 1 |
| | (1 | ) | CASH AND CASH EQUIVALENTS, beginning of period | 2 |
| | 1 |
| | 2 |
| CASH AND CASH EQUIVALENTS, end of period | $ | 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, 2017 and 2016 | S - 4 | Consolidated Statements of Operations – Years Ended December 31, 2017, 2016 and 2015 | S - 6 | Consolidated Statements of Comprehensive Income – Years Ended December 31, 2017, 2016 and 2015 | S - 7 | Consolidated Statements of Equity – Years Ended December 31, 2017, 2016 and 2015 | S - 8 | Consolidated Statements of Cash Flows – Years Ended December 31, 2017, 2016 and 2015 | S - 10 | Notes to Consolidated Financial Statements | S - 12 |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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, 2017 and 2016, the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, 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, 2017, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 23, 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 23, 2018
ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Dollars in millions) | | | | | | | | | | December 31, | | 2017 | | 2016* | ASSETS | | | | Current assets: | | | | Cash and cash equivalents | $ | 306 |
| | $ | 360 |
| Accounts receivable, net | 3,946 |
| | 3,002 |
| Accounts receivable from related companies | 318 |
| | 209 |
| Inventories | 1,589 |
| | 1,626 |
| Income taxes receivable | 135 |
| | 128 |
| Derivative assets | 24 |
| | 20 |
| Other current assets | 210 |
| | 298 |
| Total current assets | 6,528 |
| | 5,643 |
| | | | | Property, plant and equipment | 67,699 |
| | 58,220 |
| Accumulated depreciation and depletion | (9,262 | ) | | (7,303 | ) | | 58,437 |
| | 50,917 |
| | | | | Advances to and investments in unconsolidated affiliates | 3,816 |
| | 4,280 |
| Other non-current assets, net | 758 |
| | 672 |
| Intangible assets, net | 5,311 |
| | 4,696 |
| Goodwill | 3,115 |
| | 3,897 |
| Total assets | $ | 77,965 |
| | $ | 70,105 |
|
* As adjusted. See Note 2.
ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Dollars in millions) | | | | | | | | | | December 31, | | 2017 | | 2016* | LIABILITIES AND EQUITY | | | | Current liabilities: | | | | Accounts payable | $ | 4,126 |
| | $ | 2,900 |
| Accounts payable to related companies | 209 |
| | 43 |
| Derivative liabilities | 109 |
| | 166 |
| Accrued and other current liabilities | 2,143 |
| | 1,905 |
| Current maturities of long-term debt | 407 |
| | 1,189 |
| Total current liabilities | 6,994 |
| | 6,203 |
| | | | | Long-term debt, less current maturities | 32,687 |
| | 31,741 |
| Long-term notes payable – related company | — |
| | 250 |
| Non-current derivative liabilities | 145 |
| | 76 |
| Deferred income taxes | 2,883 |
| | 4,394 |
| Other non-current liabilities | 1,084 |
| | 952 |
| | | | | Commitments and contingencies |
| |
|
| Legacy ETP Preferred Units | — |
| | 33 |
| Redeemable noncontrolling interests | 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 | 244 |
| | 206 |
| Accumulated other comprehensive income | 3 |
| | 8 |
| Total partners’ capital | 28,269 |
| | 18,621 |
| Noncontrolling interest | 5,882 |
| | 7,820 |
| Total equity | 34,151 |
| | 26,441 |
| Total liabilities and equity | $ | 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, | | 2017 | | 2016* | | 2015* | REVENUES: | | | | | | Natural gas sales | $ | 4,172 |
| | $ | 3,619 |
| | $ | 3,671 |
| NGL sales | 6,972 |
| | 4,841 |
| | 3,936 |
| Crude sales | 10,184 |
| | 6,766 |
| | 8,378 |
| Gathering, transportation and other fees | 4,265 |
| | 4,003 |
| | 3,997 |
| Refined product sales (see Note 3) | 1,515 |
| | 1,047 |
| | 9,958 |
| Other (see Note 3) | 1,946 |
| | 1,551 |
| | 4,352 |
| Total revenues | 29,054 |
| | 21,827 |
| | 34,292 |
| COSTS AND EXPENSES: | | | | | | Cost of products sold (see Note 3) | 20,801 |
| | 15,080 |
| | 26,714 |
| Operating expenses (see Note 3) | 2,170 |
| | 1,839 |
| | 2,608 |
| Depreciation, depletion and amortization | 2,332 |
| | 1,986 |
| | 1,929 |
| Selling, general and administrative (see Note 3) | 434 |
| | 348 |
| | 475 |
| Impairment losses | 920 |
| | 813 |
| | 339 |
| Total costs and expenses | 26,657 |
| | 20,066 |
| | 32,065 |
| OPERATING INCOME | 2,397 |
| | 1,761 |
| | 2,227 |
| OTHER INCOME (EXPENSE): | | | | | | Interest expense, net | (1,365 | ) | | (1,317 | ) | | (1,291 | ) | Equity in earnings from unconsolidated affiliates | 156 |
| | 59 |
| | 469 |
| Impairment of investments in unconsolidated affiliates | (313 | ) | | (308 | ) | | — |
| Gains on acquisitions | — |
| | 83 |
| | — |
| Losses on extinguishments of debt | (42 | ) | | — |
| | (43 | ) | Losses on interest rate derivatives | (37 | ) | | (12 | ) | | (18 | ) | Other, net | 209 |
| | 131 |
| | 22 |
| INCOME BEFORE INCOME TAX BENEFIT | 1,005 |
| | 397 |
| | 1,366 |
| Income tax benefit | (1,496 | ) | | (186 | ) | | (123 | ) | NET INCOME | 2,501 |
| | 583 |
| | 1,489 |
| Less: Net income attributable to noncontrolling interest | 420 |
| | 295 |
| | 134 |
| Less: Net loss attributable to predecessor | — |
| | — |
| | (34 | ) | NET INCOME ATTRIBUTABLE TO PARTNERS | 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 | ) | NET INCOME (LOSS) PER COMMON UNIT: | | | | | | Basic | $ | 0.94 |
| | $ | (1.38 | ) | | $ | (0.07 | ) | Diluted | $ | 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, | | 2017 | | 2016* | | 2015* | Net income | $ | 2,501 |
| | $ | 583 |
| | $ | 1,489 |
| Other comprehensive income (loss), net of tax: | | | | | | Change in value of available-for-sale securities | 6 |
| | 2 |
| | (3 | ) | Actuarial gain (loss) relating to pension and other postretirement benefits | (12 | ) | | (1 | ) | | 65 |
| Foreign currency translation adjustment | — |
| | (1 | ) | | (1 | ) | Change in other comprehensive income (loss) from unconsolidated affiliates | 1 |
| | 4 |
| | (1 | ) | | (5 | ) | | 4 |
| | 60 |
| Comprehensive income | 2,496 |
| | 587 |
| | 1,549 |
| Less: Comprehensive income attributable to noncontrolling interest | 420 |
| | 295 |
| | 134 |
| Less: Comprehensive loss attributable to predecessor | — |
| | — |
| | (34 | ) | Comprehensive income attributable to partners | $ | 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 | | | | | | | | | | | | 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, 2014* | $ | — |
| | $ | — |
| | $ | 10,427 |
| | $ | 1,512 |
| | $ | — |
| | $ | 184 |
| | $ | (56 | ) | | $ | 5,143 |
| | $ | 8,088 |
| | $ | 25,298 |
| Distributions to partners | — |
| | — |
| | (1,863 | ) | | (247 | ) | | (80 | ) | | (944 | ) | | — |
| | — |
| | — |
| | (3,134 | ) | Distributions to noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (338 | ) | | — |
| | (338 | ) | Units issued for cash | — |
| | — |
| | 1,428 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1,428 |
| Subsidiary units issued for cash | — |
| | — |
| | 298 |
| | — |
| | — |
| | 2 |
| | — |
| | 1,219 |
| | — |
| | 1,519 |
| Capital contributions from noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 875 |
| | — |
| | 875 |
| Bakken Pipeline Transaction | — |
| | — |
| | (999 | ) | | 1,946 |
| | — |
| | — |
| | — |
| | 72 |
| | — |
| | 1,019 |
| Sunoco LP Exchange Transaction | — |
| | — |
| | (52 | ) | | — |
| | — |
| | — |
| | — |
| | (940 | ) | | — |
| | (992 | ) | Susser Exchange Transaction | — |
| | — |
| | (68 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (68 | ) | Acquisition and disposition of noncontrolling interest | — |
| | — |
| | (26 | ) | | — |
| | — |
| | — |
| | — |
| | (39 | ) | | — |
| | (65 | ) | Predecessor distributions to partners | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (202 | ) | | (202 | ) | Predecessor units issued for cash | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 34 |
| | 34 |
| Regency Merger | — |
| | — |
| | 7,890 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (7,890 | ) | | — |
| Other comprehensive income, net of tax | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 60 |
| | — |
| | — |
| | 60 |
| Other, net | — |
| | — |
| | 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 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Capital contributions from noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 236 |
| | — |
| | 236 |
| Sunoco, Inc. retail business to Sunoco LP transaction | — |
| | — |
| | (405 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (405 | ) | PennTex Acquisition | — |
| | — |
| | 307 |
| | — |
| | — |
| | — |
| | — |
| | 236 |
| | — |
| | 543 |
| Other comprehensive income, net of tax | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 4 |
| | — |
| | — |
| | 4 |
| Other, net | — |
| | — |
| | 10 |
| | — |
| | — |
| | — |
| | — |
| | 21 |
| | — |
| | 31 |
| Net income (loss) | — |
| | — |
| | (1,019 | ) | | 351 |
| | 8 |
| | 948 |
| | — |
| | 295 |
| | — |
| | 583 |
| 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, | | 2017 | | 2016* | | 2015* | OPERATING ACTIVITIES: | | | | | | Net income | $ | 2,501 |
| | $ | 583 |
| | $ | 1,489 |
| Reconciliation of net income to net cash provided by operating activities: | | | | | | Depreciation, depletion and amortization | 2,332 |
| | 1,986 |
| | 1,929 |
| Deferred income taxes | (1,531 | ) | | (169 | ) | | 202 |
| Amortization included in interest expense | 2 |
| | (20 | ) | | (36 | ) | Inventory valuation adjustments | — |
| | — |
| | (58 | ) | Unit-based compensation expense | 74 |
| | 80 |
| | 79 |
| Impairment losses | 920 |
| | 813 |
| | 339 |
| Gains on acquisitions | — |
| | (83 | ) | | — |
| Losses on extinguishments of debt | 42 |
| | — |
| | 43 |
| Impairment of investments in unconsolidated affiliates | 313 |
| | 308 |
| | — |
| Distributions on unvested awards | (31 | ) | | (25 | ) | | (16 | ) | Equity in earnings of unconsolidated affiliates | (156 | ) | | (59 | ) | | (469 | ) | Distributions from unconsolidated affiliates | 440 |
| | 406 |
| | 440 |
| Other non-cash | (261 | ) | | (271 | ) | | (22 | ) | Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | (160 | ) | | (246 | ) | | (1,173 | ) | Net cash provided by operating activities | 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 |
| | — |
| Proceeds from Bakken Pipeline Transaction | — |
| | — |
| | 980 |
| Proceeds from Susser Exchange Transaction | — |
| | — |
| | 967 |
| Proceeds from sale of noncontrolling interest | — |
| | — |
| | 64 |
| Cash paid for acquisition of PennTex noncontrolling interest | (280 | ) | | — |
| | — |
| Cash paid for Vitol Acquisition, net of cash received | — |
| | (769 | ) | | — |
| Cash paid for PennTex Acquisition, net of cash received | — |
| | (299 | ) | | — |
| Cash transferred to ETE in connection with the Sunoco LP Exchange | — |
| | — |
| | (114 | ) | Cash paid for acquisition of a noncontrolling interest | — |
| | — |
| | (129 | ) | Cash paid for all other acquisitions | (264 | ) | | (159 | ) | | (675 | ) | Capital expenditures, excluding allowance for equity funds used during construction | (8,335 | ) | | (7,550 | ) | | (9,098 | ) | Contributions in aid of construction costs | 24 |
| | 71 |
| | 80 |
| Contributions to unconsolidated affiliates | (268 | ) | | (59 | ) | | (45 | ) | Distributions from unconsolidated affiliates in excess of cumulative earnings | 136 |
| | 135 |
| | 124 |
| Proceeds from the sale of assets | 35 |
| | 25 |
| | 23 |
| Change in restricted cash | — |
| | 14 |
| | 19 |
| Other | 1 |
| | 1 |
| | (16 | ) | Net cash used in investing activities | (5,473 | ) | | (6,390 | ) | | (7,820 | ) | | | | | | |
| | | | | | | | | | | | | FINANCING ACTIVITIES: | | | | | | Proceeds from borrowings | 26,736 |
| | 19,916 |
| | 22,462 |
| Repayments of long-term debt | (26,494 | ) | | (15,799 | ) | | (17,843 | ) | 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 |
| Predecessor units issued for cash | — |
| | — |
| | 34 |
| Capital contributions from noncontrolling interest | 1,214 |
| | 236 |
| | 841 |
| Distributions to partners | (3,468 | ) | | (3,542 | ) | | (3,134 | ) | Predecessor distributions to partners | — |
| | — |
| | (202 | ) | Distributions to noncontrolling interest | (430 | ) | | (481 | ) | | (338 | ) | Redemption of Legacy ETP Preferred Units | (53 | ) | | — |
| | — |
| Debt issuance costs | (83 | ) | | (22 | ) | | (63 | ) | Other | 5 |
| | 2 |
| | — |
| Net cash provided by financing activities | 934 |
| | 2,920 |
| | 4,937 |
| Decrease in cash and cash equivalents | (54 | ) | | (167 | ) | | (136 | ) | Cash and cash equivalents, beginning of period | 360 |
| | 527 |
| | 663 |
| Cash and cash equivalents, end of period | $ | 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 Partners 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, NGLs and refined 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. Recent Accounting Pronouncements ASU 2014-09 In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from 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.
The Partnership adopted ASU 2014-09 on January 1, 2018. The Partnership applied the cumulative catchup transition method and recognized the cumulative effect of the retrospective application of the standard. The effect of the retrospective application of the standard was not material. For future periods, we expect that the adoption of this standard will result in a change to revenues with offsetting changes to costs associated primarily with the designation 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 accounting for noncash consideration in multiple of our reportable segments, as well as fuel usage and loss allowances. None of these changes is expected to have a material impact on 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 in the first quarter of 2019 and 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, 2018, the Partnership 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. We do not anticipate a material impact to our financial position or results of operations as a result of the adoption of this standard. ASU 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’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance did 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, 2018, with early adoption permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and 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. 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 segment 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, | | 2017 | | 2016 | | 2015 | Accounts receivable | $ | (950 | ) | | $ | (919 | ) | | $ | 819 |
| Accounts receivable from related companies | 67 |
| | 30 |
| | (243 | ) | Inventories | 37 |
| | (497 | ) | | (157 | ) | Other current assets | 39 |
| | 83 |
| | (178 | ) | Other non-current assets, net | (94 | ) | | (78 | ) | | 188 |
| Accounts payable | 758 |
| | 972 |
| | (1,215 | ) | Accounts payable to related companies | (3 | ) | | 29 |
| | (160 | ) | Accrued and other current liabilities | (47 | ) | | 39 |
| | (83 | ) | Other non-current liabilities | 24 |
| | 33 |
| | (219 | ) | Price risk management assets and liabilities, net | 9 |
| | 62 |
| | 75 |
| Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | $ | (160 | ) | | $ | (246 | ) | | $ | (1,173 | ) |
Non-cash investing and financing activities and supplemental cash flow information are as follows: | | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | NON-CASH INVESTING ACTIVITIES: | | | | | | Accrued capital expenditures | $ | 1,059 |
| | $ | 822 |
| | $ | 896 |
| Sunoco LP limited partner interest received in exchange for contribution of the Sunoco, Inc. retail business to Sunoco LP | — |
| | 194 |
| | — |
| Net gains from subsidiary common unit transactions | — |
| | 37 |
| | 300 |
| NON-CASH FINANCING ACTIVITIES: | | | | | | Issuance of Common Units in connection with the PennTex Acquisition | $ | — |
| | $ | 307 |
| | $ | — |
| Issuance of Common Units in connection with the Regency Merger | — |
| | — |
| | 9,250 |
| Issuance of Class H Units in connection with the Bakken Pipeline Transaction | — |
| | — |
| | 1,946 |
| Contribution of assets from noncontrolling interest | 988 |
| | — |
| | 34 |
| Redemption of Common Units in connection with the Bakken Pipeline Transaction | — |
| | — |
| | 999 |
| Redemption of Common Units in connection with the Sunoco LP Exchange | — |
| | — |
| | 52 |
| SUPPLEMENTAL CASH FLOW INFORMATION: | | | | | | Cash paid for interest, net of interest capitalized | $ | 1,329 |
| | $ | 1,411 |
| | $ | 1,467 |
| Cash paid for (refund of) income taxes | 50 |
| | (229 | ) | | 71 |
|
Accounts Receivable Our 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. We have a diverse portfolio of 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 and spare parts, all of which are valued at the lower of cost or net realizable value utilizing the weighted-average cost method.
Inventories consisted of the following: | | | | | | | | | | 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, | | 2017 | | 2016 | Deposits paid to vendors | $ | 64 |
| | $ | 74 |
| Prepaid expenses and other | 146 |
| | 224 |
| Total other current assets | $ | 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 NGL 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, | | 2017 | | 2016 | Land and improvements | $ | 1,706 |
| | $ | 676 |
| Buildings and improvements (1 to 45 years) | 1,960 |
| | 1,617 |
| Pipelines and equipment (5 to 83 years) | 44,050 |
| | 36,356 |
| Natural gas and NGL storage facilities (5 to 46 years) | 1,681 |
| | 1,452 |
| Bulk storage, equipment and facilities (2 to 83 years) | 3,036 |
| | 3,701 |
| Vehicles (1 to 25 years) | 124 |
| | 217 |
| Right of way (20 to 83 years) | 3,424 |
| | 3,349 |
| Natural resources | 434 |
| | 434 |
| Other (1 to 40 years) | 534 |
| | 484 |
| Construction work-in-process | 10,750 |
| | 9,934 |
| | 67,699 |
| | 58,220 |
| Less – Accumulated depreciation and depletion | (9,262 | ) | | (7,303 | ) | Property, plant and equipment, net | $ | 58,437 |
| | $ | 50,917 |
|
We recognized the following amounts for the periods presented: | | | | | | | | | | December 31, | | 2014 | | 2013 | Available-for-sale securities | $ | (1 | ) | | $ | (1 | ) | Foreign currency translation adjustment | 2 |
| | 1 |
| Actuarial gain relating to pension and other postretirement benefits | (37 | ) | | (39 | ) | Total | $ | (36 | ) | | $ | (39 | ) |
| | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | Depreciation and depletion expense | $ | 2,060 |
| | $ | 1,793 |
| | $ | 1,713 |
| 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, | | 2017 | | 2016 | Regulatory assets | $ | 85 |
| | $ | 86 |
| Deferred charges | 210 |
| | 217 |
| Restricted funds | 192 |
| | 190 |
| Long-term affiliated receivable | 85 |
| | 90 |
| Other | 186 |
| | 89 |
| Total other non-current assets, net | $ | 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, 2017 | | December 31, 2016 | | Gross Carrying Amount | | Accumulated Amortization | | Gross Carrying Amount | | Accumulated Amortization | Amortizable intangible assets: | | | | | | | | Customer relationships, contracts and agreements (3 to 46 years) | $ | 6,250 |
| | $ | (1,003 | ) | | $ | 5,362 |
| | $ | (737 | ) | Patents (10 years) | 48 |
| | (26 | ) | | 48 |
| | (21 | ) | Trade Names (20 years) | 66 |
| | (25 | ) | | 66 |
| | (22 | ) | Other (5 to 20 years) | 1 |
| | — |
| | 2 |
| | (2 | ) | Total intangible assets | $ | 6,365 |
| | $ | (1,054 | ) | | $ | 5,478 |
| | $ | (782 | ) |
Aggregate amortization expense of intangible assets was as follows: | | | | | | | | | | | | | | 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: | | 2018 | $ | 280 |
| 2019 | 278 |
| 2020 | 278 |
| 2021 | 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 NGL 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 | | NGL and Refined Products Transportation and Services | | Crude Oil Transportation and Services | | All Other | | Total | 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 | — |
| | (262 | ) | | — |
| | (79 | ) | | — |
| | (452 | ) | | (793 | ) | Other | — |
| | — |
| | (1 | ) | | — |
| | — |
| | — |
| | (1 | ) | 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 $99 million in the interstate transportation and storage segment and $106 million in the NGL and refined products transportation and services segment primarily due to market declines in current and expected future commodity prices in the fourth quarter of 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 discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as of December 31, 2017 and 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. We 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. As of December 31, 2017 and 2016, other non-current liabilities in the Partnership’s consolidated balance 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 $2 million and $14 million, and were reflected as property, plant and equipment on our balance sheet as of December 31, 2017 and 2016, respectively. In addition, the Partnership had $21 million and $13 million legally restricted funds for the purpose of settling AROs that was reflected as other non-current assets as of December 31, 2017 and 2016, respectively. Accrued and Other Current Liabilities Accrued and other current liabilities consisted of the following: | | | | | | | | | | December 31, | | 2017 | | 2016 | Interest payable | $ | 443 |
| | $ | 440 |
| Customer advances and deposits | 59 |
| | 56 |
| Accrued capital expenditures | 1,006 |
| | 749 |
| Accrued wages and benefits | 208 |
| | 212 |
| Taxes payable other than income taxes | 108 |
| | 63 |
| Exchanges payable | 154 |
| | 208 |
| Other | 165 |
| | 177 |
| Total accrued and other current liabilities | $ | 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 our consolidated subsidiaries has the option to sell its interests to 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, 2017 was $34.28 billion and $33.09 billion, respectively. As of December 31, 2016, the aggregate fair value and carrying amount of our debt obligations was $33.85 billion and $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. During the year ended December 31, 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, 2017 and 2016 based on inputs used to derive their fair values: | | | | | | | | | | | | | | Fair Value Total | | Fair Value Measurements at December 31, 2017 | | Level 1 | | Level 2 | Assets: | | | | | | Commodity derivatives: | | | | | | Natural Gas: | | | | | | Basis Swaps IFERC/NYMEX | $ | 11 |
| | $ | 11 |
| | $ | — |
| Swing Swaps IFERC | 13 |
| | — |
| | 13 |
| Fixed Swaps/Futures | 70 |
| | 70 |
| | — |
| Forward Physical Swaps | 8 |
| | — |
| | 8 |
| Power: | | | | | | Forwards | 23 |
| | — |
| | 23 |
| Natural Gas Liquids – Forwards/Swaps | 193 |
| | 193 |
| | — |
| Crude – Futures | 2 |
| | 2 |
| | — |
| Total commodity derivatives | 320 |
| | 276 |
| | 44 |
| Other non-current assets | 21 |
| | 14 |
| | 7 |
| Total assets | $ | 341 |
| | $ | 290 |
| | $ | 51 |
| Liabilities: | | | | | | Interest rate derivatives | $ | (219 | ) | | $ | — |
| | $ | (219 | ) | Commodity derivatives: | | | | | | Natural Gas: | | | | | | Basis Swaps IFERC/NYMEX | (24 | ) | | (24 | ) | | — |
| Swing Swaps IFERC | (15 | ) | | (1 | ) | | (14 | ) | Fixed Swaps/Futures | (57 | ) | | (57 | ) | | — |
| Forward Physical Swaps | (2 | ) | | — |
| | (2 | ) | Power – Forwards | (22 | ) | | — |
| | (22 | ) | Natural Gas Liquids – Forwards/Swaps | (192 | ) | | (192 | ) | | — |
| Refined Products – Futures | (25 | ) | | (25 | ) | | — |
| Crude – Futures | (1 | ) | | (1 | ) | | — |
| Total commodity derivatives | (338 | ) | | (300 | ) | | (38 | ) | Total liabilities | $ | (557 | ) | | $ | (300 | ) | | $ | (257 | ) |
| | | | | | | | | | | | | | | | | | 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 Cost 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, 2015, 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 by our 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, and 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 The 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 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. Changes 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 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: |
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. 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, ETP contributed 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 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 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’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”), which increased Sunoco 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.
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 provided substantially all of the remaining capital necessary to complete the projects. As of December 31, 2017, $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, 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: | | | | | | Year Ended December 31, 2015 | Revenues | $ | 12,482 |
| Cost of products sold | 11,174 |
| Operating expenses | 798 |
| Selling, general and administrative expenses | 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 in 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 31.5 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 provided 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. At December 31, 2017, the Partnership held 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 46.2 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 entitled 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 provided 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 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 and 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 0.6186 Partnership common units. ETP issued 258.3 million Partnership common units to Regency unitholders, including 23.3 million units issued to Partnership subsidiaries. Regency’s 1.9 million outstanding Series A Convertible Preferred Units were converted into corresponding Legacy 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.
| | 4. | ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES: |
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, an approximately 5,360-mile natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula. Our investment in Citrus is reflected in our 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, 2017, the Partnership’s interest in Sunoco LP common units consisted of 43.5 million units, representing 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, Citrus, FEP, MEP, HPC and Sunoco LP (on a 100% basis) for all periods presented: | | | | | | | | | | December 31, | | 2017 | | 2016 | Current assets | $ | 4,750 |
| | $ | 1,532 |
| Property, plant and equipment, net | 9,893 |
| | 10,310 |
| Other assets | 2,286 |
| | 5,980 |
| Total assets | $ | 16,929 |
| | $ | 17,822 |
| | | | | Current liabilities | $ | 2,075 |
| | $ | 1,918 |
| Non-current liabilities | 9,375 |
| | 10,343 |
| Equity | 5,479 |
| | 5,561 |
| Total liabilities and equity | $ | 16,929 |
| | $ | 17,822 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | Revenue | $ | 13,081 |
| | $ | 11,150 |
| | $ | 13,815 |
| Operating income | 636 |
| | 859 |
| | 1,052 |
| 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, | | 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, | | 2017 | | 2016 | ETP Debt | | | | 6.125% Senior Notes due February 15, 2017 | $ | — |
| | $ | 400 |
| 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 |
| 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 |
|
| | | | | | | | | 4.15% Senior Notes due October 1, 2020 | 1,050 |
| | 1,050 |
| 4.40% Senior Notes due April 1, 2021 | 600 |
| | 600 |
| 6.50% Senior Notes due July 15, 2021 | — |
| | 500 |
| 4.65% Senior Notes due June 1, 2021 | 800 |
| | 800 |
| 5.20% Senior Notes due February 1, 2022 | 1,000 |
| | 1,000 |
| 4.65% Senior Notes due February 15, 2022 | 300 |
| | 300 |
| 5.875% Senior Notes due March 1, 2022 | 900 |
| | 900 |
| 5.00% Senior Notes due October 1, 2022 | 700 |
| | 700 |
| 3.45% Senior Notes due January 15, 2023 | 350 |
| | 350 |
| 3.60% Senior Notes due February 1, 2023 | 800 |
| | 800 |
| 5.50% Senior Notes due April 15, 2023 | — |
| | 700 |
| 4.50% Senior Notes due November 1, 2023 | 600 |
| | 600 |
| 4.90% Senior Notes due February 1, 2024 | 350 |
| | 350 |
| 7.60% Senior Notes due February 1, 2024 | 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 |
| 5.95% Senior Notes due December 1, 2025 | 400 |
| | 400 |
| 4.75% Senior Notes due January 15, 2026 | 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 |
| 4.90% Senior Notes due March 15, 2035 | 500 |
| | 500 |
| 6.625% Senior Notes due October 15, 2036 | 400 |
| | 400 |
| 7.50% Senior Notes due July 1, 2038 | 550 |
| | 550 |
| 6.85% Senior Notes due February 15, 2040 | 250 |
| | 250 |
| 6.05% Senior Notes due June 1, 2041 | 700 |
| | 700 |
| 6.50% Senior Notes due February 1, 2042 | 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 |
| 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 |
| Deferred debt issuance costs | (1 | ) | | (1 | ) | | 574 |
| | 656 |
| Panhandle Debt | | | | 6.20% Senior Notes due November 1, 2017 | — |
| | 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 | 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) | As of December 31, 2017 management had the intent and ability to refinance the $650 million 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 based 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 $118 million in unamortized net premiums, fair value adjustments and deferred debt issuance costs: | | | | | | 2018 | | $ | 1,700 |
| 2019 | | 3,500 |
| 2020 | | 1,875 |
| 2021 | | 1,400 |
| 2022 | | 5,346 |
| Thereafter | | 19,391 |
| Total | | $ | 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 Senior Notes 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 as 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 4.39% at December 31, 2017. Credit Facilities and Commercial Paper ETP Credit Facilities On 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 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. We use the ETP Credit Facilities to provide temporary financing for our 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 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”), 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. In connection with the Sunoco Logistics Merger, the 364-Day Credit Facility was terminated and repaid in May 2017. Bakken Credit Facility In August 2016, Energy Transfer Partners, L.P., Sunoco Logistics and Phillips 66 completed project-level financing of the 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, 2017, the Bakken Credit Facility had $2.50 billion of outstanding borrowings. The weighted average interest rate on the total amount outstanding as of December 31, 2017 was 3.00%. PennTex Revolving Credit Facility PennTex previously maintained a $275 million revolving credit commitment (the “PennTex Revolving Credit Facility”). In August 2017, the PennTex Revolving Credit Facility was 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 Facilities 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 Facilities) during certain Defaults (as defined in the ETP Credit Facilities) and during any Event of Default (as defined in the ETP Credit 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 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 Facilities also limit us, on a rolling four quarter basis, to a maximum Consolidated Funded Indebtedness to Consolidated EBITDA ratio, as defined in the underlying credit agreements, of 5.0 to 1, which can generally be increased to 5.5 to 1 during a Specified Acquisition Period. Our Leverage Ratio was 3.96 to 1 at December 31, 2017, as calculated in accordance with the 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 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. Compliance with our Covenants We were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2017.
| | 7. | LEGACY ETP PREFERRED UNITS: |
The Legacy ETP Preferred Units were mandatorily redeemable on September 2, 2029 for $35 million plus all accrued but unpaid distributions and interest thereon and were reflected as long-term liabilities in our consolidated balance sheets. The Legacy ETP Preferred Units were 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. In January 2017, ETP repurchased all of its 1.9 million outstanding Legacy 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 I Units, Class J Units and Class K 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, | | 2017 (1) | | 2016 (1) | | 2015 (1) | Number of Common Units, beginning of period | 794.8 |
| | 758.5 |
| | 533.4 |
| Common Units redeemed in connection with certain transactions | — |
| | (26.7 | ) | | (77.8 | ) | Common Units issued in connection with public offerings | 54.0 |
| | — |
| | — |
| Common Units issued in connection with certain acquisitions | — |
| | 13.3 |
| | 258.2 |
| Common Units issued in connection with the Distribution Reinvestment Plan | 12.0 |
| | 9.9 |
| | 11.7 |
| Common Units issued in connection with Equity Distribution Agreements | 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 | 1.6 |
| | 0.8 |
| | 1.3 |
| Number of Common Units, end of period | 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 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 $1.00 billion. During the year ended December 31, 2017, we issued 22.6 million units for $503 million, net of commissions of $5 million. As of December 31, 2017, $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 and 2015, aggregate distributions of $228 million, $216 million, and $360 million, respectively, were reinvested under the DRIP resulting in the issuance in aggregate of 25.5 million Common Units. As of December 31, 2017, a total of 20.8 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 23.7 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. As the Class E Units are owned by a wholly-owned subsidiary, 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 the Class E Units at a future date. Class G Units There are currently 90.7 million Class G Units outstanding, all of which are held by a wholly-owned subsidiary of the Partnership. The Class G Units generally do not have any voting rights. The Class G Units are 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 G Unit per year. Allocations 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 reflected as treasury units in the consolidated financial statements. Class H Units 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 were 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. The Class H units were cancelled in connection with the merger of ETP and Sunoco Logistics in April 2017. Class I Units In connection with the 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 ended 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 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. 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, 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, 2017, a total of 101.5 million Class K Units were held by wholly-owned subsidiaries of ETP. Sales of Common Units by legacy 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 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 Sunoco Logistics Merger, the previous Sunoco Logistics equity distribution agreement was terminated. ETP Preferred Units In November 2017, ETP issued 950,000 of its 6.250% Series A Preferred Units at a price of $1,000 per unit, and 550,000 of 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 date of original 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 not previously owned by ETP for $20.00 per common unit in cash. ETP now owns all of the economic interests of PennTex, and PennTex common units are no longer publicly traded or listed on the NASDAQ. Quarterly Distributions of Available Cash Under the Partnership’s limited partnership agreement, within 45 days after the end of each quarter, the Partnership distributes all cash on hand at the end of the quarter, less reserves established by the general partner in its discretion. This is defined as “available cash” in the partnership agreement. The general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct the Partnership’s business. The Partnership will make quarterly distributions to the extent 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.” The following table shows the target distribution levels and distribution “splits” between the general and limited partners and the holders of the Partnership’s incentive distribution rights (”IDRs”): | | | | | | | | | | | | 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 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, ETE has agreed to relinquish its right to the following amounts of incentive distributions in future periods: | | | | | | | | Total Year | 2018 | | $ | 153 |
| 2019 | | 128 |
| Each year beyond 2019 | | 33 |
|
Distributions declared and paid by ETP to the preferred unitholders were as follows: | | | | | | | | | | | | | | | 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, | | 2017 | | 2016 | Available-for-sale securities | $ | 8 |
| | $ | 2 |
| Foreign currency translation adjustment | (5 | ) | | (5 | ) | Actuarial gain related to pensions and other postretirement benefits | (5 | ) | | 7 |
| Investments in unconsolidated affiliates, net | 5 |
| | 4 |
| Total AOCI, net of tax | $ | 3 |
| | $ | 8 |
|
The table below sets forth the tax amounts included in the respective components of other comprehensive income: | | | | | | | | | | December 31, | | 2017 | | 2016 | Available-for-sale securities | $ | (2 | ) | | $ | (2 | ) | Foreign currency translation adjustment | 3 |
| | 3 |
| Actuarial loss relating to pension and other postretirement benefits | 3 |
| | — |
| Total | $ | 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, 2014,2017, an aggregate total of 5.48.4 million ETP Common Units remain available to be awarded under our equity incentive plans. Restricted UnitsPension and Other Postretirement Benefit Plans
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.Panhandle
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 | Unvested awards as of December 31, 2013 | 3.2 |
| | $ | 49.65 |
| Awards granted | 1.0 |
| | 60.85 |
| Awards vested | (0.5 | ) | | 48.12 |
| Awards forfeited | (0.1 | ) | | 32.36 |
| Unvested awards as of December 31, 2014 | 3.6 |
| | 53.83 |
|
DuringPostretirement 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, 2013retiree 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 weighted average grant-date fair value per unit award grantedtrust. 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, 2017 | | December 31, 2016 | | Pension Benefits | | | | Pension 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 | $ | 18 |
| | $ | 51 |
| | $ | 166 |
| | $ | 20 |
| | $ | 57 |
| | $ | 181 |
| Interest cost | 1 |
| | 1 |
| | 4 |
| | 1 |
| | 2 |
| | 4 |
| Amendments | — |
| | — |
| | 7 |
| | — |
| | — |
| | — |
| Benefits paid, net | (2 | ) | | (6 | ) | | (20 | ) | | (1 | ) | | (7 | ) | | (21 | ) | Actuarial (gain) loss and other | 2 |
| | 1 |
| | (1 | ) | | (2 | ) | | (1 | ) | | 2 |
| Settlements | (18 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| Benefit obligation at end of period | $ | 1 |
| | $ | 47 |
| | $ | 156 |
| | $ | 18 |
| | $ | 51 |
| | $ | 166 |
| | | | | | | | | | | | | Change in plan assets: | | | | | | | | | | | | Fair value of plan assets at beginning of period | $ | 12 |
| | $ | — |
| | $ | 256 |
| | $ | 15 |
| | $ | — |
| | $ | 261 |
| Return on plan assets and other | 3 |
| | — |
| | 11 |
| | (2 | ) | | — |
| | 6 |
| Employer contributions | 6 |
| | — |
| | 10 |
| | — |
| | — |
| | 10 |
| Benefits paid, net | (2 | ) | | — |
| | (20 | ) | | (1 | ) | | — |
| | (21 | ) | Settlements | (18 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| Fair value of plan assets at end of period | $ | 1 |
| | $ | — |
| | $ | 257 |
| | $ | 12 |
| | $ | — |
| | $ | 256 |
| | | | | | | | | | | | | Amount underfunded (overfunded) at end of period | $ | — |
| | $ | 47 |
| | $ | (101 | ) | | $ | 6 |
| | $ | 51 |
| | $ | (90 | ) | | | | | | | | | | | | | Amounts recognized in the consolidated balance sheets consist of: | | | | | | | | | | | | Non-current assets | $ | — |
| | $ | — |
| | $ | 127 |
| | $ | — |
| | $ | — |
| | $ | 114 |
| Current liabilities | — |
| | (8 | ) | | (2 | ) | | — |
| | (7 | ) | | (2 | ) | Non-current liabilities | — |
| | (39 | ) | | (24 | ) | | (6 | ) | | (44 | ) | | (23 | ) | | $ | — |
| | $ | (47 | ) | | $ | 101 |
| | $ | (6 | ) | | $ | (51 | ) | | $ | 89 |
| | | | | | | | | | | | | Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of: | | | | | | | | | | | | Net actuarial gain | $ | — |
| | $ | 5 |
| | $ | (18 | ) | | $ | — |
| | $ | — |
| | $ | (13 | ) | Prior service cost | — |
| | — |
| | 21 |
| | — |
| | — |
| | 15 |
| | $ | — |
| | $ | 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, 2017 | | December 31, 2016 | | Pension Benefits | | | | Pension Benefits | | | | Funded Plans | | Unfunded Plans | | Other Postretirement Benefits | | Funded Plans | | Unfunded Plans | | Other Postretirement Benefits | Projected benefit obligation | $ | 1 |
| | $ | 47 |
| | N/A |
| | $ | 18 |
| | $ | 51 |
| | N/A |
| Accumulated benefit obligation | 1 |
| | 47 |
| | $ | 156 |
| | 18 |
| | 51 |
| | $ | 166 |
| Fair value of plan assets | 1 |
| | — |
| | 257 |
| | 12 |
| | — |
| | 256 |
|
Components of Net Periodic Benefit Cost | | | | | | | | | | | | | | | | | | December 31, 2017 | | December 31, 2016 | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Net Periodic Benefit Cost: | | | | | | | | Interest cost | $ | 2 |
| | $ | 4 |
| | $ | 3 |
| | $ | 4 |
| Expected return on plan assets | — |
| | (9 | ) | | (1 | ) | | (8 | ) | Prior service cost amortization | — |
| | 2 |
| | — |
| | 1 |
| Net periodic benefit cost | $ | 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, 2017 | | December 31, 2016 | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Discount rate | 3.27 | % | | 2.34 | % | | 3.65 | % | | 2.34 | % | Rate of compensation increase | 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, 2017 | | December 31, 2016 | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Discount rate | 3.52 | % | | 3.10 | % | | 3.60 | % | | 3.06 | % | Expected return on assets: | | | | | | | | Tax exempt accounts | 3.50 | % | | 7.00 | % | | 3.50 | % | | 7.00 | % | Taxable accounts | N/A |
| | 4.50 | % | | N/A |
| | 4.50 | % | Rate of compensation increase | N/A |
| | N/A |
| | N/A |
| | N/A |
|
The long-term expected rate of return on plan assets was $60.85, $50.54estimated based on a variety of factors including the historical investment return achieved over a long-term period, the targeted allocation of plan assets and $43.93, respectively. 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, | | 2017 | | 2016 | Health care cost trend rate | 7.20 | % | | 6.73 | % | Rate to which the cost trend is assumed to decline (the ultimate trend rate) | 4.99 | % | | 4.96 | % | Year that the rate reaches the ultimate trend rate | 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%. 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 awards vested was $26 million, $29 million and $29 million, respectively, based on the market price of ETP Common Units as of the vesting date. As of December 31, 2014, a total of 3.6 million unit awards remain unvested, for which ETP expects to recognize a total of $128 million in compensation expense over a weighted average period of 2.0 years. Cash Restricted Units. The Partnership has also granted cash restricted units, which vest 100%pension plan assets by asset category at the end of the third year of service. A cash restricted unit entitles the award recipient to receive cash equal to the market value of one ETP Common Unit upon vesting.dates indicated is as follows:
As of December 31, 2014, a total of 0.4 million unvested cash restricted units were outstanding.Based on the trading price of ETP Common Units at December 31, 2014, the Partnership expects to recognize $24 million of unit-based compensation expense related to non-vested cash restricted units over a period of 1.8 years.
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 and unit options of Sunoco Logistics covering an additional 0.7 million Sunoco Logistics common units. As of December 31, 2014, a total of 1.5 million Sunoco Logistics restricted units were outstanding for which Sunoco Logistics expects to recognize $33 million of expense over a weighted average period of 2.9 years. | | | | | | | | | | | | | | | | | | | | | | 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 |
| | $ | — |
| | $ | — |
|
| | 10.(1) | INCOME TAXES:Comprised of 100% equities as of December 31, 2017. |
As a partnership, we are not subject to U.S. 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, | | 2014 | | 2013 | | 2012 | Current expense (benefit): | | | | | | Federal | $ | 321 |
| | $ | 51 |
| | $ | (3 | ) | State | 81 |
| | (2 | ) | | 4 |
| Total | 402 |
| | 49 |
| | 1 |
| Deferred expense (benefit): | | | | | | Federal | (50 | ) | | (6 | ) | | 45 |
| State | 3 |
| | 54 |
| | 17 |
| Total | (47 | ) | | 48 |
| | 62 |
| Total income tax expense from continuing operations | $ | 355 |
| | $ | 97 |
| | $ | 63 |
|
Historically, our effective rate differed from the statutory rate primarily due to Partnership earnings that are not subject to U.S. 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. statutory rate to the income tax expense (benefit) attributable to continuing operations for the years ended December 31, 2014 and 2013 is as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2014 | | December 31, 2013 | | Corporate Subsidiaries(1) | | Partnership(2) | | Consolidated | | Corporate Subsidiaries(1) | | Partnership(2) | | Consolidated | Income tax expense (benefit) at U.S. statutory rate of 35 percent | $ | 217 |
| | $ | — |
| | $ | 217 |
| | $ | (166 | ) | | $ | — |
| | $ | (166 | ) | Increase (reduction) in income taxes resulting from: | | | | |
|
| | | | | | | Nondeductible goodwill | — |
| | — |
| | — |
| | 241 |
| | — |
| | 241 |
| Nondeductible goodwill included in the Lake Charles LNG Transaction | 105 |
| | — |
| | 105 |
| | — |
| | — |
| | — |
| State income taxes (net of federal income tax effects) | 9 |
| | 42 |
| | 51 |
| | 31 |
| | 5 |
| | 36 |
| Premium on debt retirement | (10 | ) | | — |
| | (10 | ) | | — |
| | — |
| | — |
| Foreign | (8 | ) | | — |
| | (8 | ) | | — |
| | — |
| | — |
| Other | — |
| | — |
| | — |
| | (13 | ) | | (1 | ) | | (14 | ) | Income tax from continuing operations | $ | 313 |
|
| $ | 42 |
| | $ | 355 |
| | $ | 93 |
| | $ | 4 |
| | $ | 97 |
|
| | | | | | | | | | | | | | | | | | | | | | 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) | Includes ETP Holdco, Susser, Oasis Pipeline Company, Susser Petroleum Property Company LLC, Aloha Petroleum Ltd., Inland Corporation, Mid-Valley Pipeline Company and West Texas Gulf Pipeline Company. ETP Holdco, which was formed via the Sunoco Merger and the ETP Holdco Transaction (see Note 3), includes Sunoco, Inc. and Panhandle. ETE held a 60% interest in ETP Holdco until April 30, 2013. Subsequent to the ETP Holdco Acquisition (see Note 3) on April 30, 2013, ETP ownsComprised of 100% equities as of ETP Holdco.December 31, 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, 2017 | | | Fair Value Total | | Level 1 | | Level 2 | | Level 3 | Asset Category: | | | | | | | | | Cash and Cash Equivalents | | $ | 33 |
| | $ | 33 |
| | $ | — |
| | $ | — |
| Mutual funds (1) | | 154 |
| | 154 |
| | — |
| | — |
| Fixed income securities | | 70 |
| | — |
| | 70 |
| | — |
| Total | | $ | 257 |
| | $ | 187 |
| | $ | 70 |
| | $ | — |
|
| | (2)(1)
| Includes ETPPrimarily comprised of approximately 38% equities, 61% fixed income securities and its subsidiaries that are classified2% cash as pass-through entities for federal income tax purposes.of December 31, 2017. |
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, | | 2014 | | 2013 | Deferred income tax assets: | | | | Net operating losses and alternative minimum tax credit | $ | 116 |
| | $ | 217 |
| Pension and other postretirement benefits | 47 |
| | 57 |
| Long term debt | 53 |
| | 108 |
| Other | 111 |
| | 104 |
| Total deferred income tax assets | 327 |
| | 486 |
| Valuation allowance | (84 | ) | | (74 | ) | Net deferred income tax assets | $ | 243 |
| | $ | 412 |
| | | | | Deferred income tax liabilities: | | | | Properties, plants and equipment | $ | (1,486 | ) | | $ | (1,522 | ) | Inventory | (153 | ) | | (302 | ) | Investment in unconsolidated affiliates | (2,528 | ) | | (2,244 | ) | Trademarks | (355 | ) | | (180 | ) | Other | (32 | ) | | (45 | ) | Total deferred income tax liabilities | (4,554 | ) | | (4,293 | ) | Net deferred income tax liability | (4,311 | ) | | (3,881 | ) | Less: current portion of deferred income tax liabilities, net | (85 | ) | | (119 | ) | Accumulated deferred income taxes | $ | (4,226 | ) | | $ | (3,762 | ) |
The completion of the Southern Union Merger, Sunoco Merger, ETP Holdco Transaction and Susser Merger (see Note 3) significantly increased the deferred tax assets (liabilities). The table below provides a rollforward of the net deferred income tax liability as follows:
| | | | | | | | | | December 31, | | 2014 | | 2013 | Net deferred income tax liability, beginning of year | $ | (3,881 | ) | | $ | (3,606 | ) | Susser acquisition | (488 | ) | | — |
| SUGS Contribution to Regency | — |
| | (115 | ) | Tax provision (including discontinued operations) | 58 |
| | (111 | ) | Other | — |
| | (49 | ) | Net deferred income tax liability | $ | (4,311 | ) | | $ | (3,881 | ) |
ETP Holdco, Susser and other corporate subsidiaries have gross federal net operating loss carryforwards of $5 million, all of which will expire in 2032 and 2033. Our corporate subsidiaries had less than $1 million of federal alternative minimum tax credits at December 31, 2014. Our corporate subsidiaries have state net operating loss carryforward benefits of $111 million, net of federal tax, which expire between 2014 and 2033. The valuation allowance of $84 million is applicable to the state net operating loss carryforward benefits applicable to Sunoco, Inc. pre-acquisition periods.
The following table sets forth the changes in unrecognized tax benefits:
| | | | | | | | | | | | | | Years Ended December 31, | | 2014 | | 2013 | | 2012 | Balance at beginning of year | $ | 429 |
| | $ | 27 |
| | $ | 2 |
| Additions attributable to acquisitions | — |
| | — |
| | 28 |
| Additions attributable to tax positions taken in the current year | 20 |
| | — |
| | — |
| Additions attributable to tax positions taken in prior years | (1 | ) | | 406 |
| | — |
| Settlements | (5 | ) | | — |
| | — |
| Lapse of statute | (3 | ) | | (4 | ) | | (3 | ) | Balance at end of year | $ | 440 |
| | $ | 429 |
| | $ | 27 |
|
As of December 31, 2014, we have $439 million ($425 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 $4 million ($2 million, net of federal tax) within the next twelve months due to settlement of certain positions.
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 open statute years, Sunoco, Inc. has proposed to the IRS that these government incentive payments be excluded from federal taxable income. If Sunoco, Inc. is fully successful with its claims, it will receive tax refunds of approximately $372 million. However, due to the uncertainty surrounding the claims, a reserve of $372 million was established for the full amount of the claims. Due to the timing of the expected settlement of the claims and the related reserve, the receivable and the reserve for this issue have been netted in the financial statements as of December 31, 2014.
Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During 2014, we recognized interest and penalties of less than $1 million. At December 31, 2014, we have interest and penalties accrued of $6 million, net of tax.
In general, ETP and its subsidiaries are no longer subject to examination by the IRS for the 2010 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 and Southern Union and its subsidiaries are no longer subject to examination by the IRS for tax years prior to 2004.
Sunoco, Inc. has been examined by the IRS for tax years through 2012. 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. Southern Union is under examination for the tax years 2004 through 2009. As of December 31, 2014, the IRS has proposed only one adjustment for the years under examination. For the 2006 tax year, the IRS is challenging $545 million of the $690 million of deferred gain associated with a like kind exchange involving certain assets of its distribution operations and its gathering and processing operations. We have vigorously defended this tax position and believe we have reached a tentative settlement with the IRS which will not have a material impact on our consolidated financial position or results of operations.
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.
| | 11. | REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES: |
Contingent Matters Potentially Impacting the Partnership from Our Investment in Citrus
Florida Gas Pipeline Relocation Costs. The Florida Department of Transportation, Florida’s Turnpike Enterprise (“FDOT/FTE”) has various turnpike/State Road 91 widening projects that have impacted or may, over time, impact one or more of FGTs’ mainline pipelines located in FDOT/FTE rights-of-way. Certain FDOT/FTE projects have been or are the subject of litigation in Broward County, Florida. On November 16, 2012, FDOT paid to FGT the sum of approximately $100 million, representing the amount of the judgment, plus interest, in a case tried in 2011.
On April 14, 2011, FGT filed suit against the FDOT/FTE and other defendants in Broward County, Florida seeking an injunction and damages as the result of the construction of a mechanically stabilized earth wall and other encroachments in FGT easements as part of FDOT/FTE’s I-595 project. On August 21, 2013, FGT and FDOT/FTE entered into a settlement agreement pursuant to which, among other things, FDOT/FTE paid FGT approximately $19 million in September 2013 in settlement of FGT’s claims with respect to the I-595 project. The settlement agreement also provided for agreed easement widths for FDOT/FTE right-of-way and for cost sharing between FGT and FDOT/FTE for any future relocations. Also in September 2013, FDOT/FTE paid FGT an additional approximate $1 million for costs related to the aforementioned turnpike/State Road 91 case tried in 2011.
FGT will continue to seek rate recovery in the future for these types of costs to the extent not reimbursed by the FDOT/FTE. There can be no assurance that FGT will be successful in obtaining complete reimbursement for any such relocation costs from the FDOT/FTE or from its customers or that the timing of such reimbursement will fully compensate FGT for its costs.
Contingent Residual Support Agreement – AmeriGas
In connection with the closing of the contribution of its propane operations in January 2012, ETP agreed to provide contingent, residual support of $1.55 billion of intercompany borrowings made by AmeriGas 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.
PEPL Holdings Guarantee of Collection
In connection with the SUGS Contribution, Regency issued $600 million of 4.50% senior notes due 2023(the “Regency Debt”), the proceeds of which were used by Regency to fund the cash portion of the consideration, as adjusted, and pay certain other expenses or disbursements directly related to the closing of the SUGS Contribution. In connection with the closing of the SUGS Contribution on April 30, 2013, Regency entered into an agreement with PEPL Holdings, a subsidiary of Southern Union, pursuant to which PEPL Holdings provided a guarantee of collection (on a nonrecourse basis to Southern Union) to Regency and Regency Energy Finance Corp. with respect to the payment of the principal amount of the Regency Debt through maturity in 2023. In connection with the completion of the Panhandle Merger, in which PEPL Holdings was merged with and into Panhandle, the guarantee of collection for the Regency Debt was assumed by Panhandle.
NGL Pipeline Regulation
We have interests in NGL pipelines located in Texas and New Mexico. We commenced the interstate transportation of NGLs in 2013, which is subject to the jurisdiction of the FERC under 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.
Transwestern Rate Case
On October 1, 2014, Transwestern filed a general NGA Section 4 rate case pursuant to the 2011 settlement agreement with its shippers. On December 2, 2014, the FERC issued an order accepting and suspending the rates to be effective April 1, 2015, subject to refund, and setting a procedural schedule with a hearing scheduled in August 2015.
FGT Rate Case
On October 31, 2014, FGT filed a general NGA Section 4 rate case pursuant to a 2010 settlement agreement with its shippers. On November 28, 2014, the FERC issued an order accepting and suspending the rates to be effective May 1, 2015, subject to refund, and setting a procedural schedule with a hearing scheduled in late 2015.
Commitments
In the normal course of our business, we purchase, process and sell natural gas pursuant to long-term contracts and we enter 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 our financial position or results of operations.
We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2058. 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, | | | 2014 | | 2013 | | 2012 | Rental expense(1) | | $ | 139 |
| | $ | 140 |
| | $ | 57 |
| Less: Sublease rental income | | (26 | ) | | (24 | ) | | (4 | ) | Rental expense, net | | $ | 113 |
| | $ | 116 |
| | $ | 53 |
|
| | | | | | | | | | | | | | | | | | | | | | 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) | | 142 |
| | 142 |
| | — |
| | — |
| Fixed income securities | | 91 |
| | — |
| | 91 |
| | — |
| Total | | $ | 256 |
| | $ | 165 |
| | $ | 91 |
| | $ | — |
|
| | (1) | Includes contingent rentals totaling $24 million, $22 millionPrimarily comprised of approximately 31% equities, 66% fixed income securities and $6 million for the years ended3% cash as of December 31, 2014, 2013 and 2012, respectively.2016. |
Future minimum lease commitmentsThe 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 $8 million to pension plans and $10 million to other postretirement plans in 2018. The cost of the plans are funded in accordance with federal regulations, not to exceed the amounts deductible for such leases are: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: | | | | | Years Ending December 31: | | 2015 | $ | 146 |
| 2016 | 124 |
| 2017 | 114 |
| 2018 | 105 |
| 2019 | 100 |
| Thereafter | 803 |
| Future minimum lease commitments | 1,392 |
| Less: Sublease rental income | (34 | ) | Net future minimum lease commitments | $ | 1,358 |
|
| | | | | | | | | | Years | | Pension Benefits - Unfunded Plans (1) | | Other Postretirement Benefits (Gross, Before Medicare Part D) | 2018 | | $ | 8 |
| | $ | 24 |
| 2019 | | 6 |
| | 23 |
| 2020 | | 6 |
| | 21 |
| 2021 | | 5 |
| | 19 |
| 2022 | | 4 |
| | 17 |
| 2023 – 2027 | | 15 |
| | 37 |
|
Our joint venture agreements require that we fund our proportionate share(1) Expected benefit payments of capital contributions to our unconsolidated affiliates. Such contributions will depend upon our unconsolidated affiliates’ capital requirements, suchfunded 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 for funding capital projects or repayment of long-term obligations. 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 namedwell as a defendantfederal 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 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.any future periods. MTBE Litigation
| | 14. | RELATED PARTY TRANSACTIONS: |
Sunoco, Inc., along with other refiners, manufacturers and sellers of gasoline, is a defendant in lawsuits alleging MTBE contamination of groundwater. The plaintiffs typically include water purveyors and municipalities responsible for supplying drinking water and governmental authorities. The plaintiffs are asserting primarily product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws and deceptive business practices. The plaintiffs inIn June 2017, ETP acquired all of the cases are seeking to recover compensatory damages,publicly held PennTex common units through a tender offer and exercise of a limited call right, as further discussed in some cases also seek natural resource damages, injunctive relief, punitive damages and attorneys’ fees.Note 8.
As of December 31, 2014, Sunoco, Inc. is a defendant in five cases, including cases initiated by the States of New Jersey, Vermont, the Commonwealth of Pennsylvania, and two others by the Commonwealth of Puerto Rico with the more recent Puerto Rico action being a companion case alleging damages for additional sites beyond those at issue in the initial Puerto
Rico action. Four of these cases are venued 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.
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. Insufficient information has been developed about the plaintiffs’ legal theories or the facts with respect to statewide natural resource damage claimsETE previously paid ETP to provide an analysis of the ultimate potential liability of Sunoco, Inc. in these matters. It is reasonably possible that a loss may be realized; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. Management believes that an 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 said adverse determination occurs, but does not believe that any such adverse determination would have a material adverse effect on the Partnership’s consolidated financial position.
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 recoveryservices on its counterclaims. Enterprise has filed a noticebehalf and on behalf of appeal. other subsidiaries of ETE, which included the reimbursement of various operating and general and administrative expenses incurred by ETP on behalf of ETE and its subsidiaries. These agreements expired in 2016.
In accordanceaddition, subsidiaries of ETE recorded sales 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. Other Litigation and Contingencies
We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For eachaffiliates 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, 2014 and 2013, accruals of approximately $37$303 million, $221 million and $46$290 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, 2014 or 2013 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.
Attorney General of the Commonwealth of Massachusetts v. New England Gas Company
On July 7, 2011, the Massachusetts Attorney General (“AG”) filed a regulatory complaint with the Massachusetts Department of Public Utilities (“MDPU”) against New England Gas Company with respect to certain environmental cost recoveries. The AG is seeking a refund to New England Gas Company customers for alleged “excessive and imprudently incurred costs” related to legal fees associated with Southern Union’s environmental response activities. In the complaint, the AG requests that the MDPU initiate an investigation into the New England Gas Company’s collection and reconciliation of recoverable environmental costs including: (i) the prudence of any and all legal fees, totaling approximately $19 million, that were charged by the Kasowitz, Benson, Torres & Friedman firm and passed through the recovery mechanism since 2005, the year when a partner in the firm, the Southern Union former Vice Chairman, President and Chief Operating Officer, joined Southern Union’s management team; (ii) the prudence of any and all legal fees that were charged by the Bishop, London & Dodds firm and passed through the recovery mechanism since 2005, the period during which a member of the firm served as Southern Union’s Chief Ethics Officer; and (iii) the propriety and allocation of certain legal fees charged that were passed through the recovery mechanism that the AG contends only qualify for a lesser, 50%, level of recovery. Southern Union has filed its answer denying the allegations and moved to dismiss the complaint, in part on a theory of collateral estoppel. The hearing officer has deferred consideration of Southern Union’s motion to dismiss. The AG’s motion to be reimbursed expert and consultant costs by Southern Union of up to $150,000 was granted. By tariff, these costs are recoverable through rates charged to New England Gas Company customers. The hearing officer previously stayed discovery pending resolution of a dispute concerning the
applicability of attorney-client privilege to legal billing invoices. The MDPU issued an interlocutory order on June 24, 2013 that lifted the stay, and discovery has resumed. Panhandle (as successor to Southern Union) believes it has complied with all applicable requirements regarding its filings for cost recovery and has not recorded any accrued liability; however, Panhandle will continue to assess its potential exposure for such cost recoveries as the matter progresses.
Environmental Matters
Our operations are subject to extensive federal, 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. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the business of transporting, storing, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products. As a result, there can be no assurance that significant costs and liabilities will not be incurred. 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 remedial obligations, the issuance of injunctions 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.
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 include 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, 2014, Sunoco, Inc. had been named as a PRP at approximately 51 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, | | 2014 | | 2013 | Current | $ | 39 |
| | $ | 45 |
| Non-current | 352 |
| | 350 |
| Total environmental liabilities | $ | 391 |
| | $ | 395 |
|
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, 20142017, 2016 and 2013, Sunoco, Inc. had $46 million and $36 million, respectively, of expenditures related to environmental cleanup programs.2015, respectively.
On June 29, 2011, the U.S. Environmental Protection Agency finalized a rule under the Clean Air Act that revised the new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines. The rule became effective on August 29, 2011. The rule modifications may require us to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment, if we replace equipment or expand existing facilities in the future. At this point, we are not able to predict the cost to comply with the rule’s requirements, because the rule applies only to changes we might make in the future.
Our pipeline operations are subject to regulation by the U.S. 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.
Our operations are also subject to the requirements of the OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’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 operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances. | | 12.15. | PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:REPORTABLE SEGMENTS: |
Commodity Price RiskSubsequent 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: 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, | | 2017 | | 2016 | | 2015 | Equity in earnings of unconsolidated affiliates: | | | | | | Investment in ETP | $ | 156 |
| | $ | 59 |
| | $ | 469 |
| Adjustments and Eliminations | (12 | ) | | 211 |
| | (193 | ) | Total equity in earnings of unconsolidated affiliates | $ | 144 |
| | $ | 270 |
| | $ | 276 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | Segment Adjusted EBITDA: | | | | | | Investment in ETP | $ | 6,712 |
| | $ | 5,733 |
| | $ | 5,517 |
| Investment in Sunoco LP | 732 |
| | 665 |
| | 719 |
| Investment in Lake Charles LNG | 175 |
| | 179 |
| | 196 |
| Corporate and Other | (31 | ) | | (170 | ) | | (104 | ) | Adjustments and Eliminations | (268 | ) | | (272 | ) | | (590 | ) | Total Segment Adjusted EBITDA | 7,320 |
| | 6,135 |
| | 5,738 |
| Depreciation, depletion and amortization | (2,554 | ) | | (2,216 | ) | | (1,951 | ) | Interest expense, net of interest capitalized | (1,922 | ) | | (1,804 | ) | | (1,622 | ) | Gains on acquisitions | — |
| | 83 |
| | — |
| Impairment of investments in unconsolidated affiliates | (313 | ) | | (308 | ) | | — |
| Impairment losses | (1,039 | ) | | (1,040 | ) | | (339 | ) | Losses on interest rate derivatives | (37 | ) | | (12 | ) | | (18 | ) | Non-cash unit-based compensation expense | (99 | ) | | (70 | ) | | (91 | ) | Unrealized gains (losses) on commodity risk management activities | 59 |
| | (136 | ) | | (65 | ) | Losses on extinguishments of debt | (89 | ) | | — |
| | (43 | ) | Inventory valuation adjustments | 24 |
| | 97 |
| | (67 | ) | Adjusted EBITDA related to discontinued operations | (223 | ) | | (199 | ) | | (228 | ) | Adjusted EBITDA related to unconsolidated affiliates | (716 | ) | | (675 | ) | | (713 | ) | Equity in earnings of unconsolidated affiliates | 144 |
| | 270 |
| | 276 |
| Other, net | 155 |
| | 79 |
| | 23 |
| 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, | | 2017 | | 2016 | | 2015 | Total assets: | | | | | | Investment in ETP | $ | 77,965 |
| | $ | 70,105 |
| | $ | 65,128 |
| Investment in Sunoco LP | 8,344 |
| | 8,701 |
| | 8,842 |
| Investment in Lake Charles LNG | 1,646 |
| | 1,508 |
| | 1,369 |
| Corporate and Other | 598 |
| | 711 |
| | 638 |
| Adjustments and Eliminations | (2,307 | ) | | (2,100 | ) | | (4,833 | ) | Total | $ | 86,246 |
| | $ | 78,925 |
| | $ | 71,144 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | 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 | $ | 5,901 |
| | $ | 5,810 |
| | $ | 8,167 |
| Investment in Sunoco LP | 103 |
| | 119 |
| | 178 |
| Investment in Lake Charles LNG | 2 |
| | — |
| | 1 |
| Adjustments and Eliminations | — |
| | — |
| | (123 | ) | Total | $ | 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, | | 2017 | | 2016 | | 2015 | Intrastate Transportation and Storage | $ | 2,891 |
| | $ | 2,155 |
| | $ | 1,912 |
| Interstate Transportation and Storage | 915 |
| | 946 |
| | 1,008 |
| Midstream | 2,510 |
| | 2,342 |
| | 2,607 |
| 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 | 2,740 |
| | 2,872 |
| | 15,216 |
| Total revenues | 29,054 |
| | 21,827 |
| | 34,292 |
| Less: Intersegment revenues | 441 |
| | 209 |
| | 136 |
| Revenues from external customers | $ | 28,613 |
| | $ | 21,618 |
| | $ | 34,156 |
|
Investment in Sunoco LP | | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | Retail operations | $ | 2,263 |
| | $ | 1,991 |
| | $ | 2,226 |
| Wholesale operations | 9,460 |
| | 7,995 |
| | 10,204 |
| Total revenues | 11,723 |
| | 9,986 |
| | 12,430 |
| Less: Intersegment revenues | 10 |
| | 9 |
| | 11 |
| Revenues from external customers | $ | 11,713 |
| | $ | 9,977 |
| | $ | 12,419 |
|
Investment in Lake Charles LNG Lake Charles LNG’s revenues of $197 million, $197 million and $216 million for the years ended December 31, 2017, 2016 and 2015, respectively, were related to LNG terminalling.
| | 16. | QUARTERLY FINANCIAL DATA (UNAUDITED): |
Summarized unaudited quarterly financial data is presented below. Earnings per unit are exposedcomputed on a stand-alone basis for each quarter and total year. | | | | | | | | | | | | | | | | | | | | | | Quarters Ended | | | | March 31* | | June 30* | | September 30* | | December 31 | | Total Year | 2017: | | | | | | | | | | Revenues | $ | 9,660 |
| | $ | 9,427 |
| | $ | 9,984 |
| | $ | 11,452 |
| | $ | 40,523 |
| Operating income (loss) | 758 |
| | 746 |
| | 924 |
| | 285 |
| | 2,713 |
| Net income (loss) | 319 |
| | 121 |
| | 758 |
| | 1,168 |
| | 2,366 |
| Limited Partners’ interest in net income | 232 |
| | 204 |
| | 240 |
| | 239 |
| | 915 |
| Basic net income per limited partner unit | $ | 0.22 |
| | $ | 0.18 |
| | $ | 0.22 |
| | $ | 0.22 |
| | $ | 0.85 |
| Diluted net income per limited partner unit | $ | 0.21 |
| | $ | 0.18 |
| | $ | 0.22 |
| | $ | 0.22 |
| | $ | 0.83 |
|
| | | | | | | | | | | | | | | | | | | | | | Quarters Ended | | | | March 31* | | June 30* | | September 30* | | December 31* | | Total Year* | 2016: | | | | | | | | | | Revenues | $ | 6,447 |
| | $ | 7,866 |
| | $ | 8,156 |
| | $ | 9,323 |
| | $ | 31,792 |
| Operating income | 680 |
| | 814 |
| | 624 |
| | (275 | ) | | 1,843 |
| Net income (loss) | 320 |
| | 417 |
| | (3 | ) | | (734 | ) | | — |
| Limited Partners’ interest in net income | 311 |
| | 239 |
| | 207 |
| | 226 |
| | 983 |
| Basic net income per limited partner unit | $ | 0.30 |
| | $ | 0.23 |
| | $ | 0.20 |
| | $ | 0.22 |
| | $ | 0.94 |
| Diluted net income per limited partner unit | $ | 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 marketthe quarterly data has not been presented due to immateriality. The three months ended December 31, 2017 and 2016 reflected the recognition of impairment losses of $1.04 billion and $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 ETP’s interstate transportation and storage operations and midstream operations as well as Sunoco LP’s retail operations. The three months ended December 31, 2017 and December 31, 2016 reflected the recognition of a non-cash impairment of ETP’s investments in subsidiaries of $313 million and $308 million, respectively, in its 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, | | 2017 | | 2016 | ASSETS | | | | CURRENT ASSETS: | | | | Cash and cash equivalents | $ | 1 |
| | $ | 2 |
| Accounts receivable from related companies | 65 |
| | 55 |
| Other current assets | 1 |
| | — |
| Total current assets | 67 |
| | 57 |
| PROPERTY, PLANT AND EQUIPMENT, net | 27 |
| | 36 |
| ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES | 6,082 |
| | 5,088 |
| INTANGIBLE ASSETS, net | — |
| | 1 |
| GOODWILL | 9 |
| | 9 |
| OTHER NON-CURRENT ASSETS, net | 8 |
| | 10 |
| Total assets | $ | 6,193 |
| | $ | 5,201 |
| LIABILITIES AND PARTNERS’ CAPITAL | | | | CURRENT LIABILITIES: | | | | Accounts payable | $ | — |
| | $ | 1 |
| Accounts payable to related companies | — |
| | 22 |
| Interest payable | 66 |
| | 66 |
| Accrued and other current liabilities | 4 |
| | 3 |
| Total current liabilities | 70 |
| | 92 |
| LONG-TERM DEBT, less current maturities | 6,700 |
| | 6,358 |
| NOTE PAYABLE TO AFFILIATE | 617 |
| | 443 |
| OTHER NON-CURRENT LIABILITIES | 2 |
| | 2 |
| | | | | COMMITMENTS AND CONTINGENCIES |
| |
| | | | | PARTNERS’ DEFICIT: | | | | General Partner | (3 | ) | | (3 | ) | Limited Partners: | | | | 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 | (1,196 | ) | | (1,694 | ) | Total liabilities and partners’ deficit | $ | 6,193 |
| | $ | 5,201 |
|
STATEMENTS OF OPERATIONS | | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | SELLING, GENERAL AND ADMINISTRATIVE EXPENSES | $ | (31 | ) | | $ | (185 | ) | | $ | (112 | ) | OTHER INCOME (EXPENSE): | | | | | | Interest expense, net of interest capitalized | (347 | ) | | (327 | ) | | (294 | ) | Equity in earnings of unconsolidated affiliates | 1,381 |
| | 1,511 |
| | 1,601 |
| Loss on extinguishment of debt | (47 | ) | | — |
| | — |
| Other, net | (2 | ) | | (4 | ) | | (5 | ) | INCOME BEFORE INCOME TAXES | 954 |
| | 995 |
| | 1,190 |
| Income tax expense | — |
| | — |
| | 1 |
| NET INCOME | 954 |
| | 995 |
| | 1,189 |
| General Partner’s interest in net income | 2 |
| | 3 |
| | 3 |
| Convertible Unitholders’ interest in income | 37 |
| | 9 |
| | — |
| Class D Unitholder’s interest in net income | — |
| | — |
| | 3 |
| Limited Partners’ interest in net income | $ | 915 |
| | $ | 983 |
| | $ | 1,183 |
|
STATEMENTS OF CASH FLOWS | | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES | $ | 831 |
| | $ | 918 |
| | $ | 1,103 |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | Cash paid for Bakken Pipeline Transaction | — |
| | — |
| | (817 | ) | Contributions to unconsolidated affiliates | (861 | ) | | (70 | ) | | — |
| Capital expenditures | (1 | ) | | (16 | ) | | (19 | ) | Contributions in aid of construction costs | 7 |
| | — |
| | — |
| Net cash used in investing activities | (855 | ) | | (86 | ) | | (836 | ) | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | Proceeds from borrowings | 2,219 |
| | 225 |
| | 3,672 |
| Principal payments on debt | (1,881 | ) | | (210 | ) | | (1,985 | ) | Distributions to partners | (1,010 | ) | | (1,022 | ) | | (1,090 | ) | Proceeds from affiliate | 174 |
| | 176 |
| | 210 |
| Common Units issued for cash | 568 |
| | — |
| | — |
| Units repurchased under buyback program | — |
| | — |
| | (1,064 | ) | Debt issuance costs | (47 | ) | | — |
| | (11 | ) | Net cash provided by (used in) financing activities | 23 |
| | (831 | ) | | (268 | ) | INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | (1 | ) | | 1 |
| | (1 | ) | CASH AND CASH EQUIVALENTS, beginning of period | 2 |
| | 1 |
| | 2 |
| CASH AND CASH EQUIVALENTS, end of period | $ | 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, 2017 and 2016 | S - 4 | Consolidated Statements of Operations – Years Ended December 31, 2017, 2016 and 2015 | S - 6 | Consolidated Statements of Comprehensive Income – Years Ended December 31, 2017, 2016 and 2015 | S - 7 | Consolidated Statements of Equity – Years Ended December 31, 2017, 2016 and 2015 | S - 8 | Consolidated Statements of Cash Flows – Years Ended December 31, 2017, 2016 and 2015 | S - 10 | Notes to Consolidated Financial Statements | S - 12 |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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, 2017 and 2016, the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, 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, 2017, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 23, 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 23, 2018
ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Dollars in millions) | | | | | | | | | | December 31, | | 2017 | | 2016* | ASSETS | | | | Current assets: | | | | Cash and cash equivalents | $ | 306 |
| | $ | 360 |
| Accounts receivable, net | 3,946 |
| | 3,002 |
| Accounts receivable from related companies | 318 |
| | 209 |
| Inventories | 1,589 |
| | 1,626 |
| Income taxes receivable | 135 |
| | 128 |
| Derivative assets | 24 |
| | 20 |
| Other current assets | 210 |
| | 298 |
| Total current assets | 6,528 |
| | 5,643 |
| | | | | Property, plant and equipment | 67,699 |
| | 58,220 |
| Accumulated depreciation and depletion | (9,262 | ) | | (7,303 | ) | | 58,437 |
| | 50,917 |
| | | | | Advances to and investments in unconsolidated affiliates | 3,816 |
| | 4,280 |
| Other non-current assets, net | 758 |
| | 672 |
| Intangible assets, net | 5,311 |
| | 4,696 |
| Goodwill | 3,115 |
| | 3,897 |
| Total assets | $ | 77,965 |
| | $ | 70,105 |
|
* As adjusted. See Note 2.
ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Dollars in millions) | | | | | | | | | | December 31, | | 2017 | | 2016* | LIABILITIES AND EQUITY | | | | Current liabilities: | | | | Accounts payable | $ | 4,126 |
| | $ | 2,900 |
| Accounts payable to related companies | 209 |
| | 43 |
| Derivative liabilities | 109 |
| | 166 |
| Accrued and other current liabilities | 2,143 |
| | 1,905 |
| Current maturities of long-term debt | 407 |
| | 1,189 |
| Total current liabilities | 6,994 |
| | 6,203 |
| | | | | Long-term debt, less current maturities | 32,687 |
| | 31,741 |
| Long-term notes payable – related company | — |
| | 250 |
| Non-current derivative liabilities | 145 |
| | 76 |
| Deferred income taxes | 2,883 |
| | 4,394 |
| Other non-current liabilities | 1,084 |
| | 952 |
| | | | | Commitments and contingencies |
| |
|
| Legacy ETP Preferred Units | — |
| | 33 |
| Redeemable noncontrolling interests | 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 | 244 |
| | 206 |
| Accumulated other comprehensive income | 3 |
| | 8 |
| Total partners’ capital | 28,269 |
| | 18,621 |
| Noncontrolling interest | 5,882 |
| | 7,820 |
| Total equity | 34,151 |
| | 26,441 |
| Total liabilities and equity | $ | 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, | | 2017 | | 2016* | | 2015* | REVENUES: | | | | | | Natural gas sales | $ | 4,172 |
| | $ | 3,619 |
| | $ | 3,671 |
| NGL sales | 6,972 |
| | 4,841 |
| | 3,936 |
| Crude sales | 10,184 |
| | 6,766 |
| | 8,378 |
| Gathering, transportation and other fees | 4,265 |
| | 4,003 |
| | 3,997 |
| Refined product sales (see Note 3) | 1,515 |
| | 1,047 |
| | 9,958 |
| Other (see Note 3) | 1,946 |
| | 1,551 |
| | 4,352 |
| Total revenues | 29,054 |
| | 21,827 |
| | 34,292 |
| COSTS AND EXPENSES: | | | | | | Cost of products sold (see Note 3) | 20,801 |
| | 15,080 |
| | 26,714 |
| Operating expenses (see Note 3) | 2,170 |
| | 1,839 |
| | 2,608 |
| Depreciation, depletion and amortization | 2,332 |
| | 1,986 |
| | 1,929 |
| Selling, general and administrative (see Note 3) | 434 |
| | 348 |
| | 475 |
| Impairment losses | 920 |
| | 813 |
| | 339 |
| Total costs and expenses | 26,657 |
| | 20,066 |
| | 32,065 |
| OPERATING INCOME | 2,397 |
| | 1,761 |
| | 2,227 |
| OTHER INCOME (EXPENSE): | | | | | | Interest expense, net | (1,365 | ) | | (1,317 | ) | | (1,291 | ) | Equity in earnings from unconsolidated affiliates | 156 |
| | 59 |
| | 469 |
| Impairment of investments in unconsolidated affiliates | (313 | ) | | (308 | ) | | — |
| Gains on acquisitions | — |
| | 83 |
| | — |
| Losses on extinguishments of debt | (42 | ) | | — |
| | (43 | ) | Losses on interest rate derivatives | (37 | ) | | (12 | ) | | (18 | ) | Other, net | 209 |
| | 131 |
| | 22 |
| INCOME BEFORE INCOME TAX BENEFIT | 1,005 |
| | 397 |
| | 1,366 |
| Income tax benefit | (1,496 | ) | | (186 | ) | | (123 | ) | NET INCOME | 2,501 |
| | 583 |
| | 1,489 |
| Less: Net income attributable to noncontrolling interest | 420 |
| | 295 |
| | 134 |
| Less: Net loss attributable to predecessor | — |
| | — |
| | (34 | ) | NET INCOME ATTRIBUTABLE TO PARTNERS | 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 | ) | NET INCOME (LOSS) PER COMMON UNIT: | | | | | | Basic | $ | 0.94 |
| | $ | (1.38 | ) | | $ | (0.07 | ) | Diluted | $ | 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, | | 2017 | | 2016* | | 2015* | Net income | $ | 2,501 |
| | $ | 583 |
| | $ | 1,489 |
| Other comprehensive income (loss), net of tax: | | | | | | Change in value of available-for-sale securities | 6 |
| | 2 |
| | (3 | ) | Actuarial gain (loss) relating to pension and other postretirement benefits | (12 | ) | | (1 | ) | | 65 |
| Foreign currency translation adjustment | — |
| | (1 | ) | | (1 | ) | Change in other comprehensive income (loss) from unconsolidated affiliates | 1 |
| | 4 |
| | (1 | ) | | (5 | ) | | 4 |
| | 60 |
| Comprehensive income | 2,496 |
| | 587 |
| | 1,549 |
| Less: Comprehensive income attributable to noncontrolling interest | 420 |
| | 295 |
| | 134 |
| Less: Comprehensive loss attributable to predecessor | — |
| | — |
| | (34 | ) | Comprehensive income attributable to partners | $ | 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 | | | | | | | | | | | | 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, 2014* | $ | — |
| | $ | — |
| | $ | 10,427 |
| | $ | 1,512 |
| | $ | — |
| | $ | 184 |
| | $ | (56 | ) | | $ | 5,143 |
| | $ | 8,088 |
| | $ | 25,298 |
| Distributions to partners | — |
| | — |
| | (1,863 | ) | | (247 | ) | | (80 | ) | | (944 | ) | | — |
| | — |
| | — |
| | (3,134 | ) | Distributions to noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (338 | ) | | — |
| | (338 | ) | Units issued for cash | — |
| | — |
| | 1,428 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1,428 |
| Subsidiary units issued for cash | — |
| | — |
| | 298 |
| | — |
| | — |
| | 2 |
| | — |
| | 1,219 |
| | — |
| | 1,519 |
| Capital contributions from noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 875 |
| | — |
| | 875 |
| Bakken Pipeline Transaction | — |
| | — |
| | (999 | ) | | 1,946 |
| | — |
| | — |
| | — |
| | 72 |
| | — |
| | 1,019 |
| Sunoco LP Exchange Transaction | — |
| | — |
| | (52 | ) | | — |
| | — |
| | — |
| | — |
| | (940 | ) | | — |
| | (992 | ) | Susser Exchange Transaction | — |
| | — |
| | (68 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (68 | ) | Acquisition and disposition of noncontrolling interest | — |
| | — |
| | (26 | ) | | — |
| | — |
| | — |
| | — |
| | (39 | ) | | — |
| | (65 | ) | Predecessor distributions to partners | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (202 | ) | | (202 | ) | Predecessor units issued for cash | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 34 |
| | 34 |
| Regency Merger | — |
| | — |
| | 7,890 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (7,890 | ) | | — |
| Other comprehensive income, net of tax | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 60 |
| | — |
| | — |
| | 60 |
| Other, net | — |
| | — |
| | 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 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Capital contributions from noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 236 |
| | — |
| | 236 |
| Sunoco, Inc. retail business to Sunoco LP transaction | — |
| | — |
| | (405 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (405 | ) | PennTex Acquisition | — |
| | — |
| | 307 |
| | — |
| | — |
| | — |
| | — |
| | 236 |
| | — |
| | 543 |
| Other comprehensive income, net of tax | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 4 |
| | — |
| | — |
| | 4 |
| Other, net | — |
| | — |
| | 10 |
| | — |
| | — |
| | — |
| | — |
| | 21 |
| | — |
| | 31 |
| Net income (loss) | — |
| | — |
| | (1,019 | ) | | 351 |
| | 8 |
| | 948 |
| | — |
| | 295 |
| | — |
| | 583 |
| 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, | | 2017 | | 2016* | | 2015* | OPERATING ACTIVITIES: | | | | | | Net income | $ | 2,501 |
| | $ | 583 |
| | $ | 1,489 |
| Reconciliation of net income to net cash provided by operating activities: | | | | | | Depreciation, depletion and amortization | 2,332 |
| | 1,986 |
| | 1,929 |
| Deferred income taxes | (1,531 | ) | | (169 | ) | | 202 |
| Amortization included in interest expense | 2 |
| | (20 | ) | | (36 | ) | Inventory valuation adjustments | — |
| | — |
| | (58 | ) | Unit-based compensation expense | 74 |
| | 80 |
| | 79 |
| Impairment losses | 920 |
| | 813 |
| | 339 |
| Gains on acquisitions | — |
| | (83 | ) | | — |
| Losses on extinguishments of debt | 42 |
| | — |
| | 43 |
| Impairment of investments in unconsolidated affiliates | 313 |
| | 308 |
| | — |
| Distributions on unvested awards | (31 | ) | | (25 | ) | | (16 | ) | Equity in earnings of unconsolidated affiliates | (156 | ) | | (59 | ) | | (469 | ) | Distributions from unconsolidated affiliates | 440 |
| | 406 |
| | 440 |
| Other non-cash | (261 | ) | | (271 | ) | | (22 | ) | Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | (160 | ) | | (246 | ) | | (1,173 | ) | Net cash provided by operating activities | 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 |
| | — |
| Proceeds from Bakken Pipeline Transaction | — |
| | — |
| | 980 |
| Proceeds from Susser Exchange Transaction | — |
| | — |
| | 967 |
| Proceeds from sale of noncontrolling interest | — |
| | — |
| | 64 |
| Cash paid for acquisition of PennTex noncontrolling interest | (280 | ) | | — |
| | — |
| Cash paid for Vitol Acquisition, net of cash received | — |
| | (769 | ) | | — |
| Cash paid for PennTex Acquisition, net of cash received | — |
| | (299 | ) | | — |
| Cash transferred to ETE in connection with the Sunoco LP Exchange | — |
| | — |
| | (114 | ) | Cash paid for acquisition of a noncontrolling interest | — |
| | — |
| | (129 | ) | Cash paid for all other acquisitions | (264 | ) | | (159 | ) | | (675 | ) | Capital expenditures, excluding allowance for equity funds used during construction | (8,335 | ) | | (7,550 | ) | | (9,098 | ) | Contributions in aid of construction costs | 24 |
| | 71 |
| | 80 |
| Contributions to unconsolidated affiliates | (268 | ) | | (59 | ) | | (45 | ) | Distributions from unconsolidated affiliates in excess of cumulative earnings | 136 |
| | 135 |
| | 124 |
| Proceeds from the sale of assets | 35 |
| | 25 |
| | 23 |
| Change in restricted cash | — |
| | 14 |
| | 19 |
| Other | 1 |
| | 1 |
| | (16 | ) | Net cash used in investing activities | (5,473 | ) | | (6,390 | ) | | (7,820 | ) | | | | | | |
| | | | | | | | | | | | | FINANCING ACTIVITIES: | | | | | | Proceeds from borrowings | 26,736 |
| | 19,916 |
| | 22,462 |
| Repayments of long-term debt | (26,494 | ) | | (15,799 | ) | | (17,843 | ) | 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 |
| Predecessor units issued for cash | — |
| | — |
| | 34 |
| Capital contributions from noncontrolling interest | 1,214 |
| | 236 |
| | 841 |
| Distributions to partners | (3,468 | ) | | (3,542 | ) | | (3,134 | ) | Predecessor distributions to partners | — |
| | — |
| | (202 | ) | Distributions to noncontrolling interest | (430 | ) | | (481 | ) | | (338 | ) | Redemption of Legacy ETP Preferred Units | (53 | ) | | — |
| | — |
| Debt issuance costs | (83 | ) | | (22 | ) | | (63 | ) | Other | 5 |
| | 2 |
| | — |
| Net cash provided by financing activities | 934 |
| | 2,920 |
| | 4,937 |
| Decrease in cash and cash equivalents | (54 | ) | | (167 | ) | | (136 | ) | Cash and cash equivalents, beginning of period | 360 |
| | 527 |
| | 663 |
| Cash and cash equivalents, end of period | $ | 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 Partners 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, NGLs and refined 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 volatilitybusiness of commodity prices. To managelegacy 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 impactfourth quarter of volatility from these prices, we utilize various exchange-traded2017, 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 OTC commodityNGLs 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 instrument contracts. These contracts consist primarilystatements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of futures, swapsassets and optionsliabilities and are recordedthe accrual for and disclosure of contingent assets and liabilities at fair value in our consolidated balance sheets.the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We inject and holdThe natural gas in our Bammelindustry 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 facility to take advantage of contango markets (i.e., when the price of natural gas is higheroperations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the future thanfollowing month’s financial statements. Management believes that the current spot price). We use financial derivatives to hedgeestimated operating results represent the natural gas heldactual results in connection with these arbitrage opportunities. At the inceptionall material respects.
Some of the hedge, we lock in a marginother significant estimates made by purchasing gas inmanagement include, but are not limited to, the spot market or off peak season and entering into a financial contract to lock in the sale price. If we designate the related financial contract as a fair value hedge for accounting purposes, we value thetiming of certain forecasted transactions that are hedged, natural gas inventory at current spot
market prices along with the financial derivative we use to hedge it. Changes in the spread between the forward natural gas prices designated as fair value hedges 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. Unrealized margins represent the unrealized gains or losses from our derivative instruments using mark-to-market accounting, with changes in 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.
Recent Accounting Pronouncements ASU 2014-09 In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from 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.
The Partnership adopted ASU 2014-09 on January 1, 2018. The Partnership applied the cumulative catchup transition method and recognized the cumulative effect of the retrospective application of the standard. The effect of the retrospective application of the standard was not material. For future periods, we expect that the adoption of this standard will result in a change to revenues with offsetting changes to costs associated primarily with the designation of certain of our derivatives being recorded directly in earnings. These margins fluctuate based uponmidstream 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 spreads betweenaccounting for noncash consideration in multiple of our reportable segments, as well as fuel usage and loss allowances. None of these changes is expected to have a material impact on net income. ASU 2016-02 In February 2016, the physical spot priceFASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which establishes the principles that lessees and forwardlessors 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 in the first quarter of 2019 and 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, 2018, the Partnership 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. We do not anticipate a material impact to our financial position or results of operations as a result of the adoption of this standard. ASU 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’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance did 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, 2018, with early adoption permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures. Revenue Recognition Revenues for sales of natural gas prices. Ifand NGLs are recognized at the spread narrows betweenlater of the physical and financial prices, we will record unrealized gains or lower unrealized losses. Iftime of delivery of the spread widens, we will record unrealized losses or lower unrealized gains. Typically, as we enterproduct to the winter months, the spread converges so that we recognize in earnings the original locked-in spread through either mark-to-market adjustmentscustomer or the physical withdrawtime of 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. Wegas that flows through the transportation pipelines. Under transportation contracts, our customers are also exposedcharged (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 market risk onpay 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 retain for fees inpurchase 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 operationalmargin from fees charged for storing customers’ working natural gas sales onin our interstate transportationstorage 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 segment.reservoir. We usepurchase physical natural gas and then sell financial derivativescontracts at a price sufficient to hedgecover our carrying costs and provide for a gross profit margin. We expect margins from natural gas storage transactions to be higher during the sales priceperiods from November to March of thiseach 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 futures, swaps and options. Certain contracts that qualify for hedge accounting are designated as cash flow hedges of the forecasted saleweather, availability of natural gas.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 segment margins principally under fee-based or other arrangements in which we receive a fee for natural gas gathering, compressing, treating or processing services. The change in value,revenue earned from these arrangements is directly related to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivativevolume of natural gas that flows through our systems and is recorded in cost of products sold in the consolidated statement of operations.not directly dependent on commodity prices. We are also exposed to commodity price risk on NGLs and residue gas we retain for feesutilize other types of arrangements in our midstream segment, whereby our subsidiaries generallyincluding (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 residueperiod in which the discontinuance of regulatory accounting treatment occurs. Although Panhandle’s natural gas transmission systems and NGLs.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 useconsider 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, | | 2017 | | 2016 | | 2015 | Accounts receivable | $ | (950 | ) | | $ | (919 | ) | | $ | 819 |
| Accounts receivable from related companies | 67 |
| | 30 |
| | (243 | ) | Inventories | 37 |
| | (497 | ) | | (157 | ) | Other current assets | 39 |
| | 83 |
| | (178 | ) | Other non-current assets, net | (94 | ) | | (78 | ) | | 188 |
| Accounts payable | 758 |
| | 972 |
| | (1,215 | ) | Accounts payable to related companies | (3 | ) | | 29 |
| | (160 | ) | Accrued and other current liabilities | (47 | ) | | 39 |
| | (83 | ) | Other non-current liabilities | 24 |
| | 33 |
| | (219 | ) | Price risk management assets and liabilities, net | 9 |
| | 62 |
| | 75 |
| Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | $ | (160 | ) | | $ | (246 | ) | | $ | (1,173 | ) |
Non-cash investing and financing activities and supplemental cash flow information are as follows: | | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | NON-CASH INVESTING ACTIVITIES: | | | | | | Accrued capital expenditures | $ | 1,059 |
| | $ | 822 |
| | $ | 896 |
| Sunoco LP limited partner interest received in exchange for contribution of the Sunoco, Inc. retail business to Sunoco LP | — |
| | 194 |
| | — |
| Net gains from subsidiary common unit transactions | — |
| | 37 |
| | 300 |
| NON-CASH FINANCING ACTIVITIES: | | | | | | Issuance of Common Units in connection with the PennTex Acquisition | $ | — |
| | $ | 307 |
| | $ | — |
| Issuance of Common Units in connection with the Regency Merger | — |
| | — |
| | 9,250 |
| Issuance of Class H Units in connection with the Bakken Pipeline Transaction | — |
| | — |
| | 1,946 |
| Contribution of assets from noncontrolling interest | 988 |
| | — |
| | 34 |
| Redemption of Common Units in connection with the Bakken Pipeline Transaction | — |
| | — |
| | 999 |
| Redemption of Common Units in connection with the Sunoco LP Exchange | — |
| | — |
| | 52 |
| SUPPLEMENTAL CASH FLOW INFORMATION: | | | | | | Cash paid for interest, net of interest capitalized | $ | 1,329 |
| | $ | 1,411 |
| | $ | 1,467 |
| Cash paid for (refund of) income taxes | 50 |
| | (229 | ) | | 71 |
|
Accounts Receivable Our 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. We have a diverse portfolio of 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 and spare parts, all of which are valued at the lower of cost or net realizable value utilizing the weighted-average cost method.
Inventories consisted of the following: | | | | | | | | | | 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, | | 2017 | | 2016 | Deposits paid to vendors | $ | 64 |
| | $ | 74 |
| Prepaid expenses and other | 146 |
| | 224 |
| Total other current assets | $ | 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 NGL and crude derivative swap contractsrefined products transportation and services segment primarily due to hedge forecasted salesan 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, | | 2017 | | 2016 | Land and improvements | $ | 1,706 |
| | $ | 676 |
| Buildings and improvements (1 to 45 years) | 1,960 |
| | 1,617 |
| Pipelines and equipment (5 to 83 years) | 44,050 |
| | 36,356 |
| Natural gas and NGL storage facilities (5 to 46 years) | 1,681 |
| | 1,452 |
| Bulk storage, equipment and facilities (2 to 83 years) | 3,036 |
| | 3,701 |
| Vehicles (1 to 25 years) | 124 |
| | 217 |
| Right of way (20 to 83 years) | 3,424 |
| | 3,349 |
| Natural resources | 434 |
| | 434 |
| Other (1 to 40 years) | 534 |
| | 484 |
| Construction work-in-process | 10,750 |
| | 9,934 |
| | 67,699 |
| | 58,220 |
| Less – Accumulated depreciation and depletion | (9,262 | ) | | (7,303 | ) | Property, plant and equipment, net | $ | 58,437 |
| | $ | 50,917 |
|
We recognized the following amounts for the periods presented: | | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | Depreciation and depletion expense | $ | 2,060 |
| | $ | 1,793 |
| | $ | 1,713 |
| 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, | | 2017 | | 2016 | Regulatory assets | $ | 85 |
| | $ | 86 |
| Deferred charges | 210 |
| | 217 |
| Restricted funds | 192 |
| | 190 |
| Long-term affiliated receivable | 85 |
| | 90 |
| Other | 186 |
| | 89 |
| Total other non-current assets, net | $ | 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, 2017 | | December 31, 2016 | | Gross Carrying Amount | | Accumulated Amortization | | Gross Carrying Amount | | Accumulated Amortization | Amortizable intangible assets: | | | | | | | | Customer relationships, contracts and agreements (3 to 46 years) | $ | 6,250 |
| | $ | (1,003 | ) | | $ | 5,362 |
| | $ | (737 | ) | Patents (10 years) | 48 |
| | (26 | ) | | 48 |
| | (21 | ) | Trade Names (20 years) | 66 |
| | (25 | ) | | 66 |
| | (22 | ) | Other (5 to 20 years) | 1 |
| | — |
| | 2 |
| | (2 | ) | Total intangible assets | $ | 6,365 |
| | $ | (1,054 | ) | | $ | 5,478 |
| | $ | (782 | ) |
Aggregate amortization expense of intangible assets was as follows: | | | | | | | | | | | | | | 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: | | 2018 | $ | 280 |
| 2019 | 278 |
| 2020 | 278 |
| 2021 | 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 NGL and condensate equity volumes. Certain contractsrefined 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 | | NGL and Refined Products Transportation and Services | | Crude Oil Transportation and Services | | All Other | | Total | 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 | — |
| | (262 | ) | | — |
| | (79 | ) | | — |
| | (452 | ) | | (793 | ) | Other | — |
| | — |
| | (1 | ) | | — |
| | — |
| | — |
| | (1 | ) | 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 $99 million in the interstate transportation and storage segment and $106 million in the NGL and refined products transportation and services segment primarily due to market declines in current and expected future commodity prices in the fourth quarter of 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 discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as of December 31, 2017 and 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. We 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. As of December 31, 2017 and 2016, other non-current liabilities in the Partnership’s consolidated balance 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 $2 million and $14 million, and were reflected as property, plant and equipment on our balance sheet as of December 31, 2017 and 2016, respectively. In addition, the Partnership had $21 million and $13 million legally restricted funds for the purpose of settling AROs that was reflected as other non-current assets as of December 31, 2017 and 2016, respectively. Accrued and Other Current Liabilities Accrued and other current liabilities consisted of the following: | | | | | | | | | | December 31, | | 2017 | | 2016 | Interest payable | $ | 443 |
| | $ | 440 |
| Customer advances and deposits | 59 |
| | 56 |
| Accrued capital expenditures | 1,006 |
| | 749 |
| Accrued wages and benefits | 208 |
| | 212 |
| Taxes payable other than income taxes | 108 |
| | 63 |
| Exchanges payable | 154 |
| | 208 |
| Other | 165 |
| | 177 |
| Total accrued and other current liabilities | $ | 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 hedgeopen credit.
Redeemable Noncontrolling Interests The noncontrolling interest holders in one of our consolidated subsidiaries has the option to sell its interests to 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, 2017 was $34.28 billion and $33.09 billion, respectively. As of December 31, 2016, the aggregate fair value and carrying amount of our debt obligations was $33.85 billion and $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 cash flow hedges. The changeassets 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 extentlevel of activity of these contracts on the contractsexchange 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 effective, remainsunobservable. During the year ended December 31, 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, 2017 and 2016 based on inputs used to derive their fair values: | | | | | | | | | | | | | | Fair Value Total | | Fair Value Measurements at December 31, 2017 | | Level 1 | | Level 2 | Assets: | | | | | | Commodity derivatives: | | | | | | Natural Gas: | | | | | | Basis Swaps IFERC/NYMEX | $ | 11 |
| | $ | 11 |
| | $ | — |
| Swing Swaps IFERC | 13 |
| | — |
| | 13 |
| Fixed Swaps/Futures | 70 |
| | 70 |
| | — |
| Forward Physical Swaps | 8 |
| | — |
| | 8 |
| Power: | | | | | | Forwards | 23 |
| | — |
| | 23 |
| Natural Gas Liquids – Forwards/Swaps | 193 |
| | 193 |
| | — |
| Crude – Futures | 2 |
| | 2 |
| | — |
| Total commodity derivatives | 320 |
| | 276 |
| | 44 |
| Other non-current assets | 21 |
| | 14 |
| | 7 |
| Total assets | $ | 341 |
| | $ | 290 |
| | $ | 51 |
| Liabilities: | | | | | | Interest rate derivatives | $ | (219 | ) | | $ | — |
| | $ | (219 | ) | Commodity derivatives: | | | | | | Natural Gas: | | | | | | Basis Swaps IFERC/NYMEX | (24 | ) | | (24 | ) | | — |
| Swing Swaps IFERC | (15 | ) | | (1 | ) | | (14 | ) | Fixed Swaps/Futures | (57 | ) | | (57 | ) | | — |
| Forward Physical Swaps | (2 | ) | | — |
| | (2 | ) | Power – Forwards | (22 | ) | | — |
| | (22 | ) | Natural Gas Liquids – Forwards/Swaps | (192 | ) | | (192 | ) | | — |
| Refined Products – Futures | (25 | ) | | (25 | ) | | — |
| Crude – Futures | (1 | ) | | (1 | ) | | — |
| Total commodity derivatives | (338 | ) | | (300 | ) | | (38 | ) | Total liabilities | $ | (557 | ) | | $ | (300 | ) | | $ | (257 | ) |
| | | | | | | | | | | | | | | | | | 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 AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gainAid of Construction Costs On certain of our capital projects, third parties are obligated to reimburse us for all or lossa 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 derivativeperiod in which it is recordedrealized. 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 Cost of products sold include actual cost of fuel sold, adjusted for the consolidated statementeffects 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 may use derivativesrecord the collection of taxes to be remitted to government authorities on a net basis except for our all other segment in our liquids transportation and services segment to manage our storage facilities and the purchase and sale of purity NGLs. Sunoco Logistics utilizes derivatives such as swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the pricewhich consumer excise taxes on sales of refined products and NGLs. These derivative contracts act as a hedging mechanism against the volatility of prices by allowing Sunoco Logistics to transfer this price risk to counterparties whomerchandise are ableincluded in both revenues and willing to bear it. Since the first quarter 2013, Sunoco Logistics has not designated any of its derivative contracts as hedges for accounting purposes. Therefore, all realizedcosts and unrealized gains and losses from these derivative contracts are recognizedexpenses in the consolidated statements of operations, duringwith no effect on net income (loss). For the current period.year ended December 31, 2015, 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 by our consolidated operations subsequent to that date.
Issuances of Subsidiary Units We also use derivatives to hedge a variety of price risksrecord changes in our retail marketing segment. Futuresownership 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 swapsthe 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, and 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 achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floatingvalue our financial derivatives and related transactions have been determined using independent third-party prices, to lock in margins for certain refined productsreadily available market information, broker quotes and to lock in the priceappropriate valuation techniques.
At inception of a portionhedge, 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 natural gas purchases or salesthe hedge and transportation costs. Theon a quarterly basis, whether the derivatives that are used in our retail marketing segment represent economic hedges; however,hedging transactions are highly effective in offsetting changes in cash flows. If we have elected not to designate anydetermine 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 hedgesderivative in this business segment. Therefore, all realized and unrealized gains and losses from these derivative contracts are recognizednet 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 consolidated statements of operations during the current period. Our trading activities include the use of financial commodity derivatives to take advantage of market opportunities. These trading activities are a complement to our transportation and storage segment’s operations and are nettedhedged asset or liability in cost of products sold in our consolidated statements of operations. Additionally,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 also have tradingdesignate a derivative financial instrument as a cash flow hedge and marketing activitiesit 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 power and natural gascash flow hedges remain in our all other segment which are also nettedAOCI 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.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 The 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 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. Changes 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 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: |
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. 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 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 volatilityRover construction costs incurred by ETP through the useclosing date, along with the payment of daily positionadditional amounts subject to certain adjustments. ETP and profitSunoco Logistics Merger As discussed in Note 1, in April 2017, Energy Transfer Partners, L.P. and loss reports providedSunoco 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 our risk oversight committee,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, ETP contributed an approximate 15% ownership interest in Dakota Access and ETCO to PEP, which includes membersresulted 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 senior management,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 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 limitsPartnership purchased PennTex’s remaining outstanding common units in June 2017. Summary of Assets Acquired and authorizations set forth in our commodity risk management policy.Liabilities Assumed
The following table details our outstanding commodity-related derivatives:total purchase price was allocated as follows: | | | | | | | | | | | | December 31, 2014 | | December 31, 2013 | | Notional Volume | | Maturity | | Notional Volume | | Maturity | Mark-to-Market Derivatives | | | | | | | | (Trading) | | | | | | | | Natural Gas (MMBtu): | | | | | | | | Fixed Swaps/Futures | (232,500 | ) | | 2015 | | 9,457,500 |
| | 2014-2019 | Basis Swaps IFERC/NYMEX(1) | (13,907,500 | ) | | 2015-2016 | | (487,500 | ) | | 2014-2017 | Swing Swaps | — |
| | — | | 1,937,500 |
| | 2014-2016 | Options – Calls | 5,000,000 |
| | 2015 | | — |
| | — | Power (Megawatt): | | | | | | | | Forwards | 288,775 |
| | 2015 | | 351,050 |
| | 2014 | Futures | (156,000 | ) | | 2015 | | (772,476 | ) | | 2014 | Options – Puts | (72,000 | ) | | 2015 | | (52,800 | ) | | 2014 | Options – Calls | 198,556 |
| | 2015 | | 103,200 |
| | 2014 | Crude (Bbls) – Futures | — |
| | — | | 103,000 |
| | 2014 | (Non-Trading) | | | | | | | | Natural Gas (MMBtu): | | | | | | | | Basis Swaps IFERC/NYMEX | 57,500 |
| | 2015 | | 570,000 |
| | 2014 | Swing Swaps IFERC | 46,150,000 |
| | 2015 | | (9,690,000 | ) | | 2014-2016 | Fixed Swaps/Futures | (8,779,000 | ) | | 2015-2016 | | (8,195,000 | ) | | 2014-2015 | Forward Physical Contracts | (9,116,777 | ) | | 2015 | | 5,668,559 |
| | 2014-2015 | Natural Gas Liquid (Bbls) – Forwards/Swaps | (2,179,400 | ) | | 2015 | | (1,133,600 | ) | | 2014 | Refined Products (Bbls) – Futures | 13,745,755 |
| | 2015 | | (280,000 | ) | | 2014 | Fair Value Hedging Derivatives | | | | | | | | (Non-Trading) | | | | | | | | Natural Gas (MMBtu): | | | | | | | | Basis Swaps IFERC/NYMEX | (39,287,500 | ) | | 2015 | | (7,352,500 | ) | | 2014 | Fixed Swaps/Futures | (39,287,500 | ) | | 2015 | | (50,530,000 | ) | | 2014 | Hedged Item – Inventory | 39,287,500 |
| | 2015 | | 50,530,000 |
| | 2014 | Cash Flow Hedging Derivatives | | | | | | | | (Non-Trading) | | | | | | | | Natural Gas (MMBtu): | | | | | | | | Basis Swaps IFERC/NYMEX | — |
| | — | | (1,825,000 | ) | | 2014 | Fixed Swaps/Futures | — |
| | — | | (12,775,000 | ) | | 2014 | Natural Gas Liquid (Bbls) – Forwards/Swaps | — |
| | — | | (780,000 | ) | | 2014 | Crude (Bbls) – Futures | — |
| | — | | (30,000 | ) | | 2014 |
| | | | | | | | 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) | Includes aggregate amountsNone of the goodwill is expected to be deductible for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.tax purposes. |
Interest Rate RiskThe fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.
We are exposed to market riskSunoco 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 changes$760 million plus working capital. The acquisition provides Sunoco Logistics with an approximately 2 million barrel crude oil terminal in interest rates. To maintainMidland, Texas, a cost effective capital structure, we borrow funds using a mix of fixed rate debtcrude oil gathering 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 lockmainline pipeline system in the rateMidland Basin, including a significant acreage dedication from an investment-grade Permian producer, and crude oil inventories related to Vitol’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”), which increased Sunoco 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.
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 provided substantially all of the remaining capital necessary to complete the projects. As of December 31, 2017, $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, 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: | | | | | | Year Ended December 31, 2015 | Revenues | $ | 12,482 |
| Cost of products sold | 11,174 |
| Operating expenses | 798 |
| Selling, general and administrative expenses | 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 in 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 31.5 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 provided 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. At December 31, 2017, the Partnership held 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 anticipated debt issuances.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 46.2 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 entitled 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 provided 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 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 and 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 0.6186 Partnership common units. ETP issued 258.3 million Partnership common units to Regency unitholders, including 23.3 million units issued to Partnership subsidiaries. Regency’s 1.9 million outstanding Series A Convertible Preferred Units were converted into corresponding Legacy 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.
| | 4. | ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES: |
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, an approximately 5,360-mile natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula. Our investment in Citrus is reflected in our 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, 2017, the Partnership’s interest in Sunoco LP common units consisted of 43.5 million units, representing 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 summarizes our interest rate swaps outstanding, nonepresents equity in earnings (losses) of which were designated as hedges for accounting purposes:unconsolidated affiliates: | | | | | | | | | | | | | | Entity | | Term | | Type(1) | | Notional Amount Outstanding | December 31, 2014 | | December 31, 2013 | ETP | | July 2014(2) | | Forward-starting to pay a fixed rate of 4.25% and receive a floating rate | | $ | — |
| | $ | 400 |
| ETP | | July 2015(2) | | Forward-starting to pay a fixed rate of 3.38% and receive a floating rate | | 200 |
| | — |
| ETP | | July 2016(3) | | Forward-starting to pay a fixed rate of 3.80% and receive a floating rate | | 200 |
| | — |
| ETP | | July 2017(4) | | Forward-starting to pay a fixed rate of 3.84% and receive a floating rate | | 300 |
| | — |
| ETP | | July 2018(4) | | Forward-starting to pay a fixed rate of 4.00% and receive a floating rate | | 200 |
| | — |
| ETP | | July 2019(4) | | Forward-starting to pay a fixed rate of 3.19% and receive a floating rate | | 300 |
| | — |
| ETP | | July 2018 | | Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70% | | — |
| | 600 |
| ETP | | June 2021 | | Pay a floating rate plus a spread of 2.17% and receive a fixed rate of 4.65% | | — |
| | 400 |
| ETP | | February 2023 | | Pay a floating rate plus a spread of 1.73% and receive a fixed rate of 3.60% | | 200 |
| | 400 |
| Panhandle | | November 2021 | | Pay a fixed rate of 3.82% and receive a floating rate | | — |
| | 275 |
|
| | | | | | | | | | | | | | 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) | Floating ratesFor 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, Citrus, FEP, MEP, HPC and Sunoco LP (on a 100% basis) for all periods presented: | | | | | | | | | | December 31, | | 2017 | | 2016 | Current assets | $ | 4,750 |
| | $ | 1,532 |
| Property, plant and equipment, net | 9,893 |
| | 10,310 |
| Other assets | 2,286 |
| | 5,980 |
| Total assets | $ | 16,929 |
| | $ | 17,822 |
| | | | | Current liabilities | $ | 2,075 |
| | $ | 1,918 |
| Non-current liabilities | 9,375 |
| | 10,343 |
| Equity | 5,479 |
| | 5,561 |
| Total liabilities and equity | $ | 16,929 |
| | $ | 17,822 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | Revenue | $ | 13,081 |
| | $ | 11,150 |
| | $ | 13,815 |
| Operating income | 636 |
| | 859 |
| | 1,052 |
| 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, | | 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, | | 2017 | | 2016 | ETP Debt | | | | 6.125% Senior Notes due February 15, 2017 | $ | — |
| | $ | 400 |
| 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 |
| 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 |
|
| | | | | | | | | 4.15% Senior Notes due October 1, 2020 | 1,050 |
| | 1,050 |
| 4.40% Senior Notes due April 1, 2021 | 600 |
| | 600 |
| 6.50% Senior Notes due July 15, 2021 | — |
| | 500 |
| 4.65% Senior Notes due June 1, 2021 | 800 |
| | 800 |
| 5.20% Senior Notes due February 1, 2022 | 1,000 |
| | 1,000 |
| 4.65% Senior Notes due February 15, 2022 | 300 |
| | 300 |
| 5.875% Senior Notes due March 1, 2022 | 900 |
| | 900 |
| 5.00% Senior Notes due October 1, 2022 | 700 |
| | 700 |
| 3.45% Senior Notes due January 15, 2023 | 350 |
| | 350 |
| 3.60% Senior Notes due February 1, 2023 | 800 |
| | 800 |
| 5.50% Senior Notes due April 15, 2023 | — |
| | 700 |
| 4.50% Senior Notes due November 1, 2023 | 600 |
| | 600 |
| 4.90% Senior Notes due February 1, 2024 | 350 |
| | 350 |
| 7.60% Senior Notes due February 1, 2024 | 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 |
| 5.95% Senior Notes due December 1, 2025 | 400 |
| | 400 |
| 4.75% Senior Notes due January 15, 2026 | 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 |
| 4.90% Senior Notes due March 15, 2035 | 500 |
| | 500 |
| 6.625% Senior Notes due October 15, 2036 | 400 |
| | 400 |
| 7.50% Senior Notes due July 1, 2038 | 550 |
| | 550 |
| 6.85% Senior Notes due February 15, 2040 | 250 |
| | 250 |
| 6.05% Senior Notes due June 1, 2041 | 700 |
| | 700 |
| 6.50% Senior Notes due February 1, 2042 | 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 |
| 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 |
| Deferred debt issuance costs | (1 | ) | | (1 | ) | | 574 |
| | 656 |
| Panhandle Debt | | | | 6.20% Senior Notes due November 1, 2017 | — |
| | 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 | 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) | As of December 31, 2017 management had the intent and ability to refinance the $650 million 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 based on 3-month LIBOR.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 $118 million in unamortized net premiums, fair value adjustments and deferred debt issuance costs: | | | | | | 2018 | | $ | 1,700 |
| 2019 | | 3,500 |
| 2020 | | 1,875 |
| 2021 | | 1,400 |
| 2022 | | 5,346 |
| Thereafter | | 19,391 |
| Total | | $ | 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 Senior Notes 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 as 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 4.39% at December 31, 2017. Credit Facilities and Commercial Paper ETP Credit Facilities On 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 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. We use the ETP Credit Facilities to provide temporary financing for our 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 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”), 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. In connection with the Sunoco Logistics Merger, the 364-Day Credit Facility was terminated and repaid in May 2017. Bakken Credit Facility In August 2016, Energy Transfer Partners, L.P., Sunoco Logistics and Phillips 66 completed project-level financing of the 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, 2017, the Bakken Credit Facility had $2.50 billion of outstanding borrowings. The weighted average interest rate on the total amount outstanding as of December 31, 2017 was 3.00%. PennTex Revolving Credit Facility PennTex previously maintained a $275 million revolving credit commitment (the “PennTex Revolving Credit Facility”). In August 2017, the PennTex Revolving Credit Facility was 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 Facilities 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 Facilities) during certain Defaults (as defined in the ETP Credit Facilities) and during any Event of Default (as defined in the ETP Credit 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 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 Facilities also limit us, on a rolling four quarter basis, to a maximum Consolidated Funded Indebtedness to Consolidated EBITDA ratio, as defined in the underlying credit agreements, of 5.0 to 1, which can generally be increased to 5.5 to 1 during a Specified Acquisition Period. Our Leverage Ratio was 3.96 to 1 at December 31, 2017, as calculated in accordance with the 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 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. Compliance with our Covenants We were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2017.
| | 7. | LEGACY ETP PREFERRED UNITS: |
The Legacy ETP Preferred Units were mandatorily redeemable on September 2, 2029 for $35 million plus all accrued but unpaid distributions and interest thereon and were reflected as long-term liabilities in our consolidated balance sheets. The Legacy ETP Preferred Units were 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. In January 2017, ETP repurchased all of its 1.9 million outstanding Legacy 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 I Units, Class J Units and Class K 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, | | 2017 (1) | | 2016 (1) | | 2015 (1) | Number of Common Units, beginning of period | 794.8 |
| | 758.5 |
| | 533.4 |
| Common Units redeemed in connection with certain transactions | — |
| | (26.7 | ) | | (77.8 | ) | Common Units issued in connection with public offerings | 54.0 |
| | — |
| | — |
| Common Units issued in connection with certain acquisitions | — |
| | 13.3 |
| | 258.2 |
| Common Units issued in connection with the Distribution Reinvestment Plan | 12.0 |
| | 9.9 |
| | 11.7 |
| Common Units issued in connection with Equity Distribution Agreements | 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 | 1.6 |
| | 0.8 |
| | 1.3 |
| Number of Common Units, end of period | 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 effective date. These forward-starting swaps have termsSunoco Logistics common units outstanding at the close of 10 years with a mandatory termination date the same asSunoco Logistics Merger. See Note 1 for discussion on the effective date. |
| | (3)
| Representsaccounting treatment of 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. |
| | (4)
| Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.Sunoco Logistics Merger. |
Credit Risk
Credit risk refersOur 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 riskLimited 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 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 $1.00 billion. During the year ended December 31, 2017, we issued 22.6 million units for $503 million, net of commissions of $5 million. As of December 31, 2017, $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 default on its contractual obligationselect 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 and 2015, aggregate distributions of $228 million, $216 million, and $360 million, respectively, were reinvested under the DRIP resulting in the issuance in aggregate of 25.5 million Common Units. As of December 31, 2017, a losstotal of 20.8 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 23.7 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. As the Class E Units are owned by a wholly-owned subsidiary, 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 the Class E Units at a future date. Class G Units There are currently 90.7 million Class G Units outstanding, all of which are held by a wholly-owned subsidiary of the Partnership. The Class G Units generally do not have any voting rights. The Class G Units are 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 G Unit per year. Allocations of depreciation and amortization 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. We also implement the use of industry standard commercial agreements which allowClass G Units for the netting of positive and negative 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 and midstream companies. 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.
We have maintenance margin deposits with certain counterparties in the OTC market, primarily independent system operators, and with clearing brokers. Payments on margin depositstax purposes 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 callsbased on a daily basis for exchange traded transactions. Since the margin callspredetermined percentage and are made daily with the exchange brokers, the fair value of the financial derivative instrumentsnot contingent on whether ETP has net income or loss. These units are deemed current and netted in deposits paid to vendors within other current assetsreflected as treasury units in the consolidated balance sheets.financial statements.
For financial instruments, failureClass H Units
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 counterpartynew class of limited partner interest in ETP (the “Class H Units”), which were generally entitled to perform on a contract could result(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. The Class H units were cancelled in connection with the merger of ETP and Sunoco Logistics in April 2017. Class I Units In connection with the 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 inabilityPartnership Agreement, as amended, (the “Partnership Agreement”) for such quarter over the cumulative amount of available cash previously distributed commencing with the quarter ended 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 realize amountsthe April 2017 merger of ETP and Sunoco Logistics, 100 Class I Units remain outstanding. 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. 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, 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, 2017, a total of 101.5 million Class K Units were held by wholly-owned subsidiaries of ETP. Sales of Common Units by legacy 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 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 Sunoco Logistics Merger, the previous Sunoco Logistics equity distribution agreement was terminated. ETP Preferred Units In November 2017, ETP issued 950,000 of its 6.250% Series A Preferred Units at a price of $1,000 per unit, and 550,000 of 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 date of original 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 not previously owned by ETP for $20.00 per common unit in cash. ETP now owns all of the economic interests of PennTex, and PennTex common units are no longer publicly traded or listed on the NASDAQ. Quarterly Distributions of Available Cash Under the Partnership’s limited partnership agreement, within 45 days after the end of each quarter, the Partnership distributes all cash on hand at the end of the quarter, less reserves established by the general partner in its discretion. This is defined as “available cash” in the partnership agreement. The general partner has broad discretion to establish cash reserves that have been recorded on our consolidated balance sheetsit determines are necessary or appropriate to properly conduct the Partnership’s business. The Partnership will make quarterly distributions to the extent there is sufficient cash from operations after establishment of cash reserves and recognizedpayment of fees and expenses, including payments to the general partner. If cash distributions exceed $0.0833 per unit in net income or other comprehensive income.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.” Derivative Summary
The following table provides a summaryshows the target distribution levels and distribution “splits” between the general and limited partners and the holders of our derivative assets and liabilities:the Partnership’s incentive distribution rights (”IDRs”): | | | | | | | | | | | | | | | | | | Fair Value of Derivative Instruments | | Asset Derivatives | | Liability Derivatives | | December 31, 2014 | | December 31, 2013 | | December 31, 2014 | | December 31, 2013 | Derivatives designated as hedging instruments: | | | | | | | | Commodity derivatives (margin deposits) | $ | 43 |
| | $ | 3 |
| | $ | — |
| | $ | (18 | ) | | 43 |
| | 3 |
| | — |
| | (18 | ) | Derivatives not designated as hedging instruments: | | | | | | | | Commodity derivatives (margin deposits) | 617 |
| | 227 |
| | (577 | ) | | (209 | ) | Commodity derivatives | 23 |
| | 39 |
| | (23 | ) | | (38 | ) | Interest rate derivatives | 3 |
| | 47 |
| | (155 | ) | | (95 | ) | | 643 |
| | 313 |
| | (755 | ) | | (342 | ) | Total derivatives | $ | 686 |
| | $ | 316 |
| | $ | (755 | ) | | $ | (360 | ) |
| | | | | | | | | | | | 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 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, ETE has agreed to relinquish its right to the following amounts of incentive distributions in future periods: | | | | | | | | Total Year | 2018 | | $ | 153 |
| 2019 | | 128 |
| Each year beyond 2019 | | 33 |
|
Distributions declared and paid by ETP to the preferred unitholders were as follows: | | | | | | | | | | | | | | | 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 fair valuecomponents 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:AOCI, net of tax: | | | | | | | | | | | | | | | | | | | | | | | | Asset Derivatives | | Liability Derivatives | | | Balance Sheet Location | | December 31, 2014 | | December 31, 2013 | | December 31, 2014 | | December 31, 2013 | Derivatives in offsetting agreements: | | | | | | | | | OTC contracts | | Price risk management assets (liabilities) | | $ | 23 |
| | $ | 41 |
| | $ | (23 | ) | | $ | (38 | ) | Broker cleared derivative contracts | | Other current assets | | 674 |
| | 265 |
| | (574 | ) | | (318 | ) | | | 697 |
| | 306 |
| | (597 | ) | | (356 | ) | Offsetting agreements: | | | | | | | | | Counterparty netting | | Price risk management assets (liabilities) | | (19 | ) | | (36 | ) | | 19 |
| | 36 |
| Payments on margin deposit | | Other current assets | | 5 |
| | (1 | ) | | (22 | ) | | 55 |
| | | (14 | ) | | (37 | ) | | (3 | ) | | 91 |
| Net derivatives with offsetting agreements | | 683 |
| | 269 |
| | (600 | ) | | (265 | ) | Derivatives without offsetting agreements | | 3 |
| | 47 |
| | (155 | ) | | (95 | ) | Total derivatives | | $ | 686 |
| | $ | 316 |
| | $ | (755 | ) | | $ | (360 | ) |
| | | | | | | | | | December 31, | | 2017 | | 2016 | Available-for-sale securities | $ | 8 |
| | $ | 2 |
| Foreign currency translation adjustment | (5 | ) | | (5 | ) | Actuarial gain related to pensions and other postretirement benefits | (5 | ) | | 7 |
| Investments in unconsolidated affiliates, net | 5 |
| | 4 |
| Total AOCI, net of tax | $ | 3 |
| | $ | 8 |
|
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 summarizetable below sets forth the tax amounts recognized with respect to our derivative financial instruments:included in the respective components of other comprehensive income: | | | | | | | | | | | | | | Change in Value Recognized in OCI on Derivatives (Effective Portion) | | Years Ended December 31, | | 2014 | | 2013 | | 2012 | Derivatives in cash flow hedging relationships: | | | | | | Commodity derivatives | $ | — |
| | $ | (1 | ) | | $ | 8 |
| Total | $ | — |
| | $ | (1 | ) | | $ | 8 |
|
| | | | | | | | | | December 31, | | 2017 | | 2016 | Available-for-sale securities | $ | (2 | ) | | $ | (2 | ) | Foreign currency translation adjustment | 3 |
| | 3 |
| Actuarial loss relating to pension and other postretirement benefits | 3 |
| | — |
| Total | $ | 4 |
| | $ | 1 |
|
| | | | | | | | | | | | | | | | Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) | | Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) | | | | Years Ended December 31, | | | | 2014 | | 2013 | | 2012 | Derivatives in cash flow hedging relationships: | | | | | | | | Commodity derivatives | Cost of products sold | | $ | (3 | ) | | $ | 4 |
| | $ | 14 |
| Total | | | $ | (3 | ) | | $ | 4 |
| | $ | 14 |
|
| | | | | | | | | | | | | | | | 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, | | | | 2014 | | 2013 | | 2012 | Derivatives in fair value hedging relationships (including hedged item): | | | | | | | | Commodity derivatives | Cost of products sold | | $ | (8 | ) | | $ | 8 |
| | $ | 54 |
| Total | | | $ | (8 | ) | | $ | 8 |
| | $ | 54 |
|
| | | | | | | | | | | | | | | | Location of Gain/(Loss) Recognized in Income on Derivatives | | Amount of Gain (Loss) Recognized in Income on Derivatives | | | | Years Ended December 31, | | | | 2014 | | 2013 | | 2012 | Derivatives not designated as hedging instruments: | | | | | | | | Commodity derivatives – Trading | Cost of products sold | | $ | (6 | ) | | $ | (11 | ) | | $ | (7 | ) | Commodity derivatives – Non-trading | Cost of products sold | | 106 |
| | (12 | ) | | (15 | ) | Commodity contracts – Non-trading | Deferred gas purchases | | — |
| | (3 | ) | | (26 | ) | Interest rate derivatives | Gains (losses) on interest rate derivatives | | (157 | ) | | 44 |
| | (4 | ) | Total | | | $ | (57 | ) | | $ | 18 |
| | $ | (52 | ) |
| | 13.9. | RETIREMENT BENEFITS:UNIT-BASED COMPENSATION PLANS: |
Savings and Profit Sharing PlansETP Unit-Based Compensation Plan
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 $50 million, $38 million and $21 million to these 401(k) savingshave issued equity incentive plans for the years ended 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, 2014, 2013 and 2012, respectively.2017, an aggregate total of 8.4 million ETP Common Units remain available to be awarded under our equity incentive plans. 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 were available tocovered substantially all of its employees, pendingemployees. 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 meeting certain age and service requirements.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 anticipates approval for the distribution of assets from the plan, pending approval from the Pension Benefit Guaranty Corporationpaid lump sums to eligible active and the IRS,terminated vested participants in the fourth quarter ofDecember 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$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, 2014 | | December 31, 2013 | 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 | $ | 632 |
| | $ | 61 |
| | $ | 223 |
| | $ | 1,117 |
| | $ | 78 |
| | $ | 296 |
| $ | 18 |
| | $ | 51 |
| | $ | 166 |
| | $ | 20 |
| | $ | 57 |
| | $ | 181 |
| Service cost | — |
| | — |
| | — |
| | 3 |
| | — |
| | — |
| | Interest cost | 28 |
| | 3 |
| | 5 |
| | 33 |
| | 2 |
| | 6 |
| 1 |
| | 1 |
| | 4 |
| | 1 |
| | 2 |
| | 4 |
| Amendments | — |
| | — |
| | 1 |
| | — |
| | — |
| | 2 |
| — |
| | — |
| | 7 |
| | — |
| | — |
| | — |
| Benefits paid, net | (45 | ) | | (9 | ) | | (28 | ) | | (99 | ) | | (16 | ) | | (26 | ) | (2 | ) | | (6 | ) | | (20 | ) | | (1 | ) | | (7 | ) | | (21 | ) | Actuarial (gain) loss and other | 130 |
| | 10 |
| | 2 |
| | (74 | ) | | (3 | ) | | (14 | ) | 2 |
| | 1 |
| | (1 | ) | | (2 | ) | | (1 | ) | | 2 |
| Settlements | (27 | ) | | — |
| | — |
| | (95 | ) | | — |
| | — |
| (18 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| Dispositions | — |
| | — |
| | (1 | ) | | (253 | ) | | — |
| | (41 | ) | | Benefit obligation at end of period | 718 |
| | 65 |
| | 202 |
| | 632 |
| | 61 |
| | 223 |
| $ | 1 |
| | $ | 47 |
| | $ | 156 |
| | $ | 18 |
| | $ | 51 |
| | $ | 166 |
| | | | | | | | | | | | | | | | | | | | | | | | Change in plan assets: | | | | | | | | | | | | | | | | | | | | | | | Fair value of plan assets at beginning of period | 600 |
| | — |
| | 284 |
| | 906 |
| | — |
| | 312 |
| $ | 12 |
| | $ | — |
| | $ | 256 |
| | $ | 15 |
| | $ | — |
| | $ | 261 |
| Return on plan assets and other | 70 |
| | — |
| | 6 |
| | 43 |
| | — |
| | 17 |
| 3 |
| | — |
| | 11 |
| | (2 | ) | | — |
| | 6 |
| Employer contributions | — |
| | — |
| | 8 |
| | — |
| | — |
| | 8 |
| 6 |
| | — |
| | 10 |
| | — |
| | — |
| | 10 |
| Benefits paid, net | (45 | ) | | — |
| | (28 | ) | | (99 | ) | | — |
| | (26 | ) | (2 | ) | | — |
| | (20 | ) | | (1 | ) | | — |
| | (21 | ) | Settlements | (27 | ) | | — |
| | — |
| | (95 | ) | | — |
| | — |
| (18 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| Dispositions | — |
| | — |
| | (5 | ) | | (155 | ) | | — |
| | (27 | ) | | Fair value of plan assets at end of period | 598 |
| | — |
| | 265 |
| | 600 |
| | — |
| | 284 |
| $ | 1 |
| | $ | — |
| | $ | 257 |
| | $ | 12 |
| | $ | — |
| | $ | 256 |
| | | | | | | | | | | | | | | | | | | | | | | | Amount underfunded (overfunded) at end of period | $ | 120 |
| | $ | 65 |
| | $ | (63 | ) | | $ | 32 |
| | $ | 61 |
| | $ | (61 | ) | $ | — |
| | $ | 47 |
| | $ | (101 | ) | | $ | 6 |
| | $ | 51 |
| | $ | (90 | ) | | | | | | | | | | | | | | | | | | | | | | | | Amounts recognized in the consolidated balance sheets consist of: | | | | | | | | | | | | | | | | | | | | | | | Non-current assets | $ | — |
| | $ | — |
| | $ | 90 |
| | $ | — |
| | $ | — |
| | $ | 86 |
| $ | — |
| | $ | — |
| | $ | 127 |
| | $ | — |
| | $ | — |
| | $ | 114 |
| Current liabilities | — |
| | (9 | ) | | (2 | ) | | — |
| | (9 | ) | | (2 | ) | — |
| | (8 | ) | | (2 | ) | | — |
| | (7 | ) | | (2 | ) | Non-current liabilities | (120 | ) | | (56 | ) | | (25 | ) | | (32 | ) | | (52 | ) | | (23 | ) | — |
| | (39 | ) | | (24 | ) | | (6 | ) | | (44 | ) | | (23 | ) | | $ | (120 | ) | | $ | (65 | ) | | $ | 63 |
| | $ | (32 | ) | | $ | (61 | ) | | $ | 61 |
| $ | — |
| | $ | (47 | ) | | $ | 101 |
| | $ | (6 | ) | | $ | (51 | ) | | $ | 89 |
| | | | | | | | | | | | | | | | | | | | | | | | Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of: | | | | | | | | | | | | | | | | | | | | | | | Net actuarial gain | $ | 18 |
| | $ | 7 |
| | $ | (20 | ) | | $ | (86 | ) | | $ | (4 | ) | | $ | (25 | ) | $ | — |
| | $ | 5 |
| | $ | (18 | ) | | $ | — |
| | $ | — |
| | $ | (13 | ) | Prior service cost | — |
| | — |
| | 17 |
| | — |
| | — |
| | 18 |
| — |
| | — |
| | 21 |
| | — |
| | — |
| | 15 |
| | $ | 18 |
| | $ | 7 |
| | $ | (3 | ) | | $ | (86 | ) | | $ | (4 | ) | | $ | (7 | ) | $ | — |
| | $ | 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, 2014 | | December 31, 2013 | 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 | $ | 718 |
| | $ | 65 |
| | N/A |
| | $ | 632 |
| | 61 |
| | N/A |
| $ | 1 |
| | $ | 47 |
| | N/A |
| | $ | 18 |
| | $ | 51 |
| | N/A |
| Accumulated benefit obligation | 718 |
| | 65 |
| | 202 |
| | 632 |
| | 61 |
| | $ | 223 |
| 1 |
| | 47 |
| | $ | 156 |
| | 18 |
| | 51 |
| | $ | 166 |
| Fair value of plan assets | 598 |
| | — |
| | 265 |
| | 600 |
| | — |
| | 284 |
| 1 |
| | — |
| | 257 |
| | 12 |
| | — |
| | 256 |
|
Components of Net Periodic Benefit Cost | | | | | | | | | | | | | | | | | | December 31, 2014 | | December 31, 2013 | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Net periodic benefit cost: | | | | | | | | Service cost | $ | — |
| | $ | — |
| | $ | 3 |
| | $ | — |
| Interest cost | 31 |
| | 5 |
| | 35 |
| | 6 |
| Expected return on plan assets | (40 | ) | | (8 | ) | | (54 | ) | | (9 | ) | Prior service cost amortization | — |
| | 1 |
| | — |
| | 1 |
| Actuarial loss amortization | (1 | ) | | (1 | ) | | 2 |
| | — |
| Settlements | (4 | ) | | — |
| | (2 | ) | | — |
| | (14 | ) | | (3 | ) | | (16 | ) | | (2 | ) | Regulatory adjustment(1) | — |
| | — |
| | 5 |
| | — |
| Net periodic benefit cost | $ | (14 | ) | | $ | (3 | ) | | $ | (11 | ) | | $ | (2 | ) |
| | | | | | | | | | | | | | | | | | December 31, 2017 | | December 31, 2016 | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Net Periodic Benefit Cost: | | | | | | | | Interest cost | $ | 2 |
| | $ | 4 |
| | $ | 3 |
| | $ | 4 |
| Expected return on plan assets | — |
| | (9 | ) | | (1 | ) | | (8 | ) | Prior service cost amortization | — |
| | 2 |
| | — |
| | 1 |
| Net periodic benefit cost | $ | 2 |
| | $ | (3 | ) | | $ | 2 |
| | $ | (3 | ) |
| | (1)
| Southern Union, the predecessor of Panhandle, historically recovered certain qualified pension benefit plan and other postretirement benefit plan costs through rates charged to utility customers in its distribution operations. Certain utility commissions require that the recovery of these costs be based on the Employee Retirement Income Security Act of 1974, as amended, or other utility commission specific guidelines. The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and amortized to expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission. |
Assumptions The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below: | | | December 31, 2014 | | December 31, 2013 | 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 | 3.62 | % | | 2.24 | % | | 4.65 | % | | 2.33 | % | 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, 2014 | | December 31, 2013 | 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 | 4.65 | % | | 3.02 | % | | 3.50 | % | | 2.68 | % | 3.52 | % | | 3.10 | % | | 3.60 | % | | 3.06 | % | Expected return on assets: | | | | | | | | | | | | | | | Tax exempt accounts | 7.50 | % | | 7.00 | % | | 7.50 | % | | 6.95 | % | 3.50 | % | | 7.00 | % | | 3.50 | % | | 7.00 | % | Taxable accounts | N/A |
| | 4.50 | % | | N/A |
| | 4.42 | % | 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 PanhandlePanhandle’s and Sunoco, Inc.’s other postretirement benefit plans are shown in the table below: | | | | December 31, | December 31, | | | 2014 | | 2013 | 2017 | | 2016 | Health care cost trend rate | | 7.09 | % | | 7.57 | % | 7.20 | % | | 6.73 | % | Rate to which the cost trend is assumed to decline (the ultimate trend rate) | | 5.41 | % | | 5.42 | % | 4.99 | % | | 4.96 | % | Year that the rate reaches the ultimate trend rate | | 2018 |
| | 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, 2014 Using Fair Value Hierarchy | | Fair Value as of December 31, 2014 | | Level 1 | | Level 2 | | Level 3 | Asset category: | | | | | | | | Cash and cash equivalents | $ | 25 |
| | $ | 25 |
| | $ | — |
| | $ | — |
| Mutual funds(1) | 110 |
| | — |
| | 110 |
| | — |
| Fixed income securities | 463 |
| | — |
| | 463 |
| | — |
| Total | $ | 598 |
| | $ | 25 |
| | $ | 573 |
| | $ | — |
|
| | | | | | | | | | | | | | | | | | | | | | 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) | Primarily comprisedComprised of approximately 100% equities as of December 31, 2014.2017. |
| | | | | | | | | | | | | | | | | | | | Fair Value Measurements at December 31, 2013 Using Fair Value Hierarchy | | Fair Value as of December 31, 2013 | | Level 1 | | Level 2 | | Level 3 | Asset category: | | | | | | | | Cash and cash equivalents | $ | 12 |
| | $ | 12 |
| | $ | — |
| | $ | — |
| Mutual funds(1) | 368 |
| | — |
| | 281 |
| | 87 |
| Fixed income securities | 220 |
| | — |
| | 220 |
| | — |
| Total | $ | 600 |
| | $ | 12 |
| | $ | 501 |
| | $ | 87 |
|
| | | | | | | | | | | | | | | | | | | | | | 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) | Primarily comprisedComprised of approximately 41%100% equities 45% fixed income securities, and 14% in other investments as of December 31, 2013.2016. |
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, 2014 Using Fair Value Hierarchy | | Fair Value as of December 31, 2014 | | Level 1 | | Level 2 | | Level 3 | Asset category: | | | | | | | | Cash and cash equivalents | $ | 9 |
| | $ | 9 |
| | $ | — |
| | $ | — |
| Mutual funds(1) | 131 |
| | 131 |
| | — |
| | — |
| Fixed income securities | 125 |
| | — |
| | 125 |
| | — |
| Total | $ | 265 |
| | $ | 140 |
| | $ | 125 |
| | $ | — |
|
| | | | | | | | | | | | | | | | | | | | | | 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) | | 154 |
| | 154 |
| | — |
| | — |
| Fixed income securities | | 70 |
| | — |
| | 70 |
| | — |
| Total | | $ | 257 |
| | $ | 187 |
| | $ | 70 |
| | $ | — |
|
| | (1) | Primarily comprised of approximately 38% equities, 61% fixed income securities and 2% 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) | | 142 |
| | 142 |
| | — |
| | — |
| Fixed income securities | | 91 |
| | — |
| | 91 |
| | — |
| Total | | $ | 256 |
| | $ | 165 |
| | $ | 91 |
| | $ | — |
|
| | (1) | Primarily comprised of approximately 56%31% equities, 38%66% fixed income securities and 6%3% cash as of December 31, 2014.2016. |
| | | | | | | | | | | | | | | | | | | | Fair Value Measurements at December 31, 2013 Using Fair Value Hierarchy | | Fair Value as of December 31, 2013 | | Level 1 | | Level 2 | | Level 3 | Asset category: | | | | | | | | Cash and cash equivalents | $ | 10 |
| | $ | 10 |
| | $ | — |
| | $ | — |
| Mutual funds(1) | 130 |
| | 112 |
| | 18 |
| | — |
| Fixed income securities | 144 |
| | — |
| | 144 |
| | — |
| Total | $ | 284 |
| | $ | 122 |
| | $ | 162 |
| | $ | — |
|
| | (1)
| Primarily comprised of approximately 41% equities, 48% fixed income securities, 6% cash, and 5% in other investments as of December 31, 2013. |
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. See Note 2for information related to the framework used to measure the fair value of its pension and other postretirement plan assets. Contributions We expect to contribute approximately $129$8 million to pension plans and approximately $10 million to other postretirement plans in 2015.2018. The cost of the plans are funded in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes.
Benefit Payments PanhandlePanhandle’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) | 2015 | | $ | 717 |
| | $ | 9 |
| | $ | 28 |
| 2016 | | — |
| | 8 |
| | 26 |
| 2017 | | — |
| | 7 |
| | 25 |
| 2018 | | — |
| | 7 |
| | 23 |
| 2019 | | — |
| | 6 |
| | 22 |
| 2020 – 2024 | | — |
| | 23 |
| | 65 |
|
| | | | | | | | | | Years | | Pension Benefits - Unfunded Plans (1) | | Other Postretirement Benefits (Gross, Before Medicare Part D) | 2018 | | $ | 8 |
| | $ | 24 |
| 2019 | | 6 |
| | 23 |
| 2020 | | 6 |
| | 21 |
| 2021 | | 5 |
| | 19 |
| 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, ETP 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 subsidiariespreviously paid ETP to provide or receiveservices on its behalf and on behalf of other subsidiaries of ETE, which included the reimbursement of various operating and general and administrative expenses incurred by ETP on behalf of ETE and its subsidiaries. These agreements expired in 2016. In addition, subsidiaries of ETE recorded sales with affiliates of $303 million, $221 million and $290 million during the years ended December 31, 2017, 2016 and 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: 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, | | 2017 | | 2016 | | 2015 | Equity in earnings of unconsolidated affiliates: | | | | | | Investment in ETP | $ | 156 |
| | $ | 59 |
| | $ | 469 |
| Adjustments and Eliminations | (12 | ) | | 211 |
| | (193 | ) | Total equity in earnings of unconsolidated affiliates | $ | 144 |
| | $ | 270 |
| | $ | 276 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | Segment Adjusted EBITDA: | | | | | | Investment in ETP | $ | 6,712 |
| | $ | 5,733 |
| | $ | 5,517 |
| Investment in Sunoco LP | 732 |
| | 665 |
| | 719 |
| Investment in Lake Charles LNG | 175 |
| | 179 |
| | 196 |
| Corporate and Other | (31 | ) | | (170 | ) | | (104 | ) | Adjustments and Eliminations | (268 | ) | | (272 | ) | | (590 | ) | Total Segment Adjusted EBITDA | 7,320 |
| | 6,135 |
| | 5,738 |
| Depreciation, depletion and amortization | (2,554 | ) | | (2,216 | ) | | (1,951 | ) | Interest expense, net of interest capitalized | (1,922 | ) | | (1,804 | ) | | (1,622 | ) | Gains on acquisitions | — |
| | 83 |
| | — |
| Impairment of investments in unconsolidated affiliates | (313 | ) | | (308 | ) | | — |
| Impairment losses | (1,039 | ) | | (1,040 | ) | | (339 | ) | Losses on interest rate derivatives | (37 | ) | | (12 | ) | | (18 | ) | Non-cash unit-based compensation expense | (99 | ) | | (70 | ) | | (91 | ) | Unrealized gains (losses) on commodity risk management activities | 59 |
| | (136 | ) | | (65 | ) | Losses on extinguishments of debt | (89 | ) | | — |
| | (43 | ) | Inventory valuation adjustments | 24 |
| | 97 |
| | (67 | ) | Adjusted EBITDA related to discontinued operations | (223 | ) | | (199 | ) | | (228 | ) | Adjusted EBITDA related to unconsolidated affiliates | (716 | ) | | (675 | ) | | (713 | ) | Equity in earnings of unconsolidated affiliates | 144 |
| | 270 |
| | 276 |
| Other, net | 155 |
| | 79 |
| | 23 |
| 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, | | 2017 | | 2016 | | 2015 | Total assets: | | | | | | Investment in ETP | $ | 77,965 |
| | $ | 70,105 |
| | $ | 65,128 |
| Investment in Sunoco LP | 8,344 |
| | 8,701 |
| | 8,842 |
| Investment in Lake Charles LNG | 1,646 |
| | 1,508 |
| | 1,369 |
| Corporate and Other | 598 |
| | 711 |
| | 638 |
| Adjustments and Eliminations | (2,307 | ) | | (2,100 | ) | | (4,833 | ) | Total | $ | 86,246 |
| | $ | 78,925 |
| | $ | 71,144 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | 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 | $ | 5,901 |
| | $ | 5,810 |
| | $ | 8,167 |
| Investment in Sunoco LP | 103 |
| | 119 |
| | 178 |
| Investment in Lake Charles LNG | 2 |
| | — |
| | 1 |
| Adjustments and Eliminations | — |
| | — |
| | (123 | ) | Total | $ | 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, | | 2017 | | 2016 | | 2015 | Intrastate Transportation and Storage | $ | 2,891 |
| | $ | 2,155 |
| | $ | 1,912 |
| Interstate Transportation and Storage | 915 |
| | 946 |
| | 1,008 |
| Midstream | 2,510 |
| | 2,342 |
| | 2,607 |
| 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 | 2,740 |
| | 2,872 |
| | 15,216 |
| Total revenues | 29,054 |
| | 21,827 |
| | 34,292 |
| Less: Intersegment revenues | 441 |
| | 209 |
| | 136 |
| Revenues from external customers | $ | 28,613 |
| | $ | 21,618 |
| | $ | 34,156 |
|
Investment in Sunoco LP | | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | Retail operations | $ | 2,263 |
| | $ | 1,991 |
| | $ | 2,226 |
| Wholesale operations | 9,460 |
| | 7,995 |
| | 10,204 |
| Total revenues | 11,723 |
| | 9,986 |
| | 12,430 |
| Less: Intersegment revenues | 10 |
| | 9 |
| | 11 |
| Revenues from external customers | $ | 11,713 |
| | $ | 9,977 |
| | $ | 12,419 |
|
Investment in Lake Charles LNG Lake Charles LNG’s revenues of $197 million, $197 million and $216 million for the years ended December 31, 2017, 2016 and 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 | | | | March 31* | | June 30* | | September 30* | | December 31 | | Total Year | 2017: | | | | | | | | | | Revenues | $ | 9,660 |
| | $ | 9,427 |
| | $ | 9,984 |
| | $ | 11,452 |
| | $ | 40,523 |
| Operating income (loss) | 758 |
| | 746 |
| | 924 |
| | 285 |
| | 2,713 |
| Net income (loss) | 319 |
| | 121 |
| | 758 |
| | 1,168 |
| | 2,366 |
| Limited Partners’ interest in net income | 232 |
| | 204 |
| | 240 |
| | 239 |
| | 915 |
| Basic net income per limited partner unit | $ | 0.22 |
| | $ | 0.18 |
| | $ | 0.22 |
| | $ | 0.22 |
| | $ | 0.85 |
| Diluted net income per limited partner unit | $ | 0.21 |
| | $ | 0.18 |
| | $ | 0.22 |
| | $ | 0.22 |
| | $ | 0.83 |
|
| | | | | | | | | | | | | | | | | | | | | | Quarters Ended | | | | March 31* | | June 30* | | September 30* | | December 31* | | Total Year* | 2016: | | | | | | | | | | Revenues | $ | 6,447 |
| | $ | 7,866 |
| | $ | 8,156 |
| | $ | 9,323 |
| | $ | 31,792 |
| Operating income | 680 |
| | 814 |
| | 624 |
| | (275 | ) | | 1,843 |
| Net income (loss) | 320 |
| | 417 |
| | (3 | ) | | (734 | ) | | — |
| Limited Partners’ interest in net income | 311 |
| | 239 |
| | 207 |
| | 226 |
| | 983 |
| Basic net income per limited partner unit | $ | 0.30 |
| | $ | 0.23 |
| | $ | 0.20 |
| | $ | 0.22 |
| | $ | 0.94 |
| Diluted net income per limited partner unit | $ | 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, 2017 and 2016 reflected the recognition of impairment losses of $1.04 billion and $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 ETP’s interstate transportation and storage operations and midstream operations as well as Sunoco LP’s retail operations. The three months ended December 31, 2017 and December 31, 2016 reflected the recognition of a non-cash impairment of ETP’s investments in subsidiaries of $313 million and $308 million, respectively, in its 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, | | 2017 | | 2016 | ASSETS | | | | CURRENT ASSETS: | | | | Cash and cash equivalents | $ | 1 |
| | $ | 2 |
| Accounts receivable from related companies | 65 |
| | 55 |
| Other current assets | 1 |
| | — |
| Total current assets | 67 |
| | 57 |
| PROPERTY, PLANT AND EQUIPMENT, net | 27 |
| | 36 |
| ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES | 6,082 |
| | 5,088 |
| INTANGIBLE ASSETS, net | — |
| | 1 |
| GOODWILL | 9 |
| | 9 |
| OTHER NON-CURRENT ASSETS, net | 8 |
| | 10 |
| Total assets | $ | 6,193 |
| | $ | 5,201 |
| LIABILITIES AND PARTNERS’ CAPITAL | | | | CURRENT LIABILITIES: | | | | Accounts payable | $ | — |
| | $ | 1 |
| Accounts payable to related companies | — |
| | 22 |
| Interest payable | 66 |
| | 66 |
| Accrued and other current liabilities | 4 |
| | 3 |
| Total current liabilities | 70 |
| | 92 |
| LONG-TERM DEBT, less current maturities | 6,700 |
| | 6,358 |
| NOTE PAYABLE TO AFFILIATE | 617 |
| | 443 |
| OTHER NON-CURRENT LIABILITIES | 2 |
| | 2 |
| | | | | COMMITMENTS AND CONTINGENCIES |
| |
| | | | | PARTNERS’ DEFICIT: | | | | General Partner | (3 | ) | | (3 | ) | Limited Partners: | | | | 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 | (1,196 | ) | | (1,694 | ) | Total liabilities and partners’ deficit | $ | 6,193 |
| | $ | 5,201 |
|
STATEMENTS OF OPERATIONS | | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | SELLING, GENERAL AND ADMINISTRATIVE EXPENSES | $ | (31 | ) | | $ | (185 | ) | | $ | (112 | ) | OTHER INCOME (EXPENSE): | | | | | | Interest expense, net of interest capitalized | (347 | ) | | (327 | ) | | (294 | ) | Equity in earnings of unconsolidated affiliates | 1,381 |
| | 1,511 |
| | 1,601 |
| Loss on extinguishment of debt | (47 | ) | | — |
| | — |
| Other, net | (2 | ) | | (4 | ) | | (5 | ) | INCOME BEFORE INCOME TAXES | 954 |
| | 995 |
| | 1,190 |
| Income tax expense | — |
| | — |
| | 1 |
| NET INCOME | 954 |
| | 995 |
| | 1,189 |
| General Partner’s interest in net income | 2 |
| | 3 |
| | 3 |
| Convertible Unitholders’ interest in income | 37 |
| | 9 |
| | — |
| Class D Unitholder’s interest in net income | — |
| | — |
| | 3 |
| Limited Partners’ interest in net income | $ | 915 |
| | $ | 983 |
| | $ | 1,183 |
|
STATEMENTS OF CASH FLOWS | | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES | $ | 831 |
| | $ | 918 |
| | $ | 1,103 |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | Cash paid for Bakken Pipeline Transaction | — |
| | — |
| | (817 | ) | Contributions to unconsolidated affiliates | (861 | ) | | (70 | ) | | — |
| Capital expenditures | (1 | ) | | (16 | ) | | (19 | ) | Contributions in aid of construction costs | 7 |
| | — |
| | — |
| Net cash used in investing activities | (855 | ) | | (86 | ) | | (836 | ) | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | Proceeds from borrowings | 2,219 |
| | 225 |
| | 3,672 |
| Principal payments on debt | (1,881 | ) | | (210 | ) | | (1,985 | ) | Distributions to partners | (1,010 | ) | | (1,022 | ) | | (1,090 | ) | Proceeds from affiliate | 174 |
| | 176 |
| | 210 |
| Common Units issued for cash | 568 |
| | — |
| | — |
| Units repurchased under buyback program | — |
| | — |
| | (1,064 | ) | Debt issuance costs | (47 | ) | | — |
| | (11 | ) | Net cash provided by (used in) financing activities | 23 |
| | (831 | ) | | (268 | ) | INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | (1 | ) | | 1 |
| | (1 | ) | CASH AND CASH EQUIVALENTS, beginning of period | 2 |
| | 1 |
| | 2 |
| CASH AND CASH EQUIVALENTS, end of period | $ | 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, 2017 and 2016 | S - 4 | Consolidated Statements of Operations – Years Ended December 31, 2017, 2016 and 2015 | S - 6 | Consolidated Statements of Comprehensive Income – Years Ended December 31, 2017, 2016 and 2015 | S - 7 | Consolidated Statements of Equity – Years Ended December 31, 2017, 2016 and 2015 | S - 8 | Consolidated Statements of Cash Flows – Years Ended December 31, 2017, 2016 and 2015 | S - 10 | Notes to Consolidated Financial Statements | S - 12 |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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, 2017 and 2016, the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, 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, 2017, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 23, 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 23, 2018
ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Dollars in millions) | | | | | | | | | | December 31, | | 2017 | | 2016* | ASSETS | | | | Current assets: | | | | Cash and cash equivalents | $ | 306 |
| | $ | 360 |
| Accounts receivable, net | 3,946 |
| | 3,002 |
| Accounts receivable from related companies | 318 |
| | 209 |
| Inventories | 1,589 |
| | 1,626 |
| Income taxes receivable | 135 |
| | 128 |
| Derivative assets | 24 |
| | 20 |
| Other current assets | 210 |
| | 298 |
| Total current assets | 6,528 |
| | 5,643 |
| | | | | Property, plant and equipment | 67,699 |
| | 58,220 |
| Accumulated depreciation and depletion | (9,262 | ) | | (7,303 | ) | | 58,437 |
| | 50,917 |
| | | | | Advances to and investments in unconsolidated affiliates | 3,816 |
| | 4,280 |
| Other non-current assets, net | 758 |
| | 672 |
| Intangible assets, net | 5,311 |
| | 4,696 |
| Goodwill | 3,115 |
| | 3,897 |
| Total assets | $ | 77,965 |
| | $ | 70,105 |
|
* As adjusted. See Note 2.
ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Dollars in millions) | | | | | | | | | | December 31, | | 2017 | | 2016* | LIABILITIES AND EQUITY | | | | Current liabilities: | | | | Accounts payable | $ | 4,126 |
| | $ | 2,900 |
| Accounts payable to related companies | 209 |
| | 43 |
| Derivative liabilities | 109 |
| | 166 |
| Accrued and other current liabilities | 2,143 |
| | 1,905 |
| Current maturities of long-term debt | 407 |
| | 1,189 |
| Total current liabilities | 6,994 |
| | 6,203 |
| | | | | Long-term debt, less current maturities | 32,687 |
| | 31,741 |
| Long-term notes payable – related company | — |
| | 250 |
| Non-current derivative liabilities | 145 |
| | 76 |
| Deferred income taxes | 2,883 |
| | 4,394 |
| Other non-current liabilities | 1,084 |
| | 952 |
| | | | | Commitments and contingencies |
| |
|
| Legacy ETP Preferred Units | — |
| | 33 |
| Redeemable noncontrolling interests | 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 | 244 |
| | 206 |
| Accumulated other comprehensive income | 3 |
| | 8 |
| Total partners’ capital | 28,269 |
| | 18,621 |
| Noncontrolling interest | 5,882 |
| | 7,820 |
| Total equity | 34,151 |
| | 26,441 |
| Total liabilities and equity | $ | 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, | | 2017 | | 2016* | | 2015* | REVENUES: | | | | | | Natural gas sales | $ | 4,172 |
| | $ | 3,619 |
| | $ | 3,671 |
| NGL sales | 6,972 |
| | 4,841 |
| | 3,936 |
| Crude sales | 10,184 |
| | 6,766 |
| | 8,378 |
| Gathering, transportation and other fees | 4,265 |
| | 4,003 |
| | 3,997 |
| Refined product sales (see Note 3) | 1,515 |
| | 1,047 |
| | 9,958 |
| Other (see Note 3) | 1,946 |
| | 1,551 |
| | 4,352 |
| Total revenues | 29,054 |
| | 21,827 |
| | 34,292 |
| COSTS AND EXPENSES: | | | | | | Cost of products sold (see Note 3) | 20,801 |
| | 15,080 |
| | 26,714 |
| Operating expenses (see Note 3) | 2,170 |
| | 1,839 |
| | 2,608 |
| Depreciation, depletion and amortization | 2,332 |
| | 1,986 |
| | 1,929 |
| Selling, general and administrative (see Note 3) | 434 |
| | 348 |
| | 475 |
| Impairment losses | 920 |
| | 813 |
| | 339 |
| Total costs and expenses | 26,657 |
| | 20,066 |
| | 32,065 |
| OPERATING INCOME | 2,397 |
| | 1,761 |
| | 2,227 |
| OTHER INCOME (EXPENSE): | | | | | | Interest expense, net | (1,365 | ) | | (1,317 | ) | | (1,291 | ) | Equity in earnings from unconsolidated affiliates | 156 |
| | 59 |
| | 469 |
| Impairment of investments in unconsolidated affiliates | (313 | ) | | (308 | ) | | — |
| Gains on acquisitions | — |
| | 83 |
| | — |
| Losses on extinguishments of debt | (42 | ) | | — |
| | (43 | ) | Losses on interest rate derivatives | (37 | ) | | (12 | ) | | (18 | ) | Other, net | 209 |
| | 131 |
| | 22 |
| INCOME BEFORE INCOME TAX BENEFIT | 1,005 |
| | 397 |
| | 1,366 |
| Income tax benefit | (1,496 | ) | | (186 | ) | | (123 | ) | NET INCOME | 2,501 |
| | 583 |
| | 1,489 |
| Less: Net income attributable to noncontrolling interest | 420 |
| | 295 |
| | 134 |
| Less: Net loss attributable to predecessor | — |
| | — |
| | (34 | ) | NET INCOME ATTRIBUTABLE TO PARTNERS | 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 | ) | NET INCOME (LOSS) PER COMMON UNIT: | | | | | | Basic | $ | 0.94 |
| | $ | (1.38 | ) | | $ | (0.07 | ) | Diluted | $ | 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, | | 2017 | | 2016* | | 2015* | Net income | $ | 2,501 |
| | $ | 583 |
| | $ | 1,489 |
| Other comprehensive income (loss), net of tax: | | | | | | Change in value of available-for-sale securities | 6 |
| | 2 |
| | (3 | ) | Actuarial gain (loss) relating to pension and other postretirement benefits | (12 | ) | | (1 | ) | | 65 |
| Foreign currency translation adjustment | — |
| | (1 | ) | | (1 | ) | Change in other comprehensive income (loss) from unconsolidated affiliates | 1 |
| | 4 |
| | (1 | ) | | (5 | ) | | 4 |
| | 60 |
| Comprehensive income | 2,496 |
| | 587 |
| | 1,549 |
| Less: Comprehensive income attributable to noncontrolling interest | 420 |
| | 295 |
| | 134 |
| Less: Comprehensive loss attributable to predecessor | — |
| | — |
| | (34 | ) | Comprehensive income attributable to partners | $ | 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 | | | | | | | | | | | | 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, 2014* | $ | — |
| | $ | — |
| | $ | 10,427 |
| | $ | 1,512 |
| | $ | — |
| | $ | 184 |
| | $ | (56 | ) | | $ | 5,143 |
| | $ | 8,088 |
| | $ | 25,298 |
| Distributions to partners | — |
| | — |
| | (1,863 | ) | | (247 | ) | | (80 | ) | | (944 | ) | | — |
| | — |
| | — |
| | (3,134 | ) | Distributions to noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (338 | ) | | — |
| | (338 | ) | Units issued for cash | — |
| | — |
| | 1,428 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1,428 |
| Subsidiary units issued for cash | — |
| | — |
| | 298 |
| | — |
| | — |
| | 2 |
| | — |
| | 1,219 |
| | — |
| | 1,519 |
| Capital contributions from noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 875 |
| | — |
| | 875 |
| Bakken Pipeline Transaction | — |
| | — |
| | (999 | ) | | 1,946 |
| | — |
| | — |
| | — |
| | 72 |
| | — |
| | 1,019 |
| Sunoco LP Exchange Transaction | — |
| | — |
| | (52 | ) | | — |
| | — |
| | — |
| | — |
| | (940 | ) | | — |
| | (992 | ) | Susser Exchange Transaction | — |
| | — |
| | (68 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (68 | ) | Acquisition and disposition of noncontrolling interest | — |
| | — |
| | (26 | ) | | — |
| | — |
| | — |
| | — |
| | (39 | ) | | — |
| | (65 | ) | Predecessor distributions to partners | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (202 | ) | | (202 | ) | Predecessor units issued for cash | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 34 |
| | 34 |
| Regency Merger | — |
| | — |
| | 7,890 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (7,890 | ) | | — |
| Other comprehensive income, net of tax | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 60 |
| | — |
| | — |
| | 60 |
| Other, net | — |
| | — |
| | 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 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Capital contributions from noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 236 |
| | — |
| | 236 |
| Sunoco, Inc. retail business to Sunoco LP transaction | — |
| | — |
| | (405 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (405 | ) | PennTex Acquisition | — |
| | — |
| | 307 |
| | — |
| | — |
| | — |
| | — |
| | 236 |
| | — |
| | 543 |
| Other comprehensive income, net of tax | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 4 |
| | — |
| | — |
| | 4 |
| Other, net | — |
| | — |
| | 10 |
| | — |
| | — |
| | — |
| | — |
| | 21 |
| | — |
| | 31 |
| Net income (loss) | — |
| | — |
| | (1,019 | ) | | 351 |
| | 8 |
| | 948 |
| | — |
| | 295 |
| | — |
| | 583 |
| 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, | | 2017 | | 2016* | | 2015* | OPERATING ACTIVITIES: | | | | | | Net income | $ | 2,501 |
| | $ | 583 |
| | $ | 1,489 |
| Reconciliation of net income to net cash provided by operating activities: | | | | | | Depreciation, depletion and amortization | 2,332 |
| | 1,986 |
| | 1,929 |
| Deferred income taxes | (1,531 | ) | | (169 | ) | | 202 |
| Amortization included in interest expense | 2 |
| | (20 | ) | | (36 | ) | Inventory valuation adjustments | — |
| | — |
| | (58 | ) | Unit-based compensation expense | 74 |
| | 80 |
| | 79 |
| Impairment losses | 920 |
| | 813 |
| | 339 |
| Gains on acquisitions | — |
| | (83 | ) | | — |
| Losses on extinguishments of debt | 42 |
| | — |
| | 43 |
| Impairment of investments in unconsolidated affiliates | 313 |
| | 308 |
| | — |
| Distributions on unvested awards | (31 | ) | | (25 | ) | | (16 | ) | Equity in earnings of unconsolidated affiliates | (156 | ) | | (59 | ) | | (469 | ) | Distributions from unconsolidated affiliates | 440 |
| | 406 |
| | 440 |
| Other non-cash | (261 | ) | | (271 | ) | | (22 | ) | Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | (160 | ) | | (246 | ) | | (1,173 | ) | Net cash provided by operating activities | 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 |
| | — |
| Proceeds from Bakken Pipeline Transaction | — |
| | — |
| | 980 |
| Proceeds from Susser Exchange Transaction | — |
| | — |
| | 967 |
| Proceeds from sale of noncontrolling interest | — |
| | — |
| | 64 |
| Cash paid for acquisition of PennTex noncontrolling interest | (280 | ) | | — |
| | — |
| Cash paid for Vitol Acquisition, net of cash received | — |
| | (769 | ) | | — |
| Cash paid for PennTex Acquisition, net of cash received | — |
| | (299 | ) | | — |
| Cash transferred to ETE in connection with the Sunoco LP Exchange | — |
| | — |
| | (114 | ) | Cash paid for acquisition of a noncontrolling interest | — |
| | — |
| | (129 | ) | Cash paid for all other acquisitions | (264 | ) | | (159 | ) | | (675 | ) | Capital expenditures, excluding allowance for equity funds used during construction | (8,335 | ) | | (7,550 | ) | | (9,098 | ) | Contributions in aid of construction costs | 24 |
| | 71 |
| | 80 |
| Contributions to unconsolidated affiliates | (268 | ) | | (59 | ) | | (45 | ) | Distributions from unconsolidated affiliates in excess of cumulative earnings | 136 |
| | 135 |
| | 124 |
| Proceeds from the sale of assets | 35 |
| | 25 |
| | 23 |
| Change in restricted cash | — |
| | 14 |
| | 19 |
| Other | 1 |
| | 1 |
| | (16 | ) | Net cash used in investing activities | (5,473 | ) | | (6,390 | ) | | (7,820 | ) | | | | | | |
| | | | | | | | | | | | | FINANCING ACTIVITIES: | | | | | | Proceeds from borrowings | 26,736 |
| | 19,916 |
| | 22,462 |
| Repayments of long-term debt | (26,494 | ) | | (15,799 | ) | | (17,843 | ) | 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 |
| Predecessor units issued for cash | — |
| | — |
| | 34 |
| Capital contributions from noncontrolling interest | 1,214 |
| | 236 |
| | 841 |
| Distributions to partners | (3,468 | ) | | (3,542 | ) | | (3,134 | ) | Predecessor distributions to partners | — |
| | — |
| | (202 | ) | Distributions to noncontrolling interest | (430 | ) | | (481 | ) | | (338 | ) | Redemption of Legacy ETP Preferred Units | (53 | ) | | — |
| | — |
| Debt issuance costs | (83 | ) | | (22 | ) | | (63 | ) | Other | 5 |
| | 2 |
| | — |
| Net cash provided by financing activities | 934 |
| | 2,920 |
| | 4,937 |
| Decrease in cash and cash equivalents | (54 | ) | | (167 | ) | | (136 | ) | Cash and cash equivalents, beginning of period | 360 |
| | 527 |
| | 663 |
| Cash and cash equivalents, end of period | $ | 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 Partners 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, NGLs and refined 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. Recent Accounting Pronouncements ASU 2014-09 In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from 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.
The Partnership adopted ASU 2014-09 on January 1, 2018. The Partnership applied the cumulative catchup transition method and recognized the cumulative effect of the retrospective application of the standard. The effect of the retrospective application of the standard was not material. For future periods, we expect that the adoption of this standard will result in a change to revenues with offsetting changes to costs associated primarily with the designation 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 accounting for noncash consideration in multiple of our reportable segments, as well as fuel usage and loss allowances. None of these changes is expected to have a material impact on 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 in the first quarter of 2019 and 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, 2018, the Partnership 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. We do not anticipate a material impact to our financial position or results of operations as a result of the adoption of this standard. ASU 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’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance did 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, 2018, with early adoption permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and 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. 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 segment 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, | | 2017 | | 2016 | | 2015 | Accounts receivable | $ | (950 | ) | | $ | (919 | ) | | $ | 819 |
| Accounts receivable from related companies | 67 |
| | 30 |
| | (243 | ) | Inventories | 37 |
| | (497 | ) | | (157 | ) | Other current assets | 39 |
| | 83 |
| | (178 | ) | Other non-current assets, net | (94 | ) | | (78 | ) | | 188 |
| Accounts payable | 758 |
| | 972 |
| | (1,215 | ) | Accounts payable to related companies | (3 | ) | | 29 |
| | (160 | ) | Accrued and other current liabilities | (47 | ) | | 39 |
| | (83 | ) | Other non-current liabilities | 24 |
| | 33 |
| | (219 | ) | Price risk management assets and liabilities, net | 9 |
| | 62 |
| | 75 |
| Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | $ | (160 | ) | | $ | (246 | ) | | $ | (1,173 | ) |
Non-cash investing and financing activities and supplemental cash flow information are as follows: | | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | NON-CASH INVESTING ACTIVITIES: | | | | | | Accrued capital expenditures | $ | 1,059 |
| | $ | 822 |
| | $ | 896 |
| Sunoco LP limited partner interest received in exchange for contribution of the Sunoco, Inc. retail business to Sunoco LP | — |
| | 194 |
| | — |
| Net gains from subsidiary common unit transactions | — |
| | 37 |
| | 300 |
| NON-CASH FINANCING ACTIVITIES: | | | | | | Issuance of Common Units in connection with the PennTex Acquisition | $ | — |
| | $ | 307 |
| | $ | — |
| Issuance of Common Units in connection with the Regency Merger | — |
| | — |
| | 9,250 |
| Issuance of Class H Units in connection with the Bakken Pipeline Transaction | — |
| | — |
| | 1,946 |
| Contribution of assets from noncontrolling interest | 988 |
| | — |
| | 34 |
| Redemption of Common Units in connection with the Bakken Pipeline Transaction | — |
| | — |
| | 999 |
| Redemption of Common Units in connection with the Sunoco LP Exchange | — |
| | — |
| | 52 |
| SUPPLEMENTAL CASH FLOW INFORMATION: | | | | | | Cash paid for interest, net of interest capitalized | $ | 1,329 |
| | $ | 1,411 |
| | $ | 1,467 |
| Cash paid for (refund of) income taxes | 50 |
| | (229 | ) | | 71 |
|
Accounts Receivable Our 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. We have a diverse portfolio of 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 and spare parts, all of which are valued at the lower of cost or net realizable value utilizing the weighted-average cost method.
Inventories consisted of the following: | | | | | | | | | | 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, | | 2017 | | 2016 | Deposits paid to vendors | $ | 64 |
| | $ | 74 |
| Prepaid expenses and other | 146 |
| | 224 |
| Total other current assets | $ | 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 NGL 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, | | 2017 | | 2016 | Land and improvements | $ | 1,706 |
| | $ | 676 |
| Buildings and improvements (1 to 45 years) | 1,960 |
| | 1,617 |
| Pipelines and equipment (5 to 83 years) | 44,050 |
| | 36,356 |
| Natural gas and NGL storage facilities (5 to 46 years) | 1,681 |
| | 1,452 |
| Bulk storage, equipment and facilities (2 to 83 years) | 3,036 |
| | 3,701 |
| Vehicles (1 to 25 years) | 124 |
| | 217 |
| Right of way (20 to 83 years) | 3,424 |
| | 3,349 |
| Natural resources | 434 |
| | 434 |
| Other (1 to 40 years) | 534 |
| | 484 |
| Construction work-in-process | 10,750 |
| | 9,934 |
| | 67,699 |
| | 58,220 |
| Less – Accumulated depreciation and depletion | (9,262 | ) | | (7,303 | ) | Property, plant and equipment, net | $ | 58,437 |
| | $ | 50,917 |
|
We recognized the following amounts for the periods presented: | | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | Depreciation and depletion expense | $ | 2,060 |
| | $ | 1,793 |
| | $ | 1,713 |
| 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, | | 2017 | | 2016 | Regulatory assets | $ | 85 |
| | $ | 86 |
| Deferred charges | 210 |
| | 217 |
| Restricted funds | 192 |
| | 190 |
| Long-term affiliated receivable | 85 |
| | 90 |
| Other | 186 |
| | 89 |
| Total other non-current assets, net | $ | 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, 2017 | | December 31, 2016 | | Gross Carrying Amount | | Accumulated Amortization | | Gross Carrying Amount | | Accumulated Amortization | Amortizable intangible assets: | | | | | | | | Customer relationships, contracts and agreements (3 to 46 years) | $ | 6,250 |
| | $ | (1,003 | ) | | $ | 5,362 |
| | $ | (737 | ) | Patents (10 years) | 48 |
| | (26 | ) | | 48 |
| | (21 | ) | Trade Names (20 years) | 66 |
| | (25 | ) | | 66 |
| | (22 | ) | Other (5 to 20 years) | 1 |
| | — |
| | 2 |
| | (2 | ) | Total intangible assets | $ | 6,365 |
| | $ | (1,054 | ) | | $ | 5,478 |
| | $ | (782 | ) |
Aggregate amortization expense of intangible assets was as follows: | | | | | | | | | | | | | | 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: | | 2018 | $ | 280 |
| 2019 | 278 |
| 2020 | 278 |
| 2021 | 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 NGL 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 | | NGL and Refined Products Transportation and Services | | Crude Oil Transportation and Services | | All Other | | Total | 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 | — |
| | (262 | ) | | — |
| | (79 | ) | | — |
| | (452 | ) | | (793 | ) | Other | — |
| | — |
| | (1 | ) | | — |
| | — |
| | — |
| | (1 | ) | 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 $99 million in the interstate transportation and storage segment and $106 million in the NGL and refined products transportation and services segment primarily due to market declines in current and expected future commodity prices in the fourth quarter of 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 discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as of December 31, 2017 and 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. We 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. As of December 31, 2017 and 2016, other non-current liabilities in the Partnership’s consolidated balance 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 $2 million and $14 million, and were reflected as property, plant and equipment on our balance sheet as of December 31, 2017 and 2016, respectively. In addition, the Partnership had $21 million and $13 million legally restricted funds for the purpose of settling AROs that was reflected as other non-current assets as of December 31, 2017 and 2016, respectively. Accrued and Other Current Liabilities Accrued and other current liabilities consisted of the following: | | | | | | | | | | December 31, | | 2017 | | 2016 | Interest payable | $ | 443 |
| | $ | 440 |
| Customer advances and deposits | 59 |
| | 56 |
| Accrued capital expenditures | 1,006 |
| | 749 |
| Accrued wages and benefits | 208 |
| | 212 |
| Taxes payable other than income taxes | 108 |
| | 63 |
| Exchanges payable | 154 |
| | 208 |
| Other | 165 |
| | 177 |
| Total accrued and other current liabilities | $ | 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 our consolidated subsidiaries has the option to sell its interests to 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, 2017 was $34.28 billion and $33.09 billion, respectively. As of December 31, 2016, the aggregate fair value and carrying amount of our debt obligations was $33.85 billion and $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. During the year ended December 31, 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, 2017 and 2016 based on inputs used to derive their fair values: | | | | | | | | | | | | | | Fair Value Total | | Fair Value Measurements at December 31, 2017 | | Level 1 | | Level 2 | Assets: | | | | | | Commodity derivatives: | | | | | | Natural Gas: | | | | | | Basis Swaps IFERC/NYMEX | $ | 11 |
| | $ | 11 |
| | $ | — |
| Swing Swaps IFERC | 13 |
| | — |
| | 13 |
| Fixed Swaps/Futures | 70 |
| | 70 |
| | — |
| Forward Physical Swaps | 8 |
| | — |
| | 8 |
| Power: | | | | | | Forwards | 23 |
| | — |
| | 23 |
| Natural Gas Liquids – Forwards/Swaps | 193 |
| | 193 |
| | — |
| Crude – Futures | 2 |
| | 2 |
| | — |
| Total commodity derivatives | 320 |
| | 276 |
| | 44 |
| Other non-current assets | 21 |
| | 14 |
| | 7 |
| Total assets | $ | 341 |
| | $ | 290 |
| | $ | 51 |
| Liabilities: | | | | | | Interest rate derivatives | $ | (219 | ) | | $ | — |
| | $ | (219 | ) | Commodity derivatives: | | | | | | Natural Gas: | | | | | | Basis Swaps IFERC/NYMEX | (24 | ) | | (24 | ) | | — |
| Swing Swaps IFERC | (15 | ) | | (1 | ) | | (14 | ) | Fixed Swaps/Futures | (57 | ) | | (57 | ) | | — |
| Forward Physical Swaps | (2 | ) | | — |
| | (2 | ) | Power – Forwards | (22 | ) | | — |
| | (22 | ) | Natural Gas Liquids – Forwards/Swaps | (192 | ) | | (192 | ) | | — |
| Refined Products – Futures | (25 | ) | | (25 | ) | | — |
| Crude – Futures | (1 | ) | | (1 | ) | | — |
| Total commodity derivatives | (338 | ) | | (300 | ) | | (38 | ) | Total liabilities | $ | (557 | ) | | $ | (300 | ) | | $ | (257 | ) |
| | | | | | | | | | | | | | | | | | 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 Cost 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, 2015, 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 by our 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, and 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 The 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 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. Changes 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 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: |
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, payspursuant 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 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, ETP contributed 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 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 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’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”), which increased Sunoco 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.
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 provided substantially all of the remaining capital necessary to complete the projects. As of December 31, 2017, $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, 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: | | | | | | Year Ended December 31, 2015 | Revenues | $ | 12,482 |
| Cost of products sold | 11,174 |
| Operating expenses | 798 |
| Selling, general and administrative expenses | 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 in 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 31.5 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 provided 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. At December 31, 2017, the Partnership held 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 46.2 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 entitled 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 provided 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 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 and 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 0.6186 Partnership common units. ETP issued 258.3 million Partnership common units to Regency unitholders, including 23.3 million units issued to Partnership subsidiaries. Regency’s 1.9 million outstanding Series A Convertible Preferred Units were converted into corresponding Legacy 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.
| | 4. | ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES: |
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, an approximately 5,360-mile natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula. Our investment in Citrus is reflected in our 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, 2017, the Partnership’s interest in Sunoco LP common units consisted of 43.5 million units, representing 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, Citrus, FEP, MEP, HPC and Sunoco LP (on a 100% basis) for all periods presented: | | | | | | | | | | December 31, | | 2017 | | 2016 | Current assets | $ | 4,750 |
| | $ | 1,532 |
| Property, plant and equipment, net | 9,893 |
| | 10,310 |
| Other assets | 2,286 |
| | 5,980 |
| Total assets | $ | 16,929 |
| | $ | 17,822 |
| | | | | Current liabilities | $ | 2,075 |
| | $ | 1,918 |
| Non-current liabilities | 9,375 |
| | 10,343 |
| Equity | 5,479 |
| | 5,561 |
| Total liabilities and equity | $ | 16,929 |
| | $ | 17,822 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | Revenue | $ | 13,081 |
| | $ | 11,150 |
| | $ | 13,815 |
| Operating income | 636 |
| | 859 |
| | 1,052 |
| 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, | | 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, | | 2017 | | 2016 | ETP Debt | | | | 6.125% Senior Notes due February 15, 2017 | $ | — |
| | $ | 400 |
| 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 |
| 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 |
|
| | | | | | | | | 4.15% Senior Notes due October 1, 2020 | 1,050 |
| | 1,050 |
| 4.40% Senior Notes due April 1, 2021 | 600 |
| | 600 |
| 6.50% Senior Notes due July 15, 2021 | — |
| | 500 |
| 4.65% Senior Notes due June 1, 2021 | 800 |
| | 800 |
| 5.20% Senior Notes due February 1, 2022 | 1,000 |
| | 1,000 |
| 4.65% Senior Notes due February 15, 2022 | 300 |
| | 300 |
| 5.875% Senior Notes due March 1, 2022 | 900 |
| | 900 |
| 5.00% Senior Notes due October 1, 2022 | 700 |
| | 700 |
| 3.45% Senior Notes due January 15, 2023 | 350 |
| | 350 |
| 3.60% Senior Notes due February 1, 2023 | 800 |
| | 800 |
| 5.50% Senior Notes due April 15, 2023 | — |
| | 700 |
| 4.50% Senior Notes due November 1, 2023 | 600 |
| | 600 |
| 4.90% Senior Notes due February 1, 2024 | 350 |
| | 350 |
| 7.60% Senior Notes due February 1, 2024 | 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 |
| 5.95% Senior Notes due December 1, 2025 | 400 |
| | 400 |
| 4.75% Senior Notes due January 15, 2026 | 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 |
| 4.90% Senior Notes due March 15, 2035 | 500 |
| | 500 |
| 6.625% Senior Notes due October 15, 2036 | 400 |
| | 400 |
| 7.50% Senior Notes due July 1, 2038 | 550 |
| | 550 |
| 6.85% Senior Notes due February 15, 2040 | 250 |
| | 250 |
| 6.05% Senior Notes due June 1, 2041 | 700 |
| | 700 |
| 6.50% Senior Notes due February 1, 2042 | 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 |
| 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 |
| Deferred debt issuance costs | (1 | ) | | (1 | ) | | 574 |
| | 656 |
| Panhandle Debt | | | | 6.20% Senior Notes due November 1, 2017 | — |
| | 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 | 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) | As of December 31, 2017 management had the intent and ability to refinance the $650 million 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 based 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 $118 million in unamortized net premiums, fair value adjustments and deferred debt issuance costs: | | | | | | 2018 | | $ | 1,700 |
| 2019 | | 3,500 |
| 2020 | | 1,875 |
| 2021 | | 1,400 |
| 2022 | | 5,346 |
| Thereafter | | 19,391 |
| Total | | $ | 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 Senior Notes 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 as 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 4.39% at December 31, 2017. Credit Facilities and Commercial Paper ETP Credit Facilities On 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 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. We use the ETP Credit Facilities to provide temporary financing for our 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 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”), 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. In connection with the Sunoco Logistics Merger, the 364-Day Credit Facility was terminated and repaid in May 2017. Bakken Credit Facility In August 2016, Energy Transfer Partners, L.P., Sunoco Logistics and Phillips 66 completed project-level financing of the 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, 2017, the Bakken Credit Facility had $2.50 billion of outstanding borrowings. The weighted average interest rate on the total amount outstanding as of December 31, 2017 was 3.00%. PennTex Revolving Credit Facility PennTex previously maintained a $275 million revolving credit commitment (the “PennTex Revolving Credit Facility”). In August 2017, the PennTex Revolving Credit Facility was 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 Facilities 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 Facilities) during certain Defaults (as defined in the ETP Credit Facilities) and during any Event of Default (as defined in the ETP Credit 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 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 Facilities also limit us, on a rolling four quarter basis, to a maximum Consolidated Funded Indebtedness to Consolidated EBITDA ratio, as defined in the underlying credit agreements, of 5.0 to 1, which can generally be increased to 5.5 to 1 during a Specified Acquisition Period. Our Leverage Ratio was 3.96 to 1 at December 31, 2017, as calculated in accordance with the 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 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. Compliance with our Covenants We were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2017.
| | 7. | LEGACY ETP PREFERRED UNITS: |
The Legacy ETP Preferred Units were mandatorily redeemable on September 2, 2029 for $35 million plus all accrued but unpaid distributions and interest thereon and were reflected as long-term liabilities in our consolidated balance sheets. The Legacy ETP Preferred Units were 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. In January 2017, ETP repurchased all of its 1.9 million outstanding Legacy 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 I Units, Class J Units and Class K 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, | | 2017 (1) | | 2016 (1) | | 2015 (1) | Number of Common Units, beginning of period | 794.8 |
| | 758.5 |
| | 533.4 |
| Common Units redeemed in connection with certain transactions | — |
| | (26.7 | ) | | (77.8 | ) | Common Units issued in connection with public offerings | 54.0 |
| | — |
| | — |
| Common Units issued in connection with certain acquisitions | — |
| | 13.3 |
| | 258.2 |
| Common Units issued in connection with the Distribution Reinvestment Plan | 12.0 |
| | 9.9 |
| | 11.7 |
| Common Units issued in connection with Equity Distribution Agreements | 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 | 1.6 |
| | 0.8 |
| | 1.3 |
| Number of Common Units, end of period | 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 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 $1.00 billion. During the year ended December 31, 2017, we issued 22.6 million units for $503 million, net of commissions of $5 million. As of December 31, 2017, $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 and 2015, aggregate distributions of $228 million, $216 million, and $360 million, respectively, were reinvested under the DRIP resulting in the issuance in aggregate of 25.5 million Common Units. As of December 31, 2017, a total of 20.8 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 23.7 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. As the Class E Units are owned by a wholly-owned subsidiary, 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 the Class E Units at a future date. Class G Units There are currently 90.7 million Class G Units outstanding, all of which are held by a wholly-owned subsidiary of the Partnership. The Class G Units generally do not have any voting rights. The Class G Units are 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 G Unit per year. Allocations 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 reflected as treasury units in the consolidated financial statements. Class H Units 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 were 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. The Class H units were cancelled in connection with the merger of ETP and Sunoco Logistics in April 2017. Class I Units In connection with the 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 ended 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 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. 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, 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, 2017, a total of 101.5 million Class K Units were held by wholly-owned subsidiaries of ETP. Sales of Common Units by legacy 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 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 Sunoco Logistics Merger, the previous Sunoco Logistics equity distribution agreement was terminated. ETP Preferred Units In November 2017, ETP issued 950,000 of its 6.250% Series A Preferred Units at a price of $1,000 per unit, and 550,000 of 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 date of original 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 not previously owned by ETP for $20.00 per common unit in cash. ETP now owns all of the economic interests of PennTex, and PennTex common units are no longer publicly traded or listed on the NASDAQ. Quarterly Distributions of Available Cash Under the Partnership’s limited partnership agreement, within 45 days after the end of each quarter, the Partnership distributes all cash on hand at the end of the quarter, less reserves established by the general partner in its discretion. This is defined as “available cash” in the partnership agreement. The general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct the Partnership’s business. The Partnership will make quarterly distributions to the extent 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.” The following table shows the target distribution levels and distribution “splits” between the general and limited partners and the holders of the Partnership’s incentive distribution rights (”IDRs”): | | | | | | | | | | | | 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 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, ETE has agreed to relinquish its right to the following amounts of incentive distributions in future periods: | | | | | | | | Total Year | 2018 | | $ | 153 |
| 2019 | | 128 |
| Each year beyond 2019 | | 33 |
|
Distributions declared and paid by ETP to the preferred unitholders were as follows: | | | | | | | | | | | | | | | 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, | | 2017 | | 2016 | Available-for-sale securities | $ | 8 |
| | $ | 2 |
| Foreign currency translation adjustment | (5 | ) | | (5 | ) | Actuarial gain related to pensions and other postretirement benefits | (5 | ) | | 7 |
| Investments in unconsolidated affiliates, net | 5 |
| | 4 |
| Total AOCI, net of tax | $ | 3 |
| | $ | 8 |
|
The table below sets forth the tax amounts included in the respective components of other comprehensive income: | | | | | | | | | | December 31, | | 2017 | | 2016 | Available-for-sale securities | $ | (2 | ) | | $ | (2 | ) | Foreign currency translation adjustment | 3 |
| | 3 |
| Actuarial loss relating to pension and other postretirement benefits | 3 |
| | — |
| Total | $ | 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, 2017, an aggregate total of 8.4 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 | 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 | 4.9 |
| | 17.69 |
| Awards vested | (2.3 | ) | | 34.22 |
| Awards forfeited | (1.1 | ) | | 25.03 |
| Unvested awards as of December 31, 2017 | 14.1 |
| | 23.18 |
|
During the years ended December 31, 2017, 2016, and 2015, the weighted average grant-date fair value per unit award granted was $17.69, $23.82 and $23.47, respectively. The total fair value of awards vested was $40 million, $40 million and $57 million, respectively, based on the market price of ETP Common Units as of the vesting date. As of December 31, 2017, a total of 14.1 million unit awards remain unvested, for which ETP expects to recognize a total of $189 million in compensation expense over a weighted average period of 2.7 years. Cash Restricted Units. The Partnership previously granted cash restricted units, which entitled the award recipient to receive cash equal to the market value of one ETP Common Unit upon vesting. The Partnership does not currently have any cash restricted units outstanding.
As a partnership, we are not subject to 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, | | 2017 | | 2016 | | 2015 | Current expense (benefit): | | | | | | Federal | $ | 53 |
| | $ | 18 |
| | $ | (274 | ) | State | (18 | ) | | (35 | ) | | (51 | ) | Total | 35 |
| | (17 | ) | | (325 | ) | Deferred expense (benefit): | | | | | | Federal | (1,723 | ) | | (173 | ) | | 231 |
| State | 192 |
| | 4 |
| | (29 | ) | Total | (1,531 | ) | | (169 | ) | | 202 |
| 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 United States federal and most state income taxes at the partnership level. A reconciliation of income tax expense at the United States statutory rate to the Partnership’s income tax benefit for the years ended December 31, 2017, 2016 and 2015 is as follows: | | | | | | | | | | | | | | 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, | | 2017 | | 2016 | Deferred income tax assets: | | | | Net operating losses and alternative minimum tax credit | $ | 604 |
| | $ | 380 |
| Pension and other postretirement benefits | 21 |
| | 30 |
| Long-term debt | 14 |
| | 32 |
| Other | 93 |
| | 84 |
| Total deferred income tax assets | 732 |
| | 526 |
| Valuation allowance | (189 | ) | | (118 | ) | Net deferred income tax assets | $ | 543 |
| | $ | 408 |
| | | | | Deferred income tax liabilities: | | | | Property, plant and equipment | $ | (664 | ) | | $ | (1,054 | ) | Investment in unconsolidated affiliates | (2,664 | ) | | (3,728 | ) | Other | (98 | ) | | (20 | ) | Total deferred income tax liabilities | (3,426 | ) | | (4,802 | ) | 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, | | 2017 | | 2016 | Net deferred income tax liability, beginning of year | $ | (4,394 | ) | | $ | (4,082 | ) | Goodwill associated with Sunoco Retail to Sunoco LP transaction (see Note 3) | — |
| | (460 | ) | Tax provision | 1,531 |
| | 169 |
| Other | (20 | ) | | (21 | ) | Net deferred income tax liability, end of year | $ | (2,883 | ) | | $ | (4,394 | ) |
ETP Holdco and other corporate subsidiaries have federal net operating loss carryforward of $1.57 billion, all of which will expire in 2031 through 2037. Our corporate subsidiaries have $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 state net operating loss carryforward benefits of $210 million, net of federal tax, which expire between 2018 and 2036. A valuation allowance of $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 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, | | 2017 | | 2016 | | 2015 | Balance at beginning of year | $ | 615 |
| | $ | 610 |
| | $ | 440 |
| Additions attributable to tax positions taken in the current year | — |
| | 8 |
| | — |
| Additions attributable to tax positions taken in prior years | 28 |
| | 18 |
| | 178 |
| Reduction attributable to tax positions taken in prior years | (25 | ) | | (20 | ) | | — |
| Lapse of statute | (9 | ) | | (1 | ) | | (8 | ) | Balance at end of year | $ | 609 |
| | $ | 615 |
| | $ | 610 |
|
As of December 31, 2017, we have $605 million ($576 million after federal income tax benefits) related to tax positions which, if recognized, would impact our effective tax rate. Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During 2017, we recognized interest and penalties of less than $3 million. At December 31, 2017, we have interest and penalties accrued of $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, 2017. In December 2015, the Pennsylvania Commonwealth Court determined in Nextel Communications v. Commonwealth (“Nextel”) that the Pennsylvania limitation on NOL carryforward deductions violated the uniformity clause of the Pennsylvania Constitution and struck the NOL limitation in its entirety. In October 2017, the Pennsylvania Supreme Court affirmed the decision 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. has recognized approximately $67 million ($53 million after federal income tax benefits) in tax benefit based on previously filed tax returns and certain previously filed protective claims as relates to its cases currently held pending the Nextel matter. However, based upon the Pennsylvania Supreme Court’s
October 2017 decision, and because of uncertainty in the breadth of the application of the decision, we have reserved $27 million ($21 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 previously provided contingent residual support of certain debt obligations of AmeriGas. AmeriGas has subsequently repaid the remainder of the related obligations and ETP no longer provides contingent residual support for any AmeriGas 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 (“ETC M-A”). On 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: $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 the obligation to pay the principal of each series of notes once all remedies, including in the 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 respect of the principal of such notes. ETC M-A will not otherwise be subject to the covenants of the indenture governing the 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, | | | 2017 | | 2016 | | 2015 | Rental expense(1) | | $ | 90 |
| | $ | 81 |
| | $ | 176 |
| Less: Sublease rental income | | — |
| | (1 | ) | | (16 | ) | Rental expense, net | | $ | 90 |
| | $ | 80 |
| | $ | 160 |
|
| | (1) | Includes contingent rentals totaling $26 million for the year ended December 31, 2015. |
Future minimum lease commitments for such leases are: | | | | | Years Ending December 31: | | 2018 | $ | 39 |
| 2019 | 36 |
| 2020 | 37 |
| 2021 | 30 |
| 2022 | 23 |
| Thereafter | 92 |
| Future minimum lease commitments | 257 |
| Less: Sublease rental income | (8 | ) | Net future minimum lease commitments | $ | 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 On July 25, 2016, the 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. After significant delay, the USACE also issued easements to allow the pipeline to cross land owned by the USACE adjacent to the Missouri River in two locations. Also in July, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia against the USACE that challenged the legality of the permits issued for the construction of the Dakota Access pipeline across those waterways and claimed 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 intervened in the case. The SRST soon added a
request for an emergency temporary restraining order (“TRO”) to stop construction on the pipeline project. On September 9, 2016, the Court denied SRST’s motion for a preliminary injunction, rendering the TRO request moot. After the September 9, 2016 ruling, the Department of the Army, the DOJ, and the Department of the Interior released a joint statement that the USACE would not grant the easement for the land adjacent to Lake Oahe until the Department of the Army completed a review to determine whether it was necessary to reconsider the USACE’s decision under various federal statutes relevant to the pipeline approval. The SRST appealed the denial of the preliminary injunction to the 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, 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 statutes governing the use of government property. 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 February 2017, in 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 allowing the pipeline to cross Lake Oahe. Almost immediately, the Cheyenne River Sioux Tribe (“CRST”), which had intervened in the lawsuit in August 2016, moved for a preliminary injunction and 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 Court denied the TRO and preliminary injunction, and the CRST appealed and requested an injunction pending appeal in the district court 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 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 halt or suspend the operation of the pipeline, we cannot assure this outcome. 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”) 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 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. Lone Star is still quantifying the extent of its incurred and ongoing damages 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 members of the petroleum industry, are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices. The plaintiffs 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, 2017, Sunoco, Inc. is a defendant in seven cases, including one case each initiated by the States of Maryland, New Jersey, Vermont, Rhode Island, one by the Commonwealth of Pennsylvania and two by the Commonwealth of Puerto Rico. The more recent Puerto Rico action is 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 pending in a multidistrict litigation proceeding in a New York federal court; one is pending in federal court in Rhode Island, one is pending in state court in Vermont, and one is pending in state court in Maryland. Sunoco, Inc. and Sunoco, Inc. (R&M) have reached a settlement with the State of New Jersey. The Court approved the Judicial Consent Order on December 5, 2017. Dismissal of the case against Sunoco, Inc. and 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. An 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 such adverse determination occurs, but 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-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. On June 10, 2015, Adrian Dieckman (“Dieckman”), a purported Regency unitholder, filed a class action complaint, Dieckman v. Regency GP LP, et al., C.A. No. 11130-CB, in the Court of Chancery of the State of 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 Regency 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. On March 29, 2016, the Delaware Court of Chancery granted the Regency Litigation Defendants’ motion to dismiss the lawsuit in its entirety. Dieckman appealed. On January 20, 2017, the Delaware Supreme Court reversed 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 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 filed a notice of appeal with the Court of Appeals. On July 18, 2017, the Court of Appeals issued its opinion and reversed 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 due February 26, 2018. Sunoco Logistics Merger Litigation Seven purported Energy Transfer Partners, L.P. common unitholders (the “ETP Unitholder Plaintiffs”) separately filed seven putative unitholder class action lawsuits against ETP, ETP GP, ETP LLC, the members of the ETP Board, and ETE (the “ETP-SXL Defendants”) in connection with the announcement of the Sunoco Logistics Merger. Two of these lawsuits were voluntarily dismissed in March 2017. The five remaining lawsuits were consolidated as In re Energy Transfer Partners, L.P. Shareholder Litig., C.A. No. 1:17-cv-00044-CCC, in the United States District Court for the District of Delaware (the “Sunoco Logistics Merger Litigation”). The ETP Unitholder Plaintiffs allege causes of action challenging the merger and the proxy statement/prospectus filed in connection with the Sunoco Logistics Merger (the “ETP-SXL Merger Proxy”). The ETP Unitholder Plaintiffs sought rescission of the Sunoco Logistics Merger or rescissory damages for ETP unitholders, as well as an award of costs and attorneys’ fees. On October 5, 2017, the ETP-SXL Defendants filed a Motion to Dismiss the ETP Unitholder Plaintiffs’ claims. Rather than respond to the 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 any such lawsuits might be. Nor can the ETP-SXL Defendants predict the amount of time and expense that would be required to resolve such lawsuits. The ETP-SXL Defendants believe the Sunoco Logistics Merger Litigation was without merit and intend to defend vigorously against any future lawsuits challenging the 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, 2017 and 2016, accruals of approximately $33 million and $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, 2017 or 2016 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein. 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. 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, 2017, Sunoco, Inc. had been named as a PRP at approximately 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, | | 2017 | | 2016 | Current | $ | 36 |
| | $ | 26 |
| Non-current | 314 |
| | 283 |
| Total environmental liabilities | $ | 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, 2017 and 2016, the Partnership recorded $23 million and $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 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 to 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 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, we experienced a release on our products pipeline in Wellington, Ohio. In connection with this release, the PHMSA issued a Corrective Action Order under which we are obligated to follow specific requirements in the investigation of the release and the repair and reactivation of the pipeline. This 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. We have also received a “No Further Action” approval from the Ohio EPA for all soil and groundwater remediation requirements. In May 2016, we received a proposed penalty from the EPA and DOJ 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, we do not expect there to be a material impact to our 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 our 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. We do not expect there to be a material impact to our 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 our Permian Express 2 pipeline system in Texas. The proposed penalties are in excess of $100,000. The case went to Hearing in November 2016 and remains open with PHMSA. We do not expect there to be a material impact to our 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 our crude oil pipeline near Wortham, Texas. The proposed penalties are in excess of $100,000. The case went to hearing in March 2017 and remains open with PHMSA. We do not expect there to be a material impact to our 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, Occupational 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 utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and 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, 2017 | | December 31, 2016 | | Notional Volume | | Maturity | | Notional Volume | | Maturity | Mark-to-Market Derivatives | | | | | | | | (Trading) | | | | | | | | Natural Gas (BBtu): | | | | | | | | Fixed Swaps/Futures | 1,078 |
| | 2018 | | (683 | ) | | 2017 | Basis Swaps IFERC/NYMEX(1) | 48,510 |
| | 2018-2020 | | 2,243 |
| | 2017 | Options – Calls | 13,000 |
| | 2018 | | — |
| | — | Power (Megawatt): | | | | | | | | Forwards | 435,960 |
| | 2018-2019 | | 391,880 |
| | 2017-2018 | Futures | (25,760 | ) | | 2018 | | 109,564 |
| | 2017-2018 | Options – Puts | (153,600 | ) | | 2018 | | (50,400 | ) | | 2017 | Options – Calls | 137,600 |
| | 2018 | | 186,400 |
| | 2017 | Crude (MBbls) – Futures | — |
| | — | | (617 | ) | | 2017 | (Non-Trading) | | | | | | | | Natural Gas (BBtu): | | | | | | | | Basis Swaps IFERC/NYMEX | 4,650 |
| | 2018-2020 | | 10,750 |
| | 2017-2018 | Swing Swaps IFERC | 87,253 |
| | 2018-2019 | | (5,663 | ) | | 2017 | Fixed Swaps/Futures | (4,700 | ) | | 2018-2019 | | (52,653 | ) | | 2017-2019 | Forward Physical Contracts | (145,105 | ) | | 2018-2020 | | (22,492 | ) | | 2017 | 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 (BBtu): | | | | | | | | Basis Swaps IFERC/NYMEX | (39,770 | ) | | 2018 | | (36,370 | ) | | 2017 | Fixed Swaps/Futures | (39,770 | ) | | 2018 | | (36,370 | ) | | 2017 | Hedged Item – Inventory | 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, 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 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 | | Asset Derivatives | | Liability Derivatives | | December 31, 2017 | | December 31, 2016 | | December 31, 2017 | | December 31, 2016 | Derivatives designated as hedging instruments: | | | | | | | | Commodity derivatives (margin deposits) | $ | 14 |
| | $ | — |
| | $ | (2 | ) | | $ | (4 | ) | | 14 |
| | — |
| | (2 | ) | | (4 | ) | Derivatives not designated as hedging instruments: | | | | | | | | Commodity derivatives (margin deposits) | 262 |
| | 338 |
| | (281 | ) | | (416 | ) | Commodity derivatives | 44 |
| | 24 |
| | (55 | ) | | (52 | ) | Interest rate derivatives | — |
| | — |
| | (219 | ) | | (193 | ) | Embedded derivatives in Legacy ETP Preferred Units | — |
| | — |
| | — |
| | (1 | ) | | 306 |
| | 362 |
| | (555 | ) | | (662 | ) | Total derivatives | $ | 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 | | | Balance Sheet Location | | December 31, 2017 | | December 31, 2016 | | December 31, 2017 | | December 31, 2016 | Derivatives without offsetting agreements | | Derivative liabilities | | $ | — |
| | $ | — |
| | $ | (219 | ) | | $ | (194 | ) | Derivatives in offsetting agreements: | | | | | | | | | OTC contracts | | Derivative assets (liabilities) | | 44 |
| | 24 |
| | (55 | ) | | (52 | ) | Broker cleared derivative contracts | | Other current assets (liabilities) | | 276 |
| | 338 |
| | (283 | ) | | (420 | ) | | | 320 |
| | 362 |
| | (557 | ) | | (666 | ) | Offsetting agreements: | | | | | | | | | Counterparty netting | | Derivative assets (liabilities) | | (20 | ) | | (4 | ) | | 20 |
| | 4 |
| Counterparty netting | | Other current assets (liabilities) | | (263 | ) | | (338 | ) | | 263 |
| | 338 |
| 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) 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, | | | | 2017 | | 2016 | | 2015 | Derivatives in fair value hedging relationships (including hedged item): | | | | | | | | Commodity derivatives | Cost of products sold | | $ | 26 |
| | $ | 14 |
| | $ | 21 |
| Total | | | $ | 26 |
| | $ | 14 |
| | $ | 21 |
|
| | | | | | | | | | | | | | | | 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 |
|
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 and $39 million to these 401(k) savings plans for the years ended December 31, 2017, 2016, and 2015, 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, 2017 | | December 31, 2016 | | Pension Benefits | | | | Pension 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 | $ | 18 |
| | $ | 51 |
| | $ | 165 |
| | $ | 20 |
| | $ | 57 |
| | $ | 180 |
| Interest cost | 1 |
| | 1 |
| | 4 |
| | 1 |
| | 2 |
| | 4 |
| Amendments | — |
| | — |
| | 7 |
| | — |
| | — |
| | — |
| Benefits paid, net | (2 | ) | | (6 | ) | | (20 | ) | | (1 | ) | | (7 | ) | | (21 | ) | Actuarial (gain) loss and other | 2 |
| | 1 |
| | (1 | ) | | (2 | ) | | (1 | ) | | 2 |
| Settlements | (18 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| Benefit obligation at end of period | 1 |
| | 47 |
| | 155 |
| | 18 |
| | 51 |
| | 165 |
| | | | | | | | | | | | | Change in plan assets: | | | | | | | | | | | | Fair value of plan assets at beginning of period | 12 |
| | — |
| | 248 |
| | 15 |
| | — |
| | 253 |
| Return on plan assets and other | 3 |
| | — |
| | 11 |
| | (2 | ) | | — |
| | 6 |
| Employer contributions | 6 |
| | — |
| | 10 |
| | — |
| | — |
| | 10 |
| Benefits paid, net | (2 | ) | | — |
| | (20 | ) | | (1 | ) | | — |
| | (21 | ) | Settlements | (18 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| Fair value of plan assets at end of period | 1 |
| | — |
| | 249 |
| | 12 |
| | — |
| | 248 |
| | | | | | | | | | | | | Amount underfunded (overfunded) at end of period | $ | — |
| | $ | 47 |
| | $ | (94 | ) | | $ | 6 |
| | $ | 51 |
| | $ | (83 | ) | | | | | | | | | | | | | Amounts recognized in the consolidated balance sheets consist of: | | | | | | | | | | | | Non-current assets | $ | — |
| | $ | — |
| | $ | 120 |
| | $ | — |
| | $ | — |
| | $ | 108 |
| Current liabilities | — |
| | (8 | ) | | (2 | ) | | — |
| | (7 | ) | | (2 | ) | Non-current liabilities | — |
| | (39 | ) | | (24 | ) | | (6 | ) | | (44 | ) | | (23 | ) | | $ | — |
| | $ | (47 | ) | | $ | 94 |
| | $ | (6 | ) | | $ | (51 | ) | | $ | 83 |
| | | | | | | | | | | | | Amounts recognized in accumulated other comprehensive income (loss) (pre-tax basis) consist of: | | | | | | | | | | | | Net actuarial gain | $ | — |
| | $ | 5 |
| | $ | (17 | ) | | $ | — |
| | $ | — |
| | $ | (12 | ) | Prior service cost | — |
| | — |
| | 20 |
| | — |
| | — |
| | 14 |
| | $ | — |
| | $ | 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, 2017 | | December 31, 2016 | | Pension Benefits | | | | Pension Benefits | | | | Funded Plans | | Unfunded Plans | | Other Postretirement Benefits | | Funded Plans | | Unfunded Plans | | Other Postretirement Benefits | Projected benefit obligation | $ | 1 |
| | $ | 47 |
| | N/A |
| | $ | 18 |
| | $ | 51 |
| | N/A |
| Accumulated benefit obligation | 1 |
| | 47 |
| | $ | 155 |
| | 18 |
| | 51 |
| | $ | 165 |
| Fair value of plan assets | 1 |
| | — |
| | 249 |
| | 12 |
| | — |
| | 248 |
|
Components of Net Periodic Benefit Cost | | | | | | | | | | | | | | | | | | December 31, 2017 | | December 31, 2016 | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Net periodic benefit cost: | | | | | | | | Interest cost | $ | 2 |
| | $ | 4 |
| | $ | 3 |
| | $ | 4 |
| Expected return on plan assets | — |
| | (9 | ) | | (1 | ) | | (8 | ) | Prior service cost amortization | — |
| | 2 |
| | — |
| | 1 |
| Settlements | — |
| | — |
| | — |
| | — |
| Net periodic benefit cost | $ | 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, 2017 | | December 31, 2016 | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Discount rate | 3.27 | % | | 2.34 | % | | 3.65 | % | | 2.34 | % | Rate of compensation increase | 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, 2017 | | December 31, 2016 | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Discount rate | 3.52 | % | | 3.10 | % | | 3.60 | % | | 3.06 | % | Expected return on assets: | | | | | | | | Tax exempt accounts | 3.50 | % | | 7.00 | % | | 3.50 | % | | 7.00 | % | Taxable accounts | N/A |
| | 4.50 | % | | N/A |
| | 4.50 | % | Rate of compensation increase | 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, | | | 2017 | | 2016 | Health care cost trend rate | | 7.20 | % | | 6.73 | % | Rate to which the cost trend is assumed to decline (the ultimate trend rate) | | 4.99 | % | | 4.96 | % | Year that the rate reaches the ultimate trend rate | | 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%. 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. |
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. |
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 $8 million to pension plans and $10 million to other postretirement plans in 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: | | | | | | | | | | Years | | Pension Benefits - Unfunded Plans (1) | | Other Postretirement Benefits (Gross, Before Medicare Part D) | 2018 | | $ | 8 |
| | $ | 24 |
| 2019 | | 6 |
| | 23 |
| 2020 | | 6 |
| | 21 |
| 2021 | | 5 |
| | 19 |
| 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 previously 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 connection with the Lake Charles LNG Transaction, ETP agreed to continue to provide management services for ETE through 2015 These agreements expired 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 2015.2016.
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, | | 2014 | | 2013 | | 2012 | Affiliated revenues | $ | 1,117 |
| | $ | 1,550 |
| | $ | 173 |
|
| | | | | | | | | | | | | | 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, | | 2014 | | 2013 | Accounts receivable from related companies: | | | | ETE | $ | 11 |
| | $ | 18 |
| Regency | 74 |
| | 53 |
| Dakota Access Pipeline | 68 |
| | — |
| PES | 6 |
| | 7 |
| FGT | 9 |
| | 29 |
| ET Crude Oil | 10 |
| | 24 |
| Lake Charles LNG | 3 |
| | — |
| Other | 29 |
| | 34 |
| Total accounts receivable from related companies: | $ | 210 |
| | $ | 165 |
| | | | | Accounts payable to related companies: | | | | ETE | $ | — |
| | $ | 8 |
| Regency | 53 |
| | 24 |
| FGT | 2 |
| | 8 |
| Lake Charles LNG | 2 |
| | — |
| Other | 5 |
| | 5 |
| Total accounts payable to related companies: | $ | 62 |
| | $ | 45 |
|
| | | | | | | | | | December 31, | | 2017 | | 2016 | Accounts receivable from related companies: | | | | ETE | $ | — |
| | $ | 22 |
| Sunoco LP | 219 |
| | 96 |
| FGT | 11 |
| | 15 |
| Other | 88 |
| | 76 |
| Total accounts receivable from related companies | $ | 318 |
| | $ | 209 |
| | | | | Accounts payable to related companies: | | | | Sunoco LP | 195 |
| | 20 |
| Other | 14 |
| | 23 |
| Total accounts payable to related companies | $ | 209 |
| | $ | 43 |
|
| | | | | | | | | | December 31, | | 2017 | | 2016 | Long-term notes receivable (payable) – related companies: | | | | Sunoco LP | $ | 85 |
| | $ | 87 |
| Phillips 66 | — |
| | (250 | ) | Net long-term notes receivable (payable) – related companies | $ | 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; •retail marketing;crude oil transportation and services; and
•all other. Previously, our reportable segments includedThe Partnership previously presented its retail marketing business as a separate segment for NGL transportationreportable segment. Due to the transfer of the general partner interest of Sunoco LP from ETP to ETE in 2015 and services, whichcompletion 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, 2017, the Partnership’s interest in Sunoco LP common units consisted of 43.5 million units, representing 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 combined into our liquids transportation and services segment and includes our operations related to NGL and crude, except for the crude transportation operations that are included in Sunoco Logistics. The liquids transportation and services segment includes the Bakken crude project, for which capital expenditures had previously been reported in the “All other” segment.
During the fourth quarter 2013, management realigned the composition of our reportable segments, and as a result, our natural gas marketing operations are now aggregated into the “all other”all other segment. These operations wereConsequently, the retail marketing business that was previously reportedconsolidated has also been aggregated in the midstream segment. Based on this change in ourall other segment presentation, we have recast the presentation of our segment results for the prior years to be consistent with the current year presentation.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 retail marketingall 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, losslosses on extinguishmentextinguishments of debt gain on deconsolidation 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, | | 2014 | | 2013 | | 2012 | Revenues: | | | | | | Intrastate transportation and storage: | | | | | | Revenues from external customers | $ | 2,652 |
| | $ | 2,250 |
| | $ | 2,012 |
| Intersegment revenues | 205 |
| | 202 |
| | 179 |
| | 2,857 |
| | 2,452 |
| | 2,191 |
| Interstate transportation and storage: | | | | | | Revenues from external customers | 1,057 |
| | 1,270 |
| | 1,109 |
| Intersegment revenues | 15 |
| | 39 |
| | — |
| | 1,072 |
| | 1,309 |
| | 1,109 |
| Midstream: | | | | | | Revenues from external customers | 1,210 |
| | 1,307 |
| | 1,757 |
| Intersegment revenues | 1,713 |
| | 942 |
| | 196 |
| | 2,923 |
| | 2,249 |
| | 1,953 |
| Liquids transportation and services: | | | | | | Revenues from external customers | 3,790 |
| | 2,063 |
| | 619 |
| Intersegment revenues | 121 |
| | 64 |
| | 31 |
| | 3,911 |
| | 2,127 |
| | 650 |
| Investment in Sunoco Logistics: | | | | | | Revenues from external customers | 17,920 |
| | 16,480 |
| | 3,109 |
| Intersegment revenues | 168 |
| | 159 |
| | 80 |
| | 18,088 |
| | 16,639 |
| | 3,189 |
| Retail marketing: | | | | | | Revenues from external customers | 22,484 |
| | 21,004 |
| | 5,926 |
| Intersegment revenues | 3 |
| | 8 |
| | — |
| | 22,487 |
| | 21,012 |
| | 5,926 |
| All other: | | | | | | Revenues from external customers | 2,045 |
| | 1,965 |
| | 1,170 |
| Intersegment revenues | 349 |
| | 402 |
| | 385 |
| | 2,394 |
| | 2,367 |
| | 1,555 |
| Eliminations | (2,574 | ) | | (1,816 | ) | | (871 | ) | Total revenues | $ | 51,158 |
| | $ | 46,339 |
| | $ | 15,702 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2014 | | 2013 | | 2012 | Cost of products sold: | | | | | | Intrastate transportation and storage | $ | 2,169 |
| | $ | 1,737 |
| | $ | 1,394 |
| Midstream | 2,174 |
| | 1,579 |
| | 1,273 |
| Liquids transportation and services | 3,166 |
| | 1,655 |
| | 361 |
| Investment in Sunoco Logistics | 17,110 |
| | 15,574 |
| | 2,885 |
| Retail marketing | 21,154 |
| | 20,150 |
| | 5,757 |
| All other | 2,338 |
| | 2,309 |
| | 1,496 |
| Eliminations | (2,571 | ) | | (1,800 | ) | | (900 | ) | Total cost of products sold | $ | 45,540 |
| | $ | 41,204 |
| | $ | 12,266 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | Revenues: | | | | | | Intrastate transportation and storage: | | | | | | Revenues from external customers | $ | 2,891 |
| | $ | 2,155 |
| | $ | 1,912 |
| Intersegment revenues | 192 |
| | 458 |
| | 338 |
| | 3,083 |
| | 2,613 |
| | 2,250 |
| Interstate transportation and storage: | | | | | | Revenues from external customers | 915 |
| | 946 |
| | 1,008 |
| Intersegment revenues | 19 |
| | 23 |
| | 17 |
| | 934 |
| | 969 |
| | 1,025 |
| Midstream: | | | | | | Revenues from external customers | 2,510 |
| | 2,342 |
| | 2,607 |
| Intersegment revenues | 4,433 |
| | 2,837 |
| | 2,449 |
| | 6,943 |
| | 5,179 |
| | 5,056 |
| NGL and refined products transportation and services: | | | | | | Revenues from external customers | 8,326 |
| | 5,973 |
| | 4,569 |
| Intersegment revenues | 322 |
| | 436 |
| | 428 |
| | 8,648 |
| | 6,409 |
| | 4,997 |
| Crude oil transportation and services: | | | | | | Revenues from external customers | 11,672 |
| | 7,539 |
| | 8,980 |
| Intersegment revenues | 31 |
| | — |
| | — |
| | 11,703 |
| | 7,539 |
| | 8,980 |
| All other: | | | | | | Revenues from external customers | 2,740 |
| | 2,872 |
| | 15,216 |
| Intersegment revenues | 161 |
| | 400 |
| | 558 |
| | 2,901 |
| | 3,272 |
| | 15,774 |
| Eliminations | (5,158 | ) | | (4,154 | ) | | (3,790 | ) | Total revenues | $ | 29,054 |
| | $ | 21,827 |
| | $ | 34,292 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2014 | | 2013 | | 2012 | Depreciation and amortization: | | | | | | Intrastate transportation and storage | $ | 125 |
| | $ | 122 |
| | $ | 122 |
| Interstate transportation and storage | 203 |
| | 244 |
| | 209 |
| Midstream | 184 |
| | 172 |
| | 168 |
| Liquids transportation and services | 113 |
| | 91 |
| | 53 |
| Investment in Sunoco Logistics | 296 |
| | 265 |
| | 63 |
| Retail marketing | 189 |
| | 114 |
| | 28 |
| All other | 20 |
| | 24 |
| | 13 |
| Total depreciation and amortization | $ | 1,130 |
| | $ | 1,032 |
| | $ | 656 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | Cost of products sold: | | | | | | Intrastate transportation and storage | $ | 2,327 |
| | $ | 1,897 |
| | $ | 1,554 |
| Midstream | 4,761 |
| | 3,381 |
| | 3,264 |
| 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 | 2,509 |
| | 2,942 |
| | 14,029 |
| Eliminations | (5,130 | ) | | (4,109 | ) | | (3,722 | ) | Total cost of products sold | $ | 20,801 |
| | $ | 15,080 |
| | $ | 26,714 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2014 | | 2013 | | 2012 | Equity in earnings (losses) of unconsolidated affiliates: | | | | | | Intrastate transportation and storage | $ | (1 | ) | | $ | — |
| | $ | 4 |
| Interstate transportation and storage | 151 |
| | 142 |
| | 120 |
| Midstream | — |
| | — |
| | (9 | ) | Liquids transportation and services | (3 | ) | | (2 | ) | | 2 |
| Investment in Sunoco Logistics | 23 |
| | 18 |
| | 5 |
| Retail marketing | 2 |
| | 2 |
| | 1 |
| All other | 62 |
| | 12 |
| | 19 |
| Total equity in earnings of unconsolidated affiliates | $ | 234 |
| | $ | 172 |
| | $ | 142 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2014 | | 2013 | | 2012 | Segment Adjusted EBITDA: | | | | | | Intrastate transportation and storage | $ | 500 |
| | $ | 464 |
| | $ | 601 |
| Interstate transportation and storage | 1,110 |
| | 1,269 |
| | 1,013 |
| Midstream | 608 |
| | 479 |
| | 467 |
| Liquids transportation and services | 591 |
| | 351 |
| | 209 |
| Investment in Sunoco Logistics | 971 |
| | 871 |
| | 219 |
| Retail marketing | 731 |
| | 325 |
| | 109 |
| All other | 318 |
| | 194 |
| | 126 |
| Total Segment Adjusted EBITDA | 4,829 |
| | 3,953 |
| | 2,744 |
| Depreciation and amortization | (1,130 | ) | | (1,032 | ) | | (656 | ) | Interest expense, net of interest capitalized | (860 | ) | | (849 | ) | | (665 | ) | Gain on deconsolidation of Propane Business | — |
| | — |
| | 1,057 |
| Gain on sale of AmeriGas common units | 177 |
| | 87 |
| | — |
| Goodwill impairment | — |
| | (689 | ) | | — |
| Gains (losses) on interest rate derivatives | (157 | ) | | 44 |
| | (4 | ) | Non-cash unit-based compensation expense | (58 | ) | | (47 | ) | | (42 | ) | Unrealized gains (losses) on commodity risk management activities | 23 |
| | 51 |
| | (9 | ) | Inventory valuation adjustments | (473 | ) | | 3 |
| | (75 | ) | Loss on extinguishment of debt | — |
| | — |
| | (115 | ) | Non-operating environmental remediation | — |
| | (168 | ) | | — |
| Adjusted EBITDA related to discontinued operations | (27 | ) | | (76 | ) | | (99 | ) | Adjusted EBITDA related to unconsolidated affiliates | (674 | ) | | (629 | ) | | (480 | ) | Equity in earnings of unconsolidated affiliates | 234 |
| | 172 |
| | 142 |
| Other, net | (40 | ) | | 12 |
| | 22 |
| Income from continuing operations before income tax expense | $ | 1,844 |
| | $ | 832 |
| | $ | 1,820 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | Depreciation, depletion and amortization: | | | | | | Intrastate transportation and storage | $ | 147 |
| | $ | 144 |
| | $ | 129 |
| Interstate transportation and storage | 214 |
| | 207 |
| | 210 |
| Midstream | 954 |
| | 840 |
| | 720 |
| NGL and refined products transportation and services | 401 |
| | 355 |
| | 290 |
| Crude oil transportation and services | 402 |
| | 251 |
| | 218 |
| All other | 214 |
| | 189 |
| | 362 |
| Total depreciation, depletion and amortization | $ | 2,332 |
| | $ | 1,986 |
| | $ | 1,929 |
|
| | | | | | | | | | | | | | December 31, | | 2014 | | 2013 | | 2012 | Assets: | | | | | | Intrastate transportation and storage | $ | 4,563 |
| | $ | 4,606 |
| | $ | 4,691 |
| Interstate transportation and storage | 10,082 |
| | 10,988 |
| | 11,794 |
| Midstream | 3,548 |
| | 3,133 |
| | 4,946 |
| Liquids transportation and services | 4,581 |
| | 4,326 |
| | 3,765 |
| Investment in Sunoco Logistics | 13,619 |
| | 11,650 |
| | 10,291 |
| Retail marketing | 8,930 |
| | 3,936 |
| | 3,926 |
| All other | 2,898 |
| | 5,063 |
| | 3,817 |
| Total assets | $ | 48,221 |
| | $ | 43,702 |
| | $ | 43,230 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2014 | | 2013 | | 2012 | Additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (accrual basis): | | | | | | Intrastate transportation and storage | $ | 169 |
| | $ | 47 |
| | $ | 37 |
| Interstate transportation and storage | 411 |
| | 152 |
| | 133 |
| Midstream | 667 |
| | 565 |
| | 1,317 |
| Liquids transportation and services | 427 |
| | 443 |
| | 1,302 |
| Investment in Sunoco Logistics | 2,510 |
| | 1,018 |
| | 139 |
| Retail marketing | 259 |
| | 176 |
| | 58 |
| All other | 35 |
| | 54 |
| | 63 |
| Total additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs | $ | 4,478 |
| | $ | 2,455 |
| | $ | 3,049 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | Equity in earnings (losses) of unconsolidated affiliates: | | | | | | Intrastate transportation and storage | $ | (156 | ) | | $ | 35 |
| | $ | 32 |
| Interstate transportation and storage | 236 |
| | 193 |
| | 197 |
| Midstream | 20 |
| | 19 |
| | (19 | ) | NGL and refined products transportation and services | 33 |
| | 41 |
| | 29 |
| Crude oil transportation and services | 4 |
| | (4 | ) | | (9 | ) | All other | 19 |
| | (225 | ) | | 239 |
| Total equity in earnings of unconsolidated affiliates | $ | 156 |
| | $ | 59 |
| | $ | 469 |
|
| | | | | | | | | | | | | | December 31, | | 2014 | | 2013 | | 2012 | Advances to and investments in unconsolidated affiliates: | | | | | | Intrastate transportation and storage | $ | 1 |
| | $ | 1 |
| | $ | 2 |
| Interstate transportation and storage | 1,954 |
| | 2,040 |
| | 2,142 |
| Midstream | — |
| | — |
| | 1 |
| Liquids transportation and services | 31 |
| | 29 |
| | 29 |
| Investment in Sunoco Logistics | 226 |
| | 125 |
| | 118 |
| Retail marketing | 19 |
| | 22 |
| | 21 |
| All other | 1,609 |
| | 2,219 |
| | 1,189 |
| Total advances to and investments in unconsolidated affiliates | $ | 3,840 |
| | $ | 4,436 |
| | $ | 3,502 |
|
| | | | | | | | | | | | | | 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 |
|
| | | | | | | | | | | | | | 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 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | 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 | $ | 175 |
| | $ | 76 |
| | $ | 105 |
| Interstate transportation and storage | 726 |
| | 280 |
| | 866 |
| Midstream | 1,308 |
| | 1,255 |
| | 2,174 |
| 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 | 268 |
| | 160 |
| | 811 |
| 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 |
|
| | | | | | | | | | | | | | December 31, | | 2017 | | 2016 | | 2015 | Advances to and investments in unconsolidated affiliates: | | | | | | Intrastate transportation and storage | $ | 85 |
| | $ | 399 |
| | $ | 406 |
| Interstate transportation and storage | 2,118 |
| | 2,149 |
| | 2,516 |
| Midstream | 126 |
| | 111 |
| | 117 |
| NGL and refined products transportation and services | 234 |
| | 235 |
| | 258 |
| Crude oil transportation and services | 22 |
| | 18 |
| | 21 |
| All other | 1,231 |
| | 1,368 |
| | 1,685 |
| Total advances to and investments in unconsolidated affiliates | $ | 3,816 |
| | $ | 4,280 |
| | $ | 5,003 |
|
| | 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 | 2014: | | | | | | | | | | | | 2017: | | | | | | | | | | | | Revenues | | $ | 12,232 |
| | $ | 13,029 |
| | $ | 13,618 |
| | $ | 12,279 |
| | $ | 51,158 |
| | $ | 6,895 |
| | $ | 6,576 |
| | $ | 6,973 |
| | $ | 8,610 |
| | $ | 29,054 |
| Gross profit | | 1,366 |
| | 1,393 |
| | 1,494 |
| | 1,365 |
| | 5,618 |
| | Operating income | | 688 |
| | 736 |
| | 668 |
| | 383 |
| | 2,475 |
| | 683 |
| | 736 |
| | 779 |
| | 199 |
| | 2,397 |
| Net income | | 491 |
| | 581 |
| | 447 |
| | 34 |
| | 1,553 |
| | 393 |
| | 296 |
| | 715 |
| | 1,097 |
| | 2,501 |
| Common Unitholders’ interest in net income (loss) | | 253 |
| | 295 |
| | 148 |
| | (90 | ) | | 606 |
| | 32 |
| | (49 | ) | | 335 |
| | 668 |
| | 986 |
| Basic net income (loss) per Common Unit | | $ | 0.76 |
| | $ | 0.92 |
| | $ | 0.44 |
| | $ | (0.28 | ) | | $ | 1.77 |
| | $ | 0.03 |
| | $ | (0.04 | ) | | $ | 0.29 |
| | $ | 0.57 |
| | $ | 0.94 |
| Diluted net income (loss) per Common Unit | | $ | 0.76 |
| | $ | 0.92 |
| | $ | 0.44 |
| | $ | (0.28 | ) | | $ | 1.77 |
| | $ | 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* | 2013: | | | | | | | | | | | | 2016: | | | | | | | | | | | | Revenues | | $ | 10,854 |
| | $ | 11,551 |
| | $ | 11,902 |
| | $ | 12,032 |
| | $ | 46,339 |
| | $ | 4,481 |
| | $ | 5,289 |
| | $ | 5,531 |
| | $ | 6,526 |
| | $ | 21,827 |
| Gross profit | | 1,260 |
| | 1,322 |
| | 1,248 |
| | 1,305 |
| | 5,135 |
| | Operating income (loss) | | 534 |
| | 632 |
| | 526 |
| | (151 | ) | | 1,541 |
| | Net income (loss) | | 424 |
| | 413 |
| | 404 |
| | (473 | ) | | 768 |
| | Operating income | | | 598 |
| | 708 |
| | 594 |
| | (139 | ) | | 1,761 |
| Net income | | | 360 |
| | 465 |
| | 94 |
| | (336 | ) | | 583 |
| Common Unitholders’ interest in net income (loss) | | 194 |
| | 165 |
| | 209 |
| | (666 | ) | | (98 | ) | | (71 | ) | | 58 |
| | (252 | ) | | (754 | ) | | (1,019 | ) | Basic net income (loss) per Common Unit | | $ | 0.63 |
| | $ | 0.53 |
| | $ | 0.55 |
| | $ | (1.90 | ) | | $ | (0.18 | ) | | $ | (0.11 | ) | | $ | 0.06 |
| | $ | (0.34 | ) | | $ | (0.97 | ) | | $ | (1.38 | ) | Diluted net income (loss) per Common Unit | | $ | 0.63 |
| | $ | 0.53 |
| | $ | 0.55 |
| | $ | (1.90 | ) | | $ | (0.18 | ) | | $ | (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, 20142017 and 2016 reflected the unfavorable impactsrecognition of $456impairment losses of $920 million and $813 million, respectively. Impairment losses in 2017 were primarily related to non-cash inventory valuation adjustmentsour Trunkline, SUG Holdings, CDM, Sea Robin and refined products reporting units. Impairment losses in 2016 were primarily inrelated to our investment in Sunoco LogisticsPEPL reporting unit, Sea Robin reporting unit and retail marketing segments.midstream midcontinent operations. The three months ended December 31, 20132017 and September 30, 2016 reflected ETP’sthe recognition of a goodwillnon-cash impairment of $689 million.our investments in subsidiaries of $313 million and $308 million, respectively, in our interstate transportation and storage segment. For the three months ended December 31, 2014 and 2013,certain periods reflected above, distributions paid for the period exceeded net income attributable to partners by $544 million and $1.12 billion, respectively.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.
| | 2.17. | REGENCY ENERGY PARTNERS LPCONSOLIDATING GUARANTOR FINANCIAL STATEMENTSINFORMATION |
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.”
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
| | | | Page | ReportThe 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 Independent Registered Public Accounting Firm
| S - 78 | Consolidated Balance Sheets – December 31, 2014 and 2013 | S - 79 | Consolidated Statements of Operations – Years Ended December 31, 2014, 2013 and 2012 | S - 81 | Consolidated Statements of Comprehensive Income – Years Ended December 31, 2014, 2013 and 2012 | S - 82 | Consolidated Statements of Cash Flows – Years Ended December 31, 2014, 2013 and 2012 | S - 83 | Consolidated Statements of Partners’ Capital and Noncontrolling Interest
– Years Ended December 31, 2014, 2013 and 2012 | S - 85 | Notes to Consolidated Financial Statements | S - 87 | | | | |
Introductory Statement
References in this report to the “Partnership,” “we,” “our,” “us” and similar terms refer to Regency Energy Partners LP and its subsidiaries. We use the following definitionscondensed consolidating information, the Parent Guarantor’s investments in these consolidated financial statements and footnotes:
| | | | Name | | Definition or Description | 2018 Notes | | $600 million of 6.875% senior notes with original maturity on December 1, 2018 | AOCI | | Accumulated Other Comprehensive Income (Loss) | Aqua - PVR | | Aqua - PVR Water Services, LLC | ARO | | Asset Retirement Obligation | APM | | Anadarko Pecos Midstream LLC | Barclays | | Barclays Capital Inc. | bps | | Basis points | Citi | | Citigroup Global Markets Inc. | CM | | Chesapeake West Texas Processing, L.L.C. | Coal Handling | | Coal Handling Solutions LLC, Kingsport Handling LLC, and Kingsport Services LLC, now known as Materials Handling Solutions LLC | Eagle Rock | | Eagle Rock Energy Partners, L.P. | EFS Haynesville | | EFS Haynesville, LLC, a wholly-owned subsidiary of GECC | ELG | | Edwards Lime Gathering LLC and its wholly-owned subsidiaries ELG Oil LLC and ELG Utility LLC | EPD | | Enterprise Products Partners L.P. | ETC | | Energy Transfer Company, the name assumed by La Grange Acquisition, L.P. for conducting business and shared services, a wholly-owned subsidiary of ETP | ETE | | Energy Transfer Equity, L.P. | ETE Common Holdings | | ETE Common Holdings, LLC, a wholly-owned subsidiary of ETE | ETE GP | | ETE GP Acquirer LLC | ETP | | Energy Transfer Partners, L.P. | ETP GP | | Energy Transfer Partners GP, LP | Exchange Act | | Securities Exchange Act of 1934, as amended | FASB | | Financial Accounting Standards Board | FASB ASC | | FASB Accounting Standards Codification | Finance Corp. | | Regency Energy Finance Corp., a wholly-owned subsidiary of the Partnership | GAAP | | Accounting principles generally accepted in the United States of America | General Partner | | Regency GP LP, the general partner of the Partnership, or Regency GP LLC, the general partner of Regency GP LP, which effectively manages the business and affairs of the Partnership through its board of directors and Regency Employees Management LLC | Grey Ranch | | Grey Ranch Plant LP, a former joint venture of the Partnership | Gulf States | | Gulf States Transmission LLC, a wholly-owned subsidiary of the Partnership | Holdco | | ETP Holdco Corporation | Hoover | | Hoover Energy Partners, LP | HPC | | RIGS Haynesville Partnership Co. and its wholly-owned subsidiary, Regency Intrastate Gas LP | IDRs | | Incentive Distribution Rights | IRS | | Internal Revenue Service | KMP | | Kinder Morgan Energy Partners, L.P. | LDH | | LDH Energy Asset Holdings LLC | LIBOR | | London Interbank Offered Rate | Lone Star | | Lone Star NGL LLC | LTIP | | Long-Term Incentive Plan |
| | | | Name | | Definition or Description | MEP | | Midcontinent Express Pipeline LLC | Mi Vida JV | | Mi Vida JV LLC | MLP | | Master Limited Partnership | NGLs | | Natural gas liquids, including ethane, propane, normal butane, iso butane and natural gasoline | NMED | | New Mexico Environmental Development | NYSE | | New York Stock Exchange | ORS | | Ohio River System LLC | PADEP | | Pennsylvania Department of Environmental Protection | Partnership | | Regency Energy Partners LP | PEPL | | Panhandle Eastern Pipe Line Company, LP | PEPL Holdings | | PEPL Holdings, LLC, a former wholly-owned subsidiary of Southern Union that merged into PEPL | PVR | | PVR Partners, L.P. | Ranch JV | | Ranch Westex JV LLC | Regency Western | | Regency Western G&P LLC, a wholly-owned subsidiary of the Partnership | RGS | | Regency Gas Services, LP, a wholly-owned subsidiary of the Partnership | RIGS | | Regency Intrastate Gas System | SEC | | Securities and Exchange Commission | Securities Act | | Securities Act of 1933, as amended | Senior Notes | | The collective of 2019 Notes, 2020 Notes, 2020 PVR Notes, 2021 Notes, 2021 PVR Notes, 2022 Notes, October 2022 Notes, 2023 4.5% Notes and 2023 5.5% Notes | Series A Preferred Units | | Series A convertible redeemable preferred units | Services Co. | | ETE Services Company, LLC | Southern Union | | Southern Union Company | SUGS | | Southern Union Gas Services | SUN | | Sunoco LP (formerly known as Susser, L.P.) | Sweeny JV | | Sweeny Gathering, L.P. | SXL | | Sunoco Logistics Partners L.P. | TCEQ | | Texas Commission on Environmental Quality | U.S. | | United States | Wells Fargo | | Wells Fargo Securities, LLC | WTI | | West Texas Intermediate Crude |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Partners
Regency Energy Partners LP
We have audited the accompanying consolidated balance sheets of Regency Energy Partners LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive income, cash flows, and partners’ capital and noncontrolling interest for each of the three yearsSubsidiary Issuer’s investments in the period ended December 31, 2014. These financial statementsits subsidiaries are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the financial statements of Midcontinent Express Pipeline LLC, a 50 percent owned investee company, the Partnership’s investment in which is accounted for under the equity method of accounting. The Partnership’s investment in Midcontinent Express Pipeline LLC as of December 31, 2014 and 2013 was $695 million and $549 million, respectively, and its equity inTo present the earnings of Midcontinent Express Pipeline LLC was $45 million, $40 million, and $42 million, respectively, for each ofsupplemental condensed consolidating financial information on a comparable basis, the three years in theprior period ended December 31, 2014. Those statements were audited by other auditors, whose reportfinancial information has been furnished to us, and our opinion, insofar as it relates to the amounts included for Midcontinent Express Pipeline LLC, is based solely on the report of the other auditors.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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 and the report of the other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the report of the other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Regency Energy Partners LP and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 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), the Partnership’s internal control over financial reporting as of December 31, 2014, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 26, 2015 (not separately included herein) expressed an unqualified opinion thereon.
/s/ GRANT THORNTON LLP
Dallas, Texas
February 26, 2015
REGENCY ENERGY PARTNERS LP
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
| | | | | | | | | | December 31, | | 2014 | | 2013 | ASSETS | | | | Current Assets: | | | | Cash and cash equivalents | $ | 24 |
| | $ | 19 |
| Trade accounts receivable, net of allowance for doubtful accounts of $7 and $1 | 483 |
| | 292 |
| Related party receivables | 45 |
| | 28 |
| Inventories | 67 |
| | 42 |
| Derivative assets | 75 |
| | 3 |
| Other current assets | 9 |
| | 16 |
| Total current assets | 703 |
| | 400 |
| Property, Plant and Equipment: | | | | Gathering and transmission systems | 5,207 |
| | 1,671 |
| Compression equipment | 2,378 |
| | 1,627 |
| Gas plants and buildings | 386 |
| | 825 |
| Other property, plant and equipment | 679 |
| | 414 |
| Natural resources | 454 |
| | — |
| Construction-in-progress | 1,156 |
| | 513 |
| Total property, plant and equipment | 10,260 |
| | 5,050 |
| Less accumulated depreciation and depletion | (1,043 | ) | | (632 | ) | Property, plant and equipment, net | 9,217 |
| | 4,418 |
| Other Assets: | | | | Investments in unconsolidated affiliates | 2,418 |
| | 2,097 |
| Other, net of accumulated amortization of debt issuance costs of $28 and $24 | 103 |
| | 57 |
| Total other assets | 2,521 |
| | 2,154 |
| Intangible Assets and Goodwill: | | | | Intangible assets, net of accumulated amortization of $212 and $107 | 3,439 |
| | 682 |
| Goodwill | 1,223 |
| | 1,128 |
| Total intangible assets and goodwill | 4,662 |
| | 1,810 |
| TOTAL ASSETS | $ | 17,103 |
| | $ | 8,782 |
|
REGENCY ENERGY PARTNERS LP
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
| | | | | | | | | | December 31, | | 2014 | | 2013 | LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST | | | | Current Liabilities: | | | | Drafts payable | $ | 15 |
| | $ | 26 |
| Trade accounts payable | 529 |
| | 291 |
| Related party payables | 64 |
| | 69 |
| Accrued expenses | 43 |
| | 25 |
| Accrued interest | 81 |
| | 38 |
| Other current liabilities | 24 |
| | 26 |
| Total current liabilities | 756 |
| | 475 |
| Long-term derivative liabilities | 16 |
| | 19 |
| Other long-term liabilities | 72 |
| | 30 |
| Long-term debt, net | 6,641 |
| | 3,310 |
| Commitments and contingencies | | | | Series A Preferred Units, redemption amount of $38 and $38 | 33 |
| | 32 |
| Partners’ Capital and Noncontrolling Interest: | | | | Common units (412,681,151 and 214,287,955 units authorized; 409,406,482 and 210,850,232 units issued and outstanding at December 31, 2014 and 2013) | 8,531 |
| | 3,886 |
| Class F units (6,274,483 units authorized, issued and outstanding at December 31, 2014 and 2013) | 153 |
| | 146 |
| General partner interest | 781 |
| | 782 |
| Total partners’ capital | 9,465 |
| | 4,814 |
| Noncontrolling interest | 120 |
| | 102 |
| Total partners’ capital and noncontrolling interest | 9,585 |
| | 4,916 |
| TOTAL LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST | $ | 17,103 |
| | $ | 8,782 |
|
REGENCY ENERGY PARTNERS LP
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions, except unit data and per unit data)
| | | | | | | | | | | | | | Years Ended December 31, | | 2014 | | 2013 | | 2012 | REVENUES | | | | | | Gas sales, including related party amounts of $80, $71, and $42 | $ | 1,903 |
| | $ | 826 |
| | $ | 508 |
| NGL sales, including related party amounts of $282, $81, and $28 | 1,741 |
| | 1,053 |
| | 991 |
| Gathering, transportation and other fees, including related party amounts of $23, $26, and $29 | 989 |
| | 545 |
| | 401 |
| Net realized and unrealized gain (loss) from derivatives | 93 |
| | (8 | ) | | 23 |
| Other | 225 |
| | 105 |
| | 77 |
| Total revenues | 4,951 |
| | 2,521 |
| | 2,000 |
| OPERATING COSTS AND EXPENSES | | | | | | Cost of sales, including related party amounts of $66, $56, and $35 | 3,452 |
| | 1,793 |
| | 1,387 |
| Operation and maintenance | 448 |
| | 296 |
| | 228 |
| General and administrative | 158 |
| | 88 |
| | 100 |
| (Gain) loss on asset sales, net | (1 | ) | | 2 |
| | 3 |
| Depreciation, depletion and amortization | 541 |
| | 287 |
| | 252 |
| Goodwill impairment | 370 |
| | — |
| | — |
| Total operating costs and expenses | 4,968 |
| | 2,466 |
| | 1,970 |
| OPERATING (LOSS) INCOME | (17 | ) | | 55 |
| | 30 |
| Income from unconsolidated affiliates | 195 |
| | 135 |
| | 105 |
| Interest expense, net | (304 | ) | | (164 | ) | | (122 | ) | Loss on debt refinancing, net | (25 | ) | | (7 | ) | | (8 | ) | Other income and deductions, net | 12 |
| | 7 |
| | 29 |
| (LOSS) INCOME BEFORE INCOME TAXES | (139 | ) | | 26 |
| | 34 |
| Income tax expense (benefit) | 3 |
| | (1 | ) | | — |
| NET (LOSS) INCOME | $ | (142 | ) | | $ | 27 |
| | $ | 34 |
| Net income attributable to noncontrolling interest | (15 | ) | | (8 | ) | | (2 | ) | NET (LOSS) INCOME ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP | $ | (157 | ) | | $ | 19 |
| | $ | 32 |
| Amounts attributable to Series A preferred units | 4 |
| | 6 |
| | 10 |
| General partner’s interest, including IDRs | 31 |
| | 11 |
| | 9 |
| Beneficial conversion feature for Class F units | 7 |
| | 4 |
| | — |
| Pre-acquisition loss from SUGS allocated to predecessor equity | — |
| | (36 | ) | | (14 | ) | Limited partners’ interest in net (loss) income | $ | (199 | ) | | $ | 34 |
| | $ | 27 |
| Basic and diluted (loss) income per common unit: | | | | | | Limited partners’ interest in net (loss) income | $ | (199 | ) | | $ | 34 |
| | $ | 27 |
| Weighted average number of common units outstanding | 348,070,121 |
| | 196,227,348 |
| | 167,492,735 |
| Basic (loss) income per common unit | $ | (0.57 | ) | | $ | 0.17 |
| | $ | 0.16 |
| Diluted (loss) income per common unit | $ | (0.57 | ) | | $ | 0.17 |
| | $ | 0.13 |
| Distributions per common unit | $ | 1.975 |
| | $ | 1.87 |
| | $ | 1.84 |
| Amount allocated to beneficial conversion feature for Class F units | $ | 7 |
| | $ | 4 |
| | $ | — |
| Total number of Class F units outstanding | 6,274,483 |
| | 6,274,483 |
| | — |
| Income per Class F unit due to beneficial conversion feature | $ | 1.08 |
| | $ | 0.72 |
| | $ | — |
|
REGENCY ENERGY PARTNERS LP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME
(Dollars in millions)
| | | | | | | | | | | | | | Years Ended December 31, | | 2014 | | 2013 | | 2012 | Net (loss) income | $ | (142 | ) | | $ | 27 |
| | $ | 34 |
| Other comprehensive income: | | | | | | Net cash flow hedge amounts reclassified to earnings | — |
| | — |
| | 6 |
| Change in fair value of cash flow hedges | — |
| | — |
| | (4 | ) | Total other comprehensive income | $ | — |
| | $ | — |
| | $ | 2 |
| Comprehensive (loss) income | $ | (142 | ) | | $ | 27 |
| | $ | 36 |
| Comprehensive income attributable to noncontrolling interest | 15 |
| | 8 |
| | 2 |
| Comprehensive (loss) income attributable to Regency Energy Partners LP | $ | (157 | ) | | $ | 19 |
| | $ | 34 |
|
REGENCY ENERGY PARTNERS LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
| | | | | | | | | | | | | | Years Ended December 31, | | 2014 | | 2013 | | 2012 | OPERATING ACTIVITIES | | | | | | Net (loss) income | $ | (142 | ) | | $ | 27 |
| | $ | 34 |
| Reconciliation of net (loss) income to net cash flows provided by operating activities: | | | | | | Depreciation, depletion and amortization, including debt issuance cost amortization and bond premium write-off and amortization | 525 |
| | 293 |
| | 259 |
| Income from unconsolidated affiliates | (195 | ) | | (135 | ) | | (105 | ) | Derivative valuation changes | (93 | ) | | 6 |
| | (12 | ) | (Gain) loss on asset sales, net | (1 | ) | | 2 |
| | 3 |
| Unit-based compensation expenses | 10 |
| | 7 |
| | 5 |
| Revaluation of unconsolidated affiliate upon acquisition | (6 | ) | | — |
| | — |
| Goodwill impairment | 370 |
| | — |
| | — |
| Cash flow changes in current assets and liabilities: | | | | | | Trade accounts receivable and related party receivables | 28 |
| | (96 | ) | | — |
| Other current assets and other current liabilities | 34 |
| | (54 | ) | | 10 |
| Trade accounts payable and related party payables | (16 | ) | | 119 |
| | 18 |
| Distributions of earnings received from unconsolidated affiliates | 204 |
| | 142 |
| | 121 |
| Cash flow changes in other assets and liabilities | 1 |
| | 125 |
| | (9 | ) | Net cash flows provided by operating activities | 719 |
| | 436 |
| | 324 |
| INVESTING ACTIVITIES | | | | | | Capital expenditures | (1,088 | ) | | (1,034 | ) | | (560 | ) | Contributions to unconsolidated affiliates | (355 | ) | | (148 | ) | | (356 | ) | Distributions in excess of earnings of unconsolidated affiliates | 68 |
| | 249 |
| | 83 |
| Acquisitions, net of cash received | (805 | ) | | (475 | ) | | — |
| Proceeds from asset sales | 11 |
| | 15 |
| | 26 |
| Net cash flows used in investing activities | (2,169 | ) | | (1,393 | ) | | (807 | ) | FINANCING ACTIVITIES | | | | | | Borrowings (repayments) under revolving credit facility, net | 380 |
| | 318 |
| | (140 | ) | Proceeds from issuance of senior notes | 1,580 |
| | 1,000 |
| | 700 |
| Redemptions of senior notes | (983 | ) | | (163 | ) | | (88 | ) | Debt issuance costs | (31 | ) | | (24 | ) | | (15 | ) | Partner distributions and distributions on unvested unit awards | (706 | ) | | (386 | ) | | (322 | ) | Noncontrolling interest contributions, net of distributions | 3 |
| | 17 |
| | 42 |
| Contributions from previous parent | — |
| | — |
| | 51 |
| Drafts payable | (11 | ) | | 18 |
| | 4 |
| Common units issued under unit offerings, equity distribution program and LTIP, net of issuance costs, forfeitures and tax withholding | 1,227 |
| | 149 |
| | 311 |
| Distributions to Series A Preferred Units | (4 | ) | | (6 | ) | | (8 | ) | Net cash flows provided by financing activities | 1,455 |
| | 923 |
| | 535 |
|
REGENCY ENERGY PARTNERS LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
| | | | | | | | | | | | | | Years Ended December 31, | | 2014 | | 2013 | | 2012 | Net change in cash and cash equivalents | 5 |
| | (34 | ) | | 52 |
| Cash and cash equivalents at beginning of period | 19 |
| | 53 |
| | 1 |
| Cash and cash equivalents at end of period | $ | 24 |
| | $ | 19 |
| | $ | 53 |
| | | | | | | Supplemental cash flow information: | | | | | | Accrued capital expenditures | $ | 102 |
| | $ | 60 |
| | $ | 136 |
| Issuance of Class F and common units in connection with SUGS Acquisition | — |
| | 961 |
| | — |
| Issuance of common units in connection with PVR, Hoover, and Eagle Rock acquisitions | 4,281 |
| | — |
| | — |
| Long-term debt assumed in PVR Acquisition | 1,887 |
| | — |
| | — |
| Long-term debt exchanged in connection with the Eagle Rock Midstream Acquisition | 499 |
| | — |
| | — |
| Interest paid, net of amounts capitalized | 303 |
| | 146 |
| | 112 |
| Accrued capital contribution to unconsolidated affiliate | — |
| | 13 |
| | 23 |
|
REGENCY ENERGY PARTNERS LP
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
AND NONCONTROLLING INTEREST
(Dollars in millions)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Regency Energy Partners LP | | | | | | Common Units | | Class F Units | | General Partner Interest | | Predecessor Equity | | AOCI | | Non-controlling Interest | | Total | Balance - December 31, 2011 | $ | 3,173 |
| | $ | — |
| | $ | 330 |
| | $ | — |
| | $ | (5 | ) | | $ | 33 |
| | $ | 3,531 |
| Common unit offerings, net of costs | 297 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 297 |
| Issuance of common units under equity distribution program, net of costs | 15 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 15 |
| Common units issued under LTIP, net of forfeitures and tax withholding | (1 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (1 | ) | Unit-based compensation expenses | 5 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 5 |
| Partner distributions | (309 | ) | | — |
| | (13 | ) | | — |
| | — |
| | — |
| | (322 | ) | Net income (loss) | 37 |
| | — |
| | 9 |
| | (14 | ) | | — |
| | 2 |
| | 34 |
| Noncontrolling interest contributions, net of distributions | — |
| | — |
| | — |
| | — |
| | — |
| | 42 |
| | 42 |
| Distributions to Series A Preferred Units | (8 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (8 | ) | Accretion of Series A Preferred Units | (2 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (2 | ) | Net cash flow hedge amounts reclassified to earnings | — |
| | — |
| | — |
| | — |
| | 5 |
| | — |
| | 5 |
| Contribution of net investment to unitholders | — |
| | — |
| | — |
| | 1,747 |
| | (3 | ) | | — |
| | 1,744 |
| Balance - December 31, 2012 | $ | 3,207 |
| | $ | — |
| | $ | 326 |
| | $ | 1,733 |
| | $ | (3 | ) | | $ | 77 |
| | $ | 5,340 |
| Contribution of net investment to the Partnership | — |
| | — |
| | 1,925 |
| | (1,928 | ) | | 3 |
| | — |
| | — |
| Issuance of common units in connection with the SUGS Acquisition, net of costs | 819 |
| | — |
| | (819 | ) | | — |
| | — |
| | — |
| | — |
| Issuance of Class F units in connection with the SUGS Acquisition, net of costs | — |
| | 142 |
| | (142 | ) | | — |
| | — |
| | — |
| | — |
| Contribution of assets between entities under common control below historical cost | — |
| | — |
| | (504 | ) | | 231 |
| | — |
| | — |
| | (273 | ) | Issuance of common units under equity distribution program, net of costs | 149 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 149 |
| Conversion of Series A Preferred Units for common units | 41 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 41 |
| Unit-based compensation expenses | 7 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 7 |
| Partner distributions and distributions on unvested unit awards | (371 | ) | | — |
| | (15 | ) | | — |
| | — |
| | — |
| | (386 | ) | Noncontrolling interest contributions, net of distributions | — |
| | — |
| | — |
| | — |
| | — |
| | 17 |
| | 17 |
| Net income (loss) | 40 |
| | 4 |
| | 11 |
| | (36 | ) | | — |
| | 8 |
| | 27 |
| Distributions to Series A Preferred Units | (6 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (6 | ) | Balance - December 31, 2013 | $ | 3,886 |
| | $ | 146 |
| | $ | 782 |
| | $ | — |
| | $ | — |
| | $ | 102 |
| | $ | 4,916 |
|
REGENCY ENERGY PARTNERS LP
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
AND NONCONTROLLING INTEREST
(Dollars in millions)
| | | | | | | | | | | | | | | | | | | | | | Regency Energy Partners LP | | | | | | Common Units | | Class F Units | | General Partner Interest | | Noncontrolling Interest | | Total | Balance - December 31, 2013 | $ | 3,886 |
| | $ | 146 |
| | $ | 782 |
| | $ | 102 |
| | $ | 4,916 |
| Issuance of common units under equity distribution program, net of costs | 428 |
| | — |
| | — |
| | — |
| | 428 |
| Issuance of common units to ETE Common Holdings | 800 |
| | — |
| | — |
| | — |
| | 800 |
| Issuance of common units in connection with Hoover Acquisition | 109 |
| | — |
| | — |
| | — |
| | 109 |
| Issuance of common units in connection with PVR Acquisition | 3,906 |
| | — |
| | — |
| | — |
| | 3,906 |
| Issuance of common units in connection with Eagle Rock Midstream Acquisition | 266 |
| | — |
| | — |
| | — |
| | 266 |
| Common units issued under LTIP, net of forfeitures and tax withholding | (1 | ) | | — |
| | — |
| | — |
| | (1 | ) | Unit-based compensation expenses | 10 |
| | — |
| | — |
| | — |
| | 10 |
| Partner distributions and distributions on unvested unit awards | (674 | ) | | — |
| | (32 | ) | | — |
| | (706 | ) | Noncontrolling interest contributions, net of distributions | — |
| | — |
| | — |
| | 3 |
| | 3 |
| Net (loss) income | (195 | ) | | 7 |
| | 31 |
| | 15 |
| | (142 | ) | Distributions to Series A Preferred Units | (4 | ) | | — |
| | — |
| | — |
| | (4 | ) | Balance - December 31, 2014 | $ | 8,531 |
| | $ | 153 |
| | $ | 781 |
| | $ | 120 |
| | $ | 9,585 |
|
REGENCY ENERGY PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Tabular dollar amounts, except unit and per unit data, are in millions)
1. ORGANIZATION AND BASIS OF PRESENTATION
Organization. The consolidated financial statements presented herein contain the results of Regency Energy Partners LP and its subsidiaries (the “Partnership”), a Delaware limited partnership. The Partnership was formed on September 8, 2005, and completed its IPO on February 3, 2006. The Partnership and its subsidiaries are engaged in the business of gathering and processing, compression, treating and transportation of natural gas; the transportation, fractionation and storage of NGLs; the gathering, transportation and terminaling of oil (crude and/or condensate, a lighter oil) received from producers; natural gas and NGL marketing and trading; and the management of coal and natural resource properties in the United States. Regency GP LP is the Partnership’s general partner and Regency GP LLC (collectively the “General Partner”) is the managing general partner of the Partnership and the general partner of Regency GP LP.
Pending Merger with ETP. On January 25, 2015, the Partnership and ETP entered into the Merger Agreement pursuant to which the Partnership will merge with a wholly-owned subsidiary of ETP, with the Partnership continuing as the surviving entity and becoming a wholly-owned subsidiary of ETP (the “Merger”). At the effective time of the Merger (the “Effective Time”), each Partnership common unit and Class F unit will be converted into the right to receive 0.4066 ETP common units, plus a number of additional ETP common units equal to $0.32 per Partnership unit divided by the lesser of (i) the volume weighted average price of ETP common units for the five trading days ending on the third trading day immediately preceding the Effective Time and (ii) the closing price of ETP common units on the third trading day immediately preceding the Effective Time, rounded to the nearest ten thousandth of a unit. Each Series A Preferred Unit will be converted into the right to receive a preferred unit representing a limited partner interest in ETP, a new class of units in ETP to be established at the Effective Time. Early termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, for the Merger was granted by the United States Federal Trade Commission on February 24, 2015. The transaction is expected to close in the second quarter of 2015 and is subject to other customary closing conditions including approval by the Partnership’s unitholders.
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 numbers have been conformed to the current year presentation.
Reclassifications. During 2014, the Partnership reclassified amounts within property, plant and equipment asset categories. These reclassifications did not have any impact on amounts recorded for depreciation, depletion or amortization in 2014, and because the reclassified amounts have no significant effect on our consolidated balance sheets, prior period balances have not been adjusted for comparability purposes.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates. These consolidated financial statements have been prepared in conformity with GAAP, which includes the use of estimates and assumptions by management that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates.
Common Control Transactions. Entities and assets acquired from ETE and its affiliates are accounted for as common control transactions whereby the net assets acquired are combined with the Partnership’s net assets at their historical amounts. If consideration transferred differs from the carrying value of the net assets acquired, the excess or deficiency is treated as a capital transaction similar to a dividend or capital contribution. To the extent that such transactions require prior periods to be recast historical net equity amounts prior to the transaction date are reflected in predecessor equity.
Cash and Cash Equivalents. Cash and cash equivalents include temporary cash investments with original maturities of three months or less.
Equity Method Investments. The equity method of accounting is used to account for the Partnership’s interest in investments of greater than 20% voting interest or where the Partnership exerts significant influence over an investee but lacks control over the investee. Even though there is a presumption of a controlling financial interest in Aqua - PVR (because of our 51% ownership), our partner in this joint venture has substantive participating rights and management authority that preclude us from controlling the joint venture. Therefore, it is accounted for as an equity method investment. The Partnership acquired a 50% interest in Coal Handling as part of the PVR Acquisition and purchased the remaining 50% interest effective December 31, 2014 for $16 million, resulting in a gain on the purchase due to the revaluation of the Partnership’s previously held non-controlling interest.
Inventories. Inventories are valued at the lower of cost or market and include materials and parts primarily utilized by the Contract Services and Gathering & Processing segments.
Property, Plant and Equipment. Property, plant and equipment is recorded at historical cost of construction or, upon acquisition, the fair value of the assets acquired. Gains or losses on sales or retirements of assets are included in operating income unless the disposition is treated as discontinued operations. Natural gas and NGLs used to maintain pipeline minimum pressures is classified as property, plant and equipment. Financing costs associated with the construction of larger assets requiring ongoing efforts over a period of time are capitalized. For the years ended December 31, 2014, 2013 and 2012, the Partnership capitalized interest of $14 million, $2 million and $1 million, respectively. The costs of maintenance and repairs, which are not significant improvements, are expensed when incurred. Expenditures to extend the useful lives of the assets are capitalized.
Depreciation expense related to property, plant and equipment was $418 million, $258 million, and $219 million for the years ended December 31, 2014, 2013 and 2012, respectively. In March 2012, the Partnership recorded a $7 million “out-of-period” adjustment to depreciation expense to correct the estimated useful lives of certain assets to comply with its policy.
Depreciation of property, plant and equipment is recorded on a straight-line basis over the following estimated useful lives:
| | | | Functional Class of Property | | Useful Lives (Years) | Gathering and Transmission Systems | | 20 - 40 | Compression Equipment | | 2 - 30 | Gas Plants and Buildings | | 5 - 20 | Other Property, Plant and Equipment | | 3 - 15 |
Depletion expense related to the Natural Resources segment was $11 million for the year ended December 31, 2014. Coal properties are depleted on an area-by-area basis at a rate based on the cost of the mineral properties and the number of tons of estimated proven and probable coal reserves contained therein. Proven and probable coal reserves have been estimated by the Partnership’s own geologists. The Partnership’s estimates of coal reserves are updated periodically and may result in adjustments to coal reserves and depletion rates that are recognized prospectively. From time to time, the Partnership carries out core-hole drilling activities on coal properties in order to ascertain the quality and quantity of the coal contained in those properties. These core-hole drilling activities are expensed as incurred. The Partnership depletes timber using a methodology consistent with the units-of-production method, which is based on the quantity of timber harvested. The Partnership determines depletion of oil and gas royalty interests by the units-of-production method and these amounts could change with revisions to estimated proved recoverable reserves.
Intangible Assets. As of December 31, 2014, intangible assets consisted of trade names and customer relations, and are amortized on a straight line basis over their estimated useful lives, which is the period over which the assets are expected to contribute directly or indirectly to the Partnership’s future cash flows. The estimated useful lives range from 8 to 30 years.
The Partnership assesses long-lived assets, including property, plant and equipment and intangible assets, for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability is assessed by comparing the carrying amount of an asset to undiscounted future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured as the amount by which the carrying amounts exceed the fair value of the assets. The Partnership did not record any impairment in 2014, 2013, or 2012.
Goodwill. Goodwill represents the excess of the purchase price over the fair value of identifiable net assets acquired in a business combination. Goodwill is not amortized, but is tested for impairment annually based on the carrying values as of November 30 or December 31 depending upon the reporting unit, or more frequently if impairment indicators arise that suggest the carrying value of goodwill may not be recovered. The Partnership has the option to first assess qualitative factors to determine whether it is more likely than not that the fair value of the reporting unit is less than its carrying amount as a basis for determining whether further impairment testing is necessary. Impairment is indicated when the carrying amount of a reporting unit exceeds its fair value. To estimate the fair value of the reporting units, the Partnership makes estimates and judgments about future cash flows, as well as revenues, cost of sales, operating expenses, capital expenditures and net working capital based on assumptions that are consistent with the Partnership’s most recent forecast. At the time it is determined that an impairment has occurred, the carrying value of the goodwill is written down to its fair value.
In 2014, a $370 million goodwill impairment charge was recorded related to the Permian reporting unit within the Gathering and Processing segment. The decline in estimated fair value of that reporting unit is primarily driven by the significant decline in commodity prices in the fourth quarter of 2014, and the resulting impact to future commodity prices as well as increases in future estimated operations and maintenance expenses. As a result of the Partnership’s determination that the estimated fair value of the reporting unit being less than the carrying value, the Partnership performed the second step of the goodwill impairment assessment,
which requires the assets and liabilities of the reporting unit to be fair valued on a hypothetical basis. Any excess value over the estimated fair value of the reporting unit, determined in this case through established valuation techniques such as discounted cash flow methods and market comparable analyses, compared to the hypothetical fair value of all assets and liabilities of the reporting unit is the implied fair value of goodwill. To the extent that the implied fair value of goodwill is less than the carrying value of goodwill, an impairment is recognized to eliminate any excess carrying amounts.
No other goodwill impairments were identified or recorded for the Partnership’s other reporting units in 2014. No goodwill impairment charges were incurred in 2013 or 2012.
Other Assets, net. Other assets, net primarily consists of debt issuance costs, which are capitalized and amortized to interest expense, net over the life of the related debt.
Gas Imbalances. Quantities of natural gas or NGLs over-delivered or under-delivered related to imbalance agreements are recorded monthly as other current assets or other current liabilities using then current market prices or the weighted average prices of natural gas or NGLs at the plant or system pursuant to imbalance agreements for which settlement prices are not contractually established.
Within certain volumetric limits determined at the sole discretion of the creditor, these imbalances are generally settled by deliveries of natural gas. Imbalance receivables and payables as of December 31, 2014 and 2013 were immaterial.
Asset Retirement Obligations. Legal obligations associated with the retirement of long-lived assets are recorded at fair value at the time the obligations are incurred, if a reasonable estimate of fair value can be made. Present value techniques are used which reflect assumptions such as removal and remediation costs, inflation, and profit margins that third parties would demand to settle the amount of the future obligation. The Partnership does not include a market risk premium for unforeseeable circumstances in its fair value estimates because such a premium cannot be reliably estimated. Upon initial recognition of the liability, costs are capitalized as a part of the long-lived asset and allocated to expense over the useful life of the related asset. The liability is accreted to its present value each period with accretion being recorded to operating expense with a corresponding increase in the carrying amount of the liability. The ARO assets and liabilities were immaterial as of December 31, 2014.
Environmental. The Partnership’s operations are subject to federal, state and local laws and rules and regulations regarding water quality, hazardous and solid waste management, air quality control and other environmental matters. These laws, rules and regulations require the Partnership to conduct its operations in a specified manner and to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Failure to comply with applicable environmental laws, rules and regulations may expose the Partnership to significant fines, penalties and/or interruptions in operations. The Partnership’s environmental policies and procedures are designed to achieve compliance with such applicable laws and regulations. These evolving laws and regulations and claims for damages to property, employees, other persons and the environment resulting from current or past operations may result in significant expenditures and liabilities in the future.
Predecessor Equity. Predecessor equity included on the consolidated statements of partners’ capital and noncontrolling interest represents SUGS member’s capital prior to the acquisition date (April 30, 2013).
Revenue Recognition. The Partnership earns revenue from (i) domestic sales of natural gas, NGLs and condensate, (ii) natural gas, NGL, condensate, and salt water gathering, processing and transportation, (iii) contract compression and treating services, and (iv) coal royalties. Revenue associated with sales of natural gas, NGLs and condensate are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery occurs. Revenue associated with transportation and processing fees are recognized when the service is provided. For contract compression and contract treating services, revenue is recognized when the service is performed. For gathering and processing services, the Partnership receives either fees or commodities from natural gas producers depending on the type of contract. Commodities received are in turn sold and recognized as revenue in accordance with the criteria outlined above. Under the percentage-of-proceeds contract type, the Partnership is paid for its services by keeping a percentage of the NGLs produced and a percentage of the residue gas resulting from processing the natural gas. Under the percentage-of-index contract type, the Partnership earns revenue by purchasing wellhead natural gas at a percentage of the index price and selling processed natural gas and NGLs at a price approximating the index price to third parties. The Partnership generally reports revenue gross in the consolidated statements of operations when it acts as the principal, takes title to the product, and incurs the risks and rewards of ownership. Revenue for fee-based arrangements is presented net, because the Partnership takes the role of an agent for the producers. Allowance for doubtful accounts is determined based on historical write-off experience and specific identification.
Coal Royalties Revenues and Deferred Income. The Partnership recognizes coal royalties revenues on the basis of tons of coal sold by its lessees and the corresponding revenues from those sales. The Partnership does not have access to actual production and revenues information until 30 days following the month of production. Therefore, financial results include estimated revenues and accounts receivable for the month of production. The Partnership records any differences between the actual amounts ultimately received or paid and the original estimates in the period they become finalized. Most lessees must make minimum monthly or
annual payments that are generally recoverable over certain time periods. These minimum payments are recorded as deferred income. If the lessee recovers a minimum payment through production, the deferred income attributable to the minimum payment is recognized as coal royalties revenues. If a lessee fails to meet its minimum production for certain pre-determined time periods, the deferred income attributable to the minimum payment is recognized as minimum rental revenues, which is a component of other revenues on our consolidated statements of operations. Other liabilities on the balance sheet also include deferred unearned income from a coal services facility lease, which is recognized in other income as it is earned.
Derivative Instruments. The Partnership’s net income and cash flows are subject to volatility stemming from changes in market prices such as natural gas prices, NGLs prices, processing margins and interest rates. The Partnership uses product-specific swaps to create offsetting positions to specific commodity price exposures, and uses interest rate swap contracts to create offsetting positions to specific interest rate exposures. Derivative financial instruments are recorded on the balance sheet at their fair value based on their settlement date. The Partnership employs derivative financial instruments in connection with an underlying asset, liability and/or anticipated transaction and not for speculative purposes. Furthermore, the Partnership regularly assesses the creditworthiness of counterparties to manage the risk of default. As of December 31, 2014 and 2013, no derivative financial instruments were designated as hedges. In the statement of cash flows, the effects of settlements of derivative instruments are classified consistent with the related hedged transactions.
Benefits. The Partnership provides medical, dental, and other healthcare benefits to employees. The total amount incurred by the Partnership for the years ended December 31, 2014, 2013 and 2012, was $17 million, $9 million and $9 million, respectively, in operation and maintenance and general and administrative expenses, as appropriate. The Partnership also provides a matching contribution to its employee’s 401(k) accounts which vest immediately upon contribution. The total amount of matching contributions for the years ended December 31, 2014, 2013 and 2012 was $9 million, $7 million and $4 million, respectively, and were recorded in operation and maintenance and general and administrative expenses, as appropriate. The Partnership has no pension obligations or other post-employment benefits. Beginning January 1, 2013, the Partnership provides a 3% profit sharing contribution to employee 401(k) accounts for all employees with base compensation below a specified threshold. The contribution is in addition to the 401(k) matching contribution and employees become vested based on years of service.
Income Taxes. The Partnership is generally not subject to income taxes, except as discussed below, because its income is taxed directly to its partners. The Partnership is subject to the gross margins tax enacted by the state of Texas. The Partnership has one wholly-owned subsidiary that is subject to income tax and provides for deferred income taxes using the asset and liability method. Accordingly, deferred taxes are recorded for differences between the tax and book basis that will reverse in future periods. The Partnership has deferred tax liabilities of $20 million and $22 million as of December 31, 2014 and 2013, respectively, related to the difference between the book and tax basis of property, plant and equipment and intangible assets and they are included in other long-term liabilities in the accompanying consolidated balance sheets. The Partnership follows the guidance for uncertainties in income taxes where a liability for an unrecognized tax benefit is recorded for a tax position that does not meet the “more likely than not” criteria. The Partnership has not recorded any uncertain tax positions meeting the more likely than not criteria as of December 31, 2014 and 2013. The Partnership recognized $3 million for current and deferred federal and state income tax for the year ended December 31, 2014 and an immaterial amount for current and deferred federal and state income tax benefit for the years ended December 31, 2013 and 2012.
Effective with the Partnership’s acquisition of SUGS on April 30, 2013, SUGS is generally no longer subject to federal income taxes and subject only to gross margins tax in the state of Texas. Substantially all previously recorded current and deferred tax liabilities were settled with Southern Union, along with all other intercompany receivables and payables at the date of acquisition.
The Partnership has its 2007 and 2008 tax years under audit by the IRS. Until this matter is fully resolved, it is not known whether any amounts ultimately recorded would be material, or how such adjustments would affect unitholders. The statute of limitations for these audits has been extended to December 31, 2015.
Equity-Based Compensation. The Partnership accounts for common unit options and phantom units by recognizing the grant-date fair value of awards into expense as they are earned, using an estimated forfeiture rate. The forfeiture rate assumption is reviewed annually to determine whether any adjustments to expense are required. Cash restricted units are recorded in other long-term liabilities on our consolidated balance sheet. The fair value of cash restricted units is remeasured at the end of each reporting period, based on the trading price of our common units, and compensation expense is recorded using the straight-line method over the vesting period.
Earnings per Unit. Basic net income per common unit is computed through the use of the two-class method, which allocates earnings to each class of equity security based on their participation in distributions and deemed distributions. Accretion of the Series A Preferred Units is considered as deemed distributions. Distributions and deemed distributions to the Series A Preferred Units reduce the amount of net income available to the general partner and limited partner interests. The general partners’ interest in net income or loss consists of its respective percentage interest, make-whole allocations for any losses allocated in a prior tax year and IDRs. After deducting the General Partner’s interest, the limited partners’ interest in the remaining net income or loss is
allocated to each class of equity units based on distributions and beneficial conversion feature amounts, if applicable, then divided by the weighted average number of common and subordinated units outstanding in each class of security. Diluted net income per common unit is computed by dividing limited partners’ interest in net income, after deducting the General Partner’s interest, by the weighted average number of units outstanding and the effect of non-vested phantom units, Series A Preferred Units and unit options. For special classes of common units, such as the Class F units issued with a beneficial conversion feature, the amount of the benefit associated with the period is added back to net income and the unconverted class is added to the denominator.
New Accounting Pronouncement. In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from 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. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period, with earlier adoption not permitted. ASU 2014-09 can be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. The Partnership is currently evaluating the impact, if any, that adopting this new accounting standard will have on our revenue recognition policies.
3. PARTNERS’ CAPITAL AND DISTRIBUTIONS
Units Activity. The changes in common and Class F units were as follows: | | | | | | | | | Common | | Class F | | Balance - December 31, 2011 | 157,437,608 |
| | — |
| | Common unit offerings, net of costs | 12,650,000 |
| | — |
| | Issuance of common units under the equity distribution agreement, net of cost | 691,129 |
| | — |
| | Issuance of common units under LTIP, net of forfeitures and tax withholding | 172,720 |
| | — |
| | Balance - December 31, 2012 | 170,951,457 |
| | — |
| | Issuance of common units under LTIP, net of forfeitures and tax withholding | 184,995 |
| | — |
| | Issuance of common units under the equity distribution agreement, net of cost | 5,712,138 |
| | — |
| | Conversion of Series A preferred units for common units | 2,629,223 |
| | — |
| | Issuance of common units and Class F units in connection with SUGS Acquisition | 31,372,419 |
| (1) | 6,274,483 |
| (2) | Balance - December 31, 2013 | 210,850,232 |
| | 6,274,483 |
| | Issuance of common units under LTIP, net of forfeitures and tax withholding | 163,054 |
| | — |
| | Issuance of common units under the equity distribution agreements | 14,827,919 |
| | — |
| | Issuance of common units in connection with Hoover Acquisition | 4,040,471 |
| | — |
| | Issuance of common units in connection with PVR Acquisition | 140,388,382 |
| | — |
| | Issuance of common units in connection with Eagle Rock Midstream Acquisition | 8,245,859 |
| | — |
| | Issuance of common units to ETE Common Holdings | 30,890,565 |
| | — |
| | Balance - December 31, 2014 | 409,406,482 |
| | 6,274,483 |
| |
| | (1) | ETE has agreed to forgo IDR payments on the Partnership common units issued with the SUGS Acquisition for twenty-four months post-transaction closing. |
| | (2) | The Class F units are not entitled to participate in the Partnership’s distributions or earnings for twenty-four months post-transaction closing. |
Equity Distribution Agreement. In June 2012, the Partnership entered into an equity distribution agreement with Citi under which the Partnership offered and sold common units for an aggregate offering price of $200 million, from time to time through Citi, as sales agent for the Partnership. Sales of these common units made from time to time under the equity distribution agreement were made by means of ordinary brokers’ transactions on the New York Stock Exchange at market prices, in block transactions, or as otherwise agreed upon by the Partnership and Citi. The Partnership used the net proceeds from the sale of these common units for general partnership purposes. For the years ended December 31, 2014 and 2013, the Partnership received net proceeds of $34 million and $149 million, respectively, from common units sold pursuant to this equity distribution agreement. No amounts remain available to be issued under this agreement and it is no longer effective.
In May 2014, the Partnership entered into an equity distribution agreement with a group of banks and investment companies (the “Managers”) under which the Partnership offered and sold common units for an aggregate offering price of $400 million, from time to time through the Managers, as sales agent for the Partnership. Sales of these units made from time to time under the equity distribution agreement were made by means of ordinary brokers’ transactions on the New York Stock Exchange at market prices, in block transactions, or as otherwise agreed upon by the Partnership and the Managers. The Partnership used the net proceeds
from the sale of these units for general partnership purposes. For the year ended December 31, 2014, the Partnership received net proceeds of $395 million from common units sold pursuant to this equity distribution agreement. No amounts remained available to be issues under this agreement and it is no longer effective.
In January 2015, the Partnership entered into an equity distribution agreement with another group of banks and investment companies (the "2015 Managers") under which the Partnership may offer and sell common units for an aggregate offering price of up to $1 billion, from time to time through the 2015 Managers, as sales agent for the Partnership. Sales of these common units made from time to time under the equity distribution agreement will be made by means of ordinary brokers’ transactions on the New York Stock Exchange at market prices, in block transactions, or as otherwise agreed upon by the Partnership and the 2015 Managers. The Partnership may also sell common units to the 2015 Managers as principal for their own accounts at a price agreed upon at the time of sale. Any sale of common units to the 2015 Managers as principal would be pursuant to the terms of a separate agreement between the Partnership and the 2015 Managers. The Partnership intends to use the net proceeds from the sale of these common units for general partnership purposes.
Common Units Sold. In June 2014, the Partnership sold 14.4 million common units to ETE Common Holdings for proceeds of $400 million. Proceeds from the issuance were used to pay down borrowings on the Partnership’s revolving credit facility, to redeem certain senior notes of the Partnership and for general partnership purposes. In July 2014, the Partnership sold 16.5 million common units to ETE Common Holdings for proceeds of $400 million. Proceeds from the issuance were used to fund a portion of the cash consideration paid to Eagle Rock in connection with the Eagle Rock Midstream Acquisition.
Public Common Unit Offerings. In March 2012, the Partnership issued 12,650,000 common units representing limited partner interests in a public offering at a price of $24.47 per common unit, resulting in net proceeds of $297 million. In May 2012, the Partnership used the net proceeds from this offering to redeem 35%, or $88 million, in aggregate principal amounts of its outstanding senior notes due 2016; pay related premium, expenses and accrued interest; and repay outstanding borrowings under the revolving credit facility.
Beneficial Conversion Feature. The Partnership issued 6,274,483 Class F units in connection with the SUGS Acquisition. At the commitment date (February 27, 2013), the sales price of $23.91 per unit represented a $2.19 per unit discount from the fair value of the Partnership’s common units as of April 30, 2013. Under FASB ASC 470-20, “Debt with Conversion and Other Options,” the discount represents a beneficial conversion feature that is treated as a non-cash distribution for purposes of calculating earnings per unit. The beneficial conversion feature is reflected in income per unit using the effective yield method over the period the Class F units are outstanding, as indicated on the statement of operations in the line item entitled “beneficial conversion feature for Class F units.” The Class F units are convertible to common units on a one-for-one basis on May 8, 2015.
Noncontrolling Interest. The Partnership operates ELG, a gas gathering joint venture in south Texas in which other third party companies own a 40% interest, and ORS, a gathering joint venture in Ohio in which a third party company owns a 25% interest, which are reflected on the Partnership’s consolidated balance sheet as noncontrolling interest.
Distributions. The partnership agreement requires the distribution of all of the Partnership’s Available Cash (defined below) within 45 days after the end of each quarter to unitholders of record on the applicable record date, as determined by the General Partner.
Available Cash. Available Cash, for any quarter, generally consists of all cash and cash equivalents on hand at the end of that quarter less the amount of cash reserves established by the general partner to: (i) provide for the proper conduct of the Partnership’s business; (ii) comply with applicable law, any debt instruments or other agreements; or (iii) provide funds for distributions to the unitholders and to the General Partner for any one or more of the next four quarters and plus, all cash on hand on that date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter for which the determination is being made.
General Partner Interest and Incentive Distribution Rights. The General Partner is entitled to its proportionate share of all quarterly distributions that the Partnership makes prior to its liquidation. The General Partner has the right, but not the obligation, to contribute a proportionate amount of capital to the Partnership to maintain its current general partner interest. The General Partner’s initial 2% interest in these distributions has been reduced since the Partnership has issued additional units and the General Partner has not contributed a proportionate amount of capital to the Partnership to maintain its General Partner interest. The General Partner ownership interest as of December 31, 2014 was 0.69%. This General Partner interest is represented by 2,834,381 equivalent units as of December 31, 2014.
The IDRs held by the General Partner entitle it to receive an increasing share of Available Cash when pre-defined distribution targets are achieved. The General Partner’s IDRs are not reduced if the Partnership issues additional units in the future and the general partner does not contribute a proportionate amount of capital to the Partnership to maintain its general partner interest.
In connection with the SUGS Acquisition, ETE agreed to forgo IDR payments on the Partnership common units issued with this transaction for the twenty-four months post-transaction closing.
Distributions. The Partnership made the following cash distributions per unit during the years ended December 31, 2014 and 2013:
| | | | | | Distribution Date | | Cash Distribution (per common unit) | November 14, 2014 | | $ | 0.5025 |
| August 14, 2014 | | 0.490 |
| May 15, 2014 | | 0.480 |
| February 14, 2014 | | 0.475 |
| | | | November 14, 2013 | | $ | 0.470 |
| August 14, 2013 | | 0.465 |
| May 13, 2013 | | 0.460 |
| February 14, 2013 | | 0.460 |
|
The Partnership paid a cash distribution of $0.5025 per common unit on February 13, 2015.
4. (LOSS) INCOME PER LIMITED PARTNER UNIT
The following table provides a reconciliation of the numerator and denominator of the basic and diluted (loss) earnings per unit computations for the years ended December 31, 2014, 2013, and 2012.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Years Ended December 31, | | 2014 | | 2013 | | 2012 | | Loss (Numerator) | | Units (Denominator) | | Per-Unit Amount | | Income (Numerator) | | Units (Denominator) | | Per-Unit Amount | | Income (Numerator) | | Units (Denominator) | | Per-Unit Amount | Basic (loss) income per unit | | | | | | | | | | | | | | | | | | Limited Partners’ interest in net (loss) income | $ | (199 | ) | | 348,070,121 |
| | $ | (0.57 | ) | | $ | 34 |
| | 196,227,348 |
| | $ | 0.17 |
| | $ | 27 |
| | 167,492,735 |
| | $ | 0.16 |
| Effect of Dilutive Securities: | | | | | | | | | | | | | | | | | | Common unit options | — |
| | — |
| | | | — |
| | 22,714 |
| | | | — |
| | 10,854 |
| | | Phantom units * | — |
| | — |
| | | | — |
| | 357,230 |
| | | | — |
| | 223,325 |
| | | Series A Preferred Units | — |
| | — |
| | | | — |
| | 2,050,854 |
| | | | (5 | ) | | 4,658,700 |
| | | Diluted (loss) income per unit | $ | (199 | ) | | 348,070,121 |
| | $ | (0.57 | ) | | $ | 34 |
| | 198,658,146 |
| | $ | 0.17 |
| | $ | 22 |
| | 172,385,614 |
| | $ | 0.13 |
|
__________________
| | * | Amount assumes maximum conversion rate for market condition awards. |
The following data show securities that could potentially dilute earnings per unit in the future that were not included in the computation of diluted earnings per unit because to do so would have been antidilutive for the period presented:
| | | | | Year Ended December 31, 2014 | Common unit options | 25,959 |
| Phantom units | 469,264 |
| Series A Preferred Units | 2,059,503 |
|
The partnership agreement requires that the General Partner shall receive a 100% allocation of income until its capital account is made whole for all of the net losses allocated to it in prior years.
5. ACQUISITIONS
2014
Eagle Rock Midstream Acquisition. On July 1, 2014, the Partnership acquired Eagle Rock’s midstream business (the “Eagle Rock Midstream Acquisition”) for $1.3 billion, including the issuance of 8.2 million Regency common units to Eagle Rock and 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 common units issued to ETE Common Holdings and borrowings under the Partnership’s revolving credit facility. The Partnership accounted for the Eagle Rock Midstream 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. This acquisition complemented the Partnership’s core gathering and processing business and further diversified the Partnership’s geographic presence in the mid-continent region, east Texas and south Texas. Revenues and net income attributable to Eagle Rock’s operations included in the statement of operations for the year ended December 31, 2014 were $903 million and $30 million, respectively.
Management’s evaluation of the assigned fair values is ongoing. The table below represents a preliminary allocation of the total purchase price:
| | | | | Assets | At July 1, 2014 | Current assets | $ | 120 |
| Property, plant and equipment | 1,295 |
| Other long-term assets | 4 |
| Goodwill (1) | 49 |
| Total Assets Acquired | $ | 1,468 |
| Liabilities | | Current liabilities | $ | 116 |
| Long-term debt | 499 |
| Long-term liabilities | 12 |
| Total Liabilities Assumed | $ | 627 |
| | | Net Assets Acquired | $ | 841 |
|
(1) Goodwill is reported in the Gathering and Processing segment.
The fair values of the assets acquired and liabilities assumed is being determined using various valuation techniques, including the income and market approaches.
PVR Acquisition. On March 21, 2014, the Partnership acquired PVR for a total purchase price of $5.7 billion, including $1.8 billion principal amount of assumed debt (“PVR Acquisition”). PVR unitholders received (on a per unit basis) 1.02 Partnership common units and a one-time cash payment of $36 million, which was funded through borrowings under the Partnership’s revolving credit facility. The PVR Acquisition enhanced the Partnership’s geographic diversity by adding a strategic presence in the Marcellus and Utica shales in the Appalachian Basin and the Granite Wash in the Mid-Continent region. The Partnership accounted for the acquisition of PVR 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. Revenues and net income
attributable to PVR’s operations included in the statement of operations for the year ended December 31, 2014 were $956 million and $166 million, respectively.
Management 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 |
| Gathering and transmission systems | 1,396 |
| Compression equipment | 342 |
| Gas plants and buildings | 110 |
| Natural resources | 454 |
| Other property, plant and equipment | 229 |
| Construction in process | 185 |
| Investments in unconsolidated affiliates | 62 |
| Intangible assets | 2,717 |
| Goodwill (1) | 370 |
| Other long-term assets | 18 |
| Total Assets Acquired | $ | 6,032 |
| Liabilities | | Current liabilities | $ | 168 |
| Long-term debt | 1,788 |
| Premium related to senior notes | 99 |
| Long-term liabilities | 30 |
| Total Liabilities Assumed | $ | 2,085 |
| | | Net Assets Acquired | $ | 3,947 |
|
(1) Goodwill is reported in the Gathering and Processing segment.
The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.
Assets.Cash and cash equivalents, accounts receivable, net, other current assets, and construction in process, were valued using a cost basis as this basis approximates fair value due to the current nature of these items. Real property, including gathering and transmission systems, compression equipment, gas plants and buildings, and other property, plant and equipment, were valued based on a combination of the income, market and cost approaches, depending on the type of asset. Coal and timber reserves were valued using the income approach for active coal and timber reserves. The investments in unconsolidated affiliates were valued using the income approach. Intangible assets, other than goodwill, are customer contract related intangibles, which have an average useful life of 30 years, and have been valued using the income approach. The goodwill is the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized.
Liabilities. The Partnership assumed accounts payable, accrued liabilities, deferred income, and other long-term liabilities as part of the PVR Acquisition. The Partnership determined that the historical cost basis of these liabilities approximated fair value as they comprise normal operating liabilities. The Partnership assumed long-term debt as part of the acquisition, consisting of amounts outstanding under PVR’s revolving credit facility and PVR’s outstanding senior notes. The amount related to the revolving credit facility was valued at historical book value while the senior notes were valued using quoted market prices, which are considered Level 1 inputs.
Change in Control. The PVR Acquisition constituted a change of control for certain PVR employment agreements. Pursuant to the terms of those agreements, certain payments and benefits, including severance payments, were triggered by the PVR Acquisition. The Partnership recorded $10 million of severance payments due to the change in control and recorded $2 million in retention bonuses that were paid to various retained PVR employees upon the expiration of their retention period.
Hoover Energy Acquisition.On February 3, 2014, the Partnership acquired certain subsidiaries of Hoover for a total purchase price of $293 million, consisting of (i) 4,040,471 common units issued to Hoover and (ii) $184 million in cash, and (iii) $2 million in asset retirement obligations assumed (the “Hoover Acquisition”). The Hoover Acquisition increased the Partnership’s fee-based revenue, expanding its existing footprint in the southern portion of the Delaware Basin in west Texas, and its services to producers into crude and water gathering. A portion of the consideration is in escrow as security for certain indemnification claims. The Partnership financed the cash portion of the purchase price through borrowings under its revolving credit facility. The Partnership accounted for the Hoover 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. Revenues and net income attributable to Hoover’s operations included in the statement of operations for the year ended December 31, 2014 were $35 million and less than $1 million, respectively.
Management 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 February 3, 2014 | Accounts receivable, net | $ | 5 |
| Gathering and transmission systems | 60 |
| Compression equipment | 16 |
| Gas plants and buildings | 12 |
| Other property, plant, and equipment | 23 |
| Construction in process | 6 |
| Intangible assets | 148 |
| Goodwill (1) | 30 |
| Total Assets Acquired | $ | 300 |
| Liabilities | | Accounts payable and accrued liabilities | $ | 5 |
| Asset retirement obligation | 2 |
| Total Liabilities Assumed | $ | 7 |
| | | Net Assets Acquired | $ | 293 |
|
(1) Goodwill is reported in the Gathering and Processing segment.
The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.
Assets.Accounts receivable, net, other current assets, and construction in process were valued using a cost basis as this basis approximates fair value due to the current nature of these items. Real property, including gathering and transmission systems, compression equipment, and other property, plant and equipment, were valued based on a combination of the income, market and cost approaches, depending on the type of asset. Intangible assets, other than goodwill, are customer contract related intangibles, which have an average useful life of 30 years, and have been valued using the income approach. The goodwill is the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized.
Liabilities. The Partnership assumed accounts payable, accrued liabilities, and an asset retirement obligation as part of the Hoover Acquisition. The Partnership determined that the historical cost basis of the accounts payable and the accrued liabilities approximated fair value as they comprise normal operating liabilities. The asset retirement obligation was valued based on estimates prepared by an independent environmental consulting firm.
Pro Forma Results of Operations
The following unaudited pro forma consolidated results of operations for the years ended December 31, 2014 and 2013 are presented as if the PVR, Hoover and Eagle Rock Midstream acquisitions had been completed on January 1, 2013. The pro forma information includes adjustments to reflectincremental expenses associated with the fair value adjustments recorded as a result of applying the acquisition method of accounting and incremental interest expense related to the financing of a portion of the purchase price. This pro forma information is not necessarily indicative of the results that would have occurred had the acquisitionsSunoco Logistics Merger occurred on January 1, 2013, nor is it indicative of future results of operations. Actual results for the year ended December 31, 2014 include PVR, Hoover, and the Eagle Rock midstream business from their respective dates of acquisition.
| | | | | | | | | | Years Ended December 31, | | 2014 | | 2013 | Revenues | $ | 5,780 |
| | $ | 4,695 |
| Net loss attributable to the Partnership | (252 | ) | | (195 | ) | | | | | Basic net loss per Limited Partner unit | $ | (0.76 | ) | | $ | (0.50 | ) | Diluted net loss per Limited Partner unit | $ | (0.76 | ) | | $ | (0.50 | ) |
2013
SUGS Acquisition.In April 2013, the Partnership acquired SUGS from Southern Union, a wholly-owned subsidiary of Holdco, for $1.5 billion (the “SUGS Acquisition”).
The Partnership accounted for the SUGS Acquisition in a manner similar to the pooling of interest method of accounting as it was a transaction between commonly controlled entities. The Partnership retrospectively adjusted its financial statements to include the balances and operations of SUGS for periods March 26, 2012 to April 30, 2013. The SUGS Acquisition did not impact historical earnings per unit as pre-acquisition earnings were allocated to predecessor equity.
The assets acquired and liabilities assumed in the SUGS Acquisition were as follows:
| | | | | | April 30, 2013 | Current assets | $ | 113 |
| Property, plant and equipment, net | 1,608 |
| Goodwill | 337 |
| Other non-current assets | 1 |
| Total Assets Acquired | $ | 2,059 |
| Less: | | Current liabilities | (93 | ) | Non-current liabilities | (36 | ) | Net Assets Acquired | $ | 1,930 |
|
The following table presents the revenues and net income (loss) for the previously separate entities and combined amounts presented herein:
| | | | | | | | | | Years Ended December 31, | | 2013 (1) | | 2012 | Revenues: | | | | Partnership | $ | 2,253 |
| | $ | 1,339 |
| SUGS (1) | 268 |
| | 661 |
| Combined | $ | 2,521 |
| | $ | 2,000 |
| | | | | Net income (loss): | | | | Partnership | $ | 63 |
| | $ | 48 |
| SUGS (1) | (36 | ) | | (14 | ) | Combined | $ | 27 |
| | $ | 34 |
|
| | (1)
| Combined amounts attributable to SUGS include the period from March 26, 2012 to December 31, 2012 for the year ended December 31, 2012, and the period from January 1, 2013 to April 30, 2013 for the year ended December 31, 2013. Subsequent to the closing of the SUGS Acquisition on April 30, 2013, the results of SUGS were attributable to the Partnership. |
6. INVESTMENTS IN UNCONSOLIDATED AFFILIATES
The carrying value of the Partnership’s investment in each of the unconsolidated affiliates as of December 31, 2014 and 2013 is as follows:
| | | | | | | | | | | | | | | | | | | | December 31, | | | Ownership | | Type | | 2014 | | 2013 | HPC | | 49.99% | | General Partner | | $ | 422 |
| | $ | 442 |
| MEP | | 50.00% | | Membership Interest | | 695 |
| | 549 |
| Lone Star | | 30.00% | | Membership Interest | | 1,162 |
| | 1,070 |
| Ranch JV | | 33.33% | | Membership Interest | | 38 |
| | 36 |
| Aqua - PVR | | 51.00% | | Membership Interest | | 46 |
| | — |
| Mi Vida JV | | 50.00% | | Membership Interest | | 54 |
| | — |
| Others (1) | | | | | | 1 |
| | — |
| | | | | | | $ | 2,418 |
| | $ | 2,097 |
|
(1) Others includes Coal Handling, Sweeny JV and Grey Ranch
The Partnership’s interests in the Aqua - PVR joint venture was acquired in the PVR Acquisition. In March 2014, the Partnership entered into an agreement, whereby the Partnership’s 50% interest in Grey Ranch was assigned to SandRidge Midstream, Inc., resulting in a cash settlement of $4 million and a loss of $1 million recorded to income from unconsolidated affiliates.
The following tables summarize the changes in the Partnership’s investment activities in each of the unconsolidated affiliates for the years ended December 31, 2014, 2013 and 2012:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2014 | | HPC | | MEP (2) | | Lone Star | | Ranch JV | | Aqua - PVR | | Mi Vida JV | | Others (4) | Contributions to unconsolidated affiliates | $ | — |
| | $ | 175 |
| | $ | 114 |
| | $ | — |
| | $ | — |
| | $ | 54 |
| | $ | — |
| Distributions from unconsolidated affiliates | (48 | ) | | (73 | ) | | (137 | ) | | (8 | ) | | (1 | ) | | — |
| | (4 | ) | Share of earnings of unconsolidated affiliates’ net income (loss) | 33 |
| | 45 |
| | 116 |
| | 9 |
| | (4 | ) | | — |
| | 2 |
| Amortization of excess fair value of investment (1) | (6 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2013 | | HPC (3) | | MEP | | Lone Star | | Ranch JV | | Others (4) | Contributions to unconsolidated affiliates | $ | — |
| | $ | — |
| | $ | 137 |
| | $ | 2 |
| | $ | — |
| Distributions from unconsolidated affiliates | (238 | ) | | (72 | ) | | (79 | ) | | (2 | ) | | — |
| Share of earnings of unconsolidated affiliates’ net income | 36 |
| | 40 |
| | 64 |
| | 1 |
| | — |
| Amortization of excess fair value of investment (1) | (6 | ) | | — |
| | — |
| | — |
| | — |
|
| | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2012 | | HPC | | MEP | | Lone Star | | Ranch JV | | Others (4) | Contributions to unconsolidated affiliates | $ | — |
| | $ | — |
| | $ | 343 |
| | $ | 36 |
| | $ | — |
| Distributions from unconsolidated affiliates | (61 | ) | | (75 | ) | | (68 | ) | | — |
| | — |
| Share of earnings of unconsolidated affiliates’ net income (loss) | 35 |
| | 42 |
| | 44 |
| | (1 | ) | | (9 | ) | Amortization of excess fair value of investment (1) | (6 | ) | | — |
| | — |
| | — |
| | — |
|
__________________
| | (1) | The Partnership’s investment in HPC was adjusted to its fair value on May 26, 2010 and the excess fair value over net book value was comprised of two components: (1) $155 million was attributed to HPC’s long-lived assets and is being amortized as a reduction of income from unconsolidated affiliates over the useful lives of the respective assets, which vary from 15 to 30 years, and (2) $32 million could not be attributed to a specific asset and therefore will not be amortized in future periods. |
| | (2) | The Partnership contributed $175 million to MEP in September 2014 for the repayment of MEP’s debt. |
| | (3) | HPC entered into a $500 million 5-year revolving credit facility in September 2013, pursuant to which the Partnership pledged its 49.99% equity interest in HPC. Upon closing such credit facility, HPC borrowed $370 million to fund a non-recurring return of investment to its partners of which the Partnership received $185 million. The amount outstanding under this facility was $450 million as of December 31, 2014. The Partnership’s contingent obligation with respect to the outstanding borrowings under this facility was $225 million at December 31, 2014. |
| | (4) | Includes Coal Handling, Grey Ranch, and Sweeny JV. |
Summarized Financial Information
Consolidated financial statements for HPC, MEP, and Lone Star are filed as exhibits to this Form 10-K. The following tables present aggregated selected balance sheet and income statement data for Ranch JV (on a 100% basis) for all periods presented:
| | | | | | | | | | December 31, | | 2014 | | 2013 | Current assets | $ | 16 |
| | $ | 7 |
| Property, plant and equipment, net | 95 |
| | 100 |
| Other assets | 4 |
| | 4 |
| Total assets | $ | 115 |
| | $ | 111 |
| | | | | Current liabilities | $ | 2 |
| | $ | 3 |
| Equity | 113 |
| | 108 |
| Total liabilities and equity | $ | 115 |
| | $ | 111 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2014 | | 2013 | | 2012 | Revenue | $ | 41 |
| | $ | 16 |
| | $ | 1 |
| Operating income (loss) | 29 |
| | 4 |
| | (2 | ) | Net income (loss) | 29 |
| | 4 |
| | (2 | ) |
7. DERIVATIVE INSTRUMENTS
Policies. The Partnership established comprehensive risk management policies and procedures to monitor and manage the market risks associated with commodity prices, counterparty credit and interest rates. The General Partner is responsible for delegation
of transaction authority levels, and the Audit and Risk Committee of the General Partner is responsible for overseeing the management of these risks, including monitoring exposure limits. The Audit and Risk Committee receives regular briefings on exposures and overall risk management in the context of market activities.
Commodity Price Risk. The Partnership is a net seller of NGLs, condensate and natural gas as a result of its gathering and processing operations. The prices of these commodities are impacted by changes in supply and demand as well as market forces. Both the Partnership’s profitability and cash flow are affected by the inherent volatility of these commodities which could adversely affect its ability to make distributions to its unitholders. The Partnership manages this commodity price exposure through an integrated strategy that includes management of its contract portfolio, matching sales prices of commodities with purchases, optimization of its portfolio by monitoring basis and other price differentials in operating areas, and the use of derivative contracts. In some cases, the Partnership may not be able to match pricing terms or cover its risk to price exposure with financial hedges, and it may be exposed to commodity price risk.
The Partnership has swap contracts settled against certain NGLs, condensate and natural gas market prices.
Marketing & Trading. The Partnership conducts natural gas marketing and trading activities intended to capitalize on favorable price differentials between various receipt and delivery locations. The Partnership enters into both financial derivatives and physical contracts. These financial derivatives, primarily basis swaps, are transacted: (i) to economically hedge subscribed capacity exposed to market rate fluctuations and (ii) to mitigate the price risk related to other purchases and sales of natural gas. By entering into a basis swap, one pricing index is exchanged for another, effectively locking in the margin between the natural gas purchase and sale by removing index spread risk on the combined physical and financial transaction. Changes in the fair value of these financial and physical contracts are recorded as adjustments to natural gas sales and realized (unrealized) gain (loss) from derivatives, as appropriate.
The Partnership has credit exposure to additional counterparties. The Partnership monitors its exposure to any single counterparty and the creditworthiness of its counterparties on an ongoing basis. In addition, the Partnership’s natural gas purchase and sale contracts, for certain counterparties, are subject to counterparty netting agreements governing settlement under such natural gas purchase and sales contracts, and when possible, the Partnership nets the open positions of each counterparty.
Interest Rate Risk. The Partnership is exposed to variable interest rate risk as a result of borrowings under its revolving credit facility. As of December 31, 2014, the Partnership had $1.5 billion of outstanding borrowings exposed to variable interest rate risk.
Credit Risk. The Partnership’s resale of NGLs, condensate and natural gas exposes it to credit risk, as the margin on any sale is generally a very small percentage of the total sales price. Therefore, a credit loss can be very large relative to overall profitability on these transactions. The Partnership attempts to ensure that it issues credit only to credit-worthy counterparties and that in appropriate circumstances any such extension of credit is backed by adequate collateral, such as a letter of credit or parental guarantee from a parent company with potentially better credit.
The Partnership is exposed to credit risk from its derivative contract counterparties. The Partnership does not require collateral from these counterparties. The Partnership deals primarily with financial institutions when entering into financial derivatives, and utilizes master netting agreements that allow for netting of swap contract receivables and payables in the event of default by either party. If the Partnership’s counterparties failed to perform under existing swap contracts, the Partnership’s maximum loss as of December 31, 2014 was $82 million, which would be reduced by less than $1 million due to the netting feature. The Partnership has elected to present assets and liabilities under master netting agreements gross on the consolidated balance sheets.
Embedded Derivatives. The Series A Preferred Units contain embedded derivatives which are required to be bifurcated and accounted for separately, such as the holders’ conversion option and the Partnership’s call option. These embedded derivatives are accounted for using mark-to-market accounting. The Partnership does not expect the embedded derivatives to affect its cash flows.
The Partnership’s derivative assets and liabilities, including credit risk adjustments, as of December 31, 2014 and 2013 are detailed below:
| | | | | | | | | | | | | | | | | | Assets | | Liabilities | | December 31, | | December 31, | | 2014 | | 2013 | | 2014 | | 2013 | Derivatives not designated as cash flow hedges | | | | | | | | Current amounts | | | | | | | | Commodity contracts | $ | 75 |
| | $ | 3 |
| | $ | — |
| | $ | 9 |
| Long-term amounts | | | | | | | | Commodity contracts | 10 |
| | 1 |
| | — |
| | — |
| Embedded derivatives in Series A Preferred Units | — |
| | — |
| | 16 |
| | 19 |
| Total derivatives | $ | 85 |
| | $ | 4 |
| | $ | 16 |
| | $ | 28 |
|
The Partnership’s statements of operations for the years ended December 31, 2014, 2013 and 2012 were impacted by derivative instruments activities as detailed below:
| | | | | | | | | | | | | | | | | | Years Ended December 31, | | | | 2014 | | 2013 | | 2012 | Derivatives in cash flow hedging relationships: | | | Change in Value Recognized in AOCI on Derivatives (Effective Portion) | Commodity derivatives | | | $ | — |
| | $ | — |
| | $ | (4 | ) | Derivatives in cash flow hedging relationships: | Location of Gain/(Loss) Recognized in Income | | Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) | Commodity derivatives | Revenue | | $ | — |
| | $ | — |
| | $ | 6 |
|
| | | | | | | | | | | | | | | | | | Years Ended December 31, | | | | 2014 | | 2013 | | 2012 | Derivatives not designated in a hedging relationship: | Location of Gain/(Loss) Recognized in Income | | Amount of Gain/(Loss) from De-designation Amortized from AOCI into Income | Commodity derivatives | Revenue | | $ | — |
| | $ | — |
| | $ | (5 | ) | Derivatives not designated in a hedging relationship: | Location of Gain/(Loss) Recognized in Income | | Amount of Gain/(Loss) Recognized in Income from Derivatives | Commodity derivatives | Revenue | | $ | 93 |
| | $ | (9 | ) | | $ | 16 |
| Embedded derivatives | Other income & deductions | | 3 |
| | 6 |
| | 14 |
| | | | $ | 96 |
| | $ | (3 | ) | | $ | 30 |
|
8. LONG-TERM DEBT
Obligations in the form of senior notes and borrowings under the credit facilities are as follows:
| | | | | | | | | | December 31, | | 2014 | | 2013 | Senior notes | $ | 5,089 |
| | $ | 2,800 |
| Revolving loans | 1,504 |
| | 510 |
| Unamortized premiums and discounts | 48 |
| | — |
| Long-term debt | $ | 6,641 |
| | $ | 3,310 |
| Availability under revolving credit facility: | | | | Total credit facility limit | $ | 2,000 |
| | $ | 1,200 |
| Revolving loans | (1,504 | ) | | (510 | ) | Letters of credit | (23 | ) | | (14 | ) | Total available | $ | 473 |
| | $ | 676 |
|
Long-term debt maturities as of December 31, 2014 for each of the next five years are as follows:
| | | | | Year Ended December 31, | Amount | 2015 | $ | — |
| 2016 | — |
| 2017 | — |
| 2018 | — |
| 2019 | 2,003 |
| Thereafter | 4,590 |
| Total * | $ | 6,593 |
|
| | * | Excludes a $67 million unamortized premium on the 2020 PVR Notes and the 2021 PVR Notes assumed by the Partnership and a $19 million unamortized discount on the combined 2022 Notes. |
Revolving Credit Facility
In the years ended December 31, 2014, 2013 and 2012 the Partnership borrowed $3.86 billion, $1.83 billion and $1.56 billion, respectively, under its revolving credit facility; these borrowings were to fund capital expenditures and acquisitions. During the same periods, the Partnership repaid $3.48 billion, $1.52 billion and $1.70 billion, respectively, with proceeds from equity offerings and issuances of senior notes.
In February 2014, RGS entered into the First Amendment (the "First Amendment") to the Sixth Amended and Restated Credit Agreement (the “Credit Agreement”) to, among other things, expressly permit the pending PVR and Eagle Rock Midstream acquisitions, and to increase the commitment base to $1.5 billion and increase the uncommitted incremental facility to $500 million. The First Amendment allowed the Partnership to assume the legacy PVR senior notes that mature prior to the Credit Agreement.
In September 2014, RGS entered into the Second Amendment to the Credit Agreement to, among other things, increase the letter of credit sublimit from $50 million to $100 million, with none of the four individual issuing banks being required to issue letters of credit in excess of $25 million; increase in the general basket of permitted investments from $300 million to $500 million; add provisions permitting investments in ORS, affording it similar treatment to the Partnership’s existing joint ventures; and update various swap agreement provisions to conform to current market standards.
In November 2014, RGS entered into the Seventh Amended and Restated Credit Agreement (the "New Credit Agreement") to increase the commitment to $2 billion and extended the maturity date to November 25, 2019. The material differences between the Credit Agreement and the New Credit Agreement include:
the addition of provisions permitting investments in Mi Vida JV affording it similar treatment to the Partnership’s existing joint ventures;
an increase in certain permitted covenant baskets; and
updates to various pricing terms and the permitted maximum total leverage ratio to reflect the Partnership’s growth.
In connection with the New Credit Agreement, the Partnership capitalized $5 million of net loan fees related to the amendments completed in the year ended December 31, 2014, which are being amortized over the remaining term.
In May 2013, RGS entered into the Credit Agreement to increase the commitment to $1.2 billion with a $300 million uncommitted incremental facility and extended the maturity date to May 21, 2018. The material differences between the Fifth Amended and Restated Credit Agreement and the Credit Agreement include:
A 75 bps decrease in pricing, with an additional 50 bps decrease upon the achievement of an investment grade rating;
No limitation on the maximum amount that the loan parties may invest in joint ventures existing on the date of the credit agreement so long as the Partnership is in pro forma compliance with the financial covenants;
The addition of a “Restricted Subsidiary” structure such that certain designated subsidiaries are not subject to the credit facility covenants and do not guarantee the obligations thereunder or pledge their assets in support thereof;
The addition of provisions such that upon the achievement of an investment grade rating by the Partnership, the collateral package will be released; the facility will become unsecured; and the covenant package will be significantly reduced;
An eight-quarter increase in the permitted Total Leverage Ratio; and
After March 2015, an increase in the permitted total leverage ratio for the two fiscal quarters following any $50 million or greater acquisition.
In connection with the Credit Agreement, the Partnership capitalized $6 million of net loan fees related to this amendment which are being amortized over the remaining term.
Borrowings under the New Credit Agreement are secured by substantially all of the Partnership’s assets and are guaranteed by the Partnership and its consolidated subsidiaries, except for ELG and ORS. The New Credit Agreement and the guarantees thereunder are senior to the Partnership’s and the guarantors’ unsecured obligations.
The outstanding balance under the New Credit Agreement bears interest at LIBOR plus a margin or alternate base rate (equivalent to the U.S. prime lending rate) plus a margin, or a combination of both. The alternate base rate used to calculate interest on base rate loans will be calculated based on the greatest to occur of a base rate, a federal funds effective rate plus 0.50% and an adjusted one-month LIBOR rate plus 1.00%. The applicable margin shall range from 0.50% to 1.25% for base rate loans, 1.50% to 2.25% for Eurodollar loans. The weighted average interest rate on the amounts outstanding under the Partnership’s Credit Agreement was 2.17% as of December 31, 2014 and 2013.
RGS must pay (i) a commitment fee ranging from 0.25% to 0.375% per annum of the unused portion of the revolving loan commitments, (ii) a participation fee for each revolving lender participating in letters of credit ranging from 1.5% to 2.25% per annum of the average daily amount of such lender’s letter of credit exposure and (iii) a fronting fee to the issuing bank of letters of credit equal to 0.20% per annum of the average daily amount of the letter of credit exposure. These fees are included in interest expense, net in the consolidated statement of operations.
The New Credit Agreement contains financial covenants requiring RGS and its subsidiaries to maintain a debt to consolidated EBITDA (as defined in the credit agreement) ratio less than 5.50, a consolidated EBITDA to consolidated interest expense ratio greater than 2.50 and a secured debt to consolidated EBITDA ratio less than 3.25. At December 31, 2014 and 2013, RGS and its subsidiaries were in compliance with these covenants.
The New Credit Agreement restricts the ability of RGS to pay dividends and distributions other than reimbursements to the Partnership for expenses and payment of dividends to the Partnership for the amount of available cash (as defined) so long as no default or event of default has occurred or is continuing. The New Credit Agreement also contains various covenants that limit (subject to certain exceptions), among other things, the ability of RGS to:
enter into sale and leaseback transactions;
make certain investments, loans and advances;
dissolve or enter into a merger or consolidation;
enter into asset sales or make acquisitions;
enter into transactions with affiliates;
prepay other indebtedness or amend organizational documents or transactions documents (as defined in the New Credit Agreement);
issue capital stock or create subsidiaries; or
engage in any business other than those businesses in which it was engaged at the time of the effectiveness of the New Credit Agreement or reasonable extension thereof.
In February 2015, RGS exercised the accordion feature of the New Credit Agreement to increase commitments under the revolving credit facility by $500 million to a total of $2.5 billion. The increased commitments will be available pursuant to the same terms and subject to the same interest rates and fees as the existing commitments under the New Credit Agreement.
Senior Notes
The Partnership and Finance Corp. have the following series of senior notes (collectively “Senior Notes”):
$400 million in aggregate principal amount of our 5.75% senior notes due September 1, 2020 (the “2020 Notes“) with interest payable semi-annually in arrears on March 1 and September 1;
$500 million in aggregate principal amount of our 6.5% senior notes due July 15, 2021 (the “2021 Notes“) with interest payable semi-annually in arrears on January 15 and July 15;
$900 million in aggregate principal of our 5.875% senior notes due March 1, 2022 (the “2022 Notes“), issued in February 2014, with interest payable semi-annually in arrears on March 1 and September 1;
$700 million in aggregate principal amount of our 5.5% senior notes due April 15, 2023 (the “2023 5.5% Notes“) with interest payable semi-annually in arrears on April 15 and October 15;
$600 million in aggregate principal amount of our 4.5% senior notes due November 1, 2023 (the “2023 4.5% Notes“) with interest payable semi-annually in arrears on May 1 and November 1;
$390 million, after partial redemption, in aggregate principal amount of our 8.375% senior notes due June 1, 2020 (the “2020 PVR Notes“) with interest payable semi-annually in arrears on June 1 and December 1;
$400 million in aggregate principal amount of our 6.5% senior notes due May 15, 2021 (the “2021 PVR Notes“) with interest payable semi-annually in arrears on May 15 and November 15;
$499 million in aggregate principal amount of our 8.375% senior notes due June 1, 2019 (the “2019 Notes“) with interest payable semi-annually in arrears on June 1 and December 1; and
$700 million in aggregate principal amount of our 5% senior notes due October 1, 2022 (the “October 2022 Notes“) with interest payable semi-annually in arrears on April 1 and October 1.
In May 2009, the Partnership and Finance Corp. issued $250 million of senior notes with a maturity of June 1, 2016 (the “2016 Notes”). The 2016 Notes bore interest at 9.375% with interest payable semi-annually in arrears on June 1 and December 1. In May 2012, the Partnership redeemed 35%, or $88 million, of the 2016 Notes, bringing the total outstanding principal amount to $163 million. A redemption premium of $8 million was charged to loss on debt refinancing, net in the consolidated statements of operations and $4 million of accrued interest was paid. The Partnership also wrote off the unamortized loan fee of $1 million and unamortized bond premium of $2 million to loss on debt refinancing, net in the consolidated statement of operations. In June 2013, the Partnership redeemed all amounts outstanding 2016 Notes for $178 million cash, inclusive of accrued and unpaid interest of $7 million and other fees and expenses.
In February 2014, the Partnership and Finance Corp. issued $900 million of senior notes that mature on March 1, 2022 (the “2022 Notes”). The 2022 Notes bear interest at 5.875% with interest payable semi-annually in arrears on September 1 and March 1. At any time prior to December 1, 2021, the Partnership may redeem some or all of the notes at 100% of the principal amount thereof, plus a “make-whole” redemption price and accrued and unpaid interest, if any, to the redemption date. On or after December 1, 2021, the Partnership may redeem some or all of the 2022 Notes at a redemption price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date. The 2022 Notes rank equally with the Partnership’s other Senior Notes.
In March 2014, in connection with the PVR Acquisition, the Partnership assumed $1.2 billion in aggregate principal amount of PVR’s outstanding senior notes, consisting of $300 million of 8.25% senior notes that mature on April 15, 2018 (the “2018 PVR Notes”), $400 million of 6.5% senior notes that mature on May 15, 2021 (the “2021 PVR Notes”), and $473 million of 8.375% senior notes that mature on June 1, 2020 (the “2020 PVR Notes”, and together with the 2021 PVR Notes, the "PVR Notes"). In April 2014, the Partnership redeemed all of the 2018 PVR Notes for $313 million at a price of 104.125% plus accrued and unpaid interest paid to the redemption date. Interest on the 2021 PVR Notes and the 2020 PVR Notes accrue semi-annually on May 15 and November 15 and June 1 and December 1, respectively. The PVR Notes rank equally with the Partnership’s other Senior Notes.
On March 24, 2014, in accordance with the Partnership’s obligations under the indentures governing the PVR Notes, the Partnership commenced change of control offers pursuant to which holders of such notes were entitled to require the Partnership to repurchase all or a portion of its PVR Notes at a purchase price of 101% of the principal amount thereof, plus accrued and unpaid interest to the repurchase date. The change of control offers for the PVR Notes expired on April 22, 2014 and, on April 23, 2014, the Partnership accepted for purchase less than $1 million in aggregate principal amount of 2021 PVR Notes.
In July 2014, in connection with the Eagle Rock Midstream Acquisition, the Partnership exchanged $499 million of 8.375% Senior Notes due 2019 of Eagle Rock and Eagle Rock Energy Finance Corp. for 8.375% Senior Notes due 2019 issued by the Partnership and Finance Corp. (the “New Partnership Notes”). The New Partnership Notes rank equally with the Partnership’s other Senior Notes.
In July 2014, the Partnership and Finance Corp. issued $700 million of senior notes that mature on October 1, 2022 (the “October 2022 Notes”). The October 2022 Notes bear interest at 5% with interest payable semi-annual in arrears on October 1 and April 1, beginning April 1, 2015. At any time prior to July 1, 2022, the Partnership may redeem some or all of the October 2022 Notes at 100% of the principal amount thereof, plus a “make-whole” redemption price and accrued and unpaid interest, if any, to the redemption date. On or after, July 1, 2022, the Partnership may redeem some or all of the October 2022 Notes at a redemption price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date. The October 2022 Notes rank equally with the Partnership’s other Senior Notes.
In July 2014, the Partnership redeemed $83 million of the $473 million outstanding 2020 PVR Notes for $91 million, including $8 million of accrued interest and redemption premium.
In December 2014, the Partnership redeemed all of the outstanding $600 million 2018 Notes, for a total price of 103.438% or $621 million.
The Senior Notes issued by the Partnership and Finance Corp. are fully and unconditionally guaranteed, on a joint and several
basis, by all of the Partnership’s consolidated subsidiaries, except for ELG and ORS.
The Senior Notes are redeemable at any time prior to the dates specified below at a price equal to 100% of the principal amount of the applicable series, plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date:
2020 Notes - Redeemable, in whole or in part, prior to June 1, 2020 at 100% of the principal amount plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date; redeemable, in whole or in part, on or after June 1, 2020 at 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date
2021 Notes - Any time prior to July 15, 2014, up to 35% may be redeemed at a price of 106.5% plus accrued and unpaid interest, if any; beginning July 15, 2016, 100% may be redeemed at fixed redemption price of 103.25% (July 15, 2017 - 102.167%, July 15, 2018 - 101.083% and July 15, 2019 and thereafter - 100%) plus accrued and unpaid interest, if any, to the redemption date
2022 Notes - Redeemable, in whole or in part, prior to December 1, 2021 at 100% at the principal amount plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date; redeemable, in whole or in part, on or after December 1, 2021 at 100% at the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date
2023 5.5% Notes - Any time prior to October 15, 2015, up to 35% may be redeemed at a price of 105.5% plus accrued and unpaid interest, if any; beginning October 15, 2017, 100% may be redeemed at fixed redemption price of 102.75% (October 15, 2018 - 101.833%, October 15, 2019 - 100.917% and October 15, 2020 and thereafter - 100%) plus accrued and unpaid interest, if any, to the redemption date
2023 4.5% Notes - Redeemable, in whole or in part, prior to August 1, 2023 at 100% of the principal amount plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date; redeemable, in whole or in part, on or after August 1, 2023 at 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date
2020 PVR Notes - Any time prior to June 1, 2015, up to 35% may be redeemed at a price of 108.375% plus accrued and unpaid interest, if any; beginning June 1, 2016, 100% may be redeemed at fixed redemption price of 104.188% (June 1, 2017 - 102.094%, June 1, 2018 and thereafter - 100%) plus accrued and unpaid interest, if any, to the redemption date
2021 PVR Notes - Any time prior to May 15, 2016, up to 35% may be redeemed at a price of 106.5% plus accrued and unpaid interest and liquidated damages, if any; beginning May 15, 2016, 100% may be redeemed at a fixed redemption price of 104.875% (May 15, 2017 - 103.250%, May 15, 2018 - 101.625% and May 15, 2019 and thereafter - 100%) plus accrued and unpaid interest, if any, to the redemption date
2019 Notes - Redeemable, in whole or in part, prior to June 1, 2015 at 100% at the principal amount plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date; beginning June 1, 2015, 100% may be redeemed at a fixed redemption price of 104.188% (June 1, 2016 - 102.094% and June 1, 2017 and thereafter - 100%) plus accrued and unpaid interest, if any, to the redemption date
October 2022 Notes - Redeemable, in whole or in part, prior to July 1, 2022 at 100% of the principal amount plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date; redeemable, in whole or in part, on or
after July 1, 2022 at 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date
Upon a change of control followed by a ratings downgrade within 90 days of a change of control, each holder of the Partnership’s Senior Notes, other than the PVR Notes, will be entitled to require the Partnership to repurchase all or a portion of its notes at a purchase price of 101% plus accrued and unpaid interest, if any. Upon a change of control, the indenture governing the PVR Notes requires the Partnership to make an offer to repurchase all outstanding notes at101%of the principal amount thereof, plus accrued and unpaid interest (and additional interest, if any) to the date of repurchase. The Partnership’s ability to repurchase the Senior Notes upon a change of control will be limited by the terms of our debt agreements, including the Partnership’s revolving credit facility.
The Senior Notes contain various covenants that limit, among other things, the Partnership’s ability, and the ability of certain of the Partnership’s subsidiaries, to:
incur additional indebtedness;
pay distributions on, or repurchase or redeem our equity interests;
make certain investments;
enter into certain types of transactions with affiliates; and
sell assets or consolidate or merge with or into other companies.
If the Senior Notes achieve investment grade ratings by both Moody’s and Standard & Poor’s and no default or event of default has occurred and is continuing, the Partnership will no longer be subject to many of the foregoing covenants. At December 31, 2014, the Partnership was in compliance with these covenants.
9. INTANGIBLE ASSETS
Activity related to intangible assets, net consisted of the following:
| | | | | | | | | | | | | | Customer Relations | | Trade Names | | Total | Balance at January 1, 2013 | $ | 655 |
| | $ | 57 |
| | $ | 712 |
| Amortization | (26 | ) | | (4 | ) | | (30 | ) | Balance at December 31, 2013 | 629 |
| | 53 |
| | 682 |
| Amortization | (105 | ) | | (3 | ) | | (108 | ) | Intangible assets acquired | 2,865 |
| | — |
| | 2,865 |
| Balance at December 31, 2014 | $ | 3,389 |
| | $ | 50 |
| | $ | 3,439 |
|
The average remaining amortization periods for customer relations and trade names are 28 and 15 years, respectively. The expected amortization of the intangible assets for each of the five succeeding years is $135 million.
10. FAIR VALUE MEASURES
The fair value measurement provisions establish a three-tiered fair value hierarchy that prioritizes inputs to valuation techniques used in fair value calculations. The three levels of inputs are defined as follows:
Level 1—unadjusted quoted prices for identical assets or liabilities in active accessible markets;
Level 2—inputs that are observable in the marketplace other than those classified as Level 1; and
Level 3—inputs that are unobservable in the marketplace and significant to the valuation.
Entities are encouraged to maximize the use of observable inputs and minimize the use of unobservable inputs. If a financial instrument uses inputs that fall in different levels of the hierarchy, the instrument will be categorized based upon the lowest level of input that is significant to the fair value calculation.
The Partnership’s financial assets and liabilities measured at fair value on a recurring basis are derivatives related to commodity
swaps and embedded derivatives in the Series A Preferred Units. Derivatives related to commodity swaps are valued using discounted cash flow techniques. These techniques incorporate Level 1 and Level 2 inputs such as commodity prices. These market inputs are utilized in the discounted cash flow calculation considering the instrument’s term, notional amount, discount rate and credit risk and are classified as Level 2 in the hierarchy. Embedded derivatives related to Series A Preferred Units are valued using
a binomial lattice model. The inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected volatility, and are classified as Level 3 in the hierarchy.
The following table presents the Partnership’s derivative assets and liabilities measured at fair value on a recurring basis:
| | | | | | | | | | | | | | | | | | | | | | | | | | Fair Value Measurement at December 31, | | 2014 | | 2013 | | Fair Value Total | | Level 2 | | Level 3 | | Fair Value Total | | Level 2 | | Level 3 | Assets | | | | | | | | | | | | Commodity Derivatives: | | | | | | | | | | | | Natural Gas | $ | 26 |
| | $ | 26 |
| | $ | — |
| | $ | 2 |
| | $ | 2 |
| | $ | — |
| Natural Gas Liquids | 23 |
| | 23 |
| | — |
| | 2 |
| | 2 |
| | — |
| Condensate | 36 |
| | 36 |
| | — |
| | — |
| | — |
| | — |
| Total Assets | $ | 85 |
| | $ | 85 |
| | $ | — |
| | $ | 4 |
| | $ | 4 |
| | $ | — |
| Liabilities | | | | | | | | | | | | Commodity Derivatives: | | | | |
| | | | | | | Natural Gas | $ | — |
| | $ | — |
| | $ | — |
| | $ | 4 |
| | $ | 4 |
| | $ | — |
| Natural Gas Liquids | — |
| | — |
| | — |
| | 4 |
| | 4 |
| | — |
| Condensate | — |
| | — |
| | — |
| | 1 |
| | 1 |
| | — |
| Embedded Derivatives in Series A Preferred Units | 16 |
| | — |
| | 16 |
| | 19 |
| | — |
| | 19 |
| Total Liabilities | $ | 16 |
| | $ | — |
| | $ | 16 |
| | $ | 28 |
| | $ | 9 |
| | $ | 19 |
|
The following table presents the material unobservable inputs used to estimate the fair value of the embedded derivatives in the Series A Preferred Units:
| | | | | Unobservable Input | | December 31, 2014 | Credit Spread | | 4.76 | % | Volatility | | 35.8 | % |
Changes in the Partnership’s cost of equity and U.S. Treasury yields would cause a change in the credit spread used to value the embedded derivatives.
The following table presents the changes in Level 3 derivatives measured on a recurring basis for the years ended December 31, 2014 and 2013. There were no transfers between Level 2 and Level 3 derivatives for the years ended December 31, 2014 and 2013.
| | | | | | Embedded Derivatives in Series A Preferred Units | Balance at January 1, 2013 | $ | 25 |
| Change in fair value, net of gain at conversion of $26 million | (6 | ) | Balance at December 31, 2013 | 19 |
| Change in fair value | (3 | ) | Balance at December 31, 2014 | $ | 16 |
|
The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximates fair value due to their short-term maturities. Long-term debt, other than the Senior Notes, is comprised of borrowings under which interest accrues under a floating interest rate structure. Accordingly, the carrying value approximates fair value.
The aggregate fair value and carrying amount of the Senior Notes at December 31, 2014 and 2013 was $5.1 billion and $2.8 billion, respectively. The fair value of the Senior Notes is a Level 1 valuation based on third party market value quotations.
11. LEASES
The following table is a schedule of future minimum lease payments for office space and certain equipment leased by the Partnership, that had initial or remaining non-cancelable lease terms in excess of one year as of December 31, 2014:
| | | | | | For the year ending December 31, | | Operating Lease | 2015 | | $ | 5 |
| 2016 | | 5 |
| 2017 | | 4 |
| 2018 | | 3 |
| 2019 | | 2 |
| Thereafter | | 26 |
| Total minimum lease payments | $ | 45 |
|
Total rent expense for operating leases, including those leases with terms of less than one year, was $20 million, $11 million and $11 million for the years ended December 31, 2014, 2013 and 2012, respectively.
12. COMMITMENTS AND CONTINGENCIES
Legal. The Partnership is involved in various claims, lawsuits and audits by taxing authorities incidental to its business. These claims and lawsuits in the aggregate are not expected to have a material adverse effect on the Partnership’s business, financial condition, results of operations or cash flows.
ETP Merger Shareholder Litigation.Following the January 26, 2015 announcement of the definitive merger agreement with ETP, purported Partnership unitholders filed lawsuits in state and federal courts in Dallas, Texas asserting claims relating to the proposed transaction.
On February 3, 2015, William Engel and Enno Seago, purported Partnership unitholders, filed a class action petition on behalf of the Partnership’s common unitholders and a derivative suit on behalf of the Partnership in the 162nd Judicial District Court of Dallas County, Texas (the “Engel Lawsuit”). The lawsuit names as defendants the General Partner, the members of the General Partner’s board of directors, ETP, ETP GP, ETE, and, as a nominal party, the Partnership. The Engel Lawsuit alleges that (1) the General Partner’s directors breached duties to the Partnership and the Partnership’s unitholders by employing a conflicted and unfair process and failing to maximize the merger consideration; (2) the General Partner’s directors breached the implied covenant of good faith and fair dealing by engaging in a flawed merger process; and (3) the non-director defendants aided and abetted in these claimed breaches. The plaintiffs seek an injunction preventing the defendants from closing the proposed transaction or an order rescinding the transaction if it has already been completed. The plaintiffs also seek money damages and court costs, including attorney’s fees.
On February 9, 2015, Stuart Yeager, a purported Partnership unitholder, filed a class action petition on behalf of the Partnership’s common unitholders and a derivative suit on behalf of the Partnership in the 134th Judicial District Court of Dallas County, Texas (the “Yeager Lawsuit”). The allegations, claims, and relief sought in the Yeager Lawsuit are nearly identical to those in the Engel Lawsuit.
On February 10, 2015, Lucien Coggia a purported Partnership unitholder, filed a class action petition on behalf of the Partnership’s common unitholders and a derivative suit on behalf of the Partnership in the 192nd Judicial District Court of Dallas County, Texas (the “Coggia Lawsuit”). The allegations, claims, and relief sought in the Coggia Lawsuit are nearly identical to those in the Engel Lawsuit.
On February 3, 2015, Linda Blankman, a purported Partnership unitholder, filed a class action complaint on behalf of the Partnership’s common unitholders in the United States District Court for the Northern District of Texas (the “Blankman Lawsuit”). The allegations and claims in the Blankman Lawsuit are similar to those in the Engel Lawsuit. However, the Blankman Lawsuit does not allege any derivative claims and includes the Partnership as a defendant rather than a nominal party. The lawsuit also omits one of the General Partner’s directors, Richard Brannon, who was named in the Engel Lawsuit. The Blankman Lawsuit alleges that the General Partner’s directors breached their fiduciary duties to the unitholders by failing to maximize the value of the Partnership, failing to properly value the Partnership, and ignoring conflicts of interest. The plaintiff also asserts a claim against the non-director defendants for aiding and abetting the directors’ alleged breach of fiduciary duty. The Blankman Lawsuit seeks the same relief that the plaintiffs seek in the Engel Lawsuit.
On February 6, 2015, Edwin Bazini, a purported Partnership unitholder, filed a class action complaint on behalf of the Partnership’s common unitholders in the United States District Court for the Northern District of Texas (the “Bazini Lawsuit”). The allegations, claims, and relief sought in the Bazini Lawsuit are nearly identical to those in the Blankman Lawsuit.
On February 11, 2015, Mark Hinnau, a purported Partnership unitholder, filed a class action complaint on behalf of the Partnership’s common unitholders in the United States District Court for the Northern District of Texas (the “Hinnau Lawsuit”). The allegations, claims, and relief sought in the Hinnau Lawsuit are nearly identical to those in the Blankman Lawsuit.
On February 11, 2015, Stephen Weaver, a purported Partnership unitholder, filed a class action complaint on behalf of the Partnership’s common unitholders in the United States District Court for the Northern District of Texas (the “Weaver Lawsuit”). The allegations, claims, and relief sought in the Weaver Lawsuit are nearly identical to those in the Blankman Lawsuit.
On February 11, 2015, Adrian Dieckman, a purported Partnership unitholder, filed a class action complaint on behalf of the Partnership’s common unitholders in the United States District Court for the Northern District of Texas (the “Dieckman Lawsuit”). The allegations, claims, and relief sought in the Dieckman Lawsuit are similar to those in the Blankman Lawsuit, except that the Dieckman Lawsuit does not assert an aiding and abetting claim.
On February 13, 2015, Irwin Berlin, a purported Partnership unitholder, filed a class action complaint on behalf of the Partnership’s common unitholders in the United States District Court for the Northern District of Texas (the “Dieckman Lawsuit”). The allegations, claims, and relief sought in the Berlin Lawsuit are similar to those in the Blankman Lawsuit.
Each of these lawsuits is at a preliminary stage. We cannot predict the outcome of these or any other lawsuits that might be filed, nor can we predict the amount of time and expense that will be required to resolve these lawsuits. The Partnership and the other defendants named in the lawsuits intend to defend vigorously against these and any other actions.
PVR Shareholder Litigation. Five putative class action lawsuits challenging the PVR Acquisition are currently pending. All of the cases name PVR, PVR GP and the then-incumbent directors of PVR GP, as well as the Partnership and the General Partner (collectively, the “Regency Defendants”), as defendants. Each of the lawsuits has been brought by a purported unitholder of PVR, both individually and on behalf of a putative class consisting of public unitholders of PVR. The lawsuits generally allege, among other things, that the directors of PVR GP breached their fiduciary duties to unitholders of PVR, that PVR GP, PVR and the Regency Defendants aided and abetted the directors of PVR GP in the alleged breach of these fiduciary duties, and, as to the actions in federal court, that some or all of PVR, PVR GP, and the directors of PVR GP violated Section 14(a) of the Exchange Act and Rule 14a-9 promulgated thereunder and Section 20(a) of the Exchange Act. The lawsuits purport to seek, in general, (i) injunctive relief, (ii) disclosure of certain additional information concerning the transaction, (iii) rescission or an award of rescissory damages, (iv) an award of plaintiffs’ costs and (v) the accounting for damages allegedly causes by the defendants to these actions, and, (vi) such further relief as the court deems just and proper. The styles of the pending cases are as follows: David Naiditch v. PVR Partners, L.P., et al. in the Court of Chancery of the State of Delaware); Charles Monatt v. PVR Partners, LP, et al. and Saul Srour v. PVR Partners, L.P., et al., each pending in the Court of Common Pleas for Delaware County, Pennsylvania; Stephen Bushansky v. PVR Partners, L.P., et al.; and Mark Hinnau v. PVR Partners, L.P., et al., pending in the United States District Court for the Eastern District of Pennsylvania.
On January 28, 2014, the defendants entered into a Memorandum of Understanding (“MOU”) with Monatt, Srour, Bushansky, Naiditch and Hinnau pursuant to which defendants and the referenced plaintiffs agreed in principle to a settlement of their lawsuits (“Settled Lawsuits”), which will be memorialized in a separate settlement agreement, subject to customary conditions, including consummation of the PVR Acquisition, which occurred on March 21, 2014, completion of certain confirmatory discovery (which was completed as of September 5, 2014), class certification and final approval by the Court of Common Pleas for Delaware County, Pennsylvania. If the Court approves the settlement, the Settled Lawsuits will be dismissed with prejudice and all defendants will be released from any and all claims relating to the Settled Lawsuits.
The settlement did not affect any provisions of the merger agreement or the form or amount of consideration received by PVR unitholders in the PVR Acquisition. The defendants have denied and continue to deny any wrongdoing or liability with respect to the plaintiffs’ claims in the aforementioned litigation and have entered into the settlement to eliminate the uncertainty, burden, risk, expense, and distraction of further litigation.
Eagle Rock Shareholder Litigation. Three putative class action lawsuits challenging the Eagle Rock Midstream Acquisition were previously filed in federal district court in Houston, Texas. All cases name Eagle Rock and its current directors, as well as the Partnership and a subsidiary, as defendants. One of the lawsuits also names additional Eagle Rock entities as defendants. Each of the lawsuits has been brought by a purported unitholder of Eagle Rock (collectively, the “Plaintiffs”), both individually and on behalf of a putative class consisting of public unitholders of Eagle Rock. The Plaintiffs in each case seek to rescind the transaction,
claiming, among other things, that it yields inadequate consideration, was tainted by conflict and constitutes breaches of common law fiduciary duties or contractually imposed duties to the shareholders. Plaintiffs also seek monetary damages and attorneys’ fees. The Partnership and its subsidiary are named as “aiders and abettors” of the allegedly wrongful actions of Eagle Rock and its board. In November 2014, the US District Court issued a Notice of Voluntary Dismissal without Prejudice of all claims in this matter.
PADEP Consent Assessment. On November 21, 2014, our subsidiary, Regency Marcellus Gas Gathering LLC (“Regency Marcellus”), received a Notice of Violation (“NOV”) from the Pennsylvania Department of Environmental Protection (“PADEP”) relating to unpermitted wetlands and streams along the second phase of construction of the Canton Pipeline Project with proposed civil penalties potentially in excess of $100,000. Regency Marcellus has submitted amended permit applications for this phase of construction and is working with the PADEP to acquire amended permits for the proposed crossings of the wetland resources. Regency Marcellus is in discussions with the PADEP regarding the aforementioned NOV. The timing or outcome of this matter cannot reasonably be determined at this time, however we do not expect there to be a material impact on our business or results of operations.
CDM Sales Tax Audit. CDM Resource Management LLC (“CDM”), a subsidiary of the Partnership, has historically claimed the manufacturing exemption from sales tax in Texas, as is common in the industry. The exemption is based on the fact that CDM’s natural gas compression equipment is used in the process of treating natural gas for ultimate use and sale. In a recent audit by the Texas Comptroller’s office, the Comptroller has challenged the applicability of the manufacturing exemption to CDM. The period being audited is from August 2006 to August 2007, and liability for that period is potentially covered by an indemnity obligation from CDM’s prior owners. CDM may also have liability for periods since 2008, and prospectively, if the Comptroller’s challenge is ultimately successful. An audit of the 2008 period has commenced. In April 2013, an independent audit review agreed with the Comptroller’s position. While CDM continues to disagree with this position and intends to seek redetermination and other relief, we are unable to predict the final outcome of this matter.
Environmental. The Partnership is responsible for environmental remediation at certain sites on its gathering and processing systems, resulting primarily from releases of hydrocarbons. The Partnership’s remediation program typically involves the management of contaminated soils and may involve remediation of groundwater. Activities vary with site conditions and locations, the extent and nature of the contamination, remedial requirements and complexity. The ultimate liability and total costs associated with these sites will depend upon many factors. In addition, the Partnership has reclamation and bonding requirements with respect to certain un-leased and inactive coal properties.
The table below reflects the undiscounted environmental liabilities recorded in the consolidated balance sheet at December 31, 2014 and 2013 where management believes a loss is probable and reasonably estimable. The Partnership does not have any material environmental remediation matters assessed as reasonably possible that would require disclosure in the financial statements.
| | | | | | | | | | December 31, | | 2014 | | 2013 | Current | $ | 2 |
| | $ | 2 |
| Noncurrent | 8 |
| | 6 |
| Total environmental liabilities | $ | 10 |
| | $ | 8 |
|
The Partnership made expenditures related to environmental remediation of $2 million for the year ended December 31, 2014.
Air Quality Control. The Partnership is currently negotiating settlements to certain enforcement actions by the NMED and the TCEQ. The TCEQ recently initiated a state-wide emissions inventory for the sulfur dioxide emissions from sites with reported emissions of 10 tons per year or more. If this data demonstrates that any source or group of sources may cause or contribute to a violation of the National Ambient Air Quality Standards, they must be sufficiently controlled to ensure timely attainment of the standard. This may potentially affect three recovery units in Texas. It is unclear at this time how the NMED will address the sulfur dioxide standard.
Compliance Orders from the NMED. The Partnership has been in discussions with the NMED concerning allegations of violations of New Mexico air regulations related to the Jal #3 and Jal #4 facilities. Hearings on the compliance orders were delayed until May 2015 to allow the parties to pursue substantive settlement discussions. The Partnership has meritorious defenses to the NMED claims and can offer significant mitigating factors to the claimed violations. The Partnership has recorded a liability of less than $1 million related to the claims and will continue to assess its potential exposure to the allegations as the matters progress.
Mine Health and Safety Laws. There are numerous mine health and safety laws and regulations applicable to the coal mining industry. However, since the Partnership does not operate any mines and does not employ any coal miners, it is not subject to such laws and regulations. Accordingly, the Partnership has not accrued any related liabilities.
In addition to the matters discussed above, the Partnership is involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business.
13. SERIES A PREFERRED UNITS
On September 2, 2009, the Partnership issued 4,371,586 Series A Preferred Units for net proceeds of $79 million, inclusive of the General Partner’s contribution of $2 million.
Holders may elect to convert Series A Preferred Units to common units at any time. In July 2013, certain holders of Series A Preferred Units exercised their right to convert 2,459,017 Series A Preferred Units into common units. Concurrent with this transaction, the Partnership recognized a $26 million gain in other income and deductions, net, related to the embedded derivative and reclassified $41 million from the Series A Preferred Units into common units. As of December 31, 2014, the remaining Series A Preferred Units were convertible into 2,064,805 common units, and if outstanding, are mandatorily redeemable on September 2, 2029 for $35 million plus all accrued but unpaid distributions and interest thereon (the “Series A Liquidation Value”). The Series A Preferred Units receive fixed quarterly cash distributions of $0.445 per unit if outstanding on the record dates of the Partnership’s common unit distributions.
Distributions on the Series A Preferred Units were accrued for the first two quarters (and not paid in cash) and will result in an increase in the number of common units issuable upon conversion. If on any distribution payment date beginning March 31, 2010, the Partnership (1) fails to pay distributions on the Series A Preferred Units, (2) reduces the distributions on the common units to zero and (3) is prohibited by its material financing agreements from paying cash distributions, such distributions shall automatically accrue and accumulate until paid in cash. If the Partnership has failed to pay cash distributions in full for two quarters (whether or not consecutive) from and including the quarter ended on March 31, 2010, then if the Partnership fails to pay cash distributions on the Series A Preferred Units, all future distributions on the Series A Preferred Units that are accrued rather than being paid in cash by the Partnership will consist of the following: (1) $0.35375 per Series A Preferred Unit per quarter, (2) $0.09125 per Series A Preferred Unit per quarter (the “Common Unit Distribution Amount”), payable solely in common units, and (3) $0.09125 per Series A Preferred Unit per quarter (the “PIK Distribution Additional Amount”), payable solely in common units. The total number of common units payable in connection with the Common Unit Distribution Amount or the PIK Distribution Additional Amount cannot exceed $2 million in any period of 20 consecutive fiscal quarters.
Upon the Partnership’s breach of certain covenants (a “Covenant Default”), the holders of the Series A Preferred Units will be entitled to an increase of $0.1825 per quarterly distribution, payable solely in common units (the “Covenant Default Additional Amount”). All accumulated and unpaid distributions will accrue interest (i) at a rate of 2.432% per quarter, or (ii) if the Partnership has failed to pay all PIK Distribution Additional Amounts or Covenant Default Additional Amounts or any Covenant Default has occurred and is continuing, at a rate of 3.429% per quarter while such failure to pay or such Covenant Default continues.
The Series A Preferred Units are convertible, at the holder’s option, into common units, provided that the holder must request conversion of at least 375,000 Series A Preferred Units. The conversion price will initially be $18.30, subject to adjustment for customary events (such as unit splits). The number of common units issuable is equal to the issue price of the Series A Preferred Units (i.e. $18.30) being converted plus all accrued but unpaid distributions and accrued but unpaid interest thereon (the “Redeemable Face Amount”), divided by the applicable conversion price.
If at any time the volume-weighted average trading price of the common units over the trailing 20-trading day period (the “VWAP Price”) is less than the then-applicable conversion price, the conversion ratio is increased to: the quotient of (1) the Redeemable Face Amount on the date that the holder’s conversion notice is delivered, divided by (2) the product of (x) the VWAP Price set forth in the applicable conversion notice and (y) 91%, but will not be less than $10.
The Partnership has the right at any time to convert all or part of the Series A Preferred Units into common units, if (1) the daily volume-weighted average trading price of the common units is greater than 150% of the then-applicable conversion price for 20 out of the trailing 30 trading days, and (2) certain minimum public float and trading volume requirements are satisfied.
In the event of a change of control, the Partnership will be required to make an offer to the holders of the Series A Preferred Units to purchase their Series A Preferred Units for an amount equal to 101% of their Series A Liquidation Value. In addition, in the event of certain business combinations or other transactions involving the Partnership in which the holders of common units receive cash consideration exclusively in exchange for their common units (a “Cash Event”), the Partnership must use commercially reasonable efforts to ensure that the holders of the Series A Preferred Units will be entitled to receive a security issued by the surviving entity in the Cash Event with comparable powers, preferences and rights to the Series A Preferred Units. If the Partnership
is unable to ensure that the holders of the Series A Preferred Units will be entitled to receive such a security, then the Partnership will be required to make an offer to the holders of the Series A Preferred Units to purchase their Series A Preferred Units for an amount equal to 120% of their Series A Liquidation Value. If the Partnership enters into any recapitalization, reorganization, consolidation, merger, spin-off that is not a Cash Event, the Partnership will make appropriate provisions to ensure that the holders of the Series A Preferred Units receive a security with comparable powers, preferences and rights to the Series A Preferred Units upon consummation of such transaction. Subsequent to the ETE Acquisition, no unitholder exercised this option.
As of December 31, 2014, the Series A Preferred Units were convertible to 2,064,805 common units.
The following table provides a reconciliation of the beginning and ending balances of the Series A Preferred Units for the years ended December 31, 2014 and 2013:
| | | | | | | | | | Units | | Amount | | Balance at January 1, 2013 | 4,371,586 |
| | $ | 73 |
| | Series A Preferred Units converted to common units | (2,459,017 | ) | | (41 | ) | | Balance at January 1, 2014 | 1,912,569 |
| | 32 |
| | Accretion to redemption value | N/A |
| | 1 |
| | Balance at December 31, 2014 | 1,912,569 |
| | $ | 33 |
| * |
* This amount will be accreted to $35 million plus any accrued but unpaid distributions and interest by deducting amounts from
partners’ capital over the remaining periods until the mandatory redemption date of September 2, 2029. Accretion during 2013
was immaterial.
14. RELATED PARTY TRANSACTIONS
As of December 31, 2014 and 2013, details of the Partnership’s related party receivables and related party payables were as follows:
| | | | | | | | | | December 31, | | 2014 | | 2013 | Related party receivables | | | | ETE and its subsidiaries | 43 |
| | 25 |
| HPC | 1 |
| | 1 |
| Ranch JV | 1 |
| | 2 |
| Total related party receivables | $ | 45 |
| | $ | 28 |
| | | | | Related party payables | | | | ETE and its subsidiaries | 50 |
| | 68 |
| HPC | 3 |
| | 1 |
| Mi Vida JV | 11 |
| | — |
| Total related party payables | $ | 64 |
| | $ | 69 |
|
Transactions with ETE and its subsidiaries.Under the service agreement with Services Co., the Partnership paid Services Co.’s direct expenses for services performed, plus an annual fee of $10 million, and received the benefit of any cost savings recognized for these services. The services agreement has a five year term ending May 26, 2015, subject to earlier termination rights in the event of a change in control, the failure to achieve certain cost savings for the Partnership or upon an event of default. On April 30, 2013, this agreement was amended to provide for a waiver of the $10 million annual fee effective as of May 1, 2013 through and including April 30, 2015 and to clarify the scope and expenses chargeable as direct expenses thereunder.
On April 30, 2013, the Partnership entered into the second amendment (the “Operation and Service Amendment”) to the Operation and Service Agreement (the “Operation and Service Agreement”), by and among the Partnership, ETC, the General Partner and RGS. Under the Operation and Service Agreement, ETC performs certain operations, maintenance and related services reasonably required to operate and maintain certain facilities owned by the Partnership, and the Partnership reimburses ETC for actual costs and expenses incurred in connection with the provision of these services based on an annual budget agreed upon by both parties.
The Partnership incurred total service fees related to the agreements described above from ETE and its subsidiaries of $6 million, $11 million and $17 million for the years ended December 31, 2014, 2013 and 2012, respectively.
In conjunction with distributions made by the Partnership to the limited and general partner interests, ETE and its subsidiaries received cash distributions of $175 million, $107 million and $62 million for the years ended December 31, 2014, 2013 and 2012, respectively.
The General Partner has the right, but not the obligation, to contribute a proportionate amount of capital to the Partnership to maintain its general partner interest. No capital contributions were contributed during the years ended December 31, 2014 and 2013.
The Partnership’s Gathering and Processing segment, in the ordinary course of business, sells natural gas and NGLs to subsidiaries of ETE and records the revenue in gas sales and NGL sales. The Partnership’s Contract Services segment provides contract compression services to a subsidiary of ETE and records revenue in gathering, transportation and other fees on the statement of operations. As these transactions are between entities under common control, partners’ capital was increased, which represented a deemed contribution of the excess sales price over the carrying amounts. The Partnership’s Gathering and Processing segment recorded revenues from subsidiaries of ETE of $351 million and cost of sales to subsidiaries of ETE of $52 million for the year ended December 31, 2014. The Partnership’s Contract Services segment recorded revenues from a subsidiary of ETE of $1 million for the year ended December 31, 2014. The Partnership’s Contract Services segment purchased $67 million and $95 million of compression equipment from a subsidiary of ETE during the years ended December 31, 2014 and 2013, respectively.
Prior to April 30, 2013, Southern Union provided certain administrative services for SUGS that were either based on SUGS’s pro-rata share of combined net investment, margin and certain expenses or direct costs incurred by Southern Union on the behalf of SUGS. Southern Union also charged a management and royalty fee to SUGS for certain management support services provided by Southern Union on the behalf of SUGS and for the use of certain Southern Union trademarks, trade names and service marks by SUGS. The amounts were $21 million and $1 million for the period from March 26, 2012 to December 31, 2012. These administrative services were no longer being provided subsequent to the SUGS Acquisition.
Transactions with Lone Star. The Partnership entered into various agreements to sell NGLs to Lone Star. For the year ended December 31, 2014, the Partnership had recorded $257 million in NGL sales under these contracts.
Transactions with HPC. Under a Master Services Agreement with HPC, the Partnership operates and provides all employees and services for the operation and management of HPC. For the years ended December 31, 2014, 2013, and 2012, the related party general and administrative expenses reimbursed to the Partnership were $14 million, $18 million, and $20 million, respectively, which is recorded in gathering, transportation and other fees.
The Partnership’s Contract Services segment provides compression services to HPC and records revenue in gathering, transportation and other fees. The Partnership also receives transportation services from HPC and records it as cost of sales.
15. CONCENTRATION RISK
The following table provides information about the extent of reliance on major customers and gas suppliers. Total revenues and cost of sales from transactions with an external customer or supplier amounting to 10% or more of revenue or cost of gas and liquids are disclosed below, together with the identity of the reportable segment.
| | | | | | | | | | | | | | | | | | Years Ended December 31, | | Reportable Segment | | 2014 | | 2013 | | 2012 | Customer | | | | | | | | Customer A | Gathering and Processing | | $ | — |
| | $ | 381 |
| | $ | 367 |
| Customer B | Gathering and Processing | | 780 |
| | 362 |
| | 451 |
| Supplier | | | | | | | | Supplier A | Gathering and Processing | | — |
| | 164 |
| | 171 |
| Supplier B | Gathering and Processing | | — |
| | 185 |
| | — |
|
The Partnership is a party to various commercial netting agreements that allow it and contractual counterparties to net receivable and payable obligations. These agreements are customary and the terms follow standard industry practice. In the opinion of management, these agreements reduce the overall counterparty risk exposure.
16. SEGMENT INFORMATION
The Partnership has six reportable segments: Gathering and Processing, Natural Gas Transportation, NGL Services, Contract Services, Natural Resources and Corporate. The reportable segments are as described below:
Gathering and Processing. The Partnership provides “wellhead-to-market” services to producers of natural gas, which include transporting raw natural gas from the wellhead through gathering systems, processing raw natural gas to separate NGLs from the raw natural gas and selling or delivering pipeline-quality natural gas and NGLs to various markets and pipeline systems, the gathering of oil (crude and/or condensate, a lighter oil) received from producers, the gathering and disposing of salt water, and natural gas and NGL marketing and trading. This segment also includes the Partnership’s 60% membership interest in ELG, which operates natural gas gathering, oil pipeline, and oil stabilization facilities in south Texas, the Partnership’s 33.33% membership interest in Ranch JV, which processes natural gas delivered from NGL-rich shale formations in west Texas, the Partnership’s 50% interest in Sweeny JV, which operates a natural gas gathering facility in south Texas, the Partnership’s 51% membership interest in Aqua - PVR, which transports and supplies fresh water to natural gas producers in the Marcellus shale in Pennsylvania, the Partnership’s 75% membership interest in ORS, which will operate a natural gas gathering system in the Utica shale in Ohio, and the Partnership’s 50% interest in Mi Vida JV, which will operate a cryogenic processing plant and related facilities in west Texas.
Natural Gas Transportation. The Partnership owns a 49.99% general partner interest in HPC, which owns RIGS, a 450-mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets, and a 50% membership interest in MEP, which owns a 500-mile interstate natural gas pipeline stretching from southeast Oklahoma through northeast Texas, northern Louisiana and central Mississippi to an interconnect with the Transcontinental Gas Pipe Line system in Butler, Alabama. This segment also includes Gulf States, which owns a 10-mile interstate pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana.
NGL Services. The Partnership owns a 30% membership interest in Lone Star, an entity owning a diverse set of midstream energy assets including NGL pipelines, storage, fractionation and processing facilities located in Texas, New Mexico, Mississippi and Louisiana.
Contract Services. The Partnership owns and operates a fleet of compressors used to provide turn-key natural gas compression services for customer specific systems. The Partnership also owns and operates a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management.
Natural Resources. The Partnership is involved in the management of coal and natural resources properties and the related collection of royalties. The Partnership also earns revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities, and collecting oil and gas royalties. This segment also included the Partnership’s 50%interest in Coal Handling, which owns and operates end-user coal handling facilities. The Partnership purchased the remaining 50% interest in these companies effective December 31, 2014.
Corporate. The Corporate segment comprises the Partnership’s corporate assets.
The Partnership accounts for intersegment revenues as if the revenues were to third parties, exclusive of certain cost of capital charges.
Management evaluates the performance of each segment and makes capital allocation decisions through the separate consideration of segment margin and operation and maintenance expenses. Segment margin, for the Gathering and Processing and the Natural Gas Transportation segments is defined as total revenues, including service fees, less cost of sales. In the Contract Services segment, segment margin is defined as revenues less direct costs. The Natural Resources segment margin is generally equal to total revenues
as there is typically minimal cost of sales associated with the management and leasing of properties.
Management believes segment margin is an important measure because it directly relates to volume, commodity price changes, and revenue generating horsepower. Operation and maintenance expenses are a separate measure used by management to evaluate performance of field operations. Direct labor, insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of operation and maintenance expenses. These expenses fluctuate depending on the activities performed during a specific period. The Partnership does not deduct operation and maintenance expenses from total revenues in calculating segment margin because management separately evaluates commodity volume and price changes in segment margin. The Partnership does not record segment margin for its investments in unconsolidated affiliates (HPC, MEP, Lone Star, Ranch JV, Aqua - PVR, Mi Vida JV and Sweeny JV) because it records its ownership percentages of their net income as income from unconsolidated affiliates in accordance with the equity method of accounting.
Results for each period, together with amounts related to each segment are shown below:
| | | | | | | | | | | | | | Years Ended December 31, | | 2014 | | 2013 | | 2012 | External Revenue | | | | | | Gathering and Processing | $ | 4,570 |
| | $ | 2,287 |
| | $ | 1,797 |
| Natural Gas Transportation | — |
| | 1 |
| | 1 |
| NGL Services | — |
| | — |
| | — |
| Contract Services | 307 |
| | 215 |
| | 183 |
| Natural Resources | 58 |
| | — |
| | — |
| Corporate | 16 |
| | 18 |
| | 19 |
| Eliminations | — |
| | — |
| | — |
| Total | $ | 4,951 |
| | $ | 2,521 |
| | $ | 2,000 |
| | | | | | | Intersegment Revenue | | | | | | Gathering and Processing | $ | — |
| | $ | — |
| | $ | — |
| Natural Gas Transportation | — |
| | — |
| | — |
| NGL Services | — |
| | — |
| | — |
| Contract Services | 14 |
| | 15 |
| | 21 |
| Natural Resources | — |
| | — |
| | — |
| Corporate | — |
| | — |
| | — |
| Eliminations | (14 | ) | | (15 | ) | | (21 | ) | Total | $ | — |
| | $ | — |
| | $ | — |
| | | | | | | Cost of Sales | | | | | | Gathering and Processing | $ | 3,381 |
| | $ | 1,767 |
| | $ | 1,373 |
| Natural Gas Transportation | — |
| | — |
| | (1 | ) | NGL Services | — |
| | — |
| | — |
| Contract Services | 67 |
| | 26 |
| | 15 |
| Natural Resources | — |
| | — |
| | — |
| Corporate | 4 |
| | — |
| | — |
| Eliminations | — |
| | — |
| | — |
| Total | $ | 3,452 |
| | $ | 1,793 |
| | $ | 1,387 |
| | | | | | | Segment Margin | | | | | | Gathering and Processing | $ | 1,189 |
| | $ | 520 |
| | $ | 423 |
| Natural Gas Transportation | — |
| | 1 |
| | 2 |
| NGL Services | — |
| | — |
| | — |
| Contract Services | 254 |
| | 204 |
| | 189 |
| Natural Resources | 58 |
| | — |
| | — |
| Corporate | 12 |
| | 18 |
| | 20 |
| Eliminations | (14 | ) | | (15 | ) | | (21 | ) | Total | $ | 1,499 |
| | $ | 728 |
|
| $ | 613 |
| | | | | | |
| | | | | | | | | | | | | | Years Ended December 31, | | 2014 | | 2013 | | 2012 | Operation and Maintenance | | | | | | Gathering and Processing | $ | 360 |
| | $ | 237 |
| | $ | 183 |
| Natural Gas Transportation | — |
| | — |
| | — |
| NGL Services | — |
| | — |
| | — |
| Contract Services | 86 |
| | 72 |
| | 66 |
| Natural Resources | 12 |
| | — |
| | — |
| Corporate | 3 |
| | 1 |
| | — |
| Eliminations | (13 | ) | | (14 | ) | | (21 | ) | Total | $ | 448 |
| | $ | 296 |
| | $ | 228 |
| | | | | | | Depreciation, Depletion and Amortization | | | | | | Gathering and Processing | $ | 385 |
| | $ | 186 |
| | $ | 159 |
| Natural Gas Transportation | — |
| | — |
| | — |
| NGL Services | — |
| | — |
| | — |
| Contract Services | 134 |
| | 98 |
| | 86 |
| Natural Resources | 14 |
| | — |
| | — |
| Corporate | 8 |
| | 3 |
| | 7 |
| Eliminations | — |
| | — |
| | — |
| Total | $ | 541 |
| | $ | 287 |
| | $ | 252 |
|
| | | | | | | | | | | | | Income from Unconsolidated Affiliates | | | | | | Gathering and Processing | $ | 5 |
| | $ | 1 |
| | $ | (10 | ) | Natural Gas Transportation | 72 |
| | 70 |
| | 71 |
| NGL Services | 116 |
| | 64 |
| | 44 |
| Contract Services | — |
| | — |
| | — |
| Natural Resources | 2 |
| | — |
| | — |
| Corporate | — |
| | — |
| | — |
| Eliminations | — |
| | — |
| | — |
| Total | $ | 195 |
| | $ | 135 |
| | $ | 105 |
| | | | | | | Expenditures for Long-Lived Assets | | | | | | Gathering and Processing | $ | 700 |
| | $ | 721 |
| | $ | 395 |
| Natural Gas Transportation | — |
| | — |
| | — |
| NGL Services | — |
| | — |
| | — |
| Contract Services | 371 |
| | 311 |
| | 164 |
| Natural Resources | — |
| | — |
| | — |
| Corporate | 17 |
| | 2 |
| | 1 |
| Eliminations | — |
| | — |
| | — |
| Total | $ | 1,088 |
| | $ | 1,034 |
| | $ | 560 |
|
| | | | | | | | | | | | | | December 31, | | 2014 | | 2013 | | 2012 | Assets | | | | | | Gathering and Processing | $ | 12,069 |
| | $ | 4,748 |
| | $ | 4,210 |
| Natural Gas Transportation | 1,119 |
| | 991 |
| | 1,232 |
| NGL Services | 1,162 |
| | 1,070 |
| | 948 |
| Contract Services | 2,035 |
| | 1,897 |
| | 1,672 |
| Natural Resources | 529 |
| | — |
| | — |
| Corporate | 189 |
| | 76 |
| | 61 |
| Eliminations | — |
| | — |
| | — |
| Total | $ | 17,103 |
| | $ | 8,782 |
| | $ | 8,123 |
| | | | | | | Investments in Unconsolidated Affiliates | | | | | | Gathering and Processing | $ | 139 |
| | $ | 36 |
| | $ | 35 |
| Natural Gas Transportation | 1,117 |
| | 991 |
| | 1,231 |
| NGL Services | 1,162 |
| | 1,070 |
| | 948 |
| Contract Services | — |
| | — |
| | — |
| Natural Resources | — |
| | — |
| | — |
| Corporate | — |
| | — |
| | — |
| Eliminations | — |
| | — |
| | — |
| Total | $ | 2,418 |
| | $ | 2,097 |
| | $ | 2,214 |
| | | | | | | Goodwill | | | | | | Gathering and Processing (1) | $ | 732 |
| | $ | 651 |
| | $ | 651 |
| Natural Gas Transportation | — |
| | — |
| | — |
| NGL Services | — |
| | — |
| | — |
| Contract Services | 476 |
| | 477 |
| | 477 |
| Natural Resources | 15 |
| | — |
| | — |
| Corporate | — |
| | — |
| | — |
| Eliminations | — |
| | — |
| | — |
| Total | $ | 1,223 |
| | $ | 1,128 |
| | $ | 1,128 |
|
(1) In 2014, the Partnership recorded a $370 million impairment charge at the Permian reporting unit within this segment.
The table below provides a reconciliation of total segment margin to (loss) income before income taxes:
| | | | | | | | | | | | | | | Years Ended December 31, | | 2014 | | 2013 | | 2012 | | Total segment margin | $ | 1,499 |
| | $ | 728 |
| | $ | 613 |
| | Operation and maintenance | (448 | ) | | (296 | ) | | (228 | ) | | General and administrative | (158 | ) | | (88 | ) | | (100 | ) | | Gain (loss) on assets sales, net | 1 |
| | (2 | ) | | (3 | ) | | Depreciation, depletion and amortization | (541 | ) | | (287 | ) | | (252 | ) | | Goodwill impairment | (370 | ) | | — |
| | — |
| | Income from unconsolidated affiliates | 195 |
| | 135 |
| | 105 |
| | Interest expense, net | (304 | ) | | (164 | ) | | (122 | ) | | Loss on debt refinancing, net | (25 | ) | | (7 | ) | | (8 | ) | | Other income and deductions, net | 12 |
| | 7 |
| | 29 |
| * | (Loss) income before income taxes | $ | (139 | ) | | $ | 26 |
| | $ | 34 |
| |
__________________
| | * | Other income and deductions, net for the year ended December 31, 2012, included a one-time producer payment of $16 million related to an assignment of certain contracts.
|
17. EQUITY-BASED COMPENSATION
In December 2011, the Partnership’s unitholders approved the Regency Energy Partners LP 2011 Long-Term Incentive Plan (the “2011 Incentive Plan”), which provides for awards of options to purchase the Partnership’s common units; awards of the Partnership’s restricted units, phantom units and common units; awards of distribution equivalent rights; awards of common unit appreciation rights; and other unit-based awards to employees, directors and consultants of the Partnership and its affiliates and subsidiaries. The 2011 Incentive Plan will be administered by the Compensation Committee of the board of directors, which may, in its sole discretion, delegate its powers and duties under the 2011 Incentive Plan to the Chief Executive Officer. Up to 3,000,000 of the Partnership’s common units may be granted as awards under the 2011 Incentive Plan, with such amount subject to adjustment as provided for under the terms of the 2011 Incentive Plan.
The 2011 Incentive Plan may be amended or terminated at any time by the board of directors or the Compensation Committee without the consent of any participant or unitholder, including an amendment to increase the number of common units available for awards under the plan; however, any material amendment, such as a change in the types of awards available under the plan, would require the approval of the unitholders of the Partnership. The Compensation Committee is also authorized to make adjustments in the terms and conditions of, and the criteria included in awards under the 2011 Incentive Plan in specified circumstances. The 2011 Incentive Plan is effective until December 19, 2021 or, if earlier, the time at which all available units under the 2011 Incentive Plan have been issued to participants or the time of termination of the plan by the board of directors.
Unit-based compensation expense of $10 million, $7 million, and $5 million is recorded in general and administrative expense in the statement of operations for the years ended December 31, 2014, 2013 and 2012, respectively.
Common Unit Options. The fair value of each option award is estimated on the date of grant using the Black-Scholes Option Pricing Model. Upon the exercise of the common unit options, the Partnership intends to settle these obligations with new issues of common units on a net basis. The common unit options activity for the year ended December 31, 2014 is as follows:
| | | | | | | | | Common Unit Options | | Units | | Weighted Average Exercise Price | Outstanding at the beginning of period | | 142,550 |
| | $ | 22.04 |
| Exercised | | (34,900 | ) | | 20.03 |
| Outstanding at end of period | | 107,650 |
| | 22.68 |
| Exercisable at the end of the period | | 107,650 |
| | |
The common unit options have an intrinsic value of less than $1 million related to non-vested units with a weighted average contractual term of 1.5 years. Intrinsic value is the closing market price of a common unit less the option strike price, multiplied by the number of unit options outstanding as of the end of the period presented. Unit options with an exercise price greater than the end of the period closing market price are excluded.
Phantom Units. During 2014, the Partnership awarded 1,450,230 phantom units to senior management and certain key employees. These awards are service condition (time-based) grants that vest 60% after the third year of continued employment and 40% after the fifth year of continued employment. Distributions on the phantom units will be paid concurrent with the Partnership’s distribution for common units.
During 2013, the Partnership awarded 62,360 phantom units to senior management and certain key employees. These awards are service condition (time-based) grants that generally vest 60% after the third year of continued employment and 40% after the fifth year of continued employment. Distributions on the phantom units will be paid concurrent with the Partnership’s distribution for common units.
In December 2012, the Partnership awarded 495,375 phantom units to senior management and certain key employees. These awards are service condition (time-based) grants that vest 60% after the third year of continued employment and 40% after the fifth year of continued employment. Also during 2012, 8,250 phantom units were awarded to senior management and key employees as service condition (time-based) grants that generally vest ratably over a 5 year period. Distributions on the phantom units will be paid concurrent with the Partnership’s distribution for common units.
The following table presents phantom unit activity for the year ended December 31, 2014:
| | | | | | | | | Phantom Units | | Units | | Weighted Average Grant Date Fair Value | Outstanding at the beginning of the period | | 982,242 |
| | $ | 23.16 |
| Service condition grants | | 1,450,230 |
| | 25.24 |
| Vested service condition | | (183,380 | ) | | 25.25 |
| Forfeited service condition | | (81,373 | ) | | 24.83 |
| Total outstanding at end of period | | 2,167,719 |
| | 24.31 |
|
During the years ended December 31, 2014, 2013 and 2012, the weighted average grant date fair value per phantom unit granted was $25.24, $25.44, and $21.39, respectively. The total fair value of awards vested was $5 million, $6 million, and $5 million for the years ended December 31, 2014, 2013 and 2012, respectively, based on the market price of Regency common units as of the vesting date.
The Partnership expects to recognize $42 million of unit-based compensation expense related to non-vested phantom units over a period of 3.9 years.
Cash Restricted Units. The Partnership began granting cash restricted units in 2014. These awards are service condition (time-based) grants of notional units that vest 100% after the third year of continued employment. A cash restricted unit entitles the award recipient to receive cash equal to the market price of one Regency common unit as of the vesting date.
The following table presents cash restricted unit activity for the year ended December 31, 2014:
| | | | | Cash Restricted Units | | Units | Outstanding at the beginning of the period | | — |
| Service condition grants | | 400,928 |
| Vested service condition | | (500 | ) | Forfeited service condition | | (21,100 | ) | Total outstanding at end of period | | 379,328 |
|
Based on the trading price of Regency common units at December 31, 2014, the Partnership expects to recognize $7 million of unit-based compensation expense related to non-vested cash restricted units over a period of 2.5 years.
18. CONSOLIDATING GUARANTOR FINANCIAL INFORMATION
ELG, Aqua - PVR, and ORS do not fully and unconditionally guarantee, on a joint and several basis, the Senior Notes issued and outstanding as of December 31, 2014, by the Partnership and Finance Corp. Included in the Parent financial statements are the Partnership’s intercompany investments in all consolidated subsidiaries and the Partnership’s investments in unconsolidated affiliates. ELG, Aqua - PVR, and ORS are included in the non-guarantor subsidiaries.
The consolidating financial information for the Parent Guarantor, Subsidiaries,Subsidiary Issuer and Non GuarantorNon-Guarantor Subsidiaries are as follows: | | | | | | | | | | | | | | | | | | | | | | December 31, 2014 | | Parent | | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | Eliminations | | Consolidated Partnership | ASSETS | | | | | | | | | | Cash | $ | — |
| | $ | — |
| | $ | 32 |
| | $ | (8 | ) | | $ | 24 |
| All other current assets | — |
| | 667 |
| | 13 |
| | (1 | ) | | 679 |
| Property, plant, and equipment, net | — |
| | 8,948 |
| | 353 |
| | (84 | ) | | 9,217 |
| Investments in subsidiaries | 19,829 |
| | — |
| | — |
| | (19,829 | ) | | — |
| Investments in unconsolidated affiliates | — |
| | 2,252 |
| | — |
| | 166 |
| | 2,418 |
| All other assets | — |
| | 4,765 |
| | — |
| | — |
| | 4,765 |
| TOTAL ASSETS | $ | 19,829 |
| | $ | 16,632 |
| | $ | 398 |
| | $ | (19,756 | ) | | $ | 17,103 |
| | | | | | | | | | | LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST | | | | | | | | | | All other current liabilities | — |
| | 723 |
| | 34 |
| | (1 | ) | | 756 |
| Long-term liabilities | 5,185 |
| | 1,575 |
| | 6 |
| | (4 | ) | | 6,762 |
| Noncontrolling interest | — |
| | — |
| | — |
| | 120 |
| | 120 |
| Total partners’ capital and noncontrolling interest | 14,644 |
| | 14,334 |
| | 358 |
| | (19,871 | ) | | 9,465 |
| TOTAL LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST | $ | 19,829 |
| | $ | 16,632 |
| | $ | 398 |
| | $ | (19,756 | ) | | $ | 17,103 |
|
| | | | | | | | | | | | | | | | | | | | | | 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 |
|
| | | | | | | | | | | | | | | | | | | | | | December 31, 2013 | | Parent | | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | Eliminations | | Consolidated Partnership | ASSETS | | | | | | | | | | Cash | $ | — |
| | $ | — |
| | $ | 19 |
| | $ | — |
| | $ | 19 |
| All other current assets | — |
| | 366 |
| | 15 |
| | — |
| | 381 |
| Property, plant, and equipment, net | — |
| | 4,244 |
| | 174 |
| | — |
| | 4,418 |
| Investments in subsidiaries | 10,446 |
| | — |
| | — |
| | (10,446 | ) | | — |
| Investments in unconsolidated affiliates | — |
| | 1,995 |
| | — |
| | 102 |
| | 2,097 |
| All other assets | — |
| | 1,867 |
| | — |
| | — |
| | 1,867 |
| TOTAL ASSETS | $ | 10,446 |
| | $ | 8,472 |
| | $ | 208 |
| | $ | (10,344 | ) | | $ | 8,782 |
| | | | | | | | | | | LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST | | | | | | | | | | All other current liabilities | — |
| | 466 |
| | 9 |
| | — |
| | 475 |
| Long-term liabilities | 2,832 |
| | 559 |
| | — |
| | — |
| | 3,391 |
| Noncontrolling interest | — |
| | — |
| | — |
| | 102 |
| | 102 |
| Total partners’ capital and noncontrolling interest | 7,614 |
| | 7,447 |
| | 199 |
| | (10,446 | ) | | 4,814 |
| TOTAL LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST | $ | 10,446 |
| | $ | 8,472 |
| | $ | 208 |
| | $ | (10,344 | ) | | $ | 8,782 |
|
| | | | | | | | | | | | | | | | | | | | | | For the year ended December 31, 2014 | | Parent | | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | Eliminations | | Consolidated Partnership | Revenues | $ | — |
| | $ | 4,888 |
| | $ | 66 |
| | $ | (3 | ) | | $ | 4,951 |
| Operating costs, expenses, and other | — |
| | 4,942 |
| | 35 |
| | (9 | ) | | 4,968 |
| Operating (loss) income | — |
| | (54 | ) | | 31 |
| | 6 |
| | (17 | ) | Income from unconsolidated affiliates | — |
| | 195 |
| | — |
| | — |
| | 195 |
| Interest expense, net | (290 | ) | | (14 | ) | | — |
| | — |
| | (304 | ) | Loss on debt refinancing, net | (24 | ) | | (1 | ) | | — |
| | — |
| | (25 | ) | Equity in consolidated subsidiaries | 166 |
| | — |
| | — |
| | (166 | ) | | — |
| Other income and deductions, net | 3 |
| | 9 |
| | — |
| | — |
| | 12 |
| (Loss) income before income taxes | (145 | ) | | 135 |
| | 31 |
| | (160 | ) | | (139 | ) | Income tax expense (benefit) | 4 |
| | (2 | ) | | 1 |
| | — |
| | 3 |
| Net (loss) income | (149 | ) | | 137 |
| | 30 |
| | (160 | ) | | (142 | ) | Net income attributable to noncontrolling interest | — |
| | — |
| | — |
| | (15 | ) | | (15 | ) | Net (loss) income attributable to Regency Energy Partners LP | $ | (149 | ) | | $ | 137 |
| | $ | 30 |
| | $ | (175 | ) | | $ | (157 | ) | | | | | | | | | | | Total other comprehensive income | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| Comprehensive (loss) income | (149 | ) | | 137 |
| | 30 |
| | (160 | ) | | (142 | ) | Comprehensive income attributable to noncontrolling interest | — |
| | — |
| | — |
| | 15 |
| | 15 |
| Comprehensive (loss) income attributable to Regency Energy Partners LP | $ | (149 | ) | | $ | 137 |
| | $ | 30 |
| | $ | (175 | ) | | $ | (157 | ) |
| | | | | | | | | | | | | | | | | | | | | | For the year ended December 31, 2013 | | Parent | | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | Eliminations | | Consolidated Partnership | Revenues | $ | — |
| | $ | 2,489 |
| | $ | 32 |
| | $ | — |
| | $ | 2,521 |
| Operating costs, expenses, and other | 3 |
| | 2,448 |
| | 15 |
| | — |
| | 2,466 |
| Operating (loss) income | (3 | ) | | 41 |
| | 17 |
| | — |
| | 55 |
| Income from unconsolidated affiliates | — |
| | 135 |
| | — |
| | — |
| | 135 |
| Interest expense, net | (148 | ) | | (16 | ) | | — |
| | — |
| | (164 | ) | Loss on debt refinancing, net | (7 | ) | | — |
| | — |
| | — |
| | (7 | ) | Equity in consolidated subsidiaries | 172 |
| | — |
| | — |
| | (172 | ) | | — |
| Other income and deductions, net | 7 |
| | — |
| | — |
| | — |
| | 7 |
| Income before income taxes | 21 |
| | 160 |
| | 17 |
| | (172 | ) | | 26 |
| Income tax expense (benefit) | 1 |
| | (2 | ) | | — |
| | — |
| | (1 | ) | Net income | 20 |
| | 162 |
| | 17 |
| | (172 | ) | | 27 |
| Net income attributable to noncontrolling interest | — |
| | (8 | ) | | — |
| | — |
| | (8 | ) | Net income attributable to Regency Energy Partners LP | $ | 20 |
| | $ | 154 |
| | $ | 17 |
| | $ | (172 | ) | | $ | 19 |
| | | | | | | | | | | Total other comprehensive income | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| Comprehensive income | 20 |
| | 162 |
| | 17 |
| | (172 | ) | | 27 |
| Comprehensive income attributable to noncontrolling interest | — |
| | 8 |
| | — |
| | — |
| | 8 |
| Comprehensive income attributable to Regency Energy Partners LP | $ | 20 |
| | $ | 154 |
| | $ | 17 |
| | $ | (172 | ) | | $ | 19 |
|
| | | | | | | | | | | | | | | | | | | | | | For the year ended December 31, 2012 | | Parent | �� | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | Eliminations | | Consolidated Partnership | Revenues | $ | — |
| | $ | 1,985 |
| | $ | 15 |
| | $ | — |
| | $ | 2,000 |
| Operating costs, expenses, and other | 10 |
| | 1,951 |
| | 9 |
| | — |
| | 1,970 |
| Operating (loss) income | (10 | ) | | 34 |
| | 6 |
| | — |
| | 30 |
| Income from unconsolidated affiliates | — |
| | 105 |
| | — |
| | — |
| | 105 |
| Interest expense, net | (104 | ) | | (18 | ) | | — |
| | — |
| | (122 | ) | Gain (loss) on debt refinancing, net | (8 | ) | | — |
| | — |
| | — |
| | (8 | ) | Equity in consolidated subsidiaries | 141 |
| | — |
| | — |
| | (141 | ) | | — |
| Other income and deductions, net | 14 |
| | 15 |
| | — |
| | — |
| | 29 |
| Income before income taxes | 33 |
| | 136 |
| | 6 |
| | (141 | ) | | 34 |
| Income tax expense (benefit) | 1 |
| | (1 | ) | | — |
| | — |
| | — |
| Net income | 32 |
| | 137 |
| | 6 |
| | (141 | ) | | 34 |
| Net income attributable to noncontrolling interest | — |
| | (2 | ) | | — |
| | — |
| | (2 | ) | Net income attributable to Regency Energy Partners LP | $ | 32 |
| | $ | 135 |
| | $ | 6 |
| | $ | (141 | ) | | $ | 32 |
| | | | | | | | | | | Total other comprehensive income (loss) | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 2 |
| Comprehensive income | 32 |
| | 139 |
| | 6 |
| | (141 | ) | | 36 |
| Comprehensive income attributable to noncontrolling interest | — |
| | 2 |
| | — |
| | — |
| | 2 |
| Comprehensive income attributable to Regency Energy Partners LP | $ | 32 |
| | $ | 137 |
| | $ | 6 |
| | $ | (141 | ) | | $ | 34 |
|
| | | | | | | | | | | | | | | | | | | | | | 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 |
|
| | | | | | | | | | | | | | | | | | | | | | For the year ended December 31, 2014 | | Parent | | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | Eliminations | | Consolidated Partnership | Cash flows from operating activities | $ | — |
| | $ | 664 |
| | $ | 56 |
| | $ | (1 | ) | | $ | 719 |
| Cash flows from investing activities | — |
| | (2,130 | ) | | (30 | ) | | (9 | ) | | (2,169 | ) | Cash flows from financing activities | — |
| | 1,466 |
| | (13 | ) | | 2 |
| | 1,455 |
| Change in cash | — |
| | — |
| | 13 |
| | (8 | ) | | 5 |
| Cash at beginning of period | — |
| | — |
| | 19 |
| | — |
| | 19 |
| Cash at end of period | $ | — |
| | $ | — |
| | $ | 32 |
| | $ | (8 | ) | | $ | 24 |
|
| | | | | | | | | | | | | | | | | | | | | | 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 |
|
| | | | | | | | | | | | | | | | | | | | | | For the year ended December 31, 2013 | | Parent | | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | Eliminations | | Consolidated Partnership | Cash flows from operating activities | $ | — |
| | $ | 424 |
| | $ | 12 |
| | $ | — |
| | $ | 436 |
| Cash flows from investing activities | — |
| | (1,303 | ) | | (90 | ) | | — |
| | (1,393 | ) | Cash flows from financing activities | — |
| | 879 |
| | 44 |
| | — |
| | 923 |
| Change in cash | — |
| | — |
| | (34 | ) | | — |
| | (34 | ) | Cash at beginning of period | — |
| | — |
| | 53 |
| | — |
| | 53 |
| Cash at end of period | $ | — |
| | $ | — |
| | $ | 19 |
| | $ | — |
| | $ | 19 |
|
| | | | | | | | | | | | | | | | | | | | | | 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 |
|
| | | | | | | | | | | | | | | | | | | | | | For the year ended December 31, 2012 | | Parent | | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | Eliminations | | Consolidated Partnership | Cash flows from operating activities | $ | — |
| | $ | 316 |
| | $ | 8 |
| | $ | — |
| | $ | 324 |
| Cash flows from investing activities | — |
| | (746 | ) | | (61 | ) | | — |
| | (807 | ) | Cash flows from financing activities | — |
| | 430 |
| | 105 |
| | — |
| | 535 |
| Change in cash | — |
| | — |
| | 52 |
| | — |
| | 52 |
| Cash at beginning of period | — |
| | — |
| | 1 |
| | — |
| | 1 |
| Cash at end of period | $ | — |
| | $ | — |
| | $ | 53 |
| | $ | — |
| | $ | 53 |
|
19. QUARTERLY FINANCIAL DATA (UNAUDITED)
| | | | | | | | | | | | | | | | | | | | Quarter Ended | 2014 | | December 31 | | September 30 | | June 30 | | March 31 | Operating revenues | | $ | 1,427 |
| | $ | 1,483 |
| | $ | 1,178 |
| | $ | 863 |
| Operating (loss) income | | (218 | ) | | 144 |
| | 35 |
| | 22 |
| Net (loss) income attributable to Regency Energy Partners LP | | (261 | ) | | 103 |
| | (8 | ) | | 9 |
| Earnings per common units: | | | | | | | | | Basic net (loss) income per common unit | | (0.67 | ) | | 0.23 |
| | (0.05 | ) | | 0.00 |
| Diluted net (loss) income per common unit | | (0.67 | ) | | 0.23 |
| | (0.05 | ) | | 0.00 |
| | | | | | | | | | | | Quarter Ended | 2013 | | December 31 | | September 30 | | June 30 | | March 31 | Operating revenues | | $ | 677 |
| | $ | 665 |
| | $ | 639 |
| | $ | 540 |
| Operating income (loss) | | 12 |
| | 24 |
| | 34 |
| | (15 | ) | Net (loss) income attributable to Regency Energy Partners LP | | (1 | ) | | 39 |
| | 10 |
| | (29 | ) | Earnings per common units: | | | | | | | | | Basic net (loss) income per common unit | | (0.03 | ) | | 0.16 |
| | 0.07 |
| | (0.06 | ) | Diluted net (loss) income per common unit | | (0.03 | ) | | 0.05 |
| | 0.07 |
| | (0.06 | ) |
The three months ended December 31, 2014 includes a $370 million goodwill impairment charge recorded related to the Permian reporting unit within the Gathering and Processing segment.
|