The Parent Company’s outstanding senior notes are collateralized by its interests in certain of its subsidiaries. SEC Rule 3-16 of Regulation S-X (“Rule 3-16”) requires a registrant to file financial statements for each of its affiliates whose securities constitute a substantial portion of the collateral for registered securities. The Parent Company’s limited partner interests in ETP constitutes substantial portions of the collateral for the Parent Company’s outstanding senior notes; accordingly, financial statements of ETP are required under Rule 3-16 to be included in this Annual Report on Form 10-KIncludes minimum guaranteed payments under service concession arrangements with New Jersey Turnpike Authority and have been included herein.The Parent Company’s interests in ETP GP and ETE Common Holdings, LLC (collectively, the “Non-Reporting Entities”) also constitute substantial portions of the collateral for the Parent Company’s outstanding senior notes. Accordingly, the financial statements of the Non-Reporting Entities 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 has substantive operations of its own; rather, each of the Non-Reporting Entities holds only direct or indirect interests in ETP and/or the consolidated subsidiaries of ETP.
As further discussed in Note 6 to the consolidated financial statements, as referenced in (a) above, the financial statements of the Non-Reporting Entities would substantially duplicate information that is available in the financial statements of ETP. Therefore, the financial statements of the Non-Reporting Entities have been excluded from this Annual Report on Form 10-K.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| | | | | | | | ENERGY TRANSFER EQUITY, L.P. | | | | | | | By: | | LE GP, LLC, | | | | | its general partner | | | | | Date: | February 29, 2016 | By: | | /s/ Thomas E. Long | | | | | Thomas E. Long | | | | | Group Chief Financial Officer (duly
authorized to sign on behalf of the registrant)
|
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons in the capacities and on the dates indicated:
| | | | | | Signature | | Title | | Date | | | | | | /s/ John W. McReynolds | | Director and President | | February 29, 2016 | John W. McReynolds | | (Principal Executive Officer) | | | | | | | | /s/ Thomas E. Long | | Group Chief Financial Officer (Principal Financial and Accounting Officer) | | February 29, 2016 | Thomas E. Long | | | | | | | | | /s/ Kelcy L. Warren | | Director and Chairman of the Board | | February 29, 2016 | Kelcy L. Warren | | | | | | | | | | /s/ Marshall S. McCrea, III | | Director | | February 29, 2016 | Marshall S. McCrea, III | | | | | | | | | | /s/ Matthew S. Ramsey | | Director | | February 29, 2016 | Matthew S. Ramsey | | | | | | | | | | /s/ K. Rick Turner | | Director | | February 29, 2016 | K. Rick Turner | | | | | | | | | | /s/ William P. Williams | | Director | | February 29, 2016 | William P. Williams | | | | | | | | | | /s/ Ted Collins, Jr. | | Director | | February 29, 2016 | Ted Collins, Jr. | | | | |
INDEX TO EXHIBITS
The exhibits listed on the following Exhibit Index are filed as part of this report. Exhibits required by Item 601 of Regulation S-K, but which are not listed below, are not applicable.
| | | | Exhibit
Number
| | Description | | | Energy Transfer Equity, L.P. | 2.1 | | Redemption and Transfer Agreement, by and between Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. dated November 19, 2013 (incorporated by reference to Exhibit 2.1 of Form 8-K, File No. 1-32740, filed November 21, 2013) | 2.2 | | Exchange and Repurchase Agreement, by and among Energy Transfer Partners, L.P., Energy Transfer Equity, L.P. and ETE Common Holdings, LLC, dated December 23, 2014 (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed December 23, 2014) | 2.3 | | Agreement and Plan of Merger, dated as of September 28, 2015, among Energy Transfer Corp LP, ETE Corp GP, LLC, Energy Transfer Equity, L.P., LE GP, LLC, ETE GP, LLC and The Williams Companies, Inc. (incorporated by reference to Exhibit 2.1 of Form 8-K/A, File No. 1-32740, filed October 2, 2015) | | | | | | Energy Transfer Partners, L.P. | 2.4 | | Purchase and Sale Agreement, by and between Southern Union Company, as Seller, Plaza Missouri Acquisition, Inc. and for certain limited purposes The Laclede Group, Inc., as Buyers, dated as of December 14, 2012 (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-11727, filed December 17, 2012) | 2.5 | | Purchase and Sale Agreement, by and between Southern Union Company, as Seller, Plaza Massachusetts Acquisition, Inc. and for certain limited purposes The Laclede Group, Inc., as Buyers, dated as of December 14, 2012 (incorporated by reference to Exhibit 10.2 of Form 8-K, File No. 1-11727, filed December 17, 2012) | 2.6 | | Contribution Agreement, dated as of February 27, 2013, by and among Southern Union Company, Regency Energy Partners LP, Regency Western G&P LLC, and for certain limited purposes, ETP Holdco Corporation, Energy Transfer Equity, L.P., Energy Transfer Partners, L.P. and ETC Texas Pipeline, Ltd. (incorporated by reference to Exhibit 2.1 of Form 8-K, File No. 1-06407, filed February 28, 2013) | 2.7 | | Agreement and Plan of Merger, dated as of October 9, 2013, by and among Regency Energy Partners LP, RVP LLC, Regency GP LP, PVR Partners, L.P. and PVR GP, LLC (incorporated by reference to Exhibit 2.1 of Form 8-K, File No. 1-35262, filed October 10, 2013) | 2.8 | | Amendment No. 1 to Agreement and Plan of Merger, dated as of November 7, 2013, by and among Regency Energy Partners LP, RVP LLC, Regency GP LP, PVR Partners, L.P. and PVR GP, LLC (incorporated by reference to Exhibit 2.1 of Form 8-K, File No. 1-35262, filed November 8, 2013) | 2.9 | | Contribution Agreement, dated as of December 23, 2013, by and among Regency Energy Partners LP, Regal Midstream LLC, and Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 2.1 of Form 8-K, File No. 1-35262, filed December 24, 2013) | 2.10 | | Agreement and Plan of Merger, dated as of April 27, 2014, by and among, Energy Transfer Partners, L.P., Drive Acquisition Corporation, Heritage Holdings, Inc., Energy Transfer Partners GP, L.P., Susser Holdings Corporation, and, for certain limited purposes set forth therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.1 of Form 8-K, File No. 1-11727, filed April 28, 2014) | 2.11 | | Agreement and Plan of Merger, dated as of January 25, 2015, by and among Energy Transfer Partners, L.P., Energy Transfer Partners, GP, L.P., Regency Energy Partners LP, Regency GP LP and, solely for purposes of certain provisions therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.1 of Form 8-K, File No. 1-11727, filed January 26, 2015) | 2.12 | | Amendment No. 1 to Agreement and Plan of Merger, dated as of February 18, 2015, by and among Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., Rendezvous I LLC, Rendezvous II LLC, Regency Energy Partners LP, Regency GP LP, ETE GP Acquirer LLC and, solely for purposes of certain provisions therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.2 of Form 8-K, File No. 1-11727, filed February 19, 2015) | | | | | | Sunoco Logistics Partners L.P. | 2.13 | | Exchange Agreement, dated as of September 16, 2015, by and among Energy Transfer Partners, L.P., La Grange Acquisition, L.P., Sunoco Logistics Partners L.P., and Sunoco Pipeline L.P. (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-31219, filed October 15, 2015) | | | | | | Sunoco LP | 2.14 | | Contribution Agreement, dated as of September 25, 2014, by and among Mid-Atlantic Convenience Stores, LLC, ETC M-A Acquisition LLC, Susser Petroleum Partners LP and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 2.1 of Form 8-K, File No. 1-35653, filed October 1, 2014) |
| | | | Exhibit
Number
| | Description | 2.15 | | Contribution Agreement, dated as of March 23, 2015, by and among Sunoco, LLC, ETP Retail Holdings, LLC, Sunoco LP and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 2.1 of Form 8-K, File No. 1-35653, filed March 23, 2015) | 2.16 | | Contribution Agreement, dated as of July 14, 2015, by and among Susser Holdings Corporation, Heritage Holdings, Inc., ETP Holdco Corporation, Sunoco LP, Sunoco GP LLC and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 2.1 of Form 8-K, File No. 1-35653, filed July 15, 2015) | 2.17 | | Contribution Agreement, dated as of November 15, 2015, by and among Sunoco, LLC, Sunoco, Inc., ETP Retail Holdings, LLC, Sunoco LP, Sunoco GP LLC, and solely with respect to limited provisions therein, Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 2.1 of Form 8-K, File No. 1-35653, filed November 16, 2015) | | | | | | Energy Transfer Equity, L.P. | 3.1 | | Certificate of Limited Partnership of Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 3.2 of Form S-1, File No. 333-128097, filed September 2, 2005) | 3.2 | | Third Amended Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated February 8, 2006 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-32740, filed February 14, 2006) | 3.3 | | Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P. dated November 1, 2006 (incorporated by reference to Exhibit 3.3.1 of Form 10-K, File No. 1-32740, filed November 29, 2006) | 3.4 | | Amendment No. 2 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated November 9, 2007 (incorporated by reference to Exhibit 3.3.2 of Form 8-K, File No. 1-32740, filed November 13, 2007) | 3.5 | | Amendment No. 3 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated May 26, 2010 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-32740, filed June 2, 2010) | 3.6 | | Amendment No. 4 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated December 23, 2013 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-32740, filed December 27, 2013) | | | | | | Energy Transfer Equity, L.P. | 3.7 | | Amended Certificate of Limited Partnership of Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 3.3 of Form 10-Q, File No. 1-11727, filed April 14, 2004) | 3.8 | | Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P. (formerly named Heritage Propane Partners, L.P.) dated July 28, 2009 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-11727, filed July 29, 2009) | 3.9 | | Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated March 26, 2012 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-11727, filed March 28, 2012) | 3.10 | | Amendment No. 2 to Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated October 5, 2012 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-11727, filed October 5, 2012) | 3.11 | | Amendment No. 3 to Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated April 15, 2013 (incorporated by reference to Exhibit 3.1 to Form 8-K/A, File No. 1-11727, filed April 18, 2013) | 3.12 | | Amendment No. 4 to Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated April 30, 2013 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-11727, filed May 1, 2013) | 3.13 | | Amendment No. 5 to Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated October 31, 2013 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-11727, filed November 1, 2013) | 3.14 | | Amendment No. 6 to Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated February 19, 2014 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-11727, filed February 19, 2014) | 3.15 | | Amendment No. 7 to Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated March 3, 2014 (incorporated by reference to Exhibit 4.1 of Form 8-K, File No. 1-11727, filed March 5, 2014) | 3.16 | | Amendment No. 8 to Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated August 29, 2014 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-11727, filed August 29, 2014) |
| | | | Exhibit
Number
| | Description | 3.17 | | Amendment No. 9 to Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated March 9, 2015 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-11727, filed March 10, 2015) | 3.18 | | Amendment No. 10 to Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated April 30, 2015 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-11727, filed April 30, 2015) | 3.19 | | Amendment No. 11 to Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated August 21, 2015 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-11727, filed August 27, 2015) | | | | | | Sunoco Logistics Partners L.P. | 3.20 | | Certificate of Limited Partnership of Sunoco Logistics Partners L.P. (incorporated by reference to Exhibit 3.1 of Form S-1, File No. 333-71968, filed October 22, 2001) | 3.21 | | Third Amended and Restated Agreement of Limited Partnership of Sunoco Logistics Partners L.P., dated as of January 26, 2010 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-31219, filed January 28, 2010) | 3.22 | | Amendment No. 1 to Third Amended and Restated Partnership Agreement of Sunoco Logistics Partners L.P., dated as of July 1, 2011 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-31219, filed July 5, 2011) | 3.23 | | Amendment No. 2 to Third Amended and Restated Partnership Agreement of Sunoco Logistics Partners L.P., dated as of November 21, 2011 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-31219, filed November 28, 2011) | 3.24 | | Amendment No. 3 to Third Amended and Restated Partnership Agreement of Sunoco Logistics Partners L.P., dated as of June 12, 2014 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-31219, filed June 17, 2014) | 3.25 | | Amendment No. 4 to Third Amended and Restated Partnership Agreement of Sunoco Logistics Partners L.P., dated as of July 30, 2014 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-31219, filed August 4, 2014) | 3.26 | | Amendment No. 5 to Third Amended and Restated Partnership Agreement of Sunoco Logistics Partners L.P., dated as of August 28, 2015 (incorporated by reference to Exhibit 3.2 of Form 8-K, File No. 1-31219, filed September 1, 2015) | 3.27 | | Amendment No. 6 to Third Amended and Restated Partnership Agreement of Sunoco Logistics Partners L.P., dated as of October 8, 2015 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-31219, filed October 15, 2015) | | | | | | Sunoco LP | 3.28 | | Certificate of Limited Partnership of Susser Petroleum Partners LP (incorporated by reference to Exhibit 3.1 of Form S-1, File No. 333-182276, filed June 22, 2012) | 3.29 | | Certificate of Amendment to the Certificate of Limited Partnership of Susser Petroleum Partners LP (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-35653, filed October 28, 2014) | 3.30 | | First Amended and Restated Agreement of Limited Partnership of Susser Petroleum Partners LP, dated September 25, 2012 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-35653, filed September 25, 2012) | 3.31 | | Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of Susser Petroleum Partners LP, dated October 27, 2014 (incorporated by reference to Exhibit 3.2 of Form 8-K, File No. 1-35653, filed October 28, 2014) | 3.32 | | Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of Sunoco LP, dated July 31, 2015 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-35653, filed August 6, 2015) | 3.33 | | Amendment No. 3 to First Amended and Restated Agreement of Limited Partnership of Sunoco LP, dated January 1, 2016 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-35653, filed January 5, 2016) | | | | | | Energy Transfer Equity, L.P. | 4.1 | | Indenture, dated September 20, 2010 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.14 of Form 8-K, File No. 1-32740, filed September 20, 2010) | 4.2 | | First Supplemental Indenture, dated September 20, 2010 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (including form of the Notes) (incorporated by reference to Exhibit 4.15 of Form 8-K, File No. 1-32740, filed September 20, 2010) | 4.3 | | Second Supplemental Indenture, dated December 20, 2011 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 of Form S-3, File No. 1-32740, filed November 14, 2013) |
| | | | Exhibit
Number
| | Description | 4.4 | | Second Supplemental Indenture, dated February 16, 2012 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 of Form 8-K, File No. 1-32740, filed February 17, 2012) | 4.5 | | Third Supplemental Indenture, dated April 24, 2012 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (including form of the Notes) (incorporated by reference to Exhibit 4.15 of Form 8-K, File No. 1-32740, filed September 20, 2010) | 4.6 | | Fourth Supplemental Indenture, dated December 2, 2013 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (including form of the Notes) (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-32740, filed December 2, 2013) | 4.7 | | Fifth Supplemental Indenture, dated May 28, 2014 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-32740, filed May 28, 2014) | 4.8 | | Sixth Supplemental Indenture, dated May 28, 2014 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 of Form 8-K, File No. 1-32740, filed May 28, 2014) | 4.9 | | Seventh Supplemental Indenture, dated May 22, 2015 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (including form of the Notes) (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-32740, filed May 22, 2015) | | | | | | Energy Transfer Partners, L.P. | 4.10 | | Indenture, dated January 18, 2005 among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 of Form 8-K, File No. 1-11727, filed January 19, 2005) | 4.11 | | First Supplemental Indenture, dated January 18, 2005 among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-11727, filed January 19, 2005) | 4.12 | | Second Supplemental Indenture, dated February 24, 2005 among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association (incorporated by reference to Exhibit 10.45 of Form 10-Q, File No. 1-11727, filed February 28, 2005) | 4.13 | | Fourth Supplemental Indenture, dated June 29, 2006 among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.13 of Form 10-K File No. 1-11727, filed August 31, 2006) | 4.14 | | Fifth Supplemental Indenture, dated October 23, 2006 among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 of ETP’s Form 8-K filed October 25, 2006) | 4.15 | | Sixth Supplemental Indenture, dated March 28, 2008 between Energy Transfer Partners, L.P. and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 of Form 8-K File No. 1-11727, filed March 28, 2008) | 4.16 | | Seventh Supplemental Indenture, dated December 23, 2008 between Energy Transfer Partners, L.P. and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-11727, filed December 23, 2008) | 4.17 | | Eighth Supplemental Indenture, dated April 7, 2009 between Energy Transfer Partners, L.P. and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-11727, filed April 7, 2009) | 4.18 | | Ninth Supplemental Indenture, dated May 12, 2011 between Energy Transfer Partners, L.P. and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K, File No. 1-11727, filed May 12, 2011) | 4.19 | | Tenth Supplemental Indenture, dated January 17, 2012 between Energy Transfer Partners, L.P. and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 1.1 of Form 8-K, File No. 1-11727, filed January 17, 2012) | 4.20 | | Eleventh Supplemental Indenture, dated January 22, 2013 between Energy Transfer Partners, L.P. and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-11727, filed January 22, 2013) | 4.21 | | Twelfth Supplemental Indenture, dated June 24, 2013 between Energy Transfer Partners, L.P. and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-11727, filed June 26, 2013) | 4.22 | | Thirteenth Supplemental Indenture, dated September 19, 2013 between Energy Transfer Partners, L.P. and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-11727, filed September 19, 2013) |
| | | | Exhibit
Number
| | Description | 4.23 | | Fourteenth Supplemental Indenture, dated as of March 12, 2015 between Energy Transfer Partners, L.P. and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-11727, filed March 12, 2015) | 4.24 | | Fifteenth Supplemental Indenture, dated as of June 23, 2015 between Energy Transfer Partners, L.P. and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.3 of Form 8-K, File No. 1-11727, filed June 18, 2015) | 4.25 | | Indenture, dated June 24, 2013 between Energy Transfer Partners, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 of Form 8-K, File No. 1-11727, filed June 26, 2013) | 4.26 | | First Supplemental Indenture, dated June 24, 2013 between Energy Transfer Partners, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.4 of Form 8-K, File No. 1-11727, filed June 26, 2013) | 4.27 | | Second Amended and Restated Credit Agreement, dated October 27, 2011, among Energy Transfer Partners, L.P., the borrower, and Wachovia Bank, National Association, as administrative agent, LC issuer and swingline lender, Bank of America, N.A., as syndication agent, BNP Paribas, JPMorgan Chase Bank, N.A. and the Royal Bank of Scotland PLC, as co-documentation agents, and Citibank, N.A., Credit Suisse, Cayman Islands Branch, Deutsche Bank Securities, Inc., Morgan Stanley Bank, Suntrust Bank and UBS Securities, LLC, as senior managing agents, and the other lenders party hereto (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-11727, filed November 2, 2011) | 4.28 | | First Amendment to Second Amended and Restated Credit Agreement, dated November 19, 2013, among Energy Transfer Partners, L.P., Wells Fargo Bank, National Association, as administrative agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-11727, filed November 20, 2013) | 4.29 | | Guarantee of Collection, made as of March 26, 2012, by Citrus ETP Finance LLC, to Energy Transfer Partners, L.P. under the Indenture dated as of January 18, 2005, as supplemented by the Tenth Supplemental Indenture dated as of January 17, 2012 (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-11727, filed March 28, 2012) | 4.30 | | Support Agreement, dated March 26, 2012, by and among PEPL Holdings, LLC, Energy Transfer Partners, L.P. and Citrus ETP Finance LLC (incorporated by reference to Exhibit 10.2 of Form 8-K, File No. 1-11727, filed March 28, 2012) | 4.31 | | Guarantee of Collection, made as of April 1, 2015, by ETP Retail Holdings, LLC, to Sunoco LP and Sunoco Finance Corp. (incorporated by reference to Exhibit 10.2 of Form 8-K, File No. 1-11727, filed April 1, 2015) | 4.32 | | Support Agreement, made as of April 1, 2015, by and among Sunoco, Inc. (R&M), Sunoco LP, Sunoco Finance Corp. and ETP Retail Holdings, LLC (incorporated by reference to Exhibit 10.3 of Form 8-K, File No. 1-11727, filed April 1, 2015) | 4.33 | | Support Agreement, made as of April 1, 2015, by and among Atlantic Refining & Marketing Corp., Sunoco LP, Sunoco Finance Corp. and ETP Retail Holdings, LLC (incorporated by reference to Exhibit 10.4 of Form 8-K, File No. 1-11727, filed April 1, 2015) | 4.34 | | Note Purchase Agreement, dated as of November 17, 2004, by and among Transwestern Pipeline Company, LLC and the Purchasers parties thereto (incorporated by reference to Exhibit 10.55 of Form 10-Q, File No. 1-11727, filed May 31, 2007) | 4.35 | | Amendment No. 1 to the Note Purchase Agreement, dated as of April 18, 2007, by and among Transwestern Pipeline Company, LLC and the Purchasers parties thereto (incorporated by reference to Exhibit 10.55.1 of Form 10-Q, File No. 1-11727, filed May 31, 2007) | 4.36 | | Note Purchase Agreement, dated as of May 24, 2007, by and among Transwestern Pipeline Company, LLC and the Purchasers parties thereto (incorporated by reference to Exhibit 10.6 of Form 10-Q, File No. 1-11727, filed May 31, 2007) | 4.37 | | Note Purchase Agreement, dated December 9, 2009, by and among Transwestern Pipeline Company, LLC and the Purchasers parties thereto (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-11727, filed December 14, 2009) | 4.38 | | Indenture, dated as of June 30, 2000 between Sunoco, Inc. and U.S. Bank National Association, as successor trustee to Citibank, N.A. (incorporated by reference to Exhibit 4.4 of Form 8-K, File No. 1-11727, filed October 5, 2012) | 4.39 | | First Supplemental Indenture, dated October 5, 2012 among Energy Transfer Partners, L.P., Sunoco, Inc. and U.S. Bank National Association, as successor trustee to Citibank, N.A. (incorporated by reference to Exhibit 4.7 of Form 8-K, File No. 1-11727, filed October 5, 2012) | 4.40 | | Indenture, dated May 15, 1994 between Sun Company, Inc. and U.S. Bank National Association, as successor trustee to Citibank, N.A. (incorporated by reference to Exhibit 4.8 of Form 8-K, File No. 1-11727, filed October 5, 2012) | 4.41 | | First Supplemental Indenture, dated October 5, 2012 among Energy Transfer Partners, L.P., Sunoco, Inc. and U.S. Bank National Association, as successor trustee to Citibank, N.A. (incorporated by reference to Exhibit 4.9 of Form 8-K, File No. 1-11727, filed October 5, 2012) |
| | | | Exhibit
Number
| | Description | 4.42 | | Indenture, dated October 27, 2010 among Regency Energy Partners LP, Regency Energy Finance Corp., the guarantors party thereto and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 of Form 8-K, File No. 0-51757, filed October 27, 2010) | 4.43 | | Third Supplemental Indenture, dated May 26, 2011 among Regency Energy Partners LP, Regency Energy Finance Corp., the guarantors party thereto and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 of Form 8-K, File No. 0-51757, filed May 26, 2011) | 4.44 | | Fifth Supplemental Indenture, dated October 2, 2012 among Regency Energy Partners LP, Regency Energy Finance Corp., the guarantors party thereto and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-35262, filed October 2, 2012) | 4.45 | | Eleventh Supplemental Indenture, dated as of April 30, 2015 by and among Regency Energy Partners LP, Regency Energy Finance Corp., the subsidiary guarantors party thereto, Energy Transfer Partners, L.P., as parent guarantor, and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-11727, filed April 30, 2015) | 4.46 | | Twelfth Supplemental Indenture, dated as of August 10, 2015 by and among Energy Transfer Partners, L.P., Regency Energy Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-11727, filed August 13, 2015) | 4.47 | | Indenture, dated April 30, 2013 among Regency Energy Partners LP, Regency Energy Finance Corp., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 of Form 8-K, File No. 1-11727, filed April 30, 2013) | 4.48 | | Seventh Supplemental Indenture, dated as of May 28, 2015 by and among Regency Energy Partners LP, Regency Energy Finance Corp., the subsidiary guarantors party thereto, Panhandle Eastern Pipe Line Company, LP, Energy Transfer Partners, L.P., as co-obligor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-11727, filed June 1, 2015) | 4.49 | | Eighth Supplemental Indenture, dated as of August 10, 2015 by and among Energy Transfer Partners, L.P., Regency Energy Finance Corp. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.2 of Form 8-K, File No. 1-11727, filed August 13, 2015) | 4.50 | | Indenture, dated September 11, 2013 among Regency Energy Partners LP, Regency Energy Finance Corp., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 of Form 8-K, File No. 1-35262, filed September 11, 2013) | 4.51 | | First Supplemental Indenture, dated September 11, 2013 among Regency Energy Partners LP, Regency Energy Finance Corp., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-35262, filed September 11, 2013) | 4.52 | | Third Supplemental Indenture, dated February 10, 2014 among Regency Energy Partners LP, Regency Energy Finance Corp., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 of Form 8-K, File No. 1-35262, filed February 10, 2014) | 4.53 | | Sixth Supplemental Indenture, dated as of July 25, 2014 among Regency Energy Partners LP, Regency Energy Finance Corp., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-35262, filed July 28, 2014) | 4.54 | | Eighth Supplemental Indenture, dated as of April 30, 2015 by and among Regency Energy Partners LP, Regency Energy Finance Corp., the subsidiary guarantors party thereto, Energy Transfer Partners, L.P., as parent guarantor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.4 of Form 8-K, File No. 1-11727, filed April 30, 2015) | 4.55 | | Ninth Supplemental Indenture, dated as of August 10, 2015 by and among Energy Transfer Partners, L.P., Regency Energy Finance Corp. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.3 of Form 8-K, File No. 1-11727, filed August 13, 2015) | 4.56 | | Indenture, dated as of March 29, 1999 among CMS Panhandle Holding Company, Panhandle Eastern Pipe Line Company, LP and NBD Bank (the predecessor to Bank One Trust Company, National Association, J.P. Morgan Trust Company, National Association, The Bank of New York Trust Company, N.A. and The Bank of New York Mellon Trust Company, N.A.), as trustee (incorporated by reference to Exhibit 4(a) of Form 10-Q, File No. 1-02921, filed May 14, 1999) | 4.57 | | First Supplemental Indenture, dated as of March 29, 1999 among CMS Panhandle Holding Company, Panhandle Eastern Pipe Line Company, LP and NBD Bank (the predecessor to Bank One Trust Company, National Association, J.P. Morgan Trust Company, National Association, The Bank of New York Trust Company, N.A. and The Bank of New York Mellon Trust Company, N.A.), as trustee (incorporated by reference to Exhibit 4(b) of Form 10-Q, File No. 1-02921, filed May 14, 1999) | 4.58 | | Fifth Supplemental Indenture, dated as of October 26, 2007 between Panhandle Eastern Pipe Line Company, LP and the Bank of New York Trust Company, N.A. (now known as The Bank of New York Mellon Trust Company, N.A.), as trustee (incorporated by reference to Exhibit 4.1 of Form 8-K, File No. 1-02921, filed October 29, 2007)Thruway Authority. |
| | | | Exhibit
Number
| | Description | 4.59 | | Form of Sixth Supplemental Indenture, dated as of June 12, 2008 between Panhandle Eastern Pipe Line Company, LP and the Bank of New York Trust Company, N.A. (now known as The Bank of New York Mellon Trust Company, N.A.), as trustee (incorporated by reference to Exhibit 4.1 of Form 8-K, File No. 1-02921, filed June 11, 2008) | 4.60 | | Form of Seventh Supplemental Indenture, dated June 2, 2009 between Panhandle Eastern Pipeline Company, LP and the Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Exhibit 4.1 of Form 8-K, File No. 1-02921, filed May 28, 2009) | 4.61 | | Senior Debt Securities Indenture between Southern Union Company and The Chase Manhattan Bank (National Association), which changed its name to JP Morgan Chase Bank and then to JP Morgan Chase Bank, N.A., which was then succeeded to by The Bank of New York Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company N.A., as trustee (incorporated by reference to Exhibit 4.1 of Form 8-K, File No. 1-06407, filed February 15, 1994) | 4.62 | | Form of Supplemental Indenture No. 1, dated June 11, 2003 between Southern Union Company and JP Morgan Chase Bank, which changed its name to JP Morgan Chase Bank, N.A., the predecessor to The Bank of New York Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Exhibit 4.5 of Form 8-A/A, File No. 1-06407, filed June 20, 2003) | 4.63 | | Supplemental Indenture No. 2, dated February 11, 2005 between Southern Union Company and JP Morgan Chase Bank, N.A., the predecessor to The Bank of New York Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Exhibit 4.4 of Form 8-A/A, File No. 1-06407, filed February 22, 2005) | 4.64 | | Subordinated Debt Securities Indenture between Southern Union and The Chase Manhattan Bank (National Association), which changed its name to JP Morgan Chase Bank and then to JP Morgan Chase Bank, N.A., which was then succeeded to by The Bank of New York Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4-G of Form S-3, File No. 033-58297, filed May 8, 1995) | 4.65 | | Second Supplemental Indenture, dated October 23, 2006 between Southern Union Company and The Bank of New York Trust Company, N.A., now known as The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Exhibit 4.1 of Form 8-K/A, File No. 1-06407, filed October 24, 2006) | 4.66 | | 2006 Series A Junior Subordinated Notes Due November 1, 2066, dated October 23, 2006 (incorporated by reference to Exhibit 4.2 of Form 8-K/A, File No. 1-06407, filed October 24, 2006) | | | | | | Sunoco Logistics Partners L.P. | 4.67 | | Indenture, dated December 16, 2005 among Sunoco Logistics Partners Operations L.P., Sunoco Logistics Partners L.P., the subsidiary guarantors named therein and U.S. Bank National Association, as successor trustee (incorporated by reference to Exhibit 4.4 of Form S-3, File No. 333-13056, filed December 21, 2005) | 4.68 | | First Supplemental Indenture, dated as of May 8, 2006 by and among Sunoco Logistics Partners Operations L.P., Sunoco Logistics Partners L.P., Sunoco Partners Marketing & Terminals L.P., Sunoco Pipeline L.P. and Citibank, N.A., (incorporated by reference to Exhibit 1.3 of Form 8-K, File No. 1-31219, filed May 8, 2006) | 4.69 | | Third Supplemental Indenture, dated as of February 12, 2010 by and among Sunoco Logistics Partners Operations L.P., Sunoco Logistics Partners L.P. and U.S. Bank National Association (incorporated by reference to Exhibit 1.2 of Form 8-K, File No. 1-31219, filed February 12, 2010) | 4.70 | | Fourth Supplemental Indenture, dated as of February 12, 2010 by and among Sunoco Logistics Partners Operations L.P., Sunoco Logistics Partners L.P. and U.S. Bank National Association (incorporated by reference to Exhibit 1.3 of Form 8-K, File No. 1-31219, filed February 12, 2010) | 4.71 | | Fifth Supplemental Indenture, dated as of August 2, 2011 by and among Sunoco Logistics Partners Operations L.P., Sunoco Logistics Partners L.P. and U.S. Bank National Association (incorporated by reference to Exhibit 1.2 of Form 8-K, File No. 1-31219, filed August 2, 2011) | 4.72 | | Sixth Supplemental Indenture, dated as of August 2, 2011 by and among Sunoco Logistics Partners Operations L.P., Sunoco Logistics Partners L.P. and U.S. Bank National Association (incorporated by reference to Exhibit 1.3 of Form 8-K, File No. 1-31219, filed August 2, 2011) | 4.73 | | Seventh Supplemental Indenture, dated January 10, 2013 among Sunoco Logistics Partners Operations L.P., Sunoco Logistics Partners L.P. and U.S. Bank National Association, as successor trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-31219, filed January 10, 2013) | 4.74 | | Eighth Supplemental Indenture, dated January 10, 2013 among Sunoco Logistics Partners Operations L.P., Sunoco Logistics Partners L.P. and U.S. Bank National Association, as successor trustee (incorporated by reference to Exhibit 4.4 of Form 8-K, File No. 1-31219, filed January 10, 2013) | 4.75 | | Ninth Supplemental Indenture, dated April 3, 2014 among Sunoco Logistics Partners Operations L.P., Sunoco Logistics Partners L.P. and U.S. Bank National Association, as successor trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-31219, filed April 3, 2014) |
| | | | Exhibit
Number
| | Description | 4.76 | | Tenth Supplemental Indenture, dated April 3, 2014 among Sunoco Logistics Partners Operations L.P., Sunoco Logistics Partners L.P. and U.S. Bank National Association, as successor trustee (incorporated by reference to Exhibit 4.4 of Form 8-K, File No. 1-31219, filed April 3, 2014) | 4.77 | | Eleventh Supplemental Indenture, dated as of November 17, 2014 by and among Sunoco Logistics Partners Operations L.P., Sunoco Logistics Partners L.P. and U.S. Bank National Association, as successor trustee (incorporated by reference to Exhibit 4.4 of Form 8-K, File No. 1-31219, filed November 17, 2014) | 4.78 | | Twelfth Supplemental Indenture, dated as of November 17, 2015 by and among Sunoco Logistics Partners Operations L.P., Sunoco Logistics Partners L.P. and U.S. Bank National Association (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-31219, filed November 17, 2015) | 4.79 | | Thirteenth Supplemental Indenture, dated as of November 17, 2015 by and among Sunoco Logistics Partners Operations L.P., Sunoco Logistics Partners L.P. and U.S. Bank National Association (incorporated by reference to Exhibit 4.4 of Form 8-K, File No. 1-31219, filed November 17, 2015) | 4.80 | | Unitholder Agreement, dated as of October 8, 2015, between Energy Transfer Partners, L.P. and Sunoco Logistics Partners L.P. (incorporated by reference to Exhibit 10.2 of Form 8-K, File No. 1-31219, filed October 2, 2015) | | | | | | Sunoco LP | 4.81 | | Indenture, dated as of April 1, 2015, by and among Sunoco LP, Sunoco Finance Corp., the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 of Form 8-K, File No. 1-35653, filed on April 2, 2015) | 4.82 | | Indenture, dated as of July 20, 2015 by and among Sunoco LP, Sunoco Finance Corp., the Guarantors party thereto and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 of Form 8-K, File No. 1-35653, filed July 21, 2015) | | | | | | Energy Transfer Equity, L.P. | 10.1+ | | Energy Transfer Equity, L.P. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.25 of Form S-1, File No. 333-128097, filed December 20, 2005) | 10.2+ | | Form of Director and Officer Indemnification Agreement (incorporated by reference to Exhibit 10.26 of Form S-1, File No. 333-128097, filed December 20, 2005) | 10.3 | | Registration Rights Agreement, dated November 1, 2006, between Energy Transfer Equity, L.P. and Energy Transfer Investments, L.P. (incorporated by reference to Exhibit 10.38 of Form 10-K, File No. 1-32740, filed November 29, 2006) | 10.4 | | Registration Rights Agreement, dated November 27, 2006, by and among Energy Transfer Equity, L.P. and certain investors named therein (incorporated by reference to Exhibit 99.1 of Form 8-K, File No. 1-32740, filed November 30, 2006) | 10.5+ | | LE GP, LLC Outside Director Compensation Policy (incorporated by reference to Exhibit 99.1 of Form 8-K, File No. 1-32740, filed December 26, 2006) | 10.6 | | Registration Rights Agreement, dated March 2, 2007, by and among Energy Transfer Equity, L.P. and certain investors named therein (incorporated by reference to Exhibit 99.1 of Form 8-K, File No. 1-32740, filed March 5, 2007) | 10.7 | | Unitholder Rights and Restrictions Agreement, dated as of May 7, 2007, by and among Energy Transfer Equity, L.P., Ray C. Davis, Natural Gas Partners VI, L.P. and Enterprise GP Holdings, L.P. (incorporated by reference to Exhibit 10.45 of Form 8-K, File No. 1-32740, filed May 7, 2007) | 10.8 | | Letter Agreement, dated as of April 29, 2012, by and among Energy Transfer Partners, L.P. and Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed May 1, 2012) | 10.9 | | First Amendment, dated April 30, 2013, to the Services Agreement, effective as of May 26, 2010, by and among Energy Transfer Equity, L.P., ETE Services Company LLC and Regency Energy Partners LP (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed May 1, 2013) | 10.10 | | Second Amendment, dated April 30, 2013, to the Shared Services Agreement dated as of August 26, 2005, as amended May 26, 2010, by and between Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P.(incorporated by reference to Exhibit 10.2 of Form 8-K, File No. 1-32740, filed May 1, 2013) | 10.11 | | Third Amendment, dated February 19, 2014, to the Shared Services Agreement dated as of August 26, 2005, as amended May 26, 2010 and April 30, 2013 by and between Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed February 19, 2014) | 10.12 | | Exchange and Redemption Agreement by and among Energy Transfer Partners, L.P., Energy Transfer Equity, L.P. and ETE Common Holdings, LLC, dated August 7, 2013 (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed August 8, 2013) |
| | | | Exhibit
Number
| | Description | 10.13 | | Credit Agreement, dated as of December 2, 2013 among Energy Transfer Equity, L.P., Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed December 2, 2013) | 10.14 | | 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) | 10.15 | | 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) | 10.16 | | 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) | 10.17 | | 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) | 10.18 | | Amendment and Incremental Commitment Agreement No. 3, dated February 10, 2015 among Energy Transfer Equity, L.P., Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed February 17, 2015) | 10.19 | | Senior Secured Term Loan C Agreement, dated March 5, 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 March 9, 2015) | 10.20 | | Class D Unit Agreement (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed December 27, 2013) | 10.21*+ | | Retention Agreement, by and among Energy Transfer Equity, L.P. and Thomas P. Mason, dated February 24, 2016. | | | | | | Energy Transfer Partners, L.P. | 10.22 | | Cushion Gas Litigation Agreement, dated January 26, 2005, among AEP Energy Services Gas Holding Company II, L.L.C. and HPL Storage LP, as Sellers, and LaGrange Acquisition, L.P., as Buyer, and AEP Asset Holdings LP, AEP Leaseco LP, Houston Pipe Line Company, LP and HPL Resources Company LP, as Companies (incorporated by reference to Exhibit 10.2 of Form 8-K, File No. 1-11727, filed February 1, 2005) | 10.23 | | Second Amended and Restated Credit Agreement, dated October 27, 2011, among Energy Transfer Partners, L.P., the borrower, and Wachovia Bank, National Association, as administrative agent, LC issuer and swingline lender, Bank of America, N.A., as syndication agent, BNP Paribas, JPMorgan Chase Bank, N.A. and the Royal Bank of Scotland PLC, as co-documentation agents, and Citibank, N.A., Credit Suisse, Cayman Islands Branch, Deutsche Bank Securities, Inc., Morgan Stanley Bank, Suntrust Bank and UBS Securities, LLC, as senior managing agents, and other lenders party hereto (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-11727, filed November 2, 2011) | 10.24 | | Redemption Agreement, dated September 14, 2006, between Energy Transfer Partners, L.P. and CCE Holdings, LLC (incorporated by reference to Exhibit 10.2 of Form 8-K, File No. 1-11727, filed September 18, 2006) | 10.25 | | Letter Agreement, dated September 14, 2006, between Energy Transfer Partners, L.P. and Southern Union Company (incorporated by reference to Exhibit 10.3 of Form 8-K, File No. 1-11727, filed September 18, 2006) | 10.26+ | | Energy Transfer Partners, L.P. Amended and Restated 2004 Unit Plan (incorporated by reference to Exhibit 10.6.6 of Form 10-Q, File No. 1-11727, filed August 11, 2008) | 10.27+ | | Energy Transfer Partners, L.P. Second Amended and Restated 2008 Long Term Incentive Plan (incorporated by reference to Exhibit A of Definitive Proxy Statement on Schedule 14A, File No. 1-11727, filed October 24, 2014) | 10.28+ | | Energy Transfer Partners Deferred Compensation Plan (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-11727, filed March 31, 2010) | 10.29+ | | Form of Grant Agreement under the Energy Transfer Partners, L.P. Amended and Restated 2004 Unit Plan and the Energy Transfer Partners, L.P. 2008 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-11727, filed November 1, 2004) | 10.30+ | | Energy Transfer Partners, L.P. Annual Bonus Plan (incorporated by reference to Exhibit 10.2 of Form 10-Q, File No. 1-11727, filed August 7, 2014) | 10.31+ | | Energy Transfer Partners, L.L.C. Annual Bonus Plan effective January 1, 2014 (incorporated by reference to Exhibit 10.2 of Form 10-Q, File No. 1-11727, filed August 7, 2014) | | | | | | | | | | | | |
| | | | Exhibit
Number
| | Description | | | Sunoco Logistics Partners L.P. | 10.32 | | $2,500,000,000 Amended and Restated Credit Agreement, dated as of March 20, 2015, among Sunoco Logistics Partners Operations L.P., as the Borrower; Sunoco Logistics Partners L.P., as the Guarantor; Citibank, N.A., as Administrative Agent, Swingline Lender and a L/C Issuer; and the other LC Issuers and Lenders party thereto (incorporated by reference to Exhibit 10.1 of Form 10-Q, File No. 1-31219, filed May 7, 2015) | 10.33 | | Amendment No. 1 to the $2,500,000,000 Amended and Restated Credit Agreement, dated as of June 29, 2015, among Sunoco Logistics Partners Operations L.P., as the Borrower; Sunoco Logistics Partners L.P., as the Guarantor; Citibank, N.A., as Administrative Agent, Swing Line Lender and a L/C Issuer; and the other LC Issuers and Lenders party thereto (incorporated by reference to Exhibit 10.1 of Form 10-Q, File No. 1-31219, filed August 6, 2015) | | | | | | Sunoco LP | 10.34 | | Credit Agreement among Susser Petroleum Partners LP, as the Borrower, the lenders from time to time party thereto and Bank of America, N.A., as Administrative Agent, Collateral Agent, Swingline Lender and an LC Issuer, dated September 25, 2014 (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-35653, filed October 1, 2014) | 10.35 | | First Amendment to Credit Agreement and Increase Agreement by and among Sunoco LP, Bank of America, N.A., as Administrative Agent, Collateral Agent, Swingline Lender and an LC Issuer, and the financial institutions parties thereto, dated April 10, 2015 (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-35653, filed April 13, 2015) | 10.36 | | Second Amendment to Credit Agreement, dated as of December 2, 2015, by and among Sunoco LP, Bank of America, N.A. and the financial institutions parties thereto as Lenders (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-35653, filed December 8, 2015) | 10.37 | | Registration Rights Agreement, dated as of December 3, 2015, by and among Sunoco LP and the purchasers named on Schedule A thereto (incorporated by reference to Exhibit 4.1 of Form 8-K, File No. 1-35653, filed December 8, 2015) | | | | | | Other Exhibits | 12.1* | | Computation of Ratio of Earnings to Fixed Charges. | 21.1* | | List of Subsidiaries. | 23.1* | | Consent of Grant Thornton LLP related to Energy Transfer Equity, L.P. | 23.2* | | Consent of Grant Thornton LLP related to Energy Transfer Partners, L.P. | 23.3* | | Consent of Ernst & Young LLP related to Susser Holdings Corporation. | 23.4* | | Consent of Ernst & Young LLP related to Sunoco LP. | 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 Susser Holdings Corporation. | 99.2* | | Report of Independent Registered Public Accounting Firm — Ernst & Young LLP opinion on consolidated financial statements of Sunoco LP. | 99.3 | | Statement of Policies Relating to Potential Conflicts among Energy Transfer Partners, L.P., Energy Transfer Equity, L.P. and Regency Energy Partners LP dated as of April 26, 2011 (incorporated by reference to Exhibit 99.1 of Form 10-Q, file No. 1-32740, filed August 8, 2011) | 101* | | Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Balance Sheets as of December 31, 2015 and December 31, 2014; (ii) our Consolidated Statements of Operations for the years ended December 31, 2015, 2014 and 2013; (iii) our Consolidated Statements of Comprehensive Income for years ended December 31, 2015, 2014 and 2013; (iv) our Consolidated Statement of Equity for the years ended December 31, 2015, 2014 and 2013; and (v) our Consolidated Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013. |
| | | * | Filed herewith. | ** | Furnished herewith. | + | Denotes a management contract or compensatory plan or arrangement. |
INDEX TO FINANCIAL STATEMENTS
Energy Transfer Equity, L.P. and Subsidiaries
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Partners
Energy Transfer Equity, L.P.
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, 2015 and 2014, and the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2015. These financial statements 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 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 as of December 31, 2014 and for the period from September 1, 2014 to December 31, 2014, is based solely on the reports 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 subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 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, 2015, 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 29, 2016 expressed an unqualified opinion thereon.
/s/ GRANT THORNTON LLP
Dallas, Texas
February 29, 2016
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
| | | | | | | | | | December 31, | | 2015 | | 2014 | ASSETS | | | | Current assets: | | | | Cash and cash equivalents | $ | 606 |
| | $ | 847 |
| Accounts receivable, net | 2,400 |
| | 3,378 |
| Accounts receivable from related companies | 119 |
| | 35 |
| Inventories | 1,636 |
| | 1,467 |
| Exchanges receivable | 31 |
| | 44 |
| Derivative assets | 46 |
| | 81 |
| Other current assets | 572 |
| | 287 |
| Total current assets | 5,410 |
| | 6,139 |
| | | | | Property, plant and equipment | 54,979 |
| | 45,018 |
| Accumulated depreciation and depletion | (6,296 | ) | | (4,726 | ) | | 48,683 |
| | 40,292 |
| | | | | Advances to and investments in unconsolidated affiliates | 3,462 |
| | 3,659 |
| Non-current derivative assets | — |
| | 10 |
| Other non-current assets, net | 730 |
| | 732 |
| Intangible assets, net | 5,431 |
| | 5,582 |
| Goodwill | 7,473 |
| | 7,865 |
| Total assets | $ | 71,189 |
| | $ | 64,279 |
|
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, | | 2015 | | 2014 | LIABILITIES AND EQUITY | | | | Current liabilities: | | | | Accounts payable | $ | 2,274 |
| | $ | 3,349 |
| Accounts payable to related companies | 28 |
| | 19 |
| Exchanges payable | 106 |
| | 184 |
| Derivative liabilities | 69 |
| | 21 |
| Accrued and other current liabilities | 2,302 |
| | 2,102 |
| Current maturities of long-term debt | 131 |
| | 1,008 |
| Total current liabilities | 4,910 |
| | 6,683 |
| | | | | Long-term debt, less current maturities | 36,837 |
| | 29,477 |
| Deferred income taxes | 4,590 |
| | 4,410 |
| Non-current derivative liabilities | 137 |
| | 154 |
| Other non-current liabilities | 1,069 |
| | 1,193 |
| | | | | Commitments and contingencies |
|
| |
|
| Preferred units of subsidiary (Note 7) | 33 |
| | 33 |
| Redeemable noncontrolling interests | 15 |
| | 15 |
| | | | | Equity: | | | | General Partner | (2 | ) | | (1 | ) | Limited Partners: | | | | Common Unitholders (1,044,767,336 and 1,077,533,798 units authorized, issued and outstanding as of December 31, 2015 and 2014, respectively) | (952 | ) | | 648 |
| Class D Units (2,156,000 and 3,080,000 units authorized, issued and outstanding as of December 31, 2015 and 2014, respectively) | 22 |
| | 22 |
| Accumulated other comprehensive loss | — |
| | (5 | ) | Total partners’ capital | (932 | ) | | 664 |
| Noncontrolling interest | 24,530 |
| | 21,650 |
| Total equity | 23,598 |
| | 22,314 |
| Total liabilities and equity | $ | 71,189 |
| | $ | 64,279 |
|
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, | | 2015 | | 2014 | | 2013 | REVENUES: | | | | | | Natural gas sales | $ | 3,671 |
| | $ | 5,386 |
| | $ | 3,842 |
| NGL sales | 3,935 |
| | 5,845 |
| | 3,618 |
| Crude sales | 8,378 |
| | 16,416 |
| | 15,477 |
| Gathering, transportation and other fees | 4,200 |
| | 3,733 |
| | 3,097 |
| Refined product sales | 15,672 |
| | 19,437 |
| | 18,479 |
| Other | 6,270 |
| | 4,874 |
| | 3,822 |
| Total revenues | 42,126 |
| | 55,691 |
| | 48,335 |
| COSTS AND EXPENSES: | | | | | | Cost of products sold | 34,009 |
| | 48,414 |
| | 42,580 |
| Operating expenses | 2,661 |
| | 2,102 |
| | 1,669 |
| Depreciation, depletion and amortization | 2,079 |
| | 1,724 |
| | 1,313 |
| Selling, general and administrative | 639 |
| | 611 |
| | 533 |
| Impairment losses | 339 |
| | 370 |
| | 689 |
| Total costs and expenses | 39,727 |
| | 53,221 |
| | 46,784 |
| OPERATING INCOME | 2,399 |
| | 2,470 |
| | 1,551 |
| OTHER INCOME (EXPENSE): | | | | | | Interest expense, net | (1,643 | ) | | (1,369 | ) | | (1,221 | ) | Equity in earnings from unconsolidated affiliates | 276 |
| | 332 |
| | 236 |
| Gain on sale of AmeriGas common units | — |
| | 177 |
| | 87 |
| Losses on extinguishments of debt | (43 | ) | | (25 | ) | | (162 | ) | Gains (losses) on interest rate derivatives | (18 | ) | | (157 | ) | | 53 |
| Non-operating environmental remediation | — |
| | — |
| | (168 | ) | Other, net | 22 |
| | (11 | ) | | (1 | ) | INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE | 993 |
| | 1,417 |
| | 375 |
| Income tax expense (benefit) from continuing operations | (100 | ) | | 357 |
| | 93 |
| INCOME FROM CONTINUING OPERATIONS | 1,093 |
| | 1,060 |
| | 282 |
| Income from discontinued operations | — |
| | 64 |
| | 33 |
| NET INCOME | 1,093 |
| | 1,124 |
| | 315 |
| Less: Net income (loss) attributable to noncontrolling interest | (96 | ) | | 491 |
| | 119 |
| NET INCOME ATTRIBUTABLE TO PARTNERS | 1,189 |
| | 633 |
| | 196 |
| General Partner’s interest in net income | 3 |
| | 2 |
| | — |
| Class D Unitholder’s interest in net income | 3 |
| | 2 |
| | — |
| Limited Partners’ interest in net income | $ | 1,183 |
| | $ | 629 |
| | $ | 196 |
| INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT: | | | | | | Basic | $ | 1.11 |
| | $ | 0.58 |
| | $ | 0.17 |
| Diluted | $ | 1.11 |
| | $ | 0.57 |
| | $ | 0.17 |
| NET INCOME PER LIMITED PARTNER UNIT: | | | | | | Basic | $ | 1.11 |
| | $ | 0.58 |
| | $ | 0.18 |
| Diluted | $ | 1.11 |
| | $ | 0.57 |
| | $ | 0.18 |
|
The accompanying notes are an integral part of these consolidated financial statements.
F - 5
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in millions)
| | | | | | | | | | | | | | Years Ended December 31, | | 2015 | | 2014 | | 2013 | Net income | $ | 1,093 |
| | $ | 1,124 |
| | $ | 315 |
| 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 | ) | Change in value of derivative instruments accounted for as cash flow hedges | — |
| | — |
| | (1 | ) | Change in value of available-for-sale securities | (3 | ) | | 1 |
| | 2 |
| Actuarial gain (loss) relating to pension and other postretirement benefits | 65 |
| | (113 | ) | | 66 |
| Foreign currency translation adjustment | (1 | ) | | (2 | ) | | (1 | ) | Change in other comprehensive income from unconsolidated affiliates | (1 | ) | | (6 | ) | | 17 |
| | 60 |
| | (117 | ) | | 79 |
| Comprehensive income | 1,153 |
| | 1,007 |
| | 394 |
| Less: Comprehensive income (loss) attributable to noncontrolling interest | (41 | ) | | 388 |
| | 181 |
| Comprehensive income attributable to partners | $ | 1,194 |
| | $ | 619 |
| | $ | 213 |
|
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, 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 |
| Distributions to partners | (3 | ) | | (1,084 | ) | | (3 | ) | | — |
| | — |
| | (1,090 | ) | Distributions to noncontrolling interest | — |
| | — |
| | — |
| | — |
| | (2,335 | ) | | (2,335 | ) | Subsidiary units issued for cash | (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 |
| | — |
| | (96 | ) | | 1,093 |
| Balance, December 31, 2015 | $ | (2 | ) | | $ | (952 | ) | | $ | 22 |
| | $ | — |
| | $ | 24,530 |
| | $ | 23,598 |
|
The accompanying notes are an integral part of these consolidated financial statements.
F - 7
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
| | | | | | | | | | | | | | Years Ended December 31, | | 2015 | | 2014 | | 2013 | OPERATING ACTIVITIES: | | | | | | Net income | $ | 1,093 |
| | $ | 1,124 |
| | $ | 315 |
| Reconciliation of net income to net cash provided by operating activities: | | | | | | Depreciation, depletion and amortization | 2,079 |
| | 1,724 |
| | 1,313 |
| Deferred income taxes | 242 |
| | (50 | ) | | 43 |
| Amortization included in interest expense | (21 | ) | | (51 | ) | | (55 | ) | Unit-based compensation expense | 91 |
| | 82 |
| | 61 |
| Impairment losses | 339 |
| | 370 |
| | 689 |
| Gain on sale of AmeriGas common units | — |
| | (177 | ) | | (87 | ) | Losses on extinguishments of debt | 43 |
| | 25 |
| | 162 |
| (Gains) losses on disposal of assets | (8 | ) | | (1 | ) | | 2 |
| Equity in earnings of unconsolidated affiliates | (276 | ) | | (332 | ) | | (236 | ) | Distributions from unconsolidated affiliates | 409 |
| | 291 |
| | 313 |
| Inventory valuation adjustments | 249 |
| | 473 |
| | (3 | ) | Other non-cash | (8 | ) | | (72 | ) | | 51 |
| Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | (1,164 | ) | | (231 | ) | | (149 | ) | Net cash provided by operating activities | 3,068 |
| | 3,175 |
| | 2,419 |
| INVESTING ACTIVITIES: | | | | | | Proceeds from sale of noncontrolling interest | 64 |
| | — |
| | — |
| Proceeds from the sale of AmeriGas common units | — |
| | 814 |
| | 346 |
| Cash paid for acquisitions, net of cash received | (835 | ) | | (2,367 | ) | | (405 | ) | Cash paid for acquisition of a noncontrolling interest | (129 | ) | | — |
| | — |
| Capital expenditures (excluding allowance for equity funds used during construction) | (9,386 | ) | | (5,381 | ) | | (3,505 | ) | Contributions in aid of construction costs | 80 |
| | 45 |
| | 52 |
| Contributions to unconsolidated affiliates | (45 | ) | | (334 | ) | | (3 | ) | Distributions from unconsolidated affiliates in excess of cumulative earnings | 128 |
| | 136 |
| | 419 |
| Proceeds from the sale of discontinued operations | — |
| | 77 |
| | 1,008 |
| Proceeds from the sale of other assets | 26 |
| | 62 |
| | 89 |
| Change in restricted cash | 19 |
| | 172 |
| | (348 | ) | Other | (16 | ) | | (19 | ) | | — |
| Net cash used in investing activities | (10,094 | ) | | (6,795 | ) | | (2,347 | ) | FINANCING ACTIVITIES: | | | | | | Proceeds from borrowings | 26,455 |
| | 18,375 |
| | 12,934 |
| Repayments of long-term debt | (19,828 | ) | | (13,886 | ) | | (11,951 | ) | Subsidiary units issued for cash | 3,889 |
| | 3,057 |
| | 1,759 |
| Distributions to partners | (1,090 | ) | | (821 | ) | | (733 | ) | Distributions to noncontrolling interests | (2,335 | ) | | (1,905 | ) | | (1,428 | ) | Debt issuance costs | (75 | ) | | (77 | ) | | (87 | ) | Capital contributions from noncontrolling interest | 841 |
| | 139 |
| | 18 |
| Redemption of Preferred Units | — |
| | — |
| | (340 | ) | Units repurchased under buyback program | (1,064 | ) | | (1,000 | ) | | — |
| Other, net | (8 | ) | | (5 | ) | | (26 | ) | Net cash provided by financing activities | 6,785 |
| | 3,877 |
| | 146 |
| Increase (decrease) in cash and cash equivalents | (241 | ) | | 257 |
| | 218 |
| Cash and cash equivalents, beginning of period | 847 |
| | 590 |
| | 372 |
| Cash and cash equivalents, end of period | $ | 606 |
| | $ | 847 |
| | $ | 590 |
|
The accompanying notes are an integral part of these consolidated financial statements.
F - 8
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.(4) | Expected contributions to fund our pension and postretirement benefit plans were included in “Other” above. Environmental liabilities, asset retirement obligations, unrecognized tax benefits, contingency accruals and deferred revenue, which were included in “Other non-current liabilities” in our consolidated balance sheets were excluded from the table above as the amounts do not represent contractual obligations or, in some cases, the amount and/or timing of the cash payments is uncertain. |
| | OPERATIONS AND ORGANIZATION:(5)
| Excludes net non-current deferred tax liabilities of $2.93 billion due to uncertainty of the timing of future cash flows for such liabilities. |
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, 2015, 2014, and 2013, 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.Cash Distributions
Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include ETP, ETP GP, ETP LLC, ETE Common Holdings, LLC, Panhandle (or Southern Union prior to its merger into Panhandle in January 2014), Sunoco Logistics, Sunoco LP and ETP Holdco. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.
As discussed in Note 8, in January 2014 and July 2015, the Partnership completed two-for-one splits of ETE Common Units. All references to unit and per unit amounts in the consolidated financial statements and in these notes to the consolidated financial statements have been adjusted to reflect the effects of the unit splits for all periods presented.
At December 31, 2015, our interests in ETP and Sunoco LP consisted of 100% of the respective general partner interests and IDRs, as well as 2.6 million ETP common units and 81.0 million ETP Class H units heldCash Distributions Paid by us or our wholly-owned subsidiaries. We also own 0.1% of Sunoco Partners LLC, the entity that owns the general partner interest and IDRs of Sunoco Logistics, while ETP owns the remaining 99.9% of Sunoco Partners LLC. Additionally, ETE owns 100 ETP Class I Units, the distributions from which offset a portion of IDR subsidies ETE has previously provided to ETP.
The consolidated financial statements of ETE presented herein include the results of operations of:
the Parent Company;
our controlled subsidiaries, ETP and Sunoco LP (see description of their respective operations below under “Business Operations”);
ETP’s and Sunoco LP’s consolidated subsidiaries and our wholly-owned subsidiaries that own the general partner and IDR interests in ETP and Sunoco LP; and
our wholly-owned subsidiary, Lake Charles LNG.
Our subsidiaries also own varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other forms of entities. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage or injury that may occur to their own customers. As a result, we apply proportionate consolidation for our interests in these entities.
Certain prior period amounts have been reclassified to conform to the 2015 presentation. These reclassifications had no impact on net income or total equity.
Business Operations
The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Sunoco LP. 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
Under the Parent Company Partnership Agreement, the Parent Company will distribute all of its Available Cash, as defined, within 50 days following the end of each fiscal quarter. Available cash generally means, with respect to any quarter, all cash on a stand-alone basis, see Note 17 for stand-alone financial information apart fromhand at the end of such quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the consolidated partnership information included herein.General Partner that is necessary or appropriate to provide for future cash requirements.
Distributions declared and paid during the periods presented are as follows:
| | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | 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 | | May 10, 2017 | | May 19, 2017 | | 0.2850 |
| June 30, 2017 | | August 7, 2017 | | August 21, 2017 | | 0.2850 |
| September 30, 2017 | | November 7, 2017 | | November 20, 2017 | | 0.2950 |
| December 31, 2017 | | February 8, 2018 | | February 20, 2018 | | 0.3050 |
| March 31, 2018 | | May 7, 2018 | | May 21, 2018 | | 0.3050 |
| June 30, 2018 | | August 6, 2018 | | August 20, 2018 | | 0.3050 |
| September 30, 2018 | | November 8, 2018 | | November 19, 2018 | | 0.3050 |
| December 31, 2018 | | February 8, 2019 | | February 19, 2019 | | 0.3050 |
|
| | (1) | Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forego their cash distributions on all or a portion of their common units for a period of up to nine quarters commencing with the distribution for the quarter ended March 31, 2016 and, in lieu of receiving cash distributions on these common units for each such quarter, each said unitholder received Convertible Units (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $0.11 per Convertible Unit. See Note 8 to the Partnership’s consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.” |
Our distributions declared and paid with respect to our Convertible Unit during the periods presented 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 |
| March 31, 2018 | | May 7, 2018 | | May 21, 2018 | | 0.1100 |
|
The total amounts of Contents
ETP is a publicly traded partnership whose operations comprisedistributions declared and paid during the following:
periods presented (all from Available Cash from the gatheringParent Company’s operating surplus and processing, compression, treating and transportation of natural gas, focusing on providing midstream services in some of the most prolific natural gas producing regionsare shown in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Utica, Bone Spring, and Avalon shales; intrastate transportation and storage natural gas operations that own and operate natural gas pipeline systems that are engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia;
interstate pipelines that are owned and operated, either directly or through equity method investments, that transport natural gas to various markets in the United States; and
a controlling interest in Sunoco Logistics, a publicly traded Delaware limited partnership that owns and operates a logistics business, consisting of crude oil, NGL and refined products pipelines.
ETP also 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. In November 2015, ETP and certain of its subsidiaries entered into a contribution agreement with Sunoco LP and certain of its subsidiaries, pursuantperiod to which ETP agreed to contribute to Sunocothey relate) are as follows:
| | | | | | | | | | | | | | Years Ended December 31, | | 2018 (1) | | 2017 | | 2016 | Limited Partners | $ | 2,215 |
| | $ | 1,022 |
| | $ | 971 |
| General Partner interest | 3 |
| | 3 |
| | 3 |
| Total Parent Company distributions | $ | 2,218 |
| | $ | 1,025 |
| | $ | 974 |
|
| | (1) | Include distributions declared by Energy Transfer LP for periods subsequent to the Energy Transfer Merger. |
The total amounts of distributions declared and paid during the ETP’s remaining 68.42% membership interest in Sunoco, LLC and 100% of the membership interests in Sunoco Retail LLC. Sunoco Retail LLC, which is expected to be formedperiods presented prior to the closing of the contribution, is expectedEnergy Transfer Merger as discussed in Note 1 (all from Available Cash from ETO’s operating surplus and are shown in the period to own all of the ETP’s remaining retail assets thatwhich they relate) are currently held by subsidiaries of Sunoco, Inc., along with certain other assets. In exchange, ETP expects to receive $2.03 billion in cash, subject to certain working capital adjustments, and 5.7 million Sunoco LP common units, which will be issued and sold to a subsidiary of ETP in private transactions exempt from registration under Section 4(a)(2) of the Securities Act of 1933, as amended. The transaction will be effective January 1, 2016 and is expected to close in March 2016.follows: 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 21 million ETP common units owned by ETE.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. | | | | | | | | | | | | | | | | | | Years Ended December 31, | | ETO | | Sunoco Logistics | | 2018 | | 2017 | | 2016 | | 2016 | Common Units held by public | $ | 1,286 |
| | $ | 2,435 |
| | $ | 2,168 |
| | $ | 485 |
| Common Units held by ETO | — |
| | — |
| | — |
| | 135 |
| Common Units held by ET | 31 |
| | 61 |
| | 28 |
| | — |
| Class H Units held by ET | — |
| | — |
| | 357 |
| | — |
| General Partner interest and IDRs | 900 |
| | 1,654 |
| | 1,395 |
| | 412 |
| IDR relinquishments (1) | (84 | ) | | (656 | ) | | (409 | ) | | (15 | ) | Series A Preferred Units | 59 |
| | 15 |
| | — |
| | — |
| Series B Preferred Units | 36 |
| | 9 |
| | — |
| | — |
| Series C Preferred Units (2) | 23 |
| | — |
| | — |
| | — |
| Series D Preferred Units (2) | 15 |
| | — |
| | — |
| | — |
| Total distributions declared to partners | $ | 2,266 |
| | $ | 3,518 |
| | $ | 3,539 |
| | $ | 1,017 |
|
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.
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”). Regency previously was a direct subsidiary of ETE and had been presented as a separate reportable segment. Each Regency common unit and Class F unit was converted into the right to receive 0.4124 ETP common units. ETP issued 172.2 million ETP common units to Regency unitholders, including 15.5 million units issued to subsidiaries of ETP. The 1.9 million outstanding Regency Preferred Units were converted into corresponding new ETP Series A Preferred Units on a one-for-one basis. In connection with the Regency Merger, ETE agreed to reduce the incentive distributions it receives from ETP by a total of $320 million over a five-year period. The IDR subsidy was $80 million for the year ended December 31, 2015 and will total $60 million per year for the following four years.
| | 2.(1) | Net of Class I unit distributions |
| | ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:(2)
| Distributions reflect prorated distributions for the year ended December 31, 2018. |
Cash Distributions Paid by Subsidiaries Certain of our subsidiaries are required by their respective partnership agreements to distribute all cash on hand at the end of each quarter, less appropriate reserves determined by the board of directors of their respective general partners. ETO Preferred Unit Distributions Distributions on the Partnership’s Series A, Series B, Series C and Series D preferred units declared and/or paid by the Partnership during the periods presented were as follows: | | | | | | | | | | | | | | | | | | | | | | | Period Ended | | Record Date | | Payment Date | | Series A (1) | | Series B (1) | | Series C | | Series D | | December 31, 2017 | | February 1, 2018 | | February 15, 2018 | | $ | 15.4510 |
| * | $ | 16.3780 |
| * | $ | — |
| | $ | — |
| | June 30, 2018 | | August 1, 2018 | | August 15, 2018 | | 31.2500 |
| | 33.1250 |
| | 0.5634 |
| * | — |
| | September 30, 2018 | | November 1, 2018 | | November 15, 2018 | | — |
| | — |
| | 0.4609 |
| | 0.5931 |
| * | December 31, 2018 | | February 1, 2019 | | February 15, 2019 | | 31.2500 |
| | 33.1250 |
| | 0.4609 |
| | 0.4766 |
| |
| | * | Represent prorated initial distributions. |
(1) Series A and Series B preferred unit distributions are paid on a bi-annual basis.
Sunoco LP Cash Distributions 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. | | | | | | | | | | | | 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 on Sunoco LP’s units declared and/or paid by Sunoco LP were as follows: | | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | 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 6, 2018 | | February 14, 2018 | | 0.8255 |
| March 31, 2018 | | May 7, 2018 | | May 15, 2018 | | 0.8255 |
| June 30, 2018 | | August 7, 2018 | | August 15, 2018 | | 0.8255 |
| September 30, 2018 | | November 6, 2018 | | November 14, 2018 | | 0.8255 |
| December 31, 2018 | | February 6, 2019 | | February 14, 2019 | | 0.8255 |
|
The total amount of distributions to the Partnership from Sunoco LP for the periods presented below is as follows: | | | | | | | | | | | | | | Years Ended December 31, | | 2018 | | 2017 | | 2016 | Distributions from Sunoco LP | | | | | | Limited Partner interests | $ | 94 |
| | $ | 150 |
| | $ | 151 |
| General Partner interest and IDRs | 70 |
| | 85 |
| | 81 |
| Series A Preferred | 2 |
| | 23 |
| | — |
| Total distributions from Sunoco LP | $ | 166 |
| | $ | 258 |
| | $ | 232 |
|
USAC Cash Distributions Subsequent to the Energy Transfer Merger and USAC Transactions described in Note 1 and Note 3, respectively, ETO owns approximately 39.7 million USAC common units and 6.4 million USAC Class B units. As of December 31, 2018, USAC had
approximately 96.4 million common units outstanding. USAC currently has a non-economic general partner interest and no outstanding incentive distribution rights. Distributions on USAC’s units declared and/or paid by USAC subsequent to the USAC transaction on April 2, 2018 were as follows: | | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | March 31, 2018 | | May 1, 2018 | | May 11, 2018 | | $ | 0.5250 |
| June 30, 2018 | | July 30, 2018 | | August 10, 2018 | | 0.5250 |
| September 30, 2018 | | October 29, 2018 | | November 09, 2018 | | 0.5250 |
| December 31, 2018 | | January 28, 2019 | | February 8, 2019 | | 0.5250 |
|
The total amount of distributions to the Partnership from USAC for the periods presented below is as follows: | | | | | | | | | | | | | | Years Ended December 31, | | 2018 | | 2017 | | 2016 | Distributions from USAC | | | | | | Limited Partner interests | $ | 73 |
| | $ | — |
| | $ | — |
| Total distributions from USAC | $ | 73 |
| | $ | — |
| | $ | — |
|
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. Upon the adoption of ASU 2014-09, the amount of revenue that the Partnership recognizes on certain contracts has changed, primarily due to decreases in revenue (with offsetting decreases to cost of sales) resulting from recognition of non-cash consideration as revenue when received and as cost of sales when sold to third parties. In addition, income statement reclassifications were required for fuel usage and loss allowances related to multiple segments as well as contracts deemed to be in-substance supply agreements in our midstream segment. In addition to the evaluation performed, we have made appropriate design and implementation updates to our business processes, systems and internal controls to support recognition and disclosure under the new standard. Utilizing the practical expedients allowed under the modified retrospective adoption method, Accounting Standards Codification (“ASC”) Topic 606 was only applied to existing contracts for which the Partnership has remaining performance obligations as of January 1, 2018, and new contracts entered into after January 1, 2018. ASC Topic 606 was not applied to contracts that were completed prior to January 1, 2018. The Partnership has elected to apply the modified retrospective method to adopt the new standard. For contracts in scope of the new revenue standard as of January 1, 2018, the cumulative effect adjustment to partners’ capital was not material. The comparative information has not been restated under the modified retrospective method and continues to be reported under the accounting standards in effect for those periods. 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 information about the amount, timing, and uncertainty of cash flows arising from a lease. The update requires lessees to record virtually all leases on their balance sheets. For lessors, this amended guidance modifies the classification criteria and the accounting for sales-type and direct financing leases. In January 2018, the FASB issued Accounting Standards Update No. 2018-01 (“ASU 2018-01”), which provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the existing lease guidance. The Partnership plans to elect the package of transition practical expedients and will adopt this standard beginning with its first quarter of fiscal 2019 and apply it retrospectively at the beginning of the period of
adoption through a cumulative-effect adjustment to retained earnings. The Partnership has performed several procedures to evaluate the impact of the adoption of this standard on the financial statements and disclosures and address the implications of Topic 842 on future lease arrangements. The procedures include reviewing all forms of leases, performing a completeness assessment over the lease population, establishing processes and controls to timely identify new and modified lease agreements, educating its employees on these new processes and controls and implementing a third-party supported lease accounting information system to account for our leases in accordance with the new standard. The Partnership is finalizing its evaluation of the impacts that the adoption of this accounting guidance will have on the consolidated financial statements, and estimates approximately $1.0 billion of right-to-use assets and lease liabilities will be recognized in the consolidated balance sheet upon adoption, with no material impact to its consolidated statements of operations. ASU 2017-12 In August 2017, the FASB issued Accounting Standards Update No. 2017-12, Derivatives and Hedging (Topic 815): TargetedImprovements 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 expects to adopt the new rules in the first quarter of 2019 and does not expect the adoption of the new accounting rules to have a material impact on the consolidated financial statements and related disclosures. ASU 2018-02 In February 2018, the FASB issued Accounting Standards Update No. 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, which allows a reclassification from accumulated other comprehensive income to partners’ capital for stranded tax effects resulting from the Tax Cuts and Jobs Act of 2017. The Partnership elected to early adopt this ASU in the first quarter of 2018. The effect of the adoption was not material. Estimates and Critical Accounting Policies The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules, and we believe the proper implementation and consistent application of the accounting rules are critical. Our critical accounting policies are discussed below. For further details on our accounting policies see Note 2 to our consolidated financial statements. 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 operationssegments 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 estimated for the year ended December 31, 2018 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 results could differ from those estimates. New Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606)Recognition. (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In August 2015, the FASB deferred the effective date of ASU 2014-09, which is now effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is permitted as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within those annual periods. 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 February 2015, the FASB issued Accounting Standards Update No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (“ASU 2015-02”), which changed the requirements for consolidation analysis. Under ASU 2015-02, reporting entities are required to evaluate whether they should consolidate certain legal entities. ASU 2015-02 is effective for fiscal years beginning after December 15, 2015, and early adoption was permitted. We expect to adopt this standard for the year ended December 31, 2016, and we do not anticipate a material impact to our financial position or results of operations as a result of the adoption of this standard.
In April 2015, the FASB issued Accounting Standards Update No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30) (“ASU 2015-03”), which simplifies the presentation of debt issuance costs by requiring debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the debt liability rather than as an asset. ASU 2015-03 is effective for annual reporting periods after December 15, 2015, including interim periods within that reporting period, with early adoption permitted for financial statements that have not been previously issued. Upon adoption, ASU 2015-03 must be applied retrospectively to all prior reporting periods presented. We adopted and applied this standard to all consolidated financial statements presented and there was not a material impact to our financial position or results of operations as a result of the adoption of this standard.
In August 2015, the FASB issued ASU No. 2015-16 "Business Combinations (Topic 805) - Simplifying the Accounting for Measurement-Period Adjustments." This update requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. Additionally, this update requires that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. Finally, this update requires an entity to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The amendments in this update are effective for financial statements issued with fiscal years beginning after December 15, 2015, including interim periods within that reporting period. We do not anticipate a material impact to our financial position or results of operations as a result of the adoption of this standard.
In November 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (“ASU 2015-17”), which is intended to improve how deferred taxes are classified on organizations’ balance sheets. The ASU eliminates the current requirement for organizations to present deferred tax liabilities and assets as current and noncurrent in a classified balance sheet. Instead, organizations are now required to classify all deferred tax assets and liabilities as noncurrent. We adopted the provisions of ASU 2015-17 upon issuance and prior period amounts have been reclassified to conform to the current period presentation. As a result of the early adoption and retrospective application of ASU 2015-17, $85 million of deferred tax liability previously presented as an other current liability as of December 31, 2014 has been reclassified to other non-current liabilities in our consolidated financial statements.
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’sOur intrastate transportation and storage and interstate transportation and storage operationssegments’ 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. FuelExcess fuel retained for a feeafter consumption is typically valued at market prices. ETP’sOur intrastate transportation and storage operationssegment also generategenerates 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 purchaseswe purchase natural gas from the market, including purchases from ETP’sour marketing operations, and from producers at the wellhead.
In addition, ETP’sour intrastate transportation and storage operations generatesegment generates revenues and margin from fees charged for storing customers’ working natural gas in ETP’sour storage facilities. ETPWe also engagesengage in natural gas storage transactions in which ETP seekswe seek to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. ETP purchasesWe purchase physical natural gas and then sellssell financial contracts at a price sufficient to cover ETP’sour carrying costs and provide for a gross profit margin. ETP expectsWe 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, ETPwe 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 ETPwe operate, competitive factors in the energy industry, and other issues. 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. Results from ETP’sthe midstream operationssegment are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through ETP’sour pipeline and gathering systems and the level of natural gas and NGL prices. ETP generatesWe generate midstream revenues and grosssegment margins principally under fee-based or other arrangements in which ETP receiveswe 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 ETP’sour systems and is not directly dependent on commodity prices. ETPWe also utilizesutilize other types of arrangements in ETP’sour midstream operations,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 ETP gatherswe gather and processesprocess natural gas on behalf of producers, sellssell the resulting residue gas and NGL volumes at market prices and remitsremit to producers an agreed upon percentage of the proceeds based on an index price, and (iii) keep-whole arrangements where ETP gatherswe gather natural gas from the producer, processesprocess the natural gas and sellssell 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.prices. In many cases, ETP provideswe provide services under contracts that contain a combination of more than one of the arrangements described above. The terms of ETP’sour contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. ETP’sOur 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.
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. We have a risk management policy that provides for oversight over our marketing activities. These activities are monitored independently by our risk management function and must take place within predefined limits and authorizations. As a result of our use of derivative financial instruments that may not qualify for hedge accounting, 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 senior management and predefined limits and authorizations set forth in our risk management policy. We inject and hold natural gas in our Bammel storage facility to take advantage of contango markets, when the price of natural gas is higher in the future than the current spot price. We use financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities. At the inception of the hedge, we lock in a margin by purchasing gas in the spot market or off peak season and entering 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 the 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 prices 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 our derivatives being recorded directly in earnings. These margins fluctuate based upon changes in the spreads between the physical spot prices and forward natural gas prices. If the spread narrows between the physical and financial prices, we will record unrealized gains or lower unrealized losses. If the spread widens, we will record unrealized losses or lower unrealized gains. Typically, as we enter the winter months, the spread converges so that we recognize in earnings the original locked in spread, either through mark-to-market or the physical withdrawal of natural gas. 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’sour 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 operations 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 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.
Investment in Sunoco LP
RevenuesSunoco LP’s revenues from our two primary product categories, motor fuel and merchandise, are recognized either at the time fuel is delivered to the customer or at the time of sale. Revenue recognition on consignment sales differ from this and are discussed in greater detail below. Shipment and delivery of motor fuel generally occurs on the same day. Sunoco LP charges its wholesale customers for third-party transportation costs, which are recorded net in cost of sales. Through PropCo, Sunoco LP’s wholly ownedwholly-owned corporate subsidiary, Sunoco LP may sell motor fuel to wholesale customers on a consignmentcommission agent basis, in which Sunoco LP retains title to inventory, controlcontrols access to and sale of fuel inventory, and recognizerecognizes revenue at the time the fuel is sold to the ultimate customer. In Sunoco LP’s fuel distribution and marketing operations, Sunoco LP derives other income from rental income, propane and lubricating oils, and other ancillary product and service offerings. In Sunoco LP’s other operations, Sunoco LP derives other income from merchandise, lottery ticket sales, money orders, prepaid phone cards and wireless services, ATM transactions, car washes, movie rentals, and other ancillary product and service offerings. Sunoco LP records revenue from other retail transactions on a net commission basis when thea product is sold and/or services are rendered. Rental income
Investment in USAC USAC’s revenue from operating leasescontracted compression, station, gas treating and maintenance services is recognized on a straight line basisratably under its fixed-fee contracts over the term of the lease.contract as services are provided to its customers. Initial contract terms typically range from six months to five years. However, USAC usually continues to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-to-month or longer basis. USAC primarily enters into fixed-fee contracts whereby its customers are required to pay its monthly fee even during periods of limited or disrupted throughput. Services are generally billed monthly, one month in advance of the commencement of the service month, except for certain customers who are billed at the beginning of the service month, and payment is generally due 30 days after receipt of the invoice. Amounts invoiced in advance are recorded as deferred revenue until earned, at which time they are recognized as revenue. The amount of consideration USAC receives and revenue it recognizes is based upon the fixed fee rate stated in each service contract.
Investment in Lake Charles LNG
Lake Charles LNG’s revenues from storageUSAC’s retail parts and re-gasification of natural gasservices revenue is earned primarily on freight and crane charges that are based on capacity reservation charges and, to a lesser extent, commodity usage charges. Reservation revenues are based on contracted rates and capacity reserveddirectly reimbursable by theits customers and maintenance work on units at its customers’ locations that are outside the scope of USAC’s core maintenance activities. Revenue from retail parts and services is recognized monthly. Revenues from commodity usage charges are also recognized monthlyat the point in time the part is transferred or service is provided and representcontrol is transferred to the recoverycustomer. At such time, the customer has the ability to direct the use of electric power charges at Lake Charles LNG’s terminal.the benefits of such part or service after USAC has performed its services. USAC bills upon completion of the service or transfer of the parts, and payment is generally due 30 days after receipt of the invoice. The amount of consideration USAC receives and revenue it recognizes is based upon the invoice amount.
Regulatory Accounting – Regulatory Assets and Liabilities
ETP’s. Our interstate transportation and storage operations aresegment is subject to regulation by certain state and federal authorities, and certain subsidiaries in those operationsthat 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 ETP’sour 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 ceaseswe cease to meet the criteria for application of regulatory accounting treatment for these entities,all or part of our operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be assessed and potentially eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs. Although Panhandle’sAccounting for Derivative Instruments and Hedging Activities. We utilize various exchange-traded and OTC commodity financial instrument contracts to limit our exposure to margin fluctuations in 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 of 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, | | 2015 | | 2014 | | 2013 | Accounts receivable | $ | 856 |
| | $ | 600 |
| | $ | (556 | ) | Accounts receivable from related companies | (5 | ) | | 30 |
| | 64 |
| Inventories | (430 | ) | | 51 |
| | (254 | ) | Exchanges receivable | 14 |
| | 18 |
| | (8 | ) | Other current assets | (239 | ) | | 133 |
| | (81 | ) | Other non-current assets, net | 250 |
| | (6 | ) | | (23 | ) | Accounts payable | (1,127 | ) | | (850 | ) | | 541 |
| Accounts payable to related companies | 400 |
| | 5 |
| | (140 | ) | Exchanges payable | (79 | ) | | (99 | ) | | 128 |
| Accrued and other current liabilities | (618 | ) | | (59 | ) | | 192 |
| Other non-current liabilities | (261 | ) | | (73 | ) | | 147 |
| Derivative assets and liabilities, net | 75 |
| | 19 |
| | (159 | ) | Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | $ | (1,164 | ) | | $ | (231 | ) | | $ | (149 | ) |
Non-cash investing and financing activities and supplemental cash flow information were as follows:
| | | | | | | | | | | | | | Years Ended December 31, | | 2015 | | 2014 | | 2013 | NON-CASH INVESTING ACTIVITIES: | | | | | | Accrued capital expenditures | $ | 910 |
| | $ | 643 |
| | $ | 226 |
| Net gains (losses) from subsidiary common unit transactions | (526 | ) | | 744 |
| | (384 | ) | NON-CASH FINANCING ACTIVITIES: | | | | | | Contribution of property, plant and equipment from noncontrolling interest | $ | 34 |
| | $ | — |
| | $ | — |
| Subsidiary issuances of common units in connection with PVR, Hoover and Eagle Rock Midstream acquisitions | — |
| | 4,281 |
| | — |
| Subsidiary issuances of common units in connection with the Susser Merger | — |
| | 908 |
| | — |
| Long-term debt assumed in PVR Acquisition | — |
| | 1,887 |
| | — |
| Long-term debt exchanged in Eagle Rock Midstream Acquisition | — |
| | 499 |
| | — |
| SUPPLEMENTAL CASH FLOW INFORMATION: | | | | | | Cash paid for interest, net of interest capitalized | $ | 1,800 |
| | $ | 1,416 |
| | $ | 1,256 |
| Cash paid for income taxes | 72 |
| | 345 |
| | 58 |
|
Accounts Receivable
Our subsidiaries assess the credit risk of their customers and take steps to mitigate risk as necessary. Management reviews accounts receivable and an allowance for doubtful accounts is determined based on the overall creditworthiness of customers, historical write-off experience, general and specific economic trends, and identification of specific customers with payment issues.
Inventories
Inventories consist principally of natural gas held in storage, crude oil, refined products and spare parts. Natural gas held in storage is valued at the lower of cost or market utilizing the weighted-average cost method. The cost ofNGL, crude oil and refined productsproducts. These contracts consist primarily of futures and swaps.
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 determined usingdeferred in AOCI until the last-in, first out method. Theunderlying 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 spare parts is determined byproducts sold in the first-in, first-out method.consolidated statements of operations. Inventories consisted of the following:
| | | | | | | | | | December 31, | | 2015 | | 2014 | Natural gas and NGLs | $ | 415 |
| | $ | 392 |
| Crude oil | 424 |
| | 364 |
| Refined products | 420 |
| | 392 |
| Spare parts and other | 377 |
| | 319 |
| Total inventories | $ | 1,636 |
| | $ | 1,467 |
|
During the year ended December 31, 2015, the Partnership recorded write downs of $249 million on its crude oil, refined products and NGL inventoriesIf we designate a hedging relationship as a result of a decline in the market price of these products. The write-down was calculated based upon current replacement costs.
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. Changeshedge, we record the changes in fair value of the designated hedged inventory have been recorded in inventory on our consolidated balance sheets andasset or liability in cost of products sold in our consolidated statementsstatement 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.
Exchanges
Exchanges consistWe utilize published settlement prices for exchange-traded contracts, quotes provided by brokers, and estimates 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, | | 2015 | | 2014 | Deposits paid to vendors | $ | 74 |
| | $ | 65 |
| Income taxes receivable | 326 |
| | 17 |
| Prepaid expenses and other | 172 |
| | 205 |
| Total other current assets | $ | 572 |
| | $ | 287 |
|
Property, Plant and Equipment
Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Natural gas and NGLs used to maintain pipeline minimum pressures is capitalized and classified as property, plant and equipment. Additionally, our subsidiaries capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. For the Lake Charles LNG project, a portion of the management fees are capitalized. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our consolidated statements of operations.
Property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value. In 2015, we recorded $110 million fixed asset impairments related to ETP’s liquids transportation and services operations primarily due to an expected decrease in future cash flows. No other fixed asset impairments were identified or recorded for our reporting units.
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, | | 2015 | | 2014 | Land and improvements | $ | 686 |
| | $ | 1,307 |
| Buildings and improvements (1 to 45 years) | 1,526 |
| | 1,922 |
| Pipelines and equipment (5 to 83 years) | 32,677 |
| | 27,149 |
| Natural gas and NGL storage facilities (5 to 46 years) | 390 |
| | 1,214 |
| Bulk storage, equipment and facilities (2 to 83 years) | 2,853 |
| | 4,010 |
| Tanks and other equipment (5 to 40 years) | 1,488 |
| | 58 |
| Retail equipment (2 to 99 years) | 401 |
| | 515 |
| Vehicles (1 to 25 years) | 220 |
| | 203 |
| Right of way (20 to 83 years) | 2,573 |
| | 2,451 |
| Furniture and fixtures (2 to 25 years) | 57 |
| | 59 |
| Linepack | 61 |
| | 119 |
| Pad gas | 44 |
| | 44 |
| Natural resources | 484 |
| | 454 |
| Other (1 to 30 years) | 3,675 |
| | 999 |
| Construction work-in-process | 7,844 |
| | 4,514 |
| | 54,979 |
| | 45,018 |
| Less – Accumulated depreciation and depletion | (6,296 | ) | | (4,726 | ) | Property, plant and equipment, net | $ | 48,683 |
| | $ | 40,292 |
|
We recognized the following amounts for the periods presented:
| | | | | | | | | | | | | | Years Ended December 31, | | 2015 | | 2014 | | 2013 | Depreciation and depletion expense | $ | 1,776 |
| | $ | 1,457 |
| | $ | 1,128 |
| Capitalized interest, excluding AFUDC | $ | 163 |
| | $ | 113 |
| | $ | 43 |
|
Advancesdaily contract activity 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.
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, | | 2015 | | 2014 | Unamortized financing costs(1) | $ | 29 |
| | $ | 41 |
| Regulatory assets | 90 |
| | 85 |
| Deferred charges | 198 |
| | 220 |
| Restricted funds | 192 |
| | 177 |
| Other | 221 |
| | 209 |
| Total other non-current assets, net | $ | 730 |
| | $ | 732 |
|
(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, 2015 | | December 31, 2014 | | Gross Carrying Amount | | Accumulated Amortization | | Gross Carrying Amount | | Accumulated Amortization | Amortizable intangible assets: | | | | | | | | Customer relationships, contracts and agreements (3 to 46 years) | $ | 5,254 |
| | $ | (738 | ) | | $ | 5,144 |
| | $ | (485 | ) | Trade names (15 years) | 559 |
| | (25 | ) | | 556 |
| | (15 | ) | Patents (9 years) | 48 |
| | (16 | ) | | 48 |
| | (11 | ) | Other (1 to 15 years) | 15 |
| | (7 | ) | | 36 |
| | (7 | ) | Total amortizable intangible assets | 5,876 |
| | (786 | ) | | 5,784 |
| | (518 | ) | Non-amortizable intangible assets: | | | | | | | | Trademarks | 341 |
| | — |
| | 316 |
| | — |
| Total intangible assets | $ | 6,217 |
| | $ | (786 | ) | | $ | 6,100 |
| | $ | (518 | ) |
Aggregate amortization expense of intangibles assets was as follows:
| | | | | | | | | | | | | | Years Ended December 31, | | 2015 | | 2014 | | 2013 | Reported in depreciation, depletion and amortization | $ | 303 |
| | $ | 219 |
| | $ | 120 |
|
Estimated aggregate amortization expense of intangible assets for the next five years was as follows:
| | | | | Years Ending December 31: | | 2016 | $ | 242 |
| 2017 | 242 |
| 2018 | 241 |
| 2019 | 239 |
| 2020 | 239 |
|
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 ETP’s liquids transportation and services operations primarily due to an expected decrease in future cash flows.
Goodwill
Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test is performed during the fourth quarter.
Changes in the carrying amount of goodwill were as follows:
| | | | | | | | | | | | | | | | | | | | | | Investment in ETP | | Investment in Sunoco LP | | Investment in Lake Charles LNG | | Corporate, Other and Eliminations | | Total | Balance, December 31, 2013 | $ | 5,856 |
| | $ | — |
| | $ | 184 |
| | $ | (146 | ) | | $ | 5,894 |
| Goodwill acquired | 2,340 |
| | 1,854 |
| | — |
| | (1,854 | ) | | 2,340 |
| Lake Charles LNG Transaction (1) | (184 | ) | | — |
| | — |
| | 184 |
| | — |
| Goodwill impairment | (370 | ) | | — |
| | — |
| | — |
| | (370 | ) | Other | — |
| | — |
| | — |
| | 1 |
| | 1 |
| Balance, December 31, 2014 | 7,642 |
| | 1,854 |
| | 184 |
| | (1,815 | ) | | 7,865 |
| Goodwill acquired | — |
| | 31 |
| | — |
| | — |
| | 31 |
| Sunoco LP Exchange | (2,018 | ) | | — |
| | — |
| | 2,018 |
| | — |
| Goodwill impairment | (205 | ) | | — |
| | — |
| | — |
| | (205 | ) | Other | 9 |
| | (63 | ) | | — |
| | (164 | ) | | (218 | ) | Balance, December 31, 2015 | $ | 5,428 |
| | $ | 1,822 |
| | $ | 184 |
| | $ | 39 |
| | $ | 7,473 |
|
| | (1)
| As discussed in Note 3, ETP completed the transfer to ETE of Lake Charles LNG on February 19, 2014. Therefore, the December 31, 2013 goodwill balances include goodwill attributable to Lake Charles LNG of $184 million 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 decrease in goodwill of $392 million during the year ended December 31, 2015 primarily due to the impairments discussed below as well as purchase price allocation adjustments.
During 2015, the Partnership voluntarily changed the date of the annual goodwill impairment testing to the first day of the fourth quarter. The Partnership believes this new date is preferable because it allows for more timely completion of the annual goodwill impairment test prior to the end of the annual financial reporting period. This change in accounting principle does not delay, accelerate or avoid any potential impairment loss, nor does the change have a cumulative effect on income from continuing operations, net income or loss, or net assets. This change was not applied retrospectively, as doing so would require the use of significant estimates and assumptions that include hindsight. Accordingly, the Partnership applied the change in annual goodwill impairment testing date prospectively beginning October 1, 2015.
During the fourth quarter of 2015, ETP performed goodwill impairment tests on its reporting units and recognized goodwill impairments of: (i) $99 million in the Transwestern reporting unit due primarily to the market declines in current and expected future commodity prices in the fourth quarter of 2015, and (ii) $106 million in the Lone Star Refinery Services reporting unit due primarily to changes in assumptions related to potential future revenues decrease as well as the market declines in current and expected future commodity prices.
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.
The Partnership determinedestimate the fair value of our reporting units using a weighted combination ofthese contracts. Changes in the discounted cash flow method and the guideline company method. Determiningmethods used to determine the fair value of these contracts could have a reporting unit requires judgment and the usematerial effect on our results of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital andoperations. We do not anticipate 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. Changeschanges in the liability are recorded for the passage of time (accretion) or for revisionsmethods used 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 measuredetermine the fair value of asset retirement obligations as of December 31, 2015these derivative contracts. See “Item 7A. Quantitative and 2014, 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 obligationsQualitative Disclosures about Market Risk” 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 it 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.further discussion regarding our derivative activities.
Below is a schedule of AROs by segment recorded as other non-current liabilities in our consolidated balance sheets:
| | | | | | | | | | December 31, | | 2015 | | 2014 | Investment in ETP: | | | | Interstate transportation and storage operations | $ | 58 |
| | $ | 60 |
| Investment in Sunoco Logistics | 88 |
| | 41 |
| Retail marketing operations | 66 |
| | 87 |
| | $ | 212 |
| | $ | 188 |
|
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 $18 million and were reflected as property, plant and equipment on our balance sheet as of December 31, 2015 and 2014. In addition, Panhandle had $6 million legally restricted funds for the purpose of settling AROs that was reflected as other non-current assets as of December 31, 2015.
Accrued and Other Current Liabilities
Accrued and other current liabilities consisted of the following:
| | | | | | | | | | December 31, | | 2015 | | 2014 | Interest payable | $ | 519 |
| | $ | 440 |
| Customer advances and deposits | 114 |
| | 103 |
| Accrued capital expenditures | 743 |
| | 673 |
| Accrued wages and benefits | 218 |
| | 233 |
| Taxes payable other than income taxes | 76 |
| | 236 |
| Other | 632 |
| | 417 |
| Total accrued and other current liabilities | $ | 2,302 |
| | $ | 2,102 |
|
Deposits or advances are received from customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit.
Redeemable Noncontrolling Interests
The noncontrolling interest holders in one of Sunoco Logistics’ 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 the consolidated balance sheet.
Environmental Remediation
We accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in the range is accrued.
Fair Value of Financial Instruments The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value.
Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our consolidated debt obligations as of December 31, 2015 was $33.22 billion and $36.97 billion, respectively. As of December 31, 2014, the aggregate fair value and carrying amount of our consolidated debt obligations was $31.68 billion and $30.49 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.
. We have commodity derivatives, interest rate derivatives and embedded derivatives in the ETP Preferred Unitsour preferred units that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. Derivatives related to the embedded derivatives in our preferred units are valued using a binomial lattice model. The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected value, and are considered Levellevel 3. See further information on our fair value assets and liabilities in Note 2 of our consolidated financial statements. Impairment of Long-Lived Assets, Goodwill, Intangible Assets and Investments in Unconsolidated Affiliates. Long-lived assets are required to be tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. Goodwill and intangibles with indefinite lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be impaired. 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. An impairment loss should be recognized only if the carrying amount of the asset/goodwill is not recoverable and exceeds its fair value. In order to test for recoverability when performing a quantitative impairment test, we must make estimates of projected cash flows related to the asset, which include, but are not limited to, assumptions about the use or disposition of the asset, estimated remaining life of the asset, and future expenditures necessary to maintain the asset’s existing service potential. In order to determine fair
value, we make certain estimates and assumptions, including, among other things, changes in general economic conditions in regions in which our markets are located, the availability and prices of natural gas, our ability to negotiate favorable sales agreements, the risks that natural gas exploration and production activities will not occur or be successful, our dependence on certain significant customers and producers of natural gas, and competition from other companies, including major energy producers. While we believe we have made reasonable assumptions to calculate the fair value, if future results are not consistent with our estimates, we could be exposed to future impairment losses that could be material to our results of operations. The Partnership determined the fair value of its 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. One key assumption for the measurement of an impairment is management’s estimate of future cash flows and EBITDA. These estimates are based on the annual budget for the upcoming year and forecasted amounts for multiple subsequent years. The annual budget process is typically completed near the annual goodwill impairment testing date, and management uses the most recent information for the annual impairment tests. The forecast is also subjected to a comprehensive update annually in conjunction with the annual budget process and is revised periodically to reflect new information and/or revised expectations. The estimates of future cash flows and EBITDA are subjective in nature and are subject to impacts from the business risks described in “Item 1A. Risk Factors.” Therefore, the actual results could differ significantly from the amounts used for goodwill impairment testing, and significant changes in fair value estimates could occur in a given period. Such changes in fair value estimates could result in additional impairments in future periods; therefore, the actual results could differ significantly from the amounts used for goodwill impairment testing, and significant changes in fair value estimates could occur in a given period, resulting in additional impairments. Management does not believe that any of the goodwill balances in its reporting units is currently at significant risk of impairment; however, of the $4.89 billion of goodwill on the Partnership’s consolidated balance sheet as of December 31, 2018, approximately $650 million is recorded in reporting units for which the estimated fair value exceeded the carrying value by less than 20% in the most recent quantitative test. During the year ended December 31, 2015, no transfers were made2018, the Partnership recorded the following impairments: A $378 million impairment was recorded related to the goodwill associated with the Partnership’s Northeast operations within the midstream segment primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded. These changes in assumptions reflect delays in the construction of third-party takeaway capacity in the Northeast. Additionally, the Partnership recorded asset impairments of $4 million related to our midstream operations and asset impairments $9 million related to our crude operations idle leased assets. Sunoco LP also recognized a $30 million impairment charge on its contractual rights primarily due to decreases in projected future revenues and cash flows from the date the intangible asset was originally recorded. USAC also recognized a $9 million fixed asset impairment related to certain idle compressor assets. During the year ended December 31, 2017, the Partnership recorded the following impairments: a $223 million impairment was recorded related to the goodwill associated with CDM. In January 2018, the Partnership announced the contribution of CDM to USAC. Based on the Partnership’s anticipated proceeds in the contribution transaction, the implied fair value of the CDM reporting unit was less than the Partnership’s carrying value. As the Partnership believes that the contribution consideration also represented an appropriate estimate of fair value as of the 2017 annual impairment test date, the Partnership recorded an impairment for the difference between any levels withinthe carrying value and the fair value hierarchy.of the reporting unit. Subsequent to the impairment, a total of $253 million of goodwill remains in the CDM reporting unit, which amount is subject to further impairment based on changes in the contribution transaction prior to closing or any other factors
affecting the fair value of the CDM reporting unit. Assuming the contribution transaction closes, the remaining CDM goodwill balance will be derecognized; if the transaction does not close, then the CDM goodwill balance will remain on the Partnership’s consolidated balance sheet and will continue to be tested for impairment in the future. a $262 million impairment was recorded related to the goodwill associated with the Partnership’s interstate transportation and storage reporting units, and a $229 million impairment was recorded related to the goodwill associated with the general partner of Panhandle in the all other segment. These impairments were due to a reduction in management’s forecasted future cash flows from the related reporting units, which reduction reflected the impacts discussed in “Results of Operations” above, along with the impacts of re-contracting assumptions related to future periods. F - 21a $79 million impairment was recorded related to the goodwill associated the Partnership’s refined products transportation and services reporting unit. Subsequent to the Sunoco Logistics Merger, the Partnership restructured the internal reporting of legacy Sunoco Logistics’ business to be consistent with the internal reporting of legacy ETO. Subsequent to this reallocation the carrying value of certain refined products reporting units was less than the estimated fair value due to a reduction in management’s forecasted future cash flows from the related reporting units, and the goodwill associated with those reporting units was fully impaired. No goodwill remained in the respective reporting units subsequent to the impairment.
Tablea $127 million impairment of Contentsproperty, plant and equipment 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.a $141 million impairment of the Partnership’s equity method investment in FEP. The Partnership concluded that the carrying value of its investment in FEP was other than temporarily impaired based on an anticipated decrease in production in the Fayetteville basin and a customer re-contracting with a competitor during 2017. a $172 million impairment of the Partnership’s equity method investment in HPC primarily due to a decrease in projected future revenues and cash flows driven be 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. For 2017, Sunoco LP also recognized impairments of $404 million, of which $119 million was allocated to continuing operations, as discussed further below. During the year ended December 31, 2016, the Partnership recorded the following impairments: a $638 million goodwill impairment and a $133 million impairment to property, plant and equipment were recorded in the interstate transportation and storage segment primarily due to decreases in projected future revenues and cash flows driven by changes in the markets that these assets serve. a $32 million goodwill impairment was recorded in the midstream segment primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices. a $308 million impairment of the Partnership’s equity method investment in MEP. The Partnership concluded that the carrying value of its investment in MEP was other than temporarily impaired based on commercial discussions with current and potential shippers on MEP during 2016, which negatively affected the outlook for long-term transportation contract rates. For 2016, Sunoco LP also recognized impairments of $641 million, of which $227 million was allocated to continuing operations, as discussed further below. Except for the 2017 impairment of the goodwill associated with CDM, as discussed above, the goodwill impairments recorded by the Partnership during the years ended December 31, 2018, 2017 and 2016 represented all of the goodwill within the respective reporting units. During 2017, Sunoco LP announced the sale of a majority of the assets in its retail and Stripes reporting units. These reporting units include the retail operations in the continental United States but excludes the retail convenience store operations in Hawaii that comprise the Aloha reporting unit. Upon the classification of assets and related liabilities as held for sale, Sunoco LP’s management applied the measurement guidance in ASC 360, Property, Plant and Equipment, to calculate the fair value less cost to sell of the disposal group. In accordance with ASC 360-10-35-39, Sunoco LP’s management first tested the goodwill included within the disposal group for impairment prior to measuring the disposal group’s fair value less the cost to sell. In the determination of the classification of assets held for sale and the related liabilities, Sunoco LP’s management allocated a portion of the goodwill balance previously included in the Sunoco LP retail and Stripes reporting units to assets held for sale based on the relative fair values of the business to be disposed of and the portion of the respective reporting unit that will be retained in accordance with ASC 350-20-40-3.
Sunoco LP recognized goodwill impairments of $387 million in 2017, of which $102 million was allocated to continuing operations,primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded. Additionally, 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 primarily due to decreases in projected future revenues and cash flows from the date the intangible asset was originally recorded. For the year ended December 31, 2016, 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. Property, Plant and Equipment. 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 the consolidated statement of operations. Depreciation of property, plant and equipment is provided using the straight-line method based on their estimated useful lives ranging from 1 to 99 years. Changes in the estimated useful lives of the assets could have a material effect on our results of operation. We do not anticipate future changes in the estimated useful lives of our property, plant and equipment. 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, 2018 and 2017, 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 AROs 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 AROs related to Sunoco, Inc.’s pipeline assets and storage tanks, for which it is not possible to estimate whether or when the AROs will be settled. Consequently, these AROs cannot be measured at this time. Sunoco LP has AROs related to the estimated future cost to remove underground storage tanks. 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 $106 million and $103 million and were reflected as property, plant and equipment on our consolidated balance sheet as of December 31, 2018 and 2017, respectively. In addition, other non-current assets on the Partnership’s consolidated balance sheet included $26 million and $21 million of legally restricted funds for the purpose of settling AROs as of December 31, 2018 and 2017, respectively.
Pensions and Other Postretirement Benefit Plans. We are required to measure plan assets and benefit obligations as of its fiscal year-end balance sheet date. We recognize the changes in the funded status of our defined benefit postretirement plans through AOCI or are reflected as a regulatory asset or regulatory liability for regulated subsidiaries. The calculation of the net periodic benefit cost and benefit obligation requires the use of a number of assumptions. Changes in these assumptions can have a significant effect on the amounts reported in the financial statements. The Partnership believes that the two most critical assumptions are the assumed discount rate and the expected rate of return on plan assets. The discount rate is established by using a hypothetical portfolio of high-quality debt instruments that would provide the necessary cash flows to pay the benefits when due. Net periodic benefit cost and benefit obligation increases and equity correspondingly decreases as the discount rate is reduced. The expected rate of return on plan assets is based on long-term expectations given current investment objectives and historical results. Net periodic benefit cost increases as the expected rate of return on plan assets is correspondingly reduced. Legal Matters.We are subject to litigation and regulatory proceedings as a result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from claims, orders, judgments or settlements. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. We expense legal costs as incurred, and all recorded legal liabilities are revised as required as better information becomes available to us. The factors we consider when recording an accrual for contingencies include, among others: (i) the opinions and views of our legal counsel; (ii) our previous experience; and (iii) the decision of our management as to how we intend to respond to the complaints. For more information on our litigation and contingencies, see Note 11 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” in this report. Environmental Remediation Activities. The followingPartnership’s accrual for environmental remediation activities reflects anticipated work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. The accrual for known claims is undiscounted and is based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. It is often extremely difficult to develop reasonable estimates of future site remediation costs due to changing regulations, changing technologies and their associated costs, and changes in the economic environment. Engineering studies, historical experience and other factors are used to identify and evaluate remediation alternatives and their related costs in determining the estimated accruals for environmental remediation activities. Losses attributable to unasserted claims are generally reflected in the accruals on an undiscounted basis, to the extent they are probable of occurrence and reasonably estimable. ETO has 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, ETO accrues losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company. In general, each remediation site/issue is evaluated individually based upon information available for the site/issue and no pooling or statistical analysis is used to evaluate an aggregate risk for a group of similar items (e.g., service station sites) in determining the amount of probable loss accrual to be recorded. ETO’s estimates of environmental remediation costs also frequently involve evaluation of a range of estimates. In many cases, it is difficult to determine that one point in the range of loss estimates is more likely than any other. In these situations, existing accounting guidance requires that the minimum of the range be accrued. Accordingly, the low end of the range often represents the amount of loss which has been recorded. The Partnership’s consolidated balance sheet reflected $337 million in environmental accruals as of December 31, 2018. Total future costs for environmental remediation activities will depend upon, among other things, the identification of any additional sites, the determination of the extent of the contamination at each site, the timing and nature of required remedial actions, the nature of operations at each site, the technology available and needed to meet the various existing legal requirements, the nature and terms of cost-sharing arrangements with other potentially responsible parties, the availability of insurance coverage, the nature and extent of future environmental laws and regulations, inflation rates, terms of consent agreements or remediation permits with regulatory agencies and the determination of the Partnership’s liability at the sites, if any, in light of the number, participation level and financial viability of the other parties. The recognition of additional losses, if and when they were to occur, would likely extend over many years. Management believes that the Partnership’s exposure to adverse developments with respect to any individual site is not expected to be material. However, if changes in environmental laws or regulations occur or the assumptions used to estimate losses at multiple sites are adjusted, such changes could impact multiple facilities, formerly owned facilities and third-party sites at the same time. As a result, from time to time, significant charges against income for environmental remediation may
occur; however, management does not believe that any such charges would have a material adverse impact on the Partnership’s consolidated financial position. Deferred Income Taxes. ET recognizes benefits in earnings and related deferred tax assets for net operating loss carryforwards (“NOLs”) and tax credit carryforwards. If necessary, a charge to earnings and a related valuation allowance are recorded to reduce deferred tax assets to an amount that is more likely than not to be realized by the Partnership in the future. Deferred income tax assets attributable to state and federal NOLs and federal tax alternative minimum tax credit carryforwards totaling $768 million have been included in ET’s consolidated balance sheet as of December 31, 2018. The state NOL carryforward benefits of $213 million ($168 million net of federal benefit) begin to expire in 2019 with a substantial portion expiring between 2032 and 2038. The federal NOLs of $2.60 billion ($546 million in benefits) will expire in 2031 and 2037 if attributable to tax years prior to 2018. Any federal NOL generated in 2018 and future years can be carried forward indefinitely. Federal alternative minimum tax credit carryforwards of $31 million remained at December 31, 2018. We have determined that a valuation allowance totaling $124 million ($98 million net of federal income tax effects) is required for the state NOLs at December 31, 2018 primarily due to significant restrictions on their use in the Commonwealth of Pennsylvania. In making the assessment of the future realization of the deferred tax assets, we rely on future reversals of existing taxable temporary differences, tax planning strategies and forecasted taxable income based on historical and projected future operating results. The potential need for valuation allowances is regularly reviewed by management. If it is more likely than not that the recorded asset will not be realized, additional valuation allowances which increase income tax expense may be recognized in the period such determination is made. Likewise, if it is more likely than not that additional deferred tax assets will be realized, an adjustment to the deferred tax asset will increase income in the period such determination is made. Forward-Looking Statements This annual report contains various forward-looking statements and information that are based on our beliefs and those of our General Partner, as well as assumptions made by and information currently available to us. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. When used in this annual report, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “could,” “believe,” “may,” “will” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our General Partner believe that the expectations on which such forward-looking statements are based are reasonable, neither we nor our General Partner can give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Among the key risk factors that may have a direct bearing on our results of operations and financial condition are: the ability of our subsidiaries to make cash distributions to us, which is dependent on their results of operations, cash flows and financial condition; the actual amount of cash distributions by our subsidiaries to us; the volumes transported on our subsidiaries’ pipelines and gathering systems; the level of throughput in our subsidiaries’ processing and treating facilities; the fees our subsidiaries charge and the margins they realize for their gathering, treating, processing, storage and transportation services; the prices and market demand for, and the relationship between, natural gas and NGLs; energy prices generally; the prices of natural gas and NGLs compared to the price of alternative and competing fuels; the general level of petroleum product demand and the availability and price of NGL supplies; the level of domestic oil, natural gas and NGL production; the availability of imported oil, natural gas and NGLs; actions taken by foreign oil and gas producing nations; the political and economic stability of petroleum producing nations;
the effect of weather conditions on demand for oil, natural gas and NGLs; availability of local, intrastate and interstate transportation systems; the continued ability to find and contract for new sources of natural gas supply; availability and marketing of competitive fuels; the impact of energy conservation efforts; energy efficiencies and technological trends; governmental regulation and taxation; changes to, and the application of, regulation of tariff rates and operational requirements related to our subsidiaries’ interstate and intrastate pipelines; hazards or operating risks incidental to the gathering, treating, processing and transporting of natural gas and NGLs; competition from other midstream companies and interstate pipeline companies; loss of key personnel; loss of key natural gas producers or the providers of fractionation services; reductions in the capacity or allocations of third-party pipelines that connect with our subsidiaries pipelines and facilities; the effectiveness of risk-management policies and procedures and the ability of our subsidiaries liquids marketing counterparties to satisfy their financial commitments; the nonpayment or nonperformance by our subsidiaries’ customers; regulatory, environmental, political and legal uncertainties that may affect the timing and cost of our subsidiaries’ internal growth projects, such as our subsidiaries’ construction of additional pipeline systems; risks associated with the construction of new pipelines and treating and processing facilities or additions to our subsidiaries’ existing pipelines and facilities, including difficulties in obtaining permits and rights-of-way or other regulatory approvals and the performance by third-party contractors; the availability and cost of capital and our subsidiaries’ ability to access certain capital sources; a deterioration of the credit and capital markets; risks associated with the assets and operations of entities in which our subsidiaries own less than a controlling interests, including risks related to management actions at such entities that our subsidiaries may not be able to control or exert influence; the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results and to successfully integrate acquired businesses; changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations or new interpretations by regulatory agencies concerning such laws and regulations; and the costs and effects of legal and administrative proceedings. You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risks described under “Item 1A. Risk Factors” in this annual report. Any forward-looking statement made by us in this Annual Report on Form 10-K is based only on information currently available to us and speaks only as of the date on which it is made. We undertake no obligation to publicly update any forward-looking statement, whether written or oral, that may be made from time to time, whether as a result of new information, future developments or otherwise. Inflation Interest rates on existing and future credit facilities and future debt offerings could be significantly higher than current levels, causing our financing costs to increase accordingly. Although increased financing costs could limit our ability to raise funds in
the capital markets, we expect to remain competitive with respect to acquisitions and capital projects since our competitors would face similar circumstances. Inflation in the United States has been relatively low in recent years and has not had a material effect on our results of operations. It may in the future, however, increase the cost to acquire or replace property, plant and equipment and may increase the costs of labor and supplies. Our operating revenues and costs are influenced to a greater extent by commodity price changes. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along a portion of increased costs to our customers in the form of higher fees. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (Tabular dollar amounts are in millions) Market risk includes the risk of loss arising from adverse changes in market rates and prices. We face market risk from commodity variations, risk and interest rate variations, and to a lesser extent, credit risks. From time to time, we may utilize derivative financial instruments as described below to manage our exposure to such risks. 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 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. 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 tables below summarize commodity-related financial derivative instruments, fair values and the effect of an assumed hypothetical 10% change in the underlying price of the commodity as of December 31, 2018 and 2017 for ETO and Sunoco LP, including derivatives related to their respective subsidiaries. Dollar amounts are presented in millions. | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2018 | | December 31, 2017 | | Notional Volume | | Fair Value Asset (Liability) | | Effect of Hypothetical 10% Change | | Notional Volume | | Fair Value Asset (Liability) | | Effect of Hypothetical 10% Change | Mark-to-Market Derivatives | | | | | | | | | | | | (Trading) | | | | | | | | | | | | Natural Gas (BBtu): | | | | | | | | | | | | Fixed Swaps/Futures | 468 |
| | $ | — |
| | $ | — |
| | 1,078 |
| | $ | — |
| | $ | — |
| Basis Swaps IFERC/NYMEX(1) | 16,845 |
| | 7 |
| | 1 |
| | 48,510 |
| | 2 |
| | 1 |
| Options – Puts | 10,000 |
| | — |
| | — |
| | 13,000 |
| | — |
| | — |
| Power (Megawatt): | | | | | | | | | | | | Forwards | 3,141,520 |
| | 6 |
| | 8 |
| | 435,960 |
| | 1 |
| | 1 |
| Futures | 56,656 |
| | — |
| | — |
| | (25,760 | ) | | — |
| | — |
| Options – Puts | 18,400 |
| | — |
| | — |
| | (153,600 | ) | | — |
| | 1 |
| Options – Calls | 284,800 |
| | 1 |
| | — |
| | 137,600 |
| | — |
| | — |
| Crude (MBbls) – Futures | — |
| | — |
| | — |
| | — |
| | 1 |
| | — |
| (Non-Trading) | | | | | | | | | | | | Natural Gas (BBtu): | | | | | | | | | | | | Basis Swaps IFERC/NYMEX | (30,228 | ) | | (52 | ) | | 13 |
| | 4,650 |
| | (13 | ) | | 4 |
| Swing Swaps IFERC | 54,158 |
| | 12 |
| | — |
| | 87,253 |
| | (2 | ) | | 1 |
| Fixed Swaps/Futures | (1,068 | ) | | 19 |
| | 1 |
| | (4,390 | ) | | (1 | ) | | 2 |
| Forward Physical Contracts | (123,254 | ) | | (1 | ) | | 32 |
| | (145,105 | ) | | 6 |
| | 41 |
| NGL (MBbls) – Forwards/Swaps | (2,135 | ) | | 67 |
| | 67 |
| | (2,493 | ) | | 5 |
| | 16 |
| Crude (MBbls) – Forwards/Swaps | 20,888 |
| | (60 | ) | | 29 |
| | 9,237 |
| | (4 | ) | | 9 |
| Refined Products (MBbls) – Futures | (1,403 | ) | | (8 | ) | | 6 |
| | (3,901 | ) | | (27 | ) | | 4 |
| Corn (thousand bushels) | (1,920 | ) | | — |
| | 1 |
| | 1,870 |
| | — |
| | — |
| Fair Value Hedging Derivatives | | | | | | | | | | | | (Non-Trading) | | | | | | | | | | | | Natural Gas (BBtu): | | | | | | | | | | | | Basis Swaps IFERC/NYMEX | (17,445 | ) | | (4 | ) | | — |
| | (39,770 | ) | | (2 | ) | | — |
| Fixed Swaps/Futures | (17,445 | ) | | (10 | ) | | 6 |
| | (39,770 | ) | | 14 |
| | 11 |
|
(1) Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations. The fair values of the commodity-related financial positions have been determined using independent third-party prices, readily available market information and appropriate valuation techniques. Non-trading positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the below tables. Price-risk sensitivities were calculated by assuming a theoretical 10% change (increase or decrease) in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. Results are presented in absolute terms and represent a potential gain or loss in net income or in other comprehensive income. In the event of an actual 10% change in prompt month natural gas prices, the fair value of our total derivative portfolios may not change by 10% due to factors such as when the financial assetsinstrument settles and liabilities measuredthe location to which the financial instrument is tied (i.e., basis swaps) and recorded at fair valuethe relationship between prompt month and forward months. Interest Rate Risk As of December 31, 2018, we and our subsidiaries had $9.76 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of $98 million annually; however, our actual
change in interest expense may be less in a given period due to interest rate floors included in our variable rate debt instruments. We manage a portion of our interest rate exposure by utilizing interest rate swaps, including forward-starting interest rate swaps to lock-in the rate on a recurring basisportion of anticipated debt issuances. The following table summarizes our interest rate swaps outstanding, none of which were designated as of hedges for accounting purposes (dollar amounts presented in millions):December 31, 2015 and 2014 based on inputs used to derive their fair values:
| | | | | | | | | | | | | | | | | | Fair Value Measurements at December 31, 2015 | | Fair Value Total | | Level 1 | | Level 2 | | Level 3 | Assets: | | | | | | | | Interest rate derivatives | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| Commodity derivatives: | | | | | | | | Natural Gas: | | | | | | | | Basis Swaps IFERC/NYMEX | 16 |
| | 16 |
| | — |
| | — |
| Swing Swaps IFERC | 10 |
| | 2 |
| | 8 |
| | — |
| Fixed Swaps/Futures | 274 |
| | 274 |
| | — |
| | — |
| Forward Physical Swaps | 4 |
| | — |
| | 4 |
| | — |
| Power: | | | | | | | | Forwards | 22 |
| | — |
| | 22 |
| | — |
| Futures | 3 |
| | 3 |
| | — |
| | — |
| Options — Calls | 1 |
| | 1 |
| | — |
| | — |
| Options — Puts | 1 |
| | 1 |
| | — |
| | — |
| Natural Gas Liquids — Forwards/Swaps | 99 |
| | 99 |
| | — |
| | — |
| Refined Products – Futures | 15 |
| | 15 |
| | — |
| | — |
| Crude – Futures | 9 |
| | 9 |
| | — |
| | — |
| Total commodity derivatives | 454 |
| | 420 |
| | 34 |
| | — |
| Total assets | $ | 454 |
| | $ | 420 |
| | $ | 34 |
| | $ | — |
| Liabilities: | | | | | | | | Interest rate derivatives | $ | (171 | ) | | $ | — |
| | $ | (171 | ) | | $ | — |
| Embedded derivatives in the ETP Preferred Units | (5 | ) | | — |
| | — |
| | (5 | ) | Commodity derivatives: | | | | | | | | Natural Gas: | | | | | | | | Basis Swaps IFERC/NYMEX | (16 | ) | | (16 | ) | | — |
| | — |
| Swing Swaps IFERC | (12 | ) | | (2 | ) | | (10 | ) | | — |
| Fixed Swaps/Futures | (203 | ) | | (203 | ) | | — |
| | — |
| Power: | | | | | | | | Forwards | (22 | ) | | — |
| | (22 | ) | | — |
| Futures | (2 | ) | | (2 | ) | | — |
| | — |
| Options — Puts | (1 | ) | | (1 | ) | | — |
| | — |
| Natural Gas Liquids — Forwards/Swaps | (89 | ) | | (89 | ) | | — |
| | — |
| Refined Products – Futures | (6 | ) | | (6 | ) | | — |
| | — |
| Crude — Futures | (5 | ) | | (5 | ) | | — |
| | — |
| Total commodity derivatives | (356 | ) | | (324 | ) | | (32 | ) | | — |
| Total liabilities | $ | (532 | ) | | $ | (324 | ) | | $ | (203 | ) | | $ | (5 | ) |
| | | | | | | | | | | | Term | | Type(1) | | Notional Amount Outstanding | December 31, 2018 | | December 31, 2017 | July 2018 (2) | | Forward-starting to pay a fixed rate of 3.76% and receive a floating rate | | $ | — |
| | $ | 300 |
| July 2019 (2) | | Forward-starting to pay a fixed rate of 3.56% and receive a floating rate | | 400 |
| | 300 |
| July 2020 (2) | | Forward-starting to pay a fixed rate of 3.52% and receive a floating rate | | 400 |
| | 400 |
| July 2021 (2) | | Forward-starting to pay a fixed rate of 3.55% and receive a floating rate | | 400 |
| | — |
| December 2018 | | Pay a floating rate and receive a fixed rate of 1.53% | | — |
| | 1,200 |
| March 2019 | | Pay a floating rate 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. |
A hypothetical change of 100 basis points in interest rates for these interest rate swaps would result in a change in the fair value of the interest rate derivatives and earnings (recognized in gains (losses) on interest rate derivatives) of approximately $259 million as of December 31, 2018. For ETO’s $300 million of interest rate swaps whereby it pays a floating rate and receives a fixed rate, a hypothetical change of 100 basis points in interest rates would result in a net change in annual cash flow of less than $1 million. For the forward-starting interest rate swaps, a hypothetical change of 100 basis points in interest rates would not affect cash flows until the swaps are settled. F - 22Credit 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 industrial end-users, 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. 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. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The financial statements starting on page F-1 of this report are incorporated by reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. ITEM 9A. CONTROLS AND PROCEDURES Evaluation of ContentsDisclosure Controls and Procedures An evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rules 13a–15(e) and 15d–15(e) of the Exchange Act) as of the end of the period covered by this report. Based upon that evaluation, management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, concluded that our disclosure controls and procedures were adequate and effective as of December 31, 2018. Management’s Report on Internal Control over Financial Reporting The management of Energy Transfer LP and subsidiaries is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in the 2013 Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO Framework”). Based on our evaluation under the COSO framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2018. Grant Thornton LLP, an independent registered public accounting firm, has audited the effectiveness of our internal control over financial reporting as of December 31, 2018, as stated in their report, which is included herein.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Board of Directors of LE GP, LLC and Unitholders of Energy Transfer LP Opinion on internal control over financial reporting We have audited the internal control over financial reporting of Energy Transfer LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2018, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in the 2013 Internal Control-Integrated Framework issued by COSO. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Partnership as of and for the year ended December 31, 2018, and our report dated February 22, 2019 expressed an unqualified opinion on those financial statements. Basis for opinion The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. 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 audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. Definition and limitations of internal control over financial reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. /s/ GRANT THORNTON LLP Dallas, Texas February 22, 2019
Changes in Internal Controls over Financial Reporting There has been no change in our internal controls over financial reporting (as defined in Rules 13a–15(f) or Rule 15d–15(f)) that occurred in the three months ended December 31, 2018 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.
ITEM 9B. OTHER INFORMATION | | | | | | | | | | | | | | | | | | 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 ETP 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 | ) |
None.
PART III ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE Board of Directors Our general partner, LE GP, LLC, manages and directs all of our activities. The officers and directors of ET are officers and directors of LE GP, LLC. The members of our general partner elect our general partner’s Board of Directors. The board of directors of our general partner has the authority to appoint our executive officers, subject to provisions in the limited liability company agreement of our general partner. Pursuant to other authority, the board of directors of our general partner may appoint additional management personnel to assist in the management of our operations and, in the event of the death, resignation or removal of our chief executive officer, to appoint a replacement. As of December 31, 2018, our Board of Directors was comprised of eight persons, three of whom qualify as “independent” under the NYSE’s corporate governance standards. We have determined that Messrs. Brannon, Anderson and Grimm are all “independent” under the NYSE’s corporate governance standards. As a limited partnership, we are not required by the rules of the NYSE to seek unitholder approval for the election of any of our directors. We believe that the members of our general partner have appointed as directors individuals with experience, skills and qualifications relevant to the business of the Parent Company, such as experience in energy or related industries or with financial markets, expertise in natural gas operations or finance, and a history of service in senior leadership positions. We do not have a formal process for identifying director nominees, nor do we have a formal policy regarding consideration of diversity in identifying director nominees, but we believe that the members of our general partner have endeavored to assemble a group of individuals with the qualities and attributes required to provide effective oversight of the Parent Company. Risk Oversight Our Board of Directors generally administers its risk oversight function through the board as a whole. Our Chief Executive Officer, who reports to the Board of Directors, has day-to-day risk management responsibilities. Our Chief Executive Officer attends the meetings of our Board of Directors, where the Board of Directors routinely receives reports on our financial results, the status of our operations, and other aspects of implementation of our business strategy, with ample opportunity for specific inquiries of management. In addition, at each regular meeting of the Board, management provides a report of the Parent Company’s financial and operational performance, which often prompts questions or feedback from the Board of Directors. The Audit Committee provides additional risk oversight through its quarterly meetings, where it receives a report from the Parent Company’s internal auditor, who reports directly to the Audit Committee, and reviews the Parent Company’s contingencies with management and our independent auditors. Corporate Governance The Board of Directors has adopted both a Code of Business Conduct and Ethics applicable to our directors, officers and employees, and Corporate Governance Guidelines for directors and the Board. Current copies of our Code of Business Conduct and Ethics, Corporate Governance Guidelines and charters of the Audit and Compensation Committees of our Board of Directors are available on our website at www.energytransfer.com and will be provided in print form to any Unitholder requesting such information. Please note that the preceding Internet address is for information purposes only and is not intended to be a hyperlink. Accordingly, no information found and/or provided at such Internet addresses or at our website in general is intended or deemed to be incorporated by reference herein. Annual Certification In 2018, our Chief Executive Officer provided to the NYSE the annual CEO certification regarding our compliance with the NYSE’s corporate governance listing standards. Conflicts Committee Our Partnership Agreement provides that the Board of Directors may, from time to time, appoint members of the Board to serve on the Conflicts Committee with the authority to review specific matters for which the Board of Directors believes there may be a conflict of interest in order to determine if the resolution of such conflict proposed by the general partner is fair and reasonable to the Parent Company and our Unitholders. As a policy matter, the Conflicts Committee generally reviews any proposed related-party transaction that may be material to the Parent Company to determine if the transaction presents a conflict of interest and whether the transaction is fair and reasonable to the Parent Company. Pursuant to the terms of our partnership agreement, any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to the Parent Company,
approved by all partners of the Parent Company and not a breach by the general partner or its Board of Directors of any duties they may owe the Parent Company or the Unitholders. These duties are limited by our Partnership Agreement (see “Risks Related to Conflicts of Interest” in “Item 1A. Risk Factors” in this annual report). Audit Committee The Board of Directors has established an Audit Committee in accordance with Section 3(a)(58)(A) of the Exchange Act. The Board of Directors appoints persons who are independent under the NYSE’s standards for audit committee members to serve on its Audit Committee. In addition, the Board determines that at least one member of the Audit Committee has such accounting or related financial management expertise sufficient to qualify such person as the audit committee financial expert in accordance with Item 407(d)(5) of Regulation S-K. The Board determined that based on relevant experience, Audit Committee member Michael K. Grimm qualified as an audit committee financial expert during 2018. A description of the qualifications of Mr. Grimm may be found elsewhere in this Item 10 under “Directors and Executive Officers of the General Partner.” The Audit Committee meets on a regularly scheduled basis with our independent accountants at least four times each year and is available to meet at their request. The Audit Committee has the authority and responsibility to review our external financial reporting, review our procedures for internal auditing and the adequacy of our internal accounting controls, consider the qualifications and independence of our independent accountants, engage and direct our independent accountants, including the letter of engagement and statement of fees relating to the scope of the annual audit work and special audit work which may be recommended or required by the independent accountants, and to engage the services of any other advisors and accountants as the Audit Committee deems advisable. The Audit Committee reviews and discusses the audited financial statements with management, discusses with our independent auditors matters required to be discussed by auditing standards, and makes recommendations to the Board of Directors relating to our audited financial statements. The Audit Committee periodically recommends to the Board of Directors any changes or modifications to its charter that may be required. The Audit Committee has received written disclosures and the letter from Grant Thornton required by applicable requirements of the Audit Committee concerning independence and has discussed with Grant Thornton that firm’s independence. The Audit Committee recommended to the Board that the audited financial statements of ET be included in ET’s Annual Report on Form 10-K for the year ended December 31, 2018. The Board of Directors adopts the charter for the Audit Committee. Steven R. Anderson, Richard D. Brannon and Michael K. Grimm serve as elected members of the Audit Committee. Compensation and Nominating/Corporate Governance Committees Although we are not required under NYSE rules to appoint a Compensation Committee or a Nominating/Corporate Governance Committee because we are a limited partnership, the Board of Directors of LE GP, LLC has previously established a Compensation Committee to establish standards and make recommendations concerning the compensation of our officers and directors. In addition, the Compensation Committee determines and establishes the standards for any awards to our employees and officers under the equity compensation plans, including the performance standards or other restrictions pertaining to the vesting of any such awards. Messrs. Anderson and Grimm serve as members of the Compensation Committee. Matters relating to the nomination of directors or corporate governance matters were addressed to and determined by the full Board of Directors for the period ET did not have a compensation committee. The responsibilities of the ET Compensation Committee include, among other duties, the following: annually review and approve goals and objectives relevant to compensation of our CEO and CFO, if applicable; annually evaluate the CEO and CFO’s performance in light of these goals and objectives, and make recommendations to the Board of Directors with respect to the CEO and CFO’s compensation levels, if applicable, based on this evaluation; make determinations with respect to the grant of equity-based awards to executive officers under ET’s equity incentive plans; periodically evaluate the terms and administration of ET’s long-term incentive plans to assure that they are structured and administered in a manner consistent with ET’s goals and objectives; periodically evaluate incentive compensation and equity-related plans and consider amendments if appropriate; periodically evaluate the compensation of the directors; retain and terminate any compensation consultant to be used to assist in the evaluation of director, CEO and CFO or executive officer compensation; and
perform other duties as deemed appropriate by the Board of Directors. Code of Business Conduct and Ethics The Board of Directors has adopted a Code of Business Conduct and Ethics applicable to our officers, directors and employees. Specific provisions are applicable to the principal executive officer, principal financial officer, principal accounting officer and controller, or those persons performing similar functions, of our general partner. Amendments to, or waivers from, the Code of Business Conduct and Ethics will be available on our website and reported as may be required under SEC rules. Any technical, administrative or other non-substantive amendments to the Code of Business Conduct and Ethics may not be posted. Meetings of Non-management Directors and Communications with Directors Our non-management directors meet in regularly scheduled sessions. Our non-management directors alternate as the presiding director of such meetings. We have established a procedure by which Unitholders or interested parties may communicate directly with the Board of Directors, any committee of the Board, any of the independent directors, or any one director serving on the Board of Directors by sending written correspondence addressed to the desired person, committee or group to the attention of Sonia Aubé at Energy Transfer LP 8111 Westchester Drive, Suite 600, Dallas, Texas, 75225. Communications are distributed to the Board of Directors, or to any individual director or directors as appropriate, depending on the facts and circumstances outlined in the communication. Directors and Executive Officers of Our General Partner The following table presentssets forth certain information with respect to the material unobservable inputs used to estimateexecutive officers and members of the fair valueBoard of ETP’s Preferred UnitsDirectors of our general partner as of February 22, 2019. Executive officers and the embedded derivatives in ETP’s Preferred Units:directors are elected for indefinite terms. | | | | | | | | Unobservable InputName | | December 31, 2015 | Embedded derivatives in the ETP Preferred Units | Credit SpreadAge | | 5.33 | %Position with Our General Partner | | VolatilityKelcy L. Warren | | 37.0063 | %
| | Chief Executive Officer and Chairman of the Board (Principal Executive Officer) | Thomas E. Long | | 62 |
| | Chief Financial Officer (Principal Financial Officer) | Marshall S. (Mackie) McCrea, III | | 59 |
| | President, Chief Commercial Officer and Director | Matthew S. Ramsey | | 63 |
| | Chief Operating Officer and Director | Thomas P. Mason | | 62 |
| | Executive Vice President, General Counsel and President - LNG | John W. McReynolds | | 68 |
| | Special Advisor and Director | A. Troy Sturrock | | 48 |
| | Senior Vice President and Controller (Principal Accounting Officer) | Ray C. Davis | | 77 |
| | Director | Steven R. Anderson | | 69 |
| | Director | Richard D. Brannon | | 60 |
| | Director | Michael K. Grimm | | 64 |
| | Director |
ChangesMessrs. Warren, Ramsey and McCrea also serve as directors of ETO’s general partner. Mr. Ramsey serves as director of the general partner of Sunoco LP.
Set forth below is biographical information regarding the foregoing officers and directors of our general partner: Kelcy L. Warren. Mr. Warren serves as Chairman and Chief Executive Officer of our general partner. He was appointed Co-Chairman of the Board of Directors of our general partner, effective upon the closing of our IPO, and in August 2007, he became the sole Chairman of the Board of our general partner and the Chief Executive Officer and Chairman of the Board of the general partner of ETO. Prior to that, Mr. Warren had served as Co-Chief Executive Officer and Co-Chairman of the Board of the general partner of ETO since the combination of the midstream and intrastate transportation storage operations of ETC OLP and the retail propane operations of Heritage in January 2004. Mr. Warren also served as the Chief Executive Officer of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Prior to the combination of the operations of ETO and Heritage Propane, Mr. Warren served as President of the general partner of ET Company I, Ltd. the entity that operated ETO’s midstream assets before it acquired Aquila, Inc.’s midstream assets, having served in that capacity since 1996. From 1996 to 2000, he also served as a Director of Crosstex Energy, Inc. From 1993 to 1996, he served as President, Chief Operating Officer and a Director of Cornerstone Natural Gas, Inc. Mr. Warren has more than 30 years of business experience in the remaining termenergy industry. The members of our general partner selected Mr. Warren to serve as a director and as Chairman because he is ETO’s Chief Executive Officer and has more than 30 years in the natural gas industry. Mr. Warren also has relationships with chief executives and other senior
management at natural gas transportation companies throughout the United States, and brings a unique and valuable perspective to the Board of Directors. Thomas E. Long. Mr. Long has served as the Chief Financial Officer of our general partner since February 2016. Mr. Long also served as the Chief Financial Officer and as a director of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Long also serves as Chief Financial Officer of ETO and was previously Executive Vice President and Chief Financial Officer of Regency GP LLC from November 2010 to April 2015. From May 2008 to November 2010, Mr. Long served as Vice President and Chief Financial Officer of Matrix Service Company. Prior to joining Matrix, he served as Vice President and Chief Financial Officer of DCP Midstream Partners, LP, a publicly traded natural gas and natural gas liquids midstream business company located in Denver, CO. In that position, he was responsible for all financial aspects of the Preferred Units, U.S. Treasury yieldscompany since its formation in December 2005. From 1998 to 2005, Mr. Long served in several executive positions with subsidiaries of Duke Energy Corp., one of the nation’s largest electric power companies. Mr. Long has served as a director of Sunoco LP since May 2016, and valuationsas Chairman of the Board of USAC since April 2018. Marshall S. (Mackie) McCrea, III. Mr. McCrea is the President and Chief Commercial Officer of our general partner, having served in related instruments would causethat role since October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. Prior to that time, he had been the Group Chief Operating Officer and Chief Commercial Officer of the Energy Transfer family since November 2015. Mr. McCrea has served on the Board of Directors of our general partner since December 2009. Mr. McCrea was appointed as a changedirector of the general partner of ETO in December 2009. Prior to that, he served as President and Chief Operating Officer of ETO’s general partner from June 2008 to November 2015 and President – Midstream from March 2007 to June 2008. Previously he served as the Senior Vice President – Commercial Development since January 2004. In March 2005, Mr. McCrea was named President of La Grange Acquisition LP, ETO’s primary operating subsidiary, after serving as Senior Vice President-Business Development and Producer Services since 1997. Mr. McCrea also served as the Chairman of the Board of Directors of the general partner of Sunoco Logistics from October 2012 to April 2017. The members of our general partner selected Mr. McCrea to serve as a director because he brings extensive project development and operational experience to the Board. He has held various positions in the yieldnatural gas business over the past 25 years and is able to valueassist the Preferred Units. ChangesBoard of Directors in ETP’s costcreating and executing the Partnership’s strategic plan. Matthew S. Ramsey. Mr. Ramsey was appointed as a director of equityET’s general partner in July 2012 and U.S. Treasury yields would causeas a changedirector of ETO’s general partner in November 2015. Mr. Ramsey has been the Chief Operating Officer or our general partner since October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P., and currently serves as President and Chief Operating Officer of ETO’s general partner since November 2015. Mr. Ramsey also served as President and Chief Operating Officer and Chairman of the board of directors of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Ramsey is also a director of Sunoco LP, having served as chairman of Sunoco LP’s board since April 2015, and of USAC, having served on that board since April 2018. Mr. Ramsey previously served as President of RPM Exploration, Ltd., a private oil and gas exploration partnership, and previously served as a director of RSP Permian, Inc. where he served on the audit and compensation committees. Mr. Ramsey formerly served as President of DDD Energy, Inc. until its sale in 2002. From 1996 to 2000, Mr. Ramsey served as President and Chief Executive Officer of OEC Compression Corporation, Inc., a publicly traded oil field service company, providing gas compression services to a variety of energy clients. Previously, Mr. Ramsey served as Vice President of Nuevo Energy Company, an independent energy company. Additionally, he was employed by Torch Energy Advisors, Inc., a company providing management and operations services to energy companies including Nuevo Energy, last serving as Executive Vice President. Mr. Ramsey joined Torch Energy as Vice President of Land and was named Senior Vice President of Land in 1992. Mr. Ramsey holds a B.B.A. in Marketing from the University of Texas at Austin and a J.D. from South Texas College of Law. Mr. Ramsey is a graduate of Harvard Business School Advanced Management Program. Mr. Ramsey is licensed to practice law in the credit spread usedState of Texas. He is qualified to value the embedded derivativespractice in the ETP Preferred Units. Changes in ETP’s historical unit price volatility would causeWestern District of Texas and the United States Court of Appeals for the Fifth Circuit. Mr. Ramsey formerly served as a changedirector of Southern Union Company. The member of our general partner recognize Mr. Ramsey’s vast experience in the volatility used to value the embedded derivatives.
The following table presents a reconciliationThomas P. Mason.Mr. Mason became Executive Vice President and General Counsel of the general partner of ET in December 2015, and has served as the Executive Vice President, General Counsel and President - LNG since October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. Mr. Mason also served as a director of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Mason previously served as Senior Vice President, General Counsel and Secretary of ETO’s general partner from April 2012 to December 2015, as Vice President, General Counsel and Secretary from June 2008 and as General Counsel and Secretary from February 2007. Prior to joining ETO, he was a partner in the Houston office of Vinson & Elkins. Mr. Mason has specialized in securities offerings and mergers and acquisitions for more than 25 years. Mr. Mason also served on the Board of Directors of the general partner of Sunoco Logistics from October 2012 to April 2017 and has served on the Board of Directors of USAC since April 2018.
John W. McReynolds. Mr. McReynolds became Special Advisor to ET in October 2018. Prior to that time, Mr. McReynolds served as our President from March 2005 until October 2018. He has served as a Director since August 2005. He served as our Chief Financial Officer from August 2005 to June 2013, and previously served as a Director of ETO’s general partner from August 2001 through May 2010. Mr. McReynolds has been in the energy industry for his entire career. Prior to joining Energy Transfer, Mr. McReynolds was in private law practice for over 20 years, specializing exclusively in energy-related finance, securities, corporations and partnerships, mergers and acquisitions, syndications, and a wide variety of energy-related litigation. His practice dealt with all forms of fossil fuels, and the transportation and handling thereof, together with the financing and structuring of all forms of business entities related thereto. The members of our general partner selected Mr. McReynolds to serve in the indicated roles with the Energy Transfer partnerships because of this extensive background and experience, as well as his many contacts and relationships in the industry. A. Troy Sturrock. Mr. Sturrock is the Senior Vice President and Controller of our general partner having assumed that role in October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. He has served as the Senior Vice President and Controller of the general partner of ETO since August 2016 and previously served as Vice President and Controller of our General Partner beginning in June 2015. Mr. Sturrock also served as a Senior Vice President of PennTex Midstream Partners, LP’s general partner, from November 2016 until July 2017, and ending balancesas its Controller and Principal Accounting Officer from January 2017 until July 2017. Mr. Sturrock previously served as Vice President and Controller of Regency GP LLC from February 2008, and in November 2010 was appointed as the principal accounting officer. From June 2006 to February 2008, Mr. Sturrock served as the Assistant Controller and Director of financial reporting and tax for Regency GP LLC. Mr. Sturrock is a Certified Public Accountant. Ray C. Davis. Mr. Davis was appointed to the Board of Directors of our Levelgeneral partner in July 2018. From February 2018 to July 2018, Mr. Davis served on the Board of Directors of ETO. From February 2013 until February 2018, Mr. Davis was an independent investor. He has also been a principal owner, and served as co-chairman of the board of directors, of the Texas Rangers major league baseball club since August 2010. Mr. Davis previously served on the Board of Directors of the general partner of ET, effective upon the closing of ET’s initial public offering in February 2006 until his resignation in February 2013. Mr. Davis also served as ETO’s Co-Chief Executive Officer from the combination of the midstream and transportation operations of ETC OLP and the retail propane operations in January 2004 until his retirement from these positions in August 2007, and as Co-Chairman of the Board of Directors of our general partner from January 2004 until June 2011. Mr. Davis also held various executive positions with Energy Transfer prior to 2004. From 1996 to 2000, he served as a Director of Crosstex Energy, Inc. From 1993 to 1996, he served as Chairman of the Board of Directors and Chief Executive Officer of Cornerstone Natural Gas, Inc. The member of our general partner selected Mr. Davis to serve as a director based on his over 40 years of business experience in the energy industry and his expertise in the Partnership’s asset portfolio.
Steven R. Anderson. Mr. Anderson was elected to the Board of Directors of our general partner in June 2018 and serves on the audit committee and compensation committee. Mr. Anderson began his career in the energy business in the early 1970’s with Conoco in the Permian Basin area. He then spent some 25 years with ANR Pipeline and its successor, The Coastal Corporation, as a natural gas supply and midstream executive. He later was Vice President of Commercial Operations with Aquila Midstream and, upon the sale of that business to Energy Transfer in 2002, he became a part of the management team there. For the six years prior to his retirement from Energy Transfer in October 2009, he served as Vice President of Mergers and Acquisitions. Since that time, he has been involved in private investments and has served on the boards of directors of the St. John Health System and Saint Simeon's Episcopal Home in Tulsa, Oklahoma, as well as various other community and civic organizations. He also served on the Board of Directors of Sunoco Logistics Partners L.P. from October 2012 until April 2017. The members of our general partner selected Mr. Anderson to serve on the Board of Directors on the basis of his experience in the midstream industry generally and with Energy Transfer’s business specifically, as well as his recent experience on the board of another publicly traded partnership. Richard D. Brannon. Mr. Brannon was appointed to the Board of Directors of our general partner in March 2016 and has served as the Chairman of the audit committee since April 2016. Mr. Brannon is the CEO of CH4 Energy II, III, IV, V and Six, all independent companies focused on horizontal oil and gas development. Mr. Brannon served on the board of directors of WildHorse Resource Development from its IPO in December 2016 until June 2018. Mr. Brannon also formerly served on the Board of Directors and as a member of the audit committee and compensation committee of Sunoco LP, Regency, OEC Compression and Cornerstone Natural Gas Corp. He has over 35 years of experience in the energy business, having started his career in 1981 with Texas Oil & Gas. The members of our general partner selected Mr. Brannon to serve as director based on his knowledge of the energy industry and his experience as a director and audit and compensation committee member for other public companies.
Michael K. Grimm. Mr. Grimm was appointed to the Board of Directors of our general partner in October 2018, and has served on the audit committee and compensation committee since that time. Prior to that time, Mr. Grimm served as a director of ETO’s general partner beginning in December 2005, and served on the audit committee and compensation committee during that time. Mr. Grimm is one of the original founders of Rising Star Energy, L.L.C., a privately held upstream exploration and production
company active in onshore continental United States, and served as its President and Chief Executive Officer from 1995 until 2006 when it was sold. Mr. Grimm is currently President of Rising Star Petroleum, LLC. Mr. Grimm was formerly Chairman of the Board of RSP Permian, Inc. (NYSE: RSPP) from January 2014 until June 2018 and since November 2018 has served on the Board of Directors of Anadarko Petroleum Corporation (NYSE: APC). Prior to the formation of Rising Star, Mr. Grimm was Vice President of Worldwide Exploration and Land for Placid Oil Company from 1990 to 1994. Prior to joining Placid Oil Company, Mr. Grimm was employed by Amoco Production Company for thirteen years where he held numerous positions throughout the exploration department in Houston, New Orleans and Chicago. Mr. Grimm has been an active member of the Independent Petroleum Association of America, the American Association of Professional Landmen, Dallas Producers Club, Houston Producers Forum, Fort Worth Wildcatters and the All-American Wildcatters. He has a B.B.A. from the University of Texas at Austin. The members of our general partner selected Mr. Grimm to serve as a director because of his extensive experience in the energy industry and his service as a senior executive at several energy-related companies, in addition to his contacts in the industry gained through his involvement in energy-related organizations. Compensation of the General Partner Our general partner does not receive any management fee or other compensation in connection with its management of the Partnership. Section 16(a) Beneficial Ownership Reporting Compliance Section 16(a) of the Securities Exchange Act of 1934 requires the directors and executive officers of our general partner, as well as persons who own more than ten percent of the common units representing limited partnership interests in us, to file reports of ownership and changes of ownership on Forms 3, 4 and 5 with the SEC. The SEC regulations also require that copies of these Section 16(a) reports be furnished to us by such reporting persons. Based upon a review of copies of these reports, we believe all applicable Section 16(a) reports were timely filed in 2018.
ITEM 11. EXECUTIVE COMPENSATION Overview As a limited partnership, we are managed by our General Partner. Our General Partner is majority owned by Mr. Kelcy Warren. We own 100% of ETP GP and its general partner, ETP LLC. We refer to ETP GP and ETP LLC together as the “ETP GP Entities.” ETP GP is the general partner of ETO. Compensation Discussion and Analysis Named Executive Officers ET does not have officers or directors. Instead, we are managed by the board of directors of our General Partner, and the executive officers of our General Partner perform all of ET’s management functions. As a result, the executive officers of our General Partner are ET’s executive officers, and their compensation is administered by our General Partner. This Compensation Discussion and Analysis is, therefore, focused on the total compensation of the executive officers of our General Partner as set forth below. The persons we refer to in this discussion as our “named executive officers” are the following: Kelcy L. Warren, Chairman and Chief Executive Officer; Thomas E. Long, Chief Financial Officer; Marshall S. (Mackie) McCrea, III, President and Chief Commercial Officer; Matthew S. Ramsey, Chief Operating Officer; Thomas P. Mason, Executive Vice President, General Counsel and President — LNG; and John W. McReynolds, Former President (currently Special Advisor to the Partnership). Our Philosophy for Compensation of Executives In general, our General Partner’s philosophy for executive compensation is based on the premise that a significant portion of each executive’s compensation should be incentive-based or “at-risk” compensation and that executives’ total compensation levels should be highly competitive in the marketplace for executive talent and abilities. Our General Partner seeks a total compensation program for the named executive officers that provides for a slightly below the median market annual base compensation rate (i.e. approximately the 40th percentile of market) but incentive-based compensation composed of a combination of compensation vehicles to reward both short and long-term performance that are both targeted to pay-out at approximately the top-quartile of market. Our General Partner believes the incentive-based balance is achieved by (i) the payment of annual discretionary cash bonuses that consider the achievement of the Partnership’s financial instruments measuredperformance objectives for a fiscal year set at fairthe beginning of such fiscal year and the individual contributions of its named executive officers to the success of the Partnership and the achievement of the annual financial performance objectives and (ii) the annual grant of time-based restricted unit or phantom unit awards under the Partnership’s equity incentive plan(s) or the equity incentive programs of Sunoco LP, as applicable based on the allocation of the named executive officers’ award, which awards are intended to provide a longer term incentive and retention value to its key employees to focus their efforts on increasing the market price of its publicly traded units and to increase the cash distribution the Partnership and/or the other affiliated partnerships pay to their respective unitholders. The Partnership grants restricted unit and/or phantom unit awards that vest, based generally upon continued employment, at a recurring basis usingrate of 60% after the third year of service and the remaining 40% after the fifth year of service. The Partnership believes that these equity-based incentive arrangements are important in attracting and retaining executive officers and key employees as well as motivating these individuals to achieve stated business objectives. The equity-based compensation reflects the importance our General Partner places on aligning the interests of its named executive officers with those of unitholders. As discussed below, our compensation committee, the ETO Compensation Committee (prior to the Energy Transfer Merger) and/or the compensation committee of the general partner of Sunoco LP, as applicable, all in consultation with our General Partner, are responsible for the compensation policies and compensation level of the named executive officers of our General Partner. In this discussion, we refer to our compensation committee as the “ET Compensation Committee.” Sunoco LP does not participate or have any input in any decisions as to the compensation policies of Sunoco GP LLC or the compensation levels of the executive officers of its general partner. The Sunoco LP Compensation Committee is responsible for the approval of the compensation policies and the compensation levels of the executive officers of Sunoco GP LLC.
For a more detailed description of the compensation to the Partnership’s named executive officers, please see “– Compensation Tables” below. Distributions to Our General Partner Our General Partner is majority-owned by Mr. Warren. We pay quarterly distributions to our General Partner in accordance with our partnership agreement with respect to its ownership of its general partner interest as specified in our partnership agreement. The amount of each quarterly distribution that we must pay to our General Partner is based solely on the provisions of our partnership agreement, which agreement specifies the amount of cash we distribute to our General Partner based on the amount of cash that we distribute to our limited partners each quarter. Accordingly, the cash distributions we make to our General Partner bear no relationship to the level or components of compensation of our General Partner’s executive officers. Distributions to our General Partner are described in detail in Note 8 to our consolidated financial statements. Our named executive officers also own directly and indirectly certain of our limited partner interests and, accordingly, receive quarterly distributions. Such per unit distributions equal the per unit distributions made to all our limited partners and bear no relationship to the level of compensation of the named executive officers or the services they perform as employees. For a more detailed description of the compensation of our named executive officers, please see “Compensation Tables” below. Compensation Philosophy Our compensation programs are structured to achieve the following: reward executives with an industry-competitive total compensation package of base salaries and significant unobservable inputs forincentive opportunities yielding a total compensation package approaching the top-quartile of the market; attract, retain and reward talented executive officers and key management employees by providing total compensation competitive with that of other executive officers and key management employees employed by publicly traded limited partnerships of similar size and in similar lines of business; motivate executive officers and key employees to achieve strong financial and operational performance; emphasize performance-based or “at-risk” compensation; and reward individual performance. Components of Executive Compensation For the year ended December 31, 2015.2018, the compensation paid to our named executive officers consisted of the following components: annual base salary; non-equity incentive plan compensation consisting solely of discretionary cash bonuses; time-vested restricted/phantom unit awards under the equity incentive plan(s); payment of distribution equivalent rights (“DERs”) on unvested time-based restricted unit awards under our equity incentive plan; vesting of previously issued time-based restricted unit and/or phantom unit awards issued pursuant to our equity incentive plans or the equity incentive plans(s) of affiliates; and 401(k) plan employer contributions. Methodology The ET Compensation Committee considers relevant data available to it to assess our competitive position with respect to base salary, annual short-term incentives and long-term incentive compensation for our executive officers, including the named executive officers. The ET Compensation Committee also considers individual performance, levels of responsibility, skills and experience. Periodically, the ET Compensation Committee engages a third-party consultant to provide a full market competitive compensation analysis for compensation levels at peer companies in order to assist in the determination of compensation levels for our executive officers, including the named executive officers. Most recently, Longnecker & Associates (“Longnecker”) evaluated the market competitiveness of total compensation levels of a number of officers of the Partnership to provide market information with respect
to compensation of those executives during the year ended December 31, 2017. In particular, the review by Longnecker was designed to (i) evaluate the market competitiveness of total compensation levels for certain members of senior management, including our named executive officers; (ii) assist in the determination of appropriate compensation levels for our senior management, including the named executive officers; and (iii) confirm that our compensation programs were yielding compensation packages consistent with our overall compensation philosophy. In conducting its review, Longnecker specifically considered the larger size of the combined ET and ETO entities from an energy industry perspective. During 2017, Longnecker assisted in the development of the final “peer group” of leading companies in the energy industry that most closely reflect the profile of ET and ETO in terms of revenues, assets and market value as well as competition for talent at the senior management level and similarly situated general industry companies with similar revenues, assets and market value. In setting such peer group, the size of ET and ETO on a combined basis was considered. As part of the evaluation conducted by Longnecker, a determination was made to focus the analysis specifically on the energy industry based on a determination that an energy industry peer group provided a more than sufficient amount of comparative data to consider and evaluate total compensation. This decision allowed Longnecker to report on specific industry related data comparing the levels of annual base salary, annual short-term cash bonus and long-term equity incentive awards at industry peer group companies with those of the named executive officers to ensure that compensation of the named executive officers is both consistent with the compensation philosophy and competitive with the compensation for executive officers of these other companies. The identified companies were: | | | | | Balance, December 31, 2014 | $ | (16 | ) | Net unrealized gains included in other income (expense) | 11 |
| Balance, December 31, 2015 | $ | (5 | ) |
| | | | Energy Peer Group: | | | • Conoco Phillips | | • Anadarko Petroleum Corporation | • Enterprise Products Partners, L.P. | | • Marathon Petroleum Corporation | • Plains All American Pipeline, L.P. | | • Kinder Morgan, Inc. | • Halliburton Company | | • The Williams Companies, Inc. | • Valero Energy Corporation | | • Phillips 66 |
ContributionsThe compensation analysis provided by Longnecker in Aid2017 covered all major components of Construction Costtotal compensation, including annual base salary, annual short-term cash bonus and long-term incentive awards for the senior executives of these companies. In preparing the review materials, Longnecker utilized generally accepted compensation principles as determined by WorldatWork and gathered data from the public peer companies and published salary surveys.
OnFollowing Longnecker’s 2017 review, the ET Compensation Committee reviewed the information provided, including Longnecker’s specific conclusions and recommended considerations for all compensation going forward. The ET Compensation Committee considered and reviewed the results of the study performed by Longnecker to determine if the results indicated that the compensation programs were yielding a competitive total compensation model prioritizing incentive-based compensation and rewarding achievement of short and long-term performance objectives and considered Longnecker’s conclusions and recommendations. While Longnecker found that the Partnership is achieving its stated objectives with respect to the “at-risk” approach, they also found that certain adjustments should be implemented during 2017 to allow the Partnership to achieve its targeted percentiles on base compensation and incentive compensation (short and long-term) as described below.
In addition to the information received as part of Longnecker’s 2017 review, the ET Compensation Committee also utilizes information obtained from other sources in its determination of compensation levels for our named executive officers, such as annual third party surveys, although third party survey data is not used by the ET Compensation Committee to benchmark the amount of total compensation or any specific element of compensation for the named executive officers. While Longnecker did not provide a full study to the Partnership during 2018, Longnecker did provide (i) advice and feedback on the structure of the 2018 amendments to the Amended and Restated Energy Transfer Partners, L.L.C. Annual Bonus Plan (the “Bonus Plan”); and (ii) data and advice with respect to the Special Bonus award to Mr. Long. Additionally, Longnecker considered and provided feedback on the appropriateness, targets and composition of the 2018 equity award pool and the 2018 annual bonus awards under the Bonus Plan and benchmarking on certain non-named executive officer hires and promotions. Base Salary. Base salary is designed to provide for a competitive fixed level of pay that attracts and retains executive officers, and compensates them for their level of responsibility and sustained individual performance (including experience, scope of responsibility and results achieved). The salaries of the named executive officers are reviewed on an annual basis. As discussed above, the base salaries of our capital projects, third partiesnamed executive officers are obligatedtargeted to reimburse usyield an annual base salary slightly below the median level of market (i.e. approximately the 40th percentile of market) and are determined by the ET Compensation Committee after taking into account the recommendations of Mr. Warren.
During the 2018 merit review process, the ET Compensation Committee considered the recommendations of Mr. Warren, the existing Longnecker study (with the data aged as appropriate) and the merit increase pool set for all employees of the Partnership and/or its employing affiliates. The ET Compensation Committee approved a portion3.0% increase to the base salary of project expenditures. Mr. McCrea to $1,076,865 from its prior level of $1,045,000; a 3.0% base salary increase to Mr. Long to $545,900 from its prior level of $530,000; a 3.0% base salary increase to Mr. Ramsey to $673,041 from its prior level of $653,438; a 3% base salary increase to Mr. Mason to $610,044 from its prior level of $592,276; and a 3.0% increase for. Mr. McReynolds to $615,967 from its prior level of $598,026. Mr. Warren has voluntarily determined that his salary will be $1.00 per year (plus an amount sufficient to cover his allocated payroll deductions for health and welfare benefits), and, as such, did not receive any base salary or adjustment in 2018. The majority3.0% increase to Messrs. McCrea, Long, Ramsey, Mason and McReynolds reflected a base salary increase consistent with the 3.0% annual merit increase pool set for all employees of ET and its affiliates for 2018. Annual Bonus. In addition to base salary, the ET Compensation Committee makes determinations whether to make discretionary annual cash bonus awards to executives, including our named executive officers, following the end of the year under the Bonus Plan. The Bonus Plan is a discretionary annual cash bonus plan available to all employees, including the named executive officers. The purpose of the Bonus Plan is to reward employees for contributions towards the Partnership’s business goals and to aid in motivating employees. The Bonus Plan is administered by the ET Compensation Committee and the ET Compensation Committee has the authority to establish and interpret the rules and regulations relating to the Bonus Plan, to select participants, to determine and approve the size of any actual award amount, to make all determinations, including factual determinations, under the Bonus Plan, and to take all other actions necessary or appropriate for the proper administration of the Bonus Plan. For each calendar year (the “Performance Period”), the ET Compensation Committee will evaluate and determine an overall funded cash bonus pool based on achievement of (i) an internal Adjusted EBITDA target (“Adjusted EBITDA Target”), (ii) an internal distributable cash flow target (“DCF Target”) and (iii) performance of each department compared to the applicable departmental budget (“Departmental Budget Target”). The Adjusted EBITDA Target and the DCF Target are defined for purposes of the Bonus Plan using the same definitions as used in the Partnership’s audited financial statements included in its annual and quarterly filings on Forms 10-K and 10-Q for the terms Adjusted EBITDA and Distributable Cash Flow. The performance criteria are weighted 60% on the achievement of the Adjusted EBITDA Target, 20% on the achievement of the DCF Target and 20% on the achievement of the Departmental Budget Target (collectively, “Budget Targets”). The total amount of cash to be allocated to the funded bonus pool will range from 0% to 120% for each of the budgeted DCF Target and Adjusted EBITDA Target and will range from 0% to 100% of the Departmental Budget Target. The maximum funding of the bonus pool is 116% of the total pool target and to achieve such funding each of the Adjusted EBITDA and the DCF Target must achieve 120% funding and the Department Budget target must achieve its 100% target. While the funded bonus pool will reflect an aggregation of performance under each target, in the event performance under the Adjusted EBITDA Target is below 80% of its target, no bonus pool will be funded. If the bonus pool is funded, a participant may earn a cash award for the Performance Period based upon the level of attainment of the Budget Targets and his or her individual performance. Awards are paid in cash as soon as practicable after the end of the Performance Period but in no event later than two and one-half months after the end of the Performance Period. While the achievement of the Budget Targets sets a bonus pool under the Bonus Plan, actual bonus awards are discretionary. These discretionary bonuses, if awarded, are intended to reward our named executive officers for the achievement of the Budget Targets during the Performance Period in light of the contribution of each individual to our profitability and success during such year. The ET Compensation Committee also considers the recommendation of Mr. Warren in determining the specific annual cash bonus amounts for each of the named executive officers. The ET Compensation Committee does not establish its own financial performance objectives in advance for purposes of determining whether to approve any annual bonuses, and it does not utilize any formulaic approach to determine annual bonuses. For 2018, the ET Compensation Committee approved short-term annual cash bonus pool targets for Mr. McCrea of 160% of his annual base earnings and for Messrs. Long, Ramsey, Mason and McReynolds of 130% of their annual base earnings. The named executive officer bonus pool targets remained the same for the 2019 Performance Period as they were for the 2017 period. In February 2019, the ET Compensation Committee certified 2018 performance results under the Bonus Plan, which resulted in a bonus payout of 110% of the bonus pool target, which reflected achievement of 110% of the Adjusted EBITDA Target, 120% of the DCF Target and 100% of the Department Budget Target. Based on the approved results, the ET Compensation Committee approved a cash bonus relating to the 2018 calendar year to Messrs. McCrea, Long, Ramsey, Mason and McReynolds in the amounts of $1,866,000, $800,000, $900,000, $858,700 and $800,000, respectively. In approving the 2018 bonuses of the named executive officers, the ET Compensation Committee took into account the achievement by the Partnership of all of the targeted performance objectives for 2018 and the individual performances of each of the named executive officers. The cash bonuses awarded to each of the named executive officers for 2018 performance were materially
consistent with their applicable bonus pool targets. As with base salary and equity awards, Mr. Warren does not accept or receive an annual bonus. Equity Awards. In connection with the Energy Transfer Merger, ET assumed the obligations of ETO under the ETO equity plans and assumed such plans for purposes of employing such plans to make grants of equity-based awards relating to ET common units following the closing of the merger. The ETO equity plans assumed by ET, which have been subsequently renamed, are (i) the Second Amended and Restated Energy Transfer LP 2008 Incentive Plan (the “2008 Incentive Plan”); (ii) the Energy Transfer LP 2011 Long-Term Incentive Plan (the “2011 Incentive Plan”) and the (iii) Energy Transfer LP 2015 Long-Term Incentive Plan (the “2015 Plan”). In 2017, ET adopted the Amended and Restated Energy Transfer LP Long-Term Incentive Plan (formerly the Amended and Restated Energy Transfer Equity, L.P. Long Term Incentive Plan, together with the 2008 Incentive Plan, the 2011 Incentive Plan and the 2015 Plan, the “ET Incentive Plans”). The ET Incentive Plans authorize the ET Compensation Committee, in its discretion, to grant awards, as applicable under each respective plan of restricted units, phantom units, unit options, unit appreciation rights and other awards related to ET common units upon such terms and conditions as it may determine appropriate and in accordance with general guidelines as defined by the ET Incentive Plans. For 2018, the annual long-term incentive targets set by the ET Compensation Committee for the named executive officers were 900% of annual base salary for Mr. McCrea and 500% of annual base salary for Messrs. Long, Ramsey and Mason. Due to his significant holdings of ET units, Mr. McReynolds does not receive annual equity awards. The 500% target for Mr. Ramsey is a decrease from his previous target of 600% and represents a desire on the part of the Chairman to align the senior officers that report to him, other than Mr. McCrea, with a consistent long-term incentive target. The targets of the other named executive officers were consistent with the prior year’s targets. In December 2018, the ET Compensation Committee in consultation with ET’s Chairman determined to issue long-term incentive awards in the form of restricted units under the ET Incentive Plans to the ET named executive officers, other than Mr. McReynolds, who as noted above does not currently receive long-term incentive awards. In December of 2018, the ET Compensation Committee approved grants of phantom unit awards to Messrs. McCrea, Long, Ramsey and Mason of 605,470 units, 136,475 units, 168,260 units and 190,640 units, respectively. As with base salary and annual bonus, Mr. Warren does not accept or receive annual long term incentive awards. As more fully described below in the section titled Affiliate and Subsidiary Equity Awards, for 2018, in discussions between the General Partner, the ET Compensation Committees and the compensation committee of the general partner of Sunoco LP, it was determined that for 2018 the value of Messrs. Long and Ramsey’s awards would be comprised of restricted unit awards under the ET Incentive Plans and the Sunoco LP 2018 Long-Term Incentive Plan (the “2018 Sunoco LP Plan”) in consideration of their roles and responsibilities for Sunoco LP and their status, as members of the Boards of Directors of the general partner of Sunoco LP. Messrs. Long and Ramsey’s total 2018 long-term awards were allocated 80% to the ET Incentive Plans and 20% to the 2018 Sunoco LP Plan. The awards of Messrs. McCrea and Mason for 2018 were allocated entirely to the ET Incentive Plans. In the case of Mr. Mason this represented a change from prior year allocations of awards under the long-term incentive plans of affiliates as his time for 2018 was almost fully dedicated to ET and his role at Sunoco LP was reduced as a result of his additional ET responsibilities. It is expected that future long-term incentive awards to Messrs. Long and Ramsey of ET will recognize an aggregation of restricted units under the ET Incentive Plans and the 2018 Sunoco LP Plan, as applicable. The restricted unit awards granted in 2018 provide for incremental vesting over a five-year period, with 60% vesting at the end of the third year and the remaining 40% vesting at the end of the fifth year. Vesting of the awards are generally subject to continued employment through each specified vesting date. The restricted unit awards entitle the recipients to receive, with respect to each ET unit subject to such award that has not either vested or been forfeited, a DER cash payment promptly following each such distribution by ET to its unitholders. In approving the grant of such arrangements are associatedrestricted unit awards, including to the named executive officers, the ET Compensation Committee considered several factors, including the long-term objective of retaining such individuals as key drivers of ET’s future success, the existing level of equity ownership of such individuals and the previous awards to such individuals of equity awards subject to vesting. Vesting of the 2018 awards would accelerate in the event of the death or disability of the recipient, including the named executive officers, or in the event of a change in control of ET as that term is defined under the ET Incentive Plans. As discussed below under “Potential Payments Upon a Termination or Change of Control,” all outstanding equity would automatically accelerate upon a change in control event, which means vesting automatically accelerates upon a change of control irrespective of whether the officer is terminated. In addition, the 2014 awards to Mr. McCrea included a provision in the applicable award agreement for acceleration of unvested restricted unit/restricted phantom unit awards upon a termination of employment by the general partner of the applicable partnership issuing the award without “cause”. For purposes of the awards the term “cause” shall mean: (i) a conviction (treating a nolo contendere plea as a conviction) of a felony (whether or not any right to appeal has
been or may be exercised), (ii) willful refusal without proper cause to perform duties (other than any such refusal resulting from incapacity due to physical or mental impairment), (iii) misappropriation, embezzlement or reckless or willful destruction of property of the partnership or any of its affiliates, (iv) knowing breach of any statutory or common law duty of loyalty to the partnership or any of its or their affiliates, (v) improper conduct materially prejudicial to the business of the partnership or any of its or their affiliates by, (vi) material breach of the provisions of any agreement regarding confidential information entered into with pipeline construction and productionthe partnership or any of its or their affiliates or (vii) the continuing failure or refusal to satisfactorily perform essential duties to the partnership or any of its or their affiliates. In addition, the award agreements for the restricted units awarded in 2018, as 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 incomeawards outstanding held by Partnership employees, including the named executive officers, also include certain acceleration provisions upon retirement with the ability to accelerate 40% of outstanding unvested awards under the ET Incentive Plans at age 65 and 50% at age 68. These acceleration provisions require that the participant have not less than five (5) years of employment service to the Partnership or an affiliate and require a six (6) month delay in the periodvesting after retirement pursuant to the requirements of Section 409(A) of the Code. We believe that permitting the accelerated vesting of equity awards upon a change in which it is realized. Shipping and Handling Costs
Shipping and handling costs are includedcontrol creates an important retention tool for us by enabling employees to realize value from these awards in costthe event that we undergo a change in control transaction. In addition, we believe permitting acceleration of products sold, except for shipping and handling costs related to fuel consumed for compression and treating which are includedvesting upon a change 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,control and the costacceleration of appliances, partsvesting awards upon a termination without “cause” in the case of the 2014 awards to Mr. McCrea creates a sense of stability in the course of transactions that could create uncertainty regarding their future employment and fittings. Operating expenses include all costs incurredencourage these officers to provide productsremain focused on their job responsibilities.
Affiliate and Subsidiary Equity Awards. In addition to customers,their roles as officers of for ET and ETO during 2018, Messrs. Long and Ramsey have certain responsibilities for Sunoco LP, including compensationas members of the Board of Directors of the general partner of Sunoco LP. The Sunoco LP Compensation Committee in December 2018 approved grants of restricted unit awards to Messrs. Long and Ramsey of 19,325 and 23,825 restricted units, respectively, under the 2018 Sunoco LP Plan. The terms and conditions of the restricted unit to Messrs. Long and Ramsey under the 2018 Sunoco LP Plan, as applicable, were the same and provided for operations personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costsvesting over a five-year period, with 60% vesting at the end of the third year and plant operations. Selling, generalthe remaining 40% vesting at the end of the fifth year, subject generally to continued employment through each specified vesting date. All of the awards would be accelerated in the event of their death, disability, upon a change in control or retirement at ages 65 or 68. Special Bonus Award. On October 19, 2018, the ET Compensation Committee approved a special one-time bonus award (the “Special Award”) to Mr. Long in recognition of Mr. Long’s contributions to several key strategic initiatives, including the successful Energy Transfer Merger. The Special Award was composed of $1,000,000 cash paid in one ump-sum in October 2018 and administrative expenses include all115,200 restricted units under the 2008 Incentive Plan. The restricted units awarded to Mr. Long under the 2008 Incentive Plan carry the right to receive DER cash payments and are subject to vesting as follows: 60% of the aggregate number of ET Restricted Units on December 5, 2021, and the remaining 40% on December 5, 2023, based on continued employment with the Partnership on each such date. In the event that Mr. Long is terminated without “cause,” dies or becomes disabled or there is a change in control of ET as that term is defined under the 2008 Incentive Plan, vesting of the restricted units would automatically accelerate. For purposes of the Special Award to Mr. Long, “cause” shall mean: (i) a conviction (treating a nolo contendere plea as a conviction) of a felony (whether or not any right to appeal has been or may be exercised), (ii) willful refusal without proper cause to perform duties (other than any such refusal resulting from incapacity due to physical or mental impairment), (iii) misappropriation, embezzlement or reckless or willful destruction of property of the Partnership or any of its affiliates, (iv) knowing breach of any statutory or common law duty of loyalty to the Partnership or any of its or their affiliates, (v) improper conduct materially prejudicial to the business of the Partnership or any of its or their affiliates by, (vi) material breach of the provisions of any agreement regarding confidential information entered into with the Partnership or any of its or their affiliates or (vii) the continuing failure or refusal to satisfactorily perform essential duties to the Partnership or any of its or their affiliates. Unit Ownership Guidelines. The Board of Directors of our General Partner has adopted the Executive Unit Ownership Guidelines (the “Guidelines”), which set forth minimum ownership guidelines applicable to certain executives of ET with respect to ET and Sunoco LP common units representing limited partnership related expensesinterests, as applicable. The applicable Guidelines are denominated as a multiple of base salary, and compensation for executive, partnership, and administrative personnel. We record the collectionamount of taxescommon units required to be remittedowned increases with the level of responsibility. Under these Guidelines, the President and Chief Commercial Officer and the Chief Operating Officer are expected to governmental authoritiesown common units having a minimum value of five times his base salary, while each of the remaining named executive officers (other than the CEO) are expected to own common units having a minimum value of four times their respective base salary. In addition to the named executive officers, these Guidelines also apply to other covered executives, which executives are expected to own either directly or indirectly in accordance with the terms of the Guidelines, common units having minimum values ranging from two to four times their respective base salary.
The ET Compensation Committee believes that the ownership of ET and/or Sunoco LP common units, as reflected in these Guidelines, is an important means of tying the financial risks and rewards for its executives to ET’s total unitholder return, aligning the interests of such executives with those of ET’s Unitholders, and promoting ET’s interest in good corporate governance. Covered executives are generally required to achieve their ownership level within five years of becoming subject to the Guidelines; however, certain covered executives, based on their tenure as an executive, are required to achieve compliance within two years of the December 2013 effective date of the Guidelines. Thus, compliance with the Guidelines was required for Messrs. McCrea and Mason beginning in December 2015, and they were compliant. Compliance for Mr. Long was required in December 2018, and he was compliant. Compliance for Mr. Ramsey will be required in December 2020. Covered executives may satisfy the Guidelines through direct ownership of ET and/or Sunoco LP common units or indirect ownership by certain immediate family members. Direct or indirect ownership of ET and/or Sunoco LP common units shall count on a net basis exceptone-to-one ratio for our retail marketing operationspurposes of satisfying minimum ownership requirements; however, unvested unit awards may not be used to satisfy the minimum ownership requirements. Executive officers, including the named executive officers, who have not yet met their respective guideline must retain and hold all common units (less common units sold to cover the executive’s applicable taxes and withholding obligation) received in which consumer excise taxes on salesconnection with long-term incentive awards. Once the required ownership level is achieved, ownership of refined products and merchandise are included in both revenues and costs and expenses in the consolidated statementsrequired common units must be maintained for as long as the covered executive is subject to the Guidelines. However, those individuals who have met or exceeded their applicable ownership level guideline may dispose of operations, with no effect on net income (loss). Excise taxes collected by our retail marketing operations were $3.05 billion, $2.46 billion and $2.22 billion for the years ended December 31, 2015, 2014 and 2013, 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 betweenmanner consistent with applicable laws, rules and regulations, including regulations of the amount of consideration received or paidSEC 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,internal policies, but only to the extent that such individual’s remaining ownership of common units would continue to exceed the applicable ownership level.
Qualified Retirement Plan Benefits. The Energy Transfer LP 401(k) Plan (the “ET 401(k) Plan”) is a defined contribution 401(k) plan, which covers substantially all of our employees, including the named executive officers. Employees may elect to defer up to 100% of their eligible compensation after applicable taxes, as limited under the Internal Revenue Code. We make a matching contribution that is not included inless than the aggregate amount of matching contributions that would be credited to a taxable subsidiary, for federalparticipant’s account based on a rate of match equal to 100% of each participant’s elective deferrals up to 5% of covered compensation. The amounts deferred by the participant are fully vested at all times, and state income tax purposes are included in the tax returnsamounts contributed by the Partnership become vested based on years of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Unitholdersservice. We provide this benefit as a result of differences between the tax basismeans to incentivize employees and financial reporting basis of assets and liabilities,provide them with an opportunity to save for their retirement. The Partnership provides a 3% profit sharing contribution to employee 401(k) accounts for all employees with a base compensation below a specified threshold. The contribution is in addition to the allocation requirements related401(k) matching contribution and employees become vested based on years of service. Health and Welfare Benefits. All full-time employees, including our named executive officers may participate in ETP GP’s health and welfare benefit programs including medical, dental, vision, flexible spending, life insurance and disability insurance. Termination Benefits. Our named executive officers do not have any employment agreements that call for payments of termination or severance benefits or that provide for any payments in the event of a change in control of our General Partner; however, the award agreement to taxablethe named executive officers under the ET Incentive Plans, the 2018 Sunoco LP Plan and the Sunoco LP 2012 Long-Term Incentive Plan (the “2012 Sunoco LP Plan”) provide for immediate vesting of all unvested restricted unit awards in the event of a (i) change of control, as defined in the plan; (ii) death or (iii) disability, as defined in the applicable plan. Please refer to “Compensation Tables - Potential Payments Upon a Termination or Change of Control” for additional information. In addition, ETP GP has also adopted the ETP GP Severance Plan and Summary Plan Description effective as of June 12, 2013, (the “Severance Plan”), which provides for payment of certain severance benefits in the event of Qualifying Termination (as that term is defined in the Severance Plan). In general, the Severance Plan provides payment of two weeks of annual base salary for each year or partial year of employment service up to a maximum of fifty-two weeks or one year of annual base salary (with a minimum of four weeks of annual base salary) and up to three months of continued group health insurance coverage. The Severance Plan also provides that we may determine to pay benefits in addition to those provided under the Severance Plan based on special circumstances, which additional benefits shall be unique and non-precedent setting. The Severance Plan is available to all salaried employees on a nondiscriminatory basis; therefore, amounts that would be payable to our named executive officers upon a Qualified Termination have been excluded from “Compensation Tables – Potential Payments Upon a Termination or Change of Control” below. Energy Transfer LP Non-Qualified Deferred Compensation Plan (the “ET NQDC Plan”) is a deferred compensation plan, which permits eligible highly compensated employees to defer a portion of their salary, bonus, and/or quarterly non-vested phantom unit distribution equivalent income until retirement, termination of employment or other designated distribution event. Each year under the ET NQDC Plan, eligible employees are permitted to make an irrevocable election to defer up to 50% of their annual base
salary, 50% of their quarterly non-vested phantom unit distribution income, and/or 50% of their discretionary performance bonus compensation during the following year. Pursuant to the ET NQDC Plan, ET may make annual discretionary matching contributions to participants’ accounts; however, ET has not made any discretionary contributions to participants’ accounts and currently has no plans to make any discretionary contributions to participants’ accounts. All amounts credited under the ET NQDC Plan (other than discretionary credits) are immediately 100% vested. Participant accounts are credited with deemed earnings or losses based on hypothetical investment fund choices made by the participants among available funds. Participants may elect to have their account balances distributed in one lump sum payment or in annual installments over a period of three or five years upon retirement, and in a lump sum upon other termination events. Participants may also elect to take lump-sum in-service withdrawals five years or longer in the future, and such scheduled in-service withdrawals may be further deferred prior to the withdrawal date. Upon a change in control (as defined in the ET NQDC Plan) of ET, all ET NQDC Plan accounts are immediately vested in full. However, distributions are not accelerated and, instead, are made in accordance with the ET NQDC Plan’s normal distribution provisions unless a participant has elected to receive a change of control distribution pursuant to his deferral agreement. None of our Third Amendednamed executive officers currently participate in this plan. Risk Assessment Related to our Compensation Structure. We believe that the compensation plans and Restated Agreementprograms for our named executive officers, as well as our other employees, are appropriately structured and are not reasonably likely to result in material risk to us. We believe these compensation plans and programs are structured in a manner that does not promote excessive risk-taking that could harm our value or reward poor judgment. We also believe we have allocated compensation among base salary and short and long-term compensation in such a way as to not encourage excessive risk-taking. In particular, we generally do not adjust base annual salaries for executive officers and other employees significantly from year to year, and therefore the annual base salary of Limited Partnership (the “Partnership Agreement”).our employees is not generally impacted by our overall financial performance or the financial performance of a portion of our operations. Our subsidiaries generally determine whether, and to what extent, their respective named executive officers receive a cash bonus based on achievement of specified financial performance objectives as well as the individual contributions of our named executive officers to the Partnership’s success. We and our subsidiaries use restricted units and phantom units rather than unit options for equity awards because restricted units and phantom units retain value even in a depressed market so that employees are less likely to take unreasonable risks to get, or keep, options “in-the-money.” Finally, the time-based vesting over five years for our long-term incentive awards ensures that the interests of employees align with those of our unitholders and our subsidiaries’ unitholders for our long-term performance. AsTax and Accounting Implications of Equity-Based Compensation Arrangements
Deductibility of Executive Compensation We are a publicly traded limited partnership and not a corporation for United States federal income tax purposes. Therefore, we arebelieve that the compensation paid to the named executive officers is not subject to a statutory requirement that our “qualifying income” (as defined bythe deduction limitations under Section 162(m) of 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 corporationtherefore is generally fully deductible for United States federal and state income tax purposes. For the years ended December 31, 2015, 2014, and 2013, 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, Oasis Pipeline Company, Susser Petroleum Property Company, Aloha Petroleum and Susser Holding Corporation. The Partnership and its corporate subsidiaries account for income taxes under the asset and liability method.
Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.
The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions are recorded in our financial statements only after determining a more-likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change, we reassess these probabilities and record any changes through the provision for income taxes.
Accounting for Derivative Instruments and Hedging Activities For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the statement of operations. The market prices used to value our financial derivatives and related transactions have been determined using independent third party prices, readily available market information, broker quotes and appropriate valuation techniques.
At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in net income for the period.
If we designate a commodity hedging relationship as a fair value hedge, we record the changes in fair value of the hedged asset or liability in cost of products sold in the consolidated statement of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statement of operations.
Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged.
If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, a change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations.
We previously have managed a portion of our interest rate exposures by utilizing interest rate swaps and similar instruments. Certain of our interest rate derivatives are accounted for as either cash flow hedges or fair value hedges. For interest rate derivatives accounted for as either cash flow or fair value hedges, we report realized gains and losses and ineffectiveness portions of those hedges in interest expense. For interest rate derivatives not designated as hedges for accounting purposes, we report realized and unrealized gains and losses on those derivatives in “Gains (losses) on interest rate derivatives” in the consolidated statements of operations.
Unit-BasedNon-Cash Compensation
For awards of restricted units,non-cash compensation arrangements we recognizerecord compensation expense over the vesting period based onof the grant-date fair value, which is determined based onawards, as discussed further in Note 9 to our consolidated financial statements. Compensation Committee Interlocks and Insider Participation Mr. Michael K. Grimm and Mr. Steven R. Anderson are the market priceonly members of the Compensation Committee. During 2018, no member of the Compensation Committee was an officer or employee of us or any of our common unitssubsidiaries or served as an officer of any company with respect to which any of our executive officers served on the grant date. For awardssuch company’s board of cash restricted units, we remeasure the fair valuedirectors. Mr. Grimm is not a former employee of ours or any of our subsidiaries. Mr. Anderson was previously an employee of the award at the endPartnership until his retirement in October 2009, as discussed in his biographical information included in “Item 10. Directors, Executive Officers and Corporate Governance.”
Report of each reporting period based on the market priceCompensation Committee The board of directors of our common units asGeneral Partner has reviewed and discussed the section entitled “Compensation Discussion and Analysis” with the management of ET. Based on this review and discussion, we have recommended that the reporting date,Compensation Discussion and the fair value is recordedAnalysis be included in other non-current liabilitiesthis annual report on our consolidated balance sheets.Form 10-K. Pensions and Other Postretirement Benefit Plans
Employers are required to recognize in their balance sheets 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. Employers must recognize the change in the funded status of the plan in the year in which the change occurs within AOCI in equity or, for entities applying regulatory accounting, as a regulatory asset or regulatory liability.
Allocation of Income
For purposes of maintaining partner capital accounts, our Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests.
| | 3. | ACQUISITIONS AND RELATED TRANSACTIONS:
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Pending Transactions
WMB Merger
In September 2015, ETE, ETC and WMB entered into a merger agreement. The merger agreement provides that WMB will be merged with and into ETC, with ETC surviving the merger. ETC is a recently formed limited partnership that will elect to be treated as a corporation for federal income tax purposes and, upon closing, will own the managing member interest in our general partner and limited partner interests in ETE. At the time of the merger, each issued and outstanding share of WMB common stock will be exchanged for (i) $8.00 in cash and 1.5274 ETC common shares, (ii) 1.8716 ETC common shares, or (iii) $43.50 in cash.
The closingCompensation Committee of the transaction is subject to customary conditions, including the receipt Board of approvalDirectors of the merger from WMB’s stockholders and all required regulatory approvals, including approval pursuant to the Hart-Scott-Rodino Antitrust Improvements Act of 1976. ETE and WMB anticipate that the transaction will be completed in the first half of 2016.LE GP, LLC, WMB, headquartered in Tulsa, Oklahoma, owns approximately 60% of WPZ, including all of the 2% general-partner interest in WPZ. WPZ is a master limited partnership with operations across the natural gas value chain from gathering, processing and interstate transportation of natural gas and natural gas liquids to petrochemical production of ethylene, propylene and other olefins. With major positions in top U.S. supply basins and also in Canada, WPZ owns and operates more than 33,000 miles of pipelines system wide providing natural gas for clean-power generation, heating and industrial use.
Sunoco, Inc. to Sunoco LP
In November 2015, ETP and Sunoco LP announced ETP’s contribution to Sunoco LP of the remaining 68.42% interest in Sunoco, LLC and 100% interest in the legacy Sunoco, Inc. retail business for $2.23 billion. Sunoco LP will pay ETP $2.03 billion in cash, subject to certain working capital adjustments, and will issue to ETP 5.7 million Sunoco LP common units. The transaction will be effective January 1, 2016 and is expected to close in March 2016.
2015 Transactions
Sunoco LLC to 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 $41 million of 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.
Susser to Sunoco LP
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.
Sunoco LP to ETE
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 21 million ETP common units owned by ETE. In connection with ETP’s 2014 acquisition of Susser, ETE agreed to provide ETP a $35 million annual IDR subsidy for 10 years, which terminated upon the closing of ETE’s acquisition of Sunoco GP. In connection with the exchange and repurchase, ETE will provide ETP a $35 million annual IDR subsidy for two years beginning with the quarter ended September 30, 2015.
Bakken Pipeline
In March 2015, ETE transferred 30.8 million ETP common units, ETE’s 45% interest in the Bakken Pipeline project, and $879 million in cash to ETP in exchange for 30.8 million newly issued ETP 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 also issued to ETE 100 ETP Class I Units that provide distributions to ETE to offset IDR subsidies previously provided to ETP. These IDR subsidies, including the impact from distributions on ETP Class I Units, were reduced by $55 million in 2015 and $30 million in 2016.
In October 2015, Sunoco Logistics completed the previously announced acquisition of a 40% membership interest (the “Bakken Membership Interest”) in Bakken Holdings Company LLC (“Bakken Holdco”). Bakken Holdco, through its wholly-owned subsidiaries, owns a 75% membership interest in each of Dakota Access, LLC and Energy Transfer Crude Oil Company, LLC, which together intendLP
Michael K. Grimm Steven R. Anderson The foregoing report shall not be deemed to developbe incorporated by reference by any general statement or reference to this annual report on Form 10-K into any filing under the Bakken Pipeline system to deliver crude oil fromSecurities Act of 1933, as amended, or the Bakken/Three Forks production area in North DakotaSecurities Exchange Act of 1934, as amended, except 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 Logisticsextent that we specifically incorporate this information by reference, 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.shall not otherwise be deemed filed under those Acts. Regency MergerCompensation Tables
On April 30, 2015, a wholly-owned subsidiary of ETP merged with Regency, with Regency surviving as a wholly-owned subsidiary of ETP (the “Regency Merger”). Each Regency common unit and Class F unit was converted into the right to receive 0.4124 common units of ETP. ETP issued 172.2 million ETP common units to Regency unitholders, including 15.5 million units issued to ETP subsidiaries. The 1.9 million outstanding Regency Preferred Units were converted into corresponding new ETP Series A Preferred Units on a one-for-one basis.
In connection with the Regency Merger, ETE agreed to reduce the incentive distributions it receives from ETP by a total of $320 million over a five-year period. The IDR subsidy was $80 million for the year ended December 31, 2015 and will total $60 million per year for the following four years.
ETP has assumed all of the obligations of Regency and Regency Energy Finance Corp., of which ETP was previously a co-obligor or parent guarantor.
2014 Transactions
Susser Merger
In August 2014, ETP and Susser completed the merger of an indirect wholly-owned subsidiary of ETP, with and into Susser, with Susser surviving the merger as a subsidiary of ETP for total consideration valued at approximately $1.8 billion (the “Susser Merger”). The total consideration paid in cash was approximately $875 million and the total consideration paid in equity was approximately 15.8 million ETP Common Units. The Susser Merger broadens ETP’s retail geographic footprint and provides synergy opportunities and a platform for future growth.
In connection with the Susser Merger, ETP acquired an indirect 100% equity interest in Susser and the general partner interest and the incentive distribution rights in Sunoco LP, approximately 11 million Sunoco LP common and subordinated units, and Susser’s existing retail operations, consisting of 630 convenience store locations.
Effective with the closing of the transaction, Susser ceased to be a publicly traded company and its common stock discontinued trading on the NYSE.
Summary of Assets Acquired and Liabilities Assumed ETP accounted for the Susser Merger using the acquisition method of accounting which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date.
The following table summarizes the assets acquired and liabilities assumed recognized as of the merger date:Compensation Table
| | | | | | | | 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 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Name and Principal Position | | Year | | Salary ($) | | Bonus(1) ($) | | Equity Awards (2) ($) | | Option Awards ($) | | Non-Equity Incentive Plan Compensation(3) ($) | | Change in Pension Value and Nonqualified Deferred Compensation Earnings ($) | | All Other Compensation(4) ($) | | Total ($) | Kelcy L. Warren (5) | | 2018 | | $ | 6,138 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 6,138 |
| Chief Executive Officer | | 2017 | | 5,926 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 5,926 |
| | 2016 | | 5,920 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 58 |
| | 5,978 |
| Thomas E. Long | | 2018 | | 537,338 |
| | 1,000,000 |
| | 4,251,335 |
| | — |
| | 800,000 |
| | — |
| | 21,294 |
| | 6,609,967 |
| Chief Financial Officer | | 2017 | | 480,846 |
| | — |
| | 2,519,954 |
| | — |
| | 625,100 |
| | — |
| | 18,320 |
| | 3,644,220 |
| | 2016 | | 454,154 |
| | — |
| | 2,007,697 |
| | — |
| | 560,865 |
| | — |
| | 14,679 |
| | 3,037,395 |
| Marshall S. (Mackie) McCrea, III | | 2018 | | 1,059,976 |
| | — |
| | 7,834,782 |
| | — |
| | 1,866,000 |
| | — |
| | 19,362 |
| | 10,780,120 |
| President and Chief Commercial Officer | | 2017 | | 1,027,846 |
| | — |
| | 9,033,341 |
| | — |
| | 1,644,554 |
| | — |
| | 16,834 |
| | 11,722,575 |
| | 2016 | | 1,009,231 |
| | — |
| | 8,059,413 |
| | — |
| | 1,533,990 |
| | — |
| | 14,818 |
| | 10,617,452 |
| Matthew S. Ramsey | | 2018 | | 662,486 |
| | — |
| | 2,818,415 |
| | — |
| | 900,000 |
| | — |
| | 19,294 |
| | 4,400,195 |
| Chief Operating Officer | | 2017 | | 642,404 |
| | — |
| | 3,763,893 |
| | — |
| | 835,125 |
| | — |
| | 18,618 |
| | 5,260,040 |
| | 2016 | | 630,769 |
| | — |
| | 3,433,894 |
| | — |
| | 838,901 |
| | — |
| | 87,375 |
| | 4,990,939 |
| Thomas P. Mason | | 2018 | | 600,477 |
| | — |
| | 2,466,882 |
| | — |
| | 858,700 |
| | — |
| | 19,294 |
| | 3,945,353 |
| Executive Vice President, General Counsel and President – LNG | | 2017 | | 582,275 |
| | — |
| | 2,816,048 |
| | — |
| | 756,958 |
| | — |
| | 18,618 |
| | 4,173,899 |
| | 2016 | | 571,729 |
| | — |
| | 2,524,064 |
| | — |
| | 706,067 |
| | — |
| | 14,818 |
| | 3,816,678 |
| John W. McReynolds | | 2018 | | 606,306 |
| | — |
| | — |
| | — |
| | 800,000 |
| | — |
| | 15,967 |
| | 1,422,273 |
| Former President | | 2017 | �� | 587,928 |
| | — |
| | — |
| | — |
| | 764,306 |
| | — |
| | 15,179 |
| | 1,367,413 |
| | 2016 | | 577,280 |
| | — |
| | — |
| | — |
| | 712,922 |
| | — |
| | 10,768 |
| | 1,300,970 |
|
| | (1) | NoneFor Mr. Long, the amount shown includes the cash portion of the goodwill is expected to be deductible for tax purposes.his Special Award. |
The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.
ETP incurred merger related costs related to the Susser Merger of $25 million during the year ended December 31, 2014. Our consolidated statements of operations for the year ended December 31, 2014 reflected revenue and net income related to Susser of $2.32 billion and $105 million, respectively.
No pro forma information has been presented 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 8.
Panhandle Merger
On January 10, 2014, Panhandle consummated a merger with Southern Union, the indirect parent of Panhandle at the time of the merger, and PEPL Holdings, a wholly-owned subsidiary of Southern Union and the sole limited partner of Panhandle at the time of the merger, pursuant to which each of Southern Union and PEPL Holdings were merged with and into Panhandle (the “Panhandle Merger”), with Panhandle surviving the Panhandle Merger. In connection with the Panhandle Merger, Panhandle assumed Southern Union’s obligations under its 7.6% senior notes due 2024, 8.25% senior notes due 2029 and the junior subordinated notes due 2066. At the time of the Panhandle Merger, Southern Union did not have material operations of its own, other than its ownership of Panhandle and noncontrolling interests in PEI Power II, LLC, Regency (31.4 million Regency Common Units and 6.3 million Regency Class F Units), and ETP (2.2 million ETP Common Units). 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. Our consolidated statement of operations for the year ended December 31, 2014 included revenues and net income attributable to PVR’s operations of $956 million and $166 million, respectively.
Regency completed the evaluation of the assigned fair values to the assets acquired and liabilities assumed. The total purchase price was allocated as follows:
| | | | | Assets | At March 21, 2014 | Current assets | $ | 149 |
| Property, plant and equipment | 2,716 |
| Investment in unconsolidated affiliates | 62 |
| Intangible assets (average useful life of 30 years) | 2,717 |
| Goodwill(1) | 370 |
| Other non-current assets | 18 |
| Total assets acquired | 6,032 |
| Liabilities | | Current liabilities | 168 |
| Long-term debt | 1,788 |
| Premium related to senior notes | 99 |
| Non-current liabilities | 30 |
| Total liabilities assumed | 2,085 |
| Net assets acquired | $ | 3,947 |
|
(1)None of the goodwill is expected to be deductible for tax purposes.
The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.
Regency’s Acquisition of Eagle Rock’s Midstream Business
On July 1, 2014, Regency acquired Eagle Rock’s midstream business (the “Eagle Rock Midstream Acquisition”) for $1.3 billion, including the assumption of $499 million of Eagle Rock’s 8.375% senior notes due 2019. The remainder of the purchase price was funded by $400 million in Regency Common Units sold to a wholly-owned subsidiary of ETE, 8.2 million Regency Common Units issued to Eagle Rock and borrowings under Regency’s revolving credit facility. Our consolidated statement of operations for the year ended December 31, 2014 included revenues and net income attributable to Eagle Rock’s operations of $903 million and $30 million, respectively.
The total purchase price was allocated as follows:
| | | | | Assets | At July 1, 2014 | Current assets | $ | 120 |
| Property, plant and equipment | 1,295 |
| Other non-current assets | 4 |
| Goodwill | 49 |
| Total assets acquired | 1,468 |
| Liabilities | | Current liabilities | 116 |
| Long-term debt | 499 |
| Other non-current liabilities | 12 |
| Total liabilities assumed | 627 |
| | | Net assets acquired | $ | 841 |
|
The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.
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 Missouri Gas Energy division and Laclede Massachusetts agreed to acquire the assets of Southern Union New England Gas Company 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 New England Gas Company division.
In September 2013, Southern Union completed its sale of the assets of Missouri Gas Energy 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 New England Gas Company 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 Missouri Gas Energy and New England Gas Company’s sale dates in September 2013 and December 2013, respectively:
| | | | | | Year Ended December 31, 2013 | Revenue from discontinued operations | $ | 415 |
| Net income of discontinued operations, excluding effect of taxes and overhead allocations | 65 |
|
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 (which have subsequently converted to ETP common units in the Regency Merger) 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.
| | 4. | ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES:
|
The carrying values of the Partnership’s investments in unconsolidated affiliates as of December 31, 2015 and 2014, were as follows:
| | | | | | | | | | December 31, | | 2015 | | 2014 | Citrus | $ | 1,739 |
| | $ | 1,823 |
| AmeriGas | 80 |
| | 94 |
| FEP | 115 |
| | 130 |
| MEP | 660 |
| | 695 |
| HPC | 402 |
| | 422 |
| Others | 466 |
| | 495 |
| Total | $ | 3,462 |
| | $ | 3,659 |
|
Citrus
ETP owns CrossCountry, which 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. In 2012, 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.
AmeriGas
In 2012, ETP received 29.6 million AmeriGas common units in connection with the contribution of its propane operations. During the years ended December 31, 2014 and 2013, ETP sold 18.9 million and 7.5 million AmeriGas common units, respectively, for net proceeds of $814 million and $346 million, respectively. 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.
FEP
ETP has a 50% interest in FEP which owns an approximately 185-mile natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi.
MEP
ETP owns a 50% interest in MEP, which owns approximately 500 miles of natural gas pipeline that extends from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama.
HPC
ETP owns a 49.99% interest in HPC, which, through its ownership of RIGS, delivers natural gas from Northwest Louisiana to downstream pipelines and markets through a 450-mile intrastate pipeline system.
Summarized Financial Information
The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, including AmeriGas, Citrus, FEP, HPC and MEP (on a 100% basis) for all periods presented:
| | | | | | | | | | December 31, | | 2015 | | 2014 | Current assets | $ | 632 |
| | $ | 889 |
| Property, plant and equipment, net | 10,213 |
| | 10,520 |
| Other assets | 2,649 |
| | 2,687 |
| Total assets | $ | 13,494 |
| | $ | 14,096 |
| | | | | Current liabilities | $ | 841 |
| | $ | 1,983 |
| Non-current liabilities | 7,950 |
| | 7,359 |
| Equity | 4,703 |
| | 4,754 |
| Total liabilities and equity | $ | 13,494 |
| | $ | 14,096 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2015 | | 2014 | | 2013 | Revenue | $ | 4,026 |
| | $ | 4,925 |
| | $ | 4,695 |
| Operating income | 1,302 |
| | 1,071 |
| | 1,197 |
| Net income | 807 |
| | 577 |
| | 699 |
|
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 our Preferred Units, see Note 7. For the diluted earnings per share computation, income allocable to the limited partners is reduced, where applicable, for the decrease in earnings from ETE’s limited partner unit ownership in ETP or Sunoco LP that would have resulted assuming the incremental units related to ETP’s or Sunoco LP’s equity incentive plans, as applicable, had been issued during the respective periods. Such units have been determined based on the treasury stock method.
A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit is as follows:
| | | | | | | | | | | | | | Years Ended December 31, | | 2015 | | 2014 | | 2013 | Income from continuing operations | $ | 1,093 |
| | $ | 1,060 |
| | $ | 282 |
| Less: Income (loss) from continuing operations attributable to noncontrolling interest | (96 | ) | | 434 |
| | 99 |
| Income from continuing operations, net of noncontrolling interest | 1,189 |
| | 626 |
| | 183 |
| Less: General Partner’s interest in income from continuing operations | 3 |
| | 2 |
| | — |
| Less: Class D Unitholder’s interest in income from continuing operations | 3 |
| | 2 |
| | — |
| Income from continuing operations available to Limited Partners | $ | 1,183 |
| | $ | 622 |
| | $ | 183 |
| Basic Income from Continuing Operations per Limited Partner Unit: | | | | | | Weighted average limited partner units | 1,062.8 |
| | 1,088.6 |
| | 1,121.8 |
| Basic income from continuing operations per Limited Partner unit | $ | 1.11 |
| | $ | 0.58 |
| | $ | 0.17 |
| Basic income from discontinued operations per Limited Partner unit | $ | — |
| | $ | — |
| | $ | 0.01 |
| Diluted Income from Continuing Operations per Limited Partner Unit: | | | | | | Income from continuing operations available to Limited Partners | $ | 1,183 |
| | $ | 622 |
| | $ | 183 |
| Dilutive effect of equity-based compensation of subsidiaries and distributions to Class D Unitholder | (2 | ) | | (2 | ) | | — |
| Diluted income from continuing operations available to Limited Partners | 1,181 |
| | 620 |
| | 183 |
| Weighted average limited partner units | 1,062.8 |
| | 1,088.6 |
| | 1,121.8 |
| Dilutive effect of unconverted unit awards | 1.6 |
| | 2.2 |
| | — |
| Weighted average limited partner units, assuming dilutive effect of unvested unit awards | 1,064.4 |
| | 1,090.8 |
| | 1,121.8 |
| Diluted income from continuing operations per Limited Partner unit | $ | 1.11 |
| | $ | 0.57 |
| | $ | 0.17 |
| Diluted income from discontinued operations per Limited Partner unit | $ | — |
| | $ | — |
| | $ | 0.01 |
|
Our debt obligations consist of the following:
| | | | | | | | | | December 31, | | 2015 | | 2014 | 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 |
| 5.5% Senior Notes due June 1, 2027 | 1,000 |
| | — |
| ETE Senior Secured Term Loan, due December 2, 2019 | 2,190 |
| | 1,400 |
| ETE Senior Secured Revolving Credit Facility due December 18, 2018 | 860 |
| | 940 |
| Unamortized premiums, discounts and fair value adjustments, net | (17 | ) | | 3 |
| Deferred debt issuance costs | (38 | ) | | (34 | ) | | 6,332 |
| | 4,646 |
| | | | | Subsidiary Indebtedness: | | | | ETP Debt | | | | 5.95% Senior Notes due February 1, 2015 | — |
| | 750 |
| 6.125% Senior Notes due February 15, 2017 | 400 |
| | 400 |
| 2.5% Senior Notes due June 15, 2018 | 650 |
| | — |
| 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 |
| 5.75% Senior Notes due September 1, 2020 (assumed from Regency) | 400 |
| | — |
| 4.15% Senior Notes due October 1, 2020 | 1,050 |
| | 700 |
| 6.5% Senior Notes due May 15, 2021 (assumed from Regency) | 500 |
| | — |
| 4.65% Senior Notes due June 1, 2021 | 800 |
| | 800 |
| 5.20% Senior Notes due February 1, 2022 | 1,000 |
| | 1,000 |
| 5.875% Senior Notes due March 1, 2022 (assumed from Regency) | 900 |
| | — |
| 5.0% Senior Notes due October 1, 2022 (assumed from Regency) | 700 |
| | — |
| 3.60% Senior Notes due February 1, 2023 | 800 |
| | 800 |
| 5.5% Senior Notes due April 15, 2023 (assumed from Regency) | 700 |
| | — |
| 4.5% Senior Notes due November 1, 2023 (assumed from Regency) | 600 |
| | — |
| 4.9% Senior Notes due February 1, 2024 | 350 |
| | 350 |
| 7.6% Senior Notes due February 1, 2024 | 277 |
| | 277 |
| 4.05% Senior Notes due March 15, 2025 | 1,000 |
| | — |
| 4.75% Senior Notes due January 15, 2026 | 1,000 |
| | — |
| 8.25% Senior Notes due November 15, 2029 | 267 |
| | 267 |
| 4.90% Senior Notes due March 15, 2035 | 500 |
| | — |
| 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 |
| 5.15% Senior Notes due March 15, 2045 | 1,000 |
| | — |
| 6.125% Senior Notes due December 15, 2045 | 1,000 |
| | — |
| Floating Rate Junior Subordinated Notes due November 1, 2066 | 545 |
| | 546 |
| ETP $3.75 billion Revolving Credit Facility due November 2019 | 1,362 |
| | 570 |
| Unamortized premiums, discounts and fair value adjustments, net | (21 | ) | | (1 | ) | Deferred debt issuance costs | (147 | ) | | (55 | ) | | 20,633 |
| | 11,404 |
| | | | | Transwestern Debt | | | | 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 | ) | Deferred debt issuance costs | (2 | ) | | (3 | ) | | 779 |
| | 778 |
| | | | | Panhandle Debt | | | | 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 | 75 |
| | 99 |
| | 1,160 |
| | 1,184 |
| | | | | Sunoco, Inc. Debt | | | | 9.625% Senior Notes due April 15, 2015 | — |
| | 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 | 20 |
| | 35 |
| | 485 |
| | 750 |
| | | | | Sunoco Logistics Debt | | | | 6.125% Senior Notes due May 15, 2016(1) | 175 |
| | 175 |
| 5.50% Senior Notes due February 15, 2020 | 250 |
| | 250 |
| 4.4% Senior Notes due April 1,2021 | 600 |
| | — |
| 4.65% Senior Notes due February 15, 2022 | 300 |
| | 300 |
| 3.45% Senior Notes due January 15, 2023 | 350 |
| | 350 |
| 4.25% Senior Notes due April 1, 2024 | 500 |
| | 500 |
| 5.95% Senior Notes due December 1, 2025 | 400 |
| | — |
| 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 |
| | 700 |
| 5.35% Senior Notes due May 15, 2045 | 800 |
| | 800 |
| Sunoco Logistics $35 million Revolving Credit Facility due April 30, 2015(2) | — |
| | 35 |
| Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020 | 562 |
| | 150 |
| Unamortized premiums, discounts and fair value adjustments, net | 85 |
| | 100 |
| Deferred debt issuance costs | (32 | ) | | (26 | ) | | 5,590 |
| | 4,234 |
| | | | | Sunoco LP Debt | | | | 5.5% Senior Notes Due August 1, 2020 | 600 |
| | — |
| 6.375% Senior Notes due April 1, 2023 | 800 |
| | — |
| Sunoco LP $1.50 billion Revolving Credit Facility due September 25, 2019 | 450 |
| | 683 |
| Deferred debt issuance costs | (18 | ) | | — |
| | 1,832 |
| | 683 |
| | | | | Regency Debt, net of deferred debt issuance costs of $58 million(3) | — |
| | 6,583 |
| | | | | Other | 157 |
| | 223 |
| | 36,968 |
| | 30,485 |
| Less: current maturities | 131 |
| | 1,008 |
| | $ | 36,837 |
| | $ | 29,477 |
|
| | (1)
| Sunoco Logistics’ 6.125% senior notes due May 15, 2016 were classified as long-term debt as of December 31, 2015 as Sunoco Logistics has the ability and intent to refinance such borrowings on a long-term basis. |
| | (2) | Sunoco Logistics’ subsidiary $35 million Revolving Credit Facility maturedEquity award amounts reflect the aggregate grant date fair value of unit awards granted for the periods presented, computed in April 2015accordance with FASB ASC Topic 718. For Messrs. Long and was repaid with borrowings fromRamsey amounts include equity awards of our subsidiaries and/or affiliates, as reflected in the Sunoco Logistics $2.50 billion Revolving Credit Facility.“Grants of Plan-Based Awards Table.” See Note 9 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” for additional assumptions underlying the value of the equity awards. |
| | (3) | ET maintains the Bonus Plan which provides for discretionary basis. Award of discretionary bonuses are tied to achievement of targeted performance objectives and described in the Compensation Discussion and Analysis. The Regency senior notesdiscretionary cash bonus |
amounts earned by the named executive officers for 2018 reflect cash bonuses approved by the ET Compensation Committee in February 2019 that are expected to be paid on or before March 15, 2019. | | (4) | The amounts reflected for 2018 in this column include (i) matching contributions to the ET 401(k) Plan made on behalf of the named executive officers of $13,750 each for Messrs. Long, McCrea, Ramsey and Mason and $9,300 for Mr. McReynolds, (ii) health savings account contributions made on behalf of the named executive officers of $2,000 each for Messrs. Long and McCrea, and (iii) the dollar value of life insurance premiums paid for the benefit of the named executive officers. The amounts reflected for all periods exclude distribution payments in connection with distribution equivalent rights on unvested unit awards, because the dollar value of such distributions are factored into the grant date fair value reported in the “Equity Awards” column of the Summary Compensation Table at the time that the unit awards and distribution equivalent rights were redeemed and/originally granted. For 2018, distribution payments in connection with distribution equivalent rights totaled $594,423 for Mr. Long, $2,183,255 for Mr. McCrea, $816,297 for Mr. Ramsey, and $759,825 for Mr. Mason. |
| | (5) | Mr. Warren has voluntarily determined that his salary will be reduced to $1.00 per year (plus an amount sufficient to cover his allocated payroll deductions for health and welfare benefits). He also does not accept a cash bonus or assumed by ETP. On April 30, 2015,any equity awards under the equity incentive plans. |
Grants of Plan-Based Awards Table | | | | | | | | | | | | | | | | | | Name | | Grant Date | | All Other Unit Awards: Number of Units (#) | | All Other Option Awards: Number of Securities Underlying Options (#) | | Exercise or Base Price of Option Awards ($ / Unit) | | Grant Date Fair Value of Unit Awards (1) | ET Unit Awards: | | | | | | | | | | | Kelcy L. Warren | | N/A | | — |
| | — |
| | $ | — |
| | $ | — |
| Thomas E. Long | | 12/18/2018 | | 136,475 |
| | — |
| | — |
| | 1,765,987 |
| | | 10/19/2018 | | 115,200 |
| (2) | | | | | 1,965,312 |
| Marshal S. (Mackie) McCrea, III | | 12/18/2018 | | 605,470 |
| | — |
| | — |
| | 7,834,782 |
| Matthew S. Ramsey | | 12/18/2018 | | 168,260 |
| | — |
| | — |
| | 2,177,284 |
| Thomas P. Mason | | 12/18/2018 | | 190,640 |
| | — |
| | — |
| | 2,466,882 |
| John W. McReynolds | | N/A | | — |
| | — |
| | — |
| | — |
| Sunoco LP Unit Awards: | | | | | | | | | | | Thomas E. Long | | 12/19/2018 | | 19,325 |
| | — |
| | — |
| | 520,036 |
| Matthew S. Ramsey | | 12/19/2018 | | 23,825 |
| | — |
| | — |
| | 641,131 |
|
| | (1) | We have computed the grant date fair value of unit awards in accordance with FASB ASC Topic 718, as further described above and in Note 9 to our consolidated financial statements. |
| | (2) | Represents restricted units subject to Mr. Long’s Special Award. |
Narrative Disclosure to Summary Compensation Table and Grants of the Plan-Based Awards Table A description of material factors necessary to understand the information disclosed in the tables above with respect to salaries, bonuses, equity awards, and 401(k) plan contributions can be found in the Compensation Discussion and Analysis that precedes these tables.
Outstanding Equity Awards at 2018 Fiscal Year-End Table | | | | | | | | | | | Name | | Grant Date(1) | | Unit Awards (1) | Number of Units That Have Not Vested(2) (#) | | Market or Payout Value of Units That Have Not Vested (3) ($) | ET Unit Awards: | | | | | | | Kelcy L. Warren | | N/A | | — |
| | $ | — |
| Thomas E. Long | | 12/18/2018 | | 136,475 |
| | 1,802,835 |
| | | 10/19/2018 | | 115,200 |
| | 1,521,792 |
| | | 12/20/2017 | | 121,074 |
| | 1,599,388 |
| | | 12/29/2016 | | 75,588 |
| | 998,517 |
| | | 12/9/2015 | | 14,227 |
| | 187,941 |
| | | 12/4/2015 | | 5,739 |
| | 75,816 |
| | | 12/16/2014 | | 10,486 |
| | 138,520 |
| Marshal S. (Mackie) McCrea, III | | 12/18/2018 | | 605,740 |
| | 8,001,825 |
| | | 12/20/2017 | | 537,379 |
| | 7,098,777 |
| | | 12/29/2016 | | 430,575 |
| | 5,687,889 |
| | | 12/9/2015 | | 94,855 |
| | 1,253,032 |
| | | 12/4/2015 | | 47,816 |
| | 631,650 |
| | | 12/16/2014 | | 48,115 |
| | 635,602 |
| | | 12/5/2014 | | 21,062 |
| | 278,231 |
| Matthew S. Ramsey | | 12/18/2018 | | 168,260 |
| | 2,222,715 |
| | | 12/20/2017 | | 223,908 |
| | 2,957,825 |
| | | 12/29/2016 | | 183,601 |
| | 2,425,369 |
| | | 12/9/2015 | | 59,282 |
| | 783,119 |
| Thomas P. Mason | | 12/18/2018 | | 190,640 |
| | 2,518,354 |
| | | 12/20/2017 | | 135,300 |
| | 1,787,313 |
| | | 12/29/2016 | | 101,613 |
| | 1,342,306 |
| | | 12/9/2015 | | 22,391 |
| | 295,785 |
| | | 12/4/2015 | | 11,287 |
| | 149,101 |
| | | 12/16/2014 | | 16,592 |
| | 219,181 |
| | | 12/5/2014 | | 7,740 |
| | 102,248 |
| John W. McReynolds | | N/A | | — |
| | — |
| | | | | | | | Sunoco LP Unit Awards: | | | | | | | Thomas E. Long | | 12/19/2018 | | 19,325 |
| | $ | 525,447 |
| | | 12/21/2017 | | 17,097 |
| | 464,867 |
| | | 12/29/2016 | | 22,210 |
| | 603,890 |
| | | 12/16/2015 | | 5,650 |
| | 153,624 |
| Matthew S. Ramsey | | 12/19/2018 | | 23,825 |
| | 647,802 |
| | | 1/2/2015 | | 814 |
| | 22,133 |
| | | 11/10/2014 | | 299 |
| | 8,130 |
| Thomas P. Mason | | 12/21/2017 | | 19,106 |
| | 519,492 |
| | | 12/29/2016 | | 7,410 |
| | 201,483 |
| | | 12/16/2015 | | 23,300 |
| | 633,527 |
|
| | (1) | Certain of these outstanding awards represent Energy Transfer Partners, L.P. awards that converted into ET awards upon the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. in October 2018. Furthermore, some of those converted awards had previously been converted in connection with the Regency Merger,merger of Energy Transfer Partners, L.P. and Sunoco Logistics in April 2017. |
| | (2) | ET unit awards outstanding vest at a rate of 60% in December 2020 and 40% in December 2022 for awards granted in December 2017. Such awards may be settledat the Regency Revolving Credit Facility was paid offelection of the ET Compensation Committee in full and terminated.(i) common units of ET (subject to the approval of the ET Incentive Plans prior to the first vesting date by a majority of ET’s unitholders pursuant to the rules of the New York Stock Exchange); (ii) cash equal to the Fair Market Value (as such term is defined in the ET Incentive Plans) |
The following table reflects future maturities of long-term debt for each
of the next five years and thereafter. These amounts exclude $96 million in unamortized premiums, fair value adjustments and deferred debt issuance costs, net: | | | | | 2016 | $ | 308 |
| 2017 | 1,189 |
| 2018 | 2,515 |
| 2019 | 5,007 |
| 2020 | 4,729 |
| Thereafter | 23,316 |
| Total | $ | 37,064 |
|
Long-term debt reflected on our consolidated balance sheets includes fair value adjustments related to interest rate swaps, which represent fair value adjustmentsET common units that had been recorded in connection with fair value hedge accounting priorwould otherwise be delivered pursuant to the terminationterms of each named executive officers grant agreement; or (iii) other securities or property in an amount equal to the Fair Market Value of ET common units that would otherwise be delivered pursuant to the terms of the interestgrant agreement, or a combination thereof as determined by the ET Compensation Committee in its discretion.
Other unit awards outstanding vest as follows: at a rate swap.of 60% in December 2021 and 40% in December 2023 for awards granted in October and December 2018; Notesat a rate of 60% in December 2020 and Debentures40% in December 2022 for awards granted in December 2017;
ETE Senior Notesat a rate of 60% in December 2019 and 40% in December 2021 for awards granted in December 2016;
The ETE Senior Notes are100% in December 2020 for the Parent Company’s senior obligations, ranking equallyremaining outstanding portion of awards granted in rightDecember 2015; and
100% in December 2019 for the remaining outstanding portion of payment withall other awards. | | (3) | Market value was computed as the number of unvested awards as of December 31, 2018 multiplied by the closing price of respective common units of ET and Sunoco LP. |
Option Exercises and Units Vested Table | | | | | | | | | | | Unit Awards | Name | | Number of Units Acquired on Vesting (#) | | Value Realized on Vesting ($) (1) | ET Unit Awards: | | | | | Kelcy L. Warren | | — |
| | $ | — |
| Thomas E. Long | | 38,291 |
| | 556,981 |
| Marshall S. (Mackie) McCrea, III | | 295,241 |
| | 4,294,546 |
| Matthew S. Ramsey | | 88,923 |
| | 1,293,474 |
| Thomas P. Mason | | 81,949 |
| | 1,192,030 |
| John W. McReynolds | | — |
| | — |
| Sunoco LP Unit Awards: | | | | | Thomas E. Long | | 8,475 |
| | 235,859 |
| Matthew S. Ramsey | | 1,221 |
| | 38,895 |
| Thomas P. Mason | | 11,113 |
| | 309,275 |
|
| | (1) | Amounts presented represent the value realized upon vesting of these awards, which is calculated as the number of units vested multiplied by the applicable closing market price of applicable common units upon the vesting date. |
We have not issued option awards. Potential Payments Upon a Termination or Change of Control Equity Awards. As discussed in our other existingCompensation Discussion and future unsubordinated debt and senior toAnalysis above, any unvested equity awards granted pursuant the ET Incentive Plans will automatically become vested upon a change of its future subordinated debt. The Parent Company’s obligations undercontrol, which is generally defined as 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 alloccurrence of one or more of the Parent Company’s and certainfollowing events: (i) any person or group becomes the beneficial owner of its subsidiaries’ tangible and intangible assets, subject to certain exceptions and permitted liens. The ETE Senior Notes are not guaranteed by any50% or more of the Parent Company’s subsidiaries. The covenants relatedvoting power or voting securities of ET or its general partner; (ii) LE GP, LLC or an affiliate of LE GP, LLC ceases to be 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 salesgeneral partner of ET; or (iii) the sale or other disposition, including by liquidation or dissolution, of all or substantially all of the Parent Company’s assets.assets of ET in one or more transactions to anyone other than an affiliate of ET.
In addition, as explained in Equity Awards section of our Compensation Discussion and Analysis above, the restricted unit awards and phantom unit awards under the ET Incentive Plans, the Sunoco LP Plan and the 2012 Sunoco LP Plan generally require the continued employment of the recipient during the vesting period, provided however, the unvested awards will be accelerated in the event of the death or disability of the award recipient prior to the applicable vesting period being satisfied. All awards outstanding to the named executive officers under the ET Incentive Plans, the 2018 Sunoco LP Plan or the 2012 Sunoco LP Plan would be accelerated in the event of a change in control of the Partnership. The 2014 awards to Mr. McCrea and the 2018 Special Award to Mr. Long included a provision in the applicable award agreement for acceleration of unvested restricted unit/restricted phantom unit awards upon a termination of employment by the general partner of the applicable partnership issuing the award without “cause.” For purposes of the awards the term “cause” shall mean: (i) a conviction (treating a nolo contendere plea as a conviction) of a felony (whether or not any right to appeal has been or may be
exercised), (ii) willful refusal without proper cause to perform duties (other than any such refusal resulting from incapacity due to physical or mental impairment), (iii) misappropriation, embezzlement or reckless or willful destruction of property of the partnership or any of its affiliates, (iv) knowing breach of any statutory or common law duty of loyalty to the partnership or any of its or their affiliates, (v) improper conduct materially prejudicial to the business of the partnership or any of its or their affiliates, (vi) material breach of the provisions of any agreement regarding confidential information entered into with the partnership or any of its or their affiliates or (vii) the continuing failure or refusal to satisfactorily perform essential duties to the partnership or any of its or their affiliates. In addition, the ET Compensation Committee and the compensation committee of the general partner of Sunoco LP, have approved a retirement provision, which provides that employees, including the named executive officers with at least ten years of service with the general partner, who leave the respective general partner voluntarily due to retirement (i) after age 65 but prior to age 68 are eligible for accelerated vesting of 40% of his or her award; or (ii) after 68 are eligible for accelerated vesting of 50% his or her award. The acceleration of the awards is subject to the applicable provisions of IRC Section 409(A). In February 2016, Mr. Mason received a one-time special incentive retention bonus in the amount of $6,300,000 (the “Special Bonus”). The Special Bonus was in recognition of, among other things, (i) Mr. Mason’s appointment as the Executive Vice President and General Counsel of the General Partner; (ii) his 2015 calendar year performance; and (iii) his contributions to the family of partnerships on several key initiatives, including (a) the drop-down transactions by and between ETO and Sunoco LP, (b) the proposed merger transaction between the ET and The Williams Companies, Inc., (c) the liquefied natural gas (LNG) export project of ET, and (d) the simplification of the overall Energy Transfer family structure. The approval of the Special Bonus was conditioned upon entry by Mr. Mason into a Retention Agreement (the “Retention Agreement”) which provides (i) if, prior to the third (3rd) anniversary of the effective date of the Retention Agreement, Mr. Mason’s employment terminates (other than as a result of (x) a termination without cause or by Mr. Mason for Good Reason; (y) his death; or (z) his permanent disability), he will be obligated to remit and repay one-hundred percent (100%) of the Special Bonus to ET; (ii) if, after the third (3rd) anniversary but prior to the fourth (4th) anniversary of the effective date of the Retention Agreement, Mr. Mason’s employment terminates (other than as a result of (x) a termination without cause by ET or by Mr. Mason for Good Reason; (y) his death; or (z) his permanent disability), he will be obligated to remit and repay seventy-five percent (75%) of the Special Bonus; and (iii) if, after the fourth (4th) anniversary but prior to the fifth (5th) anniversary of the effective date of the Retention Agreement, Mr. Mason’s employment terminates (other than as a result of (x) a termination without cause by ET or by Mr. Mason for Good Reason; (y) his death; or (z) his permanent disability), he will be obligated to remit and repay fifty percent (50%) of the Special Bonus. Mr. Mason entered into the Retention Agreement on February 24, 2016. Deferred Compensation Plan. As discussed in our Compensation Discussion and Analysis above, all amounts under the ET NQDC Plan (other than discretionary credits) are immediately 100% vested. Upon a change of control (as defined in the ET NQDC Plan), distributions from the respective plan would be made in accordance with the normal distribution provisions of the respective plan. A change of control is generally defined in the ET NQDC Plan as any change of control event within the meaning of Treasury Regulation Section 1.409A-3(i)(5). CEO Pay Ratio In accordance with Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, and Item 402(u) of Regulation S-K, set forth below is information about the relationship of the annual total compensation of Mr. McReynolds, who served as the Principal Executive Officer of ET prior to the Energy Transfer Merger, and the annual total compensation of our employees. The Partnership has not incurred any significant changes in the composition of its employee population, compensation programs or employee benefits and as such will continue to rely on its determination of the “median employee” and the median of the annual total compensation of the employees supporting ET, as permitted, on its 2017 CEO Pay Ratio disclosure. The determination to include only Mr. McReynolds was based on the fact that he served as ET’s Principal Executive Officer for 75% of the year and Mr. Warren, who is now ET’s Chairman and Chief Executive Officer, does not accept or receive compensation other than an amount sufficient to cover his allocated payroll deductions for health and welfare benefits. For the 2018 calendar year: The annual total compensation of Mr. McReynolds, as reported in the Summary Compensation Tables of this Item 11was $5,926; and For 2018, the median total compensation of the employees supporting ETO (other than Mr. McReynolds) was $115,908, which amount was updated from 2017 for the designated “median employee.” Based on this information, for 2017 the ratio of the annual total compensation of Mr. McReynolds to the median of the annual total compensation of the 8,494 employees supporting ETO as of December 31, 2017 was approximately 12 to 1.
To identify the median of the annual total compensation of the employees supporting ETO, the following steps were taken: | | 1. | It was determined that, as of December 31, 2017, the applicable employee populations consisted of 8,494 with all of the identified individuals being employed in the United States. This population consisted of all of our full-time and part-time employees. We did not engage any independent contractors in 2017 or 2018 that are required to be included in our employee population for the CEO pay ratio evaluation. |
| | 2. | To identify the “median employee” from our employee population, we compared the total earnings of our employees as reflected in our payroll records as reported on Form W-2 for 2017 and, for 2018, updated the compensation of the “median employee” as reflected in our payroll records as reported on Form W-2 for 2018. |
| | 3. | We identified our median employee using W-2 reporting and applied this compensation measure consistently to all of our employees required to be included in the calculation. We did not make any cost of living adjustments in identifying the “median employee”. |
| | 4. | Once we identified our median employee, we combined all elements of the employee’s compensation for 2017 resulting in an annual compensation of $115,908. The difference between such employee’s total earnings and the employee’s total compensation represents the estimated value of the employee’s health care benefits (estimated for the employee and such employee’s eligible dependents at $10,800) and the employee’s 401(k) matching contribution and profit sharing contribution (estimated at $5,846 per employee, includes $3,633 per employee on average matching contribution and $2,213 per employee on average profit sharing contribution (employees earning over $175,000 in base are ineligible for profit sharing)). |
| | 5. | With respect to Mr. McReynolds, we used the amount reported in the “Total” column of our 2017 Summary Compensation Table under this Item 11. |
Director Compensation Directors of our General Partner, who are employees of the ETP GP or any of their subsidiaries, are not eligible for director compensation. In 2018, the compensation arrangements for outside directors included a $100,000 annual retainer for services on the board. If a director served on the ET Audit Committee, such director would receive an annual retainer ($15,000 or $25,000 in the case of the chairman). If a director served on the ET Compensation Committee, such director would receive an annual cash retainer ($7,500 or $15,000 in the case of the chairman). The fees for membership on the Conflicts Committee are determined on a per instance basis for each committee assignment. The outside directors of our General Partner are also entitled to an annual award under the ET Incentive Plans equal to an aggregate of $100,000 divided by the closing price of ET common units on the date of grant. These ET common units will vest 60% after the third year and the remaining 40% after the fifth year after the grant date. The compensation expense recorded is based on the grant-date market value of the ET common units and is recognized over the vesting period. Distributions are paid during the vesting period.
The compensation paid to the non-employee directors of our General Partner in 2018 is reflected in the following table: | | | | | | | | | | | | | | | | | | Name | | Fees Paid in Cash(1) ($) | | Unit Awards(2) ($) | | All Other Compensation ($) | | Total ($) | Steven R. Anderson (3) | | | | | | | | | As ET director | | $ | 91,760 |
| | $ | 44,200 |
| | $ | — |
| | $ | 135,960 |
| Richard D. Brannon | | | | | | | | | As ET director | | 194,225 |
| | 100,000 |
| | — |
| | 294,225 |
| Ray C. Davis | | | | | | | | | As ET director | | 25,000 |
| | 42,700 |
| | — |
| | 67,700 |
| As ETO director | | 49,750 |
| | — |
| | — |
| | 49,750 |
| Michael K. Grimm (3) | | | | | | | | | As ET director | | — |
| | — |
| | — |
| | — |
| As ETO director | | 205,425 |
| | 100,068 |
| | — |
| | 305,493 |
| K. Rick Turner (4) | |
|
| |
|
| | | |
| As ET director | | 99,701 |
| | 100,000 |
| | — |
| | 199,701 |
| As Sunoco LP Director | | 46,614 |
| | 100,006 |
| | — |
| | 146,620 |
| William P. Williams (4) | | | | | | | | | As ET director | | 128,650 |
| | 100,000 |
| | — |
| | 228,650 |
|
| | (1) | Fees paid in cash are based on amounts paid during the period. |
| | (2) | Unit award amounts reflect the aggregate grant date fair value of awards granted based on the market price of ET common units, ETO common units (prior to the Merger) or Sunoco LP Common Units, accordingly, as of the grant date. |
| | (3) | Messrs. Anderson and Grimm were appointed to the Board of Directors of LE GP on June 4, 2018 and October 19, 2018, respectively. |
| | (4) | Messrs. Turner and Williams resigned from the Board of Directors of LE GP on June 1, 2018 and October 19, 2018, respectively. |
As of December 31, 2018, Mr. Anderson had 2,500 unvested ET restricted units outstanding, Mr. Brannon had 13,353 unvested ET restricted units outstanding, Mr. Davis had 2,500 unvested ET restricted units outstanding and Mr. Grimm had 20,262 unvested ET restricted units outstanding. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS Equity Compensation Plan Information The following table sets forth in tabular format, a summary of our equity plan information as of December 31, 2018: | | | | | | | | | | | | Plan Category | | Number of securities to be issued upon exercise of outstanding options, warrants and rights (a) | | Weighted-average exercise price of outstanding options, warrants and rights (b) | | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c) | Equity compensation plans approved by security holders | | — |
| | $ | — |
| | — |
| Equity compensation plans not approved by security holders: | | 22,429,859 |
| | — |
| | 15,061,559 |
| Total | | 22,429,859 |
| | $ | — |
| | 15,061,559 |
|
Energy Transfer LP Units The following table sets forth certain information as of February 15, 2019, regarding the beneficial ownership of our voting securities by (i) certain beneficial owners of more than 5% of our Common Units, (ii) each director and named executive officer of our General Partner and (iii) all current directors and executive officers of our General Partner as a group. The General Partner knows of no other person not disclosed herein who beneficially owns more than 5% of our Common Units. | | | | | | | | Name and Address of Beneficial Owner (1) | | Beneficially Owned (2) | | Percent of Class | Kelcy L. Warren (3) | | 241,479,586 |
| | 9.2 | % | Ray C. Davis (4) | | 87,891,646 |
| | 3.4 | % | John W. McReynolds (5) | | 27,270,400 |
| | 1.0 | % | Thomas E. Long | | 141,983 |
| | * |
| Marshall S. (Mackie) McCrea, III | | 1,922,870 |
| | * |
| Matthew S. Ramsey | | 148,051 |
| | * |
| Thomas P. Mason | | 607,850 |
| | * |
| Richard D. Brannon | | 188,932 |
| | * |
| Steven R. Anderson (6) | | 1,544,588 |
| | * |
| Michael K. Grimm (7) | | 96,313 |
| | * |
| All Directors and Executive Officers as a group (11 persons) | | 361,327,518 |
| | 13.8 | % |
| | (1) | The address for Mr. Davis is 5950 Sherry Lane, Dallas, Texas 75225. The address for all other listed beneficial owners is 8111 Westchester Drive, Suite 600, Dallas, Texas 75225. |
| | (2) | Beneficial ownership for the purposes of this table is defined by Rule 13d-3 under the Exchange Act of 1934. Under that rule, a person is generally considered to be the beneficial owner of a security if he has or shares the power to vote or direct the voting thereof or to dispose or direct the disposition thereof or has the right to acquire either of those powers within sixty days. The nature of beneficial ownership for all listed persons is direct with sole investment and disposition power unless otherwise noted. The beneficial ownership of each listed person is based on 2,619,391,387 Common Units outstanding in the aggregate as of February 15, 2019. |
| | (3) | Includes 98,093,962 Common Units held by Kelcy Warren Partners, L.P. and 10,244,429 Common Units held by Kelcy Warren Partners II, L.P., the general partners of which are owned by Mr. Warren. Also includes 91,585,486 Common Units held by Seven Bridges Holdings, LLC, of which Mr. Warren is a member. Also includes 328,383 Common Units attributable to the interest of Mr. Warren in ET Company Ltd and Three Dawaco, Inc., over which Mr. Warren exercises shared voting and dispositive power with Ray Davis. Also includes 601,076 Common Units held by LE GP, LLC. Mr. Warren may be deemed to own Common Units held by LE GP, LLC due to his ownership of 81.2% of its member interests. The voting and disposition of these Common Units is directly controlled by the board of directors of LE GP, LLC. Mr. Warren disclaims beneficial ownership of Common Units owned by LE GP, LLC other than to the extent of his interest in such entity. Also includes 104,166 Common Units held by Mr. Warren’s spouse. |
| | (4) | Includes 51,701 Common Units held by Avatar Holdings LLC, 1,941,721 Common Units held by Avatar BW, Ltd., 28,203,003 Common Units held by Avatar ETC Stock Holdings LLC, 3,557,757 Common Units held by Avatar Investments LP, 121,117 Common Units held by Avatar Stock Holdings, LP and 1,112,069 Common Units held by RCD Stock Holdings, LLC, all of which entities are owned or controlled by Mr. Davis. Also includes 15,987,283 Common Units held by a remainder trust for Mr. Davis’ spouse and 9,536,054 Common Units held by two trusts for the benefit of Mr. Davis’ grandchildren, for which Mr. Davis serves as trustee. Mr. Davis shares voting and dispositive power with his wife with respect to Common Units held directly. Also includes 328,383 Common Units attributable to ET Company Ltd. Mr. Davis is a former executive officer and director of ETO and is currently a director of the general partner of ET, LE GP, LLC. |
| | (5) | Includes 17,445,608 Common Units held by McReynolds Energy Partners L.P. and 12,142,593 Common Units held by McReynolds Equity Partners L.P., the general partners of which are owned by Mr. McReynolds. Mr. McReynolds disclaims beneficial ownership of Common Units owned by such limited partnerships other than to the extent of his interest in such entities. |
| | (6) | Includes 1,544,558 held by Steven R. Anderson Revocable Trust, for which Mr. Anderson serves as trustee. |
| | (7) | Includes 5,888 Units held by two trusts for the benefit of Mr. Grimm’s children, for which Mr. Grimm serves as trustee. |
In connection with the Parent Company’s outstanding senior notes are collateralized by its interests inCompany Credit Agreement, ET and certain of its subsidiaries. SEC Rule 3-16subsidiaries entered into a Pledge and Security Agreement (the “Security Agreement”) with Credit Suisse AG, Cayman Islands Branch, as collateral agent (the “Collateral Agent”). The Security Agreement secures all of Regulation S-X (“Rule 3-16”) requiresET’s obligations under the Parent Company Credit Agreement and grants to the Collateral Agent a registrant to file financial statements for eachcontinuing first priority lien on, and security interest in, all of its affiliates whose securities constitute a substantial portionET’s and the other grantors’ tangible and intangible assets. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE As of the collateral for registered securities. The Parent Company’s limited partnerDecember 31, 2018, our interests in ETP constitute substantial portionsETO consisted of the collateral for the Parent Company’s outstanding senior notes; accordingly, financial statements of ETP are required under Rule 3-16 to be included in this Annual Report on Form 10-K and have been included herein. The Parent Company’s interests in ETP GP and ETE Common Holdings, LLC, (collectively, the “Non-Reporting Entities”) also constitute substantial portions of the collateral for the Parent Company’s outstanding senior notes. Accordingly, the financial statements of the Non-Reporting Entities 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 has substantive operations of its own; rather, each of the Non-Reporting Entities holds only direct or indirect interests in ETP and/or the consolidated subsidiaries of ETP. Following is a summary of the interests held by each of the Non-Reporting Entities, as well as a summary of the significant differences between each of the Non-Reporting Entities compared to ETP:
ETP GP owns 100% of the general partner interestinterests and 1,313,568,560 ETO common units.
The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments 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 $20.53 billion and $11.94 billion as of December 31, 2015 and 2014, respectively, would be reflected as noncontrolling interests on ETP GP’s balance sheets. Likewise, ETP’s income (loss) attributable to limited partners (including common unitholders, Class H unitholders and Class I unitholders) of $334 million, $823 million and $(50) million for the years ended December 31, 2015, 2014 and 2013, respectively, would be reflected as income attributable to noncontrolling interest in ETP GP’s statements of operations.
As of December 31, 2014, ETE Common Holdings, LLC (“ETE Common Holdings”) owned 5.2 million ETP Common Units, representing approximately 1.5% of the total outstanding ETP Common Units, and 50.2 million ETP Class H Units, representing 100% of the total outstanding ETP Class H Units. ETE Common Holdings also owned 30.9 million Regency Common Units, representing approximately 7.5% of the total outstanding Regency Common Units; ETE Common Holdings’ interest in Regency was acquired in 2014. During 2015, all of the units held by ETE Common Holdings were redeemed by ETP. ETE Common Holdings does not own the general partner interests in ETP; therefore,ETO, Sunoco LP and USAC, all of which are limited partnerships engaged in diversified energy-related services, and cash flows from the financial statementsoperations of ETE Common Holdings would only reflect equity method investmentsLake Charles LNG.
Mr. McCrea and Mr. Ramsey, current directors of LE GP, LLC, our general partner, are also directors and executive officers of ETO’s general partner. In addition, Mr. Warren, our Chief Executive Officer and Chairman of our Board of Directors, is also the Chairman and Chief Executive Officer of ETO’s general partner. For a discussion of director independence, see Item 10. “Directors, Executive Officers and Corporate Governance.” As a policy matter, our Conflicts Committee generally reviews any proposed related party transaction that may be material to the Partnership to determine whether the transaction is fair and reasonable to the Partnership. The Partnership’s board of directors makes the determinations as to whether there exists a related party transaction in ETP. The carrying valuesthe normal course of ETE Common Holdings’ investmentsreviewing transactions for approval as the Partnership’s board of directors is advised by its management of the parties involved in ETP was $1.72 billioneach material transaction as to which the board of December 31, 2014, and ETE Common Holdings’ equitydirectors’ approval is sought by the Partnership’s management. In addition, the Partnership’s board of directors makes inquiries to independently ascertain whether related parties may have an interest in earnings from its investments in ETP was $292 millionthe proposed transaction. While there are no written policies or procedures for the year ended December 31, 2014. ETP’s general partner interest, Common Units and Class H Units are reflected separatelyboard of directors to follow in ETP’s financial statements. As a result,making these determinations, the financial statements of the Non-Reporting Entities would substantially duplicate information that is availablePartnership’s board makes those determinations in the financial statements of ETP. Therefore, the financial statements of the Non-Reporting Entities have been excluded from this Annual Report on Form 10-K.
In May 2015, ETE issued $1 billion aggregate principal amountlight of its 5.5% senior notes maturing June 1, 2027.
ETP as Co-Obligor of Sunoco, Inc. Debt
In connection with the Sunoco Merger and ETP Holdco Transaction, ETP became a co-obligor on approximately $965 million of aggregate principal amount of Sunoco, Inc.’s existing senior notes and debentures. The balance of these notes was $465 million as of December 31, 2015.
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 3.65% at December 31, 2015.
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, pursuantcontractually-limited fiduciary duties to the termsUnitholders. The partnership agreement of ET provides that any matter approved by the indentureConflicts Committee will be conclusively deemed to be fair and related indenture supplements relatedreasonable to ET, approved by all the ETP senior notes. The balance is payable upon maturity. Interest onpartners of ET and not a breach by the ETP senior notes is paid semi-annually.
The ETP senior notes are unsecured obligationsGeneral Partner or its Board of ETP and the obligation of ETP to repay the ETP senior notes is not guaranteed by us or any of ETP’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.
In June 2015, ETP issued $650 million aggregate principal amount of 2.50% senior notes due June 2018, $350 million aggregate principal amount of 4.15% senior notes due October 2020, $1.0 billion aggregate principal amount of 4.75% senior notes due January 2026 and $1.0 billion aggregate principal amount of 6.125% senior notes due December 2045. ETP used the net proceeds of $2.98 billion from the offering to repay outstanding borrowings under the ETP Credit Facility, to fund growth capital expenditures and for general partnership purposes.
In March 2015, ETP issued $1.0 billion aggregate principal amount of 4.05% senior notes due March 2025, $500 million aggregate principal amount of 4.90% senior notes due March 2035, and $1.0 billion aggregate principal amount of 5.15% senior notes due March 2045. ETP used the $2.48 billion net proceeds from the offering to repay outstanding borrowings under the ETP Credit Facility, to fund growth capital expenditures and for general partnership purposes.
At the time of the Regency Merger, Regency had outstanding $5.1 billion principal amount of senior notes. On June 1, 2015, Regency redeemed all of the outstanding $499 million aggregate principal amount of its 8.375% senior notes due June 2019.
Panhandle previously agreed to fully and unconditionally guarantee (the “Panhandle Guarantee”) all of the payment obligations of Regency and Regency Energy Finance Corp. under their $600 million in aggregate principal amount of 4.50% senior notes due November 2023. On May 28, 2015, ETP entered into a supplemental indenture relating to the senior notes pursuant to which it became a co-obligor with respect to such payment obligations thereunder. Accordingly, pursuant to the terms of such supplemental indentures the Panhandle Guarantee was terminated.
On August 10, 2015, ETP entered into various supplemental indentures pursuant to which ETP has agreed to assume all of the obligations of Regency under the outstanding Regency senior notes.
On August 13, 2015, ETP redeemed in full the outstanding amount of the 8.375% senior notes due June 2020 (“the 2020 notes”) and 6.50% senior notes due May 2021 (“the 2021 notes”). The amount paid to redeem the 2020 Notes included a make whole premium of $40 million and the amount paid to redeem the 2021 Notes included a make whole premium of $24 million.
Transwestern Senior Notes
The Transwestern senior notes are redeemable at any time in whole or pro rata in part, subject to a premium or upon a change of control event or an event of default, as defined. The balance is payable upon maturity. Interest is payable semi-annually.
Sunoco Logistics Senior Notes Offerings
In November 2015, Sunoco Logistics issued $600 million aggregate principal amount of 4.40% senior notes due April 2021 and $400 million aggregate principal amount of 5.95% senior notes due December 2025.
Sunoco LP Senior Notes
In July 2015, Sunoco LP issued $600 million aggregate principal amount of 5.5% senior notes due August 2020. The net proceeds from the offering were used to fund a portion of the cash consideration for Sunoco LP’s acquisition of Susser.
In April 2015, Sunoco LP issued $800 million aggregate principal amount of 6.375% senior notes due April 2023. The net proceeds from the offering were used to fund the cash portion of the dropdown of Sunoco, LLC interests and to repay outstanding balances under the Sunoco LP revolving credit facility.
Term Loans and Credit Facilities
ETE Term Loan Facility
The Parent Company has a Senior Secured Term Loan Agreement (the “ETE Term Credit Agreement”), which has a scheduled maturity date of December 2, 2019, with an option to extend the term subject to the terms and conditions set forth therein. Pursuant to the ETE Term Credit Agreement, the lenders have provided senior secured financing in an aggregate principal amount of $1.0 billion (the “ETE Term Loan Facility”). The Parent Company shall not be required to make any amortization payments with respect to the term loans under the Term Credit Agreement. Under certain circumstances, the Partnership is required to repay the term loan in connection with dispositions of (a) incentive distribution rights in ETP or Regency, (b) general partnership interests in Regency or (c) equity interestsDirectors of any Person which owns, directlyduties they may owe ET or indirectly, incentive distribution rightsthe Unitholders (see “Risks Related to Conflicts of Interest” in ETP or Regency or general partnership interests“Item 1A. Risk Factors” in Regency, in each case, yielding net proceeds in excess of $50 million.
Under the Term Credit Agreement, the obligations of the Parent Company are secured by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets, subject to certain exceptions and permitted liens. The ETE Term Loan Facility initially is 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. The applicable margin for LIBOR rate loans is 2.50% and the applicable margin for base rate loans is 1.50%.
In April 2014, the Parent Company amended its Senior Secured Term Loan 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 date and interest rate.
In March 2015, the Parent Company entered into a Senior Secured Term Loan C Agreement (the “ETE Term Loan C Agreement”), which increased the aggregate principal amount under the ETE Term Loan Facility to $2.25 billion, an increase of $850 million. The Parent Company used the proceeds (i) to fund the cash consideration for the Bakken Pipeline Transaction, (ii) to repay amounts outstanding under the Partnership’s revolving credit facility, and (iii) to pay transaction fees and expenses related to the Bakken Pipeline Transaction, the Term Loan Facility and other transactions incidental thereto. Under the ETE Term Loan C Agreement, 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; the applicable margin for LIBOR rate loans is 3.25% and the applicable margin for base rate loans is 2.25%annual report).
For the $1.4 billion aggregate principal amount under the Senior Secured Term Loan B Agreement of the ETE Term Loan Facility, 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. The applicable margin for LIBOR rate loans is 2.50% and the applicable margin for base rate loans is 1.50%.
In October 2015, ETE entered into an Amended and Restated Commitment Letter with a syndicate of 20 banks for a senior secured credit facility in an aggregate principal amount of $6.05 billion in order to fund the cash portion of the WMB Merger. Under the terms of the facility, the banks have committed to provide a 364-day secured loan that can be extended at ETE’s option for an additional year. The interest rate on the facility is capped at 5.5%.
ETE Revolving Credit Facility
The Parent Company has a credit agreement (the “Revolving Credit Agreement”) which has a scheduled maturity date of December 2, 2018,agreements with an option for the Partnership to extend the term subject to the terms and conditions set forth therein. Pursuant to the Revolver Credit Agreement, the lenders have committedsubsidiaries to provide advances upor receive various general and administrative services. The Parent Company pays ETO to an aggregate principal amount of $600 million at any one time outstanding (the “ETE Revolving Credit Facility”),provide services on its behalf 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 Facility 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.
As partbehalf 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 million sublimit.
Under the Revolver 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. 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. 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 ratioother subsidiaries 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 fee basedreceives management fees from certain of its subsidiaries, which include the reimbursement of various general and administrative services for expenses incurred by ETO on its leverage ratio onbehalf of those subsidiaries. All such amounts have been eliminated in our consolidated financial statements.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES The following sets forth fees billed by Grant Thornton LLP for the actual daily unused amountaudit of our annual financial statements and other services rendered (dollars in millions): | | | | | | | | | | Years Ended December 31, | | 2018 | | 2017 | Audit fees (1) | $ | 11.6 |
| | $ | 11.5 |
| Audit-related fees (2) | 0.5 |
| | — |
| Tax fees (3) | 0.1 |
| | — |
| Total | $ | 12.2 |
| | $ | 11.5 |
|
| | (1) | Includes fees for audits of annual financial statements of our companies, reviews of the related quarterly financial statements, and services that are normally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents filed with the SEC and services related to the audit of our internal controls over financial reporting. |
| | (1) | Includes fees in 2018 for financial statement audits of subsidiary entities in connection with contribution and sale transactions. |
| | (2) | Includes fees in 2018 related to state and local tax consultation. |
Pursuant to the charter of the aggregate commitments. ETP Credit FacilityAudit Committee, the Audit Committee is responsible for the oversight of our accounting, reporting and financial practices. The Audit Committee has the responsibility to select, appoint, engage, oversee, retain, evaluate and terminate our external auditors; pre-approve all audit and non-audit services to be provided, consistent with all applicable laws, to us by our external auditors; and establish the fees and other compensation to be paid to our external auditors. The Audit Committee also oversees and directs our internal auditing program and reviews our internal controls.
The ETP Credit Facility allowsAudit Committee has adopted a policy for borrowingsthe pre-approval of upaudit and permitted non-audit services provided by our principal independent accountants. The policy requires that all services provided by Grant Thornton LLP including audit services, audit-related services, tax services and other services, must be pre-approved by the Audit Committee. All fees paid or expected to $3.75 billionbe paid to Grant Thornton LLP for fiscal years 2018 and expires2017 were pre-approved by the Audit Committee in November 2019. accordance with this policy. The indebtedness underAudit Committee reviews the ETP Credit Facility is unsecuredexternal auditors’ proposed scope 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. ETP uses the ETP Credit Facility to provide temporary financing for ETP’s growth projects,approach as well as the performance of the external auditors. It also has direct responsibility for general partnership purposes.and sole authority to resolve any disagreements between our management and our external auditors regarding financial reporting, regularly reviews with the external auditors any problems or difficulties the auditors encountered in the course of their audit work, and, at least annually, uses its reasonable efforts to obtain and review a report from the external auditors addressing the following (among other items): Asthe auditors’ internal quality-control procedures;
any material issues raised by the most recent internal quality-control review, or peer review, of December 31, 2015, the ETP Credit Facility had $1.36 billion outstanding,external auditors; the independence of the external auditors; the aggregate fees billed by our external auditors for each of the previous two years; and the amount available for future borrowings was $2.24 billion after taking into account lettersrotation of credit of $145 million. The weighted average interest rate on the total amount outstanding as of December 31, 2015 was 1.86%.lead partner. Sunoco Logistics Credit Facilities
Sunoco Logistics maintains a $2.50 billion unsecured credit facility (the “Sunoco Logistics Credit Facility”) which matures in March 2020. The Sunoco Logistics Credit Facility contains an accordion feature, under which the total aggregate commitment may be extended to $3.25 billion under certain conditions.
The Sunoco Logistics Credit Facility is available to fund Sunoco Logistics’ working capital requirements, to finance acquisitions and capital projects, to pay distributions and for general partnership purposes. The Sunoco Logistics Credit Facility bears interest at LIBOR or the Base Rate, each plus an applicable margin. The credit facility may be prepaid at any time. As of December 31, 2015, the Sunoco Logistics Credit Facility had $562 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”), which matures 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. The Sunoco LP Credit Facility was amended to $1.50 billion in April 2015. As of December 31, 2015,2018, the Sunoco LP Credit Facility had $450$700 million outstanding borrowings and $8 million in standby letters of credit. The unused availability on the revolver at December 31, 2018 was $792 million. The weighted average interest rate on the total amount outstanding as of December 31, 2018 was 4.45%.
USAC Credit Facility As of December 31, 2018, USAC had $1.05 billion of outstanding borrowings and no outstanding letters of credit under the credit agreement. As of December 31, 2018, USAC had $550 million of availability under its credit facility. The weighted average interest rate on the total amount outstanding borrowings.as of December 31, 2018 was 4.69%.
Covenants Related to Our Credit Agreements Covenants Related to the Parent Company The ETE Term Loan Facility and ET Revolving Credit Facility previously contained 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. Both facilities have been paid off and terminated. Covenants Related to ETO The agreements relating to the ETO 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 ETO 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 ETO Credit Facilities) during certain Defaults (as defined in the ETO Credit Facilities) and during any Event of Default (as defined in the ETO 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 ETO 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 ETO 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 ETO Five-Year Facility ranges from 0.125% to 0.300%. The applicable margin for eurodollar rate loans under the ETO 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 ETO 364-Day Facility ranges from 0.125% to 0.225%. The ETO 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 ETO 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 3.38 to 1 at December 31, 2018, 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 Partnership’s or our subsidiaries’ ability to incur additional debt and/or our ability to pay distributions to Unitholders. 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. Covenants Related to Sunoco LP The Sunoco LP Credit Facility contains various customary representations, warranties, covenants and events of default, including a change of control event of default, as defined therein. Sunoco LP’s Credit Facility requires Sunoco LP to maintain a Net Leverage Ratio of not more than 5.5 to 1. The maximum Net Leverage Ratio is subject to upwards adjustment of not more than 6.0 to 1 for a period not to exceed three fiscal quarters in the event Sunoco LP engages in certain specified acquisitions of not less than $50 million (as permitted under Sunoco LP’s Credit Facility agreement). The Sunoco LP Credit Facility also requires Sunoco LP to maintain an Interest Coverage Ratio (as defined in the Sunoco LP’s Credit Facility agreement) of not less than 2.25 to 1. Covenants Related to USAC The USAC Credit Facility contains covenants that limit (subject to certain exceptions) USAC’s ability to, among other things: make certain loans or investments; incur additional indebtedness or guarantee other indebtedness; make certain acquisitions. The credit facility is also subject to the following financial covenants, including covenants requiring us to maintain: a minimum EBITDA to interest coverage ratio of 2.5 to 1.0, determined as of the last day of each fiscal quarter; and
a maximum funded debt to EBITDA ratio, determined as of the last day of each fiscal quarter, for the annualized trailing three months of (i) 5.75 to 1 through the end of the fiscal quarter ending March 31, 2019, (ii) 5.5 to 1 through the end of the fiscal quarter ending December 31, 2019 and (iii) 5.0 to 1 thereafter, in each case subject to a provision for increases to such thresholds by 0.50 in connection with certain future acquisitions for the six consecutive month period following the period in which any such acquisition occurs. Compliance with our Covenants We were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2018. Contractual Obligations The following table summarizes our long-term debt and other contractual obligations as of December 31, 2018: | | | | | | | | | | | | | | | | | | | | | | | | Payments Due by Period | Contractual Obligations | | Total | | Less Than 1 Year | | 1-3 Years | | 3-5 Years | | More Than 5 Years | Long-term debt | | $ | 46,255 |
| | $ | 3,505 |
| | $ | 4,474 |
| | $ | 12,760 |
| | $ | 25,516 |
| Interest on long-term debt(1) | | 27,190 |
| | 2,311 |
| | 4,188 |
| | 3,462 |
| | 17,229 |
| Payments on derivatives | | 181 |
| | 76 |
| | 105 |
| | — |
| | — |
| Purchase commitments(2) | | 2,458 |
| | 2,295 |
| | 121 |
| | 22 |
| | 20 |
| Transportation, natural gas storage and fractionation contracts | | 9 |
| | 8 |
| | 1 |
| | — |
| | — |
| Operating lease obligations | | 601 |
| | 104 |
| | 169 |
| | 108 |
| | 220 |
| Service concession arrangement(3) | | 394 |
| | 15 |
| | 30 |
| | 31 |
| | 318 |
| Other(4) | | 198 |
| | 26 |
| | 51 |
| | 43 |
| | 78 |
| Total(5) | | $ | 77,286 |
| | $ | 8,340 |
| | $ | 9,139 |
| | $ | 16,426 |
| | $ | 43,381 |
|
| | (1) | Interest payments on long-term debt are based on the principal amount of debt obligations as of December 31, 2018. With respect to variable rate debt, the interest payments were estimated using the interest rate as of December 31, 2018. To the extent interest rates change, our contractual obligation for interest payments will change. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for further discussion. |
| | (2) | We define a purchase commitment as an agreement to purchase goods or services that is enforceable and legally binding (unconditional) on us that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transactions. We have long and short-term product purchase obligations for refined product and energy commodities with third-party suppliers. These purchase obligations are entered into at either variable or fixed prices. The purchase prices that we are obligated to pay under variable price contracts approximate market prices at the time we take delivery of the volumes. Our estimated future variable price contract payment obligations are based on the December 31, 2018 market price of the applicable commodity applied to future volume commitments. Actual future payment obligations may vary depending on market prices at the time of delivery. The purchase prices that we are obligated to pay under fixed price contracts are established at the inception of the contract. Our estimated future fixed price contract payment obligations are based on the contracted fixed price under each commodity contract. Obligations shown in the table represent estimated payment obligations under these contracts for the periods indicated. |
| | (3) | Includes minimum guaranteed payments under service concession arrangements with New Jersey Turnpike Authority and New York Thruway Authority. |
| | (4) | Expected contributions to fund our pension and postretirement benefit plans were included in “Other” above. Environmental liabilities, asset retirement obligations, unrecognized tax benefits, contingency accruals and deferred revenue, which were included in “Other non-current liabilities” in our consolidated balance sheets were excluded from the table above as the amounts do not represent contractual obligations or, in some cases, the amount and/or timing of the cash payments is uncertain. |
| | (5) | Excludes net non-current deferred tax liabilities of $2.93 billion due to uncertainty of the timing of future cash flows for such liabilities. |
Cash Distributions Cash Distributions Paid by the Parent Company Under the Parent Company Partnership Agreement, the Parent Company will distribute all of its Available Cash, as defined, within 50 days following the end of each fiscal quarter. Available cash generally means, with respect to any quarter, all cash on hand at the end of such quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the General Partner that is necessary or appropriate to provide for future cash requirements. Distributions declared and paid during the periods presented are as follows: | | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | 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 | | May 10, 2017 | | May 19, 2017 | | 0.2850 |
| June 30, 2017 | | August 7, 2017 | | August 21, 2017 | | 0.2850 |
| September 30, 2017 | | November 7, 2017 | | November 20, 2017 | | 0.2950 |
| December 31, 2017 | | February 8, 2018 | | February 20, 2018 | | 0.3050 |
| March 31, 2018 | | May 7, 2018 | | May 21, 2018 | | 0.3050 |
| June 30, 2018 | | August 6, 2018 | | August 20, 2018 | | 0.3050 |
| September 30, 2018 | | November 8, 2018 | | November 19, 2018 | | 0.3050 |
| December 31, 2018 | | February 8, 2019 | | February 19, 2019 | | 0.3050 |
|
| | (1) | Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forego their cash distributions on all or a portion of their common units for a period of up to nine quarters commencing with the distribution for the quarter ended March 31, 2016 and, in lieu of receiving cash distributions on these common units for each such quarter, each said unitholder received Convertible Units (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $0.11 per Convertible Unit. See Note 8 to the Partnership’s consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.” |
Our distributions declared and paid with respect to our Convertible Unit during the periods presented 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 |
| March 31, 2018 | | May 7, 2018 | | May 21, 2018 | | 0.1100 |
|
The total amounts of distributions declared and paid during the periods presented (all from Available Cash from the Parent Company’s operating surplus and are shown in the period to which they relate) are as follows: | | | | | | | | | | | | | | Years Ended December 31, | | 2018 (1) | | 2017 | | 2016 | Limited Partners | $ | 2,215 |
| | $ | 1,022 |
| | $ | 971 |
| General Partner interest | 3 |
| | 3 |
| | 3 |
| Total Parent Company distributions | $ | 2,218 |
| | $ | 1,025 |
| | $ | 974 |
|
| | (1) | Include distributions declared by Energy Transfer LP for periods subsequent to the Energy Transfer Merger. |
The total amounts of distributions declared and paid during the periods presented prior to the closing of the Energy Transfer Merger as discussed in Note 1 (all from Available Cash from ETO’s operating surplus and are shown in the period to which they relate) are as follows: | | | | | | | | | | | | | | | | | | Years Ended December 31, | | ETO | | Sunoco Logistics | | 2018 | | 2017 | | 2016 | | 2016 | Common Units held by public | $ | 1,286 |
| | $ | 2,435 |
| | $ | 2,168 |
| | $ | 485 |
| Common Units held by ETO | — |
| | — |
| | — |
| | 135 |
| Common Units held by ET | 31 |
| | 61 |
| | 28 |
| | — |
| Class H Units held by ET | — |
| | — |
| | 357 |
| | — |
| General Partner interest and IDRs | 900 |
| | 1,654 |
| | 1,395 |
| | 412 |
| IDR relinquishments (1) | (84 | ) | | (656 | ) | | (409 | ) | | (15 | ) | Series A Preferred Units | 59 |
| | 15 |
| | — |
| | — |
| Series B Preferred Units | 36 |
| | 9 |
| | — |
| | — |
| Series C Preferred Units (2) | 23 |
| | — |
| | — |
| | — |
| Series D Preferred Units (2) | 15 |
| | — |
| | — |
| | — |
| Total distributions declared to partners | $ | 2,266 |
| | $ | 3,518 |
| | $ | 3,539 |
| | $ | 1,017 |
|
| | (1) | Net of Class I unit distributions |
| | (2) | Distributions reflect prorated distributions for the year ended December 31, 2018. |
Cash Distributions Paid by Subsidiaries Certain of our subsidiaries are required by their respective partnership agreements to distribute all cash on hand at the end of each quarter, less appropriate reserves determined by the board of directors of their respective general partners. ETO Preferred Unit Distributions Distributions on the Partnership’s Series A, Series B, Series C and Series D preferred units declared and/or paid by the Partnership during the periods presented were as follows: | | | | | | | | | | | | | | | | | | | | | | | Period Ended | | Record Date | | Payment Date | | Series A (1) | | Series B (1) | | Series C | | Series D | | December 31, 2017 | | February 1, 2018 | | February 15, 2018 | | $ | 15.4510 |
| * | $ | 16.3780 |
| * | $ | — |
| | $ | — |
| | June 30, 2018 | | August 1, 2018 | | August 15, 2018 | | 31.2500 |
| | 33.1250 |
| | 0.5634 |
| * | — |
| | September 30, 2018 | | November 1, 2018 | | November 15, 2018 | | — |
| | — |
| | 0.4609 |
| | 0.5931 |
| * | December 31, 2018 | | February 1, 2019 | | February 15, 2019 | | 31.2500 |
| | 33.1250 |
| | 0.4609 |
| | 0.4766 |
| |
| | * | Represent prorated initial distributions. |
(1) Series A and Series B preferred unit distributions are paid on a bi-annual basis.
Sunoco LP Cash Distributions 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. | | | | | | | | | | | | 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 on Sunoco LP’s units declared and/or paid by Sunoco LP were as follows: | | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | 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 6, 2018 | | February 14, 2018 | | 0.8255 |
| March 31, 2018 | | May 7, 2018 | | May 15, 2018 | | 0.8255 |
| June 30, 2018 | | August 7, 2018 | | August 15, 2018 | | 0.8255 |
| September 30, 2018 | | November 6, 2018 | | November 14, 2018 | | 0.8255 |
| December 31, 2018 | | February 6, 2019 | | February 14, 2019 | | 0.8255 |
|
The total amount of distributions to the Partnership from Sunoco LP for the periods presented below is as follows: | | | | | | | | | | | | | | Years Ended December 31, | | 2018 | | 2017 | | 2016 | Distributions from Sunoco LP | | | | | | Limited Partner interests | $ | 94 |
| | $ | 150 |
| | $ | 151 |
| General Partner interest and IDRs | 70 |
| | 85 |
| | 81 |
| Series A Preferred | 2 |
| | 23 |
| | — |
| Total distributions from Sunoco LP | $ | 166 |
| | $ | 258 |
| | $ | 232 |
|
USAC Cash Distributions Subsequent to the Energy Transfer Merger and USAC Transactions described in Note 1 and Note 3, respectively, ETO owns approximately 39.7 million USAC common units and 6.4 million USAC Class B units. As of December 31, 2018, USAC had
approximately 96.4 million common units outstanding. USAC currently has a non-economic general partner interest and no outstanding incentive distribution rights. Distributions on USAC’s units declared and/or paid by USAC subsequent to the USAC transaction on April 2, 2018 were as follows: | | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | March 31, 2018 | | May 1, 2018 | | May 11, 2018 | | $ | 0.5250 |
| June 30, 2018 | | July 30, 2018 | | August 10, 2018 | | 0.5250 |
| September 30, 2018 | | October 29, 2018 | | November 09, 2018 | | 0.5250 |
| December 31, 2018 | | January 28, 2019 | | February 8, 2019 | | 0.5250 |
|
The total amount of distributions to the Partnership from USAC for the periods presented below is as follows: | | | | | | | | | | | | | | Years Ended December 31, | | 2018 | | 2017 | | 2016 | Distributions from USAC | | | | | | Limited Partner interests | $ | 73 |
| | $ | — |
| | $ | — |
| Total distributions from USAC | $ | 73 |
| | $ | — |
| | $ | — |
|
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. Upon the adoption of ASU 2014-09, the amount of revenue that the Partnership recognizes on certain contracts has changed, primarily due to decreases in revenue (with offsetting decreases to cost of sales) resulting from recognition of non-cash consideration as revenue when received and as cost of sales when sold to third parties. In addition, income statement reclassifications were required for fuel usage and loss allowances related to multiple segments as well as contracts deemed to be in-substance supply agreements in our midstream segment. In addition to the evaluation performed, we have made appropriate design and implementation updates to our business processes, systems and internal controls to support recognition and disclosure under the new standard. Utilizing the practical expedients allowed under the modified retrospective adoption method, Accounting Standards Codification (“ASC”) Topic 606 was only applied to existing contracts for which the Partnership has remaining performance obligations as of January 1, 2018, and new contracts entered into after January 1, 2018. ASC Topic 606 was not applied to contracts that were completed prior to January 1, 2018. The Partnership has elected to apply the modified retrospective method to adopt the new standard. For contracts in scope of the new revenue standard as of January 1, 2018, the cumulative effect adjustment to partners’ capital was not material. The comparative information has not been restated under the modified retrospective method and continues to be reported under the accounting standards in effect for those periods. 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 information about the amount, timing, and uncertainty of cash flows arising from a lease. The update requires lessees to record virtually all leases on their balance sheets. For lessors, this amended guidance modifies the classification criteria and the accounting for sales-type and direct financing leases. In January 2018, the FASB issued Accounting Standards Update No. 2018-01 (“ASU 2018-01”), which provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the existing lease guidance. The Partnership plans to elect the package of transition practical expedients and will adopt this standard beginning with its first quarter of fiscal 2019 and apply it retrospectively at the beginning of the period of
adoption through a cumulative-effect adjustment to retained earnings. The Partnership has performed several procedures to evaluate the impact of the adoption of this standard on the financial statements and disclosures and address the implications of Topic 842 on future lease arrangements. The procedures include reviewing all forms of leases, performing a completeness assessment over the lease population, establishing processes and controls to timely identify new and modified lease agreements, educating its employees on these new processes and controls and implementing a third-party supported lease accounting information system to account for our leases in accordance with the new standard. The Partnership is finalizing its evaluation of the impacts that the adoption of this accounting guidance will have on the consolidated financial statements, and estimates approximately $1.0 billion of right-to-use assets and lease liabilities will be recognized in the consolidated balance sheet upon adoption, with no material impact to its consolidated statements of operations. ASU 2017-12 In August 2017, the FASB issued Accounting Standards Update No. 2017-12, Derivatives and Hedging (Topic 815): TargetedImprovements 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 expects to adopt the new rules in the first quarter of 2019 and does not expect the adoption of the new accounting rules to have a material impact on the consolidated financial statements and related disclosures. ASU 2018-02 In February 2018, the FASB issued Accounting Standards Update No. 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, which allows a reclassification from accumulated other comprehensive income to partners’ capital for stranded tax effects resulting from the Tax Cuts and Jobs Act of 2017. The Partnership elected to early adopt this ASU in the first quarter of 2018. The effect of the adoption was not material. Estimates and Critical Accounting Policies The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules, and we believe the proper implementation and consistent application of the accounting rules are critical. Our critical accounting policies are discussed below. For further details on our accounting policies see Note 2 to our consolidated financial statements. 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 segments 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 operating results estimated for the year ended December 31, 2018 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 results could differ from those estimates. 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. Excess fuel retained after consumption 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. 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. 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, and (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. 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. 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. We have a risk management policy that provides for oversight over our marketing activities. These activities are monitored independently by our risk management function and must take place within predefined limits and authorizations. As a result of our use of derivative financial instruments that may not qualify for hedge accounting, 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 senior management and predefined limits and authorizations set forth in our risk management policy. We inject and hold natural gas in our Bammel storage facility to take advantage of contango markets, when the price of natural gas is higher in the future than the current spot price. We use financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities. At the inception of the hedge, we lock in a margin by purchasing gas in the spot market or off peak season and entering 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 the 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 prices 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 our derivatives being recorded directly in earnings. These margins fluctuate based upon changes in the spreads between the physical spot prices and forward natural gas prices. If the spread narrows between the physical and financial prices, we will record unrealized gains or lower unrealized losses. If the spread widens, we will record unrealized losses or lower unrealized gains. Typically, as we enter the winter months, the spread converges so that we recognize in earnings the original locked in spread, either through mark-to-market or the physical withdrawal of natural gas. 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. Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations. Investment in Sunoco LP Sunoco LP’s revenues from motor fuel 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 wholesale customers for third-party transportation costs, which are recorded net in cost of sales. Through PropCo, Sunoco LP’s wholly-owned corporate subsidiary, Sunoco LP may sell motor fuel to customers on a commission agent basis, in which Sunoco LP retains title to inventory, controls access to and sale of fuel inventory, and recognizes revenue at the time the fuel is sold to the ultimate customer. In Sunoco LP’s fuel distribution and marketing operations, Sunoco LP derives other income from rental income, propane and lubricating oils, and other ancillary product and service offerings. In Sunoco LP’s other operations, Sunoco LP derives other income from merchandise, lottery ticket sales, money orders, prepaid phone cards and wireless services, ATM transactions, car washes, movie rentals, and other ancillary product and service offerings. Sunoco LP records revenue from other retail transactions on a net commission basis when a product is sold and/or services are rendered. Investment in USAC USAC’s revenue from contracted compression, station, gas treating and maintenance services is recognized ratably under its fixed-fee contracts over the term of the contract as services are provided to its customers. Initial contract terms typically range from six months to five years. However, USAC usually continues to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-to-month or longer basis. USAC primarily enters into fixed-fee contracts whereby its customers are required to pay its monthly fee even during periods of limited or disrupted throughput. Services are generally billed monthly, one month in advance of the commencement of the service month, except for certain customers who are billed at the beginning of the service month, and payment is generally due 30 days after receipt of the invoice. Amounts invoiced in advance are recorded as deferred revenue until earned, at which time they are recognized as revenue. The amount of consideration USAC receives and revenue it recognizes is based upon the fixed fee rate stated in each service contract. USAC’s retail parts and services revenue is earned primarily on freight and crane charges that are directly reimbursable by its customers and maintenance work on units at its customers’ locations that are outside the scope of USAC’s core maintenance activities. Revenue from retail parts and services is recognized at the point in time the part is transferred or service is provided and control is transferred to the customer. At such time, the customer has the ability to direct the use of the benefits of such part or service after USAC has performed its services. USAC bills upon completion of the service or transfer of the parts, and payment is generally due 30 days after receipt of the invoice. The amount of consideration USAC receives and revenue it recognizes is based upon the invoice amount. 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 all or part of our operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be assessed and potentially eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs. Accounting for Derivative Instruments and Hedging Activities. We utilize various exchange-traded and OTC commodity financial instrument contracts to limit our exposure to margin fluctuations in natural gas, NGL, crude oil and refined products. These contracts consist primarily of futures and swaps. 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. If we designate a 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 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. We utilize published settlement prices for exchange-traded contracts, quotes provided by brokers, and estimates of market prices based on daily contract activity to estimate the fair value of these contracts. Changes in the methods used to determine the fair value of these contracts could have a material effect on our results of operations. We do not anticipate future changes in the methods used to determine the fair value of these derivative contracts. See “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” for further discussion regarding our derivative activities. Fair Value of Financial Instruments. We have commodity derivatives, interest rate derivatives and embedded derivatives in our preferred units that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. Derivatives related to the embedded derivatives in our preferred units are valued using a binomial lattice model. The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected value, and are considered level 3. See further information on our fair value assets and liabilities in Note 2 of our consolidated financial statements. Impairment of Long-Lived Assets, Goodwill, Intangible Assets and Investments in Unconsolidated Affiliates. Long-lived assets are required to be tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. Goodwill and intangibles with indefinite lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be impaired. 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. An impairment loss should be recognized only if the carrying amount of the asset/goodwill is not recoverable and exceeds its fair value. In order to test for recoverability when performing a quantitative impairment test, we must make estimates of projected cash flows related to the asset, which include, but are not limited to, assumptions about the use or disposition of the asset, estimated remaining life of the asset, and future expenditures necessary to maintain the asset’s existing service potential. In order to determine fair
value, we make certain estimates and assumptions, including, among other things, changes in general economic conditions in regions in which our markets are located, the availability and prices of natural gas, our ability to negotiate favorable sales agreements, the risks that natural gas exploration and production activities will not occur or be successful, our dependence on certain significant customers and producers of natural gas, and competition from other companies, including major energy producers. While we believe we have made reasonable assumptions to calculate the fair value, if future results are not consistent with our estimates, we could be exposed to future impairment losses that could be material to our results of operations. The Partnership determined the fair value of its 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. One key assumption for the measurement of an impairment is management’s estimate of future cash flows and EBITDA. These estimates are based on the annual budget for the upcoming year and forecasted amounts for multiple subsequent years. The annual budget process is typically completed near the annual goodwill impairment testing date, and management uses the most recent information for the annual impairment tests. The forecast is also subjected to a comprehensive update annually in conjunction with the annual budget process and is revised periodically to reflect new information and/or revised expectations. The estimates of future cash flows and EBITDA are subjective in nature and are subject to impacts from the business risks described in “Item 1A. Risk Factors.” Therefore, the actual results could differ significantly from the amounts used for goodwill impairment testing, and significant changes in fair value estimates could occur in a given period. Such changes in fair value estimates could result in additional impairments in future periods; therefore, the actual results could differ significantly from the amounts used for goodwill impairment testing, and significant changes in fair value estimates could occur in a given period, resulting in additional impairments. Management does not believe that any of the goodwill balances in its reporting units is currently at significant risk of impairment; however, of the $4.89 billion of goodwill on the Partnership’s consolidated balance sheet as of December 31, 2018, approximately $650 million is recorded in reporting units for which the estimated fair value exceeded the carrying value by less than 20% in the most recent quantitative test. During the year ended December 31, 2018, the Partnership recorded the following impairments: A $378 million impairment was recorded related to the goodwill associated with the Partnership’s Northeast operations within the midstream segment primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded. These changes in assumptions reflect delays in the construction of third-party takeaway capacity in the Northeast. Additionally, the Partnership recorded asset impairments of $4 million related to our midstream operations and asset impairments $9 million related to our crude operations idle leased assets. Sunoco LP also recognized a $30 million impairment charge on its contractual rights primarily due to decreases in projected future revenues and cash flows from the date the intangible asset was originally recorded. USAC also recognized a $9 million fixed asset impairment related to certain idle compressor assets. During the year ended December 31, 2017, the Partnership recorded the following impairments: a $223 million impairment was recorded related to the goodwill associated with CDM. In January 2018, the Partnership announced the contribution of CDM to USAC. Based on the Partnership’s anticipated proceeds in the contribution transaction, the implied fair value of the CDM reporting unit was less than the Partnership’s carrying value. As the Partnership believes that the contribution consideration also represented an appropriate estimate of fair value as of the 2017 annual impairment test date, the Partnership recorded an impairment for the difference between the carrying value and the fair value of the reporting unit. Subsequent to the impairment, a total of $253 million of goodwill remains in the CDM reporting unit, which amount is subject to further impairment based on changes in the contribution transaction prior to closing or any other factors
affecting the fair value of the CDM reporting unit. Assuming the contribution transaction closes, the remaining CDM goodwill balance will be derecognized; if the transaction does not close, then the CDM goodwill balance will remain on the Partnership’s consolidated balance sheet and will continue to be tested for impairment in the future. a $262 million impairment was recorded related to the goodwill associated with the Partnership’s interstate transportation and storage reporting units, and a $229 million impairment was recorded related to the goodwill associated with the general partner of Panhandle in the all other segment. These impairments were due to a reduction in management’s forecasted future cash flows from the related reporting units, which reduction reflected the impacts discussed in “Results of Operations” above, along with the impacts of re-contracting assumptions related to future periods. a $79 million impairment was recorded related to the goodwill associated the Partnership’s refined products transportation and services reporting unit. Subsequent to the Sunoco Logistics Merger, the Partnership restructured the internal reporting of legacy Sunoco Logistics’ business to be consistent with the internal reporting of legacy ETO. Subsequent to this reallocation the carrying value of certain refined products reporting units was less than the estimated fair value due to a reduction in management’s forecasted future cash flows from the related reporting units, and the goodwill associated with those reporting units was fully impaired. No goodwill remained in the respective reporting units subsequent to the impairment. a $127 million impairment of property, plant and equipment 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. a $141 million impairment of the Partnership’s equity method investment in FEP. The Partnership concluded that the carrying value of its investment in FEP was other than temporarily impaired based on an anticipated decrease in production in the Fayetteville basin and a customer re-contracting with a competitor during 2017. a $172 million impairment of the Partnership’s equity method investment in HPC primarily due to a decrease in projected future revenues and cash flows driven be 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. For 2017, Sunoco LP also recognized impairments of $404 million, of which $119 million was allocated to continuing operations, as discussed further below. During the year ended December 31, 2016, the Partnership recorded the following impairments: a $638 million goodwill impairment and a $133 million impairment to property, plant and equipment were recorded in the interstate transportation and storage segment primarily due to decreases in projected future revenues and cash flows driven by changes in the markets that these assets serve. a $32 million goodwill impairment was recorded in the midstream segment primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices. a $308 million impairment of the Partnership’s equity method investment in MEP. The Partnership concluded that the carrying value of its investment in MEP was other than temporarily impaired based on commercial discussions with current and potential shippers on MEP during 2016, which negatively affected the outlook for long-term transportation contract rates. For 2016, Sunoco LP also recognized impairments of $641 million, of which $227 million was allocated to continuing operations, as discussed further below. Except for the 2017 impairment of the goodwill associated with CDM, as discussed above, the goodwill impairments recorded by the Partnership during the years ended December 31, 2018, 2017 and 2016 represented all of the goodwill within the respective reporting units. During 2017, Sunoco LP announced the sale of a majority of the assets in its retail and Stripes reporting units. These reporting units include the retail operations in the continental United States but excludes the retail convenience store operations in Hawaii that comprise the Aloha reporting unit. Upon the classification of assets and related liabilities as held for sale, Sunoco LP’s management applied the measurement guidance in ASC 360, Property, Plant and Equipment, to calculate the fair value less cost to sell of the disposal group. In accordance with ASC 360-10-35-39, Sunoco LP’s management first tested the goodwill included within the disposal group for impairment prior to measuring the disposal group’s fair value less the cost to sell. In the determination of the classification of assets held for sale and the related liabilities, Sunoco LP’s management allocated a portion of the goodwill balance previously included in the Sunoco LP retail and Stripes reporting units to assets held for sale based on the relative fair values of the business to be disposed of and the portion of the respective reporting unit that will be retained in accordance with ASC 350-20-40-3.
Sunoco LP recognized goodwill impairments of $387 million in 2017, of which $102 million was allocated to continuing operations,primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded. Additionally, 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 primarily due to decreases in projected future revenues and cash flows from the date the intangible asset was originally recorded. For the year ended December 31, 2016, 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. Property, Plant and Equipment. 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 the consolidated statement of operations. Depreciation of property, plant and equipment is provided using the straight-line method based on their estimated useful lives ranging from 1 to 99 years. Changes in the estimated useful lives of the assets could have a material effect on our results of operation. We do not anticipate future changes in the estimated useful lives of our property, plant and equipment. 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, 2018 and 2017, 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 AROs 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 AROs related to Sunoco, Inc.’s pipeline assets and storage tanks, for which it is not possible to estimate whether or when the AROs will be settled. Consequently, these AROs cannot be measured at this time. Sunoco LP has AROs related to the estimated future cost to remove underground storage tanks. 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 $106 million and $103 million and were reflected as property, plant and equipment on our consolidated balance sheet as of December 31, 2018 and 2017, respectively. In addition, other non-current assets on the Partnership’s consolidated balance sheet included $26 million and $21 million of legally restricted funds for the purpose of settling AROs as of December 31, 2018 and 2017, respectively.
Pensions and Other Postretirement Benefit Plans. We are required to measure plan assets and benefit obligations as of its fiscal year-end balance sheet date. We recognize the changes in the funded status of our defined benefit postretirement plans through AOCI or are reflected as a regulatory asset or regulatory liability for regulated subsidiaries. The calculation of the net periodic benefit cost and benefit obligation requires the use of a number of assumptions. Changes in these assumptions can have a significant effect on the amounts reported in the financial statements. The Partnership believes that the two most critical assumptions are the assumed discount rate and the expected rate of return on plan assets. The discount rate is established by using a hypothetical portfolio of high-quality debt instruments that would provide the necessary cash flows to pay the benefits when due. Net periodic benefit cost and benefit obligation increases and equity correspondingly decreases as the discount rate is reduced. The expected rate of return on plan assets is based on long-term expectations given current investment objectives and historical results. Net periodic benefit cost increases as the expected rate of return on plan assets is correspondingly reduced. Legal Matters.We are subject to litigation and regulatory proceedings as a result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from claims, orders, judgments or settlements. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. We expense legal costs as incurred, and all recorded legal liabilities are revised as required as better information becomes available to us. The factors we consider when recording an accrual for contingencies include, among others: (i) the opinions and views of our legal counsel; (ii) our previous experience; and (iii) the decision of our management as to how we intend to respond to the complaints. For more information on our litigation and contingencies, see Note 11 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” in this report. Environmental Remediation Activities. The Partnership’s accrual for environmental remediation activities reflects anticipated work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. The accrual for known claims is undiscounted and is based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. It is often extremely difficult to develop reasonable estimates of future site remediation costs due to changing regulations, changing technologies and their associated costs, and changes in the economic environment. Engineering studies, historical experience and other factors are used to identify and evaluate remediation alternatives and their related costs in determining the estimated accruals for environmental remediation activities. Losses attributable to unasserted claims are generally reflected in the accruals on an undiscounted basis, to the extent they are probable of occurrence and reasonably estimable. ETO has 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, ETO accrues losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company. In general, each remediation site/issue is evaluated individually based upon information available for the site/issue and no pooling or statistical analysis is used to evaluate an aggregate risk for a group of similar items (e.g., service station sites) in determining the amount of probable loss accrual to be recorded. ETO’s estimates of environmental remediation costs also frequently involve evaluation of a range of estimates. In many cases, it is difficult to determine that one point in the range of loss estimates is more likely than any other. In these situations, existing accounting guidance requires that the minimum of the range be accrued. Accordingly, the low end of the range often represents the amount of loss which has been recorded. The Partnership’s consolidated balance sheet reflected $337 million in environmental accruals as of December 31, 2018. Total future costs for environmental remediation activities will depend upon, among other things, the identification of any additional sites, the determination of the extent of the contamination at each site, the timing and nature of required remedial actions, the nature of operations at each site, the technology available and needed to meet the various existing legal requirements, the nature and terms of cost-sharing arrangements with other potentially responsible parties, the availability of insurance coverage, the nature and extent of future environmental laws and regulations, inflation rates, terms of consent agreements or remediation permits with regulatory agencies and the determination of the Partnership’s liability at the sites, if any, in light of the number, participation level and financial viability of the other parties. The recognition of additional losses, if and when they were to occur, would likely extend over many years. Management believes that the Partnership’s exposure to adverse developments with respect to any individual site is not expected to be material. However, if changes in environmental laws or regulations occur or the assumptions used to estimate losses at multiple sites are adjusted, such changes could impact multiple facilities, formerly owned facilities and third-party sites at the same time. As a result, from time to time, significant charges against income for environmental remediation may
occur; however, management does not believe that any such charges would have a material adverse impact on the Partnership’s consolidated financial position. Deferred Income Taxes. ET recognizes benefits in earnings and related deferred tax assets for net operating loss carryforwards (“NOLs”) and tax credit carryforwards. If necessary, a charge to earnings and a related valuation allowance are recorded to reduce deferred tax assets to an amount that is more likely than not to be realized by the Partnership in the future. Deferred income tax assets attributable to state and federal NOLs and federal tax alternative minimum tax credit carryforwards totaling $768 million have been included in ET’s consolidated balance sheet as of December 31, 2018. The state NOL carryforward benefits of $213 million ($168 million net of federal benefit) begin to expire in 2019 with a substantial portion expiring between 2032 and 2038. The federal NOLs of $2.60 billion ($546 million in benefits) will expire in 2031 and 2037 if attributable to tax years prior to 2018. Any federal NOL generated in 2018 and future years can be carried forward indefinitely. Federal alternative minimum tax credit carryforwards of $31 million remained at December 31, 2018. We have determined that a valuation allowance totaling $124 million ($98 million net of federal income tax effects) is required for the state NOLs at December 31, 2018 primarily due to significant restrictions on their use in the Commonwealth of Pennsylvania. In making the assessment of the future realization of the deferred tax assets, we rely on future reversals of existing taxable temporary differences, tax planning strategies and forecasted taxable income based on historical and projected future operating results. The potential need for valuation allowances is regularly reviewed by management. If it is more likely than not that the recorded asset will not be realized, additional valuation allowances which increase income tax expense may be recognized in the period such determination is made. Likewise, if it is more likely than not that additional deferred tax assets will be realized, an adjustment to the deferred tax asset will increase income in the period such determination is made. Forward-Looking Statements This annual report contains various forward-looking statements and information that are based on our beliefs and those of our General Partner, as well as assumptions made by and information currently available to us. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. When used in this annual report, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “could,” “believe,” “may,” “will” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our General Partner believe that the expectations on which such forward-looking statements are based are reasonable, neither we nor our General Partner can give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Among the key risk factors that may have a direct bearing on our results of operations and financial condition are: the ability of our subsidiaries to make cash distributions to us, which is dependent on their results of operations, cash flows and financial condition; the actual amount of cash distributions by our subsidiaries to us; the volumes transported on our subsidiaries’ pipelines and gathering systems; the level of throughput in our subsidiaries’ processing and treating facilities; the fees our subsidiaries charge and the margins they realize for their gathering, treating, processing, storage and transportation services; the prices and market demand for, and the relationship between, natural gas and NGLs; energy prices generally; the prices of natural gas and NGLs compared to the price of alternative and competing fuels; the general level of petroleum product demand and the availability and price of NGL supplies; the level of domestic oil, natural gas and NGL production; the availability of imported oil, natural gas and NGLs; actions taken by foreign oil and gas producing nations; the political and economic stability of petroleum producing nations;
the effect of weather conditions on demand for oil, natural gas and NGLs; availability of local, intrastate and interstate transportation systems; the continued ability to find and contract for new sources of natural gas supply; availability and marketing of competitive fuels; the impact of energy conservation efforts; energy efficiencies and technological trends; governmental regulation and taxation; changes to, and the application of, regulation of tariff rates and operational requirements related to our subsidiaries’ interstate and intrastate pipelines; hazards or operating risks incidental to the gathering, treating, processing and transporting of natural gas and NGLs; competition from other midstream companies and interstate pipeline companies; loss of key personnel; loss of key natural gas producers or the providers of fractionation services; reductions in the capacity or allocations of third-party pipelines that connect with our subsidiaries pipelines and facilities; the effectiveness of risk-management policies and procedures and the ability of our subsidiaries liquids marketing counterparties to satisfy their financial commitments; the nonpayment or nonperformance by our subsidiaries’ customers; regulatory, environmental, political and legal uncertainties that may affect the timing and cost of our subsidiaries’ internal growth projects, such as our subsidiaries’ construction of additional pipeline systems; risks associated with the construction of new pipelines and treating and processing facilities or additions to our subsidiaries’ existing pipelines and facilities, including difficulties in obtaining permits and rights-of-way or other regulatory approvals and the performance by third-party contractors; the availability and cost of capital and our subsidiaries’ ability to access certain capital sources; a deterioration of the credit and capital markets; risks associated with the assets and operations of entities in which our subsidiaries own less than a controlling interests, including risks related to management actions at such entities that our subsidiaries may not be able to control or exert influence; the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results and to successfully integrate acquired businesses; changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations or new interpretations by regulatory agencies concerning such laws and regulations; and the costs and effects of legal and administrative proceedings. You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risks described under “Item 1A. Risk Factors” in this annual report. Any forward-looking statement made by us in this Annual Report on Form 10-K is based only on information currently available to us and speaks only as of the date on which it is made. We undertake no obligation to publicly update any forward-looking statement, whether written or oral, that may be made from time to time, whether as a result of new information, future developments or otherwise. Inflation Interest rates on existing and future credit facilities and future debt offerings could be significantly higher than current levels, causing our financing costs to increase accordingly. Although increased financing costs could limit our ability to raise funds in
the capital markets, we expect to remain competitive with respect to acquisitions and capital projects since our competitors would face similar circumstances. Inflation in the United States has been relatively low in recent years and has not had a material effect on our results of operations. It may in the future, however, increase the cost to acquire or replace property, plant and equipment and may increase the costs of labor and supplies. Our operating revenues and costs are influenced to a greater extent by commodity price changes. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along a portion of increased costs to our customers in the form of higher fees. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (Tabular dollar amounts are in millions) Market risk includes the risk of loss arising from adverse changes in market rates and prices. We face market risk from commodity variations, risk and interest rate variations, and to a lesser extent, credit risks. From time to time, we may utilize derivative financial instruments as described below to manage our exposure to such risks. 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 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. 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 tables below summarize commodity-related financial derivative instruments, fair values and the effect of an assumed hypothetical 10% change in the underlying price of the commodity as of December 31, 2018 and 2017 for ETO and Sunoco LP, including derivatives related to their respective subsidiaries. Dollar amounts are presented in millions. | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2018 | | December 31, 2017 | | Notional Volume | | Fair Value Asset (Liability) | | Effect of Hypothetical 10% Change | | Notional Volume | | Fair Value Asset (Liability) | | Effect of Hypothetical 10% Change | Mark-to-Market Derivatives | | | | | | | | | | | | (Trading) | | | | | | | | | | | | Natural Gas (BBtu): | | | | | | | | | | | | Fixed Swaps/Futures | 468 |
| | $ | — |
| | $ | — |
| | 1,078 |
| | $ | — |
| | $ | — |
| Basis Swaps IFERC/NYMEX(1) | 16,845 |
| | 7 |
| | 1 |
| | 48,510 |
| | 2 |
| | 1 |
| Options – Puts | 10,000 |
| | — |
| | — |
| | 13,000 |
| | — |
| | — |
| Power (Megawatt): | | | | | | | | | | | | Forwards | 3,141,520 |
| | 6 |
| | 8 |
| | 435,960 |
| | 1 |
| | 1 |
| Futures | 56,656 |
| | — |
| | — |
| | (25,760 | ) | | — |
| | — |
| Options – Puts | 18,400 |
| | — |
| | — |
| | (153,600 | ) | | — |
| | 1 |
| Options – Calls | 284,800 |
| | 1 |
| | — |
| | 137,600 |
| | — |
| | — |
| Crude (MBbls) – Futures | — |
| | — |
| | — |
| | — |
| | 1 |
| | — |
| (Non-Trading) | | | | | | | | | | | | Natural Gas (BBtu): | | | | | | | | | | | | Basis Swaps IFERC/NYMEX | (30,228 | ) | | (52 | ) | | 13 |
| | 4,650 |
| | (13 | ) | | 4 |
| Swing Swaps IFERC | 54,158 |
| | 12 |
| | — |
| | 87,253 |
| | (2 | ) | | 1 |
| Fixed Swaps/Futures | (1,068 | ) | | 19 |
| | 1 |
| | (4,390 | ) | | (1 | ) | | 2 |
| Forward Physical Contracts | (123,254 | ) | | (1 | ) | | 32 |
| | (145,105 | ) | | 6 |
| | 41 |
| NGL (MBbls) – Forwards/Swaps | (2,135 | ) | | 67 |
| | 67 |
| | (2,493 | ) | | 5 |
| | 16 |
| Crude (MBbls) – Forwards/Swaps | 20,888 |
| | (60 | ) | | 29 |
| | 9,237 |
| | (4 | ) | | 9 |
| Refined Products (MBbls) – Futures | (1,403 | ) | | (8 | ) | | 6 |
| | (3,901 | ) | | (27 | ) | | 4 |
| Corn (thousand bushels) | (1,920 | ) | | — |
| | 1 |
| | 1,870 |
| | — |
| | — |
| Fair Value Hedging Derivatives | | | | | | | | | | | | (Non-Trading) | | | | | | | | | | | | Natural Gas (BBtu): | | | | | | | | | | | | Basis Swaps IFERC/NYMEX | (17,445 | ) | | (4 | ) | | — |
| | (39,770 | ) | | (2 | ) | | — |
| Fixed Swaps/Futures | (17,445 | ) | | (10 | ) | | 6 |
| | (39,770 | ) | | 14 |
| | 11 |
|
(1) Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations. The fair values of the commodity-related financial positions have been determined using independent third-party prices, readily available market information and appropriate valuation techniques. Non-trading positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the below tables. Price-risk sensitivities were calculated by assuming a theoretical 10% change (increase or decrease) in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. Results are presented in absolute terms and represent a potential gain or loss in net income or in other comprehensive income. In the event of an actual 10% change in prompt month natural gas prices, the fair value of our total derivative portfolios may not change by 10% due to factors such as when the financial instrument settles and the location to which the financial instrument is tied (i.e., basis swaps) and the relationship between prompt month and forward months. Interest Rate Risk As of December 31, 2018, we and our subsidiaries had $9.76 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would result in a maximum potential change to interest expense of $98 million annually; however, our actual
change in interest expense may be less in a given period due to interest rate floors included in our variable rate debt instruments. We manage a portion of our interest rate exposure by utilizing interest rate swaps, including forward-starting interest rate swaps to lock-in the rate on a portion of anticipated debt issuances. The following table summarizes our interest rate swaps outstanding, none of which were designated as hedges for accounting purposes (dollar amounts presented in millions):
| | | | | | | | | | | | Term | | Type(1) | | Notional Amount Outstanding | December 31, 2018 | | December 31, 2017 | July 2018 (2) | | Forward-starting to pay a fixed rate of 3.76% and receive a floating rate | | $ | — |
| | $ | 300 |
| July 2019 (2) | | Forward-starting to pay a fixed rate of 3.56% and receive a floating rate | | 400 |
| | 300 |
| July 2020 (2) | | Forward-starting to pay a fixed rate of 3.52% and receive a floating rate | | 400 |
| | 400 |
| July 2021 (2) | | Forward-starting to pay a fixed rate of 3.55% and receive a floating rate | | 400 |
| | — |
| December 2018 | | Pay a floating rate and receive a fixed rate of 1.53% | | — |
| | 1,200 |
| March 2019 | | Pay a floating rate 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. |
A hypothetical change of 100 basis points in interest rates for these interest rate swaps would result in a change in the fair value of the interest rate derivatives and earnings (recognized in gains (losses) on interest rate derivatives) of approximately $259 million as of December 31, 2018. For ETO’s $300 million of interest rate swaps whereby it pays a floating rate and receives a fixed rate, a hypothetical change of 100 basis points in interest rates would result in a net change in annual cash flow of less than $1 million. For the forward-starting interest rate swaps, a hypothetical change of 100 basis points in interest rates would not affect cash flows until the swaps are settled. 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 industrial end-users, 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. 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. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The financial statements starting on page F-1 of this report are incorporated by reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. ITEM 9A. CONTROLS AND PROCEDURES Evaluation of Disclosure Controls and Procedures An evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rules 13a–15(e) and 15d–15(e) of the Exchange Act) as of the end of the period covered by this report. Based upon that evaluation, management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, concluded that our disclosure controls and procedures were adequate and effective as of December 31, 2018. Management’s Report on Internal Control over Financial Reporting The management of Energy Transfer LP and subsidiaries is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in the 2013 Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO Framework”). Based on our evaluation under the COSO framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2018. Grant Thornton LLP, an independent registered public accounting firm, has audited the effectiveness of our internal control over financial reporting as of December 31, 2018, as stated in their report, which is included herein.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Board of Directors of LE GP, LLC and Unitholders of Energy Transfer LP Opinion on internal control over financial reporting We have audited the internal control over financial reporting of Energy Transfer LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2018, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in the 2013 Internal Control-Integrated Framework issued by COSO. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Partnership as of and for the year ended December 31, 2018, and our report dated February 22, 2019 expressed an unqualified opinion on those financial statements. Basis for opinion The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. 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 audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. Definition and limitations of internal control over financial reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. /s/ GRANT THORNTON LLP Dallas, Texas February 22, 2019
Changes in Internal Controls over Financial Reporting There has been no change in our internal controls over financial reporting (as defined in Rules 13a–15(f) or Rule 15d–15(f)) that occurred in the three months ended December 31, 2018 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting. ITEM 9B. OTHER INFORMATION None.
PART III ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE Board of Directors Our general partner, LE GP, LLC, manages and directs all of our activities. The officers and directors of ET are officers and directors of LE GP, LLC. The members of our general partner elect our general partner’s Board of Directors. The board of directors of our general partner has the authority to appoint our executive officers, subject to provisions in the limited liability company agreement of our general partner. Pursuant to other authority, the board of directors of our general partner may appoint additional management personnel to assist in the management of our operations and, in the event of the death, resignation or removal of our chief executive officer, to appoint a replacement. As of December 31, 2018, our Board of Directors was comprised of eight persons, three of whom qualify as “independent” under the NYSE’s corporate governance standards. We have determined that Messrs. Brannon, Anderson and Grimm are all “independent” under the NYSE’s corporate governance standards. As a limited partnership, we are not required by the rules of the NYSE to seek unitholder approval for the election of any of our directors. We believe that the members of our general partner have appointed as directors individuals with experience, skills and qualifications relevant to the business of the Parent Company, such as experience in energy or related industries or with financial markets, expertise in natural gas operations or finance, and a history of service in senior leadership positions. We do not have a formal process for identifying director nominees, nor do we have a formal policy regarding consideration of diversity in identifying director nominees, but we believe that the members of our general partner have endeavored to assemble a group of individuals with the qualities and attributes required to provide effective oversight of the Parent Company. Risk Oversight Our Board of Directors generally administers its risk oversight function through the board as a whole. Our Chief Executive Officer, who reports to the Board of Directors, has day-to-day risk management responsibilities. Our Chief Executive Officer attends the meetings of our Board of Directors, where the Board of Directors routinely receives reports on our financial results, the status of our operations, and other aspects of implementation of our business strategy, with ample opportunity for specific inquiries of management. In addition, at each regular meeting of the Board, management provides a report of the Parent Company’s financial and operational performance, which often prompts questions or feedback from the Board of Directors. The Audit Committee provides additional risk oversight through its quarterly meetings, where it receives a report from the Parent Company’s internal auditor, who reports directly to the Audit Committee, and reviews the Parent Company’s contingencies with management and our independent auditors. Corporate Governance The Board of Directors has adopted both a Code of Business Conduct and Ethics applicable to our directors, officers and employees, and Corporate Governance Guidelines for directors and the Board. Current copies of our Code of Business Conduct and Ethics, Corporate Governance Guidelines and charters of the Audit and Compensation Committees of our Board of Directors are available on our website at www.energytransfer.com and will be provided in print form to any Unitholder requesting such information. Please note that the preceding Internet address is for information purposes only and is not intended to be a hyperlink. Accordingly, no information found and/or provided at such Internet addresses or at our website in general is intended or deemed to be incorporated by reference herein. Annual Certification In 2018, our Chief Executive Officer provided to the NYSE the annual CEO certification regarding our compliance with the NYSE’s corporate governance listing standards. Conflicts Committee Our Partnership Agreement provides that the Board of Directors may, from time to time, appoint members of the Board to serve on the Conflicts Committee with the authority to review specific matters for which the Board of Directors believes there may be a conflict of interest in order to determine if the resolution of such conflict proposed by the general partner is fair and reasonable to the Parent Company and our Unitholders. As a policy matter, the Conflicts Committee generally reviews any proposed related-party transaction that may be material to the Parent Company to determine if the transaction presents a conflict of interest and whether the transaction is fair and reasonable to the Parent Company. Pursuant to the terms of our partnership agreement, any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to the Parent Company,
approved by all partners of the Parent Company and not a breach by the general partner or its Board of Directors of any duties they may owe the Parent Company or the Unitholders. These duties are limited by our Partnership Agreement (see “Risks Related to Conflicts of Interest” in “Item 1A. Risk Factors” in this annual report). Audit Committee The Board of Directors has established an Audit Committee in accordance with Section 3(a)(58)(A) of the Exchange Act. The Board of Directors appoints persons who are independent under the NYSE’s standards for audit committee members to serve on its Audit Committee. In addition, the Board determines that at least one member of the Audit Committee has such accounting or related financial management expertise sufficient to qualify such person as the audit committee financial expert in accordance with Item 407(d)(5) of Regulation S-K. The Board determined that based on relevant experience, Audit Committee member Michael K. Grimm qualified as an audit committee financial expert during 2018. A description of the qualifications of Mr. Grimm may be found elsewhere in this Item 10 under “Directors and Executive Officers of the General Partner.” The Audit Committee meets on a regularly scheduled basis with our independent accountants at least four times each year and is available to meet at their request. The Audit Committee has the authority and responsibility to review our external financial reporting, review our procedures for internal auditing and the adequacy of our internal accounting controls, consider the qualifications and independence of our independent accountants, engage and direct our independent accountants, including the letter of engagement and statement of fees relating to the scope of the annual audit work and special audit work which may be recommended or required by the independent accountants, and to engage the services of any other advisors and accountants as the Audit Committee deems advisable. The Audit Committee reviews and discusses the audited financial statements with management, discusses with our independent auditors matters required to be discussed by auditing standards, and makes recommendations to the Board of Directors relating to our audited financial statements. The Audit Committee periodically recommends to the Board of Directors any changes or modifications to its charter that may be required. The Audit Committee has received written disclosures and the letter from Grant Thornton required by applicable requirements of the Audit Committee concerning independence and has discussed with Grant Thornton that firm’s independence. The Audit Committee recommended to the Board that the audited financial statements of ET be included in ET’s Annual Report on Form 10-K for the year ended December 31, 2018. The Board of Directors adopts the charter for the Audit Committee. Steven R. Anderson, Richard D. Brannon and Michael K. Grimm serve as elected members of the Audit Committee. Compensation and Nominating/Corporate Governance Committees Although we are not required under NYSE rules to appoint a Compensation Committee or a Nominating/Corporate Governance Committee because we are a limited partnership, the Board of Directors of LE GP, LLC has previously established a Compensation Committee to establish standards and make recommendations concerning the compensation of our officers and directors. In addition, the Compensation Committee determines and establishes the standards for any awards to our employees and officers under the equity compensation plans, including the performance standards or other restrictions pertaining to the vesting of any such awards. Messrs. Anderson and Grimm serve as members of the Compensation Committee. Matters relating to the nomination of directors or corporate governance matters were addressed to and determined by the full Board of Directors for the period ET did not have a compensation committee. The responsibilities of the ET Compensation Committee include, among other duties, the following: annually review and approve goals and objectives relevant to compensation of our CEO and CFO, if applicable; annually evaluate the CEO and CFO’s performance in light of these goals and objectives, and make recommendations to the Board of Directors with respect to the CEO and CFO’s compensation levels, if applicable, based on this evaluation; make determinations with respect to the grant of equity-based awards to executive officers under ET’s equity incentive plans; periodically evaluate the terms and administration of ET’s long-term incentive plans to assure that they are structured and administered in a manner consistent with ET’s goals and objectives; periodically evaluate incentive compensation and equity-related plans and consider amendments if appropriate; periodically evaluate the compensation of the directors; retain and terminate any compensation consultant to be used to assist in the evaluation of director, CEO and CFO or executive officer compensation; and
perform other duties as deemed appropriate by the Board of Directors. Code of Business Conduct and Ethics The Board of Directors has adopted a Code of Business Conduct and Ethics applicable to our officers, directors and employees. Specific provisions are applicable to the principal executive officer, principal financial officer, principal accounting officer and controller, or those persons performing similar functions, of our general partner. Amendments to, or waivers from, the Code of Business Conduct and Ethics will be available on our website and reported as may be required under SEC rules. Any technical, administrative or other non-substantive amendments to the Code of Business Conduct and Ethics may not be posted. Meetings of Non-management Directors and Communications with Directors Our non-management directors meet in regularly scheduled sessions. Our non-management directors alternate as the presiding director of such meetings. We have established a procedure by which Unitholders or interested parties may communicate directly with the Board of Directors, any committee of the Board, any of the independent directors, or any one director serving on the Board of Directors by sending written correspondence addressed to the desired person, committee or group to the attention of Sonia Aubé at Energy Transfer LP 8111 Westchester Drive, Suite 600, Dallas, Texas, 75225. Communications are distributed to the Board of Directors, or to any individual director or directors as appropriate, depending on the facts and circumstances outlined in the communication. Directors and Executive Officers of Our General Partner The following table sets forth certain information with respect to the executive officers and members of the Board of Directors of our general partner as of February 22, 2019. Executive officers and directors are elected for indefinite terms. | | | | | | | Name | | Age | | Position with Our General Partner | Kelcy L. Warren | | 63 |
| | Chief Executive Officer and Chairman of the Board (Principal Executive Officer) | Thomas E. Long | | 62 |
| | Chief Financial Officer (Principal Financial Officer) | Marshall S. (Mackie) McCrea, III | | 59 |
| | President, Chief Commercial Officer and Director | Matthew S. Ramsey | | 63 |
| | Chief Operating Officer and Director | Thomas P. Mason | | 62 |
| | Executive Vice President, General Counsel and President - LNG | John W. McReynolds | | 68 |
| | Special Advisor and Director | A. Troy Sturrock | | 48 |
| | Senior Vice President and Controller (Principal Accounting Officer) | Ray C. Davis | | 77 |
| | Director | Steven R. Anderson | | 69 |
| | Director | Richard D. Brannon | | 60 |
| | Director | Michael K. Grimm | | 64 |
| | Director |
Messrs. Warren, Ramsey and McCrea also serve as directors of ETO’s general partner. Mr. Ramsey serves as director of the general partner of Sunoco LP. Set forth below is biographical information regarding the foregoing officers and directors of our general partner: Kelcy L. Warren. Mr. Warren serves as Chairman and Chief Executive Officer of our general partner. He was appointed Co-Chairman of the Board of Directors of our general partner, effective upon the closing of our IPO, and in August 2007, he became the sole Chairman of the Board of our general partner and the Chief Executive Officer and Chairman of the Board of the general partner of ETO. Prior to that, Mr. Warren had served as Co-Chief Executive Officer and Co-Chairman of the Board of the general partner of ETO since the combination of the midstream and intrastate transportation storage operations of ETC OLP and the retail propane operations of Heritage in January 2004. Mr. Warren also served as the Chief Executive Officer of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Prior to the combination of the operations of ETO and Heritage Propane, Mr. Warren served as President of the general partner of ET Company I, Ltd. the entity that operated ETO’s midstream assets before it acquired Aquila, Inc.’s midstream assets, having served in that capacity since 1996. From 1996 to 2000, he also served as a Director of Crosstex Energy, Inc. From 1993 to 1996, he served as President, Chief Operating Officer and a Director of Cornerstone Natural Gas, Inc. Mr. Warren has more than 30 years of business experience in the energy industry. The members of our general partner selected Mr. Warren to serve as a director and as Chairman because he is ETO’s Chief Executive Officer and has more than 30 years in the natural gas industry. Mr. Warren also has relationships with chief executives and other senior
management at natural gas transportation companies throughout the United States, and brings a unique and valuable perspective to the Board of Directors. Thomas E. Long. Mr. Long has served as the Chief Financial Officer of our general partner since February 2016. Mr. Long also served as the Chief Financial Officer and as a director of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Long also serves as Chief Financial Officer of ETO and was previously Executive Vice President and Chief Financial Officer of Regency GP LLC from November 2010 to April 2015. From May 2008 to November 2010, Mr. Long served as Vice President and Chief Financial Officer of Matrix Service Company. Prior to joining Matrix, he served as Vice President and Chief Financial Officer of DCP Midstream Partners, LP, a publicly traded natural gas and natural gas liquids midstream business company located in Denver, CO. In that position, he was responsible for all financial aspects of the company since its formation in December 2005. From 1998 to 2005, Mr. Long served in several executive positions with subsidiaries of Duke Energy Corp., one of the nation’s largest electric power companies. Mr. Long has served as a director of Sunoco LP since May 2016, and as Chairman of the Board of USAC since April 2018. Marshall S. (Mackie) McCrea, III. Mr. McCrea is the President and Chief Commercial Officer of our general partner, having served in that role since October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. Prior to that time, he had been the Group Chief Operating Officer and Chief Commercial Officer of the Energy Transfer family since November 2015. Mr. McCrea has served on the Board of Directors of our general partner since December 2009. Mr. McCrea was appointed as a director of the general partner of ETO in December 2009. Prior to that, he served as President and Chief Operating Officer of ETO’s general partner from June 2008 to November 2015 and President – Midstream from March 2007 to June 2008. Previously he served as the Senior Vice President – Commercial Development since January 2004. In March 2005, Mr. McCrea was named President of La Grange Acquisition LP, ETO’s primary operating subsidiary, after serving as Senior Vice President-Business Development and Producer Services since 1997. Mr. McCrea also served as the Chairman of the Board of Directors of the general partner of Sunoco Logistics from October 2012 to April 2017. The members of our general partner selected Mr. McCrea to serve as a director because he brings extensive project development and operational experience to the Board. He has held various positions in the natural gas business over the past 25 years and is able to assist the Board of Directors in creating and executing the Partnership’s strategic plan. Matthew S. Ramsey. Mr. Ramsey was appointed as a director of ET’s general partner in July 2012 and as a director of ETO’s general partner in November 2015. Mr. Ramsey has been the Chief Operating Officer or our general partner since October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P., and currently serves as President and Chief Operating Officer of ETO’s general partner since November 2015. Mr. Ramsey also served as President and Chief Operating Officer and Chairman of the board of directors of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Ramsey is also a director of Sunoco LP, having served as chairman of Sunoco LP’s board since April 2015, and of USAC, having served on that board since April 2018. Mr. Ramsey previously served as President of RPM Exploration, Ltd., a private oil and gas exploration partnership, and previously served as a director of RSP Permian, Inc. where he served on the audit and compensation committees. Mr. Ramsey formerly served as President of DDD Energy, Inc. until its sale in 2002. From 1996 to 2000, Mr. Ramsey served as President and Chief Executive Officer of OEC Compression Corporation, Inc., a publicly traded oil field service company, providing gas compression services to a variety of energy clients. Previously, Mr. Ramsey served as Vice President of Nuevo Energy Company, an independent energy company. Additionally, he was employed by Torch Energy Advisors, Inc., a company providing management and operations services to energy companies including Nuevo Energy, last serving as Executive Vice President. Mr. Ramsey joined Torch Energy as Vice President of Land and was named Senior Vice President of Land in 1992. Mr. Ramsey holds a B.B.A. in Marketing from the University of Texas at Austin and a J.D. from South Texas College of Law. Mr. Ramsey is a graduate of Harvard Business School Advanced Management Program. Mr. Ramsey is licensed to practice law in the State of Texas. He is qualified to practice in the Western District of Texas and the United States Court of Appeals for the Fifth Circuit. Mr. Ramsey formerly served as a director of Southern Union Company. The member of our general partner recognize Mr. Ramsey’s vast experience in the oil and gas space and believe that he provides valuable industry insight as a member of our Board of Directors. Thomas P. Mason.Mr. Mason became Executive Vice President and General Counsel of the general partner of ET in December 2015, and has served as the Executive Vice President, General Counsel and President - LNG since October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. Mr. Mason also served as a director of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Mason previously served as Senior Vice President, General Counsel and Secretary of ETO’s general partner from April 2012 to December 2015, as Vice President, General Counsel and Secretary from June 2008 and as General Counsel and Secretary from February 2007. Prior to joining ETO, he was a partner in the Houston office of Vinson & Elkins. Mr. Mason has specialized in securities offerings and mergers and acquisitions for more than 25 years. Mr. Mason also served on the Board of Directors of the general partner of Sunoco Logistics from October 2012 to April 2017 and has served on the Board of Directors of USAC since April 2018.
John W. McReynolds. Mr. McReynolds became Special Advisor to ET in October 2018. Prior to that time, Mr. McReynolds served as our President from March 2005 until October 2018. He has served as a Director since August 2005. He served as our Chief Financial Officer from August 2005 to June 2013, and previously served as a Director of ETO’s general partner from August 2001 through May 2010. Mr. McReynolds has been in the energy industry for his entire career. Prior to joining Energy Transfer, Mr. McReynolds was in private law practice for over 20 years, specializing exclusively in energy-related finance, securities, corporations and partnerships, mergers and acquisitions, syndications, and a wide variety of energy-related litigation. His practice dealt with all forms of fossil fuels, and the transportation and handling thereof, together with the financing and structuring of all forms of business entities related thereto. The members of our general partner selected Mr. McReynolds to serve in the indicated roles with the Energy Transfer partnerships because of this extensive background and experience, as well as his many contacts and relationships in the industry. A. Troy Sturrock. Mr. Sturrock is the Senior Vice President and Controller of our general partner having assumed that role in October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. He has served as the Senior Vice President and Controller of the general partner of ETO since August 2016 and previously served as Vice President and Controller of our General Partner beginning in June 2015. Mr. Sturrock also served as a Senior Vice President of PennTex Midstream Partners, LP’s general partner, from November 2016 until July 2017, and as its Controller and Principal Accounting Officer from January 2017 until July 2017. Mr. Sturrock previously served as Vice President and Controller of Regency GP LLC from February 2008, and in November 2010 was appointed as the principal accounting officer. From June 2006 to February 2008, Mr. Sturrock served as the Assistant Controller and Director of financial reporting and tax for Regency GP LLC. Mr. Sturrock is a Certified Public Accountant. Ray C. Davis. Mr. Davis was appointed to the Board of Directors of our general partner in July 2018. From February 2018 to July 2018, Mr. Davis served on the Board of Directors of ETO. From February 2013 until February 2018, Mr. Davis was an independent investor. He has also been a principal owner, and served as co-chairman of the board of directors, of the Texas Rangers major league baseball club since August 2010. Mr. Davis previously served on the Board of Directors of the general partner of ET, effective upon the closing of ET’s initial public offering in February 2006 until his resignation in February 2013. Mr. Davis also served as ETO’s Co-Chief Executive Officer from the combination of the midstream and transportation operations of ETC OLP and the retail propane operations in January 2004 until his retirement from these positions in August 2007, and as Co-Chairman of the Board of Directors of our general partner from January 2004 until June 2011. Mr. Davis also held various executive positions with Energy Transfer prior to 2004. From 1996 to 2000, he served as a Director of Crosstex Energy, Inc. From 1993 to 1996, he served as Chairman of the Board of Directors and Chief Executive Officer of Cornerstone Natural Gas, Inc. The member of our general partner selected Mr. Davis to serve as a director based on his over 40 years of business experience in the energy industry and his expertise in the Partnership’s asset portfolio.
Steven R. Anderson. Mr. Anderson was elected to the Board of Directors of our general partner in June 2018 and serves on the audit committee and compensation committee. Mr. Anderson began his career in the energy business in the early 1970’s with Conoco in the Permian Basin area. He then spent some 25 years with ANR Pipeline and its successor, The Coastal Corporation, as a natural gas supply and midstream executive. He later was Vice President of Commercial Operations with Aquila Midstream and, upon the sale of that business to Energy Transfer in 2002, he became a part of the management team there. For the six years prior to his retirement from Energy Transfer in October 2009, he served as Vice President of Mergers and Acquisitions. Since that time, he has been involved in private investments and has served on the boards of directors of the St. John Health System and Saint Simeon's Episcopal Home in Tulsa, Oklahoma, as well as various other community and civic organizations. He also served on the Board of Directors of Sunoco Logistics Partners L.P. from October 2012 until April 2017. The members of our general partner selected Mr. Anderson to serve on the Board of Directors on the basis of his experience in the midstream industry generally and with Energy Transfer’s business specifically, as well as his recent experience on the board of another publicly traded partnership. Richard D. Brannon. Mr. Brannon was appointed to the Board of Directors of our general partner in March 2016 and has served as the Chairman of the audit committee since April 2016. Mr. Brannon is the CEO of CH4 Energy II, III, IV, V and Six, all independent companies focused on horizontal oil and gas development. Mr. Brannon served on the board of directors of WildHorse Resource Development from its IPO in December 2016 until June 2018. Mr. Brannon also formerly served on the Board of Directors and as a member of the audit committee and compensation committee of Sunoco LP, Regency, OEC Compression and Cornerstone Natural Gas Corp. He has over 35 years of experience in the energy business, having started his career in 1981 with Texas Oil & Gas. The members of our general partner selected Mr. Brannon to serve as director based on his knowledge of the energy industry and his experience as a director and audit and compensation committee member for other public companies.
Michael K. Grimm. Mr. Grimm was appointed to the Board of Directors of our general partner in October 2018, and has served on the audit committee and compensation committee since that time. Prior to that time, Mr. Grimm served as a director of ETO’s general partner beginning in December 2005, and served on the audit committee and compensation committee during that time. Mr. Grimm is one of the original founders of Rising Star Energy, L.L.C., a privately held upstream exploration and production
company active in onshore continental United States, and served as its President and Chief Executive Officer from 1995 until 2006 when it was sold. Mr. Grimm is currently President of Rising Star Petroleum, LLC. Mr. Grimm was formerly Chairman of the Board of RSP Permian, Inc. (NYSE: RSPP) from January 2014 until June 2018 and since November 2018 has served on the Board of Directors of Anadarko Petroleum Corporation (NYSE: APC). Prior to the formation of Rising Star, Mr. Grimm was Vice President of Worldwide Exploration and Land for Placid Oil Company from 1990 to 1994. Prior to joining Placid Oil Company, Mr. Grimm was employed by Amoco Production Company for thirteen years where he held numerous positions throughout the exploration department in Houston, New Orleans and Chicago. Mr. Grimm has been an active member of the Independent Petroleum Association of America, the American Association of Professional Landmen, Dallas Producers Club, Houston Producers Forum, Fort Worth Wildcatters and the All-American Wildcatters. He has a B.B.A. from the University of Texas at Austin. The members of our general partner selected Mr. Grimm to serve as a director because of his extensive experience in the energy industry and his service as a senior executive at several energy-related companies, in addition to his contacts in the industry gained through his involvement in energy-related organizations. Compensation of the General Partner Our general partner does not receive any management fee or other compensation in connection with its management of the Partnership. Section 16(a) Beneficial Ownership Reporting Compliance Section 16(a) of the Securities Exchange Act of 1934 requires the directors and executive officers of our general partner, as well as persons who own more than ten percent of the common units representing limited partnership interests in us, to file reports of ownership and changes of ownership on Forms 3, 4 and 5 with the SEC. The SEC regulations also require that copies of these Section 16(a) reports be furnished to us by such reporting persons. Based upon a review of copies of these reports, we believe all applicable Section 16(a) reports were timely filed in 2018.
ITEM 11. EXECUTIVE COMPENSATION Overview As a limited partnership, we are managed by our General Partner. Our General Partner is majority owned by Mr. Kelcy Warren. We own 100% of ETP GP and its general partner, ETP LLC. We refer to ETP GP and ETP LLC together as the “ETP GP Entities.” ETP GP is the general partner of ETO. Compensation Discussion and Analysis Named Executive Officers ET does not have officers or directors. Instead, we are managed by the board of directors of our General Partner, and the executive officers of our General Partner perform all of ET’s management functions. As a result, the executive officers of our General Partner are ET’s executive officers, and their compensation is administered by our General Partner. This Compensation Discussion and Analysis is, therefore, focused on the total compensation of the executive officers of our General Partner as set forth below. The persons we refer to in this discussion as our “named executive officers” are the following: Kelcy L. Warren, Chairman and Chief Executive Officer; Thomas E. Long, Chief Financial Officer; Marshall S. (Mackie) McCrea, III, President and Chief Commercial Officer; Matthew S. Ramsey, Chief Operating Officer; Thomas P. Mason, Executive Vice President, General Counsel and President — LNG; and John W. McReynolds, Former President (currently Special Advisor to the Partnership). Our Philosophy for Compensation of Executives In general, our General Partner’s philosophy for executive compensation is based on the premise that a significant portion of each executive’s compensation should be incentive-based or “at-risk” compensation and that executives’ total compensation levels should be highly competitive in the marketplace for executive talent and abilities. Our General Partner seeks a total compensation program for the named executive officers that provides for a slightly below the median market annual base compensation rate (i.e. approximately the 40th percentile of market) but incentive-based compensation composed of a combination of compensation vehicles to reward both short and long-term performance that are both targeted to pay-out at approximately the top-quartile of market. Our General Partner believes the incentive-based balance is achieved by (i) the payment of annual discretionary cash bonuses that consider the achievement of the Partnership’s financial performance objectives for a fiscal year set at the beginning of such fiscal year and the individual contributions of its named executive officers to the success of the Partnership and the achievement of the annual financial performance objectives and (ii) the annual grant of time-based restricted unit or phantom unit awards under the Partnership’s equity incentive plan(s) or the equity incentive programs of Sunoco LP, as applicable based on the allocation of the named executive officers’ award, which awards are intended to provide a longer term incentive and retention value to its key employees to focus their efforts on increasing the market price of its publicly traded units and to increase the cash distribution the Partnership and/or the other affiliated partnerships pay to their respective unitholders. The Partnership grants restricted unit and/or phantom unit awards that vest, based generally upon continued employment, at a rate of 60% after the third year of service and the remaining 40% after the fifth year of service. The Partnership believes that these equity-based incentive arrangements are important in attracting and retaining executive officers and key employees as well as motivating these individuals to achieve stated business objectives. The equity-based compensation reflects the importance our General Partner places on aligning the interests of its named executive officers with those of unitholders. As discussed below, our compensation committee, the ETO Compensation Committee (prior to the Energy Transfer Merger) and/or the compensation committee of the general partner of Sunoco LP, as applicable, all in consultation with our General Partner, are responsible for the compensation policies and compensation level of the named executive officers of our General Partner. In this discussion, we refer to our compensation committee as the “ET Compensation Committee.” Sunoco LP does not participate or have any input in any decisions as to the compensation policies of Sunoco GP LLC or the compensation levels of the executive officers of its general partner. The Sunoco LP Compensation Committee is responsible for the approval of the compensation policies and the compensation levels of the executive officers of Sunoco GP LLC.
For a more detailed description of the compensation to the Partnership’s named executive officers, please see “– Compensation Tables” below. Distributions to Our General Partner Our General Partner is majority-owned by Mr. Warren. We pay quarterly distributions to our General Partner in accordance with our partnership agreement with respect to its ownership of its general partner interest as specified in our partnership agreement. The amount of each quarterly distribution that we must pay to our General Partner is based solely on the provisions of our partnership agreement, which agreement specifies the amount of cash we distribute to our General Partner based on the amount of cash that we distribute to our limited partners each quarter. Accordingly, the cash distributions we make to our General Partner bear no relationship to the level or components of compensation of our General Partner’s executive officers. Distributions to our General Partner are described in detail in Note 8 to our consolidated financial statements. Our named executive officers also own directly and indirectly certain of our limited partner interests and, accordingly, receive quarterly distributions. Such per unit distributions equal the per unit distributions made to all our limited partners and bear no relationship to the level of compensation of the named executive officers or the services they perform as employees. For a more detailed description of the compensation of our named executive officers, please see “Compensation Tables” below. Compensation Philosophy Our compensation programs are structured to achieve the following: reward executives with an industry-competitive total compensation package of base salaries and significant incentive opportunities yielding a total compensation package approaching the top-quartile of the market; attract, retain and reward talented executive officers and key management employees by providing total compensation competitive with that of other executive officers and key management employees employed by publicly traded limited partnerships of similar size and in similar lines of business; motivate executive officers and key employees to achieve strong financial and operational performance; emphasize performance-based or “at-risk” compensation; and reward individual performance. Components of Executive Compensation For the year ended December 31, 2018, the compensation paid to our named executive officers consisted of the following components: annual base salary; non-equity incentive plan compensation consisting solely of discretionary cash bonuses; time-vested restricted/phantom unit awards under the equity incentive plan(s); payment of distribution equivalent rights (“DERs”) on unvested time-based restricted unit awards under our equity incentive plan; vesting of previously issued time-based restricted unit and/or phantom unit awards issued pursuant to our equity incentive plans or the equity incentive plans(s) of affiliates; and 401(k) plan employer contributions. Methodology The ET Compensation Committee considers relevant data available to it to assess our competitive position with respect to base salary, annual short-term incentives and long-term incentive compensation for our executive officers, including the named executive officers. The ET Compensation Committee also considers individual performance, levels of responsibility, skills and experience. Periodically, the ET Compensation Committee engages a third-party consultant to provide a full market competitive compensation analysis for compensation levels at peer companies in order to assist in the determination of compensation levels for our executive officers, including the named executive officers. Most recently, Longnecker & Associates (“Longnecker”) evaluated the market competitiveness of total compensation levels of a number of officers of the Partnership to provide market information with respect
to compensation of those executives during the year ended December 31, 2017. In particular, the review by Longnecker was designed to (i) evaluate the market competitiveness of total compensation levels for certain members of senior management, including our named executive officers; (ii) assist in the determination of appropriate compensation levels for our senior management, including the named executive officers; and (iii) confirm that our compensation programs were yielding compensation packages consistent with our overall compensation philosophy. In conducting its review, Longnecker specifically considered the larger size of the combined ET and ETO entities from an energy industry perspective. During 2017, Longnecker assisted in the development of the final “peer group” of leading companies in the energy industry that most closely reflect the profile of ET and ETO in terms of revenues, assets and market value as well as competition for talent at the senior management level and similarly situated general industry companies with similar revenues, assets and market value. In setting such peer group, the size of ET and ETO on a combined basis was considered. As part of the evaluation conducted by Longnecker, a determination was made to focus the analysis specifically on the energy industry based on a determination that an energy industry peer group provided a more than sufficient amount of comparative data to consider and evaluate total compensation. This decision allowed Longnecker to report on specific industry related data comparing the levels of annual base salary, annual short-term cash bonus and long-term equity incentive awards at industry peer group companies with those of the named executive officers to ensure that compensation of the named executive officers is both consistent with the compensation philosophy and competitive with the compensation for executive officers of these other companies. The identified companies were: | | | | Energy Peer Group: | | | • Conoco Phillips | | • Anadarko Petroleum Corporation | • Enterprise Products Partners, L.P. | | • Marathon Petroleum Corporation | • Plains All American Pipeline, L.P. | | • Kinder Morgan, Inc. | • Halliburton Company | | • The Williams Companies, Inc. | • Valero Energy Corporation | | • Phillips 66 |
The compensation analysis provided by Longnecker in 2017 covered all major components of total compensation, including annual base salary, annual short-term cash bonus and long-term incentive awards for the senior executives of these companies. In preparing the review materials, Longnecker utilized generally accepted compensation principles as determined by WorldatWork and gathered data from the public peer companies and published salary surveys. Following Longnecker’s 2017 review, the ET Compensation Committee reviewed the information provided, including Longnecker’s specific conclusions and recommended considerations for all compensation going forward. The ET Compensation Committee considered and reviewed the results of the study performed by Longnecker to determine if the results indicated that the compensation programs were yielding a competitive total compensation model prioritizing incentive-based compensation and rewarding achievement of short and long-term performance objectives and considered Longnecker’s conclusions and recommendations. While Longnecker found that the Partnership is achieving its stated objectives with respect to the “at-risk” approach, they also found that certain adjustments should be implemented during 2017 to allow the Partnership to achieve its targeted percentiles on base compensation and incentive compensation (short and long-term) as described below. In addition to the information received as part of Longnecker’s 2017 review, the ET Compensation Committee also utilizes information obtained from other sources in its determination of compensation levels for our named executive officers, such as annual third party surveys, although third party survey data is not used by the ET Compensation Committee to benchmark the amount of total compensation or any specific element of compensation for the named executive officers. While Longnecker did not provide a full study to the Partnership during 2018, Longnecker did provide (i) advice and feedback on the structure of the 2018 amendments to the Amended and Restated Energy Transfer Partners, L.L.C. Annual Bonus Plan (the “Bonus Plan”); and (ii) data and advice with respect to the Special Bonus award to Mr. Long. Additionally, Longnecker considered and provided feedback on the appropriateness, targets and composition of the 2018 equity award pool and the 2018 annual bonus awards under the Bonus Plan and benchmarking on certain non-named executive officer hires and promotions. Base Salary. Base salary is designed to provide for a competitive fixed level of pay that attracts and retains executive officers, and compensates them for their level of responsibility and sustained individual performance (including experience, scope of responsibility and results achieved). The salaries of the named executive officers are reviewed on an annual basis. As discussed above, the base salaries of our named executive officers are targeted to yield an annual base salary slightly below the median level of market (i.e. approximately the 40th percentile of market) and are determined by the ET Compensation Committee after taking into account the recommendations of Mr. Warren.
During the 2018 merit review process, the ET Compensation Committee considered the recommendations of Mr. Warren, the existing Longnecker study (with the data aged as appropriate) and the merit increase pool set for all employees of the Partnership and/or its employing affiliates. The ET Compensation Committee approved a 3.0% increase to the base salary of Mr. McCrea to $1,076,865 from its prior level of $1,045,000; a 3.0% base salary increase to Mr. Long to $545,900 from its prior level of $530,000; a 3.0% base salary increase to Mr. Ramsey to $673,041 from its prior level of $653,438; a 3% base salary increase to Mr. Mason to $610,044 from its prior level of $592,276; and a 3.0% increase for. Mr. McReynolds to $615,967 from its prior level of $598,026. Mr. Warren has voluntarily determined that his salary will be $1.00 per year (plus an amount sufficient to cover his allocated payroll deductions for health and welfare benefits), and, as such, did not receive any base salary or adjustment in 2018. The 3.0% increase to Messrs. McCrea, Long, Ramsey, Mason and McReynolds reflected a base salary increase consistent with the 3.0% annual merit increase pool set for all employees of ET and its affiliates for 2018. Annual Bonus. In addition to base salary, the ET Compensation Committee makes determinations whether to make discretionary annual cash bonus awards to executives, including our named executive officers, following the end of the year under the Bonus Plan. The Bonus Plan is a discretionary annual cash bonus plan available to all employees, including the named executive officers. The purpose of the Bonus Plan is to reward employees for contributions towards the Partnership’s business goals and to aid in motivating employees. The Bonus Plan is administered by the ET Compensation Committee and the ET Compensation Committee has the authority to establish and interpret the rules and regulations relating to the Bonus Plan, to select participants, to determine and approve the size of any actual award amount, to make all determinations, including factual determinations, under the Bonus Plan, and to take all other actions necessary or appropriate for the proper administration of the Bonus Plan. For each calendar year (the “Performance Period”), the ET Compensation Committee will evaluate and determine an overall funded cash bonus pool based on achievement of (i) an internal Adjusted EBITDA target (“Adjusted EBITDA Target”), (ii) an internal distributable cash flow target (“DCF Target”) and (iii) performance of each department compared to the applicable departmental budget (“Departmental Budget Target”). The Adjusted EBITDA Target and the DCF Target are defined for purposes of the Bonus Plan using the same definitions as used in the Partnership’s audited financial statements included in its annual and quarterly filings on Forms 10-K and 10-Q for the terms Adjusted EBITDA and Distributable Cash Flow. The performance criteria are weighted 60% on the achievement of the Adjusted EBITDA Target, 20% on the achievement of the DCF Target and 20% on the achievement of the Departmental Budget Target (collectively, “Budget Targets”). The total amount of cash to be allocated to the funded bonus pool will range from 0% to 120% for each of the budgeted DCF Target and Adjusted EBITDA Target and will range from 0% to 100% of the Departmental Budget Target. The maximum funding of the bonus pool is 116% of the total pool target and to achieve such funding each of the Adjusted EBITDA and the DCF Target must achieve 120% funding and the Department Budget target must achieve its 100% target. While the funded bonus pool will reflect an aggregation of performance under each target, in the event performance under the Adjusted EBITDA Target is below 80% of its target, no bonus pool will be funded. If the bonus pool is funded, a participant may earn a cash award for the Performance Period based upon the level of attainment of the Budget Targets and his or her individual performance. Awards are paid in cash as soon as practicable after the end of the Performance Period but in no event later than two and one-half months after the end of the Performance Period. While the achievement of the Budget Targets sets a bonus pool under the Bonus Plan, actual bonus awards are discretionary. These discretionary bonuses, if awarded, are intended to reward our named executive officers for the achievement of the Budget Targets during the Performance Period in light of the contribution of each individual to our profitability and success during such year. The ET Compensation Committee also considers the recommendation of Mr. Warren in determining the specific annual cash bonus amounts for each of the named executive officers. The ET Compensation Committee does not establish its own financial performance objectives in advance for purposes of determining whether to approve any annual bonuses, and it does not utilize any formulaic approach to determine annual bonuses. For 2018, the ET Compensation Committee approved short-term annual cash bonus pool targets for Mr. McCrea of 160% of his annual base earnings and for Messrs. Long, Ramsey, Mason and McReynolds of 130% of their annual base earnings. The named executive officer bonus pool targets remained the same for the 2019 Performance Period as they were for the 2017 period. In February 2019, the ET Compensation Committee certified 2018 performance results under the Bonus Plan, which resulted in a bonus payout of 110% of the bonus pool target, which reflected achievement of 110% of the Adjusted EBITDA Target, 120% of the DCF Target and 100% of the Department Budget Target. Based on the approved results, the ET Compensation Committee approved a cash bonus relating to the 2018 calendar year to Messrs. McCrea, Long, Ramsey, Mason and McReynolds in the amounts of $1,866,000, $800,000, $900,000, $858,700 and $800,000, respectively. In approving the 2018 bonuses of the named executive officers, the ET Compensation Committee took into account the achievement by the Partnership of all of the targeted performance objectives for 2018 and the individual performances of each of the named executive officers. The cash bonuses awarded to each of the named executive officers for 2018 performance were materially
consistent with their applicable bonus pool targets. As with base salary and equity awards, Mr. Warren does not accept or receive an annual bonus. Equity Awards. In connection with the Energy Transfer Merger, ET assumed the obligations of ETO under the ETO equity plans and assumed such plans for purposes of employing such plans to make grants of equity-based awards relating to ET common units following the closing of the merger. The ETO equity plans assumed by ET, which have been subsequently renamed, are (i) the Second Amended and Restated Energy Transfer LP 2008 Incentive Plan (the “2008 Incentive Plan”); (ii) the Energy Transfer LP 2011 Long-Term Incentive Plan (the “2011 Incentive Plan”) and the (iii) Energy Transfer LP 2015 Long-Term Incentive Plan (the “2015 Plan”). In 2017, ET adopted the Amended and Restated Energy Transfer LP Long-Term Incentive Plan (formerly the Amended and Restated Energy Transfer Equity, L.P. Long Term Incentive Plan, together with the 2008 Incentive Plan, the 2011 Incentive Plan and the 2015 Plan, the “ET Incentive Plans”). The ET Incentive Plans authorize the ET Compensation Committee, in its discretion, to grant awards, as applicable under each respective plan of restricted units, phantom units, unit options, unit appreciation rights and other awards related to ET common units upon such terms and conditions as it may determine appropriate and in accordance with general guidelines as defined by the ET Incentive Plans. For 2018, the annual long-term incentive targets set by the ET Compensation Committee for the named executive officers were 900% of annual base salary for Mr. McCrea and 500% of annual base salary for Messrs. Long, Ramsey and Mason. Due to his significant holdings of ET units, Mr. McReynolds does not receive annual equity awards. The 500% target for Mr. Ramsey is a decrease from his previous target of 600% and represents a desire on the part of the Chairman to align the senior officers that report to him, other than Mr. McCrea, with a consistent long-term incentive target. The targets of the other named executive officers were consistent with the prior year’s targets. In December 2018, the ET Compensation Committee in consultation with ET’s Chairman determined to issue long-term incentive awards in the form of restricted units under the ET Incentive Plans to the ET named executive officers, other than Mr. McReynolds, who as noted above does not currently receive long-term incentive awards. In December of 2018, the ET Compensation Committee approved grants of phantom unit awards to Messrs. McCrea, Long, Ramsey and Mason of 605,470 units, 136,475 units, 168,260 units and 190,640 units, respectively. As with base salary and annual bonus, Mr. Warren does not accept or receive annual long term incentive awards. As more fully described below in the section titled Affiliate and Subsidiary Equity Awards, for 2018, in discussions between the General Partner, the ET Compensation Committees and the compensation committee of the general partner of Sunoco LP, it was determined that for 2018 the value of Messrs. Long and Ramsey’s awards would be comprised of restricted unit awards under the ET Incentive Plans and the Sunoco LP 2018 Long-Term Incentive Plan (the “2018 Sunoco LP Plan”) in consideration of their roles and responsibilities for Sunoco LP and their status, as members of the Boards of Directors of the general partner of Sunoco LP. Messrs. Long and Ramsey’s total 2018 long-term awards were allocated 80% to the ET Incentive Plans and 20% to the 2018 Sunoco LP Plan. The awards of Messrs. McCrea and Mason for 2018 were allocated entirely to the ET Incentive Plans. In the case of Mr. Mason this represented a change from prior year allocations of awards under the long-term incentive plans of affiliates as his time for 2018 was almost fully dedicated to ET and his role at Sunoco LP was reduced as a result of his additional ET responsibilities. It is expected that future long-term incentive awards to Messrs. Long and Ramsey of ET will recognize an aggregation of restricted units under the ET Incentive Plans and the 2018 Sunoco LP Plan, as applicable. The restricted unit awards granted in 2018 provide for incremental vesting over a five-year period, with 60% vesting at the end of the third year and the remaining 40% vesting at the end of the fifth year. Vesting of the awards are generally subject to continued employment through each specified vesting date. The restricted unit awards entitle the recipients to receive, with respect to each ET unit subject to such award that has not either vested or been forfeited, a DER cash payment promptly following each such distribution by ET to its unitholders. In approving the grant of such restricted unit awards, including to the named executive officers, the ET Compensation Committee considered several factors, including the long-term objective of retaining such individuals as key drivers of ET’s future success, the existing level of equity ownership of such individuals and the previous awards to such individuals of equity awards subject to vesting. Vesting of the 2018 awards would accelerate in the event of the death or disability of the recipient, including the named executive officers, or in the event of a change in control of ET as that term is defined under the ET Incentive Plans. As discussed below under “Potential Payments Upon a Termination or Change of Control,” all outstanding equity would automatically accelerate upon a change in control event, which means vesting automatically accelerates upon a change of control irrespective of whether the officer is terminated. In addition, the 2014 awards to Mr. McCrea included a provision in the applicable award agreement for acceleration of unvested restricted unit/restricted phantom unit awards upon a termination of employment by the general partner of the applicable partnership issuing the award without “cause”. For purposes of the awards the term “cause” shall mean: (i) a conviction (treating a nolo contendere plea as a conviction) of a felony (whether or not any right to appeal has
been or may be exercised), (ii) willful refusal without proper cause to perform duties (other than any such refusal resulting from incapacity due to physical or mental impairment), (iii) misappropriation, embezzlement or reckless or willful destruction of property of the partnership or any of its affiliates, (iv) knowing breach of any statutory or common law duty of loyalty to the partnership or any of its or their affiliates, (v) improper conduct materially prejudicial to the business of the partnership or any of its or their affiliates by, (vi) material breach of the provisions of any agreement regarding confidential information entered into with the partnership or any of its or their affiliates or (vii) the continuing failure or refusal to satisfactorily perform essential duties to the partnership or any of its or their affiliates. In addition, the award agreements for the restricted units awarded in 2018, as well as other awards outstanding held by Partnership employees, including the named executive officers, also include certain acceleration provisions upon retirement with the ability to accelerate 40% of outstanding unvested awards under the ET Incentive Plans at age 65 and 50% at age 68. These acceleration provisions require that the participant have not less than five (5) years of employment service to the Partnership or an affiliate and require a six (6) month delay in the vesting after retirement pursuant to the requirements of Section 409(A) of the Code. We believe that permitting the accelerated vesting of equity awards upon a change in control creates an important retention tool for us by enabling employees to realize value from these awards in the event that we undergo a change in control transaction. In addition, we believe permitting acceleration of vesting upon a change in control and the acceleration of vesting awards upon a termination without “cause” in the case of the 2014 awards to Mr. McCrea creates a sense of stability in the course of transactions that could create uncertainty regarding their future employment and encourage these officers to remain focused on their job responsibilities. Affiliate and Subsidiary Equity Awards. In addition to their roles as officers of for ET and ETO during 2018, Messrs. Long and Ramsey have certain responsibilities for Sunoco LP, including as members of the Board of Directors of the general partner of Sunoco LP. The Sunoco LP Compensation Committee in December 2018 approved grants of restricted unit awards to Messrs. Long and Ramsey of 19,325 and 23,825 restricted units, respectively, under the 2018 Sunoco LP Plan. The terms and conditions of the restricted unit to Messrs. Long and Ramsey under the 2018 Sunoco LP Plan, as applicable, were the same and provided for vesting over a five-year period, with 60% vesting at the end of the third year and the remaining 40% vesting at the end of the fifth year, subject generally to continued employment through each specified vesting date. All of the awards would be accelerated in the event of their death, disability, upon a change in control or retirement at ages 65 or 68. Special Bonus Award. On October 19, 2018, the ET Compensation Committee approved a special one-time bonus award (the “Special Award”) to Mr. Long in recognition of Mr. Long’s contributions to several key strategic initiatives, including the successful Energy Transfer Merger. The Special Award was composed of $1,000,000 cash paid in one ump-sum in October 2018 and 115,200 restricted units under the 2008 Incentive Plan. The restricted units awarded to Mr. Long under the 2008 Incentive Plan carry the right to receive DER cash payments and are subject to vesting as follows: 60% of the aggregate number of ET Restricted Units on December 5, 2021, and the remaining 40% on December 5, 2023, based on continued employment with the Partnership on each such date. In the event that Mr. Long is terminated without “cause,” dies or becomes disabled or there is a change in control of ET as that term is defined under the 2008 Incentive Plan, vesting of the restricted units would automatically accelerate. For purposes of the Special Award to Mr. Long, “cause” shall mean: (i) a conviction (treating a nolo contendere plea as a conviction) of a felony (whether or not any right to appeal has been or may be exercised), (ii) willful refusal without proper cause to perform duties (other than any such refusal resulting from incapacity due to physical or mental impairment), (iii) misappropriation, embezzlement or reckless or willful destruction of property of the Partnership or any of its affiliates, (iv) knowing breach of any statutory or common law duty of loyalty to the Partnership or any of its or their affiliates, (v) improper conduct materially prejudicial to the business of the Partnership or any of its or their affiliates by, (vi) material breach of the provisions of any agreement regarding confidential information entered into with the Partnership or any of its or their affiliates or (vii) the continuing failure or refusal to satisfactorily perform essential duties to the Partnership or any of its or their affiliates. Unit Ownership Guidelines. The Board of Directors of our General Partner has adopted the Executive Unit Ownership Guidelines (the “Guidelines”), which set forth minimum ownership guidelines applicable to certain executives of ET with respect to ET and Sunoco LP common units representing limited partnership interests, as applicable. The applicable Guidelines are denominated as a multiple of base salary, and the amount of common units required to be owned increases with the level of responsibility. Under these Guidelines, the President and Chief Commercial Officer and the Chief Operating Officer are expected to own common units having a minimum value of five times his base salary, while each of the remaining named executive officers (other than the CEO) are expected to own common units having a minimum value of four times their respective base salary. In addition to the named executive officers, these Guidelines also apply to other covered executives, which executives are expected to own either directly or indirectly in accordance with the terms of the Guidelines, common units having minimum values ranging from two to four times their respective base salary.
The ET Compensation Committee believes that the ownership of ET and/or Sunoco LP common units, as reflected in these Guidelines, is an important means of tying the financial risks and rewards for its executives to ET’s total unitholder return, aligning the interests of such executives with those of ET’s Unitholders, and promoting ET’s interest in good corporate governance. Covered executives are generally required to achieve their ownership level within five years of becoming subject to the Guidelines; however, certain covered executives, based on their tenure as an executive, are required to achieve compliance within two years of the December 2013 effective date of the Guidelines. Thus, compliance with the Guidelines was required for Messrs. McCrea and Mason beginning in December 2015, and they were compliant. Compliance for Mr. Long was required in December 2018, and he was compliant. Compliance for Mr. Ramsey will be required in December 2020. Covered executives may satisfy the Guidelines through direct ownership of ET and/or Sunoco LP common units or indirect ownership by certain immediate family members. Direct or indirect ownership of ET and/or Sunoco LP common units shall count on a one-to-one ratio for purposes of satisfying minimum ownership requirements; however, unvested unit awards may not be used to satisfy the minimum ownership requirements. Executive officers, including the named executive officers, who have not yet met their respective guideline must retain and hold all common units (less common units sold to cover the executive’s applicable taxes and withholding obligation) received in connection with long-term incentive awards. Once the required ownership level is achieved, ownership of the required common units must be maintained for as long as the covered executive is subject to the Guidelines. However, those individuals who have met or exceeded their applicable ownership level guideline may dispose of the common units in a manner consistent with applicable laws, rules and regulations, including regulations of the SEC and our internal policies, but only to the extent that such individual’s remaining ownership of common units would continue to exceed the applicable ownership level. Qualified Retirement Plan Benefits. The Energy Transfer LP 401(k) Plan (the “ET 401(k) Plan”) is a defined contribution 401(k) plan, which covers substantially all of our employees, including the named executive officers. Employees may elect to defer up to 100% of their eligible compensation after applicable taxes, as limited under the Internal Revenue Code. We make a matching contribution that is not less than the aggregate amount of matching contributions that would be credited to a participant’s account based on a rate of match equal to 100% of each participant’s elective deferrals up to 5% of covered compensation. The amounts deferred by the participant are fully vested at all times, and the amounts contributed by the Partnership become vested based on years of service. We provide this benefit as a means to incentivize employees and provide them with an opportunity to save for their retirement. The Partnership provides a 3% profit sharing contribution to employee 401(k) accounts for all employees with a 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. Health and Welfare Benefits. All full-time employees, including our named executive officers may participate in ETP GP’s health and welfare benefit programs including medical, dental, vision, flexible spending, life insurance and disability insurance. Termination Benefits. Our named executive officers do not have any employment agreements that call for payments of termination or severance benefits or that provide for any payments in the event of a change in control of our General Partner; however, the award agreement to the named executive officers under the ET Incentive Plans, the 2018 Sunoco LP Plan and the Sunoco LP 2012 Long-Term Incentive Plan (the “2012 Sunoco LP Plan”) provide for immediate vesting of all unvested restricted unit awards in the event of a (i) change of control, as defined in the plan; (ii) death or (iii) disability, as defined in the applicable plan. Please refer to “Compensation Tables - Potential Payments Upon a Termination or Change of Control” for additional information. In addition, ETP GP has also adopted the ETP GP Severance Plan and Summary Plan Description effective as of June 12, 2013, (the “Severance Plan”), which provides for payment of certain severance benefits in the event of Qualifying Termination (as that term is defined in the Severance Plan). In general, the Severance Plan provides payment of two weeks of annual base salary for each year or partial year of employment service up to a maximum of fifty-two weeks or one year of annual base salary (with a minimum of four weeks of annual base salary) and up to three months of continued group health insurance coverage. The Severance Plan also provides that we may determine to pay benefits in addition to those provided under the Severance Plan based on special circumstances, which additional benefits shall be unique and non-precedent setting. The Severance Plan is available to all salaried employees on a nondiscriminatory basis; therefore, amounts that would be payable to our named executive officers upon a Qualified Termination have been excluded from “Compensation Tables – Potential Payments Upon a Termination or Change of Control” below. Energy Transfer LP Non-Qualified Deferred Compensation Plan (the “ET NQDC Plan”) is a deferred compensation plan, which permits eligible highly compensated employees to defer a portion of their salary, bonus, and/or quarterly non-vested phantom unit distribution equivalent income until retirement, termination of employment or other designated distribution event. Each year under the ET NQDC Plan, eligible employees are permitted to make an irrevocable election to defer up to 50% of their annual base
salary, 50% of their quarterly non-vested phantom unit distribution income, and/or 50% of their discretionary performance bonus compensation during the following year. Pursuant to the ET NQDC Plan, ET may make annual discretionary matching contributions to participants’ accounts; however, ET has not made any discretionary contributions to participants’ accounts and currently has no plans to make any discretionary contributions to participants’ accounts. All amounts credited under the ET NQDC Plan (other than discretionary credits) are immediately 100% vested. Participant accounts are credited with deemed earnings or losses based on hypothetical investment fund choices made by the participants among available funds. Participants may elect to have their account balances distributed in one lump sum payment or in annual installments over a period of three or five years upon retirement, and in a lump sum upon other termination events. Participants may also elect to take lump-sum in-service withdrawals five years or longer in the future, and such scheduled in-service withdrawals may be further deferred prior to the withdrawal date. Upon a change in control (as defined in the ET NQDC Plan) of ET, all ET NQDC Plan accounts are immediately vested in full. However, distributions are not accelerated and, instead, are made in accordance with the ET NQDC Plan’s normal distribution provisions unless a participant has elected to receive a change of control distribution pursuant to his deferral agreement. None of our named executive officers currently participate in this plan. Risk Assessment Related to our Compensation Structure. We believe that the compensation plans and programs for our named executive officers, as well as our other employees, are appropriately structured and are not reasonably likely to result in material risk to us. We believe these compensation plans and programs are structured in a manner that does not promote excessive risk-taking that could harm our value or reward poor judgment. We also believe we have allocated compensation among base salary and short and long-term compensation in such a way as to not encourage excessive risk-taking. In particular, we generally do not adjust base annual salaries for executive officers and other employees significantly from year to year, and therefore the annual base salary of our employees is not generally impacted by our overall financial performance or the financial performance of a portion of our operations. Our subsidiaries generally determine whether, and to what extent, their respective named executive officers receive a cash bonus based on achievement of specified financial performance objectives as well as the individual contributions of our named executive officers to the Partnership’s success. We and our subsidiaries use restricted units and phantom units rather than unit options for equity awards because restricted units and phantom units retain value even in a depressed market so that employees are less likely to take unreasonable risks to get, or keep, options “in-the-money.” Finally, the time-based vesting over five years for our long-term incentive awards ensures that the interests of employees align with those of our unitholders and our subsidiaries’ unitholders for our long-term performance. Tax and Accounting Implications of Equity-Based Compensation Arrangements Deductibility of Executive Compensation We are a limited partnership and not a corporation for United States federal income tax purposes. Therefore, we believe that the compensation paid to the named executive officers is not subject to the deduction limitations under Section 162(m) of the Internal Revenue Code and therefore is generally fully deductible for United States federal income tax purposes. Accounting for Non-Cash Compensation For non-cash compensation arrangements we record compensation expense over the vesting period of the awards, as discussed further in Note 9 to our consolidated financial statements. Compensation Committee Interlocks and Insider Participation Mr. Michael K. Grimm and Mr. Steven R. Anderson are the only members of the Compensation Committee. During 2018, no member of the Compensation Committee was an officer or employee of us or any of our subsidiaries or served as an officer of any company with respect to which any of our executive officers served on such company’s board of directors. Mr. Grimm is not a former employee of ours or any of our subsidiaries. Mr. Anderson was previously an employee of the Partnership until his retirement in October 2009, as discussed in his biographical information included in “Item 10. Directors, Executive Officers and Corporate Governance.”
Report of Compensation Committee The board of directors of our General Partner has reviewed and discussed the section entitled “Compensation Discussion and Analysis” with the management of ET. Based on this review and discussion, we have recommended that the Compensation Discussion and Analysis be included in this annual report on Form 10-K.
The Compensation Committee of the Board of Directors of LE GP, LLC, general partner of Energy Transfer LP
Michael K. Grimm Steven R. Anderson The foregoing report shall not be deemed to be incorporated by reference by any general statement or reference to this annual report on Form 10-K into any filing under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, except to the extent that we specifically incorporate this information by reference, and shall not otherwise be deemed filed under those Acts. Compensation Tables Summary Compensation Table | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Name and Principal Position | | Year | | Salary ($) | | Bonus(1) ($) | | Equity Awards (2) ($) | | Option Awards ($) | | Non-Equity Incentive Plan Compensation(3) ($) | | Change in Pension Value and Nonqualified Deferred Compensation Earnings ($) | | All Other Compensation(4) ($) | | Total ($) | Kelcy L. Warren (5) | | 2018 | | $ | 6,138 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 6,138 |
| Chief Executive Officer | | 2017 | | 5,926 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 5,926 |
| | 2016 | | 5,920 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 58 |
| | 5,978 |
| Thomas E. Long | | 2018 | | 537,338 |
| | 1,000,000 |
| | 4,251,335 |
| | — |
| | 800,000 |
| | — |
| | 21,294 |
| | 6,609,967 |
| Chief Financial Officer | | 2017 | | 480,846 |
| | — |
| | 2,519,954 |
| | — |
| | 625,100 |
| | — |
| | 18,320 |
| | 3,644,220 |
| | 2016 | | 454,154 |
| | — |
| | 2,007,697 |
| | — |
| | 560,865 |
| | — |
| | 14,679 |
| | 3,037,395 |
| Marshall S. (Mackie) McCrea, III | | 2018 | | 1,059,976 |
| | — |
| | 7,834,782 |
| | — |
| | 1,866,000 |
| | — |
| | 19,362 |
| | 10,780,120 |
| President and Chief Commercial Officer | | 2017 | | 1,027,846 |
| | — |
| | 9,033,341 |
| | — |
| | 1,644,554 |
| | — |
| | 16,834 |
| | 11,722,575 |
| | 2016 | | 1,009,231 |
| | — |
| | 8,059,413 |
| | — |
| | 1,533,990 |
| | — |
| | 14,818 |
| | 10,617,452 |
| Matthew S. Ramsey | | 2018 | | 662,486 |
| | — |
| | 2,818,415 |
| | — |
| | 900,000 |
| | — |
| | 19,294 |
| | 4,400,195 |
| Chief Operating Officer | | 2017 | | 642,404 |
| | — |
| | 3,763,893 |
| | — |
| | 835,125 |
| | — |
| | 18,618 |
| | 5,260,040 |
| | 2016 | | 630,769 |
| | — |
| | 3,433,894 |
| | — |
| | 838,901 |
| | — |
| | 87,375 |
| | 4,990,939 |
| Thomas P. Mason | | 2018 | | 600,477 |
| | — |
| | 2,466,882 |
| | — |
| | 858,700 |
| | — |
| | 19,294 |
| | 3,945,353 |
| Executive Vice President, General Counsel and President – LNG | | 2017 | | 582,275 |
| | — |
| | 2,816,048 |
| | — |
| | 756,958 |
| | — |
| | 18,618 |
| | 4,173,899 |
| | 2016 | | 571,729 |
| | — |
| | 2,524,064 |
| | — |
| | 706,067 |
| | — |
| | 14,818 |
| | 3,816,678 |
| John W. McReynolds | | 2018 | | 606,306 |
| | — |
| | — |
| | — |
| | 800,000 |
| | — |
| | 15,967 |
| | 1,422,273 |
| Former President | | 2017 | �� | 587,928 |
| | — |
| | — |
| | — |
| | 764,306 |
| | — |
| | 15,179 |
| | 1,367,413 |
| | 2016 | | 577,280 |
| | — |
| | — |
| | — |
| | 712,922 |
| | — |
| | 10,768 |
| | 1,300,970 |
|
| | (1) | For Mr. Long, the amount shown includes the cash portion of his Special Award. |
| | (2) | Equity award amounts reflect the aggregate grant date fair value of unit awards granted for the periods presented, computed in accordance with FASB ASC Topic 718. For Messrs. Long and Ramsey amounts include equity awards of our subsidiaries and/or affiliates, as reflected in the “Grants of Plan-Based Awards Table.” See Note 9 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” for additional assumptions underlying the value of the equity awards. |
| | (3) | ET maintains the Bonus Plan which provides for discretionary basis. Award of discretionary bonuses are tied to achievement of targeted performance objectives and described in the Compensation Discussion and Analysis. The discretionary cash bonus |
amounts earned by the named executive officers for 2018 reflect cash bonuses approved by the ET Compensation Committee in February 2019 that are expected to be paid on or before March 15, 2019. | | (4) | The amounts reflected for 2018 in this column include (i) matching contributions to the ET 401(k) Plan made on behalf of the named executive officers of $13,750 each for Messrs. Long, McCrea, Ramsey and Mason and $9,300 for Mr. McReynolds, (ii) health savings account contributions made on behalf of the named executive officers of $2,000 each for Messrs. Long and McCrea, and (iii) the dollar value of life insurance premiums paid for the benefit of the named executive officers. The amounts reflected for all periods exclude distribution payments in connection with distribution equivalent rights on unvested unit awards, because the dollar value of such distributions are factored into the grant date fair value reported in the “Equity Awards” column of the Summary Compensation Table at the time that the unit awards and distribution equivalent rights were originally granted. For 2018, distribution payments in connection with distribution equivalent rights totaled $594,423 for Mr. Long, $2,183,255 for Mr. McCrea, $816,297 for Mr. Ramsey, and $759,825 for Mr. Mason. |
| | (5) | Mr. Warren has voluntarily determined that his salary will be reduced to $1.00 per year (plus an amount sufficient to cover his allocated payroll deductions for health and welfare benefits). He also does not accept a cash bonus or any equity awards under the equity incentive plans. |
Grants of Plan-Based Awards Table | | | | | | | | | | | | | | | | | | Name | | Grant Date | | All Other Unit Awards: Number of Units (#) | | All Other Option Awards: Number of Securities Underlying Options (#) | | Exercise or Base Price of Option Awards ($ / Unit) | | Grant Date Fair Value of Unit Awards (1) | ET Unit Awards: | | | | | | | | | | | Kelcy L. Warren | | N/A | | — |
| | — |
| | $ | — |
| | $ | — |
| Thomas E. Long | | 12/18/2018 | | 136,475 |
| | — |
| | — |
| | 1,765,987 |
| | | 10/19/2018 | | 115,200 |
| (2) | | | | | 1,965,312 |
| Marshal S. (Mackie) McCrea, III | | 12/18/2018 | | 605,470 |
| | — |
| | — |
| | 7,834,782 |
| Matthew S. Ramsey | | 12/18/2018 | | 168,260 |
| | — |
| | — |
| | 2,177,284 |
| Thomas P. Mason | | 12/18/2018 | | 190,640 |
| | — |
| | — |
| | 2,466,882 |
| John W. McReynolds | | N/A | | — |
| | — |
| | — |
| | — |
| Sunoco LP Unit Awards: | | | | | | | | | | | Thomas E. Long | | 12/19/2018 | | 19,325 |
| | — |
| | — |
| | 520,036 |
| Matthew S. Ramsey | | 12/19/2018 | | 23,825 |
| | — |
| | — |
| | 641,131 |
|
| | (1) | We have computed the grant date fair value of unit awards in accordance with FASB ASC Topic 718, as further described above and in Note 9 to our consolidated financial statements. |
| | (2) | Represents restricted units subject to Mr. Long’s Special Award. |
Narrative Disclosure to Summary Compensation Table and Grants of the Plan-Based Awards Table A description of material factors necessary to understand the information disclosed in the tables above with respect to salaries, bonuses, equity awards, and 401(k) plan contributions can be found in the Compensation Discussion and Analysis that precedes these tables.
Outstanding Equity Awards at 2018 Fiscal Year-End Table | | | | | | | | | | | Name | | Grant Date(1) | | Unit Awards (1) | Number of Units That Have Not Vested(2) (#) | | Market or Payout Value of Units That Have Not Vested (3) ($) | ET Unit Awards: | | | | | | | Kelcy L. Warren | | N/A | | — |
| | $ | — |
| Thomas E. Long | | 12/18/2018 | | 136,475 |
| | 1,802,835 |
| | | 10/19/2018 | | 115,200 |
| | 1,521,792 |
| | | 12/20/2017 | | 121,074 |
| | 1,599,388 |
| | | 12/29/2016 | | 75,588 |
| | 998,517 |
| | | 12/9/2015 | | 14,227 |
| | 187,941 |
| | | 12/4/2015 | | 5,739 |
| | 75,816 |
| | | 12/16/2014 | | 10,486 |
| | 138,520 |
| Marshal S. (Mackie) McCrea, III | | 12/18/2018 | | 605,740 |
| | 8,001,825 |
| | | 12/20/2017 | | 537,379 |
| | 7,098,777 |
| | | 12/29/2016 | | 430,575 |
| | 5,687,889 |
| | | 12/9/2015 | | 94,855 |
| | 1,253,032 |
| | | 12/4/2015 | | 47,816 |
| | 631,650 |
| | | 12/16/2014 | | 48,115 |
| | 635,602 |
| | | 12/5/2014 | | 21,062 |
| | 278,231 |
| Matthew S. Ramsey | | 12/18/2018 | | 168,260 |
| | 2,222,715 |
| | | 12/20/2017 | | 223,908 |
| | 2,957,825 |
| | | 12/29/2016 | | 183,601 |
| | 2,425,369 |
| | | 12/9/2015 | | 59,282 |
| | 783,119 |
| Thomas P. Mason | | 12/18/2018 | | 190,640 |
| | 2,518,354 |
| | | 12/20/2017 | | 135,300 |
| | 1,787,313 |
| | | 12/29/2016 | | 101,613 |
| | 1,342,306 |
| | | 12/9/2015 | | 22,391 |
| | 295,785 |
| | | 12/4/2015 | | 11,287 |
| | 149,101 |
| | | 12/16/2014 | | 16,592 |
| | 219,181 |
| | | 12/5/2014 | | 7,740 |
| | 102,248 |
| John W. McReynolds | | N/A | | — |
| | — |
| | | | | | | | Sunoco LP Unit Awards: | | | | | | | Thomas E. Long | | 12/19/2018 | | 19,325 |
| | $ | 525,447 |
| | | 12/21/2017 | | 17,097 |
| | 464,867 |
| | | 12/29/2016 | | 22,210 |
| | 603,890 |
| | | 12/16/2015 | | 5,650 |
| | 153,624 |
| Matthew S. Ramsey | | 12/19/2018 | | 23,825 |
| | 647,802 |
| | | 1/2/2015 | | 814 |
| | 22,133 |
| | | 11/10/2014 | | 299 |
| | 8,130 |
| Thomas P. Mason | | 12/21/2017 | | 19,106 |
| | 519,492 |
| | | 12/29/2016 | | 7,410 |
| | 201,483 |
| | | 12/16/2015 | | 23,300 |
| | 633,527 |
|
| | (1) | Certain of these outstanding awards represent Energy Transfer Partners, L.P. awards that converted into ET awards upon the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. in October 2018. Furthermore, some of those converted awards had previously been converted in connection with the merger of Energy Transfer Partners, L.P. and Sunoco Logistics in April 2017. |
| | (2) | ET unit awards outstanding vest at a rate of 60% in December 2020 and 40% in December 2022 for awards granted in December 2017. Such awards may be settledat the election of the ET Compensation Committee in (i) common units of ET (subject to the approval of the ET Incentive Plans prior to the first vesting date by a majority of ET’s unitholders pursuant to the rules of the New York Stock Exchange); (ii) cash equal to the Fair Market Value (as such term is defined in the ET Incentive Plans) |
of the ET common units that would otherwise be delivered pursuant to the terms of each named executive officers grant agreement; or (iii) other securities or property in an amount equal to the Fair Market Value of ET common units that would otherwise be delivered pursuant to the terms of the grant agreement, or a combination thereof as determined by the ET Compensation Committee in its discretion. Other unit awards outstanding vest as follows: at a rate of 60% in December 2021 and 40% in December 2023 for awards granted in October and December 2018; at a rate of 60% in December 2020 and 40% in December 2022 for awards granted in December 2017; at a rate of 60% in December 2019 and 40% in December 2021 for awards granted in December 2016; 100% in December 2020 for the remaining outstanding portion of awards granted in December 2015; and 100% in December 2019 for the remaining outstanding portion of all other awards. | | (3) | Market value was computed as the number of unvested awards as of December 31, 2018 multiplied by the closing price of respective common units of ET and Sunoco LP. |
Option Exercises and Units Vested Table | | | | | | | | | | | Unit Awards | Name | | Number of Units Acquired on Vesting (#) | | Value Realized on Vesting ($) (1) | ET Unit Awards: | | | | | Kelcy L. Warren | | — |
| | $ | — |
| Thomas E. Long | | 38,291 |
| | 556,981 |
| Marshall S. (Mackie) McCrea, III | | 295,241 |
| | 4,294,546 |
| Matthew S. Ramsey | | 88,923 |
| | 1,293,474 |
| Thomas P. Mason | | 81,949 |
| | 1,192,030 |
| John W. McReynolds | | — |
| | — |
| Sunoco LP Unit Awards: | | | | | Thomas E. Long | | 8,475 |
| | 235,859 |
| Matthew S. Ramsey | | 1,221 |
| | 38,895 |
| Thomas P. Mason | | 11,113 |
| | 309,275 |
|
| | (1) | Amounts presented represent the value realized upon vesting of these awards, which is calculated as the number of units vested multiplied by the applicable closing market price of applicable common units upon the vesting date. |
We have not issued option awards. Potential Payments Upon a Termination or Change of Control Equity Awards. As discussed in our Compensation Discussion and Analysis above, any unvested equity awards granted pursuant the ET Incentive Plans will automatically become vested upon a change of control, which is generally defined as the occurrence of one or more of the following events: (i) any person or group becomes the beneficial owner of 50% or more of the voting power or voting securities of ET or its general partner; (ii) LE GP, LLC or an affiliate of LE GP, LLC ceases to be the general partner of ET; or (iii) the sale or other disposition, including by liquidation or dissolution, of all or substantially all of the assets of ET in one or more transactions to anyone other than an affiliate of ET. In addition, as explained in Equity Awards section of our Compensation Discussion and Analysis above, the restricted unit awards and phantom unit awards under the ET Incentive Plans, the Sunoco LP Plan and the 2012 Sunoco LP Plan generally require the continued employment of the recipient during the vesting period, provided however, the unvested awards will be accelerated in the event of the death or disability of the award recipient prior to the applicable vesting period being satisfied. All awards outstanding to the named executive officers under the ET Incentive Plans, the 2018 Sunoco LP Plan or the 2012 Sunoco LP Plan would be accelerated in the event of a change in control of the Partnership. The 2014 awards to Mr. McCrea and the 2018 Special Award to Mr. Long included a provision in the applicable award agreement for acceleration of unvested restricted unit/restricted phantom unit awards upon a termination of employment by the general partner of the applicable partnership issuing the award without “cause.” For purposes of the awards the term “cause” shall mean: (i) a conviction (treating a nolo contendere plea as a conviction) of a felony (whether or not any right to appeal has been or may be
exercised), (ii) willful refusal without proper cause to perform duties (other than any such refusal resulting from incapacity due to physical or mental impairment), (iii) misappropriation, embezzlement or reckless or willful destruction of property of the partnership or any of its affiliates, (iv) knowing breach of any statutory or common law duty of loyalty to the partnership or any of its or their affiliates, (v) improper conduct materially prejudicial to the business of the partnership or any of its or their affiliates, (vi) material breach of the provisions of any agreement regarding confidential information entered into with the partnership or any of its or their affiliates or (vii) the continuing failure or refusal to satisfactorily perform essential duties to the partnership or any of its or their affiliates. In addition, the ET Compensation Committee and the compensation committee of the general partner of Sunoco LP, have approved a retirement provision, which provides that employees, including the named executive officers with at least ten years of service with the general partner, who leave the respective general partner voluntarily due to retirement (i) after age 65 but prior to age 68 are eligible for accelerated vesting of 40% of his or her award; or (ii) after 68 are eligible for accelerated vesting of 50% his or her award. The acceleration of the awards is subject to the applicable provisions of IRC Section 409(A). In February 2016, Mr. Mason received a one-time special incentive retention bonus in the amount of $6,300,000 (the “Special Bonus”). The Special Bonus was in recognition of, among other things, (i) Mr. Mason’s appointment as the Executive Vice President and General Counsel of the General Partner; (ii) his 2015 calendar year performance; and (iii) his contributions to the family of partnerships on several key initiatives, including (a) the drop-down transactions by and between ETO and Sunoco LP, (b) the proposed merger transaction between the ET and The Williams Companies, Inc., (c) the liquefied natural gas (LNG) export project of ET, and (d) the simplification of the overall Energy Transfer family structure. The approval of the Special Bonus was conditioned upon entry by Mr. Mason into a Retention Agreement (the “Retention Agreement”) which provides (i) if, prior to the third (3rd) anniversary of the effective date of the Retention Agreement, Mr. Mason’s employment terminates (other than as a result of (x) a termination without cause or by Mr. Mason for Good Reason; (y) his death; or (z) his permanent disability), he will be obligated to remit and repay one-hundred percent (100%) of the Special Bonus to ET; (ii) if, after the third (3rd) anniversary but prior to the fourth (4th) anniversary of the effective date of the Retention Agreement, Mr. Mason’s employment terminates (other than as a result of (x) a termination without cause by ET or by Mr. Mason for Good Reason; (y) his death; or (z) his permanent disability), he will be obligated to remit and repay seventy-five percent (75%) of the Special Bonus; and (iii) if, after the fourth (4th) anniversary but prior to the fifth (5th) anniversary of the effective date of the Retention Agreement, Mr. Mason’s employment terminates (other than as a result of (x) a termination without cause by ET or by Mr. Mason for Good Reason; (y) his death; or (z) his permanent disability), he will be obligated to remit and repay fifty percent (50%) of the Special Bonus. Mr. Mason entered into the Retention Agreement on February 24, 2016. Deferred Compensation Plan. As discussed in our Compensation Discussion and Analysis above, all amounts under the ET NQDC Plan (other than discretionary credits) are immediately 100% vested. Upon a change of control (as defined in the ET NQDC Plan), distributions from the respective plan would be made in accordance with the normal distribution provisions of the respective plan. A change of control is generally defined in the ET NQDC Plan as any change of control event within the meaning of Treasury Regulation Section 1.409A-3(i)(5). CEO Pay Ratio In accordance with Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, and Item 402(u) of Regulation S-K, set forth below is information about the relationship of the annual total compensation of Mr. McReynolds, who served as the Principal Executive Officer of ET prior to the Energy Transfer Merger, and the annual total compensation of our employees. The Partnership has not incurred any significant changes in the composition of its employee population, compensation programs or employee benefits and as such will continue to rely on its determination of the “median employee” and the median of the annual total compensation of the employees supporting ET, as permitted, on its 2017 CEO Pay Ratio disclosure. The determination to include only Mr. McReynolds was based on the fact that he served as ET’s Principal Executive Officer for 75% of the year and Mr. Warren, who is now ET’s Chairman and Chief Executive Officer, does not accept or receive compensation other than an amount sufficient to cover his allocated payroll deductions for health and welfare benefits. For the 2018 calendar year: The annual total compensation of Mr. McReynolds, as reported in the Summary Compensation Tables of this Item 11was $5,926; and For 2018, the median total compensation of the employees supporting ETO (other than Mr. McReynolds) was $115,908, which amount was updated from 2017 for the designated “median employee.” Based on this information, for 2017 the ratio of the annual total compensation of Mr. McReynolds to the median of the annual total compensation of the 8,494 employees supporting ETO as of December 31, 2017 was approximately 12 to 1.
To identify the median of the annual total compensation of the employees supporting ETO, the following steps were taken: | | 1. | It was determined that, as of December 31, 2017, the applicable employee populations consisted of 8,494 with all of the identified individuals being employed in the United States. This population consisted of all of our full-time and part-time employees. We did not engage any independent contractors in 2017 or 2018 that are required to be included in our employee population for the CEO pay ratio evaluation. |
| | 2. | To identify the “median employee” from our employee population, we compared the total earnings of our employees as reflected in our payroll records as reported on Form W-2 for 2017 and, for 2018, updated the compensation of the “median employee” as reflected in our payroll records as reported on Form W-2 for 2018. |
| | 3. | We identified our median employee using W-2 reporting and applied this compensation measure consistently to all of our employees required to be included in the calculation. We did not make any cost of living adjustments in identifying the “median employee”. |
| | 4. | Once we identified our median employee, we combined all elements of the employee’s compensation for 2017 resulting in an annual compensation of $115,908. The difference between such employee’s total earnings and the employee’s total compensation represents the estimated value of the employee’s health care benefits (estimated for the employee and such employee’s eligible dependents at $10,800) and the employee’s 401(k) matching contribution and profit sharing contribution (estimated at $5,846 per employee, includes $3,633 per employee on average matching contribution and $2,213 per employee on average profit sharing contribution (employees earning over $175,000 in base are ineligible for profit sharing)). |
| | 5. | With respect to Mr. McReynolds, we used the amount reported in the “Total” column of our 2017 Summary Compensation Table under this Item 11. |
Director Compensation Directors of our General Partner, who are employees of the ETP GP or any of their subsidiaries, are not eligible for director compensation. In 2018, the compensation arrangements for outside directors included a $100,000 annual retainer for services on the board. If a director served on the ET Audit Committee, such director would receive an annual retainer ($15,000 or $25,000 in the case of the chairman). If a director served on the ET Compensation Committee, such director would receive an annual cash retainer ($7,500 or $15,000 in the case of the chairman). The fees for membership on the Conflicts Committee are determined on a per instance basis for each committee assignment. The outside directors of our General Partner are also entitled to an annual award under the ET Incentive Plans equal to an aggregate of $100,000 divided by the closing price of ET common units on the date of grant. These ET common units will vest 60% after the third year and the remaining 40% after the fifth year after the grant date. The compensation expense recorded is based on the grant-date market value of the ET common units and is recognized over the vesting period. Distributions are paid during the vesting period.
The compensation paid to the non-employee directors of our General Partner in 2018 is reflected in the following table: | | | | | | | | | | | | | | | | | | Name | | Fees Paid in Cash(1) ($) | | Unit Awards(2) ($) | | All Other Compensation ($) | | Total ($) | Steven R. Anderson (3) | | | | | | | | | As ET director | | $ | 91,760 |
| | $ | 44,200 |
| | $ | — |
| | $ | 135,960 |
| Richard D. Brannon | | | | | | | | | As ET director | | 194,225 |
| | 100,000 |
| | — |
| | 294,225 |
| Ray C. Davis | | | | | | | | | As ET director | | 25,000 |
| | 42,700 |
| | — |
| | 67,700 |
| As ETO director | | 49,750 |
| | — |
| | — |
| | 49,750 |
| Michael K. Grimm (3) | | | | | | | | | As ET director | | — |
| | — |
| | — |
| | — |
| As ETO director | | 205,425 |
| | 100,068 |
| | — |
| | 305,493 |
| K. Rick Turner (4) | |
|
| |
|
| | | |
| As ET director | | 99,701 |
| | 100,000 |
| | — |
| | 199,701 |
| As Sunoco LP Director | | 46,614 |
| | 100,006 |
| | — |
| | 146,620 |
| William P. Williams (4) | | | | | | | | | As ET director | | 128,650 |
| | 100,000 |
| | — |
| | 228,650 |
|
| | (1) | Fees paid in cash are based on amounts paid during the period. |
| | (2) | Unit award amounts reflect the aggregate grant date fair value of awards granted based on the market price of ET common units, ETO common units (prior to the Merger) or Sunoco LP Common Units, accordingly, as of the grant date. |
| | (3) | Messrs. Anderson and Grimm were appointed to the Board of Directors of LE GP on June 4, 2018 and October 19, 2018, respectively. |
| | (4) | Messrs. Turner and Williams resigned from the Board of Directors of LE GP on June 1, 2018 and October 19, 2018, respectively. |
As of December 31, 2018, Mr. Anderson had 2,500 unvested ET restricted units outstanding, Mr. Brannon had 13,353 unvested ET restricted units outstanding, Mr. Davis had 2,500 unvested ET restricted units outstanding and Mr. Grimm had 20,262 unvested ET restricted units outstanding. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS Equity Compensation Plan Information The following table sets forth in tabular format, a summary of our equity plan information as of December 31, 2018: | | | | | | | | | | | | Plan Category | | Number of securities to be issued upon exercise of outstanding options, warrants and rights (a) | | Weighted-average exercise price of outstanding options, warrants and rights (b) | | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c) | Equity compensation plans approved by security holders | | — |
| | $ | — |
| | — |
| Equity compensation plans not approved by security holders: | | 22,429,859 |
| | — |
| | 15,061,559 |
| Total | | 22,429,859 |
| | $ | — |
| | 15,061,559 |
|
Energy Transfer LP Units The following table sets forth certain information as of February 15, 2019, regarding the beneficial ownership of our voting securities by (i) certain beneficial owners of more than 5% of our Common Units, (ii) each director and named executive officer of our General Partner and (iii) all current directors and executive officers of our General Partner as a group. The General Partner knows of no other person not disclosed herein who beneficially owns more than 5% of our Common Units. | | | | | | | | Name and Address of Beneficial Owner (1) | | Beneficially Owned (2) | | Percent of Class | Kelcy L. Warren (3) | | 241,479,586 |
| | 9.2 | % | Ray C. Davis (4) | | 87,891,646 |
| | 3.4 | % | John W. McReynolds (5) | | 27,270,400 |
| | 1.0 | % | Thomas E. Long | | 141,983 |
| | * |
| Marshall S. (Mackie) McCrea, III | | 1,922,870 |
| | * |
| Matthew S. Ramsey | | 148,051 |
| | * |
| Thomas P. Mason | | 607,850 |
| | * |
| Richard D. Brannon | | 188,932 |
| | * |
| Steven R. Anderson (6) | | 1,544,588 |
| | * |
| Michael K. Grimm (7) | | 96,313 |
| | * |
| All Directors and Executive Officers as a group (11 persons) | | 361,327,518 |
| | 13.8 | % |
| | (1) | The address for Mr. Davis is 5950 Sherry Lane, Dallas, Texas 75225. The address for all other listed beneficial owners is 8111 Westchester Drive, Suite 600, Dallas, Texas 75225. |
| | (2) | Beneficial ownership for the purposes of this table is defined by Rule 13d-3 under the Exchange Act of 1934. Under that rule, a person is generally considered to be the beneficial owner of a security if he has or shares the power to vote or direct the voting thereof or to dispose or direct the disposition thereof or has the right to acquire either of those powers within sixty days. The nature of beneficial ownership for all listed persons is direct with sole investment and disposition power unless otherwise noted. The beneficial ownership of each listed person is based on 2,619,391,387 Common Units outstanding in the aggregate as of February 15, 2019. |
| | (3) | Includes 98,093,962 Common Units held by Kelcy Warren Partners, L.P. and 10,244,429 Common Units held by Kelcy Warren Partners II, L.P., the general partners of which are owned by Mr. Warren. Also includes 91,585,486 Common Units held by Seven Bridges Holdings, LLC, of which Mr. Warren is a member. Also includes 328,383 Common Units attributable to the interest of Mr. Warren in ET Company Ltd and Three Dawaco, Inc., over which Mr. Warren exercises shared voting and dispositive power with Ray Davis. Also includes 601,076 Common Units held by LE GP, LLC. Mr. Warren may be deemed to own Common Units held by LE GP, LLC due to his ownership of 81.2% of its member interests. The voting and disposition of these Common Units is directly controlled by the board of directors of LE GP, LLC. Mr. Warren disclaims beneficial ownership of Common Units owned by LE GP, LLC other than to the extent of his interest in such entity. Also includes 104,166 Common Units held by Mr. Warren’s spouse. |
| | (4) | Includes 51,701 Common Units held by Avatar Holdings LLC, 1,941,721 Common Units held by Avatar BW, Ltd., 28,203,003 Common Units held by Avatar ETC Stock Holdings LLC, 3,557,757 Common Units held by Avatar Investments LP, 121,117 Common Units held by Avatar Stock Holdings, LP and 1,112,069 Common Units held by RCD Stock Holdings, LLC, all of which entities are owned or controlled by Mr. Davis. Also includes 15,987,283 Common Units held by a remainder trust for Mr. Davis’ spouse and 9,536,054 Common Units held by two trusts for the benefit of Mr. Davis’ grandchildren, for which Mr. Davis serves as trustee. Mr. Davis shares voting and dispositive power with his wife with respect to Common Units held directly. Also includes 328,383 Common Units attributable to ET Company Ltd. Mr. Davis is a former executive officer and director of ETO and is currently a director of the general partner of ET, LE GP, LLC. |
| | (5) | Includes 17,445,608 Common Units held by McReynolds Energy Partners L.P. and 12,142,593 Common Units held by McReynolds Equity Partners L.P., the general partners of which are owned by Mr. McReynolds. Mr. McReynolds disclaims beneficial ownership of Common Units owned by such limited partnerships other than to the extent of his interest in such entities. |
| | (6) | Includes 1,544,558 held by Steven R. Anderson Revocable Trust, for which Mr. Anderson serves as trustee. |
| | (7) | Includes 5,888 Units held by two trusts for the benefit of Mr. Grimm’s children, for which Mr. Grimm serves as trustee. |
In connection with the Parent Company Credit Agreement, ET and certain of its subsidiaries entered into a Pledge and Security Agreement (the “Security Agreement”) with Credit Suisse AG, Cayman Islands Branch, as collateral agent (the “Collateral Agent”). The Security Agreement secures all of ET’s obligations under the Parent Company Credit Agreement and grants to the Collateral Agent a continuing first priority lien on, and security interest in, all of ET’s and the other grantors’ tangible and intangible assets. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE As of December 31, 2018, our interests in ETO consisted of 100% of the general partner interests and 1,313,568,560 ETO common units. 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 ETO, Sunoco LP and USAC, all of which are limited partnerships engaged in diversified energy-related services, and cash flows from the operations of Lake Charles LNG. Mr. McCrea and Mr. Ramsey, current directors of LE GP, LLC, our general partner, are also directors and executive officers of ETO’s general partner. In addition, Mr. Warren, our Chief Executive Officer and Chairman of our Board of Directors, is also the Chairman and Chief Executive Officer of ETO’s general partner. For a discussion of director independence, see Item 10. “Directors, Executive Officers and Corporate Governance.” As a policy matter, our Conflicts Committee generally reviews any proposed related party transaction that may be material to the Partnership to determine whether the transaction is fair and reasonable to the Partnership. The Partnership’s board of directors makes the determinations as to whether there exists a related party transaction in the normal course of reviewing transactions for approval as the Partnership’s board of directors is advised by its management of the parties involved in each material transaction as to which the board of directors’ approval is sought by the Partnership’s management. In addition, the Partnership’s board of directors makes inquiries to independently ascertain whether related parties may have an interest in the proposed transaction. While there are no written policies or procedures for the board of directors to follow in making these determinations, the Partnership’s board makes those determinations in light of its contractually-limited fiduciary duties to the Unitholders. The partnership agreement of ET provides that any matter approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to ET, approved by all the partners of ET and not a breach by the General Partner or its Board of Directors of any duties they may owe ET or the Unitholders (see “Risks Related to Conflicts of Interest” in “Item 1A. Risk Factors” in this annual report). The Parent Company has agreements with subsidiaries to provide or receive various general and administrative services. The Parent Company pays ETO to provide services on its behalf and the behalf of other subsidiaries of the Parent Company. The Parent Company receives management fees from certain of its subsidiaries, which include the reimbursement of various general and administrative services for expenses incurred by ETO on behalf of those subsidiaries. All such amounts have been eliminated in our consolidated financial statements. ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES The following sets forth fees billed by Grant Thornton LLP for the audit of our annual financial statements and other services rendered (dollars in millions): | | | | | | | | | | Years Ended December 31, | | 2018 | | 2017 | Audit fees (1) | $ | 11.6 |
| | $ | 11.5 |
| Audit-related fees (2) | 0.5 |
| | — |
| Tax fees (3) | 0.1 |
| | — |
| Total | $ | 12.2 |
| | $ | 11.5 |
|
| | (1) | Includes fees for audits of annual financial statements of our companies, reviews of the related quarterly financial statements, and services that are normally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents filed with the SEC and services related to the audit of our internal controls over financial reporting. |
| | (1) | Includes fees in 2018 for financial statement audits of subsidiary entities in connection with contribution and sale transactions. |
| | (2) | Includes fees in 2018 related to state and local tax consultation. |
Pursuant to the charter of the Audit Committee, the Audit Committee is responsible for the oversight of our accounting, reporting and financial practices. The Audit Committee has the responsibility to select, appoint, engage, oversee, retain, evaluate and terminate our external auditors; pre-approve all audit and non-audit services to be provided, consistent with all applicable laws, to us by our external auditors; and establish the fees and other compensation to be paid to our external auditors. The Audit Committee also oversees and directs our internal auditing program and reviews our internal controls. The Audit Committee has adopted a policy for the pre-approval of audit and permitted non-audit services provided by our principal independent accountants. The policy requires that all services provided by Grant Thornton LLP including audit services, audit-related services, tax services and other services, must be pre-approved by the Audit Committee. All fees paid or expected to be paid to Grant Thornton LLP for fiscal years 2018 and 2017 were pre-approved by the Audit Committee in accordance with this policy. The Audit Committee reviews the external auditors’ proposed scope and approach as well as the performance of the external auditors. It also has direct responsibility for and sole authority to resolve any disagreements between our management and our external auditors regarding financial reporting, regularly reviews with the external auditors any problems or difficulties the auditors encountered in the course of their audit work, and, at least annually, uses its reasonable efforts to obtain and review a report from the external auditors addressing the following (among other items): the auditors’ internal quality-control procedures; any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors; the independence of the external auditors; the aggregate fees billed by our external auditors for each of the previous two years; and the rotation of the lead partner.
PART IV ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES | | | | The following documents are filed as a part of this Report: | Page | | | | | (1) Financial Statements – see Index to Financial Statements | | | | | | (2) Financial Statement Schedules – None | | | | | | (3) Exhibits – see Index to Exhibits | |
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 | | | 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 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 Form 8-K, File No. 1-32740, 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 Form 8-K, File No. 1-32740, filed January 16, 2018) | | | Agreement and Plan of Merger, dated as of August 1, 2018, by and among LE GP, LLC, Energy Transfer Equity, L.P., Streamline Merger Sub, LLC, Energy Transfer Partners, L.L.C. and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 2.1 of Form 8-K, File No. 1-32740, filed August 3, 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) |
| | | | Exhibit Number | | Description | | | 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) | | | 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.) | | | | | | Registration Rights Agreement, dated as of April 2, 2018, by and among Energy Transfer Partners, L.P., Energy Transfer Equity, L.P., USA Compression Partners, LP and USA Compression Holdings, LLC. (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed April 3, 2018) | | | | | | | | | | | | | | | | | | | | | | | | | | | | 101* | | Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Balance Sheets as of December 31, 2018 and December 31, 2017; (ii) our Consolidated Statements of Operations for the years ended December 31, 2018, 2017 and 2016; (iii) our Consolidated Statements of Comprehensive Income for years ended December 31, 2018, 2017 and 2016; (iv) our Consolidated Statement of Equity for the years ended December 31, 2018, 2017 and 2016; and (v) our Consolidated Statements of Cash Flows for the years ended December 31, 2018, 2017 and 2016 |
| | | * | 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 LP | | | | | | | By: | | LE GP, LLC, its general partner | | | | | | | | | | Date: | February 22, 2019 | By: | | /s/ A. Troy Sturrock | | | | | A. Troy Sturrock | | | | | Senior Vice President, Controller and Principal Accounting 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/ Kelcy L. Warren | | Chief Executive Officer and Chairman of the Board | | February 22, 2019 | Kelcy L. Warren | | (Principal Executive Officer) | | | | | | | | /s/ Thomas E. Long | | Chief Financial Officer | | February 22, 2019 | Thomas E. Long | | (Principal Financial Officer) | | | | | | | | /s/ John W. McReynolds | | Special Advisor and Director | | February 22, 2019 | John W. McReynolds | | | | | | | | | | /s/ Marshall S. McCrea, III | | President, Chief Commercial Officer and Director | | February 22, 2019 | Marshall S. McCrea, III | | | | | | | | | | /s/ Matthew S. Ramsey | | Chief Operating Officer and Director | | February 22, 2019 | Matthew S. Ramsey | | | | | | | | | | /s/ A. Troy Sturrock | | Senior Vice President and Controller | | February 22, 2019 | A. Troy Sturrock | | (Principal Accounting Officer) | | | | | | | | /s/ Steven R. Anderson | | Director | | February 22, 2019 | Steven R. Anderson | | | | | | | | | | /s/ Richard D. Brannon | | Director | | February 22, 2019 | Richard D. Brannon | | | | | | | | | | /s/ Ray C. Davis | | Director | | February 22, 2019 | Ray C. Davis | | | | | | | | | | /s/ Michael K. Grimm | | Director | | February 22, 2019 | Michael K. Grimm | | | | |
INDEX TO FINANCIAL STATEMENTS Energy Transfer LP and Subsidiaries
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Board of Directors of LE GP, LLC and Unitholders of Energy Transfer LP Opinion on the financial statements We have audited the accompanying consolidated balance sheets of Energy Transfer LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2018 and 2017, the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2018, 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, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, 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, 2018, 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 22, 2019 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 revenue from contracts with customers due to the adoption of the new revenue standard. The Partnership adopted the new revenue standard using the modified retrospective method. 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 22, 2019
ENERGY TRANSFER LP AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Dollars in millions) | | | | | | | | | | December 31, | | 2018 | | 2017 | ASSETS | | | | Current assets: | | | | Cash and cash equivalents | $ | 419 |
| | $ | 336 |
| Accounts receivable, net | 4,009 |
| | 4,504 |
| Accounts receivable from related companies | 111 |
| | 53 |
| Inventories | 1,677 |
| | 2,022 |
| Income taxes receivable | 73 |
| | 136 |
| Derivative assets | 111 |
| | 24 |
| Other current assets | 350 |
| | 295 |
| Current assets held for sale | — |
| | 3,313 |
| Total current assets | 6,750 |
| | 10,683 |
| | | | | Property, plant and equipment | 79,776 |
| | 71,177 |
| Accumulated depreciation and depletion | (12,813 | ) | | (10,089 | ) | | 66,963 |
| | 61,088 |
| | | | | Advances to and investments in unconsolidated affiliates | 2,642 |
| | 2,705 |
| Other non-current assets, net | 1,006 |
| | 886 |
| Intangible assets, net | 6,000 |
| | 6,116 |
| Goodwill | 4,885 |
| | 4,768 |
| Total assets | $ | 88,246 |
| | $ | 86,246 |
|
ENERGY TRANSFER LP AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Dollars in millions) | | | | | | | | | | December 31, | | 2018 | | 2017 | LIABILITIES AND EQUITY | | | | Current liabilities: | | | | Accounts payable | $ | 3,493 |
| | $ | 4,685 |
| Accounts payable to related companies | 59 |
| | 31 |
| Derivative liabilities | 185 |
| | 111 |
| Accrued and other current liabilities | 2,918 |
| | 2,582 |
| Current maturities of long-term debt | 2,655 |
| | 413 |
| Current liabilities held for sale | — |
| | 75 |
| Total current liabilities | 9,310 |
| | 7,897 |
| | | | | Long-term debt, less current maturities | 43,373 |
| | 43,671 |
| Non-current derivative liabilities | 104 |
| | 145 |
| Deferred income taxes | 2,926 |
| | 3,315 |
| Other non-current liabilities | 1,184 |
| | 1,217 |
| | | | | Commitments and contingencies |
|
| |
|
| Redeemable noncontrolling interests | 499 |
| | 21 |
| | | | | Equity: | | | | Limited Partners: | | | | Common Unitholders (2,619,368,605 and 1,079,145,561 units authorized, issued and outstanding as of December 31, 2018 and 2017, respectively) | 20,606 |
| | (1,643 | ) | Series A Convertible Preferred Units (329,295,770 units authorized, issued and outstanding as of December 31, 2017) | — |
| | 450 |
| General Partner | (5 | ) | | (3 | ) | Accumulated other comprehensive loss | (42 | ) | | — |
| Total partners’ capital (deficit) | 20,559 |
| | (1,196 | ) | Noncontrolling interest | 10,291 |
| | 31,176 |
| Total equity | 30,850 |
| | 29,980 |
| Total liabilities and equity | $ | 88,246 |
| | $ | 86,246 |
|
ENERGY TRANSFER LP AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (Dollars in millions, except per unit data) | | | | | | | | | | | | | | Years Ended December 31, | | 2018 | | 2017 | | 2016 | REVENUES: | | | | | | Refined product sales | $ | 18,345 |
| | $ | 11,975 |
| | $ | 10,097 |
| Crude sales | 14,415 |
| | 10,706 |
| | 7,205 |
| NGL sales | 9,109 |
| | 6,972 |
| | 4,841 |
| Gathering, transportation and other fees | 6,797 |
| | 4,435 |
| | 4,172 |
| Natural gas sales | 4,452 |
| | 4,172 |
| | 3,619 |
| Other | 969 |
| | 2,263 |
| | 1,858 |
| Total revenues | 54,087 |
| | 40,523 |
| | 31,792 |
| COSTS AND EXPENSES: | | | | | | Cost of products sold | 41,658 |
| | 30,966 |
| | 23,693 |
| Operating expenses | 3,089 |
| | 2,644 |
| | 2,336 |
| Depreciation, depletion and amortization | 2,859 |
| | 2,554 |
| | 2,216 |
| Selling, general and administrative | 702 |
| | 599 |
| | 656 |
| Impairment losses | 431 |
| | 1,039 |
| | 1,040 |
| Total costs and expenses | 48,739 |
| | 37,802 |
| | 29,941 |
| OPERATING INCOME | 5,348 |
| | 2,721 |
| | 1,851 |
| OTHER INCOME (EXPENSE): | | | | | | Interest expense, net | (2,055 | ) | | (1,922 | ) | | (1,804 | ) | Equity in earnings of unconsolidated affiliates | 344 |
| | 144 |
| | 270 |
| Impairment of investments in unconsolidated affiliates | — |
| | (313 | ) | | (308 | ) | Gains on acquisitions | — |
| | — |
| | 83 |
| Losses on extinguishments of debt | (112 | ) | | (89 | ) | | — |
| Gains (losses) on interest rate derivatives | 47 |
| | (37 | ) | | (12 | ) | Other, net | 62 |
| | 206 |
| | 124 |
| INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT) | 3,634 |
| | 710 |
| | 204 |
| Income tax expense (benefit) from continuing operations | 4 |
| | (1,833 | ) | | (258 | ) | INCOME FROM CONTINUING OPERATIONS | 3,630 |
| | 2,543 |
| | 462 |
| Loss from discontinued operations, net of income taxes | (265 | ) | | (177 | ) | | (462 | ) | NET INCOME | 3,365 |
| | 2,366 |
| | — |
| Less: Net income (loss) attributable to noncontrolling interest | 1,632 |
| | 1,412 |
| | (995 | ) | Less: Net income attributable to redeemable noncontrolling interest | 39 |
| | — |
| | — |
| NET INCOME ATTRIBUTABLE TO PARTNERS | 1,694 |
| | 954 |
| | 995 |
| Convertible Unitholders’ interest in net income | 33 |
| | 37 |
| | 9 |
| General Partner’s interest in net income | 3 |
| | 2 |
| | 3 |
| Limited Partners’ interest in net income | $ | 1,658 |
| | $ | 915 |
| | $ | 983 |
| INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT: | | | | | | Basic | $ | 1.17 |
| | $ | 0.86 |
| | $ | 0.95 |
| Diluted | $ | 1.16 |
| | $ | 0.84 |
| | $ | 0.93 |
| NET INCOME PER LIMITED PARTNER UNIT: | | | | | | Basic | $ | 1.16 |
| | $ | 0.85 |
| | $ | 0.94 |
| Diluted | $ | 1.15 |
| | $ | 0.83 |
| | $ | 0.92 |
|
ENERGY TRANSFER LP AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Dollars in millions) | | | | | | | | | | | | | | Years Ended December 31, | | 2018 | | 2017 | | 2016 | Net income | $ | 3,365 |
| | $ | 2,366 |
| | $ | — |
| Other comprehensive income (loss), net of tax: | | | | | | Change in value of available-for-sale securities | (4 | ) | | 6 |
| | 2 |
| Actuarial loss relating to pension and other postretirement benefits | (43 | ) | | (12 | ) | | (1 | ) | Foreign currency translation adjustment | — |
| | — |
| | (1 | ) | Change in other comprehensive income from unconsolidated affiliates | 4 |
| | 1 |
| | 4 |
| | (43 | ) | | (5 | ) | | 4 |
| Comprehensive income | 3,322 |
| | 2,361 |
| | 4 |
| Less: Comprehensive income (loss) attributable to noncontrolling interest | 1,632 |
| | 1,407 |
| | (991 | ) | Less: Comprehensive income attributable to redeemable noncontrolling interest | 39 |
| | — |
| | — |
| Comprehensive income attributable to partners | $ | 1,651 |
| | $ | 954 |
| | $ | 995 |
|
ENERGY TRANSFER LP AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF EQUITY (Dollars in millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Series A Convertible Preferred Units | | Class D Units | | Common Unitholders | | General Partner | | Accumulated Other Comprehensive Loss | | Non- controlling Interest | | Total | Balance, December 31, 2015 | $ | — |
| | $ | 22 |
| | $ | (952 | ) | | $ | (2 | ) | | $ | — |
| | $ | 24,485 |
| | $ | 23,553 |
| Distributions to partners | — |
| | — |
| | (1,019 | ) | | (3 | ) | | — |
| | — |
| | (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 | (2 | ) | |
|
| | 39 |
| | — |
| | — |
| | — |
| | 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 | — |
| | — |
| | 30 |
| | (1 | ) | | — |
| | 14 |
| | 43 |
| Net income (loss) | 9 |
| | — |
| | 983 |
| | 3 |
| | — |
| | (995 | ) | | — |
| Balance, December 31, 2016 | $ | 180 |
| | $ | — |
| | $ | (1,871 | ) | | $ | (3 | ) | | $ | — |
| | $ | 24,125 |
| | $ | 22,431 |
| Distributions to partners | — |
| | — |
| | (1,008 | ) | | (2 | ) | | — |
| | — |
| | (1,010 | ) | Distributions to noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | (2,999 | ) | | (2,999 | ) | Distributions reinvested | 234 |
| | — |
| | (234 | ) | | — |
| | — |
| | — |
| | — |
| Units issuance | — |
| | — |
| | 568 |
| | — |
| | — |
| | — |
| | 568 |
| Subsidiary units issued for cash | (1 | ) | | — |
| | (55 | ) | | — |
| | — |
| | 3,291 |
| | 3,235 |
| Non-cash 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 | ) | 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 | 37 |
| | — |
| | 915 |
| | 2 |
| | — |
| | 1,412 |
| | 2,366 |
| Balance, December 31, 2017 | $ | 450 |
| | $ | — |
| | $ | (1,643 | ) | | $ | (3 | ) | | $ | — |
| | $ | 31,176 |
| | $ | 29,980 |
| Distributions to partners | — |
| | — |
| | (1,681 | ) | | (3 | ) | | — |
| | — |
| | (1,684 | ) | Distributions to noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | (3,117 | ) | | (3,117 | ) | Distributions reinvested | 115 |
| | — |
| | (115 | ) | | — |
| | — |
| |
|
| | — |
| Subsidiary units repurchased | (7 | ) | | — |
| | (119 | ) | | — |
| | — |
| | 102 |
| | (24 | ) | Subsidiary units issued | — |
| | — |
| | 1 |
| | — |
| | — |
| | 923 |
| | 924 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | Energy Transfer Merger | — |
| | — |
| | 21,869 |
| | — |
| | — |
| | (21,869 | ) | | — |
| Capital contributions received from noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | 649 |
| | 649 |
| Other comprehensive loss, net of tax | — |
| | — |
| | — |
| | — |
| | (43 | ) | | — |
| | (43 | ) | Cumulative effect adjustment due to change in accounting principle (see Note 2) | — |
| | — |
| | — |
| | — |
| | — |
| | (54 | ) | | (54 | ) | Acquisition of USAC NCI | — |
| | — |
| | — |
| | — |
| | — |
| | 832 |
| | 832 |
| ET Series A Convertible Preferred Units conversion | (589 | ) | | — |
| | 589 |
| | — |
| | — |
| | — |
| | — |
| Other, net | (2 | ) | | — |
| | 47 |
| | (2 | ) | | 1 |
| | 17 |
| | 61 |
| Net income, excluding amounts attributable to redeemable noncontrolling interests | 33 |
| | — |
| | 1,658 |
| | 3 |
| | — |
| | 1,632 |
| | 3,326 |
| Balance, December 31, 2018 | $ | — |
| | $ | — |
| | $ | 20,606 |
| | $ | (5 | ) | | $ | (42 | ) | | $ | 10,291 |
| | $ | 30,850 |
|
ENERGY TRANSFER LP AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in millions) | | | | | | | | | | | | | | Years Ended December 31, | | 2018 | | 2017 | | 2016 | OPERATING ACTIVITIES: | | | | | | Net income | $ | 3,365 |
| | $ | 2,366 |
| | $ | — |
| Reconciliation of net income to net cash provided by operating activities: | | | | | | Loss from discontinued operations | 265 |
| | 177 |
| | 462 |
| Depreciation, depletion and amortization | 2,859 |
| | 2,554 |
| | 2,216 |
| Deferred income taxes | (7 | ) | | (1,871 | ) | | (177 | ) | Inventory valuation adjustments | 85 |
| | (24 | ) | | (97 | ) | Non-cash compensation expense | 105 |
| | 99 |
| | 70 |
| Impairment losses | 431 |
| | 1,039 |
| | 1,040 |
| Impairment of investments in unconsolidated affiliates | — |
| | 313 |
| | 308 |
| Gains on acquisitions | — |
| | — |
| | (83 | ) | Losses on extinguishments of debt | 112 |
| | 89 |
| | — |
| Distributions on unvested awards | (38 | ) | | (35 | ) | | (29 | ) | Distributions from unconsolidated affiliates | 328 |
| | 297 |
| | 268 |
| Equity in earnings of unconsolidated affiliates | (344 | ) | | (144 | ) | | (270 | ) | Other non-cash | 56 |
| | (239 | ) | | (207 | ) | Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | 289 |
| | (192 | ) | | (179 | ) | Net cash provided by operating activities | 7,506 |
| | 4,429 |
| | 3,322 |
| INVESTING ACTIVITIES: | | | | | | Cash received in USAC acquisition, net of cash paid | 461 |
| | — |
| | — |
| 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 | ) | | — |
| Cash paid for Vitol Acquisition, net of cash received | — |
| | — |
| | (769 | ) | Cash paid for PennTex Acquisition, net of cash received | — |
| | — |
| | (299 | ) | Cash paid for acquisitions, net of cash received | (429 | ) | | (303 | ) | | (330 | ) | Capital expenditures, excluding allowance for equity funds used during construction | (7,407 | ) | | (8,444 | ) | | (7,771 | ) | Contributions in aid of construction costs | 109 |
| | 31 |
| | 71 |
| Contributions to unconsolidated affiliates | (26 | ) | | (268 | ) | | (68 | ) | Distributions from unconsolidated affiliates in excess of cumulative earnings | 69 |
| | 135 |
| | 135 |
| Proceeds from the sale of other assets | 87 |
| | 48 |
| | 35 |
| Change in restricted cash | — |
| | — |
| | 14 |
| Other | 61 |
| | (3 | ) | | — |
| Net cash used in investing activities | (7,075 | ) | | (5,606 | ) | | (8,982 | ) | FINANCING ACTIVITIES: | | | | | | Proceeds from borrowings | 29,001 |
| | 31,608 |
| | 25,785 |
| Repayments of long-term debt | (28,948 | ) | | (31,268 | ) | | (19,076 | ) | Cash (paid) received on affiliate notes | — |
| | (255 | ) | | 266 |
| Units issued for cash | — |
| | 568 |
| | — |
| Subsidiary units issued for cash | 1,402 |
| | 3,235 |
| | 2,559 |
|
| | | | | | | | | | | | | Capital contributions from noncontrolling interest | 649 |
| | 1,214 |
| | 236 |
| Distributions to partners | (1,684 | ) | | (1,010 | ) | | (1,022 | ) | Distributions to noncontrolling interests | (3,117 | ) | | (2,961 | ) | | (2,766 | ) | Distributions to redeemable noncontrolling interest | (24 | ) | | — |
| | — |
| Subsidiary units repurchased | (24 | ) | | — |
| | — |
| Redemption of preferred units | — |
| | (53 | ) | | — |
| Debt issuance costs | (171 | ) | | (131 | ) | | (52 | ) | Other, net | (166 | ) | | 6 |
| | (3 | ) | Net cash (used in) provided by financing activities | (3,082 | ) | | 953 |
| | 5,927 |
| DISCONTINUED OPERATIONS | | | | | | Operating activities | (484 | ) | | 136 |
| | 93 |
| Investing activities | 3,207 |
| | (38 | ) | | (483 | ) | Changes in cash included in current assets held for sale | 11 |
| | (5 | ) | | 5 |
| Net increase (decrease) in cash and cash equivalents of discontinued operations | 2,734 |
| | 93 |
| | (385 | ) | Increase (decrease) in cash and cash equivalents | 83 |
| | (131 | ) | | (118 | ) | Cash and cash equivalents, beginning of period | 336 |
| | 467 |
| | 585 |
| Cash and cash equivalents, end of period | $ | 419 |
| | $ | 336 |
| | $ | 467 |
|
ENERGY TRANSFER LP 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 LP and its subsidiaries (the “Partnership,” “we,” “us,” “our” or “ET”). References to the “Parent Company” mean Energy Transfer LP on a stand-alone basis. In October 2018, we completed the merger of ETO with a wholly-owned subsidiary of ET in a unit-for-unit exchange (the “Energy Transfer Merger”). In connection with the transaction, ETO unitholders (other than ET and its subsidiaries) received 1.28 common units of ET for each common unit of ETO they owned. Immediately prior to the closing of the Energy Transfer Merger, the following also occurred: the IDRs in Energy Transfer Partners, L.P. were converted into 1,168,205,710 Energy Transfer Partners, L.P. common units; and the general partner interest in ETO was converted to a non-economic general partner interest and Energy Transfer Partners, L.P. issued 18,448,341 Energy Transfer Partners, L.P. common units to ETP GP. Following the closing of the Energy Transfer Merger, Energy Transfer Equity, L.P. changed its name to “Energy Transfer LP” and its common units began trading on the New York Stock Exchange under the “ET” ticker symbol on Friday, October 19, 2018. In addition, Energy Transfer Partners, L.P. changed its name to “Energy Transfer Operating, L.P.” For purposes of maintaining clarity, the following references are used herein: References to “ETO” refer to the entity named Energy Transfer Partners, L.P. prior to the close of the Energy Transfer Merger and Energy Transfer Operating, L.P. subsequent to the close of the Energy Transfer Merger; and References to “ET” refer to the entity named Energy Transfer Equity, L.P. prior to the close of the Energy Transfer Merger and Energy Transfer LP subsequent to the close of the Energy Transfer Merger. In April 2017, Energy Transfer Partners, L.P. and Sunoco Logistics completed the previously announced merger transaction in which Sunoco Logistics acquired Energy Transfer Partners, L.P. in a unit-for-unit transaction (the “Sunoco Logistics Merger”). Under the terms of the transaction, Energy Transfer Partners, L.P. unitholders received 1.5 common units of Sunoco Logistics for each common unit of Energy Transfer Partners, L.P. 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 ET. In connection with the merger, the Energy Transfer Partners, L.P. Class H units were cancelled. The outstanding Energy Transfer Partners, L.P. 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 Energy Transfer Partners, L.P. 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 Energy Transfer Partners, L.P. at the effective time of the merger were cancelled. In connection with the Sunoco Logistics Merger, Sunoco Logistics Partners L.P. changed its name to “Energy Transfer Partners, L.P.” References to “Sunoco Logistics” refer to the entity named Sunoco Logistics Partners L.P. prior to the close of the Sunoco Logistics Merger. Subsequent to the Energy Transfer Merger, substantially all of the Partnership’s cash flows are derived from distributions related to its investment in ETO, whose cash flows are derived from its subsidiaries, including ETO’s investments in Sunoco LP and USAC. 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 ET’s subsidiaries. In order to understand the financial condition of the Parent Company on a stand-alone basis, see Note 18 for stand-alone financial information apart from that of the consolidated partnership information included herein. 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;
•NGL and refined products transportation and services; •crude oil transportation and services; •investment in Sunoco LP; •investment in USAC; and •corporate and other, including the following: activities of the Parent Company; and certain operations and investments that are not separately reflected as reportable segments. 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 owns and operates intrastate natural gas pipeline systems and storage facilities 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 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. The Partnership owns a controlling interest in Sunoco LP which 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. As of December 31, 2018, our interest in Sunoco LP consisted of 100% of the general partner and IDRs, as well as 28.5 million common units. The Partnership owns a controlling interest in USAC which provides compression services to producers, processors, gatherers and transporters of natural gas and crude oil. As of December 31, 2018, our interest in USAC consisted of 39.7 million common units and 6.4 million Class B units. Basis of Presentation. The consolidated financial statements of Energy Transfer LP presented herein for the years ended December 31, 2018, 2017 and 2016, 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. The consolidated financial statements of ET presented herein include the results of operations of: the Parent Company; our controlled subsidiary, Energy Transfer Operating, L.P. (“ETO”); Energy Transfer Partners GP, L.P. (“ETP GP”), the general partner of ETO, and Energy Transfer Partners, L.L.C. (“ETP LLC”), the general partner of ETP GP. 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. For prior periods herein, certain balances have been reclassified to assets and liabilities held for sale and certain revenues and expenses to discontinued operations. These reclassifications had no impact on net income or total equity.
| | 2. | ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL: |
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. Revenue Recognition 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. Upon the adoption of ASU 2014-09, the amount of revenue that the Partnership recognizes on certain contracts has changed, primarily due to decreases in revenue (with offsetting decreases to cost of sales) resulting from recognition of non-cash consideration as revenue when received and as cost of sales when sold to third parties. In addition, income statement reclassifications were required for fuel usage and loss allowances related to multiple segments as well as contracts deemed to be in-substance supply agreements in our midstream segment. In addition to the evaluation performed, we have made appropriate design and implementation updates to our business processes, systems and internal controls to support recognition and disclosure under the new standard. Utilizing the practical expedients allowed under the modified retrospective adoption method, Accounting Standards Codification (“ASC”) Topic 606 was only applied to existing contracts for which the Partnership has remaining performance obligations as of January 1, 2018, and new contracts entered into after January 1, 2018. ASC Topic 606 was not applied to contracts that were completed prior to January 1, 2018. The Partnership has elected to apply the modified retrospective method to adopt the new standard. For contracts in scope of the new revenue standard as of January 1, 2018, the cumulative effect adjustment to partners’ capital was not material. The comparative information has not been restated under the modified retrospective method and continues to be reported under the accounting standards in effect for those periods. For contracts in scope of the new revenue standard as of January 1, 2018, the Partnership recognized a cumulative effect adjustment to retained earnings to account for the differences in timing of revenue recognition. The comparative information has not been restated under the modified retrospective method and continues to be reported under the accounting standards in effect for those periods. The adjustments to the opening balance sheet primarily relate to a change in timing of revenue recognition for variable consideration at Sunoco LP, such as incentives paid to customers, as well as a change in timing of revenue recognition for franchise fee revenue. Historically, an asset was recognized related to the contract incentives which was amortized over the life of the agreement. Under the new standard, the timing of the recognition of incentives changed due to application of the expected value method to estimate variable consideration. Additionally, under the new standard the change in timing of franchise fee revenue is due to the treatment of revenue recognition from the symbolic license over the term of the agreement.
The cumulative effect of the changes made to the Partnership’s consolidated balance sheet for the adoption of ASU 2014-09 was as follows: | | | | | | | | | | | | | | Balance at December 31, 2017 | | Adjustments due to ASC 606 | | Balance at January 1, 2018 | Assets: | | | | | | Other current assets | $ | 295 |
| | $ | 8 |
| | $ | 303 |
| Property, plant and equipment, net | 61,088 |
| | — |
| | 61,088 |
| Intangible assets, net | 6,116 |
| | (100 | ) | | 6,016 |
| Other non-current assets, net | 886 |
| | 39 |
| | 925 |
| | | | | | | Liabilities and Equity: | | | | | | Other non-current liabilities | $ | 1,217 |
| | $ | 1 |
| | $ | 1,218 |
| Noncontrolling interest | 31,176 |
| | (54 | ) | | 31,122 |
|
The adoption of the new revenue standard resulted in reclassifications between revenue, cost of sales and operating expenses. Additionally, changes in timing of revenue recognition have required the creation of contract asset or contract liability balances, as well as certain balance sheet reclassifications. In accordance with the requirements of ASC Topic 606, the disclosure below shows the impact of adopting the new standard on the consolidated statement of operations and the consolidated balance sheet. | | | | | | | | | | | | | | Year Ended December 31, 2018 | | As Reported | | Balances Without Adoption of ASC 606 | | Effect of Change: Higher/(Lower) | Revenues: | | | | | | Natural gas sales | $ | 4,452 |
| | $ | 4,452 |
| | $ | — |
| NGL sales | 9,109 |
| | 9,071 |
| | 38 |
| Crude sales | 14,415 |
| | 14,403 |
| | 12 |
| Gathering, transportation and other fees | 6,797 |
| | 7,526 |
| | (729 | ) | Refined product sales | 18,345 |
| | 18,393 |
| | (48 | ) | Other | 969 |
| | 968 |
| | 1 |
| | | | | | | Costs and expenses: | | | | | | Cost of products sold | $ | 41,658 |
| | $ | 42,389 |
| | $ | (731 | ) | Operating expenses | 3,089 |
| | 3,045 |
| | 44 |
| Depreciation and amortization | 2,859 |
| | 2,888 |
| | (29 | ) |
| | | | | | | | | | | | | | Year Ended December 31, 2018 | | As Reported | | Balances Without Adoption of ASC 606 | | Effect of Change: Higher/(Lower) | Assets: | | | | | | Other current assets | $ | 350 |
| | $ | 338 |
| | $ | 12 |
| Property, plant and equipment, net | 66,963 |
| | 66,963 |
| | — |
| Other non-current assets, net | 1,006 |
| | 947 |
| | 59 |
| Intangible assets, net | 6,000 |
| | 6,134 |
| | (134 | ) | | | | | | | Liabilities and Equity: | | | | | | Other non-current liabilities | $ | 1,184 |
| | $ | 1,183 |
| | $ | 1 |
| Noncontrolling interest | 10,291 |
| | 10,355 |
| | (64 | ) |
Additional disclosures related to revenue recognition are included in Note 12. 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, dispositions and deconsolidation) included in cash flows from operating activities was comprised as follows: | | | | | | | | | | | | | | Years Ended December 31, | | 2018 | | 2017 | | 2016 | Accounts receivable | $ | 541 |
| | $ | (948 | ) | | $ | (1,126 | ) | Accounts receivable from related companies | 162 |
| | 24 |
| | 42 |
| Inventories | 282 |
| | 58 |
| | (480 | ) | Other current assets | 7 |
| | 38 |
| | 165 |
| Other non-current assets, net | (92 | ) | | 84 |
| | (148 | ) | Accounts payable | (766 | ) | | 712 |
| | 1,170 |
| Accounts payable to related companies | (202 | ) | | (178 | ) | | (64 | ) | Accrued and other current liabilities | 382 |
| | (97 | ) | | 89 |
| Other non-current liabilities | 28 |
| | 106 |
| | 106 |
| Derivative assets and liabilities, net | (53 | ) | | 9 |
| | 67 |
| Net change in operating assets and liabilities, net of effects of acquisitions | $ | 289 |
| | $ | (192 | ) | | $ | (179 | ) |
Non-cash investing and financing activities and supplemental cash flow information were as follows: | | | | | | | | | | | | | | Years Ended December 31, | | 2018 | | 2017 | | 2016 | NON-CASH INVESTING ACTIVITIES: | | | | | | Accrued capital expenditures | $ | 1,030 |
| | $ | 1,060 |
| | $ | 848 |
| Net gains (losses) from subsidiary common unit transactions | (126 | ) | | (56 | ) | | 16 |
| NON-CASH FINANCING ACTIVITIES: | | | | | | Issuance of Common Units in connection with the PennTex Acquisition | $ | — |
| | $ | — |
| | $ | 307 |
| Contribution of assets from noncontrolling interest | — |
| | 988 |
| | — |
| SUPPLEMENTAL CASH FLOW INFORMATION: | | | | | | Cash paid for interest, net of interest capitalized | $ | 1,870 |
| | $ | 1,914 |
| | $ | 1,922 |
| Cash paid for (refund of) income taxes | 508 |
| | 50 |
| | (229 | ) |
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 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, | | 2018 | | 2017 | Natural gas, NGLs and refined products (1) | $ | 833 |
| | $ | 1,120 |
| Crude oil | 506 |
| | 551 |
| Spare parts and other | 338 |
| | 351 |
| Total inventories | $ | 1,677 |
| | $ | 2,022 |
|
| | (1) | Due to changes in fuel prices, Sunoco LP recorded a write-down on the value of its fuel inventory of $85 million as of December 31, 2018. |
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, | | 2018 | | 2017 | Deposits paid to vendors | $ | 141 |
| | $ | 64 |
| Prepaid expenses and other | 209 |
| | 231 |
| Total other current assets | $ | 350 |
| | $ | 295 |
|
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 2018, USAC recognized a $9 million fixed asset impairment related to certain idle compressor assets. 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 its 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 its midstream segment.
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, | | 2018 | | 2017 | Land and improvements | $ | 2,146 |
| | $ | 2,222 |
| Buildings and improvements (1 to 45 years) | 2,664 |
| | 2,786 |
| Pipelines and equipment (5 to 83 years) | 57,584 |
| | 44,673 |
| Natural gas and NGL storage facilities (5 to 46 years) | 1,898 |
| | 1,681 |
| Bulk storage, equipment and facilities (2 to 83 years) | 3,395 |
| | 3,036 |
| Tanks and other equipment (5 to 40 years) | 884 |
| | 847 |
| Vehicles (1 to 25 years) | 123 |
| | 126 |
| Right of way (20 to 83 years) | 3,555 |
| | 3,432 |
| Natural resources | 434 |
| | 434 |
| Other (1 to 40 years) | 1,026 |
| | 1,029 |
| Construction work-in-process | 6,067 |
| | 10,911 |
| | 79,776 |
| | 71,177 |
| Less – Accumulated depreciation and depletion | (12,813 | ) | | (10,089 | ) | Property, plant and equipment, net | $ | 66,963 |
| | $ | 61,088 |
|
We recognized the following amounts for the periods presented: | | | | | | | | | | | | | | Years Ended December 31, | | 2018 | | 2017 | | 2016 | Depreciation, depletion and amortization expense | $ | 2,538 |
| | $ | 2,204 |
| | $ | 1,952 |
| Capitalized interest | 294 |
| | 286 |
| | 201 |
|
Advances to and Investments in 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, | | 2018 | | 2017 | Regulatory assets | 43 |
| | 85 |
| Deferred charges | 241 |
| | 210 |
| Restricted funds | 178 |
| | 192 |
| Other | 544 |
| | 399 |
| Total other non-current assets, net | $ | 1,006 |
| | $ | 886 |
|
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, 2018 | | December 31, 2017 | | Gross Carrying Amount | | Accumulated Amortization | | Gross Carrying Amount | | Accumulated Amortization | Amortizable intangible assets: | | | | | | | | Customer relationships, contracts and agreements (3 to 46 years) | $ | 7,106 |
| | $ | (1,493 | ) | | $ | 6,979 |
| | $ | (1,277 | ) | Patents (10 years) | 48 |
| | (30 | ) | | 48 |
| | (26 | ) | Trade names (20 years) | 66 |
| | (28 | ) | | 66 |
| | (25 | ) | Other (5 to 20 years) | 33 |
| | (9 | ) | | 28 |
| | (14 | ) | Total amortizable intangible assets | 7,253 |
| | (1,560 | ) | | 7,121 |
| | (1,342 | ) | Non-amortizable intangible assets: | | | | | | | | Trademarks | 295 |
| | — |
| | 295 |
| | — |
| Other | 12 |
| | — |
| | 42 |
| | — |
| Total non-amortizable intangible assets | 307 |
| | — |
| | 337 |
| | — |
| Total intangible assets | $ | 7,560 |
| | $ | (1,560 | ) | | $ | 7,458 |
| | $ | (1,342 | ) |
Aggregate amortization expense of intangibles assets was as follows: | | | | | | | | | | | | | | Years Ended December 31, | | 2018 | | 2017 | | 2016 | Reported in depreciation, depletion and amortization expense | $ | 321 |
| | $ | 344 |
| | $ | 264 |
|
Estimated aggregate amortization expense of intangible assets for the next five years was as follows: | | | | | Years Ending December 31: | | 2019 | $ | 346 |
| 2020 | 345 |
| 2021 | 342 |
| 2022 | 325 |
| 2023 | 319 |
|
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 its indefinite-lived intangible assets during the fourth quarter of 2018 and recognized a $30 million impairment charge on its contractual rights, included in other in the table above, primarily due to decreases in projected future revenues and cash flows from the date the intangible asset was originally recorded. Sunoco LP performed impairment tests on its 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 in the table above, primarily due to decreases in projected future revenues and cash flows from the date the intangible asset was originally recorded.
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 | | Investment in Sunoco LP | | Investment in USAC | | All Other | | Total | Balance, December 31, 2016 | $ | 10 |
| | $ | 458 |
| | $ | 863 |
| | $ | 772 |
| | $ | 1,163 |
| | $ | 1,550 |
| | $ | — |
| | $ | 854 |
| | $ | 5,670 |
| Acquired | — |
| | — |
| | 8 |
| | — |
| | 4 |
| | — |
| | — |
| | — |
| | 12 |
| Impaired | — |
| | (262 | ) | | — |
| | (79 | ) | | — |
| | (102 | ) | | — |
| | (452 | ) | | (895 | ) | Other | — |
| | — |
| | (1 | ) | | — |
| | — |
| | (18 | ) | | — |
| | — |
| | (19 | ) | Balance, December 31, 2017 | 10 |
| | 196 |
| | 870 |
| | 693 |
| | 1,167 |
| | 1,430 |
| | — |
| | 402 |
| | 4,768 |
| Acquired | — |
| | — |
| | — |
| | — |
| | — |
| | 129 |
| | 366 |
| | — |
| | 495 |
| CDM Contribution | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 253 |
| | (253 | ) | | — |
| Impaired | — |
| | — |
| | (378 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (378 | ) | Other | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Balance, December 31, 2018 | $ | 10 |
| | $ | 196 |
| | $ | 492 |
| | $ | 693 |
| | $ | 1,167 |
| | $ | 1,559 |
| | $ | 619 |
| | $ | 149 |
| | $ | 4,885 |
|
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. As of December 31, 2018, ETO’s ETC Marketing reporting unit, to which $72 million of goodwill is allocated, had a negative carrying amount. The reporting unit is in the all other segment. During the fourth quarter of 2018, the Partnership recognized goodwill impairments of $378 million related to our Northeast operations within the midstream segment primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded. These changes in assumptions reflect delays in the construction of third-party takeaway capacity in the Northeast. During the fourth quarter of 2017, the Partnership 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. Sunoco LP recognized goodwill impairments of $387 million, of which $102 million was allocated to continuing operations,primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded. During the fourth quarter of 2016, the Partnership recognized goodwill impairments of $638 million in 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. 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. 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, 2018 and 2017, 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 AROs 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 AROs related to Sunoco, Inc.’s pipeline assets and storage tanks, for which it is not possible to estimate whether or when the AROs will be settled. Consequently, these AROs cannot be measured at this time. Sunoco LP has AROs related to the estimated future cost to remove underground storage tanks. As of December 31, 2018 and 2017, other non-current liabilities in the Partnership’s consolidated balance sheets included AROs of $193 million and $220 million, respectively. For the years ended December 31, 2018, 2017 and 2016 aggregate accretion expense related to AROs was $13 million, $9 million and $7 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 $106 million and $103 million and were reflected as property, plant and equipment on our consolidated balance sheet as of December 31, 2018 and 2017, respectively. In addition, other non-current assets on the Partnership’s consolidated balance sheet included $26 million and $21 million of legally restricted funds for the purpose of settling AROs as of December 31, 2018 and 2017, respectively.
Accrued and Other Current Liabilities Accrued and other current liabilities consisted of the following: | | | | | | | | | | December 31, | | 2018 | | 2017 | Interest payable | $ | 571 |
| | $ | 552 |
| Customer advances and deposits | 128 |
| | 59 |
| Accrued capital expenditures | 1,030 |
| | 1,006 |
| Accrued wages and benefits | 283 |
| | 280 |
| Taxes payable other than income taxes | 256 |
| | 288 |
| Exchanges payable | 112 |
| | 154 |
| Other | 538 |
| | 243 |
| Total accrued and other current liabilities | $ | 2,918 |
| | $ | 2,582 |
|
Deposits or advances are received from customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may be required when customers exceed their credit limits or do not qualify for open credit. Redeemable Noncontrolling Interests Our redeemable noncontrolling interests relate to certain preferred unitholders of one of our consolidated subsidiaries that have the option to convert their preferred units to such subsidiary’s common units at the election of the holders and the noncontrolling interest holders in one of our consolidated subsidiaries that have the option to sell their interests to us. In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable noncontrolling interests on our consolidated balance sheet. See Note 7 for further information. Environmental Remediation We accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in the range is accrued. Fair Value of Financial Instruments The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our consolidated debt obligations as of December 31, 2018 was $45.06 billion and $46.03 billion, respectively. As of December 31, 2017, the aggregate fair value and carrying amount of our consolidated debt obligations was $45.62 billion and $44.08 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, 2018 and 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, 2018 and 2017 based on inputs used to derive their fair values: | | | | | | | | | | | | | | Fair Value Total | | Fair Value Measurements at December 31, 2018 | | Level 1 | | Level 2 | Assets: | | | | | | Commodity derivatives: | | | | | | Natural Gas: | | | | | | Basis Swaps IFERC/NYMEX | $ | 42 |
| | $ | 42 |
| | $ | — |
| Swing Swaps IFERC | 52 |
| | 8 |
| | 44 |
| Fixed Swaps/Futures | 97 |
| | 97 |
| | — |
| Forward Physical Contracts | 20 |
| | — |
| | 20 |
| Power: | | | | | | Forwards | 48 |
| | — |
| | 48 |
| Futures | 1 |
| | 1 |
| | — |
| Options – Calls | 1 |
| | 1 |
| | — |
| NGLs – Forwards/Swaps | 291 |
| | 291 |
| | — |
| Refined Products – Futures | 7 |
| | 7 |
| | — |
| Crude – Forwards/Swaps | 1 |
| | 1 |
| | — |
| Total commodity derivatives | 560 |
| | 448 |
| | 112 |
| Other non-current assets | 26 |
| | 17 |
| | 9 |
| Total assets | $ | 586 |
| | $ | 465 |
| | $ | 121 |
| Liabilities: | | | | | | Interest rate derivatives | $ | (163 | ) | | $ | — |
| | $ | (163 | ) | Commodity derivatives: | | | | | | Natural Gas: | | | | | | Basis Swaps IFERC/NYMEX | (91 | ) | | (91 | ) | | — |
| Swing Swaps IFERC | (40 | ) | | — |
| | (40 | ) | Fixed Swaps/Futures | (88 | ) | | (88 | ) | | — |
| Forward Physical Contracts | (21 | ) | | — |
| | (21 | ) | Power: | | | | | | Forwards | (42 | ) | | — |
| | (42 | ) | Futures | (1 | ) | | (1 | ) | | — |
| NGLs – Forwards/Swaps | (224 | ) | | (224 | ) | | — |
| Refined Products – Futures | (15 | ) | | (15 | ) | | — |
| Crude – Forwards/Swaps | (61 | ) | | (61 | ) | | — |
| Total commodity derivatives | (583 | ) | | (480 | ) | | (103 | ) | Total liabilities | $ | (746 | ) | | $ | (480 | ) | | $ | (266 | ) |
| | | | | | | | | | | | | | 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 Contracts | 8 |
| | — |
| | 8 |
| Power – Forwards | 23 |
| | — |
| | 23 |
| NGLs – Forwards/Swaps | 191 |
| | 191 |
| | — |
| Refined Products – Futures | 1 |
| | 1 |
| | — |
| Crude: | | | | | | Forwards/Swaps | 2 |
| | 2 |
| | — |
| 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 Contracts | (2 | ) | | — |
| | (2 | ) | Power – Forwards | (22 | ) | | — |
| | (22 | ) | NGLs – Forwards/Swaps | (186 | ) | | (186 | ) | | — |
| Refined Products – Futures | (28 | ) | | (28 | ) | | — |
| Crude: | | | | | | Forwards/Swaps | (6 | ) | | (6 | ) | | — |
| Futures | (1 | ) | | (1 | ) | | — |
| Total commodity derivatives | (341 | ) | | (303 | ) | | (38 | ) | Total liabilities | $ | (560 | ) | | $ | (303 | ) | | $ | (257 | ) |
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 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. Excise taxes collected by Sunoco LP’s retail locations where Sunoco LP holds the inventory were $370 million, $234 million and $243 million for the years ended December 31, 2018, 2017 and 2016, 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 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 ET 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 Internal Revenue Service (“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, ET would be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2018, 2017 and 2016, 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, Sunoco Property Company LLC and Aloha Petroleum. 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. Non-Cash 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. In 2018, the Company adopted Accounting Standards Update No. 2017-07 Compensation - Retirement Benefits (Topic 715) retrospectively. It requires the service cost component to be presented with other current compensation costs for the related employees in the operating section of our consolidated statements of operations, with other components of net benefit cost presented outside of the operating income. 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. Recent Accounting Pronouncements 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 information about the amount, timing, and uncertainty of cash flows arising from a lease. The update requires lessees to record virtually all leases on their balance sheets. For lessors, this amended guidance modifies the classification criteria and the accounting for sales-type and direct financing leases. In
January 2018, the FASB issued Accounting Standards Update No. 2018-01 (“ASU 2018-01”), which provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the existing lease guidance. The Partnership plans to elect the package of transition practical expedients and will adopt this standard beginning with its first quarter of fiscal 2019 and apply it retrospectively at the beginning of the period of adoption through a cumulative-effect adjustment to retained earnings. The Partnership has performed several procedures to evaluate the impact of the adoption of this standard on the financial statements and disclosures and address the implications of Topic 842 on future lease arrangements. The procedures include reviewing all forms of leases, performing a completeness assessment over the lease population, establishing processes and controls to timely identify new and modified lease agreements, educating its employees on these new processes and controls and implementing a third-party supported lease accounting information system to account for our leases in accordance with the new standard. The Partnership is finalizing its evaluation of the impacts that the adoption of this accounting guidance will have on the consolidated financial statements, and estimates approximately $1.0 billion of right-to-use assets and lease liabilities will be recognized in the consolidated balance sheet upon adoption, with no material impact to its consolidated statements of operations. ASU 2017-12 In August 2017, the FASB issued Accounting Standards Update No. 2017-12, Derivatives and Hedging (Topic 815): TargetedImprovements 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 expects to adopt the new rules in the first quarter of 2019 and does not expect the adoption of the new accounting rules to have a material impact on the consolidated financial statements and related disclosures. ASU 2018-02 In February 2018, the FASB issued Accounting Standards Update No. 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, which allows a reclassification from accumulated other comprehensive income to partners’ capital for stranded tax effects resulting from the Tax Cuts and Jobs Act of 2017. The Partnership elected to early adopt this ASU in the first quarter of 2018. The effect of the adoption was not material. | | 3. | ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS: |
2018 Transactions ET Contribution of Assets to ETO Immediately prior to the closing of the Energy Transfer Merger discussed in Note 1, ET contributed the following to ETO: 2,263,158 common units representing limited partner interests in Sunoco LP to ETO in exchange for 2,874,275 ETO common units; 100 percent of the limited liability company interests in Sunoco GP LLC, the sole general partner of Sunoco LP, and all of the IDRs in Sunoco LP, to ETO in exchange for 42,812,389 ETO common units; 12,466,912 common units representing limited partner interests in USAC and 100 percent of the limited liability company interests in USA Compression GP, LLC, the general partner of USAC, to ETO in exchange for 16,134,903 ETO common units; and a 100 percent limited liability company interest in Lake Charles LNG and a 60 percent limited liability company interest in each of Energy Transfer LNG Export, LLC, ET Crude Oil Terminals, LLC and ETC Illinois LLC (collectively, “Lake Charles LNG and Other”) to ETO in exchange for 37,557,815 ETO common units. USAC Acquisition On April 2, 2018, ET acquired a controlling interest in USAC, a publicly traded partnership that provides compression services in the United States. Specifically the Partnership acquired (i) all of the outstanding limited liability company interests in USA Compression GP, LLC (“USAC GP”), the general partner of USAC, and (ii) 12,466,912 USAC common units representing limited partner interests in USAC for cash consideration equal to $250 million (the “USAC Transaction”). Concurrently, USAC cancelled its incentive distribution rights and converted its economic general partner interest into a non-economic general partner interest in exchange for the issuance of 8,000,000 USAC common units to USAC GP.
Concurrent with these transactions, ETO contributed to USAC all of the issued and outstanding membership interests of CDM for aggregate consideration of approximately $1.7 billion, consisting of (i) 19,191,351 USAC common units, (ii) 6,397,965 units of a new class of units representing limited partner interests in USAC (“USAC Class B Units”) and (iii) $1.23 billion in cash, including customary closing adjustments (the “CDM Contribution”). The USAC Class B Units have substantially all of the rights and obligations of a USAC common unit, except the USAC Class B Units will not participate in distributions for the first four quarters following the closing date of April 2, 2018. Each USAC Class B Unit will automatically convert into one USAC common unit on the first business day following the record date attributable to the quarter ending June 30, 2019. Prior to the USAC acquisition, the CDM entities were indirect wholly-owned subsidiaries of ETO. Summary of Assets Acquired and Liabilities Assumed The USAC Transaction was recorded 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 April 2, 2018 | Total current assets | $ | 786 |
| Property, plant and equipment | 1,332 |
| Other non-current assets | 15 |
| Goodwill(1) | 366 |
| Intangible assets | 222 |
| Total assets | 2,721 |
| | | Total current liabilities | 110 |
| Long-term debt, less current maturities | 1,527 |
| Other non-current liabilities | 2 |
| Total liabilities | 1,639 |
| | | Noncontrolling interest | 832 |
| | | Total consideration | 250 |
| Cash received(2) | 711 |
| Total consideration, net of cash received(2) | $ | (461 | ) |
| | (1) | None of the goodwill is expected to be deductible for tax purposes. Goodwill recognized from the business combination primarily relates to the value attributed to additional growth opportunities, synergies and operating leverage within USAC’s operations. |
| | (2) | Cash received represents cash and cash equivalents held by USAC as of the acquisition date. |
The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches. Sunoco LP Convenience Store and Real Estate Sale On January 23, 2018, Sunoco LP completed the disposition of assets pursuant to the purchase agreement with 7-Eleven, Inc. (the “7-Eleven Transaction”). As a result of the 7-Eleven Transaction, previously eliminated wholesale motor fuel sales to Sunoco LP’s retail locations are reported as wholesale motor fuel sales to third parties. Also, the related accounts receivable from such sales are no longer eliminated from the Partnership’s consolidated balance sheets and are reported as accounts receivable. In connection with the 7-Eleven Transaction, Sunoco LP entered into a Distributor Motor Fuel Agreement dated as of January 23, 2018 (“Supply Agreement”), with 7-Eleven and SEI Fuel (collectively, “Distributor”). The Supply Agreement consists
of a 15-year take-or-pay fuel supply arrangement under which Sunoco LP has agreed to supply approximately 2.0 billion gallons of fuel annually plus additional aggregate growth volumes of up to 500 million gallons to be added incrementally over the first four years. For the period from January 1, 2018 through January 22, 2018 and the years ended December 31, 2017 and 2016, Sunoco LP recorded sales to the sites that were subsequently sold to 7-Eleven of $199 million, $3.2 billion and $2.6 billion, respectively, which were eliminated in consolidation. Sunoco LP received payments on trade receivables of $3.4 billion from 7-Eleven for the year ended December 31, 2018 subsequent to the closing of the sale. 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 are being sold through a sealed-bid. Of the 97 properties, 51 have been sold, one is under contract to be sold, and four 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 are operated by a commission agent. The Partnership has concluded that it meets the accounting requirements for reporting the financial position, results of operations and cash flows of Sunoco LP’s retail divestment as discontinued operations. The following tables present the aggregate carrying amounts of assets and liabilities classified as held for sale in the consolidated balance sheet: | | | | | | | | | | December 31, 2018 | | December 31, 2017 | Carrying amount of assets included as part of discontinued operations: | | | | Accounts receivable, net | $ | — |
| | $ | 21 |
| Inventories | — |
| | 149 |
| Other current assets | — |
| | 16 |
| Property and equipment, net | — |
| | 1,851 |
| Goodwill | — |
| | 796 |
| Intangible assets, net | — |
| | 477 |
| Other noncurrent assets | — |
| | 3 |
| Total assets classified as held for sale in the Consolidated Balance Sheet | $ | — |
| | $ | 3,313 |
| | | | | Carrying amount of liabilities included as part of discontinued operations: | | | | Other current and noncurrent liabilities | $ | — |
| | $ | 75 |
| Total liabilities classified as held for sale in the Consolidated Balance Sheet | $ | — |
| | $ | 75 |
|
The results of operations associated with discontinued operations are presented in the following table: | | | | | | | | | | | | | | Years Ended December 31, | | 2018 | | 2017 | | 2016 | REVENUES | $ | 349 |
| | $ | 6,964 |
| | $ | 5,712 |
| | | | | | | COSTS AND EXPENSES | | | | | | Cost of products sold | 305 |
| | 5,806 |
| | 4,649 |
| Operating expenses | 61 |
| | 763 |
| | 744 |
| Depreciation, depletion and amortization | — |
| | 34 |
| | 143 |
| Selling, general and administrative | 7 |
| | 168 |
| | 114 |
| Impairment losses | — |
| | 285 |
| | 447 |
| Total costs and expenses | 373 |
| | 7,056 |
| | 6,097 |
| OPERATING LOSS | (24 | ) | | (92 | ) | | (385 | ) | OTHER EXPENSE | | | | | | Interest expense, net | 2 |
| | 36 |
| | 28 |
| Loss on extinguishment of debt | 20 |
| | — |
| | — |
| Other, net | 61 |
| | 1 |
| | 8 |
| LOSS FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE | (107 | ) | | (129 | ) | | (421 | ) | Income tax expense | 158 |
| | 48 |
| | 41 |
| LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES | $ | (265 | ) | | $ | (177 | ) | | $ | (462 | ) | LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES ATTRIBUTABLE TO ET | $ | (10 | ) | | $ | (6 | ) | | $ | (12 | ) |
2017 Transactions Rover Contribution Agreement In October 2017, ETO completed the previously announced contribution transaction with a fund managed by Blackstone Energy Partners and Blackstone Capital Partners, pursuant to which ETO 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 ETO and 49.9% by Blackstone. Upon closing, Blackstone contributed funds to reimburse ETO for its pro rata share of the Rover construction costs incurred by ETO through the closing date, along with the payment of additional amounts subject to certain adjustments. ETO 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, the Partnership formed PEP, a strategic joint venture with ExxonMobil. The Partnership 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, ETO contributed an approximate 15% ownership interest in Dakota Access and ETCO to PEP, which resulted in an increase in ETO’s ownership interest in PEP to approximately 88%. ETO 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 ETO 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. ETO continues to consolidate Dakota Access and ETCO subsequent to this transaction. 2016 Transactions PennTex Acquisition On November 1, 2016, ETO acquired certain interests in PennTex from various parties for total consideration of approximately $627 million in ETO units and cash. Through this transaction, ETO acquired a controlling financial interest in PennTex, whose assets complement ETO’s existing midstream footprint in northern Louisiana. As discussed in Note 8, ETO 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.
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 the Partnership 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 the Partnership’s 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, ETO 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, 2018, $2.50 billion was outstanding under this credit facility. Bayou Bridge In April 2016, Bayou Bridge Pipeline, LLC (“Bayou Bridge”), a joint venture among ETO and Phillips 66, began commercial operations on the 30-inch segment of the pipeline from Nederland, Texas to Lake Charles, Louisiana. The Partnership holds a 60% interest in the entity and is the operator of the system. Sunoco LP Acquisitions In August 2016, Sunoco LP acquired the fuels business from Emerge Energy Services LP for $171 million, including tax deductible goodwill of $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. | | 4. | ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES: |
Citrus ETO 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 5,344-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 ETO has a 50% interest in FEP which owns an approximately 185-mile natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi. ETO’s 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 ETO owns a 50% interest in MEP, which owns approximately 500 miles of natural gas pipeline that extends from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama. ETO’s 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 existing 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 ETO previously owned a 49.99% interest in HPC, which owns RIGS, which delivers natural gas from northwest Louisiana to downstream pipelines and markets through a 450-mile intrastate pipeline system. In April 2018, ETO acquired the remaining 50.01% interest in HPC. Prior to April 2018, HPC was reflected as an unconsolidated affiliate in ETO’s financial statements; beginning in April 2018, RIGS is reflected as a wholly-owned subsidiary in ETO’s financial statements. The carrying values of the Partnership’s investments in unconsolidated affiliates as of December 31, 2018 and 2017, were as follows: | | | | | | | | | | December 31, | | 2018 | | 2017 | Citrus | $ | 1,737 |
| | $ | 1,754 |
| FEP | 107 |
| | 121 |
| MEP | 225 |
| | 242 |
| HPC | — |
| | 28 |
| Others | 573 |
| | 560 |
| Total | $ | 2,642 |
| | $ | 2,705 |
|
The following table presents equity in earnings (losses) of unconsolidated affiliates: | | | | | | | | | | | | | | Years Ended December 31, | | 2018 | | 2017 | | 2016 | Citrus | $ | 141 |
| | $ | 144 |
| | $ | 102 |
| FEP | 55 |
| | 53 |
| | 51 |
| MEP | 31 |
| | 38 |
| | 40 |
| HPC (1) | 3 |
| | (168 | ) | | 31 |
| Other | 114 |
| | 77 |
| | 46 |
| Total equity in earnings of unconsolidated affiliates | $ | 344 |
| | $ | 144 |
| | $ | 270 |
|
| | (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, Citrus, FEP, MEP, and HPC (on a 100% basis) for all periods presented, except as noted below: | | | | | | | | | | December 31, | | 2018 (1) | | 2017 | Current assets | $ | 212 |
| | $ | 206 |
| Property, plant and equipment, net | 7,800 |
| | 8,437 |
| Other assets | 39 |
| | 43 |
| Total assets | $ | 8,051 |
| | $ | 8,686 |
| | | | | Current liabilities | $ | 1,534 |
| | $ | 861 |
| Non-current liabilities | 3,439 |
| | 4,492 |
| Equity | 3,078 |
| | 3,333 |
| Total liabilities and equity | $ | 8,051 |
| | $ | 8,686 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2018 (1) | | 2017 | | 2016 | Revenue | $ | 1,249 |
| | $ | 1,358 |
| | $ | 1,164 |
| Operating income | 723 |
| | 407 |
| | 714 |
| Net income | 460 |
| | 145 |
| | 384 |
|
| | (1) | Selected balance sheet data as of December 31, 2018 does not include HPC and selected income data for the year ended December 31, 2018 reflects HPC’s results for January 1, 2018 through March 31, 2018. HPC was fully consolidated beginning April 1, 2018 as discussed above. |
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: |
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 the ET Series A Convertible Preferred Units, as discussed in Note 8. For the diluted earnings per share computation, income allocable to the limited partners is reduced, where applicable, for the decrease in earnings from ET’s limited partner unit ownership in ETO or Sunoco LP that would have resulted assuming the incremental units related to our or Sunoco LP’s equity incentive plans, as applicable, had been issued during the respective periods. Such units have been determined based on the treasury stock method.
A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit is as follows: | | | | | | | | | | | | | | Years Ended December 31, | | 2018 | | 2017 | | 2016 | Income from continuing operations | $ | 3,630 |
| | $ | 2,543 |
| | $ | 462 |
| Less: Net income attributable to redeemable noncontrolling interests | 39 |
| | — |
| | — |
| Less: Income (loss) from continuing operations attributable to noncontrolling interest | 1,888 |
| | 1,583 |
| | (545 | ) | Income from continuing operations, net of noncontrolling interest | 1,703 |
| | 960 |
| | 1,007 |
| Less: General Partner’s interest in income from continuing operations | 3 |
| | 2 |
| | 3 |
| Less: Convertible Unitholders’ interest in net income from continuing operations | 33 |
| | 38 |
| | 8 |
| Less: Class D Unitholder’s interest in income from continuing operations | — |
| | — |
| | — |
| Income from continuing operations available to Limited Partners | $ | 1,667 |
| | $ | 920 |
| | $ | 996 |
| Basic Income from Continuing Operations per Limited Partner Unit: | | | | | | Weighted average limited partner units | 1,423.8 |
| | 1,078.2 |
| | 1,045.5 |
| Basic income from continuing operations per Limited Partner unit | $ | 1.17 |
| | $ | 0.86 |
| | $ | 0.95 |
| Basic income (loss) from discontinued operations per Limited Partner unit | $ | (0.01 | ) | | $ | (0.01 | ) | | $ | (0.01 | ) | Diluted Income from Continuing Operations per Limited Partner Unit: | | | | | | Income from continuing operations available to Limited Partners | $ | 1,667 |
| | $ | 920 |
| | $ | 996 |
| Dilutive effect of equity-based compensation of subsidiaries, distributions to Convertible Units | 33 |
| | 38 |
| | 8 |
| Diluted income from continuing operations available to Limited Partners | 1,700 |
| | 958 |
| | 1,004 |
| Weighted average limited partner units | 1,423.8 |
| | 1,078.2 |
| | 1,045.5 |
| Dilutive effect of unconverted unit awards and Convertible Units | 30.3 |
| | 72.6 |
| | 33.1 |
| Dilutive effect of unvested unit awards | 7.3 |
| | — |
| | — |
| Weighted average limited partner units, assuming dilutive effect of unvested unit awards | 1,461.4 |
| | 1,150.8 |
| | 1,078.6 |
| Diluted income from continuing operations per Limited Partner unit | $ | 1.16 |
| | $ | 0.84 |
| | $ | 0.93 |
| Diluted income (loss) from discontinued operations per Limited Partner unit | $ | (0.01 | ) | | $ | (0.01 | ) | | $ | (0.01 | ) |
Our debt obligations consist of the following: | | | | | | | | | | December 31, | | 2018 | | 2017 | Parent Company Indebtedness: | | | | 7.50% Senior Notes due October 15, 2020 | $ | 1,187 |
| | $ | 1,187 |
| 4.25% Senior Notes due March 15, 2023 | 1,000 |
| | 1,000 |
| 5.875% Senior Notes due January 15, 2024 | 1,150 |
| | 1,150 |
| 5.50% Senior Notes due June 1, 2027 | 1,000 |
| | 1,000 |
| ET Senior Secured Term Loan | 1,220 |
| | 1,220 |
| ET Senior Secured Revolving Credit Facility | — |
| | 1,188 |
| Unamortized premiums, discounts and fair value adjustments, net | (10 | ) | | (11 | ) | Deferred debt issuance costs | (27 | ) | | (34 | ) | | 5,520 |
| | 6,700 |
| | | | | Subsidiary Indebtedness: | | | | ETO Debt | | | | 2.50% Senior Notes due June 15, 2018 | — |
| | 650 |
| 6.70% Senior Notes due July 1, 2018 | — |
| | 600 |
| 9.70% Senior Notes due March 15, 2019 (1) | 400 |
| | 400 |
| 9.00% Senior Notes due April 15, 2019 (1) | 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 |
| 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 |
| 4.20% Senior Notes due September 15, 2023 | 500 |
| | — |
| 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 |
| | 600 |
| 4.00% Senior Notes due October 1, 2027 | 750 |
| | 750 |
| 4.95% Senior Notes due June 15, 2028 | 1,000 |
| | — |
| 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 |
| 5.80% Senior Notes due June 15, 2038 | 500 |
| | — |
|
| | | | | | | | | 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 |
| | 900 |
| 5.40% Senior Notes due October 1, 2047 | 1,500 |
| | 1,500 |
| 6.00% Senior Notes due June 15, 2048 | 1,000 |
| | — |
| Floating Rate Junior Subordinated Notes due November 1, 2066 | 546 |
| | 546 |
| ETO $5.00 billion Revolving Credit Facility due December 2023 | 3,694 |
| | 2,292 |
| ETO $1.00 billion 364-Day Credit Facility due November 2019 | — |
| | 50 |
| Unamortized premiums, discounts and fair value adjustments, net | 17 |
| | 33 |
| Deferred debt issuance costs | (178 | ) | | (170 | ) | | 32,288 |
| | 29,210 |
| | | | | Transwestern Debt | | | | 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 |
| | 574 |
| | | | | Panhandle Debt | | | | 7.00% Senior Notes due June 15, 2018 | — |
| | 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 | 14 |
| | 28 |
| | 399 |
| | 813 |
| | | | | Bakken Project Debt | | | | Bakken $2.50 billion Credit Facility due August 2019 | 2,500 |
| | 2,500 |
| Deferred debt issuance costs | (3 | ) | | (8 | ) | | 2,497 |
| | 2,492 |
| | | | | Sunoco LP Debt | | | | 4.875% Senior Notes Due January 15, 2023 | 1,000 |
| | — |
| 5.50% Senior Notes Due February 15, 2026 | 800 |
| | — |
| 5.875% Senior Notes Due March 15, 2028 | 400 |
| | — |
| 5.50% Senior Notes due August 1, 2020 | — |
| | 600 |
|
| | | | | | | | | 6.375% Senior Notes due April 1, 2023 | — |
| | 800 |
| 6.25% Senior Notes due April 15, 2021 | — |
| | 800 |
| Sunoco LP $1.50 billion Revolving Credit Facility due July 2023 | 700 |
| | — |
| Sunoco LP $1.50 billion Revolving Credit Facility due September 2019 | — |
| | 765 |
| Sunoco LP Term Loan due October 1, 2019 | — |
| | 1,243 |
| Lease-related obligations | 107 |
| | 113 |
| Deferred debt issuance costs | (23 | ) | | (34 | ) | | 2,984 |
| | 4,287 |
| | | | | USAC Debt | | | | 6.875% Senior Notes due April 1, 2026 | 725 |
| | — |
| USAC $1.60 billion Revolving Credit Facility due April 2023 | 1,050 |
| | — |
| Deferred debt issuance costs | (16 | ) | | — |
| | 1,759 |
| | — |
| | | | | Other | 7 |
| | 8 |
| Total debt | 46,028 |
| | 44,084 |
| Less: Current maturities of long-term debt | 2,655 |
| | 413 |
| Long-term debt, less current maturities | $ | 43,373 |
| | $ | 43,671 |
|
| | (1) | As of December 31, 2018, these notes were classified as long-term as management had the intent and ability to refinance the borrowings on a long-term basis. The notes were refinanced in January 2019, as discussed below. |
The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $227 million in unamortized premiums, fair value adjustments and deferred debt issuance costs, net: | | | | | 2019 | $ | 3,505 |
| 2020 | 3,068 |
| 2021 | 1,406 |
| 2022 | 5,505 |
| 2023 | 7,255 |
| Thereafter | 25,516 |
| Total | $ | 46,255 |
|
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 ET Senior Notes Offering In October 2017, ET 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. ET Senior Notes The ET 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 ET Senior Notes previously were secured on a first-priority basis with its obligations under the Revolver Credit Agreement
and the ET 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. Subsequent to the termination of the Revolver Credit Agreement and the ET Term Loan Facility, the collateral securing the ET Senior Notes was released. The ET Senior Notes are not guaranteed by any of the Parent Company’s subsidiaries. The covenants related to the ET 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. ETO Senior Notes The ETO senior notes were registered under the Securities Act of 1933 (as amended). The Partnership may redeem some or all of the ETO senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the ETO senior notes. The balance is payable upon maturity. Interest on the ETO senior notes is paid semi-annually. The ETO senior notes are unsecured obligations of the Partnership and as a result, the ETO 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 ETO senior notes effectively rank junior to all indebtedness and other liabilities of our existing and future subsidiaries. 2019 Senior Notes Offering and Redemption In January 2019, ETO issued the following senior notes: •$750 million aggregate principal amount of 4.50% senior notes due 2024; •$1.50 billion aggregate principal amount of 5.25% senior notes due 2029; and •$1.75 billion aggregate principal amount of 6.25% senior notes due 2049. 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 principal on the senior notes is payable upon maturity and interest is paid semi-annually. The senior notes rank equally in right of payment with ETO’s existing and future senior debt, and senior in right of payment to any future subordinated debt ETO may incur. The notes of each series will initially be fully and unconditionally guaranteed by our subsidiary, Sunoco Logistics Partners Operations L.P., on a senior unsecured basis so long as it guarantees any of our other long-term debt. The guarantee for each series of notes ranks equally in right of payment with all of the existing and future senior debt of Sunoco Logistics Partners Operations L.P., including its senior notes. The $3.96 billion net proceeds from the offering were used to make an intercompany loan to ET (which ET used to repay its term loan in full), for general partnership purposes and to redeem at maturity all of the following: •ETO’s $400 million aggregate principal amount of 9.70% senior notes due March 15, 2019; •ETO’s $450 million aggregate principal amount of 9.00% senior notes due April 15, 2019; and •Panhandle’s $150 million aggregate principal amount of 8.125% senior notes due June 1, 2019. 2018 Senior Notes Offering and Redemption In June 2018, ETO issued the following senior notes: •$500 million aggregate principal amount of 4.20% senior notes due 2023; •$1.00 billion aggregate principal amount of 4.95% senior notes due 2028; •$500 million aggregate principal amount of 5.80% senior notes due 2038; and •$1.00 billion aggregate principal amount of 6.00% senior notes due 2048. 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 principal on the senior notes is payable upon maturity and interest is paid semi-annually.
The senior notes rank equally in right of payment with ETO’s existing and future senior debt, and senior in right of payment to any future subordinated debt ETO may incur. The notes of each series will initially be fully and unconditionally guaranteed by our subsidiary, Sunoco Logistics Partners Operations L.P., on a senior unsecured basis so long as it guarantees any of our other long-term debt. The guarantee for each series of notes ranks equally in right of payment with all of the existing and future senior debt of Sunoco Logistics Partners Operations L.P., including its senior notes. The $2.96 billion net proceeds from the offering were used to repay borrowings outstanding under ETO’s revolving credit facility, for general partnership purposes and to redeem at maturity all of the following senior notes: •ETO’s $650 million aggregate principal amount of 2.50% senior notes due June 15, 2018; •Panhandle’s $400 million aggregate principal amount of 7.00% senior notes due June 15, 2018; and •ETO’s $600 million aggregate principal amount of 6.70% senior notes due July 1, 2018. The aggregate amount paid to redeem these notes was approximately $1.65 billion. 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 5.559% at December 31, 2018. As part of ETO’s senior notes offering in June 2018 discussed above, Panhandle’s $400 million aggregate principal amount of 7.00% senior notes due June 15, 2018 were redeemed. Sunoco LP Senior Notes Offering On January 23, 2018, Sunoco LP completed a private offering of $2.2 billion of senior notes, comprised of $1.0 billion in aggregate principal amount of 4.875% senior notes due 2023, $800 million in aggregate principal amount of 5.500% senior notes due 2026 and $400 million in aggregate principal amount of 5.875% senior notes due 2028. Sunoco LP used the proceeds from the private offering, along with proceeds from its retail divestment to: redeem in full its existing senior notes, comprised of $800 million in aggregate principal amount of 6.250% senior notes due 2021, $600 million in aggregate principal amount of 5.500% senior notes due 2020 and $800 million in aggregate principal amount of 6.375% senior notes due 2023; repay in full and terminate its term loan; pay all closing costs in connection with its retail divestment; redeem the outstanding Sunoco LP Series A Preferred Units; and repurchase 17,286,859 Sunoco LP common units owned by ETO. On December 3, 2018, Sunoco LP completed an exchange of the notes for registered notes with substantially identical terms. USAC Senior Notes In March 2018, USAC completed a private offering of $725 million aggregate principal amount of senior notes that mature on April 1, 2026. The notes accrue interest from March 23, 2018 at the rate of 6.875% per year. Interest on the notes will be payable semi-annually in arrears on each April 1 and October 1, commencing on October 1, 2018. On January 14, 2019, USAC completed an exchange of these notes for registered notes with substantially identical terms. In February 2019, USAC announced the offering of $750 million aggregate principal amount of senior unsecured notes due 2027 in a private placement to eligible purchasers. USAC intends to use the net proceeds from this offering to repay a portion of its existing borrowings under the USAC credit facility and for general partnership purposes.
Term Loans, Credit Facilities and Commercial Paper ET Term Loan Facility On February 2, 2017, the Partnership entered into a Senior Secured Term Loan Agreement (the “Term Credit Agreement”) with Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party thereto. The Term Credit Agreement had a scheduled maturity date of February 2, 2024, with an option for the Parent Company to extend the term subject to the terms and conditions set forth therein. The Term Credit Agreement contained an accordion feature, under which the total commitments may be increased, subject to the terms thereof. In connection with the Parent Company’s entry into the Senior Secured Term Loan Agreement on February 2, 2017, the Parent Company terminated its previous term loan agreements. Pursuant to the Term Credit Agreement, the Term Lenders provided senior secured financing in an aggregate principal amount of $2.2 billion (the “Term Loan Facility”). Under the Term Credit Agreement, the obligations of the Parent Company were secured by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets. Interest accrued on advances at a LIBOR rate or a base rate, based on the election of the Parent Company for each interest period, plus an applicable margin. On January 15, 2019, Energy Transfer LP paid in full all outstanding borrowings under its Senior Secured Term Loan Agreement and thereafter terminated the term loan agreement. In connection with the termination of the term loan agreement, the collateral securing certain series of the Partnership’s outstanding senior notes was released in accordance with the terms of the applicable indentures governing such senior notes. ET Revolving Credit Facility On March 24, 2017, the Parent Company previously had 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 had a scheduled maturity date of March 24, 2022 and included 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 committed to provide advances up to an aggregate principal amount of $1.50 billion at any one time outstanding, and the Parent Company had the option to request increases in the aggregate commitments by up to $500 million in additional commitments. Under the Revolver Credit Agreement, the obligations of the Partnership were secured by a lien on substantially all of the Partnership’s and certain of its subsidiaries’ tangible and intangible assets. In connection with the closing of the Energy Transfer Merger in October 2018, the Partnership repaid in full all outstanding borrowings under the facility and the facility was terminated. ETO Five-Year Credit Facility ETO’s revolving credit facility (the “ETO Five-Year Credit Facility”) previously allowed for unsecured borrowings up to $4.00 billion and matured in December 2022. On October 19, 2018, the ETO Five-Year Credit Facility was amended to increase the borrowing capacity by $1.00 billion, to $5.00 billion, and to extend the maturity date to December 1, 2023. The ETO Five-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to $6.00 billion under certain conditions. As of December 31, 2018, the ETO Five-Year Credit Facility had $3.69 billion outstanding, of which $2.34 billion was commercial paper. The amount available for future borrowings was $1.24 billion after taking into account letters of credit of $63 million. The weighted average interest rate on the total amount outstanding as of December 31, 2018 was 3.57%. ETO 364-Day Facility ETO’s 364-day revolving credit facility (the “ETO 364-Day Facility”) previously allowed for unsecured borrowings up to $1.00 billion and matured on November 30, 2018. On October 19, 2018, the ETO 364-Day Facility was amended to extend the maturity date to November 29, 2019. As of December 31, 2018, the ETO 364-Day Facility had no outstanding borrowings. Bakken Credit Facility In August 2016, ETO and Phillips 66 completed project-level financing of the Bakken pipeline. The $2.50 billion credit facility matures in August 2019 (the “Bakken Credit Facility”). As of December 31, 2018, the Bakken Credit Facility had $2.50 billion of outstanding borrowings, all of which has been reflected in current maturities of long-term debt on the Partnership’s consolidated balance sheets. The weighted average interest rate on the total amount outstanding as of December 31, 2018 was 4.27%.
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 LP’s leverage ratio as set forth in its previously delivered compliance certificates and the resulting failure to pay incremental interest owed under the term loan. The Sunoco LP term loan was repaid in full and terminated on January 23, 2018. See “Sunoco LP Senior Notes Offering” above. Sunoco LP Credit Facility Sunoco LP maintains a $1.50 billion revolving credit agreement (the “Sunoco LP Credit Facility”). In July 2018, Sunoco LP amended its revolving credit agreement, including extending the expiration to July 2023 (which may be extended in accordance with the terms of the credit agreement). Borrowings under the amended revolving credit agreement were used to pay off Sunoco LP’s existing revolving credit facility which was entered into in September 2014. As of December 31, 2018, the Sunoco LP Credit Facility had $700 million outstanding borrowings and $8 million in standby letters of credit. The unused availability on the revolver at December 31, 2018 was $792 million. The weighted average interest rate on the total amount outstanding as of December 31, 2018 was 4.45%. USAC Credit Facility USAC currently has a $1.60 billion revolving credit facility, which matures on April 2, 2023 and permits up to $400 million of future increases in borrowing capacity. As of December 31, 2018, USAC had $1.05 billion of outstanding borrowings and no outstanding letters of credit under the credit agreement. As of December 31, 2018, USAC had $550 million of availability under its credit facility. The weighted average interest rate on the total amount outstanding as of December 31, 2018 was 4.69%. Covenants Related to Our Credit Agreements Covenants Related to the Parent Company The Term Loan Facility and ET 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 ETEET 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 ETPETO The agreements relating to the ETPETO 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 ETPETO 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 ETO Credit Facilities) during certain Defaults (as defined in such credit agreement)the ETO Credit Facilities) and during any Event of Default (as defined in such credit agreement)the ETO 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 ETO 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 ETO 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 ETO Five-Year Facility ranges from 0.125% to 0.300%. The applicable margin for eurodollar rate loans under the ETO 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 ETO 364-Day Facility ranges from 0.125% to 0.225%. The credit agreement relatingETO Credit Facilities contain various covenants including limitations on the creation of indebtedness and liens, and related to the ETPoperation and conduct of our business. The ETO 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 3.38 to 1 at December 31, 2018, as definedcalculated in accordance with the ETP Credit Facility.credit agreements. The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio. Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Partnership’s or our subsidiaries’ ability to incur additional debt and/or our ability to pay distributions to Unitholders. 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’ $2.50 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 3.6 to 1 at December 31, 2015, as calculated in accordance with the credit agreements.make certain restricted payments thereunder. Covenants Related to Sunoco LP The Sunoco LP Credit Facility contains various customary representations, warranties, covenants and events of default, including a change of control event of default, as defined therein. Sunoco LP’s Credit Facility requires Sunoco LP to maintain a leverage ratioNet Leverage Ratio of not more than 5.505.5 to 1. The maximum leverage ratioNet Leverage Ratio is subject to upwards adjustment of not more than 6.006.0 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 a joint venture for a purchase pricecertain specified acquisitions of not less than $50 million. Indebtednessmillion (as permitted under theSunoco LP’s Credit Facility agreement). The Sunoco LP Credit Facility is secured by a security interestalso requires Sunoco LP to maintain an Interest Coverage Ratio (as defined in among other things, all of the Sunoco LP’s present and future personal property and allCredit Facility agreement) of not less than 2.25 to 1. Covenants Related to USAC The USAC Credit Facility contains covenants that limit (subject to certain exceptions) USAC’s ability to, among other things: make certain loans or investments; incur additional indebtedness or guarantee other indebtedness; make certain acquisitions. The credit facility is also subject to the following financial covenants, including covenants requiring us to maintain: a minimum EBITDA to interest coverage ratio of 2.5 to 1.0, determined as of the presentlast day of each fiscal quarter; and future personal property of its guarantors, the capital stock of its material subsidiaries (or 66% a maximum funded debt to EBITDA ratio, determined as of the capital stocklast day of material foreign subsidiaries),each fiscal quarter, for the annualized trailing three months of (i) 5.75 to 1 through the end of the fiscal quarter ending March 31, 2019, (ii) 5.5 to 1 through the end of the fiscal quarter ending December 31, 2019 and (iii) 5.0 to 1 thereafter, in each case subject to a provision for increases to such thresholds by 0.50 in connection with certain future acquisitions for the six consecutive month period following the period in which any intercompany debt. Upon the first achievement by Sunoco LP of an investment grade credit rating, all security interests securing the Sunoco LP Credit Facility will be released.such acquisition occurs. 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, 2015.2018.
| | 7. | REDEEMABLE PREFERRED UNITS:NONCONTROLLING INTERESTS |
In connection withCertain redeemable noncontrolling interest in the closing of the Regency Merger, Regency’s 1.9 million outstanding series A cumulative convertible preferred units were converted into corresponding newly issued ETP cumulative convertible series A preferred units on a one-for-one basis. If outstanding, the ETP Preferred Units are mandatorily redeemable on September 2, 2029 for $35 million plus all accrued but unpaid distributions and interest thereon andPartnership’s subsidiaries are reflected as long-term liabilities in ourmezzanine equity on the consolidated balance sheets. sheet. Redeemable noncontrolling interests as of December 31, 2018 include (i) a balance of $477 million related to the USAC Preferred Units described below and (ii) a balance of $22 million related to noncontrolling interest holders in one of the Partnership’s consolidated subsidiaries that have the option to sell their interests to the Partnership.
USAC Series A Preferred Units On April 2, 2018, USAC issued 500,000 USAC Preferred Units at a price of $1,000 per USAC Preferred Unit, for total gross proceeds of $500 million in a private placement. The ETPUSAC Preferred Units are entitled to a preferentialreceive cumulative quarterly cash distribution of $0.445distributions equal to $24.375 per ETPUSAC Preferred Unit, if outstanding on the record dates of ETP’s common unit distributions. Holderssubject to increase in certain limited circumstances. The USAC Preferred Units will have a perpetual term, unless converted or redeemed. Certain portions of the ETPUSAC Preferred Units can electwill be convertible into USAC common units at the election of the holders beginning in 2021. To the extent the holders of the USAC Preferred Units have not elected to convert their preferred units by the ETPfifth anniversary of the issue date, USAC will have the option to redeem all or any portion of the USAC Preferred Units to ETP Common Unitsfor cash. In addition, at any time in accordance with ETP’s partnership agreement. The number of ETP common units issuable upon conversionon or after the tenth anniversary of the ETPissue date, the holders of the USAC Preferred Units is equalwill have the right to require USAC to redeem all or any portion of the issue price of $18.30, plus all accrued but unpaid distributions and interest thereon, divided by the conversion price of $44.37. As of December 31, 2015, the ETPUSAC Preferred Units, were convertible into 0.9 million ETP Common Units.and the Partnership may elect to pay up to 50% of such redemption amount in USAC common units.
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, 2015,2018, there were issued and outstanding 1.042.62 billion Common Units representing an aggregate 99.53%99.9% 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 ETEET Common Units during the years ended December 31, 2015, 20142018, 2017 and 20132016 was as follows: | | | Years Ended December 31, | Years Ended December 31, | | 2015 | | 2014 | | 2013 | 2018 | | 2017 | | 2016 | Number of Common Units, beginning of period | 1,077.5 |
| | 1,119.8 |
| | 1,119.8 |
| 1,079.1 |
| | 1,046.9 |
| | 1,044.8 |
| Conversion of Class D Units to ETE Common Units | 0.9 |
| | — |
| | — |
| | Repurchase of common units under buyback program | (33.6 | ) | | (42.3 | ) | | — |
| | Conversion of ET Series A Convertible Preferred Units to common units | | 79.1 |
| | — |
| | — |
| Common Unit increase from Energy Transfer Merger | | 1,458.9 |
| | — |
| | — |
| Issuance of common units | | 2.3 |
| | 32.2 |
| | 2.1 |
| Number of Common Units, end of period | 1,044.8 |
| | 1,077.5 |
| | 1,119.8 |
| 2,619.4 |
| | 1,079.1 |
| | 1,046.9 |
|
In October 2018, ET issued 1.46 billion ET Common Unit SplitUnits in connection with the Energy Transfer Merger. OnET 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 23, 2013, ETE announced31, 2018. ET Series A Convertible Preferred Units In May 2018, the Partnership converted its 329.3 million Series A Convertible Preferred Units into approximately 79.1 million ET common units in accordance with the terms of ET’s partnership agreement. ET Class A Units In connection with the Energy Transfer Merger, the Partnership issued 647,745,099 Class A units (“ET Class A Units”) representing limited partner interests in the Partnership to LE GP, LLC (“LE GP”), the general partner of ET. The number of ET Class A Units issued allows LE GP and its affiliates to retain a voting interest in the Partnership that is identical to their voting interest in the Partnership prior to the completion of the Merger. The ET Class A Units are entitled to vote together with the Partnership’s common units, as a single class, except as required by law. Additionally, ET’s partnership agreement provides that, under certain circumstances, upon the issuance by the Partnership of additional common units or any securities that have voting rights that are pari passu with the Partnership common units, the Partnership will issue to any holder of ET Class A Units additional ET Class A Units such that the board of directors ofholder maintains a voting interest in the Partnership that is identical to its general partner approved a two-for-one split ofvoting interest in the Partnership’s outstanding common units (the “2014 Split”).Partnership prior to such issuance. The 2014 Split was completed on January 27, 2014. The 2014 Split was effected by a distribution of one ETE Common Unit for each common unit outstandingET Class A Units are not entitled to distributions and held by unitholders of record at the close of business on January 13, 2014. On May 28, 2015, ETE announced that the board of directors its general partner approved a two-for-one split of the Partnership’s outstanding common units (the “2015 Split”). The 2015 Split was completed on July 27, 2015. The 2015 Split was effected by a distribution of one ETE common unit for each common unit outstanding and held by unitholders of record at the close of business on July 15, 2015.otherwise have no economic attributes.
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 ETEET Common Units in the open market at the Partnership’s discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements. The Partnership repurchased 42.3 million ETE Common Units under this program through May 23, 2014, and the program was completed.
In February 2015, the Partnership announced a common unit repurchase program, whereby the Partnership may repurchase up to an additional $2 billion of ETE Common Units in the open market at the Partnership’s discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements. The Partnership repurchased 33.6 million ETEno ET Common Units under this program in 2015,2018, 2017 or 2016 and there was $936 million available to use under the program as of December 31, 2015.2018.
Class D Units On May 1,In 2013, Jamie Welch was appointed Group Chief Financial Officer and Head of Corporate Development of LE GP, LLC, the general partner of ETE, effective June 24, 2013. Pursuant to an equity award agreement between Mr. Welch and the Partnership dated April 23, 2013, Mr. Welch received 3,000,000 restricted ETE common units representing limited partner interest. The restricted ETE common units were subject to vesting, based on continued employment with ETE. On December 23, 2013, ETE and Mr. Welch entered into (i) a rescission agreement in order to rescind the original offer letter to the extent it relates to the award of 3,000,000 common units of ETE to Mr. Welch, the original award agreements, and the receipt of cash amounts by Mr. Welch with respect to such awarded units and (ii) a new Class D Unit Agreement between ETE and Mr. Welch providing for the issuance to Mr. Welch of an aggregate ofissued 3,080,000 Class D Units of ETE, which number ofET pursuant to an agreement with a former executive. The Class D Units includes an additional 80,000 Class Dwere convertible to ET Common Units, thatsubject to certain vesting requirements which were issued to Mr. Welch in connection with other changes to his original offer letter.
Under the terms of the Class D Unit Agreement, as amended, 30% of the Class D Units converted to ETE common units on a one-for-one basis on March 31, 2015, 35% were scheduled to convert to ETE common units on a one-for-one-basis on March 31, 2018, and the remaining 35% were scheduled to convert to ETE common units on a one-for-one basis on March 31, 2020, subject in each case to (i) Mr. Welch being in Good Standing with ETE (as defined in the Class D Unit Agreement) and (ii) there being a sufficient amount of gain available (based on the ETE partnership agreement) to be allocatednot met prior to the Class D Units being converted so as to cause the capital account of each such unit to equal the capital account of an ETE Common Unit on the conversion date. Per the terms of the Class D Unit Agreement, 924,000 units converted to ETE common units on a one-for-one basis March 31, 2015. In connection with Mr. Welch’s replacement as Group Chief Financial Officer and Head of Business Development of our General Partner and hisformer executive’s termination of employment by an affiliate of ETE, any future conversion of the Class D Units is the subject of on-going discussions between ETE and Mr. Welch in connection with his separation from employment. As of this date, it is ETE’s current position that as a result of Mr. Welch’s termination, the unconverted Class D units are not eligible to be converted.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
In April 2013, ETP completed a public offering of 13.8 million ETP common units for net proceeds of $657 million. The proceeds were used to repay amounts outstanding under the ETP Credit Facility 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.
During the year ended December 31, 2015, ETP issued 21.1 million units for $1.07 billion, net of commissions of $11 million. As of December 31, 2015, $328 million of ETP Common Units remained available to be issued under the currently effective equity distribution agreement.
ETP’s Equity Incentive Plan Activity
ETP issues ETP Common Units to employees and directors upon vesting of awards granted under ETP’s equity incentive plans. Upon vesting, participants in the equity incentive plans may elect to have a portion of the ETP Common Units to which they are entitled withheld by ETP to satisfy tax-withholding obligations.
ETP’s Distribution Reinvestment Program
ETP’s Distribution Reinvestment Plan (the “DRIP”) provides ETP’s Unitholders of record and beneficial owners of ETP Common Units a voluntary means by which they can increase the number of ETP Common Units they own by reinvesting the quarterly cash distributions they would otherwise receive in the purchase of additional ETP Common Units.
During the years ended December 31, 2015, 2014 and 2013, aggregate distributions of $360 million, $155 million, and $109 million, respectively, were reinvested under the DRIP resulting in the issuance in aggregate of 12.8 million ETP Common Units.
In December 2015, ETP provided notice to the DRIP participants that it has changed the discount at which participants may purchase ETP common units through the DRIP from 5% to 1%, effective for the distributions payable in respect of the fourth quarter of 2015 and future quarters.
As of December 31, 2015, a total of 11.5 million ETP Common Units remain available to be issued under the existing registration statement.
ETPETO Class E Units
These ETPThere were previously 8.9 million Class E Units areoutstanding, all of which were owned by HHI. The Class E Units were 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 arewere owned by a wholly-owned subsidiary, of ETP Holdco, Heritage Holdings, Inc. Although no plans are currentlythe cash distributions on those units were eliminated in place, management may evaluate whetherour consolidated financial statements. On December 31, 2018, the Class E units were converted to retire some orClass L units, as described below.
ETO Class G Units There were previously 90.7 million Class G Units outstanding, all of the ETP Class E Units at a future date. All of the 8.9 million ETP Class E Units outstanding arewhich were held by a wholly-owned subsidiary of ETP and are reported by ETP as treasury units. ETPthe Partnership. The 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 equaled 90.7 million, which included 40 million ETP Class F Units issued in exchange for cash contributed by Sunoco, Inc. to ETP immediately prior to or concurrent with the closing of the Sunoco Merger. The ETP Class F Units generally did not have any voting rights. The ETP Class F Units were entitled to aggregate cash distributions equal to 35% of the total amount of cash generated by ETPus and itsour subsidiaries, other than ETP Holdco, and available for distribution, up to a maximum of $3.75 per ETP Class FG Unit per year. In April 2013, all of the outstanding ETP Class F Units were exchanged for ETP Class G Units on a one-for-one basis. The ETP Class G Units have terms that are substantially the same as the ETP Class F Units, with the principal difference between the ETP Class G Units and the ETP Class F Units being that allocationsAllocations of depreciation and amortization to the ETP Class G Units for tax purposes arewere based on a predetermined percentage and are not contingent on whether ETPETO has net income or loss. The ETP Class G Units are held by a subsidiary of ETP and therefore areThese units were reflected by ETP as treasury units in itsthe consolidated financial statements. On December 31, 2018, the Class G units were converted to Class L units, as described below.
ETPETO Class H Units and
The ETO Class IH 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 are were generally entitled to (i) allocations of profits, losses and other items from ETPETO corresponding to 50.05%90.05% of the profits, losses, and other items allocated to ETPETO 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 ETPETO for each quarter equal to 50.05%90.05% of the cash distributed to ETPETO by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners for such quarter and, to the extent not previously distributed to holders of the Class H Units, for any previous quarters.
Bakken Pipeline Transaction
In March 2015, ETE transferred 30.8 million ETP common units, ETE’s 45% interest in the Bakken Pipeline project, and $879 million in cash to ETP in exchange for 30.8 million newly issued ETP The Class H Units that, when combinedunits were cancelled in connection with the 50.2 million previously issued ETP Class H Units, generally entitle ETE to receive 90.05%merger of the cash distributionsETO and other economic attributes of the general partner interest and IDRs of Sunoco Logistics (the “Bakken Pipeline Transaction”). Inin April 2017.
connection with this transaction, ETP also issued to ETE 100 ETPETO Class I Units that provide distributions to ETE to offset IDR subsidies previously provided to ETP. These IDR subsidies, including the impact from distributions on ETP Class I Units, were reduced by $55 million in 2015 and $30 million in 2016.
In connection with the transaction, ETPBakken Pipeline Transaction discussed in Note 3, in March 2015, ETO issued 100 ETPETO Class I Units. The ETPETO 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 ETPETO 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 ETPETO Class I Units and (ii) after making cash distributions to ETPETO 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’sETO’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, alongUnits were cancelled in connection with the currently effective IDR subsidies,Energy Transfer Merger in October 2018. Bakken Equity Sale In February 2017, Bakken Holdings Company LLC, an entity in which ETO 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 includedowned by wholly-owned subsidiaries of Phillips 66. ETO continues to consolidate Dakota Access and ETCO subsequent to this transaction. ETO Class K Units On December 29, 2016, ETO issued to certain of its indirect subsidiaries, in exchange for cash contributions and the table below under “Quarterlyexchange of outstanding common units representing limited partner interests in ETO, Class K Units, each of which is entitled to a quarterly cash distribution of $0.67275 per Class K Unit prior to ETO making distributions of available cash to any class of units, excluding any cash available distributions or dividends or capital stock sales proceeds received by ETO from ETO Holdco. If ETO 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, 2018, a total of 101.5 million Class K Units were held by wholly-owned subsidiaries of ETO.
ETO Class L Units On December 31, 2018, ETO issued a new class of limited partner interests titled Class L Units to two wholly-owned subsidiaries of the Partnership when the Partnership’s outstanding Class E units and Class G units held by such subsidiaries were converted into Class L Units. As a result of the conversion, the Class E units and Class G units were cancelled. The Class L Units generally do not have any voting rights. The Class L Units are entitled to aggregate cash distributions equal to 7.65% per annum of the total amount of cash generated by us and our subsidiaries, other than ETP Holdco, and available for distribution. Distributions shall be paid quarterly, in arrears, within 45 days after the end of Available Cash.”each quarter. As the Class L Units are owned by a wholly-owned subsidiary, the cash distributions on those units are eliminated in our consolidated financial statements. Sales of Common Units by Sunoco Logistics In 2014,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. ETO Preferred Units In November 2017, ETO 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. In April 2018, ETO issued 18 million of its 7.375% Series C Preferred Units at a price of $25 per unit. In July 2018, ETO issued 17.8 million of its 7.625% Series D Preferred Units at a price of $25 per unit. Subsequent to the Energy Transfer Merger, all of ETO’s Series A, Series B, Series C and Series D Preferred Units remain outstanding. ETO Series A Preferred Units 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 ETO’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. ETO Series B Preferred Units 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 ETO’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. ETO Series C Preferred Units Distributions on the Series C Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, May 15, 2023, at a rate of 7.375% per annum of the stated liquidation preference of $25. On and after May 15, 2023, distributions on the Series C Preferred Units will accumulate at a percentage of the $25 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.530% per annum. The Series C Preferred Units are redeemable at ETO’s option on or after May 15, 2023 at a redemption price of $25 per Series C Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
ETO Series D Preferred Units Distributions on the Series D Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, August 15, 2023, at a rate of 7.625% per annum of the stated liquidation preference of $25. On and after August 15, 2023, distributions on the Series D Preferred Units will accumulate at a percentage of the $25 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.738% per annum. The Series D Preferred Units are redeemable at ETO’s option on or after August 15, 2023 at a redemption price of $25 per Series D 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, ETO purchased all of the outstanding PennTex common units not previously owned by ETO for $20.00 per common unit in cash. ETO now owns all of the economic interests of PennTex, and PennTex common units are no longer publicly traded or listed on the NASDAQ. Subsidiary Equity Transactions Sunoco LP’s Common Unit Repurchase 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 ETO for aggregate cash consideration of approximately $540 million. ETO used the proceeds from the sale of the Sunoco LP common units to repay amounts outstanding under its revolving credit facility. Sunoco LP’s Equity Distribution Program In October 2016, Sunoco LP entered into an equity distribution agreementsagreement pursuant to which Sunoco LogisticsLP may sell from time to time common units having aggregate offering prices of up to $1.25 billion. In the fourth quarter of 2015, the aggregate capacity was increased to $2.25 billion. During$400 million. For the year ended December 31, 2015,2018, Sunoco Logistics receivedLP issued no additional units under its ATM program. For the years ended December 31, 2017 and 2016, Sunoco LP issued an additional 1.3 million and 2.8 million units with total net proceeds of $890$33 million and $71 million, net of commissions of $10$0.3 million from the issuanceand $1 million, respectively. As of 26.8December 31, 2018, $295 million common units pursuant to the equity distribution agreement, which were used for general partnership purposes. In March 2015, Sunoco Logistics completed a public offering of 13.5 million common units for net proceeds of $547 million. The proceeds were used to repay outstanding borrowings under the $2.5 billion Sunoco Logistics Credit Facility and for general partnership purposes. In April 2015, an additional 2.0 million common units were issued for net proceeds of $82 million related to the exercise of an option in connection with the March 2015 offering.
In September 2014, Sunoco Logistics completed an overnight public offering of 7.7 million common units for net proceeds of $362 million were used to repay outstanding borrowings under the Sunoco Logistics Credit Facility and for general partnership purposes.
Sales of Common Units by Sunoco LP
In October 2014 and November 2014, Sunoco LP issued an aggregate total of 9.1 million common units in an underwritten public offering. Aggregate net proceeds of $405 million from the offering were used to repay amounts outstanding under the $1.50 billion Sunoco LP Credit Facility and for general partnership purposes.
In July 2015, Sunoco LP completed an offering of 5.5 million Sunoco LP common units remained available to be issued under the currently effective equity distribution agreement.
Sunoco LP’s Unit Issuances 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 as consideration for net proceedsthe 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 $213the outstanding Class A Units held by such subsidiaries. Sunoco LP’s Series A Preferred Units On March 30, 2017, ET 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 net proceeds fromdistribution rate of Sunoco LP Series A Preferred Units is 10.00%, per annum, of the offering$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 ET 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.
USAC’s Distribution Reinvestment Program During the nine months ended December 31, 2018, distributions of $1 million were used to repay outstanding balancesreinvested under the Sunoco LP revolving credit facility.USAC distribution reinvestment program resulting in the issuance of approximately 39,280 USAC common units. ContributionsUSAC’s Warrant Private Placement
On April 2, 2018, USAC issued two tranches of warrants to Subsidiariespurchase USAC common units (the “USAC Warrants”), which included USAC Warrants to purchase 5,000,000 common units with a strike price of $17.03 per unit and USAC Warrants to purchase 10,000,000 common units with a strike price of $19.59 per unit. The USAC Warrants may be exercised by the holders thereof at any time beginning on the one year anniversary of the closing date and before the tenth anniversary of the closing date. Upon exercise of the USAC Warrants, USAC may, at its option, elect to settle the USAC Warrants in common units on a net basis. USAC’s Class B Units The Parent Company indirectly ownsUSAC Class B Units, all of which are owned by ETO, are a new class of partnership interests of USAC that have substantially all of the entire general partner interestrights and obligations of a USAC common unit, except the USAC Class B Units will not participate in ETP through its ownershipdistributions for the first four quarters following the closing date of ETP GP, the general partner of ETP. ETP GP hasUSAC Transaction on April 2, 2018. Each USAC Class B Unit will automatically convert into one USAC common unit on the right, but notfirst business day following the obligation,record date attributable 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 quarter ending June 30, 2019. 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 investmentits interest in Lake Charles LNG.ETO.
Our distributions declared duringand paid with respect to our common units for the years ended December 31, 2015, 2014, and 2013periods presented were as follows: | | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | December 31, 2012 | | February 7, 2013 | | February 19, 2013 | | $ | 0.1588 |
| March 31, 2013 | | May 6, 2013 | | May 17, 2013 | | 0.1613 |
| June 30, 2013 | | August 5, 2013 | | August 19, 2013 | | 0.1638 |
| September 30, 2013 | | November 4, 2013 | | November 19, 2013 | | 0.1681 |
| December 31, 2013 | | February 7, 2014 | | February 19, 2014 | | 0.1731 |
| March 31, 2014 | | May 5, 2014 | | May 19, 2014 | | 0.1794 |
| June 30, 2014 | | August 4, 2014 | | August 19, 2014 | | 0.1900 |
| September 30, 2014 | | November 3, 2014 | | November 19, 2014 | | 0.2075 |
| December 31, 2014 | | February 6, 2015 | | February 19, 2015 | | 0.2250 |
| March 31, 2015 | | May 8, 2015 | | May 19, 2015 | | 0.2450 |
| June 30, 2015 | | August 6, 2015 | | August 19, 2015 | | 0.2650 |
| September 30, 2015 | | November 5, 2015 | | November 19, 2015 | | 0.2850 |
| December 31, 2015 | | February 4, 2016 | | February 19, 2016 | | 0.2850 |
|
| | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | 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 |
| March 31, 2018 | | May 7, 2018 | | May 21, 2018 | | 0.3050 |
| June 30, 2018 | | August 6, 2018 | | August 20, 2018 | | 0.3050 |
| September 30, 2018 | | November 8, 2018 | | November 19, 2018 | | 0.3050 |
| December 31, 2018 | | February 8, 2019 | | February 19, 2019 | | 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. |
ETP’s Quarterly Distributions of Available Cash
ETP’s Partnership Agreement requires that ETP distribute all of its Available Cash to its UnitholdersOur distributions declared 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,paid 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 declaredour Convertible Unit during the periods presented belowyears ended December 31, 2016 and 2017 were as follows:
| | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | 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 |
| March 31, 2015 | | May 8, 2015 | | May 15, 2015 | | 1.0150 |
| June 30, 2015 | | August 6, 2015 | | August 14, 2015 | | 1.0350 |
| September 30, 2015 | | November 5, 2015 | | November 16, 2015 | | 1.0550 |
| December 31, 2015 | | February 8, 2016 | | February 16, 2016 | | 1.0550 |
|
ETE agreed to relinquish its right to the following amounts of incentive distributions in future periods, including distributions on ETP Class I Units: | | | | | | | | | | 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 |
| March 31, 2018 | | May 7, 2018 | | May 21, 2018 | | 0.1100 |
|
| | | | | | | | Total Year | 2016 | | $ | 137 |
| 2017 | | 128 |
| 2018 | | 105 |
| 2019 | | 95 |
|
Sunoco Logistics QuarterlyETO Preferred Unit Distributions of Available Cash
Distributions on the Partnership’s Series A, Series B, Series C and Series D preferred units declared and/or paid by Sunoco Logisticsthe Partnership during the years ended December 31, 2015, 2014, and 2013periods 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 |
| March 31, 2015 | | May 11, 2015 | | May 15, 2015 | | 0.4190 |
| June 30, 2015 | | August 10, 2015 | | August 14, 2015 | | 0.4380 |
| September 30, 2015 | | November 9, 2015 | | November 13, 2015 | | 0.4580 |
| December 31, 2015 | | February 8, 2016 | | February 12, 2016 | | 0.4790 |
|
| | | | | | | | | | | | | | | | | | | | | | | Period Ended | | Record Date | | Payment Date | | Series A (1) | | Series B (1) | | Series C | | Series D | | December 31, 2017 | | February 1, 2018 | | February 15, 2018 | | $ | 15.4510 |
| * | $ | 16.3780 |
| * | $ | — |
| | $ | — |
| | June 30, 2018 | | August 1, 2018 | | August 15, 2018 | | 31.2500 |
| | 33.1250 |
| | 0.5634 |
| * | — |
| | September 30, 2018 | | November 1, 2018 | | November 15, 2018 | | — |
| | — |
| | 0.4609 |
| | 0.5931 |
| * | December 31, 2018 | | February 1, 2019 | | February 15, 2019 | | 31.2500 |
| | 33.1250 |
| | 0.4609 |
| | 0.4766 |
| |
* Represent prorated initial distributions. (1) Series A and Series B preferred unit distributions are paid on a bi-annual basis. Sunoco LP QuarterlyCash Distributions The following table illustrates the percentage allocations of Available Cashavailable 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. | | | | | | | | | | | | 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 on Sunoco LP’s units declared and/or paid 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 |
| 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 |
|
| | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | 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 6, 2018 | | February 14, 2018 | | 0.8255 |
| March 31, 2018 | | May 7, 2018 | | May 15, 2018 | | 0.8255 |
| June 30, 2018 | | August 7, 2018 | | August 15, 2018 | | 0.8255 |
| September 30, 2018 | | November 6, 2018 | | November 14, 2018 | | 0.8255 |
| December 31, 2018 | | February 6, 2019 | | February 14, 2019 | | 0.8255 |
|
USAC Cash Distributions Subsequent to the Energy Transfer Merger and USAC Transactions described in Note 1 and Note 3, respectively, ETO owns approximately 39.7 million USAC common units and 6.4 million USAC Class B units. As of December 31, 2018, USAC had approximately 96.4 million common units outstanding. USAC currently has a non-economic general partner interest and no outstanding incentive distribution rights. Distributions on USAC’s units declared and/or paid by USAC subsequent to the USAC transaction on April 2, 2018 were as follows:
Table of Contents | | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | March 31, 2018 | | May 1, 2018 | | May 11, 2018 | | $ | 0.5250 |
| June 30, 2018 | | July 30, 2018 | | August 10, 2018 | | 0.5250 |
| September 30, 2018 | | October 29, 2018 | | November 09, 2018 | | 0.5250 |
| December 31, 2018 | | January 28, 2019 | | February 8, 2019 | | 0.5250 |
|
Accumulated Other Comprehensive Income (Loss) The following table presents the components of AOCI, net of tax: | | | December 31, | December 31, | | 2015 | | 2014 | 2018 | | 2017 | Available-for-sale securities(1) | $ | — |
| | $ | 3 |
| $ | 2 |
| | $ | 8 |
| Foreign currency translation adjustment | (4 | ) | | (3 | ) | (5 | ) | | (5 | ) | Net losses on commodity related hedges | — |
| | (1 | ) | | Actuarial gain (loss) related to pensions and other postretirement benefits | 8 |
| | (57 | ) | (48 | ) | | (5 | ) | Investments in unconsolidated affiliates, net | — |
| | 2 |
| 9 |
| | 5 |
| Subtotal | 4 |
| | (56 | ) | | Total AOCI, net of tax | | (42 | ) | | 3 |
| Amounts attributable to noncontrolling interest | (4 | ) | | 51 |
| — |
| | (3 | ) | Total AOCI included in partners’ capital, net of tax | $ | — |
| | $ | (5 | ) | $ | (42 | ) | | $ | — |
|
| | (1) | Effective January 1, 2018, the Partnership adopted Accounting Standards Update No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, which resulted in the reclassification of $2 million from accumulated other comprehensive income related to available-for-sale equity securities to common unitholders. |
The table below sets forth the tax amounts included in the respective components of other comprehensive income (loss): | | | December 31, | December 31, | | 2015 | | 2014 | 2018 | | 2017 | Available-for-sale securities | $ | (2 | ) | | $ | (1 | ) | $ | (1 | ) | | $ | (2 | ) | Foreign currency translation adjustment | 4 |
| | 2 |
| 2 |
| | 3 |
| Actuarial (gain) loss relating to pension and other postretirement benefits | 7 |
| | (37 | ) | | Actuarial loss relating to pension and other postretirement benefits | | 12 |
| | 3 |
| Total | $ | 9 |
| | $ | (36 | ) | $ | 13 |
| | $ | 4 |
|
| | 9. | UNIT-BASEDNON-CASH COMPENSATION PLANS: |
ET Non-Cash Compensation Plan We, ETP, Sunoco Logistics and Sunoco LP and USAC, have issued equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase Common Units, restricted units, phantom units, distribution equivalent rights (“DERs”), common unit appreciation rights, cash restricted units and other unit-based awards. ETE Long-Term Incentive Plan
The Board of Directors or the Compensation Committee of the board of directors of the our General Partner (the “Compensation Committee”) may from time to time grant additional awards to employees, directors and consultants of ETE’s general partner and its affiliates who perform services for ETE. The plan provides for the following types of awards: restricted units, phantom units, unit options, unit appreciation rights and distribution equivalent rights. The number of additional units that may be delivered pursuant to these awards is limited to 12,000,000 units. As of December 31, 2015, 11,367,454 units remain available to be awarded under the plan.
On December 23, 2013, ETE and Mr. Welch entered a Class D Unit Agreement providing for the issuance to Mr. Welch of an aggregate of 3,080,000 Class D Units of ETE. Under the terms of the Class D Unit Agreement, as amended, 30% of the Class D Units converted to ETE common units on a one-for-one basis on March 31, 2015, 35% were scheduled to convert to ETE common units on a one-for-one-basis on March 31, 2018, and the remaining 35% were scheduled to convert to ETE common units on a one-for-one basis on March 31, 2020, subject in each case to (i) Mr. Welch being in Good Standing with ETE (as defined in the Class D Unit Agreement) and (ii) there being a sufficient amount of gain available (based on the ETE partnership agreement) to be 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.
Per the terms of the Class D Unit Agreement, 924,000 units converted to ETE common units on a one-for-one basis March 31, 2015. In connection with Mr. Welch’s replacement as Group Chief Financial Officer and Head of Business Development of our General Partner and his termination of employment by an affiliate of ETE, any future conversion of the Class D Units is the subject of on-going discussions between ETE and Mr. Welch in connection with his separation from employment. As of this date, it is ETE’s current position that as a result of Mr. Welch’s termination, the unconverted Class D units are not eligible to be converted.
During 2015, no ETE unit awards were granted to ETE employees and 12,748 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 2015, a total of 26,244 ETE Common Units vested, with a total fair value of $0.8 million as of the vesting date. As of December 31, 2015, excluding Class D units, a total of 56,096 restricted units granted to ETE employees and directors remain outstanding, for which we expect to recognize a total of less than $1 million innon-cash compensation over a weighted average period of 2.7 years.
ETP Unit-Based Compensation Plans
Unit-Based Compensation Plan
ETP has 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, distribution equivalent rights (“DERs”), Common Unit appreciation rights, and other unit-based awards. As of December 31, 2015,2018, an aggregate total of 5.315.1 million ETPET Common Units remain available to be awarded under ETP’sour equity incentive plans.
Restricted UnitsET Long-Term Incentive Plan
ETP hasWe have granted restricted unit awards to employees that vest over a specified time period, typically a five-yearfive-year service vesting requirement, with vesting based on continued employment as of each applicable vesting date. Upon vesting, ETPET Common Units are issued. These unit awards entitle the recipients 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, a cash payment equal to each cash distribution per ETP Common Unit made by ETPus on itsour Common Units promptly following each such distribution by ETPus to itsour Unitholders. We refer to these rights as “distribution equivalent rights.” Under ETP’sour equity incentive plans, ETP’sour non-employee directors each receive grants with a five-yearfive-year service vesting requirement.
The following table shows the activity of the ETP awards granted to employees and non-employee directors: | | | Number of ETP Units | | Weighted Average Grant-Date Fair Value Per ETP Unit | Number of Units | | Weighted Average Grant-Date Fair Value Per Unit | Unvested awards as of December 31, 2014 | 3.5 |
| | $ | 53.83 |
| | Unvested awards as of December 31, 2017 (1) | | 19.5 |
| | $ | 18.03 |
| Awards granted | 2.1 |
| | 35.21 |
| 7.8 |
| | 13.00 |
| Awards vested | (1.2 | ) | | 48.67 |
| (3.5 | ) | | 21.35 |
| Awards forfeited | (0.4 | ) | | 55.44 |
| (1.4 | ) | | 15.16 |
| Conversion of RGP unit awards to ETP unit awards | 0.8 |
| | 58.88 |
| | Unvested awards as of December 31, 2015 | 4.8 |
| | 47.61 |
| | Unvested awards as of December 31, 2018 | | 22.4 |
| | 15.94 |
|
| | (1) | In connection with the Energy Transfer Merger, ET assumed the former ETO plans, including the related unvested awards. Outstanding awards under the former ETO plans are reflected for the entire period above. Amounts related to the period prior to the Energy Transfer Merger are adjusted for the 1.28 to 1 conversion ratio that was applied in the merger. |
During the years ended December 31, 2015, 2014,2018, 2017, and 2013,2016, the weighted average grant-date fair value per unit award granted was $35.21, $60.85$13.00, $17.01 and $50.54,$16.37, respectively. The total fair value of awards vested was $49 million, $26$40 million, and $29$40 million, respectively, based on the market price of ETPthe respective Common Units as of the vesting date. As of December 31, 2015,2018, a total of 4.822 million unit awards remain unvested, for which ETPET expects to recognize a total of $147$228 million in compensation expense over a weighted average period of 2.12.7 years. Cash Restricted Units ETP has alsoUnits. We previously granted cash restricted units, which vest 100% at the end of the third year of service. A cash restricted unit entitlesentitled the award recipient to receive cash equal to the market value of one ETPET Common Unit upon vesting. The Partnership does not currently have any cash restricted units outstanding.
Subsidiary Non-Cash Compensation Plans Each of Sunoco LP and USAC 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 three or five-year period, that entitles 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: | | | | | | | | | | | | | | | | Sunoco LP | | USAC | | 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, 2017 | 1.7 |
| | $ | 31.89 |
| | 1.0 |
| | $ | 14.24 |
| Awards granted | 1.1 |
| | 27.67 |
| | 1.1 |
| | 15.47 |
| Awards vested | (0.4 | ) | | 32.92 |
| | (0.6 | ) | | 14.79 |
| Awards forfeited | (0.3 | ) | | 31.26 |
| | (0.1 | ) | | 17.85 |
| Unvested awards as of December 31, 2018 | 2.1 |
| | 29.15 |
| | 1.4 |
| | 14.98 |
|
The following table summarizes the weighted average grant-date fair value per unit award granted: | | | | | | | | | | | | | | Years Ended December 31, | | 2018 | | 2017 | | 2016 | Sunoco LP | $ | 27.67 |
| | $ | 28.31 |
| | $ | 26.95 |
| USAC | 15.47 |
| | N/A |
| | N/A |
|
The total fair value of Subsidiary Unit Awards vested for the years ended December 31, 2018, 2017 and 2016 was $22 million, $9 million, and $0.1 million, respectively, based on the market price of Sunoco LP and USAC common units as of the vesting date for the years ended December 31, 2018 and Sunoco LP for the years ended December 31, 2017 and 2016. As of December 31, 2015, a total of 0.6 million unvested cash restricted units were outstanding. Based on the trading price of ETP Common Units at December 31, 2015, ETP expects to recognize $7 million of unit-based2018, estimated compensation expensecost related to non-vested cash restricted unitsSubsidiary Unit Awards not yet recognized was $45 million, and the weighted average period over a period of 1.3 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. As of December 31, 2015, a total of 2.5 million Sunoco Logistics
restricted units were outstanding for which Sunoco Logistics expectsthis cost is expected to recognize $52 million ofbe recognized in expense over a weighted-average period of 3.0 years.
Sunoco LP Unit-Based Compensation Plan
Sunoco LP’s general partner has a long-term incentive plan for employees and directors, which permits the grant of restricted units and unit options of Sunoco LP. As of December 31, 2015, a total of 1.1 million Sunoco LP restricted units were outstanding for which Sunoco LP expects to recognize $40 million of expense over a weighted-average period ofis 3.3 years.
As a partnership, we are not subject to U.S.United States federal income tax and most state income taxes. However, the Partnership conducts certain activities through corporate subsidiaries which are subject to federal and state income taxes. The components of the federal and state income tax expense (benefit) of our taxable subsidiaries were summarized as follows: | | | Years Ended December 31, | Years Ended December 31, | | 2015 | | 2014 | | 2013 | 2018 | | 2017 | | 2016 | Current expense (benefit): | | | | | | | | | | | Federal | $ | (292 | ) | | $ | 321 |
| | $ | 51 |
| $ | (8 | ) | | $ | 54 |
| | $ | (47 | ) | State | (51 | ) | | 86 |
| | (1 | ) | 19 |
| | (16 | ) | | (34 | ) | Total | (343 | ) | | 407 |
| | 50 |
| 11 |
| | 38 |
| | (81 | ) | Deferred expense (benefit): | | | | | | | | | | | Federal | 272 |
| | (53 | ) | | (14 | ) | 181 |
| | (2,055 | ) | | (189 | ) | State | (29 | ) | | 3 |
| | 57 |
| (188 | ) | | 184 |
| | 12 |
| Total | 243 |
| | (50 | ) | | 43 |
| (7 | ) | | (1,871 | ) | | (177 | ) | Total income tax expense (benefit) from continuing operations | $ | (100 | ) | | $ | 357 |
| | $ | 93 |
| $ | 4 |
| | $ | (1,833 | ) | | $ | (258 | ) |
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)benefit attributable to continuing operations for the years ended December 31, 20152018, 20142017 and 20132016 is as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2015 | | December 31, 2014 | | December 31, 2013 | | Corporate Subsidiaries(1) | | Consolidated (2) | | Corporate Subsidiaries(1) | | Consolidated (2) | | Corporate Subsidiaries(1) | | Consolidated (2) | Income tax expense (benefit) at U.S. statutory rate of 35 percent | $ | (19 | ) | | $ | (19 | ) | | $ | 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 |
| | — |
| | — |
| Dividend received deduction | (22 | ) | | (22 | ) | | — |
| | — |
| | — |
| | — |
| Premium on debt retirement | — |
| | — |
| | (10 | ) | | (10 | ) | | — |
| | — |
| Audit settlement | (7 | ) | | (7 | ) | | — |
| | — |
| | — |
| | — |
| Foreign taxes | — |
| | — |
| | (8 | ) | | (8 | ) | | — |
| | — |
| State income taxes (net of federal income tax effects) | (45 | ) | | (26 | ) | | 9 |
| | 55 |
| | 31 |
| | 41 |
| Other | (26 | ) | | (26 | ) | | 3 |
| | 3 |
| | (16 | ) | | (17 | ) | Income tax expense (benefit) from continuing operations | $ | (119 | ) | | $ | (100 | ) | | $ | 311 |
| | $ | 357 |
| | $ | 84 |
| | $ | 93 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2018 | | 2017 | | 2016 | Income tax expense at United States statutory rate | $ | 763 |
| | $ | 248 |
| | $ | 71 |
| Increase (reduction) in income taxes resulting from: | | | | | | Partnership earnings not subject to tax | (635 | ) | | (477 | ) | | (576 | ) | Goodwill impairment | — |
| | 207 |
| | 278 |
| State tax, net of federal tax benefit | (125 | ) | | 124 |
| | (10 | ) | Dividend received deduction | (5 | ) | | (14 | ) | | (15 | ) | Federal rate change | — |
| | (1,812 | ) | | — |
| Change in tax status of subsidiary | — |
| | (124 | ) | | — |
| Other | 6 |
| | 15 |
| | (6 | ) | Income tax expense (benefit) from continuing operations | $ | 4 |
| | $ | (1,833 | ) | | $ | (258 | ) |
| | (1)
| Includes ETP Holdco, Susser Holdings Corporation, Oasis Pipeline Company, Susser Petroleum Property Company LLC, Aloha Petroleum Ltd, Pueblo, Inland Corporation, Mid-Valley Pipeline Company and West Texas Gulf Pipeline Company.
|
| | (2)
| Includes ETE and its subsidiaries that are classified as pass-through entities for federal income tax purposes, as well as corporate subsidiaries. |
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, | | 2015 | | 2014 | 2018 | | 2017 | Deferred income tax assets: | | | | | | | Net operating losses and alternative minimum tax credit | $ | 217 |
| | $ | 116 |
| | Net operating losses, alternative minimum tax credit and other carryforwards | | $ | 768 |
| | $ | 683 |
| Pension and other postretirement benefits | 36 |
| | 47 |
| 34 |
| | 21 |
| Long term debt | 61 |
| | 53 |
| | Long-term debt | | 13 |
| | 14 |
| Other | 162 |
| | 111 |
| 181 |
| | 191 |
| Total deferred income tax assets | 476 |
| | 327 |
| 996 |
| | 909 |
| Valuation allowance | (121 | ) | | (84 | ) | (96 | ) | | (189 | ) | Net deferred income tax assets | 355 |
| | 243 |
| 900 |
| | 720 |
| | | | | | | | Deferred income tax liabilities: | | | | | | | Properties, plants and equipment | (1,633 | ) | | (1,583 | ) | | Inventory | — |
| | (153 | ) | | Property, plant and equipment | | (782 | ) | | (1,036 | ) | Investments in unconsolidated affiliates | (2,976 | ) | | (2,530 | ) | (2,872 | ) | | (2,726 | ) | Trademarks | (286 | ) | | (355 | ) | (63 | ) | | (173 | ) | Other | (50 | ) | | (32 | ) | (109 | ) | | (100 | ) | Total deferred income tax liabilities | (4,945 | ) | | (4,653 | ) | (3,826 | ) | | (4,035 | ) | Accumulated deferred income taxes | $ | (4,590 | ) | | $ | (4,410 | ) | | Net deferred income taxes | | $ | (2,926 | ) | | $ | (3,315 | ) |
As a result of the early adoption and retrospective application of ASU 2015-17 (see Note 2), $85 million of deferred tax liability previously presented as an other current liability as of December 31, 2014 has been reclassified to other non-current liabilities in our consolidated financial statements. The completion of the Southern Union Merger, Sunoco Merger,2018, ETP Holdco Transaction and Susser Merger (see Note 3) significantly increased the deferred tax assets (liabilities). The table below provideshad a rollforward of the net deferred income tax liability as follows:
| | | | | | | | | | December 31, | | 2015 | | 2014 | Net deferred income tax liability, beginning of year | $ | (4,410 | ) | | $ | (3,984 | ) | Susser acquisition | — |
| | (488 | ) | Tax provision (including discontinued operations) | (242 | ) | | 62 |
| Other | 62 |
| | — |
| Net deferred income tax liability | $ | (4,590 | ) | | $ | (4,410 | ) |
ETP Holdco, Susser Petroleum Property Company and certain other corporate subsidiaries have federal net operating loss carryforward tax benefits of $67 million, all$2.60 billion, of which $1.80 billion will expire in 20332031 through 2034.2037 while the remaining can be carried forward indefinitely. As of December 31, 2017, Sunoco Property Company LLC, a corporate subsidiary of Sunoco LP, had a federal net operating loss carryforward of $364 million. The entire net operating loss carryforward will be fully utilized to offset the taxable gain associated with the retail divestment in 2018.
Our corporate subsidiaries have $31 million of federal alternative minimum tax credits at December 31, 2018, of which $16 million is expected to be reclassified to current income tax receivable in 2019 pursuant to the Tax Cuts and Jobs Act. Our corporate subsidiaries have state net operating loss carryforward benefits of $123$168 million, net of federal tax, which expire between 20162019 and 2035. The2037. A valuation allowance of $121$98 million is applicable to the state net operating loss carryforward benefits applicableprimarily attributable 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, | | 2015 | | 2014 | | 2013 | 2018 | | 2017 | | 2016 | Balance at beginning of year | $ | 440 |
| | $ | 429 |
| | $ | 27 |
| $ | 609 |
| | $ | 615 |
| | $ | 610 |
| Additions attributable to tax positions taken in the current year | 178 |
| | 20 |
| | — |
| 8 |
| | — |
| | 8 |
| Additions attributable to tax positions taken in prior years | — |
| | (1 | ) | | 406 |
| 7 |
| | 28 |
| | 18 |
| Settlements | — |
| | (5 | ) | | — |
| | Reduction attributable to tax positions taken in prior years | | — |
| | (25 | ) | | (20 | ) | Lapse of statute | (8 | ) | | (3 | ) | | (4 | ) | — |
| | (9 | ) | | (1 | ) | Balance at end of year | $ | 610 |
| | $ | 440 |
| | $ | 429 |
| $ | 624 |
| | $ | 609 |
| | $ | 615 |
|
As of December 31, 2015,2018, we have $588$620 million ($550588 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 ($3 million, net of federal tax) within the next twelve months due to settlement of certain positions. Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During 2015,2018, we recognized interest and penalties of less than $1$6 million. At December 31, 2015,2018, we have interest and penalties accrued of $5$15 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 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 for the 2004 through 2009 years. Sunoco, Inc.’s 2010 and 2011 years are extended for this issue with the IRS. In November 2016, the CFC ruled against Sunoco, Inc., and the United States Court of Appeals for the Federal Circuit (the “Federal Circuit”) affirmed the CFC’s ruling on November 1, 2018. Sunoco, Inc. subsequently filed a petition for rehearing with the Federal Circuit, and this was denied on January 24, 2019. Sunoco, Inc. is considering further review of the Federal Circuit’s affirmation of the CFC’s ruling. If Sunoco, Inc. is ultimately fully successful with its claims,in this litigation, it will receive tax refunds of approximately $519$530 million. However, due to the uncertainty surrounding the claims,litigation, a reserve of $519$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 sheetsheets as of December 31, 2015.2018 and 2017. In December ofNovember 2015, Thethe Pennsylvania Commonwealth Court determined in Nextel Communications v. Commonwealth (“Nextel”Nextel”) that the Pennsylvania limitation on NOL carryforwardscarryforward deductions violated the uniformity clause of the Pennsylvania Constitution. Based uponConstitution and struck the NOL limitation in its entirety. In October 2017, the Pennsylvania Supreme Court affirmed the decision 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 subsequently filed a petition for writ of certiorari with the United States Supreme Court, and this was denied on June 11, 2018. Now certain Pennsylvania taxpayers are proceeding with litigation in Pennsylvania state courts on issues not addressed by the Pennsylvania Supreme Court in Nextel,, specifically, whether the Due Process and Equal Protection Clauses of the United States Constitution and the Remedies Clause of the Pennsylvania Constitution require a court to grant the taxpayer relief. Sunoco, Inc. is recognizinghas recognized approximately $46$67 million ($3053 million after federal income tax benefits) in tax benefit based on previously filed tax returns and certain previously filed protective claims.claims as relates to its cases currently held pending the Nextel matter. However, asbased upon the NextelPennsylvania Supreme Court’s October 2017 decision, is subject to appeal, and because of uncertainty in the breadth of the application of the decision, we have reserved $9$34 million ($627 million after federal income tax benefits) against the receivable. In general, ETE and its subsidiaries are no longer subject to examination by the Internal Revenue Service (“IRS”), and most state jurisdictions, for the 2012 and prior tax years. However, Sunoco, Inc.ET and its subsidiaries are no longer subject to examination by the IRS, and most state jurisdictions, for the 2013 and prior tax years. However, Sunoco, Inc. and its subsidiaries remain subject to examination by the IRS for tax years prior tobeginning in 2007. Sunoco, Inc. has been examined by the IRS for tax years through October 4, 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 was under examination by the IRS for the tax years 2004 through 2009. In July 2015, we and the IRS settled all issues related to the IRS examination of the 2004 through 2009 tax years. As a result of the settlement, we recognized a net tax benefit of $7 million.
ETEET 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 $1.81 billion in December 2017. For the year ended December 31, 2018, the Partnership recorded an income tax expense due to pre-tax income at its corporate subsidiaries, partially offset by a state statutory rate reduction. | | 11. | REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES: |
Contingent Matters Potentially ImpactingFERC Proceedings
In March 2016, the PartnershipFERC commenced an audit of Trunkline for the period from Our Investment in Citrus Florida Gas Pipeline Relocation Costs. The Florida DepartmentJanuary 1, 2013 to present to evaluate Trunkline’s compliance with the requirements 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 areits FERC gas tariff, the subject of
litigation in Broward County, Florida. On November 16, 2012, FDOT paid to FGT the sum of approximately $100 million, representing the amountaccounting regulations of the judgment, plus interest,Uniform System of Accounts as prescribed by the FERC, and the FERC’s annual reporting requirements. The FERC issued an audit report in October 2018. In response to the findings in the audit report, the Company expects to make certain changes to its processes, policies and procedures; however, the Company does not expect the findings to result in any changes to its financial statements.
By order issued January 16, 2019, the FERC initiated 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 resultreview of Panhandle’s existing rates pursuant to Section 5 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 pursuantNatural Gas Act to which, among other things, FDOT/FTE paid FGT approximately $19 million in September 2013 in settlement of FGT’s claims with respect todetermine whether 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 reimbursedrates currently charged 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’s 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.
Guarantee of Collection
Panhandle previously guaranteed the collections of the payment of $600 million of Regency 4.50% senior notes due 2023. On May 28, 2015, ETP entered into a supplemental indenture relating to the senior notes pursuant to which it has agreed to become a co-obligor with respect to the payment obligations thereunder. Accordingly, pursuant to the terms of the senior notes, Panhandle’s obligations under the Panhandle Guarantee have been released. On April 30, 2015, in connection with the Regency Merger, ETP entered into various supplemental indentures pursuant to which ETP had agreed to fully and unconditionally guarantee all payment obligations of Regency for all of its outstanding senior notes.
On May 28, 2015, ETP entered into a supplemental indenture relating to the senior notes pursuant to which it has agreed to become a co-obligor with respect to the payment obligations thereunder. Accordingly, pursuant to the terms of the senior notes, Panhandle’s obligations under the Panhandle Guarantee have been released.
ETP Retail Holdings Guarantee of Sunoco LP Notes
In April 2015, Sunoco LP acquired a 31.58% equity interest in Sunoco, LLC from Retail Holdings for $775 million of cash and $41 million of Sunoco LP common units. The cash portion of the consideration was financed through Sunoco LP’s issuance of $800 million principal amount of 6.375% senior notes due 2023. Retail Holdings entered into a guarantee of collection with Sunoco LP and Sunoco Finance Corp., a wholly owned subsidiary of Sunoco LP, pursuant to which Retail Holdings has agreed to provide a guarantee of collection, but not of payment, to Sunoco LP with respect to the principal amount of the senior notes issued by Sunoco LP.
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 beare just and reasonable and not unduly discriminatoryset the matter for hearing. Panhandle must file a cost and pipelines may not confer any undue preference. The tariff rates established for interstate services were basedrevenue study on a negotiated agreement; however,or before April 1, 2019. An initial decision is expected to be issued in the FERC’s rate-making methodologies may limit our ability to set rates basedfirst quarter of 2020.In addition, 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, TranswesternNovember 30, 2018, Sea Robin filed a general NGA Section 4 rate case pursuant to Section 4 of the 2011 settlement agreement with its shippers. On December 2, 2014,Natural Gas Act. A hearing date is scheduled for October 23, 2019 and an initial decision is expected to be issued in the first quarter of 2020.
By order issued February 19, 2019, the FERC issued an order accepting and suspendinginitiated a review of Southwest Gas Storage Company’s existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates tocurrently charged by Southwest Gas Storage Company are just and reasonable and set the matter for hearing. Southwest Gas Storage Company must file a cost and revenue study on or before May 6, 2019. The FERC is directing that an initial decision be effective April 1, 2015, subject to refund,issued within 47 weeks of the date the cost and setting a procedural schedule with a hearing scheduled in late 2015. On June 22, 2015, Transwestern
filed a settlement with the FERC which resolved or provided for the resolution of all issues set for hearing in the case. On October 15, 2015, the FERC issued an order approving the rate case settlement without condition.
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 no earlier than May 1, 2015, subject to refund. On September 11, 2015, FGT filed a settlement with the FERC which resolved or provided for the resolution of all issues set for hearing in the case. On December 4, 2015, the FERC issued an order approving the rate case settlement without condition.
Sea Robin Rate Case
On December 2, 2013, Sea Robin filed a general NGA Section 4 rate case at the FERC as required by a previous rate case settlement. In the filing, Sea Robin sought to increase its authorized rates to recover costs related to asset retirement obligations, depreciation, and return and taxes. Filed rates were put into effect June 1, 2014 and estimated settlement rates were put into effect September 1, 2014, subject to refund. A settlement was reached with the shippers and a stipulation and agreement was filed with the FERC on July 23, 2014. The settlement was certified to the FERC by the administrative law judge on October 7, 2014 and the settlement, as modified on January 16, 2015, was approved by the FERC on June 26, 2015. In September 2015, related to the final settlement, Sea Robin made refunds to customers totaling $11 million, including interest.revenue study is due.
Commitments In the normal course of business, ETPETO 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 believeETO 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. Our joint venture agreements require that we funds our proportionate share of capital contributions to its unconsolidated affiliates. Such contributions will depend upon our 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 2058.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, | | | 2015 | | 2014 | | 2013 | Rental expense(1) | | $ | 225 |
| | $ | 159 |
| | $ | 151 |
| Less: Sublease rental income | | (16 | ) | | (26 | ) | | (24 | ) | Rental expense, net | | $ | 209 |
| | $ | 133 |
| | $ | 127 |
|
| | | | | | | | | | | | | | | | Years Ended December 31, | | | 2018 | | 2017 | | 2016 | Rental expense(1) | | $ | 139 |
| | $ | 171 |
| | $ | 161 |
| Sublease rental income(2) | | 40 |
| | 25 |
| | 26 |
| Net | | $ | 99 |
| | $ | 146 |
| | $ | 135 |
|
| | (1) | Includes contingent rentals totaling $26$4 million, $24$16 million and $22$18 million for the years ended December 31, 2015, 20142018, 2017 and 2013,2016, respectively. |
| | (2) | Sublease rental income is included in other revenues in the accompanying statements of operations. |
Future minimum lease commitments for such leases are: | | Years Ending December 31: | | | 2016 | $ | 121 |
| | 2017 | 114 |
| | 2018 | 103 |
| | 2019 | 96 |
| $ | 104 |
| 2020 | 97 |
| 95 |
| 2021 | | 74 |
| 2022 | | 58 |
| 2023 | | 50 |
| Thereafter | 602 |
| 220 |
| Future minimum lease commitments | 1,133 |
| 601 |
| Less: Sublease rental income | (34 | ) | (111 | ) | Net future minimum lease commitments | $ | 1,099 |
| $ | 490 |
|
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.
LitigationCommon Units
The change in ET Common Units during the years ended December 31, 2018, 2017 and Contingencies2016 was as follows: 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 | | | | | | | | | | | Years Ended December 31, | | 2018 | | 2017 | | 2016 | Number of Common Units, beginning of period | 1,079.1 |
| | 1,046.9 |
| | 1,044.8 |
| Conversion of ET Series A Convertible Preferred Units to common units | 79.1 |
| | — |
| | — |
| Common Unit increase from Energy Transfer Merger | 1,458.9 |
| | — |
| | — |
| Issuance of common units | 2.3 |
| | 32.2 |
| | 2.1 |
| Number of Common Units, end of period | 2,619.4 |
| | 1,079.1 |
| | 1,046.9 |
|
In October 2018, ET issued 1.46 billion ET Common Units in connection with the Energy Transfer Merger. ET 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, 2018. ET Series A Convertible Preferred Units In May 2018, the Partnership converted its 329.3 million Series A Convertible Preferred Units into approximately 79.1 million ET common units in accordance with the terms of ET’s partnership agreement. ET Class A Units In connection with the Energy Transfer Merger, the Partnership issued 647,745,099 Class A units (“ET Class A Units”) representing limited partner interests in the Partnership to LE GP, LLC (“LE GP”), the general partner of ET. The number of ET Class A Units issued allows LE GP and its affiliates to retain a voting interest in the Partnership that is identical to their transportation, storage or use. Invoting interest in the ordinary coursePartnership prior to the completion of business, wethe Merger. The ET Class A Units are sometimes threatenedentitled to vote together with or namedthe Partnership’s common units, as a defendantsingle class, except as required by law. Additionally, ET’s partnership agreement provides that, under certain circumstances, upon the issuance by the Partnership of additional common units or any securities that have voting rights that are pari passu with the Partnership common units, the Partnership will issue to any holder of ET Class A Units additional ET Class A Units such that the holder maintains a voting interest in various lawsuits seeking actualthe Partnership that is identical to its voting interest in the Partnership prior to such issuance. The ET Class A Units are not entitled to distributions and punitive damagesotherwise have no economic attributes. 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 ET 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 no ET Common Units under this program in 2018, 2017 or 2016 and there was $936 million available to use under the program as of December 31, 2018. Class D Units In 2013, the Partnership issued 3,080,000 Class D Units of ET pursuant to an agreement with a former executive. The Class D Units were convertible to ET 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 product liability, personal injurythe difference between the carrying amount of its investment in subsidiaries and property damage. We maintain liability insurancethe 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.
ETO Class E Units There were previously 8.9 million Class E Units outstanding, all of which were owned by HHI. The Class E Units were 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 were owned by a wholly-owned subsidiary, the cash distributions on those units were eliminated in our consolidated financial statements. On December 31, 2018, the Class E units were converted to Class L units, as described below. ETO Class G Units There were previously 90.7 million Class G Units outstanding, all of which were held by a wholly-owned subsidiary of the Partnership. The Class G Units were 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 were based on a predetermined percentage and are not contingent on whether ETO has net income or loss. These units were reflected as treasury units in the consolidated financial statements. On December 31, 2018, the Class G units were converted to Class L units, as described below. ETO Class H Units The ETO Class H Units were generally entitled to (i) allocations of profits, losses and other items from ETO corresponding to 90.05% of the profits, losses, and other items allocated to ETO by Sunoco Partners with insurersrespect to the IDRs and general partner interest in amountsSunoco Logistics held by Sunoco Partners and (ii) distributions from available cash at ETO for each quarter equal to 90.05% of the cash distributed to ETO by Sunoco Partners with coveragerespect to the IDRs and deductibles management believes are reasonablegeneral partner interest in Sunoco Logistics held by Sunoco Partners for such quarter and, prudent,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 ETO and whichSunoco Logistics in April 2017. ETO Class I Units In connection with the Bakken Pipeline Transaction discussed in Note 3, in March 2015, ETO issued 100 ETO Class I Units. The ETO Class I Units are generally accepted inentitled to: (i) pro rata allocations of gross income or gain until the industry. However, there can be no assurance thataggregate amount of such items allocated to the levelsholders of insurance protection currently in effect will continuethe ETO 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 ETO Class I Units and (ii) after making cash distributions to ETO Class H Units, any additional available cash deemed to be available at reasonable priceseither operating surplus or that such levelscapital surplus with respect to any quarter will remain adequatebe distributed to protect us from material expenses relatedthe Class I Units in an amount equal to product liability, personal injury or property damage in the future. MTBE Litigation
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 in allexcess of the cases are seekingdistribution amount set forth in ETO’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 Class I Units were cancelled in connection with the Energy Transfer Merger in October 2018.
Bakken Equity Sale In February 2017, Bakken Holdings Company LLC, an entity in which ETO indirectly owns a 100% membership interest, sold a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to recover compensatory damages,MarEn Bakken Company LLC, an entity jointly owned by MPLX LP and Enbridge Energy Partners, L.P., for $2.00 billion in some cases also seek natural resource damages, injunctive relief, punitive damagescash. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access and attorneys’ fees.ETCO. The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETO continues to consolidate Dakota Access and ETCO subsequent to this transaction. ETO Class K Units On December 29, 2016, ETO issued to certain of its indirect subsidiaries, in exchange for cash contributions and the exchange of outstanding common units representing limited partner interests in ETO, Class K Units, each of which is entitled to a quarterly cash distribution of $0.67275 per Class K Unit prior to ETO making distributions of available cash to any class of units, excluding any cash available distributions or dividends or capital stock sales proceeds received by ETO from ETO Holdco. If ETO 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, 2015, Sunoco, Inc. is2018, a defendant in six cases, including cases initiatedtotal of 101.5 million Class K Units were held by the Stateswholly-owned subsidiaries of New Jersey, Vermont, the CommonwealthETO.
ETO Class L Units On December 31, 2018, ETO issued a new class of Pennsylvania, andlimited partner interests titled Class L Units to 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, and one case by the City of Breaux Bridge in the USDC Western District of Louisiana. 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 subjectwholly-owned subsidiaries of the first trial phase in the New Jersey case and the initial Puerto Rico case. In November 2015, Sunoco along with other co-defendants agreed to a global settlement in principle of the City of Breaux Bridge MTBE 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 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 onPartnership when the Partnership’s consolidated financial position.
Regency Merger Litigation
Following the January 26, 2015 announcement of the definitive merger agreement with Regency, purported Regency unitholders filed lawsuits in stateoutstanding Class E units and federal courts in Dallas, Texas and Delaware state court asserting claims relating to the proposed transaction.
On February 3, 2015, William Engel and Enno Seago, purported Regency unitholders, filed a class action petition on behalf of Regency’s common unitholders and a derivative suit on behalf of Regency in the 162nd Judicial District Court of Dallas County, Texas (the “Engel Lawsuit”). The lawsuit names as defendants the Regency General Partner, the members of the Regency General Partner’s board of directors, ETP, ETP GP, ETE, and, as a nominal party, Regency. The Engel Lawsuit alleges that (1) the Regency General Partner’s directors breached duties to Regency and the Regency’s unitholdersClass G units held by employing a conflicted and unfair process and failing to maximize the merger consideration; (2) the Regency 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 Regency unitholder, filed a class action petition on behalf of the Regency’s common unitholders and a derivative suit on behalf of Regency 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 Regency unitholder, filed a class action petition on behalf of Regency’s common unitholders and a derivative suit on behalf of Regency 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 Regency unitholder, filed a class action complaint on behalf of the Regency’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 Regency as a defendant rather than a nominal party. The lawsuit also omits one of the Regency General Partner’s directors, Richard Brannon, who was named in the Engel Lawsuit. The Blankman Lawsuit alleges that the Regency General Partner’s directors breached their fiduciary duties to the unitholders by failing to maximize the value of Regency, failing to properly value Regency, 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 Regency unitholder, filed a class action complaint on behalf of Regency’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 March 27, 2015, Plaintiff Bazini filed an amended complaint asserting additional claims under Sections 14(a) and 20(a) of the Securities Exchange Act of 1934.
On February 11, 2015, Mark Hinnau, a purported Regency unitholder, filed a class action complaint on behalf of Regency’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 Regency unitholder, filed a class action complaint on behalf of Regency’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 Regency unitholder, filed a class action complaint on behalf of Regency’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 Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Berlin Lawsuit”). The allegations, claims, and relief sought in the Berlin Lawsuit are similar to those in the Blankman Lawsuit.
On March 13, 2015, the Court in the 95th Judicial District Court of Dallas County, Texas transferred and consolidated the Yeager and Coggia Lawsuitssuch subsidiaries were converted into the Engel Lawsuit and captioned the consolidated lawsuit as Engel v. Regency GP, LP, et al. (the “Consolidated State Lawsuit”).
On March 30, 2015, Leonard Cooperman, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Cooperman Lawsuit”). The allegations, claims, and relief sought in the Cooperman Lawsuit are similar to those in the Blankman Lawsuit.
On March 31, 2015, the Court in United States District Court for the Northern District of Texas consolidated the Blankman, Bazini, Hinnau, Weaver, Dieckman, and Berlin Lawsuits into a consolidated lawsuit captioned Bazini v. Bradley, et al. (the “Consolidated Federal Lawsuit”). On April 1, 2015, plaintiffs in the Consolidated Federal Lawsuit filed an Emergency Motion to Expedite Discovery. On April 9, 2015, by order of the Court, the parties submitted a joint submission wherein defendants opposed plaintiffs’ request to expedite discovery. On April 17, 2015, the Court denied plaintiffs’ motion to expedite discovery.
On June 10, 2015, Adrian Dieckman, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the Court of Chancery of the State of Delaware (the “Dieckman DE Lawsuit”). The lawsuit alleges that the transaction did not comply with the Regency partnership agreement because the Conflicts Committee was not properly formed.
On July 6, 2015, Defendants filed Motions to Dismiss and the briefing has since been completed. Oral argument on the Motions was held in December 2015. On September 29, 2015, Chancellor Bouchard ordered discovery stayed, pending a ruling on Defendants’ Motions to Dismiss.
On June 5, 2015, the Dieckman Lawsuit was dismissed. On July 23, 2015, the Blankman, Bazini, Hinnau, Weaver and Berlin Lawsuits were dismissed. On August 20, 2015, the Cooperman Lawsuit was dismissed. The Consolidated Federal Lawsuit was terminated once all named plaintiffs voluntarily dismissed.
On January 8, 2016, the plaintiffs in the Consolidated State Lawsuit filed a notice of non-suit without prejudice. The Dieckman DE Lawsuit is the only lawsuit that remains. The Defendants cannot predict the outcome of this lawsuit, or the amount of time and expense that will be required to resolve it. The Defendants intend to vigorously defend the lawsuit.
Enterprise Products Partners, L.P. and Enterprise Products Operating LLC Litigation
On January 27, 2014, a trial commenced between ETP against Enterprise Products Partners, L.P. and Enterprise Products Operating LLC (collectively, “Enterprise”) and Enbridge (US) Inc. Trial resulted in a verdict in favor of ETP against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETP. The jury also found that ETP owed Enterprise $1 million under a reimbursement agreement. On July 29, 2014, the trial court entered a final judgment in favor of ETP and awarded ETP $536 million, consisting of compensatory damages, disgorgement, and pre-judgment interest. The trial court also ordered that ETP shall be entitled to recover post-judgment interest and costs of court and that Enterprise is not entitled to any net recovery on its counterclaims. Enterprise has filed a notice of appeal with the Texas Court of Appeals, and briefing by Enterprise and ETP is compete. Oral argument has not been scheduled. In accordance with GAAP, no amounts related to the original verdict or the July 29, 2014 final judgment will be recorded in our financial statements until the appeal process is completed.
Litigation Relating to the WMB Merger
Following the September 28, 2015, announcement of the proposed merger between ETE and WMB, purported WMB shareholders filed lawsuits in state and federal courts in Delaware and federal court in Oklahoma asserting claims relating to the proposed transaction.
Between October 5, 2015 and December 15, 2015, purported WMB stockholders filed five putative class action lawsuits against ETE and other defendants in the Delaware Court of Chancery challenging the merger. The suits were captioned Greenwald v. The Williams Companies, Inc., C.A. No. 11573, Ozaki v. Armstrong, C.A. No. 11574, Blystone v. The Williams Companies, Inc., C.A. No. 11601, Glener v. The Williams Companies, Inc., C.A. No. 11606, and Amaitis v. Armstrong, C.A. No. 11809. The complaints named as defendants the WMB Board, ETE, ETC, Energy Transfer Corp GP, LLC, General Partner, and Energy Transfer Equity GP, LLC (collectively, with the exception of the WMB board, the “ETE Defendants”). The Greenwald, Blystone and Glener complaints named WMB as a defendant also, and the Amaitis complaint named Barclays Capital Inc. (“Barclays”), and Lazard Freres & Co. (“Lazard”) as defendants. The Greenwald, Ozaki, Blystone and Glener complaints alleged that the WMB Board breached its fiduciary duties to WMB stockholders by agreeing to sell WMB through an unfair process and for an unfair price, and that the other named defendants aided and abetted this supposed breach of fiduciary duties. The Amaitis complaint alleged that the WMB Board breached its fiduciary duties by failing to disclose all material information about the merger, and that the directors of the WMB Board who voted in favor of the proposed merger violated their fiduciary duties by selling WMB through an unfair process and for an unfair price. The Amaitis complaint also alleged that the other named defendants aided and abetted these supposed breaches of fiduciary duty. The complaints sought, among other things, an injunction against the merger and an award of costs and attorneys’ fees.
On January 13, 2016, the Delaware Court of Chancery consolidated, pursuant to a stipulation among the plaintiffs, the Greenwald, Ozaki, Blystone, Glener, and Amaitis actions, along with another case not involving the ETE Defendants, into a new consolidated action captioned In re The Williams Companies, Inc. Merger Litigation, Consolidated C.A. No. 11844. In its stipulated order, the Court dismissed without prejudice the ETE Defendants, Barclays and Lazard from the consolidated action. There currently are no lawsuits related to the WMB merger pending against the ETE Defendants in Delaware state court.
ETE is currently a defendant in two lawsuits in federal district court challenging the proposed merger with WMB. On January 14, 2016, a purported stockholder in WMB filed a lawsuit against WMB and ETE, captioned Bumgarner v. The Williams Companies, Inc., Case No. 16-cv-26-GKF-FHM, in the United States District Court for the Northern District of Oklahoma. The plaintiff alleges that ETE and WMB have violated Section 14 of the Securities Exchange Act of 1934 (the “Exchange Act”) by making allegedly false representations concerning the merger. As relief, the complaint seeks an injunction against the proposed merger. On February 1, 2016, the plaintiff amended his complaint. On February 19, 2016, ETE and WMB moved to dismiss the lawsuit.
On January 19, 2016, a purported stockholder in WMB filed a lawsuit against WMB, the WMB Board, and the ETE Defendants, captioned City of Birmingham Retirement and Relief System v. Armstrong, Case No. 1:16-cv-00017-RGA, in the United States District Court for the District of Delaware. The lawsuit alleges that the WMB Board has violated its duty of disclosure by issuing a misleading proxy statement in support of the transaction, that a majority of the WMB Board violated its fiduciary duties by voting in favor of the transaction, and that the ETE Defendants aided and abetted this supposed breach of fiduciary duties. The complaint also alleges that the WMB Board and WMB have violated Section 14 of the Exchange Act by issuing a supposedly misleading proxy statement, and that WMB and ETE have violated Section 20 of the Exchange Act by supposedly causing a misleading proxy statement to be issued. On January 20, 2016, the plaintiff filed a motion for expedited discovery, and all defendants filed an opposition to that motion on February 8, 2016. On February 19, plaintiff filed a reply brief in support of expedited discovery. On February 10, 2016, WMB and the WMB Board filed a motion to dismiss the complaint, and on February 18, 2016, the ETE Defendants filed a motion to dismiss the complaint.
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, 2015 and 2014, accruals of approximately $40 million and $37 million, respectively, were reflected on our 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, 2015 or 2014 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.
Compliance Orders from the New Mexico Environmental Department
Regency received a Notice of Violation from the New Mexico Environmental Department on September 23, 2015 for allegations of violations of New Mexico air regulations related to Jal #3. The Partnership has accrued $250,000 related to the claims and will continue to assess its potential exposure to the allegations as the matter progresses.
Lone Star NGL Fractionators Notice of Enforcement
Lone Star NGL Fractionators received a Notice of Enforcement from the Texas Commission on Environmental Quality on August 28, 2015 for allegations of violations of Texas air regulations related to Mont Belvieu Gas Plant. The Partnership has accrued $300,000 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 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.Class L Units. As a result there can be no assurance that significant costsof the conversion, the Class E units 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 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.
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, 2015, Sunoco, Inc. had been named as a PRP at approximately 50 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.Class G units were cancelled.
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, weClass L Units generally do not have any material environmental matters assessed as reasonably possible that would require disclosurevoting rights. The Class L Units are entitled to aggregate cash distributions equal to 7.65% per annum of the total amount of cash generated by us and our subsidiaries, other than ETP Holdco, and available for distribution. Distributions shall be paid quarterly, in arrears, within 45 days after the end of each quarter. As the Class L Units are owned by a wholly-owned subsidiary, the cash distributions on those units are eliminated in our consolidated financial statements. Sales of Common Units by Sunoco Logistics | | | | | | | | | | December 31, | | 2015 | | 2014 | Current | $ | 42 |
| | $ | 41 |
| Non-current | 326 |
| | 360 |
| Total environmental liabilities | $ | 368 |
| | $ | 401 |
|
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 2013, we establishedSeptember and October 2016, a wholly-owned captive insurance companytotal 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 bear certain risks associated with environmental obligations relatedpartially fund the acquisition from Vitol. ETO Preferred Units In November 2017, ETO 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. In April 2018, ETO issued 18 million of its 7.375% Series C Preferred Units at a price of $25 per unit. In July 2018, ETO issued 17.8 million of its 7.625% Series D Preferred Units at a price of $25 per unit. Subsequent to certain sites thatthe Energy Transfer Merger, all of ETO’s Series A, Series B, Series C and Series D Preferred Units remain outstanding. ETO Series A Preferred Units 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 ETO’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. ETO Series B Preferred Units 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 ETO’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. ETO Series C Preferred Units Distributions on the Series C Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, May 15, 2023, at a rate of 7.375% per annum of the stated liquidation preference of $25. On and after May 15, 2023, distributions on the Series C Preferred Units will accumulate at a percentage of the $25 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.530% per annum. The Series C Preferred Units are redeemable at ETO’s option on or after May 15, 2023 at a redemption price of $25 per Series C Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
ETO Series D Preferred Units Distributions on the Series D Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, August 15, 2023, at a rate of 7.625% per annum of the stated liquidation preference of $25. On and after August 15, 2023, distributions on the Series D Preferred Units will accumulate at a percentage of the $25 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.738% per annum. The Series D Preferred Units are redeemable at ETO’s option on or after August 15, 2023 at a redemption price of $25 per Series D 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, ETO purchased all of the outstanding PennTex common units not previously owned by ETO for $20.00 per common unit in cash. ETO now owns all of the economic interests of PennTex, and PennTex common units 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 basedpublicly traded or listed on the discounted estimates that areNASDAQ. Subsidiary Equity Transactions Sunoco LP’s Common Unit Repurchase 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 ETO for aggregate cash consideration of approximately $540 million. ETO used the proceeds from the sale of the Sunoco LP common units to developrepay amounts outstanding under its revolving credit facility. Sunoco LP’s Equity Distribution Program 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. For the premiums paid to the captive insurance company. Duringyear ended December 31, 2018, Sunoco LP issued no additional units under its ATM program. For the years ended December 31, 20152017 and 2014, the Partnership recorded $382016, Sunoco LP issued an additional 1.3 million and $482.8 million respectively,units with total net proceeds of expenditures related$33 million and $71 million, net of commissions of $0.3 million and $1 million, respectively. As of December 31, 2018, $295 million of Sunoco LP common units remained available to environmental cleanup programs.be issued under the currently effective equity distribution agreement.
Sunoco LP’s Unit Issuances On December 2, 2010,March 31, 2016, Sunoco Inc. entered an Asset Sale and Purchase Agreement to sell the Toledo Refinery to Toledo Refining Company LLC (TRC) whereinLP sold 2.3 million of Sunoco Inc. retained certain liabilities associated with the pre-Closing time period. On January 2, 2013, USEPA issuedLP’s common units in 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 relateprivate placement to the time periodPartnership. 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 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 Inc. operated the refinery. Specifically, EPA has claimed that the refinery flares were not operatedLP to its indirect wholly-owned subsidiaries in a manner consistent with good air pollution control practiceexchange 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 requiredoutstanding Class A Units held by such subsidiaries. Sunoco LP’s Series A Preferred Units On March 30, 2017, ET 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 is 10.00%, 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 ET 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.
USAC’s Distribution Reinvestment Program During the nine months ended December 31, 2018, distributions of $1 million were reinvested under the USAC distribution reinvestment program resulting in the issuance of approximately 39,280 USAC common units. USAC’s Warrant Private Placement On April 2, 2018, USAC issued two tranches of warrants to purchase USAC common units (the “USAC Warrants”), which included USAC Warrants to purchase 5,000,000 common units with a strike price of $17.03 per unit and USAC Warrants to purchase 10,000,000 common units with a strike price of $19.59 per unit. The USAC Warrants may be exercised by the regulations. EPA has proposed penaltiesholders thereof at any time beginning on the one year anniversary of the closing date and before the tenth anniversary of the closing date. Upon exercise of the USAC Warrants, USAC may, at its option, elect to settle the USAC Warrants in excesscommon units on a net basis. USAC’s Class B Units The USAC Class B Units, all of $200,000which are owned by ETO, are a new class of partnership interests of USAC that have substantially all of the rights and obligations of a USAC common unit, except the USAC Class B Units will not participate in distributions for the first four quarters following the closing date of the USAC Transaction on April 2, 2018. Each USAC Class B Unit will automatically convert into one USAC common unit on the first business day following the record date attributable to resolve the allegations and discussions continue between the parties. The timing or outcomequarter ending June 30, 2019. Parent Company Quarterly Distributions 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.Available Cash Our pipeline operations are subject to regulation bydistribution policy is consistent with the U.S. Departmentterms of Transportation under the PHMSA, pursuant toour Partnership Agreement, 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 ofrequires that we distribute all of theseour available cash quarterly. The Parent Company’s only cash-generating assets will continue, and the potential exists that resultscurrently consist 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.distributions from its interest in ETO. Our operations are also subjectdistributions declared and paid with respect 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 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, our subsidiaries 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 pricecommon units for the residue gas and NGL. These contracts are not designatedperiods presented were as hedges for accounting purposes.follows:
We use derivatives in our liquids transportation and services segment to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes.
Sunoco Logistics utilizes swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs. 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 segment. 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, 2015 | | December 31, 2014 | | Notional Volume | | Maturity | | Notional Volume | | Maturity | Mark-to-Market Derivatives | | | | | | | | (Trading) | | | | | | | | Natural Gas (MMBtu): | | | | | | | | Fixed Swaps/Futures | (602,500 | ) | | 2016 - 2017 | | (232,500 | ) | | 2015 | Basis Swaps IFERC/NYMEX (1) | (31,240,000 | ) | | 2016 - 2017 | | (13,907,500 | ) | | 2015 - 2016 | Options – Calls | — |
| | — | | 5,000,000 |
| | 2015 | Power (Megawatt): | | | | | | | | Forwards | 357,092 |
| | 2016 - 2017 | | 288,775 |
| | 2015 | Futures | (109,791 | ) | | 2016 | | (156,000 | ) | | 2015 | Options — Puts | 260,534 |
| | 2016 | | (72,000 | ) | | 2015 | Options — Calls | 1,300,647 |
| | 2016 | | 198,556 |
| | 2105 | Crude (Bbls) – Futures | (591,000 | ) | | 2016 - 2017 | | — |
| | — | (Non-Trading) | | | | | | | | Natural Gas (MMBtu): | | | | | | | | Basis Swaps IFERC/NYMEX | (6,522,500 | ) | | 2016 - 2017 | | 57,500 |
| | 2015 | Swing Swaps IFERC | 71,340,000 |
| | 2016 - 2017 | | 46,150,000 |
| | 2015 | Fixed Swaps/Futures | (14,380,000 | ) | | 2016 - 2018 | | (34,304,000 | ) | | 2015 - 2016 | Forward Physical Contracts | 21,922,484 |
| | 2016 - 2017 | | (9,116,777 | ) | | 2015 | Natural Gas Liquid (Bbls) – Forwards/Swaps | (8,146,800 | ) | | 2016 - 2018 | | (4,417,400 | ) | | 2015 | Refined Products (Bbls) – Futures | (1,289,000 | ) | | 2016 - 2017 | | 13,745,755 |
| | 2015 | Corn (Bushels) – Futures | 1,185,000 |
| | 2016 | | — |
| | — | Fair Value Hedging Derivatives | | | | | | | | (Non-Trading) | | | | | | | | Natural Gas (MMBtu): | | | | | | | | Basis Swaps IFERC/NYMEX | (37,555,000 | ) | | 2016 | | (39,287,500 | ) | | 2015 | Fixed Swaps/Futures | (37,555,000 | ) | | 2016 | | (39,287,500 | ) | | 2015 | Hedged Item — Inventory | 37,555,000 |
| | 2016 | | 39,287,500 |
| | 2015 |
| | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | 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 |
| March 31, 2018 | | May 7, 2018 | | May 21, 2018 | | 0.3050 |
| June 30, 2018 | | August 6, 2018 | | August 20, 2018 | | 0.3050 |
| September 30, 2018 | | November 8, 2018 | | November 19, 2018 | | 0.3050 |
| December 31, 2018 | | February 8, 2019 | | February 19, 2019 | | 0.3050 |
|
| | (1) | Includes aggregate amountsCertain 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 open positions relateda period of up to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zonenine quarters commencing with the distribution for the quarter ended March 31, 2016 and, Henry Hub locations.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. |
Interest Rate Risk
WeOur 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 |
| March 31, 2018 | | May 7, 2018 | | May 21, 2018 | | 0.1100 |
|
ETO Preferred Unit Distributions Distributions on the Partnership’s Series A, Series B, Series C and Series D preferred units declared and/or paid by the Partnership during the periods presented were as follows: | | | | | | | | | | | | | | | | | | | | | | | Period Ended | | Record Date | | Payment Date | | Series A (1) | | Series B (1) | | Series C | | Series D | | December 31, 2017 | | February 1, 2018 | | February 15, 2018 | | $ | 15.4510 |
| * | $ | 16.3780 |
| * | $ | — |
| | $ | — |
| | June 30, 2018 | | August 1, 2018 | | August 15, 2018 | | 31.2500 |
| | 33.1250 |
| | 0.5634 |
| * | — |
| | September 30, 2018 | | November 1, 2018 | | November 15, 2018 | | — |
| | — |
| | 0.4609 |
| | 0.5931 |
| * | December 31, 2018 | | February 1, 2019 | | February 15, 2019 | | 31.2500 |
| | 33.1250 |
| | 0.4609 |
| | 0.4766 |
| |
* Represent prorated initial distributions. (1) Series A and Series B preferred unit distributions 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 ratepaid on a portion of anticipated debt issuances.bi-annual basis.
F - 63Sunoco LP Cash Distributions
The following table summarizes ourillustrates 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 rate swaps outstanding, nonein 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 designated as hedges for accounting purposes:also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. | | | | | | | | | | | | | | | | | | Notional Amount Outstanding | Entity | | Term | | Type(1) | | December 31, 2015 | | December 31, 2014 | 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 |
| | 200 |
| ETP | | July 2017(4) | | Forward-starting to pay a fixed rate of 3.84% and receive a floating rate | | 300 |
| | 300 |
| ETP | | July 2018(4) | | Forward-starting to pay a fixed rate of 4.00% and receive a floating rate | | 200 |
| | 200 |
| ETP | | July 2019(4) | | Forward-starting to pay a fixed rate of 3.25% and receive a floating rate | | 200 |
| | 300 |
| ETP | | July 2018 | | Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% | | 1,200 |
| | — |
| ETP | | June 2021 | | Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% | | 300 |
| | — |
| ETP | | February 2023 | | Pay a floating rate plus a spread of 1.73% and receive a fixed rate of 3.60% | | — |
| | 200 |
|
| | (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 | | | | | | | | | | | | 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% |
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’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, ETP may at times require collateral under certain circumstances to mitigate credit risk as necessary. ETP also implements the use of 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 utilizes master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.
ETP’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. ETP’s overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact its 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.
ETP 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 its pre-established credit limit with the counterparty. Margin deposits are returned to ETP on the settlement date for non-exchange traded derivatives, and ETP exchanges 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:Distributions on Sunoco LP’s units declared and/or paid by Sunoco LP were as follows:
| | | | | | | | | | | | | | | | | | Fair Value of Derivative Instruments | | Asset Derivatives | | Liability Derivatives | | December 31, 2015 | | December 31, 2014 | | December 31, 2015 | | December 31, 2014 | Derivatives designated as hedging instruments: | | | | | | | | Commodity derivatives (margin deposits) | $ | 38 |
| | $ | 43 |
| | $ | (3 | ) | | $ | — |
| | 38 |
| | 43 |
| | (3 | ) | | — |
| Derivatives not designated as hedging instruments: | | | | | | | | Commodity derivatives (margin deposits) | 353 |
| | 617 |
| | (306 | ) | | (577 | ) | Commodity derivatives | 63 |
| | 107 |
| | (47 | ) | | (23 | ) | Interest rate derivatives | — |
| | 3 |
| | (171 | ) | | (155 | ) | Embedded derivatives in ETP Preferred Units | — |
| | — |
| | (5 | ) | | (16 | ) | | 416 |
| | 727 |
| | (529 | ) | | (771 | ) | Total derivatives | $ | 454 |
| | $ | 770 |
| | $ | (532 | ) | | $ | (771 | ) |
| | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | 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 6, 2018 | | February 14, 2018 | | 0.8255 |
| March 31, 2018 | | May 7, 2018 | | May 15, 2018 | | 0.8255 |
| June 30, 2018 | | August 7, 2018 | | August 15, 2018 | | 0.8255 |
| September 30, 2018 | | November 6, 2018 | | November 14, 2018 | | 0.8255 |
| December 31, 2018 | | February 6, 2019 | | February 14, 2019 | | 0.8255 |
|
USAC Cash Distributions Subsequent to the Energy Transfer Merger and USAC Transactions described in Note 1 and Note 3, respectively, ETO owns approximately 39.7 million USAC common units and 6.4 million USAC Class B units. As of December 31, 2018, USAC had approximately 96.4 million common units outstanding. USAC currently has a non-economic general partner interest and no outstanding incentive distribution rights. Distributions on USAC’s units declared and/or paid by USAC subsequent to the USAC transaction on April 2, 2018 were as follows: | | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | March 31, 2018 | | May 1, 2018 | | May 11, 2018 | | $ | 0.5250 |
| June 30, 2018 | | July 30, 2018 | | August 10, 2018 | | 0.5250 |
| September 30, 2018 | | October 29, 2018 | | November 09, 2018 | | 0.5250 |
| December 31, 2018 | | January 28, 2019 | | February 8, 2019 | | 0.5250 |
|
Accumulated Other Comprehensive Income (Loss) 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, 2015 | | December 31, 2014 | | December 31, 2015 | | December 31, 2014 | Derivatives without offsetting agreements | | Derivative assets (liabilities) | | $ | — |
| | $ | 3 |
| | $ | (176 | ) | | $ | (171 | ) | Derivatives in offsetting agreements: | | | | | | | | | OTC contracts | | Derivative assets (liabilities) | | 63 |
| | 107 |
| | (47 | ) | | (23 | ) | Broker cleared derivative contracts | | Other current assets | | 391 |
| | 660 |
| | (309 | ) | | (577 | ) | | | 454 |
| | 770 |
| | (532 | ) | | (771 | ) | Offsetting agreements: | | | | | | | | | Counterparty netting | | Derivative assets (liabilities) | | (17 | ) | | (19 | ) | | 17 |
| | 19 |
| Payments on margin deposit | | Other current assets | | (309 | ) | | (577 | ) | | 309 |
| | 577 |
| Total net derivatives | | $ | 128 |
| | $ | 174 |
| | $ | (206 | ) | | $ | (175 | ) |
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:
| | | | | | | | | | | | | | Change in Value Recognized in OCI on Derivatives (Effective Portion) | | Years Ended December 31, | | 2015 | | 2014 | | 2013 | Derivatives in cash flow hedging relationships: | | | | | | Commodity derivatives | $ | — |
| | $ | — |
| | $ | (1 | ) | Total | $ | — |
| | $ | — |
| | $ | (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, | | 2015 | | 2014 | | 2013 | Derivatives in cash flow hedging relationships: | | | | | | | | Commodity derivatives | Cost of products sold | | $ | — |
| | $ | (3 | ) | | $ | 4 |
| Total | | | $ | — |
| | $ | (3 | ) | | $ | 4 |
|
| | | | | | | | | | | | | | | | 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, | | 2015 | | 2014 | | 2013 | Derivatives in fair value hedging relationships (including hedged item): | | | | | | | | Commodity derivatives | Cost of products sold | | $ | 21 |
| | $ | (8 | ) | | $ | 8 |
| Total | | | $ | 21 |
| | $ | (8 | ) | | $ | 8 |
|
| | | | | | | | | | | | | | | | Location of Gain/(Loss) Recognized in Income on Derivatives | | Amount of Gain/(Loss) Recognized in Income on Derivatives | | | Years Ended December 31, | | | 2015 | | 2014 | | 2013 | Derivatives not designated as hedging instruments: | | | | | | | | Commodity derivatives – Trading | Cost of products sold | | $ | (11 | ) | | $ | (6 | ) | | $ | (11 | ) | Commodity derivatives – Non-trading | Cost of products sold | | 15 |
| | 199 |
| | (21 | ) | Commodity contracts – Non-trading | Deferred gas purchases | | — |
| | — |
| | (3 | ) | Interest rate derivatives | Gains (losses) on interest rate derivatives | | (18 | ) | | (157 | ) | | 53 |
| Embedded derivatives | Other, net | | 12 |
| | 3 |
| | 6 |
| Total | | | $ | (2 | ) | | $ | 39 |
| | $ | 24 |
|
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 $40 million, $50 million and $47 million to the 401(k) savings plan for the years ended December 31, 2015, 2014, and 2013, respectively.
Pension and Other Postretirement Benefit Plans
Panhandle
Postretirement benefits expense for the years ended December 31, 2015 and 2014 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, 2015 | | December 31, 2014 | | 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 | $ | 718 |
| | $ | 65 |
| | $ | 203 |
| | $ | 632 |
| | $ | 61 |
| | $ | 223 |
| Interest cost | 23 |
| | 2 |
| | 4 |
| | 28 |
| | 3 |
| | 5 |
| Amendments | — |
| | — |
| | — |
| | — |
| | — |
| | 1 |
| Benefits paid, net | (46 | ) | | (8 | ) | | (20 | ) | | (45 | ) | | (9 | ) | | (28 | ) | Actuarial (gain) loss and other | 16 |
| | (2 | ) | | (6 | ) | | 130 |
| | 10 |
| | 2 |
| Settlements | (691 | ) | | — |
| | — |
| | (27 | ) | | — |
| | — |
| Benefit obligation at end of period | $ | 20 |
| | $ | 57 |
| | $ | 181 |
| | $ | 718 |
| | $ | 65 |
| | $ | 203 |
| | | | | | | | | | | | | Change in plan assets: | | | | | | | | | | | | Fair value of plan assets at beginning of period | $ | 598 |
| | $ | — |
| | $ | 272 |
| | $ | 600 |
| | $ | — |
| | $ | 284 |
| Return on plan assets and other | 16 |
| | — |
| | — |
| | 70 |
| | — |
| | 7 |
| Employer contributions | 138 |
| | — |
| | 9 |
| | — |
| | — |
| | 9 |
| Benefits paid, net | (46 | ) | | — |
| | (20 | ) | | (45 | ) | | — |
| | (28 | ) | Settlements | (691 | ) | | — |
| | — |
| | (27 | ) | | — |
| | — |
| Fair value of plan assets at end of period | $ | 15 |
| | $ | — |
| | $ | 261 |
| | $ | 598 |
| | $ | — |
| | $ | 272 |
| | | | | | | | | | | | | Amount underfunded (overfunded) at end of period | $ | 5 |
| | $ | 57 |
| | $ | (80 | ) | | $ | 120 |
| | $ | 65 |
| | $ | (69 | ) | | | | | | | | | | | | | Amounts recognized in the consolidated balance sheets consist of: | | | | | | | | | | | | Non-current assets | $ | — |
| | $ | — |
| | $ | 103 |
| | $ | — |
| | $ | — |
| | $ | 96 |
| Current liabilities | — |
| | (9 | ) | | (2 | ) | | — |
| | (9 | ) | | (2 | ) | Non-current liabilities | (5 | ) | | (48 | ) | | (22 | ) | | (120 | ) | | (56 | ) | | (25 | ) | | $ | (5 | ) | | $ | (57 | ) | | $ | 79 |
| | $ | (120 | ) | | $ | (65 | ) | | $ | 69 |
| | | | | | | | | | | | | Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of: | | | | | | | | | | | | Net actuarial gain | $ | 2 |
| | $ | 4 |
| | $ | (18 | ) | | $ | 18 |
| | $ | 7 |
| | $ | (21 | ) | Prior service cost | — |
| | — |
| | 16 |
| | — |
| | — |
| | 18 |
| | $ | 2 |
| | $ | 4 |
| | $ | (2 | ) | | $ | 18 |
| | $ | 7 |
| | $ | (3 | ) |
The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets:
| | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2015 | | December 31, 2014 | | Pension Benefits | | | | Pension Benefits | | | | Funded Plans | | Unfunded Plans | | Other Postretirement Benefits | | Funded Plans | | Unfunded Plans | | Other Postretirement Benefits | Projected benefit obligation | $ | 20 |
| | $ | 57 |
| | N/A |
| | $ | 718 |
| | $ | 65 |
| | N/A |
| Accumulated benefit obligation | 20 |
| | 57 |
| | $ | 181 |
| | 718 |
| | 65 |
| | $ | 203 |
| Fair value of plan assets | 15 |
| | — |
| | 261 |
| | 598 |
| | — |
| | 272 |
|
Components of Net Periodic Benefit Cost
| | | | | | | | | | | | | | | | | | December 31, 2015 | | December 31, 2014 | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Net Periodic Benefit Cost: | | | | | | | | Interest cost | $ | 25 |
| | $ | 4 |
| | $ | 31 |
| | $ | 5 |
| Expected return on plan assets | (16 | ) | | (8 | ) | | (40 | ) | | (8 | ) | Prior service cost amortization | — |
| | 1 |
| | — |
| | 1 |
| Actuarial loss amortization | — |
| | — |
| | (1 | ) | | (1 | ) | Settlements | 32 |
| | — |
| | (4 | ) | | — |
| Net periodic benefit cost | $ | 41 |
| | $ | (3 | ) | | $ | (14 | ) | | $ | (3 | ) |
Assumptions
The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below:
| | | | | | | | | | | | | | December 31, 2015 | | December 31, 2014 | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Discount rate | 3.59 | % | | 2.38 | % | | 3.62 | % | | 2.24 | % | 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, 2015 | | December 31, 2014 | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Discount rate | 3.65 | % | | 2.79 | % | | 4.65 | % | | 3.02 | % | Expected return on assets: | | | | | | | | Tax exempt accounts | 7.50 | % | | 7.00 | % | | 7.50 | % | | 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, | | 2015 | | 2014 | Health care cost trend rate | 7.16 | % | | 7.09 | % | Rate to which the cost trend is assumed to decline (the ultimate trend rate) | 5.39 | % | | 5.41 | % | Year that the rate reaches the ultimate trend rate | 2018 |
| | 2018 |
|
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, 2015 Using Fair Value Hierarchy | | | Fair Value as of December 31, 2015 | | Level 1 | | Level 2 | | Level 3 | Asset Category: | | | | | | | | | Mutual funds (1) | | $ | 15 |
| | $ | — |
| | $ | 15 |
| | $ | — |
| Total | | $ | 15 |
| | $ | — |
| | $ | 15 |
| | $ | — |
|
| | (1)
| Comprised of 100% equities as of December 31, 2015. |
| | | | | | | | | | | | | | | | | | | | | | 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 |
| | $ | — |
|
| | (1)
| Comprised of 100% equities as of December 31, 2014. |
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, 2015 Using Fair Value Hierarchy | | | Fair Value as of December 31, 2015 | | Level 1 | | Level 2 | | Level 3 | Asset Category: | | | | | | | | | Cash and Cash Equivalents | | $ | 18 |
| | $ | 18 |
| | $ | — |
| | $ | — |
| Mutual funds (1) | | 141 |
| | 141 |
| | — |
| | — |
| Fixed income securities | | 102 |
| | — |
| | 102 |
| | — |
| Total | | $ | 261 |
| | $ | 159 |
| | $ | 102 |
| | $ | — |
|
| | (1)
| Primarily comprised of approximately 56% equities, 33% fixed income securities and 11% cash as of December 31, 2015. |
| | | | | | | | | | | | | | | | | | | | | | 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) | | 138 |
| | 138 |
| | — |
| | — |
| Fixed income securities | | 125 |
| | — |
| | 125 |
| | — |
| Total | | $ | 272 |
| | $ | 147 |
| | $ | 125 |
| | $ | — |
|
| | | | | | | | | | December 31, | | 2018 | | 2017 | Available-for-sale securities (1) | $ | 2 |
| | $ | 8 |
| Foreign currency translation adjustment | (5 | ) | | (5 | ) | Actuarial gain (loss) related to pensions and other postretirement benefits | (48 | ) | | (5 | ) | Investments in unconsolidated affiliates, net | 9 |
| | 5 |
| Total AOCI, net of tax | (42 | ) | | 3 |
| Amounts attributable to noncontrolling interest | — |
| | (3 | ) | Total AOCI included in partners’ capital, net of tax | $ | (42 | ) | | $ | — |
|
| | (1) | Primarily comprisedEffective January 1, 2018, the Partnership adopted Accounting Standards Update No. 2016-01, Recognition and Measurement of approximately Financial Assets and Financial Liabilities53% equities, 41% fixed, which resulted in the reclassification of $2 million from accumulated other comprehensive income related to available-for-sale equity securities and 6% cash as of December 31, 2014.to common unitholders.
|
The Level 1 plan assets are valued based on active market quotes. The Level 2 plan assets are valued based ontable below sets forth 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 $16 million to pension plans and $10 million to other postretirement plans in 2016. The cost of the plans are funded in accordance with federal regulations, not to exceed thetax 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 andincluded in the aggregate for the five years thereafter are shown in the table below:respective components of other comprehensive income (loss):
| | | | | | | | | | | | | | | | Pension Benefits | | | Years | | Funded Plans | | Unfunded Plans | | Other Postretirement Benefits (Gross, Before Medicare Part D) | 2016 | | $ | 20 |
| | $ | 9 |
| | $ | 21 |
| 2017 | | — |
| | 7 |
| | 20 |
| 2018 | | — |
| | 7 |
| | 19 |
| 2019 | | — |
| | 6 |
| | 17 |
| 2020 | | — |
| | 6 |
| | 16 |
| 2021 – 2025 | | — |
| | 2 |
| | 58 |
|
| | | | | | | | | | December 31, | | 2018 | | 2017 | Available-for-sale securities | $ | (1 | ) | | $ | (2 | ) | Foreign currency translation adjustment | 2 |
| | 3 |
| Actuarial loss relating to pension and other postretirement benefits | 12 |
| | 3 |
| Total | $ | 13 |
| | $ | 4 |
|
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.
| | 14.9. | RELATED PARTY TRANSACTIONS:NON-CASH COMPENSATION PLANS: |
The Parent Company has agreementsET Non-Cash Compensation Plan
We, Sunoco LP and USAC, 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 non-cash compensation awards. As of December 31, 2018, an aggregate total of 15.1 million ET Common Units remain available to be awarded under our equity incentive plans. ET Long-Term Incentive Plan We have granted restricted unit awards to employees that vest over a specified time period, typically a five-year service vesting requirement, with subsidiaries to provide or receive various general and administrative services. The Parent Company pays ETP to provide servicesvesting based on its behalf andcontinued employment as of each applicable vesting date. Upon vesting, ET Common Units are issued. These unit awards entitle the behalf of other subsidiariesrecipients of the Parent Company. 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 Parent Company receives management fees from certainfollowing table shows the activity of its subsidiaries, which include the reimbursement of various generalawards granted to employees and administrative services for expenses incurred by ETP on behalf of those subsidiaries. All such amounts have been eliminated in our consolidated financial statements.non-employee directors: In the ordinary course of business, our subsidiaries have related party transactions between each other which are generally based on transactions made at market-related rates. Our consolidated revenues and expenses reflect the elimination of all material intercompany transactions (see Note 15).In addition, subsidiaries of ETE recorded sales with affiliates of $290 million, $965 million and $1.44 billion during | | | | | | | | | Number of Units | | Weighted Average Grant-Date Fair Value Per Unit | Unvested awards as of December 31, 2017 (1) | 19.5 |
| | $ | 18.03 |
| Awards granted | 7.8 |
| | 13.00 |
| Awards vested | (3.5 | ) | | 21.35 |
| Awards forfeited | (1.4 | ) | | 15.16 |
| Unvested awards as of December 31, 2018 | 22.4 |
| | 15.94 |
|
| | (1) | In connection with the Energy Transfer Merger, ET assumed the former ETO plans, including the related unvested awards. Outstanding awards under the former ETO plans are reflected for the entire period above. Amounts related to the period prior to the Energy Transfer Merger are adjusted for the 1.28 to 1 conversion ratio that was applied in the merger. |
During the years ended December 31, 2015, 20142018, 2017, and 2013,2016, the weighted average grant-date fair value per unit award granted was $13.00, $17.01 and $16.37, respectively. Subsequent to ETE’s acquisition The total fair value of a controlling interest in Sunoco LP, our financial statements reflectawards vested was $49 million, $40 million, and $40 million, respectively, based on 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:
activitiesmarket price of the Parent Company; and
the goodwill and property, plant and equipment fair value adjustments recordedrespective Common Units as a result of the 2004 reverse acquisitionvesting date. As of Heritage Propane Partners, L.P.December 31, 2018, a total of 22 million unit awards remain unvested, for which ET expects to recognize a total of $228 million in compensation expense over a weighted average period of 2.7 years.
ETP completed its acquisitionCash Restricted Units. We previously granted cash restricted units, which entitled the award recipient to receive cash equal to the market value of Regency in April 2015; therefore, the Investment in ETP segment amountsone ET Common Unit upon vesting. The Partnership does not currently have been retrospectively adjusted to reflect Regency for the periods presented.any cash restricted units outstanding.
The Investment in Sunoco LP segment reflects the resultsSubsidiary Non-Cash Compensation Plans
Each of Sunoco LP beginning August 29, 2014,and USAC has granted restricted or phantom unit awards (collectively, the date“Subsidiary Unit Awards”) to employees and directors that ETP originally obtained control of Sunoco LP. ETE’s consolidated results reflectentitle the elimination of MACS, Sunoco, LLC and Susser for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP. In addition, subsequentgrantees 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, loss on extinguishment 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%receive common units of the subsidiaries’ resultsrespective subsidiary. In some cases, at the
discretion of operations. Based on the change in our reportable segments we have recastrespective subsidiary’s compensation committee, the presentationgrantee may instead receive an amount of our segment results for the prior years to be consistent with the current year presentation. Eliminations in the tables below include the following:
ETP’s Segment Adjusted EBITDA reflected the results of Lake Charles LNG priorcash equivalent to the Lake Charles LNG Transaction,value of common units upon vesting. Substantially all of the Subsidiary Unit Awards are time-vested grants, which was effective January 1, 2014. generally vest over a three or five-year period, that entitles 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 Investment in Lake Charles LNG segment reflectedfollowing table summarizes the resultsactivity of operations of Lake Charles LNG for all periods presented. Consequently, the results of operations of Lake Charles LNG were reflected in two segments for the year ended December 31, 2013. Therefore, the results of Lake Charles LNG were included in eliminations for 2013. MACS, Sunoco LLC and Susser 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, | | 2015 | | 2014 | | 2013 | Revenues: | | | | | | Investment in ETP: | | | | | | Revenues from external customers | $ | 34,156 |
| | $ | 55,475 |
| | $ | 48,335 |
| Intersegment revenues | 136 |
| | — |
| | — |
| | 34,292 |
| | 55,475 |
| | 48,335 |
| Investment in Sunoco LP: | | | | | | Revenues from external customers | 15,163 |
| | 5,972 |
| | — |
| Intersegment revenues | 1,772 |
| | 853 |
| | — |
| | 16,935 |
| | 6,825 |
| | — |
| Investment in Lake Charles LNG: | | | | | | Revenues from external customers | 216 |
| | 216 |
| | 216 |
| |
|
| |
|
| |
|
| Adjustments and Eliminations: | (9,317 | ) | | (6,825 | ) | | (216 | ) | Total revenues | $ | 42,126 |
| | $ | 55,691 |
| | $ | 48,335 |
| | | | | | | Costs of products sold: | | | | | | Investment in ETP | $ | 27,029 |
| | $ | 48,414 |
| | $ | 42,580 |
| Investment in Sunoco LP | 15,477 |
| | 6,444 |
| | — |
| Adjustments and Eliminations | (8,497 | ) | | (6,444 | ) | | — |
| Total costs of products sold | $ | 34,009 |
| | $ | 48,414 |
| | $ | 42,580 |
| | | | | | | Depreciation, depletion and amortization: | | | | | | Investment in ETP | $ | 1,929 |
| | $ | 1,669 |
| | $ | 1,296 |
| Investment in Sunoco LP | 201 |
| | 60 |
| | — |
| Investment in Lake Charles LNG | 39 |
| | 39 |
| | 39 |
| Corporate and Other | 17 |
| | 16 |
| | 16 |
| Adjustments and Eliminations | (107 | ) | | (60 | ) | | (38 | ) | Total depreciation, depletion and amortization | $ | 2,079 |
| | $ | 1,724 |
| | $ | 1,313 |
|
Subsidiary Unit Awards: | | | | | | | | | | | | | | Years Ended December 31, | | 2015 | | 2014 | | 2013 | Equity in earnings of unconsolidated affiliates: | | | | | | Investment in ETP | $ | 469 |
| | $ | 332 |
| | $ | 236 |
| Adjustments and Eliminations | (193 | ) | | — |
| | — |
| Total equity in earnings of unconsolidated affiliates | $ | 276 |
| | $ | 332 |
| | $ | 236 |
|
| | | | | | | | | | | | | | | | Sunoco LP | | USAC | | 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, 2017 | 1.7 |
| | $ | 31.89 |
| | 1.0 |
| | $ | 14.24 |
| Awards granted | 1.1 |
| | 27.67 |
| | 1.1 |
| | 15.47 |
| Awards vested | (0.4 | ) | | 32.92 |
| | (0.6 | ) | | 14.79 |
| Awards forfeited | (0.3 | ) | | 31.26 |
| | (0.1 | ) | | 17.85 |
| Unvested awards as of December 31, 2018 | 2.1 |
| | 29.15 |
| | 1.4 |
| | 14.98 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2015 | | 2014 | | 2013 | Segment Adjusted EBITDA: | | | | | | Investment in ETP | $ | 5,714 |
| | $ | 5,710 |
| | $ | 4,404 |
| Investment in Sunoco LP | 614 |
| | 277 |
| | — |
| Investment in Lake Charles LNG | 196 |
| | 195 |
| | 187 |
| Corporate and Other | (104 | ) | | (97 | ) | | (43 | ) | Adjustments and Eliminations | (485 | ) | | (245 | ) | | (181 | ) | Total Segment Adjusted EBITDA | 5,935 |
| | 5,840 |
| | 4,367 |
| Depreciation, depletion and amortization | (2,079 | ) | | (1,724 | ) | | (1,313 | ) | Interest expense, net of interest capitalized | (1,643 | ) | | (1,369 | ) | | (1,221 | ) | Gain on sale of AmeriGas common units | — |
| | 177 |
| | 87 |
| Impairment losses | (339 | ) | | (370 | ) | | (689 | ) | Gains (losses) on interest rate derivatives | (18 | ) | | (157 | ) | | 53 |
| Non-cash unit-based compensation expense | (91 | ) | | (82 | ) | | (61 | ) | Unrealized gains (losses) on commodity risk management activities | (65 | ) | | 116 |
| | 48 |
| Losses on extinguishments of debt | (43 | ) | | (25 | ) | | (162 | ) | Inventory valuation adjustments | (249 | ) | | (473 | ) | | 3 |
| Adjusted EBITDA related to discontinued operations | — |
| | (27 | ) | | (76 | ) | Adjusted EBITDA related to unconsolidated affiliates | (713 | ) | | (748 | ) | | (727 | ) | Equity in earnings of unconsolidated affiliates | 276 |
| | 332 |
| | 236 |
| Non-operating environmental remediation | — |
| | — |
| | (168 | ) | Other, net | 22 |
| | (73 | ) | | (2 | ) | Income from continuing operations before income tax expense | $ | 993 |
| | $ | 1,417 |
| | $ | 375 |
|
The following table summarizes the weighted average grant-date fair value per unit award granted: | | | | | | | | | | | | | | December 31, | | 2015 | | 2014 | | 2013 | Total assets: | | | | | | Investment in ETP | $ | 65,173 |
| | $ | 62,518 |
| | $ | 49,900 |
| Investment in Sunoco LP | 6,248 |
| | 6,149 |
| | — |
| Investment in Lake Charles LNG | 1,369 |
| | 1,210 |
| | 1,338 |
| Corporate and Other | 638 |
| | 1,119 |
| | 720 |
| Adjustments and Eliminations | (2,239 | ) | | (6,717 | ) | | (1,628 | ) | Total | $ | 71,189 |
| | $ | 64,279 |
| | $ | 50,330 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2015 | | 2014 | | 2013 | Additions to property, plant and equipment, net of contributions in aid of construction costs (accrual basis): | | | | | | Investment in ETP | $ | 8,167 |
| | $ | 5,494 |
| | $ | 3,327 |
| Investment in Sunoco LP | 368 |
| | 116 |
| | — |
| Investment in Lake Charles LNG | 1 |
| | 1 |
| | 2 |
| Adjustments and Eliminations | — |
| | (52 | ) | | 13 |
| Total | $ | 8,536 |
| | $ | 5,559 |
| | $ | 3,342 |
|
| | | | | | | | | | | | | | December 31, | | 2015 | | 2014 | | 2013 | Advances to and investments in affiliates: | | | | | | Investment in ETP | $ | 5,003 |
| | $ | 3,760 |
| | $ | 4,050 |
| Adjustments and Eliminations | (1,541 | ) | | (101 | ) | | (36 | ) | Total | $ | 3,462 |
| | $ | 3,659 |
| | $ | 4,014 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2018 | | 2017 | | 2016 | Sunoco LP | $ | 27.67 |
| | $ | 28.31 |
| | $ | 26.95 |
| USAC | 15.47 |
| | N/A |
| | N/A |
|
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, | | 2015 | | 2014 | | 2013 | Intrastate Transportation and Storage | $ | 1,912 |
| | $ | 2,645 |
| | $ | 2,242 |
| Interstate Transportation and Storage | 1,008 |
| | 1,057 |
| | 1,270 |
| Midstream | 2,622 |
| | 4,770 |
| | 3,220 |
| Liquids Transportation and Services | 3,232 |
| | 3,730 |
| | 2,025 |
| Investment in Sunoco Logistics | 10,302 |
| | 17,920 |
| | 16,480 |
| Retail Marketing | 12,478 |
| | 22,484 |
| | 21,004 |
| All Other | 2,738 |
| | 2,869 |
| | 2,094 |
| Total revenues | 34,292 |
| | 55,475 |
| | 48,335 |
| Less: Intersegment revenues | 136 |
| | — |
| | — |
| Revenues from external customers | $ | 34,156 |
| | $ | 55,475 |
| | $ | 48,335 |
|
Investment in Sunoco LP
| | | | | | | | | | | | | | Years Ended December 31, | | 2015 | | 2014 | | 2013 | Retail operations | $ | 4,919 |
| | $ | 1,805 |
| | $ | — |
| Wholesale operations | 12,016 |
| | 5,020 |
| | — |
| Total revenues | 16,935 |
| | 6,825 |
| | — |
| Less: Intersegment revenues | 1,772 |
| | 853 |
| | — |
| Revenues from external customers | $ | 15,163 |
| | $ | 5,972 |
| | $ | — |
|
Investment in Lake Charles LNG
Lake Charles LNG’s revenuestotal fair value of $216 million, $216 million and $216 millionSubsidiary Unit Awards vested for the years ended December 31, 2015, 20142018, 2017 and 2013, 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 | 2015: | | | | | | | | | | Revenues | $ | 10,380 |
| | $ | 11,594 |
| | $ | 10,616 |
| | $ | 9,536 |
| | $ | 42,126 |
| Operating income | 617 |
| | 896 |
| | 650 |
| | 236 |
| | 2,399 |
| Net income (loss) | 221 |
| | 772 |
| | 238 |
| | (138 | ) | | 1,093 |
| Limited Partners’ interest in net income | 282 |
| | 298 |
| | 291 |
| | 312 |
| | 1,183 |
| Basic net income per limited partner unit | $ | 0.26 |
| | $ | 0.28 |
| | $ | 0.28 |
| | $ | 0.30 |
| | $ | 1.11 |
| Diluted net income per limited partner unit | $ | 0.26 |
| | $ | 0.28 |
| | $ | 0.28 |
| | $ | 0.30 |
| | $ | 1.11 |
|
| | | | | | | | | | | | | | | | | | | | | | Quarters Ended | | | | March 31 | | June 30 | | September 30 | | December 31 | | Total Year | 2014: | | | | | | | | | | Revenues | $ | 13,080 |
| | $ | 14,143 |
| | $ | 14,987 |
| | $ | 13,481 |
| | $ | 55,691 |
| Operating income | 710 |
| | 773 |
| | 822 |
| | 165 |
| | 2,470 |
| Net income (loss) | 448 |
| | 500 |
| | 470 |
| | (294 | ) | | 1,124 |
| Limited Partners’ interest in net income | 167 |
| | 163 |
| | 188 |
| | 111 |
| | 629 |
| Basic net income per limited partner unit | $ | 0.15 |
| | $ | 0.15 |
| | $ | 0.18 |
| | $ | 0.11 |
| | $ | 0.58 |
| Diluted net income per limited partner unit | $ | 0.15 |
| | $ | 0.15 |
| | $ | 0.18 |
| | $ | 0.11 |
| | $ | 0.57 |
|
The three months ended December 31, 2015 and 2014 reflected the unfavorable impacts of $1712016 was $22 million, $9 million, and $456$0.1 million, respectively, related to non-cash inventory valuation adjustments primarily in ETP’s investment in Sunoco Logistics and retail marketing operations and our investment in Sunoco LP. The three months ended December 31, 2015 and 2014 reflected the recognition of impairment losses of $339 million and $370 million, respectively. Impairment losses in 2015 were primarily related to ETP’s Lone Star Refinery Services operations and ETP’s Transwestern pipeline, and in 2014, impairment losses were primarily related to Regency’s Permian Basin gathering and processing 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, | | 2015 | | 2014 | ASSETS | | | | CURRENT ASSETS: | | | | Cash and cash equivalents | $ | 1 |
| | $ | 2 |
| Accounts receivable from related companies | 34 |
| | 14 |
| Other current assets | — |
| | 1 |
| Total current assets | 35 |
| | 17 |
| PROPERTY, PLANT AND EQUIPMENT, net | 20 |
| | — |
| ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES | 5,764 |
| | 5,390 |
| INTANGIBLE ASSETS, net | 6 |
| | 10 |
| GOODWILL | 9 |
| | 9 |
| OTHER NON-CURRENT ASSETS, net | 10 |
| | 12 |
| Total assets | $ | 5,844 |
| | $ | 5,438 |
| LIABILITIES AND PARTNERS’ CAPITAL | | | | CURRENT LIABILITIES: | | | | Accounts payable to related companies | $ | 111 |
| | $ | 11 |
| Interest payable | 66 |
| | 58 |
| Accrued and other current liabilities | 1 |
| | 3 |
| Total current liabilities | 178 |
| | 72 |
| LONG-TERM DEBT, less current maturities | 6,332 |
| | 4,646 |
| NOTE PAYABLE TO AFFILIATE | 265 |
| | 54 |
| OTHER NON-CURRENT LIABILITIES | 1 |
| | 2 |
| | | | | COMMITMENTS AND CONTINGENCIES |
| |
| | | | | PARTNERS’ CAPITAL: | | | | General Partner | (2 | ) | | (1 | ) | Limited Partners: | | | | Limited Partners – Common Unitholders (1,044,767,336 and 1,077,533,798 units authorized, issued and outstanding at December 31, 2015 and 2014, respectively) | (952 | ) | | 648 |
| Class D Units (2,156,000 and 3,080,000 units authorized, issued and outstanding as of December 31, 2015 and 2014, respectively) | 22 |
| | 22 |
| Accumulated other comprehensive income (loss) | — |
| | (5 | ) | Total partners’ capital | (932 | ) | | 664 |
| Total liabilities and partners’ capital | $ | 5,844 |
| | $ | 5,438 |
|
STATEMENTS OF OPERATIONS
| | | | | | | | | | | | | | Years Ended December 31, | | 2015 | | 2014 | | 2013 | SELLING, GENERAL AND ADMINISTRATIVE EXPENSES | $ | (112 | ) | | $ | (111 | ) | | $ | (56 | ) | OTHER INCOME (EXPENSE): | | | | | | Interest expense, net of interest capitalized | (294 | ) | | (205 | ) | | (210 | ) | Equity in earnings of unconsolidated affiliates | 1,601 |
| | 955 |
| | 617 |
| Gains on interest rate derivatives | — |
| | — |
| | 9 |
| Loss on extinguishment of debt | — |
| | — |
| | (157 | ) | Other, net | (5 | ) | | (5 | ) | | (8 | ) | INCOME BEFORE INCOME TAXES | 1,190 |
| | 634 |
| | 195 |
| Income tax expense (benefit) | 1 |
| | 1 |
| | (1 | ) | NET INCOME | 1,189 |
| | 633 |
| | 196 |
| GENERAL PARTNER’S INTEREST IN NET INCOME | 3 |
| | 2 |
| | — |
| CLASS D UNITHOLDER’S INTEREST IN NET INCOME | 3 |
| | 2 |
| | — |
| LIMITED PARTNERS’ INTEREST IN NET INCOME | $ | 1,183 |
| | $ | 629 |
| | $ | 196 |
|
STATEMENTS OF CASH FLOWS
| | | | | | | | | | | | | | Years Ended December 31, | | 2015 | | 2014 | | 2013 | NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES | $ | 1,103 |
| | $ | 816 |
| | $ | 768 |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | Cash paid for Bakken Pipeline Transaction | (817 | ) | | — |
| | — |
| Proceeds from ETP Holdco Transaction | — |
| | — |
| | 1,332 |
| Contributions to unconsolidated affiliates | — |
| | (118 | ) | | (8 | ) | Capital expenditures | (19 | ) | | — |
| | — |
| Purchase of additional interest in Regency | — |
| | (800 | ) | | — |
| Payments received on note receivable from affiliate | — |
| | — |
| | 166 |
| Net cash provided by (used in) investing activities | (836 | ) | | (918 | ) | | 1,490 |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | Proceeds from borrowings | 3,672 |
| | 3,020 |
| | 2,080 |
| Principal payments on debt | (1,985 | ) | | (1,142 | ) | | (3,235 | ) | Distributions to partners | (1,090 | ) | | (821 | ) | | (733 | ) | Proceeds from affiliate | 210 |
| | 54 |
| | — |
| Redemption of Preferred Units | — |
| | — |
| | (340 | ) | Units repurchased under buyback program | (1,064 | ) | | (1,000 | ) | | — |
| Debt issuance costs | (11 | ) | | (15 | ) | | (31 | ) | Net cash provided by (used in) financing activities | (268 | ) | | 96 |
| | (2,259 | ) | DECREASE IN CASH AND CASH EQUIVALENTS | (1 | ) | | (6 | ) | | (1 | ) | CASH AND CASH EQUIVALENTS, beginning of period | 2 |
| | 8 |
| | 9 |
| CASH AND CASH EQUIVALENTS, end of period | $ | 1 |
| | $ | 2 |
| | $ | 8 |
|
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, 2015 and 2014 | S - 4 | Consolidated Statements of Operations – Years Ended December 31, 2015, 2014 and 2013 | S - 6 | Consolidated Statements of Comprehensive Income – Years Ended December 31, 2015, 2014 and 2013 | S - 7 | Consolidated Statements of Equity – Years Ended December 31, 2015, 2014 and 2013 | S - 8 | Consolidated Statements of Cash Flows – Years Ended December 31, 2015, 2014 and 2013 | S - 10 | Notes to Consolidated Financial Statements | S - 12 |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Partners
Energy Transfer Partners, L.P.
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, 2015 and 2014, and the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2015. These financial statements 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 statementsmarket price of Sunoco LP and Susser Holdings Corporation, both previously 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 8 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 as of December 31, 2014 and for the period from September 1, 2014 to December 31, 2014, is based solely on the reports 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 subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 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, 2015, 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 29, 2016 (not separately included herein) expressed an unqualified opinion thereon.
/s/ GRANT THORNTON LLP
Dallas, Texas
February 29, 2016
ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
| | | | | | | | | | December 31, | | 2015 | | 2014 | ASSETS | | | | Current assets: | | | | Cash and cash equivalents | $ | 527 |
| | $ | 663 |
| Accounts receivable, net | 2,118 |
| | 3,360 |
| Accounts receivable from related companies | 268 |
| | 139 |
| Inventories | 1,213 |
| | 1,460 |
| Exchanges receivable | 30 |
| | 44 |
| Derivative assets | 40 |
| | 81 |
| Other current assets | 502 |
| | 282 |
| Total current assets | 4,698 |
| | 6,029 |
| | | | | Property, plant and equipment | 50,869 |
| | 43,404 |
| Accumulated depreciation and depletion | (5,782 | ) | | (4,497 | ) | | 45,087 |
| | 38,907 |
| | | | | Advances to and investments in unconsolidated affiliates | 5,003 |
| | 3,760 |
| Non-current derivative assets | — |
| | 10 |
| Other non-current assets, net | 536 |
| | 644 |
| Intangible assets, net | 4,421 |
| | 5,526 |
| Goodwill | 5,428 |
| | 7,642 |
| Total assets | $ | 65,173 |
| | $ | 62,518 |
|
ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
| | | | | | | | | | December 31, | | 2015 | | 2014 | LIABILITIES AND EQUITY | | | | Current liabilities: | | | | Accounts payable | $ | 1,859 |
| | $ | 3,348 |
| Accounts payable to related companies | 25 |
| | 25 |
| Exchanges payable | 105 |
| | 183 |
| Derivative liabilities | 63 |
| | 21 |
| Accrued and other current liabilities | 1,943 |
| | 2,000 |
| Current maturities of long-term debt | 126 |
| | 1,008 |
| Total current liabilities | 4,121 |
| | 6,585 |
| | | | | Long-term debt, less current maturities | 28,553 |
| | 24,831 |
| Long-term notes payable – related company | 233 |
| | — |
| Non-current derivative liabilities | 137 |
| | 154 |
| Deferred income taxes | 4,082 |
| | 4,331 |
| Other non-current liabilities | 968 |
| | 1,258 |
| | | | | Commitments and contingencies | | | | Series A Preferred Units | 33 |
| | 33 |
| Redeemable noncontrolling interests | 15 |
| | 15 |
| | | | | Equity: | | | | General Partner | 306 |
| | 184 |
| Limited Partners: | | | | Common Unitholders (505,645,703 and 355,510,227 units authorized, issued and outstanding as of December 31, 2015 and 2014, respectively) | 17,043 |
| | 10,430 |
| Class E Unitholders (8,853,832 units authorized, issued and outstanding – held by subsidiary) | — |
| | — |
| Class G Unitholders (90,706,000 units authorized, issued and outstanding – held by subsidiary) | — |
| | — |
| Class H Unitholders (81,001,069 and 50,160,000 units authorized, issued and outstanding as of December 31, 2015 and 2014, respectively) | 3,469 |
| | 1,512 |
| Class I Unitholders (100 units authorized, issued and outstanding) | 14 |
| | — |
| Accumulated other comprehensive income (loss) | 4 |
| | (56 | ) | Total partners’ capital | 20,836 |
| | 12,070 |
| Noncontrolling interest | 6,195 |
| | 5,153 |
| Predecessor equity | — |
| | 8,088 |
| Total equity | 27,031 |
| | 25,311 |
| Total liabilities and equity | $ | 65,173 |
| | $ | 62,518 |
|
ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions, except per unit data)
| | | | | | | | | | | | | | Years Ended December 31, | | 2015 | | 2014 | | 2013 | REVENUES: | | | | | | Natural gas sales | $ | 3,671 |
| | $ | 5,386 |
| | $ | 3,842 |
| NGL sales | 3,936 |
| | 5,845 |
| | 3,618 |
| Crude sales | 8,378 |
| | 16,416 |
| | 15,477 |
| Gathering, transportation and other fees | 3,997 |
| | 3,517 |
| | 3,097 |
| Refined product sales | 9,958 |
| | 19,437 |
| | 18,479 |
| Other | 4,352 |
| | 4,874 |
| | 3,822 |
| Total revenues | 34,292 |
| | 55,475 |
| | 48,335 |
| COSTS AND EXPENSES: | | | | | | Cost of products sold | 27,029 |
| | 48,414 |
| | 42,580 |
| Operating expenses | 2,261 |
| | 2,059 |
| | 1,669 |
| Depreciation, depletion and amortization | 1,929 |
| | 1,669 |
| | 1,296 |
| Selling, general and administrative | 475 |
| | 520 |
| | 482 |
| Impairment losses | 339 |
| | 370 |
| | 689 |
| Total costs and expenses | 32,033 |
| | 53,032 |
| | 46,716 |
| OPERATING INCOME | 2,259 |
| | 2,443 |
| | 1,619 |
| OTHER INCOME (EXPENSE): | | | | | | Interest expense, net | (1,291 | ) | | (1,165 | ) | | (1,013 | ) | Equity in earnings from unconsolidated affiliates | 469 |
| | 332 |
| | 236 |
| Gain on sale of AmeriGas common units | — |
| | 177 |
| | 87 |
| Losses on extinguishments of debt | (43 | ) | | (25 | ) | | (7 | ) | Gains (losses) on interest rate derivatives | (18 | ) | | (157 | ) | | 44 |
| Non-operating environmental remediation | — |
| | — |
| | (168 | ) | Other, net | 22 |
| | (12 | ) | | 12 |
| INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE | 1,398 |
| | 1,593 |
| | 810 |
| Income tax expense (benefit) from continuing operations | (123 | ) | | 358 |
| | 97 |
| INCOME FROM CONTINUING OPERATIONS | 1,521 |
| | 1,235 |
| | 713 |
| Income from discontinued operations | — |
| | 64 |
| | 33 |
| NET INCOME | 1,521 |
| | 1,299 |
| | 746 |
| Less: Net income attributable to noncontrolling interest | 157 |
| | 116 |
| | 255 |
| Less: Net income (loss) attributable to predecessor | (34 | ) | | (153 | ) | | 35 |
| NET INCOME ATTRIBUTABLE TO PARTNERS | 1,398 |
| | 1,336 |
| | 456 |
| General Partner’s interest in net income | 1,064 |
| | 513 |
| | 506 |
| Class H Unitholder’s interest in net income | 258 |
| | 217 |
| | 48 |
| Class I Unitholder’s interest in net income | 94 |
| | — |
| | — |
| Common Unitholders’ interest in net income (loss) | $ | (18 | ) | | $ | 606 |
| | $ | (98 | ) | INCOME (LOSS) FROM CONTINUING OPERATIONS PER COMMON UNIT: | | | | | | Basic | $ | (0.09 | ) | | $ | 1.58 |
| | $ | (0.23 | ) | Diluted | $ | (0.10 | ) | | $ | 1.58 |
| | $ | (0.23 | ) | NET INCOME (LOSS) PER COMMON UNIT: | | | | | | Basic | $ | (0.09 | ) | | $ | 1.77 |
| | $ | (0.18 | ) | Diluted | $ | (0.10 | ) | | $ | 1.77 |
| | $ | (0.18 | ) |
ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in millions)
| | | | | | | | | | | | | | Years Ended December 31, | | 2015 | | 2014 | | 2013 | Net income | $ | 1,521 |
| | $ | 1,299 |
| | $ | 746 |
| 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 | ) | Change in value of derivative instruments accounted for as cash flow hedges | — |
| | — |
| | (1 | ) | Change in value of available-for-sale securities | (3 | ) | | 1 |
| | 2 |
| Actuarial gain (loss) relating to pension and other postretirement benefits | 65 |
| | (113 | ) | | 66 |
| Foreign currency translation adjustment | (1 | ) | | (2 | ) | | (1 | ) | Change in other comprehensive income from unconsolidated affiliates | (1 | ) | | (6 | ) | | 17 |
| | 60 |
| | (117 | ) | | 79 |
| Comprehensive income | 1,581 |
| | 1,182 |
| | 825 |
| Less: Comprehensive income attributable to noncontrolling interest | 157 |
| | 116 |
| | 255 |
| Less: Comprehensive income (loss) attributable to predecessor | (34 | ) | | (153 | ) | | 35 |
| Comprehensive income attributable to partners | $ | 1,458 |
| | $ | 1,219 |
| | $ | 535 |
|
ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
(Dollars in millions)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Limited Partners | | | | | | | | | | General Partner | | Common Unitholders | | Class H Units | | Class I Units | | Accumulated Other Comprehensive Income (Loss) | | Noncontrolling Interest | | Predecessor Equity | | Total | Balance, December 31, 2012 | $ | 188 |
| | $ | 9,026 |
| | $ | — |
| | $ | — |
| | $ | (13 | ) | | $ | 7,260 |
| | $ | 3,521 |
| | $ | 19,982 |
| Distributions to partners | (523 | ) | | (1,228 | ) | | (51 | ) | | — |
| | — |
| | — |
| | — |
| | (1,802 | ) | Predecessor distributions to partners | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (342 | ) | | (342 | ) | Distributions to noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | (303 | ) | | — |
| | (303 | ) | Units issued for cash | — |
| | 1,611 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1,611 |
| Predecessor units issued for cash | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 149 |
| | 149 |
| Issuance of Class H Units | — |
| | (1,514 | ) | | 1,514 |
| | — |
| | — |
| | — |
| | — |
| | — |
| Capital contributions from noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | 18 |
| | — |
| | 18 |
| ETP Holdco Acquisition and SUGS Contribution | — |
| | 2,013 |
| | — |
| | — |
| | (5 | ) | | (3,448 | ) | | — |
| | (1,440 | ) | Other comprehensive income, net of tax | — |
| | — |
| | — |
| | — |
| | 79 |
| | — |
| | — |
| | 79 |
| Other, net | — |
| | (13 | ) | | — |
| | — |
| | — |
| | (2 | ) | | 11 |
| | (4 | ) | Net income (loss) | 506 |
| | (98 | ) | | 48 |
| | — |
| | — |
| | 255 |
| | 35 |
| | 746 |
| Balance, December 31, 2013 | 171 |
| | 9,797 |
| | 1,511 |
| | — |
| | 61 |
| | 3,780 |
| | 3,374 |
| | 18,694 |
| Distributions to partners | (500 | ) | | (1,252 | ) | | (212 | ) | | — |
| | — |
| | — |
| | — |
| | (1,964 | ) | Distributions to noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | (241 | ) | | — |
| | (241 | ) | Units issued for cash | — |
| | 1,382 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1,382 |
| Subsidiary units issued for cash | 1 |
| | 174 |
| | — |
| | — |
| | — |
| | 1,069 |
| | — |
| | 1,244 |
| Capital contributions from noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | 67 |
| | — |
| | 67 |
| Lake Charles LNG Transaction | — |
| | (1,167 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (1,167 | ) | Susser Merger | — |
| | 908 |
| | — |
| | — |
| | — |
| | 626 |
| | — |
| | 1,534 |
| Sunoco Logistics acquisition of a noncontrolling interest | (1 | ) | | (79 | ) | | — |
| | — |
| | — |
| | (245 | ) | | — |
| | (325 | ) | Predecessor distributions to partners | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (645 | ) | | (645 | ) | Predecessor units issued for cash | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1,227 |
| | 1,227 |
| Predecessor equity issued for acquisitions, net of cash received | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 4,281 |
| | 4,281 |
| Other comprehensive loss, net of tax | — |
| | — |
| | — |
| | — |
| | (117 | ) | | — |
| | — |
| | (117 | ) | Other, net | — |
| | 61 |
| | (4 | ) | | — |
| | — |
| | (19 | ) | | 4 |
| | 42 |
| Net income (loss) | 513 |
| | 606 |
| | 217 |
| | — |
| | — |
| | 116 |
| | (153 | ) | | 1,299 |
| Balance, December 31, 2014 | 184 |
| | 10,430 |
| | 1,512 |
| | — |
| | (56 | ) | | 5,153 |
| | 8,088 |
| | 25,311 |
| Distributions to partners | (944 | ) | | (1,863 | ) | | (247 | ) | | (80 | ) | | — |
| | — |
| | — |
| | (3,134 | ) | Predecessor distributions to partners | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (202 | ) | | (202 | ) | Distributions to noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | (338 | ) | | — |
| | (338 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Units issued for cash | — |
| | 1,428 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1,428 |
| Subsidiary units issued for cash | 2 |
| | 298 |
| | — |
| | — |
| | — |
| | 1,219 |
| | — |
| | 1,519 |
| Predecessor units issued for cash | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 34 |
| | 34 |
| Capital contributions from noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | 875 |
| | — |
| | 875 |
| Regency Merger | — |
| | 7,890 |
| | — |
| | — |
| | — |
| | — |
| | (7,890 | ) | | — |
| 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 | ) | Other comprehensive income, net of tax | — |
| | — |
| | — |
| | — |
| | 60 |
| | — |
| | — |
| | 60 |
| Other, net | — |
| | 23 |
| | — |
| | — |
| | — |
| | 36 |
| | 4 |
| | 63 |
| Net income (loss) | 1,064 |
| | (18 | ) | | 258 |
| | 94 |
| | — |
| | 157 |
| | (34 | ) | | 1,521 |
| Balance, December 31, 2015 | $ | 306 |
| | $ | 17,043 |
| | $ | 3,469 |
| | $ | 14 |
| | $ | 4 |
| | $ | 6,195 |
| | $ | — |
| | $ | 27,031 |
|
ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
| | | | | | | | | | | | | | Years Ended December 31, | | 2015 | | 2014 | | 2013 | OPERATING ACTIVITIES: | | | | | | Net income | $ | 1,521 |
| | $ | 1,299 |
| | $ | 746 |
| Reconciliation of net income to net cash provided by operating activities: | | | | | | Depreciation, depletion and amortization | 1,929 |
| | 1,669 |
| | 1,296 |
| Deferred income taxes | 202 |
| | (49 | ) | | 48 |
| Amortization included in interest expense | (36 | ) | | (60 | ) | | (72 | ) | Inventory valuation adjustments | 104 |
| | 473 |
| | (3 | ) | Unit-based compensation expense | 79 |
| | 68 |
| | 54 |
| Impairment losses | 339 |
| | 370 |
| | 689 |
| Gain on sale of AmeriGas common units | — |
| | (177 | ) | | (87 | ) | Losses on extinguishments of debt | 43 |
| | 25 |
| | 7 |
| Distributions on unvested awards | (16 | ) | | (16 | ) | | (12 | ) | Equity in earnings of unconsolidated affiliates | (469 | ) | | (332 | ) | | (236 | ) | Distributions from unconsolidated affiliates | 440 |
| | 291 |
| | 313 |
| Other non-cash | (22 | ) | | (72 | ) | | 42 |
| Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | (1,367 | ) | | (320 | ) | | (158 | ) | Net cash provided by operating activities | 2,747 |
| | 3,169 |
| | 2,627 |
| INVESTING ACTIVITIES: | | | | | | Proceeds from Bakken Pipeline Transaction | 980 |
| | — |
| | — |
| Proceeds from Susser Exchange Transaction | 967 |
| | — |
| | — |
| Proceeds from sale of noncontrolling interest | 64 |
| | — |
| | — |
| Proceeds from the sale of AmeriGas common units | — |
| | 814 |
| | 346 |
| Cash transferred to ETE in connection with the Sunoco LP Exchange | (114 | ) | | — |
| | — |
| Cash paid for acquisition of a noncontrolling interest | (129 | ) | | (325 | ) | | — |
| Cash paid for Susser Merger, net of cash received | — |
| | (808 | ) | | — |
| Cash paid for predecessor acquisitions, net of cash received | — |
| | (762 | ) | | — |
| Cash paid for ETP Holdco Acquisition | — |
| | — |
| | (1,332 | ) | Cash paid for all other acquisitions | (675 | ) | | (472 | ) | | (405 | ) | Capital expenditures (excluding allowance for equity funds used during construction) | (9,098 | ) | | (5,213 | ) | | (3,469 | ) | Contributions in aid of construction costs | 80 |
| | 45 |
| | 52 |
| Contributions to unconsolidated affiliates | (45 | ) | | (399 | ) | | (3 | ) | Distributions from unconsolidated affiliates in excess of cumulative earnings | 124 |
| | 136 |
| | 419 |
| Proceeds from sale of discontinued operations | — |
| | 77 |
| | 1,008 |
| Proceeds from the sale of assets | 23 |
| | 61 |
| | 68 |
| Change in restricted cash | 19 |
| | 172 |
| | (348 | ) | Other | (16 | ) | | (18 | ) | | 21 |
| Net cash used in investing activities | (7,820 | ) | | (6,692 | ) | | (3,643 | ) | | | | | | |
| | | | | | | | | | | | | FINANCING ACTIVITIES: | | | | | | Proceeds from borrowings | 22,462 |
| | 15,354 |
| | 10,854 |
| Repayments of long-term debt | (17,843 | ) | | (12,702 | ) | | (8,700 | ) | Proceeds from borrowings from affiliates | 233 |
| | — |
| | — |
| Repayments of borrowings from affiliates | — |
| | — |
| | (166 | ) | Units issued for cash | 1,428 |
| | 1,382 |
| | 1,611 |
| Subsidiary units issued for cash | 1,519 |
| | 1,244 |
| | — |
| Predecessor units issued for cash | 34 |
| | 1,227 |
| | 149 |
| Capital contributions from noncontrolling interest | 841 |
| | 67 |
| | 18 |
| Distributions to partners | (3,134 | ) | | (1,964 | ) | | (1,802 | ) | Predecessor distributions to partners | (202 | ) | | (645 | ) | | (342 | ) | Distributions to noncontrolling interest | (338 | ) | | (241 | ) | | (303 | ) | Debt issuance costs | (63 | ) | | (63 | ) | | (57 | ) | Other | — |
| | (41 | ) | | (42 | ) | Net cash provided by financing activities | 4,937 |
| | 3,618 |
| | 1,220 |
| Increase (decrease) in cash and cash equivalents | (136 | ) | | 95 |
| | 204 |
| Cash and cash equivalents, beginning of period | 663 |
| | 568 |
| | 364 |
| Cash and cash equivalents, end of period | $ | 527 |
| | $ | 663 |
| | $ | 568 |
|
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” 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.
The Partnership is engaged in the gathering and processing, compression, treating and transportation of natural gas, focusing on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Utica, Bone Spring and Avalon shales.
The Partnership is engaged in intrastate transportation and storage natural gas operations that own and operate natural gas pipeline systems that are engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia.
The Partnership owns and operates interstate pipelines, either directly or through equity method investments, that transport natural gas to various markets in the United States.
The Partnership owns a controlling interest in Sunoco Logistics, a publicly traded Delaware limited partnership that owns and operates a logistics business, consisting of crude oil, NGL and refined products pipelines.
The Partnership 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. In November 2015, the Partnership and certain of its subsidiaries entered into a contribution agreement with Sunoco LP and certain of its subsidiaries, pursuant to which the Partnership agreed to contribute to Sunoco LP the Partnership’s remaining 68.42% membership interest in Sunoco, LLC and 100% of the membership interests in Sunoco Retail LLC. Sunoco Retail LLC, which is expected to be formed prior to the closing of the contribution, is expected to own all of the Partnership’s remaining retail assets that are currently held by subsidiaries of Sunoco, Inc., along with certain other assets. In exchange, the Partnership expects to receive $2.03 billion in cash, subject to certain working capital adjustments, and 5.7 million Sunoco LPUSAC common units which will be issued and sold to a subsidiary of the Partnership in private transactions exempt from registration under Section 4(a)(2) of the Securities Act of 1933, as amended. The transaction will be effective January 1, 2016 and is expected to close in early March 2016.
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 21 million ETP common units owned by ETE. These operations were reported within the retail marketing segment. In connection with this transaction, the Partnership deconsolidated Sunoco LP, and its remaining investment in Sunoco LP is accounted for under the equity method.
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 0.4124 Partnership common units. ETP issued 172.2 million Partnership common units to Regency unitholders, including 15.5 million units issued to Partnership subsidiaries. The 1.9 million outstanding Regency series A preferred units were converted into corresponding new Partnership Series A 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.
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.
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: |
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.
New Accounting Pronouncements
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. In August 2015, the FASB deferred the effective date of ASU 2014-09, which is now effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is permitted as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within those annual periods. ASU 2014-09 can be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the vesting 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 February 2015, the FASB issued Accounting Standards Update No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis (“ASU 2015-02”), which changed the requirements for consolidation analysis. Under ASU 2015-02, reporting entities are required to evaluate whether they should consolidate certain legal entities. ASU 2015-02 is effective for fiscal years beginning after December 15, 2015, and early adoption was permitted. We expect to adopt this standard for the year ended December 31, 2016, and we do not anticipate a material impact to our financial position or results of operations as a result of the adoption of this standard.
In April 2015, the FASB issued Accounting Standards Update No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30) (“ASU 2015-03”), which simplifies the presentation of debt issuance costs by requiring debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the debt liability rather than as an asset. ASU 2015-03 is effective for annual reporting periods after December 15, 2015, including interim periods within that reporting period, with early adoption permitted for financial statements that have not been previously issued. Upon adoption, ASU 2015-03 must be applied retrospectively to all prior reporting period presented. We adopted and applied this standard to all consolidated financial statements presented and there was not a material impact to our financial position or results of operations as a result of the adoption of this standard.
In August 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805) - Simplifying the Accounting for Measurement-Period Adjustments. This update requires that an acquirer recognize adjustments to provisional amounts that
are identified during the measurement period in the reporting period in which the adjustment amounts are determined. Additionally, this update requires that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. Finally, this update requires an entity to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The amendments in this update are effective for financial statements issued with fiscal years beginning after December 15, 2015, including interim periods within that reporting period. We do not anticipate a material impact to our financial position or results of operations as a result of the adoption of this standard.
In November 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (“ASU 2015-17”), which is intended to improve how deferred taxes are classified on organizations’ balance sheets. The ASU eliminates the current requirement for organizations to present deferred tax liabilities and assets as current and noncurrent in a classified balance sheet. Instead, organizations are now required to classify all deferred tax assets and liabilities as noncurrent. We adopted the provisions of ASU 2015-17 upon issuance and prior period amounts have been reclassified to conform to the current period presentation. As a result of the early adoption and retrospective application of ASU 2015-17, $85 million of deferred tax liability previously presented as an other current liability as of December 31, 2014 has been reclassified to other non-current liabilities in our consolidated financial statements.
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. 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 gross 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.
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 of 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, | | 2015 | | 2014 | | 2013 | Accounts receivable | $ | 819 |
| | $ | 600 |
| | $ | (557 | ) | Accounts receivable from related companies | (243 | ) | | (22 | ) | | 26 |
| Inventories | (351 | ) | | 51 |
| | (254 | ) | Exchanges receivable | 13 |
| | 18 |
| | (8 | ) | Other current assets | (191 | ) | | 132 |
| | (58 | ) | Other non-current assets, net | 188 |
| | (6 | ) | | (45 | ) | Accounts payable | (1,215 | ) | | (851 | ) | | 542 |
| Accounts payable to related companies | (160 | ) | | 3 |
| | (143 | ) | Exchanges payable | (78 | ) | | (99 | ) | | 128 |
| Accrued and other current liabilities | (5 | ) | | (92 | ) | | 211 |
| Other non-current liabilities | (219 | ) | | (73 | ) | | 147 |
| Price risk management assets and liabilities, net | 75 |
| | 19 |
| | (147 | ) | Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | $ | (1,367 | ) | | $ | (320 | ) | | $ | (158 | ) |
Non-cash investing and financing activities and supplemental cash flow information are as follows:
| | | | | | | | | | | | | | Years Ended December 31, | | 2015 | | 2014 | | 2013 | NON-CASH INVESTING ACTIVITIES: | | | | | | Accrued capital expenditures | $ | 896 |
| | $ | 643 |
| | $ | 226 |
| Net gains from subsidiary common unit transactions | 300 |
| | 175 |
| | — |
| NON-CASH FINANCING ACTIVITIES: | | | | | | 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 |
| | — |
| | — |
| Issuance of Common Units in connection with the Susser Merger | — |
| | 908 |
| | — |
| Issuance of Common Units in connection with the ETP Holdco Acquisition | — |
| | — |
| | 2,464 |
| Issuance of Class H Units | — |
| | — |
| | 1,514 |
| Contribution of property, plant and equipment from noncontrolling interest | 34 |
| | — |
| | — |
| Long-term debt assumed and non-compete agreement notes payable issued in acquisitions | — |
| | 564 |
| | — |
| Predecessor equity issuances of common units in connection with Regency’s acquisitions | — |
| | 4,281 |
| | — |
| Long-term debt assumed or exchanged in Regency’s acquisitions | — |
| | 2,386 |
| | — |
| Redemption of Common Units in connection with the Bakken Pipeline Transaction | 999 |
| | — |
| | — |
| Redemption of Common Units in connection with the Sunoco LP Exchange | 52 |
| | — |
| | — |
| Redemption of Common Units in connection with the Lake Charles LNG Transaction | — |
| | 1,167 |
| | — |
| SUPPLEMENTAL CASH FLOW INFORMATION: | | | | | | Cash paid for interest, net of interest capitalized | $ | 1,467 |
| | $ | 1,232 |
| | $ | 1,049 |
| Cash paid for income taxes | 71 |
| | 344 |
| | 58 |
|
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 for all counterparties and limits are monitored against credit exposure. Letters of credit or prepayments may be required from those counterparties that are not investment grade depending on the internal credit rating and level of commercial activity with the counterparty. Master setoff agreements are put in place with counterparties where appropriate to mitigate risk. Bad debt expense related to these receivables is recognized at the time an account is deemed uncollectible.
Our investment in Sunoco Logistics segment extends credit terms to certain customers after review of various credit indicators, including the customer’s credit rating. Based on that review, a letter of credit or other security may be required. Outstanding customer receivable balances are regularly reviewed for possible non-payment indicators and reserves are recorded for doubtful accounts based upon management’s estimate of collectability at the time of review. Actual balances are charged against the reserve when all collection efforts have been exhausted.
We have a concentration of customers in the electric and gas utility industries as well as oil and natural gas producers and municipalities. 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. We manage trade credit risk to mitigate credit losses and exposure to uncollectible trade receivables. Prospective and existing customers are reviewed regularly for creditworthiness based upon pre-established standards consistent with FERC filed tariffs 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.
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 in the form of a cash deposit, letter of credit or mortgages may be required. Management records reserves for bad debt by computing a proportion of average write-off activity over 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.
We enter into netting arrangements with counterparties of derivative contracts 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
Inventories consist principally of natural gas held in storage, crude oil, refined products and spare parts. Natural gas held in storage is valued at the lower of cost or market utilizing the weighted-average cost method. The cost of crude oil and refined products is determined using the last-in, first out method. The cost of spare parts is determined by the first-in, first-out method.
Inventories consisted of the following:
| | | | | | | | | | December 31, | | 2015 | | 2014 | Natural gas and NGLs | $ | 415 |
| | $ | 392 |
| Crude oil | 424 |
| | 364 |
| Refined products | 104 |
| | 392 |
| Spare parts and other | 270 |
| | 312 |
| Total inventories | $ | 1,213 |
| | $ | 1,460 |
|
During the year ended December 31, 2015, the Partnership recorded write-downs of $104 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.
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 cost 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, | | 2015 | | 2014 | Deposits paid to vendors | $ | 74 |
| | $ | 65 |
| Income taxes receivable | 291 |
| | 17 |
| Prepaid expenses and other | 137 |
| | 200 |
| Total other current assets | $ | 502 |
| | $ | 282 |
|
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 2015, the Partnership recorded a $110 million fixed asset impairment related to the liquids 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.
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, | | 2015 | | 2014 | Land and improvements | $ | 686 |
| | $ | 1,307 |
| Buildings and improvements (1 to 45 years) | 1,526 |
| | 1,918 |
| Pipelines and equipment (5 to 83 years) | 33,148 |
| | 27,164 |
| Natural gas and NGL storage facilities (5 to 46 years) | 391 |
| | 1,215 |
| Bulk storage, equipment and facilities (2 to 83 years) | 2,853 |
| | 2,583 |
| Tanks and other equipment (5 to 40 years) | 60 |
| | 58 |
| Retail equipment (2 to 99 years) | 401 |
| | 515 |
| Vehicles (1 to 25 years) | 220 |
| | 203 |
| Right of way (20 to 83 years) | 2,573 |
| | 2,445 |
| Furniture and fixtures (2 to 25 years) | 55 |
| | 57 |
| Linepack | 61 |
| | 119 |
| Pad gas | 44 |
| | 44 |
| Natural resources | 484 |
| | 454 |
| Other (1 to 30 years) | 523 |
| | 979 |
| Construction work-in-process | 7,844 |
| | 4,343 |
| | 50,869 |
| | 43,404 |
| Less – Accumulated depreciation and depletion | (5,782 | ) | | (4,497 | ) | Property, plant and equipment, net | $ | 45,087 |
| | $ | 38,907 |
|
We recognized the following amounts for the periods presented:
| | | | | | | | | | | | | | Years Ended December 31, | | 2015 | | 2014 | | 2013 | Depreciation and depletion expense | $ | 1,713 |
| | $ | 1,457 |
| | $ | 1,202 |
| Capitalized interest, excluding AFUDC | $ | 163 |
| | $ | 101 |
| | $ | 45 |
|
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.
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, | | 2015 | | 2014 | Unamortized financing costs(1) | $ | 11 |
| | $ | 30 |
| Regulatory assets | 90 |
| | 85 |
| Deferred charges | 198 |
| | 220 |
| Restricted funds | 192 |
| | 177 |
| Other | 45 |
| | 132 |
| Total other non-current assets, net | $ | 536 |
| | $ | 644 |
|
(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, 2015 | | December 31, 2014 | | Gross Carrying Amount | | Accumulated Amortization | | Gross Carrying Amount | | Accumulated Amortization | Amortizable intangible assets: | | | | | | | | Customer relationships, contracts and agreements (3 to 46 years) | $ | 4,601 |
| | $ | (554 | ) | | $ | 5,067 |
| | $ | (464 | ) | Patents (9 years) | 48 |
| | (16 | ) | | 48 |
| | (11 | ) | Trade Names (15 years) | 66 |
| | (18 | ) | | 556 |
| | (15 | ) | Other (1 to 15 years) | 6 |
| | (3 | ) | | 36 |
| | (7 | ) | Total amortizable intangible assets | $ | 4,721 |
| | $ | (591 | ) | | $ | 5,707 |
| | $ | (497 | ) | Non-amortizable intangible assets: | | | | | | | | Trademarks | 291 |
| | — |
| | 316 |
| | — |
| Total intangible assets | $ | 5,012 |
| | $ | (591 | ) | | $ | 6,023 |
| | $ | (497 | ) |
Aggregate amortization expense of intangible assets was as follows:
| | | | | | | | | | | | | | Years Ended December 31, | | 2015 | | 2014 | | 2013 | Reported in depreciation, depletion and amortization | $ | 216 |
| | $ | 212 |
| | $ | 117 |
|
Estimated aggregate amortization expense for the next five years is as follows:
| | | | | Years Ending December 31: | | 2016 | $ | 195 |
| 2017 | 195 |
| 2018 | 195 |
| 2019 | 193 |
| 2020 | 193 |
|
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 liquids transportation and services segment primarily due to an expected decrease in future cash flows.
Goodwill
Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test is performed during the fourth quarter.
Changes in the carrying amount of goodwill were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Intrastate Transportation and Storage | | Interstate Transportation and Storage | | Midstream | | Liquids Transportation and Services | | Investment in Sunoco Logistics | | Retail Marketing | | All Other | | Total | Balance, December 31, 2013 | $ | 10 |
| | $ | 1,195 |
| | $ | 686 |
| | $ | 432 |
| | $ | 1,346 |
| | $ | 1,445 |
| | $ | 742 |
| | $ | 5,856 |
| Acquired | — |
| | — |
| | 451 |
| | — |
| | 12 |
| | 1,862 |
| | 15 |
| | 2,340 |
| Disposed | — |
| | (184 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (184 | ) | Impaired | — |
| | — |
| | (370 | ) | | — |
| | — |
| | — |
| | — |
| | (370 | ) | Balance, December 31, 2014 | 10 |
| | 1,011 |
| | 767 |
| | 432 |
| | 1,358 |
| | 3,307 |
| | 757 |
| | 7,642 |
| Reduction due to Sunoco LP deconsolidation | — |
| | — |
| | — |
| | — |
| | — |
| | (2,018 | ) | | — |
| | (2,018 | ) | Impaired | — |
| | (99 | ) | | — |
| | (106 | ) | | — |
| |
|
| | — |
| | (205 | ) | Other | — |
| | — |
| | (49 | ) | | — |
| | — |
| | — |
| | 58 |
| | 9 |
| Balance, December 31, 2015 | $ | 10 |
| | $ | 912 |
| | $ | 718 |
| | $ | 326 |
| | $ | 1,358 |
| | $ | 1,289 |
| | $ | 815 |
| | $ | 5,428 |
|
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 decrease in goodwill of $2.21 billion during the year ended December 31, 2015, primarily due the deconsolidation of Sunoco LP of $2.02 billion subsequent to ETE’s acquisition in 2015 (see Note 3).
During 2015, the Partnership voluntarily changed the date of the annual goodwill impairment testing to the first day of the fourth quarter. The Partnership believes this new date is preferable because it allows for more timely completion of the annual goodwill impairment test prior to the end of the annual financial reporting period. This change in accounting principle does not delay, accelerate or avoid any potential impairment loss, nor does the change have a cumulative effect on income from continuing operations, net income or loss, or net assets. This change was not applied retrospectively, as doing so would require the use of significant estimates and assumptions that include hindsight. Accordingly, the Partnership applied the change in annual goodwill impairment testing date prospectively beginning October 1, 2015.
During the fourth quarter of 2015, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of: (i) $99 million in the Transwestern reporting unit due primarily to the market declines in current and expected future commodity prices in the fourth quarter of 2015 and (ii) $106 million in the Lone Star Refinery Services reporting unit due primarily to changes in assumptions related to potential future revenues decrease as well as the market declines in current and expected future commodity prices.
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.
The Partnership determined the fair value of our reporting units using a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determined fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determined the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimated a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business.
Asset Retirement Obligations
We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be Level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.
An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an asset retirement obligation in the periods in which management can reasonably estimate the settlement dates.
Except for certain amounts recorded by Panhandle, 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, 2015 and 2014, 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 it 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 as other non-current liabilities in ETP’s consolidated balance sheets:
| | | | | | | | | | December 31, | | 2015 | | 2014 | Interstate transportation and storage | $ | 58 |
| | $ | 60 |
| Investment in Sunoco Logistics | 88 |
| | 41 |
| Retail marketing | 66 |
| | 87 |
| | $ | 212 |
| | $ | 188 |
|
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 $18 million and were reflected as property, plant and equipment on our balance sheet as of December 31, 2015 and 2014. In addition, the Partnership had $6 million legally restricted funds for the purpose of settling AROs that was reflected as other non-current assets as of December 31, 2015.
Accrued and Other Current Liabilities
Accrued and other current liabilities consisted of the following:
| | | | | | | | | | December 31, | | 2015 | | 2014 | Interest payable | $ | 425 |
| | $ | 382 |
| Customer advances and deposits | 95 |
| | 103 |
| Accrued capital expenditures | 743 |
| | 673 |
| Accrued wages and benefits | 218 |
| | 233 |
| Taxes payable other than income taxes | 76 |
| | 236 |
| Other | 386 |
| | 373 |
| Total accrued and other current liabilities | $ | 1,943 |
| | $ | 2,000 |
|
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’ 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 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, 2015 was $25.71 billion and $28.68 billion, respectively. As of December 31, 2014, the aggregate fair value and carrying amount of our debt obligations was $26.91 billion and $25.84 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.
We have commodity derivatives, interest rate derivatives and embedded derivatives in our preferred units that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. Derivatives related to the embedded derivatives in our preferred units are valued using a binomial lattice model. The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected value, and are considered Level 3. During the year ended December 31, 2015, 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, 2015 and 2014 based on inputs used to derive their fair values:
| | | | | | | | | | | | | | | | | | Fair Value Total | | Fair Value Measurements at December 31, 2015 | | Level 1 | | Level 2 | | Level 3 | Assets: | | | | | | | | Commodity derivatives: | | | | | | | | Natural Gas: | | | | | | | | Basis Swaps IFERC/NYMEX | 16 |
| | 16 |
| | — |
| | — |
| Swing Swaps IFERC | 10 |
| | 2 |
| | 8 |
| | — |
| Fixed Swaps/Futures | 274 |
| | 274 |
| | — |
| | — |
| Forward Physical Swaps | 4 |
| | — |
| | 4 |
| | — |
| Power: | | | | | | | | Forwards | 22 |
| | — |
| | 22 |
| | — |
| Futures | 3 |
| | 3 |
| | — |
| | — |
| Options – Puts | 1 |
| | 1 |
| | — |
| | — |
| Options – Calls | 1 |
| | 1 |
| | — |
| | — |
| Natural Gas Liquids – Forwards/Swaps | 99 |
| | 99 |
| | — |
| | — |
| Refined Products – Futures | 9 |
| | 9 |
| | — |
| | — |
| Crude – Futures | 9 |
| | 9 |
| | — |
| | — |
| Total commodity derivatives | 448 |
| | 414 |
| | 34 |
| | — |
| Total assets | $ | 448 |
| | $ | 414 |
| | $ | 34 |
| | $ | — |
| Liabilities: | | | | | | | | Interest rate derivatives | $ | (171 | ) | | $ | — |
| | $ | (171 | ) | | $ | — |
| Embedded derivatives in the ETP Preferred Units | (5 | ) | | — |
| | — |
| | (5 | ) | Commodity derivatives: | | | | | | | | Natural Gas: | | | | | | | | Basis Swaps IFERC/NYMEX | (16 | ) | | (16 | ) | | — |
| | — |
| Swing Swaps IFERC | (12 | ) | | (2 | ) | | (10 | ) | | — |
| Fixed Swaps/Futures | (203 | ) | | (203 | ) | | — |
| | — |
| Power: | | | | | | | | Forwards | (22 | ) | | — |
| | (22 | ) | | — |
| Futures | (2 | ) | | (2 | ) | | — |
| | — |
| Options – Puts | (1 | ) | | (1 | ) | | — |
| | — |
| Natural Gas Liquids – Forwards/Swaps | (89 | ) | | (89 | ) | | — |
| | — |
| Crude – Futures | (5 | ) | | (5 | ) | | — |
| | — |
| Total commodity derivatives | (350 | ) | | (318 | ) | | (32 | ) | | — |
| Total liabilities | $ | (526 | ) | | $ | (318 | ) | | $ | (203 | ) | | $ | (5 | ) |
| | | | | | | | | | | | | | | | | | Fair Value Total | | Fair Value Measurements at December 31, 2014 | | 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 Swaps | 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 ETP 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 | ) |
The following table presents the material unobservable inputs used to estimate the fair value of ETP’s Preferred Units and the embedded derivatives in ETP’s Preferred Units:
| | | | | | | Unobservable Input | | December 31, 2015 | Embedded derivatives in the ETP Preferred Units | Credit Spread | | 5.33 | % | | Volatility | | 37.0 | % |
Changes in the remaining term of the Preferred Units, U.S. Treasury yields and valuations in related instruments would cause a change in the yield to value the Preferred Units. Changes in ETP’s cost of equity and U.S. Treasury yields would cause a change in the credit spread used to value the embedded derivatives in the ETP Preferred Units. Changes in ETP’s historical unit price volatility would cause a change in the volatility used to value the embedded derivatives.
The following table presents a reconciliation of the beginning and ending balances for our Level 3 financial instruments measured at fair value on a recurring basis using significant unobservable inputs for the year ended December 31, 2015.
| | | | | Balance, December 31, 2014 | $ | (16 | ) | Net unrealized gains included in other income (expense) | 11 |
| Balance, December 31, 2015 | $ | (5 | ) |
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
Costs 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 retail marketing 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). Excise taxes collected by our retail marketing segment were $1.85 billion, $2.46 billion and $2.22 billion for the years ended December 31, 2015, 20142018 and 2013, respectively.
IssuancesSunoco LP for the years ended December 31, 2017 and 2016. As of December 31, 2018, estimated compensation cost related to Subsidiary Units
We record changes in our ownership interest of our subsidiaries as equity transactions, with no gain or lossUnit Awards not yet recognized was $45 million, and the weighted average period over which this cost is expected to be recognized in consolidated netexpense is 3.3 years.
As a partnership, we are not subject to United States federal 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 federaltax 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, 2015, 2014, and 2013, 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, | | 2018 | | 2017 | | 2016 | Current expense (benefit): | | | | | | Federal | $ | (8 | ) | | $ | 54 |
| | $ | (47 | ) | State | 19 |
| | (16 | ) | | (34 | ) | Total | 11 |
| | 38 |
| | (81 | ) | Deferred expense (benefit): | | | | | | Federal | 181 |
| | (2,055 | ) | | (189 | ) | State | (188 | ) | | 184 |
| | 12 |
| Total | (7 | ) | | (1,871 | ) | | (177 | ) | Total income tax expense (benefit) from continuing operations | $ | 4 |
| | $ | (1,833 | ) | | $ | (258 | ) |
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 at the United States statutory rate to the income tax benefit attributable to continuing operations for the years ended December 31, 2018, 2017 and 2016 is as follows:
| | | | | | | | | | | | | | Years Ended December 31, | | 2018 | | 2017 | | 2016 | Income tax expense at United States statutory rate | $ | 763 |
| | $ | 248 |
| | $ | 71 |
| Increase (reduction) in income taxes resulting from: | | | | | | Partnership earnings not subject to tax | (635 | ) | | (477 | ) | | (576 | ) | Goodwill impairment | — |
| | 207 |
| | 278 |
| State tax, net of federal tax benefit | (125 | ) | | 124 |
| | (10 | ) | Dividend received deduction | (5 | ) | | (14 | ) | | (15 | ) | Federal rate change | — |
| | (1,812 | ) | | — |
| Change in tax status of subsidiary | — |
| | (124 | ) | | — |
| Other | 6 |
| | 15 |
| | (6 | ) | Income tax expense (benefit) from continuing operations | $ | 4 |
| | $ | (1,833 | ) | | $ | (258 | ) |
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, | | 2018 | | 2017 | Deferred income tax assets: | | | | Net operating losses, alternative minimum tax credit and other carryforwards | $ | 768 |
| | $ | 683 |
| Pension and other postretirement benefits | 34 |
| | 21 |
| Long-term debt | 13 |
| | 14 |
| Other | 181 |
| | 191 |
| Total deferred income tax assets | 996 |
| | 909 |
| Valuation allowance | (96 | ) | | (189 | ) | Net deferred income tax assets | 900 |
| | 720 |
| | | | | Deferred income tax liabilities: | | | | Property, plant and equipment | (782 | ) | | (1,036 | ) | Investments in unconsolidated affiliates | (2,872 | ) | | (2,726 | ) | Trademarks | (63 | ) | | (173 | ) | Other | (109 | ) | | (100 | ) | Total deferred income tax liabilities | (3,826 | ) | | (4,035 | ) | Net deferred income taxes | $ | (2,926 | ) | | $ | (3,315 | ) |
As of December 31, 2018, ETP Holdco had a federal net operating loss carryforward of $2.60 billion, of which $1.80 billion will expire in 2031 through 2037 while the remaining can be carried forward indefinitely. As of December 31, 2017, Sunoco Property Company LLC, a corporate subsidiary of Sunoco LP, had a federal net operating loss carryforward of $364 million. The entire net operating loss carryforward will be fully utilized to offset the taxable gain associated with the retail divestment in 2018. Our corporate subsidiaries have $31 million of federal alternative minimum tax credits at December 31, 2018, of which $16 million is expected to be reclassified to current income tax receivable in 2019 pursuant to the Tax Cuts and Jobs Act. Our corporate subsidiaries have state net operating loss carryforward benefits of $168 million, net of federal tax, which expire between 2019 and 2037. A valuation allowance of $98 million is applicable to the state net operating loss carryforward benefits primarily attributable to significant restrictions on their use in the Commonwealth of Pennsylvania.
The following table sets forth the changes in unrecognized tax benefits: | | | | | | | | | | | | | | Years Ended December 31, | | 2018 | | 2017 | | 2016 | Balance at beginning of year | $ | 609 |
| | $ | 615 |
| | $ | 610 |
| Additions attributable to tax positions taken in the current year | 8 |
| | — |
| | 8 |
| Additions attributable to tax positions taken in prior years | 7 |
| | 28 |
| | 18 |
| Reduction attributable to tax positions taken in prior years | — |
| | (25 | ) | | (20 | ) | Lapse of statute | — |
| | (9 | ) | | (1 | ) | Balance at end of year | $ | 624 |
| | $ | 609 |
| | $ | 615 |
|
As of December 31, 2018, we have $620 million ($588 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 2018, we recognized interest and penalties of less than $6 million. At December 31, 2018, we have interest and penalties accrued of $15 million, net of tax. Sunoco, Inc. 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 for the 2004 through 2009 years. Sunoco, Inc.’s 2010 and 2011 years are extended for this issue with the IRS. In November 2016, the CFC ruled against Sunoco, Inc., and the United States Court of Appeals for the Federal Circuit (the “Federal Circuit”) affirmed the CFC’s ruling on November 1, 2018. Sunoco, Inc. subsequently filed a petition for rehearing with the Federal Circuit, and this was denied on January 24, 2019. Sunoco, Inc. is considering further review of the Federal Circuit’s affirmation of the CFC’s ruling. 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 balance sheets as of December 31, 2018 and 2017. In November 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 subsequently filed a petition for writ of certiorari with the United States Supreme Court, and this was denied on June 11, 2018. Now certain Pennsylvania taxpayers are proceeding with litigation in Pennsylvania state courts on issues not addressed by the Pennsylvania Supreme Court in Nextel, specifically, whether the Due Process and Equal Protection Clauses of the United States Constitution and the Remedies Clause of the Pennsylvania Constitution require a court to grant the taxpayer relief. 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 $34 million ($27 million after federal income tax benefits) against the receivable. In general, ET and its subsidiaries are no longer subject to examination by the IRS, and most state jurisdictions, for the 2013 and prior tax years. However, Sunoco, Inc. and its subsidiaries remain subject to examination by the IRS for tax years beginning in 2007. Sunoco, Inc. has been examined by the IRS for tax years through October 4, 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. ET 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.
On December 22, 2017, the Tax Cuts and Jobs Act was signed into law. Among other provisions, the highest corporate subsidiaries include ETP Holdco, Oasis Pipeline Company and until Julyfederal income tax rate was reduced from 35% to 21% for taxable years beginning after December 31, 2015, Susser Holding Corporation. The2017. As a result, the Partnership andrecognized a deferred tax benefit of $1.81 billion in December 2017. For the year ended December 31, 2018, the Partnership recorded an income tax expense due to pre-tax income at 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 ispartially 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.a state statutory rate reduction.
Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged.
If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, the change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations.
We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar instruments. Certain of our interest rate derivatives are accounted for as either cash flow hedges or fair value hedges. For interest rate derivatives accounted for as either cash flow or fair value hedges, we report realized gains and losses and ineffectiveness portions of those hedges in interest expense. For interest rate derivatives not designated as hedges for accounting purposes, we report realized and unrealized gains and losses on those derivatives in “Gains (losses) on interest rate derivatives” in the consolidated statements of operations.
Unit-Based Compensation
For awards of restricted units, we recognize compensation expense over the vesting period based on the grant-date fair value, which is determined based on the market price of our Common Units on the grant date. For awards of cash restricted units, we remeasure the fair value of the award at the end of each reporting period based on the market price of our Common Units as of the reporting date, and the fair value is recorded in other non-current liabilities on our consolidated balance sheets.
Pensions and Other Postretirement Benefit Plans
Employers are required to recognize in their balance sheets 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. Employers must recognize the change in the funded status of the plan in the year in which the change occurs within AOCI in equity or, for entities applying regulatory accounting, as a regulatory asset or regulatory liability.
Allocation of Income
For purposes of maintaining partner capital accounts, the Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests. The capital account provisions of our Partnership Agreement incorporate principles established for U.S. 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.
| | 3.11. | ACQUISITIONS, DIVESTITURESREGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND RELATED TRANSACTIONS:ENVIRONMENTAL LIABILITIES: |
2015 Transactions
Sunoco LLC to 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 $41 million of 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.
Susser to Sunoco LPFERC Proceedings
In July 2015, in exchangeMarch 2016, the FERC commenced an audit of Trunkline for the contributionperiod from January 1, 2013 to present to evaluate Trunkline’s compliance with the requirements of 100%its FERC gas tariff, the accounting regulations 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 subsidiariesUniform System of ETP. The Sunoco LP Class A units ownedAccounts as prescribed by the Susser subsidiaries were contributedFERC, and the FERC’s annual reporting requirements. The FERC issued an audit report in October 2018. In response to Sunoco LP as partthe findings in the audit report, the Company expects to make certain changes to its processes, policies and procedures; however, the Company does not expect the findings to result in any changes to its financial statements. By order issued January 16, 2019, the FERC initiated a review of Panhandle’s existing rates pursuant to Section 5 of the transaction. Sunoco LP subsequently contributed its interests in SusserNatural Gas Act to one of its subsidiaries. Sunoco LP to ETE
Effective Julydetermine whether the rates currently charged by Panhandle are just and reasonable and set the matter for hearing. Panhandle must file a cost and revenue study on or before April 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 21 million ETP common units owned by ETE (the “Sunoco LP Exchange”). In connection with ETP’s 2014 acquisition of Susser, ETE agreed to provide ETP a $35 million annual IDR subsidy for 10 years, which terminated upon the closing of ETE’s acquisition of Sunoco GP. In connection with the exchange and repurchase, ETE will provide 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. The Partnership continues to hold 37.8 million Sunoco LP common units accounted for under the equity method. 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.
Sunoco, Inc. to Sunoco LP
In November 2015, ETP and Sunoco LP announced ETP’s contribution to Sunoco LP of the remaining 68.42% interest in Sunoco, LLC and 100% interest in the legacy Sunoco, Inc. retail business for $2.23 billion. Sunoco LP will pay ETP $2.03 billion in cash, subject to certain working capital adjustments, and will issue to ETP 5.7 million Sunoco LP common units. The transaction will be effective January 1, 2016 and2019. An initial decision is expected to close in March 2016.
Bakken Pipeline
In March 2015, ETE transferred 30.8 million Partnership common units, ETE’s 45% interestbe issued in the Bakken Pipeline project, and $879 million in cashfirst quarter of 2020.In addition, on November 30, 2018, Sea Robin filed a rate case pursuant 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 entitle ETE to receive 90.05%Section 4 of the cash distributionsNatural Gas Act. A hearing date is scheduled for October 23, 2019 and other economic attributesan initial decision is expected to be issued in the first quarter of 2020.
By order issued February 19, 2019, the FERC initiated a review of Southwest Gas Storage Company’s existing rates pursuant to Section 5 of the general partner interestNatural Gas Act to determine whether the rates currently charged by Southwest Gas Storage Company are just and IDRsreasonable and set the matter for hearing. Southwest Gas Storage Company must file a cost and revenue study on or before May 6, 2019. The FERC is directing that an initial decision be issued within 47 weeks of Sunoco Logistics (the “Bakken Pipeline Transaction”). the date the cost and revenue study is due. Commitments In connection with this transaction, the Partnership also issuednormal course of business, ETO purchases, processes and sells natural gas pursuant to ETE 100 Class I Unitslong-term contracts and enters into long-term transportation and storage agreements. Such contracts contain terms that provide distributions to ETE to offset IDR subsidies previously provided to ETP. These IDR subsidies, includingare customary in the impact from distributionsindustry. ETO believes that the terms of these agreements are commercially reasonable and will not have a material adverse effect on Class I Units, were reduced by $55 million in 2015 and $30 million in 2016.its financial position or results of operations. In October 2015, Sunoco Logistics completed the previously announced acquisition of a 40% membership interest (the “Bakken Membership Interest”) in Bakken Holdings Company LLC (“Bakken Holdco”). Bakken Holdco, through its wholly-owned subsidiaries, owns a 75% membership interest in each of Dakota Access, LLC and Energy Transfer Crude Oil Company, LLC, 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 itsOur joint venture agreements require that we funds our proportionate share of the total cashcapital contributions madeto its unconsolidated affiliates. Such contributions will depend upon our 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 Bakken Pipeline project asaccompanying statements 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 unitoperations, which include contingent rentals, and Class F unit was converted into the right to receive 0.4124 Partnership common units. ETP issued 172.2 million Partnership common units to Regency unitholders, including 15.5 million units issued to Partnership subsidiaries. The 1.9 million outstanding Regency series A preferred units were converted into corresponding new Partnership Series A Preferred Units on a one-for-one basis.
In connection with the Regency Merger, ETE agreed to reduce the incentive distributions it receives from the Partnership by a total of $320 million over a five-year period. The IDR subsidy was $80 million for the year ended December 31, 2015 and will total $60 million per year for the following four years.
The Regency Merger was a combination of entities under common control; therefore, Regency’s assets and liabilities were not adjusted. The Partnership’s consolidated financial statements have been retrospectively adjusted to reflect consolidation of Regency for all prior periods subsequent to May 26, 2010 (the date ETE acquired Regency’s general partner). Predecessor equity included on the consolidated financial statements represents Regency’s equity prior to the Regency Merger.
ETP has assumed all of the obligations of Regency and Regency Energy Finance Corp., of which ETP was previously a co-obligor or parent guarantor.
2014 Transactions
Susser Merger
In August 2014, ETP and Susser completed the merger of an indirect wholly-owned subsidiary of ETP, with and into Susser, with Susser surviving the merger as a subsidiary of ETP for total consideration valued at approximately $1.8 billion (the “Susser Merger”). The total consideration paid in cash was approximately $875 million and the total consideration paid in equity was approximately 15.8 million ETP Common Units. The Susser Merger broadens our retail geographic footprint and provides synergy opportunities and a platform for future growth.
In connection with the Susser Merger, ETP acquired an indirect 100% equity interest in Susser and the general partner interest and the incentive distribution rights in Sunoco LP, approximately 11 million Sunoco LP common and subordinated units, and Susser’s existing retail operations, consisting of 630 convenience store locations.
Effective with the closing of the transaction, Susser ceased to be a publicly traded company and its common stock discontinued trading on the NYSE.
Summary of Assets Acquired and Liabilities Assumed
We accounted for the Susser Merger using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date.
The following table summarizes the assets acquired and liabilities assumed recognized as of the merger date:rental expense recovered through related sublease rental income:
| | | | | | | | 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 |
|
| | | | | | | | | | | | | | | | Years Ended December 31, | | | 2018 | | 2017 | | 2016 | Rental expense(1) | | $ | 139 |
| | $ | 171 |
| | $ | 161 |
| Sublease rental income(2) | | 40 |
| | 25 |
| | 26 |
| Net | | $ | 99 |
| | $ | 146 |
| | $ | 135 |
|
| | (1) | None of the goodwill is expected to be deductibleIncludes contingent rentals totaling $4 million, $16 million and $18 million for tax purposes. |
The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.
ETP incurred merger related costs related to the Susser Merger of $25 million during the year ended December 31, 2014. Our consolidated statements of operations for the year ended December 31, 2014 reflected revenue and net income related to Susser of $2.32 billion and $105 million, respectively.
No pro forma information has been presented, as the impact of these acquisitions was not material in relation to ETP’s consolidated results of operations.
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, all of which have subsequently converted into ETP common units), and ETP (2.2 million Common Units).
Regency’s Acquisition of PVR Partners, L.P.
On March 21, 2014, Regency acquired PVR for a total purchase price of $5.7 billion (based on Regency’s closing price of $27.82 per Regency Common Unit on March 21, 2014), including $1.8 billion principal amount of assumed debt (the “PVR Acquisition”). PVR unitholders received (on a per unit basis) 1.02 Regency Common Units and a one-time cash payment of $36 million, which was funded through borrowings under Regency’s revolving credit facility. Our consolidated statement of operations for the year ended December 31, 2014 included revenues and net income attributable to PVR’s operations of $956 million and $166 million, respectively.
The total purchase price was allocated as follows:
| | | | | Assets | At March 21, 2014 | Current assets | $ | 149 |
| Property, plant and equipment | 2,716 |
| Investment in unconsolidated affiliates | 62 |
| Intangible assets (average useful life of 30 years) | 2,717 |
| Goodwill(1) | 370 |
| Other non-current assets | 18 |
| Total assets acquired | 6,032 |
| Liabilities | | Current liabilities | 168 |
| Long-term debt | 1,788 |
| Premium related to senior notes | 99 |
| Non-current liabilities | 30 |
| Total liabilities assumed | 2,085 |
| Net assets acquired | $ | 3,947 |
|
(1)None of the goodwill is expected to be deductible for tax purposes.
The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.
Regency’s Acquisition of Eagle Rock’s Midstream Business
On July 1, 2014, Regency acquired Eagle Rock’s midstream business (the “Eagle Rock Midstream Acquisition”) for $1.3 billion, including the assumption of $499 million of Eagle Rock’s 8.375% senior notes due 2019. The remainder of the purchase price was funded by $400 million in Regency Common Units sold to a wholly-owned subsidiary of ETE, 8.2 million Regency Common Units issued to Eagle Rock and borrowings under Regency’s revolving credit facility. Our consolidated statement of operations for the year ended December 31, 2014 included revenues and net income attributable to Eagle Rock’s operations of $903 million and $30 million, respectively.
The total purchase price was allocated as follows:
| | | | | Assets | At July 1, 2014 | Current assets | $ | 120 |
| Property, plant and equipment | 1,295 |
| Other non-current assets | 4 |
| Goodwill | 49 |
| Total assets acquired | 1,468 |
| Liabilities | | Current liabilities | 116 |
| Long-term debt | 499 |
| Other non-current liabilities | 12 |
| Total liabilities assumed | 627 |
| | | Net assets acquired | $ | 841 |
|
The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.
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:
| | | | | | Year Ended December 31, 2013 | Revenue from discontinued operations | $ | 415 |
| Net income of discontinued operations, excluding effect of taxes and overhead allocations | 65 |
|
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.
| | 4. | ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES: |
The carrying values of the Partnership’s investments in unconsolidated affiliates as of December 31, 2015 and 2014 were as follows:
| | | | | | | | | | December 31, | | 2015 | | 2014 | Citrus | $ | 1,739 |
| | $ | 1,823 |
| AmeriGas | 80 |
| | 94 |
| FEP | 115 |
| | 130 |
| MEP | 660 |
| | 695 |
| HPC | 402 |
| | 422 |
| Sunoco LP | 1,380 |
| | — |
| Others | 627 |
| | 596 |
| Total | $ | 5,003 |
| | $ | 3,760 |
|
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 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. In 2012, 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. Our investment in Citrus is reflected in our interstate transportation and storage segment.
AmeriGas
In 2012, we received 29.6 million AmeriGas common units in connection with the contribution of our propane operations. During the years ended December 31, 2014 and 2013, we sold 18.9 million and 7.5 million AmeriGas common units, respectively, for net proceeds of $814 million and $346 million, respectively. 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 and is reflected in the all other 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.
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.
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.
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. Our investment in Sunoco LP is reflected in the retail marketing segment.
Summarized Financial Information
The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, AmeriGas, Citrus, FEP, HPC, MEP and Sunoco LP (on a 100% basis) for all periods presented:
| | | | | | | | | | December 31, | | 2015 | | 2014 | Current assets | $ | 1,646 |
| | $ | 889 |
| Property, plant and equipment, net | 12,611 |
| | 10,520 |
| Other assets | 5,485 |
| | 2,687 |
| Total assets | $ | 19,742 |
| | $ | 14,096 |
| | | | | Current liabilities | $ | 1,517 |
| | $ | 1,983 |
| Non-current liabilities | 10,428 |
| | 7,359 |
| Equity | 7,797 |
| | 4,754 |
| Total liabilities and equity | $ | 19,742 |
| | $ | 14,096 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2015 | | 2014 | | 2013 | Revenue | $ | 20,961 |
| | $ | 4,925 |
| | $ | 4,695 |
| Operating income | 1,620 |
| | 1,071 |
| | 1,197 |
| Net income | 894 |
| | 577 |
| | 699 |
|
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: |
The following table provides a reconciliation of the numerator and denominator of the basic and diluted income (loss) per unit.
| | | | | | | | | | | | | | Years Ended December 31, | | 2015 | | 2014 | | 2013 | Income from continuing operations | $ | 1,521 |
| | $ | 1,235 |
| | $ | 713 |
| Less: Income from continuing operations attributable to noncontrolling interest | 157 |
| | 116 |
| | 239 |
| Less: Income (loss) from continuing operations attributable to predecessor | (34 | ) | | (153 | ) | | 35 |
| Income from continuing operations, net of noncontrolling interest | 1,398 |
| | 1,272 |
| | 439 |
| General Partner’s interest in income from continuing operations | 1,064 |
| | 513 |
| | 505 |
| Class H Unitholder’s interest in income from continuing operations | 258 |
| | 217 |
| | — |
| Class I Unitholder’s interest in income from continuing operations | 94 |
| | — |
| | — |
| Common Unitholders’ interest in income (loss) from continuing operations | (18 | ) | | 542 |
| | (66 | ) | Additional earnings allocated to General Partner | (5 | ) | | (4 | ) | | (2 | ) | Distributions on employee unit awards, net of allocation to General Partner | (16 | ) | | (13 | ) | | (10 | ) | Income (loss) from continuing operations available to Common Unitholders | $ | (39 | ) | | $ | 525 |
| | $ | (78 | ) | Weighted average Common Units – basic | 432.8 |
| | 331.5 |
| | 343.4 |
| Basic income (loss) from continuing operations per Common Unit | $ | (0.09 | ) | | $ | 1.58 |
| | $ | (0.23 | ) | | | | | | | Income (loss) from continuing operations available to Common Unitholders | $ | (39 | ) | | $ | 525 |
| | $ | (78 | ) | Loss attributable to ETP Series A Preferred Units | (6 | ) | | — |
| | — |
| Diluted income (loss) from continuing operations available to Common Unitholders | $ | (45 | ) | | $ | 525 |
| | $ | (78 | ) | Weighted average Common Units – basic | 432.8 |
| | 331.5 |
| | 343.4 |
| Dilutive effect of unvested Unit Awards | — |
| | 1.3 |
| | — |
| Dilutive effect of Preferred Units | 0.7 |
| | — |
| | — |
| Weighted average Common Units – diluted | 433.5 |
| | 332.8 |
| | 343.4 |
| Diluted income (loss) from continuing operations per Common Unit | $ | (0.10 | ) | | $ | 1.58 |
| | $ | (0.23 | ) | Basic income from discontinued operations per Common Unit | $ | — |
| | $ | 0.19 |
| | $ | 0.05 |
| Diluted income from discontinued operations per Common Unit | $ | — |
| | $ | 0.19 |
| | $ | 0.05 |
|
Our debt obligations consist of the following:
| | | | | | | | | | December 31, | | 2015 | | 2014 | ETP Debt | | | | 5.95% Senior Notes due February 1, 2015 | $ | — |
| | $ | 750 |
| 6.125% Senior Notes due February 15, 2017 | 400 |
| | 400 |
| 2.5% Senior Notes due June 15, 2018 | 650 |
| | — |
| 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 |
| 5.75% Senior Notes due September 1, 2020 (assumed from Regency) | 400 |
| | — |
| 4.15% Senior Notes due October 1, 2020 | 1,050 |
| | 700 |
| 6.5% Senior Notes due May 15, 2021 (assumed from Regency) | 500 |
| | — |
| 4.65% Senior Notes due June 1, 2021 | 800 |
| | 800 |
| 5.20% Senior Notes due February 1, 2022 | 1,000 |
| | 1,000 |
| 5.875% Senior Notes due March 1, 2022 (assumed from Regency) | 900 |
| | — |
| 5.0% Senior Notes due October 1, 2022 (assumed from Regency) | 700 |
| | — |
| 3.60% Senior Notes due February 1, 2023 | 800 |
| | 800 |
| 5.5% Senior Notes due April 15, 2023 (assumed from Regency) | 700 |
| | — |
| 4.5% Senior Notes due November 1, 2023 (assumed from Regency) | 600 |
| | — |
| 4.9% Senior Notes due February 1, 2024 | 350 |
| | 350 |
| 7.6% Senior Notes due February 1, 2024 | 277 |
| | 277 |
| 4.05% Senior Notes due March 15, 2025 | 1,000 |
| | — |
| 4.75% Senior Notes due January 15, 2026 | 1,000 |
| | — |
| 8.25% Senior Notes due November 15, 2029 | 267 |
| | 267 |
| 4.90% Senior Notes due March 15, 2035 | 500 |
| | — |
| 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 |
| 5.15% Senior Notes due March 15, 2045 | 1,000 |
| | — |
| 6.125% Senior Notes due December 15, 2045 | 1,000 |
| | — |
| Floating Rate Junior Subordinated Notes due November 1, 2066 | 545 |
| | 546 |
| ETP $3.75 billion Revolving Credit Facility due November 2019 | 1,362 |
| | 570 |
| Unamortized premiums, discounts and fair value adjustments, net | (21 | ) | | (1 | ) | Deferred debt issuance costs | (147 | ) | | (55 | ) | | 20,633 |
| | 11,404 |
| Transwestern Debt | | | | 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 | ) | Deferred debt issuance costs | (2 | ) | | (3 | ) | | 779 |
| | 778 |
| Panhandle Debt | | | | 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 | 75 |
| | 99 |
|
| | | | | | | | | | 1,160 |
| | 1,184 |
| | | | | Sunoco, Inc. Debt | | | | 9.625% Senior Notes due April 15, 2015 | — |
| | 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 | 20 |
| | 35 |
| | 485 |
| | 750 |
| Sunoco Logistics Debt | | | | 6.125% Senior Notes due May 15, 2016 (1) | 175 |
| | 175 |
| 5.50% Senior Notes due February 15, 2020 | 250 |
| | 250 |
| 4.4% Senior Notes due April 1, 2021 | 600 |
| | — |
| 4.65% Senior Notes due February 15, 2022 | 300 |
| | 300 |
| 3.45% Senior Notes due January 15, 2023 | 350 |
| | 350 |
| 4.25% Senior Notes due April 1, 2024 | 500 |
| | 500 |
| 5.95% Senior Notes due December 1, 2025 | 400 |
| | — |
| 6.85% Senior Notes due February 15, 2040 | 250 |
| | 250 |
| 6.10% Senior Notes due February 15, 2042 | 300 |
| | 300 |
| 4.95% Senior Notes due January 15, 2043 | 350 |
| | 350 |
| 5.30% Senior Notes due April 1, 2044 | 700 |
| | 700 |
| 5.35% Senior Notes due May 15, 2045 | 800 |
| | 800 |
| Sunoco Logistics $35 million Revolving Credit Facility due April 30, 2015 (2) | — |
| | 35 |
| Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020 | 562 |
| | 150 |
| Unamortized premiums, discounts and fair value adjustments, net | 85 |
| | 100 |
| Deferred debt issuance costs | (32 | ) | | (26 | ) | | 5,590 |
| | 4,234 |
| | | | | Sunoco LP Debt (3) | — |
| | 683 |
| Regency Debt, net of deferred debt issuance costs of $58 million (4) | — |
| | 6,583 |
| | | | | Other | 32 |
| | 223 |
| | 28,679 |
| | 25,839 |
| Less: current maturities | 126 |
| | 1,008 |
| | $ | 28,553 |
| | $ | 24,831 |
|
| | (1)
| Sunoco Logistics’ 6.125% senior notes due May 15, 2016 were classified as long-term debt as of December 31, 2015 as Sunoco Logistics has the ability2018, 2017 and intent to refinance such borrowings on a long-term basis.2016, respectively. |
| | (2) | Sunoco Logistics’ subsidiary $35 million Revolving Credit Facility maturedSublease rental income is included in April 2015 and was repaid with borrowings fromother revenues in the Sunoco Logistics $2.50 billion Revolving Credit Facility.accompanying statements of operations. |
| | (3)
| In connection with ETE’s acquisition of Sunoco GP, the general partner of Sunoco LP, on July 1, 2015, ETP deconsolidated Sunoco LP. |
| | (4)
| As discussed below, the Regency senior notes were redeemed and/or assumed by the Partnership. On April 30, 2015, in connection with the Regency Merger, the Regency Revolving Credit Facility was paid off in full and terminated. |
The following table reflects future maturities of long-term debtFuture minimum lease commitments for each of the next five years and thereafter. These amounts exclude $23 million in unamortized net premiums, fair value adjustments and deferred debt issuance costs:such leases are:
| | | | | | 2016 | | $ | 301 |
| 2017 | | 1,182 |
| 2018 | | 1,650 |
| 2019 | | 2,362 |
| 2020 | | 2,937 |
| Thereafter | | 20,270 |
| Total | | $ | 28,702 |
|
| | | | | Years Ending December 31: | | 2019 | $ | 104 |
| 2020 | 95 |
| 2021 | 74 |
| 2022 | 58 |
| 2023 | 50 |
| Thereafter | 220 |
| Future minimum lease commitments | 601 |
| Less: Sublease rental income | (111 | ) | Net future minimum lease commitments | $ | 490 |
|
Long-term debt reflected on our consolidated balance sheets includes fair value adjustments related to interest rate swaps, which represent fair value adjustments that had been recorded in connection with fair value hedge accounting prior to the termination of the interest rate swap.
ETP as Co-Obligor of Sunoco, Inc. Debt
In connection with the Sunoco Merger and ETP Holdco Transaction, ETP became a co-obligor on approximately $965 million of aggregate principal amount of Sunoco, Inc.’s existing senior notes and debentures. The balance of these notes was $465 million as of December 31, 2015.
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 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.
In June 2015, ETP issued $650 million aggregate principal amount of 2.50% senior notes due June 2018, $350 million aggregate principal amount of 4.15% senior notes due October 2020, $1.0 billion aggregate principal amount of 4.75% senior notes due January 2026 and $1.0 billion aggregate principal amount of 6.125% senior notes due December 2045. ETP used the net proceeds of $2.98 billion from the offering to repay outstanding borrowings under the ETP Credit Facility, to fund growth capital expenditures and for general partnership purposes.
In March 2015, ETP issued $1.0 billion aggregate principal amount of 4.05% senior notes due March 2025, $500 million aggregate principal amount of 4.90% senior notes due March 2035, and $1.0 billion aggregate principal amount of 5.15% senior notes due March 2045. ETP used the $2.48 billion net proceeds from the offering to repay outstanding borrowings under the ETP Credit Facility, to fund growth capital expenditures and for general partnership purposes.
At the time of the Regency Merger, Regency had outstanding $5.1 billion principal amount of senior notes. On June 1, 2015, Regency redeemed all of the outstanding $499 million aggregate principal amount of its 8.375% senior notes due June 2019.
Panhandle previously agreed to fully and unconditionally guarantee (the “Panhandle Guarantee”) all of the payment obligations of Regency and Regency Energy Finance Corp. under their $600 million in aggregate principal amount of 4.50% senior notes due November 2023. On May 28, 2015, ETP entered into a supplemental indenture relating to the senior notes pursuant to which it became a co-obligor with respect to such payment obligations thereunder. Accordingly, pursuant to the terms of such supplemental indentures the Panhandle Guarantee was terminated.
On August 10, 2015, ETP entered into various supplemental indentures pursuant to which ETP has agreed to assume all of the obligations of Regency under the following series of outstanding senior notes of Regency and Regency Energy Finance Corp., of which ETP was previously a co-obligor or parent guarantor:
$400 million in aggregate principal amount of 5.750% Senior Notes due 2020;
$390 million in aggregate principal amount of 8.375% Senior Notes due 2020 (the “2020 Notes”);
$260 million in aggregate principal amount of 6.500% Senior Notes due 2021 (the “2021 Notes”);
$500 million in aggregate principal amount of 6.500% Senior Notes due 2021;
$700 million in aggregate principal amount of 5.000% Senior Notes due 2022;
$900 million in aggregate principal amount of 5.875% Senior Notes due 2022;
$600 million in aggregate principal amount of 4.500% Senior Notes due 2023; and
$700 million in aggregate principal amount of 5.500% Senior Notes due 2023.
The notes assumed from Regency are registered under the Securities Act of 1933 (as amended). The senior notes assumed from Regency may be redeemed at any time, or from time to time, pursuant to the terms of the applicable indenture and related indenture supplements related to the Regency senior notes. The balance is payable upon maturity and interest is payable semi-annually. The indentures on these notes contain various covenants that are similar to those of the indentures on ETP’s senior notes.
The senior notes assumed from Regency are fully and unconditionally guaranteed, on a joint and several basis, by all of the consolidated subsidiaries that were previously consolidated by Regency, except for ELG and its wholly-owned subsidiaries, Aqua – PVR and ORS.
On August 13, 2015, ETP redeemed in full the outstanding amount of the 2020 Notes and the 2021 Notes. The amount paid to redeem the 2020 Notes included a make whole premium of $40 million and the amount paid to redeem the 2021 Notes included a make whole premium of $24 million.
Transwestern Senior Notes
The Transwestern senior notes are redeemable at any time in whole or pro rata, subject to a premium or upon a change of control event or an event of default, as defined. The balance is payable upon maturity. Interest is paid semi-annually.
Panhandle Junior Subordinated Notes
The interest rate on the remaining portion of Panhandle’s junior subordinated notes due 2066 is a variable rate based upon the three-month LIBOR rate plus 3.0175%. The balance of the variable rate portion of the junior subordinated notes was $54 million at an effective interest rate of 3.65% at December 31, 2015.
Sunoco Logistics Senior Notes Offerings
In November 2015, Sunoco Logistics issued $600 million aggregate principal amount of 4.40% senior notes due April 2021 and $400 million aggregate principal amount of 5.95% senior notes due December 2025.
Credit Facilities
ETP Credit Facility
The ETP Credit Facility allows for borrowings of up to $3.75 billion and expires in November 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.
As of December 31, 2015, the ETP Credit Facility had $1.36 billion outstanding, and the amount available for future borrowings was $2.24 billion after taking into account letters of credit of $145 million. The weighted average interest rate on the total amount outstanding as of December 31, 2015 was 1.86%.
Sunoco Logistics Credit Facilities
Sunoco Logistics maintains a $2.50 billion unsecured credit facility (the “Sunoco Logistics Credit Facility”) which matures in March 2020. The Sunoco Logistics Credit Facility contains an accordion feature, under which the total aggregate commitment may be extended to $3.25 billion under certain conditions.
The Sunoco Logistics Credit Facility is available to fund Sunoco Logistics’ working capital requirements, to finance acquisitions and capital projects, to pay distributions and for general partnership purposes. The Sunoco Logistics Credit
Facility bears interest at LIBOR or the Base Rate, each plus an applicable margin. The credit facility may be prepaid at any time. As of December 31, 2015, the Sunoco Logistics Credit Facility had $562 million of outstanding borrowings.
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 credit agreement relating to the ETP Credit Facility contains covenants that limit (subject to 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’ $2.50 billion credit facility contains various covenants, including limitations on the creation of indebtedness and liens, and other covenants related to the operation and conduct of the business of Sunoco Logistics and its subsidiaries. The credit facility also limits Sunoco Logistics, on a rolling four-quarter basis, 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 3.6 to 1 at December 31, 2015, as calculated in accordance with the credit agreements.
Compliance with our Covenants
We were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2015.
| | 7. | SERIES A PREFERRED UNITS: |
In connection with the closing of the Regency Merger, Regency’s 1.9 million outstanding series A cumulative convertible preferred units were converted into corresponding newly issued ETP cumulative convertible series A preferred units on a one-for-one basis. If outstanding, the Preferred Units are mandatorily redeemable on September 2, 2029 for $35 million plus all accrued but unpaid distributions and interest thereon and are reflected as long-term liabilities in our consolidated balance sheets. The Preferred Units are entitled to a preferential quarterly cash distribution of $0.445 per Preferred Unit if outstanding on the record dates of the Partnership’s common unit distributions. Holders of the Preferred Units can elect to convert the ETP Preferred Units to ETP Common Units at any time in accordance with ETP’s partnership agreement. The number of common units issuable upon conversion of the Preferred Units is equal to the issue price of $18.30, plus all accrued but unpaid distributions and interest thereon, divided by the conversion price of $44.37. As of December 31, 2015, the Preferred Units were convertible into 0.9 million ETP Common Units.
Limited Partner interests are represented by Common, Class E Units, Class G Units, Class H and Class I Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement. 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 ET Common Units during the years ended December 31, 2018, 2017 and 2016 was as follows: | | | | | | | | | | | Years Ended December 31, | | 2015 | | 2014 | | 2013 | Number of Common Units, beginning of period | 355.5 |
| | 333.8 |
| | 301.5 |
| Common Units redeemed in connection with certain transactions | (51.8 | ) | | (18.7 | ) | | — |
| Common Units issued in connection with public offerings | — |
| | — |
| | 13.8 |
| Common Units issued in connection with certain acquisitions | 172.2 |
| | 15.8 |
| | 49.5 |
| Common Units redeemed for Class H Units | — |
| | — |
| | (50.2 | ) | Common Units issued in connection with the Distribution Reinvestment Plan | 7.7 |
| | 2.8 |
| | 2.3 |
| Common Units issued in connection with Equity Distribution Agreements | 21.1 |
| | 21.4 |
| | 16.9 |
| Repurchases of Common Units in open-market transactions | — |
| | — |
| | (0.4 | ) | Issuance of Common Units under equity incentive plans | 0.9 |
| | 0.4 |
| | 0.4 |
| Number of Common Units, end of period | 505.6 |
| | 355.5 |
| | 333.8 |
|
| | | | | | | | | | | Years Ended December 31, | | 2018 | | 2017 | | 2016 | Number of Common Units, beginning of period | 1,079.1 |
| | 1,046.9 |
| | 1,044.8 |
| Conversion of ET Series A Convertible Preferred Units to common units | 79.1 |
| | — |
| | — |
| Common Unit increase from Energy Transfer Merger | 1,458.9 |
| | — |
| | — |
| Issuance of common units | 2.3 |
| | 32.2 |
| | 2.1 |
| Number of Common Units, end of period | 2,619.4 |
| | 1,079.1 |
| | 1,046.9 |
|
OurIn October 2018, ET issued 1.46 billion ET Common Units are registeredin connection with the Energy Transfer Merger.
ET 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 Securities Exchange Act of 1934 (as amended) and are listeddistribution agreements 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
In April 2013, the Partnership completed a public offerings of 13.8 million Common Units, all of which have been registered under the Securities Act of 1933 (as amended), for net proceeds of $657 million. Proceeds were used to repay amounts outstanding under the ETP Credit Facility and for general partnership purposes.
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.
During the year ended December 31, 2018.
ET Series A Convertible Preferred Units In May 2018, the Partnership converted its 329.3 million Series A Convertible Preferred Units into approximately 79.1 million ET common units in accordance with the terms of ET’s partnership agreement. ET Class A Units In connection with the Energy Transfer Merger, the Partnership issued 647,745,099 Class A units (“ET Class A Units”) representing limited partner interests in the Partnership to LE GP, LLC (“LE GP”), the general partner of ET. The number of ET Class A Units issued allows LE GP and its affiliates to retain a voting interest in the Partnership that is identical to their voting interest in the Partnership prior to the completion of the Merger. The ET Class A Units are entitled to vote together with the Partnership’s common units, as a single class, except as required by law. Additionally, ET’s partnership agreement provides that, under certain circumstances, upon the issuance by the Partnership of additional common units or any securities that have voting rights that are pari passu with the Partnership common units, the Partnership will issue to any holder of ET Class A Units additional ET Class A Units such that the holder maintains a voting interest in the Partnership that is identical to its voting interest in the Partnership prior to such issuance. The ET Class A Units are not entitled to distributions and otherwise have no economic attributes. Repurchase Program In February 2015, we issued 21.1the Partnership announced a common unit repurchase program, whereby the Partnership may repurchase up to an additional $2 billion of ET 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 no ET Common Units under this program in 2018, 2017 or 2016 and there was $936 million units for $1.07 billion, net of commissions of $11 million. Asavailable to use under the program as of December 31, 2015, $328 million2018. Class D Units In 2013, the Partnership issued 3,080,000 Class D Units of ourET pursuant to an agreement with a former executive. The Class D Units were convertible to ET Common Units, remained availablesubject to be issued under our currently effective equity distribution agreement.certain vesting requirements which were not met prior to the former executive’s termination in 2016. Equity Incentive Plan Activity
We issueSale of Common Units to employeesby Subsidiaries
The Parent Company accounts for the difference between the carrying amount of its investment in subsidiaries and directors upon vestingthe underlying book value arising from issuance 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 withheldunits 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.
During the years ended December 31, 2015, 2014 and 2013, aggregate distributions of $360 million, $155 million, and $109 million, respectively, were reinvested under the DRIP resulting in the issuance in aggregate of 12.8 million Common Units.
In December, 2015, we provided noticesubsidiaries (excluding unit issuances to the DRIP participants that we have changedParent Company) as a capital transaction. If a subsidiary issues units at a price less than the discount atParent Company’s carrying value per unit, the Parent Company assesses whether the investment has been impaired, in which participants may purchase ETPcase 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 throughduring the DRIP from 5% to 1%, effective for the distributions payable in respect of the fourth quarter of 2015 and future quarters.periods presented.
As of December 31, 2015, a total of 11.5 million Common Units remain available to be issued under the existing registration statement.
ETO Class E Units There were previously 8.9 million Class E Units outstanding, all of which were owned by HHI. The Class E Units arewere entitled to aggregate cash distributions equal to 11.1% of the total amount of cash distributed to all Unitholders, including the Class E Unitholders, up to $1.41 per unit per year, with any excess thereof available for distribution to Unitholders other than 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 subsidiary of ETP Holdco, Heritage Holdings, Inc. Although no plans are currently in place, management may evaluate whether to retire some or all ofyear. As the Class E Units atwere owned by a future date. All ofwholly-owned subsidiary, the 8.9cash distributions on those units were eliminated in our consolidated financial statements. On December 31, 2018, the Class E units were converted to Class L units, as described below. ETO Class G Units There were previously 90.7 million Class EG Units outstanding, areall of which were held by a wholly-owned subsidiary and are reported as treasury units. 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.Partnership. The Class F Units generally did not have any voting rights. The Class FG Units were entitled to aggregate cash distributions equal to 35% of the total amount of cash generated by us and our subsidiaries, other than ETP Holdco, and available for distribution, up to a maximum of $3.75 per Class FG Unit per year. In April 2013, all of the outstanding Class F Units were exchanged for Class G Units on a one-for-one basis. The Class G Units have terms that are substantially the same as the Class F Units, with the principal difference between the Class G Units and the Class F Units being that allocationsAllocations of depreciation and amortization to the Class G Units for tax purposes arewere based on a predetermined percentage and are not contingent on whether ETPETO has net income or loss. These units are held by a subsidiary and therefore arewere reflected as treasury units in the consolidated financial statements. On December 31, 2018, the Class G units were converted to Class L units, as described below.
ETO Class H Units The ETO 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 ETPETO corresponding to 50.05%90.05% of the profits, losses, and other items allocated to ETPETO 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 ETPETO for each quarter equal to 50.05%90.05% of the cash distributed to ETPETO by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners for such quarter and, to the extent not previously distributed to holders of the Class H Units, for any previous quarters.
Bakken Pipeline Transaction
In March 2015, ETE transferred 30.8 million Partnership common units, ETE’s 45% interest in the Bakken Pipeline project, and $879 million in cash to the Partnership in exchange for 30.8 million newly issued The Class H Units of ETP that, when combinedunits were cancelled in connection with the 50.2 million previously issued Class H Units, generally entitle ETE to receive 90.05%merger of the cash distributionsETO 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 100in April 2017.
ETO Class I Units that provide distributions to ETE to offset IDR subsidies previously provided to ETP. These IDR subsidies, including the impact from distributions on Class I Units, were reduced by $55 million in 2015 and $30 million in 2016. In connection with the transaction, ETPBakken Pipeline Transaction discussed in Note 3, in March 2015, ETO issued 100 ETO Class I Units. The ETO 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 ETO 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 ETO Class I Units and (ii) after making cash distributions to ETO 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 ourETO’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 impactClass I Units were cancelled in connection with the Energy Transfer Merger in October 2018. Bakken Equity Sale In February 2017, Bakken Holdings Company LLC, an entity in which ETO 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 (i)Dakota Access and ETCO. The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETO continues to consolidate Dakota Access and ETCO subsequent to this transaction. ETO Class K Units On December 29, 2016, ETO issued to certain of its indirect subsidiaries, in exchange for cash contributions and the IDR subsidy adjustments and (ii)exchange of outstanding common units representing limited partner interests in ETO, Class K Units, each of which is entitled to a quarterly cash distribution of $0.67275 per Class K Unit prior to ETO making distributions of available cash to any class of units, excluding any cash available distributions or dividends or capital stock sales proceeds received by ETO from ETO Holdco. If ETO is unable to pay the Class IK Unit quarterly distribution with respect to any quarter, the accrued and unpaid distributions along withwill accumulate until paid and any accumulated balance will accrue 1.5% per annum until paid. As of December 31, 2018, a total of 101.5 million Class K Units were held by wholly-owned subsidiaries of ETO.
ETO Class L Units On December 31, 2018, ETO issued a new class of limited partner interests titled Class L Units to two wholly-owned subsidiaries of the currently effective IDR subsidies, is includedPartnership when the Partnership’s outstanding Class E units and Class G units held by such subsidiaries were converted into Class L Units. As a result of the conversion, the Class E units and Class G units were cancelled. The Class L Units generally do not have any voting rights. The Class L Units are entitled to aggregate cash distributions equal to 7.65% per annum of the total amount of cash generated by us and our subsidiaries, other than ETP Holdco, and available for distribution. Distributions shall be paid quarterly, in arrears, within 45 days after the table below under “Quarterly Distributionsend of Available Cash.”each quarter. As the Class L Units are owned by a wholly-owned subsidiary, the cash distributions on those units are eliminated in our consolidated financial statements. Sales of Common Units by Sunoco Logistics With respectPrior to our investment inthe Sunoco Logistics Merger, we accountaccounted for the difference between the carrying amount of our investment in Sunoco Logistics and the underlying book value arising from the issuance or redemption of units by the respective subsidiary (excluding transactions with us) as capital transactions.
AsIn September and October 2016, a resulttotal of Sunoco Logistics’ issuances of24.2 million common units duringwere 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 year ended December 31, 2015, we recognized increases in partners’ capital of $300 million.acquisition from Vitol.
ETO Preferred Units In 2014, November 2017, ETO 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. In April 2018, ETO issued 18 million of its 7.375% Series C Preferred Units at a price of $25 per unit. In July 2018, ETO issued 17.8 million of its 7.625% Series D Preferred Units at a price of $25 per unit. Subsequent to the Energy Transfer Merger, all of ETO’s Series A, Series B, Series C and Series D Preferred Units remain outstanding. ETO Series A Preferred Units 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 ETO’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. ETO Series B Preferred Units 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 ETO’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. ETO Series C Preferred Units Distributions on the Series C Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, May 15, 2023, at a rate of 7.375% per annum of the stated liquidation preference of $25. On and after May 15, 2023, distributions on the Series C Preferred Units will accumulate at a percentage of the $25 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.530% per annum. The Series C Preferred Units are redeemable at ETO’s option on or after May 15, 2023 at a redemption price of $25 per Series C Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
ETO Series D Preferred Units Distributions on the Series D Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, August 15, 2023, at a rate of 7.625% per annum of the stated liquidation preference of $25. On and after August 15, 2023, distributions on the Series D Preferred Units will accumulate at a percentage of the $25 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.738% per annum. The Series D Preferred Units are redeemable at ETO’s option on or after August 15, 2023 at a redemption price of $25 per Series D 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, ETO purchased all of the outstanding PennTex common units not previously owned by ETO for $20.00 per common unit in cash. ETO now owns all of the economic interests of PennTex, and PennTex common units are no longer publicly traded or listed on the NASDAQ. Subsidiary Equity Transactions Sunoco LogisticsLP’s Common Unit Repurchase 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 ETO for aggregate cash consideration of approximately $540 million. ETO used the proceeds from the sale of the Sunoco LP common units to repay amounts outstanding under its revolving credit facility. Sunoco LP’s Equity Distribution Program In October 2016, Sunoco LP entered into an equity distribution agreementsagreement pursuant to which Sunoco LogisticsLP may sell from time to time common units having aggregate offering prices of up to $1.25 billion. In$400 million. For the fourth quarter of 2015, the aggregate capacity was increased to $2.25 billion. During the year ended December 31, 2015,2018, Sunoco Logistics receivedLP issued no additional units under its ATM program. For the years ended December 31, 2017 and 2016, Sunoco LP issued an additional 1.3 million and 2.8 million units with total net proceeds of $890$33 million and $71 million, net of commissions of $10$0.3 million fromand $1 million, respectively. As of December 31, 2018, $295 million of Sunoco LP common units remained available to be issued under the currently effective equity distribution agreement. Sunoco LP’s Unit Issuances 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 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. Sunoco LP’s Series A Preferred Units On March 30, 2017, ET 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 is 10.00%, 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 ET 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.
USAC’s Distribution Reinvestment Program During the nine months ended December 31, 2018, distributions of $1 million were reinvested under the USAC distribution reinvestment program resulting in the issuance of 26.8 millionapproximately 39,280 USAC common units. USAC’s Warrant Private Placement On April 2, 2018, USAC issued two tranches of warrants to purchase USAC common units pursuant(the “USAC Warrants”), which included USAC Warrants to purchase 5,000,000 common units with a strike price of $17.03 per unit and USAC Warrants to purchase 10,000,000 common units with a strike price of $19.59 per unit. The USAC Warrants may be exercised by the holders thereof at any time beginning on the one year anniversary of the closing date and before the tenth anniversary of the closing date. Upon exercise of the USAC Warrants, USAC may, at its option, elect to settle the USAC Warrants in common units on a net basis. USAC’s Class B Units The USAC Class B Units, all of which are owned by ETO, are a new class of partnership interests of USAC that have substantially all of the rights and obligations of a USAC common unit, except the USAC Class B Units will not participate in distributions for the first four quarters following the closing date of the USAC Transaction on April 2, 2018. Each USAC Class B Unit will automatically convert into one USAC common unit on the first business day following the record date attributable to the equity distribution agreement, which were used for general partnership purposes.quarter ending June 30, 2019. In March 2015, Sunoco Logistics completed a public offering of 13.5 million common units for net proceeds of $547 million. The proceeds were used to repay outstanding borrowings under the $2.5 billion Sunoco Logistics Credit Facility and for general partnership purposes. In April 2015, an additional 2.0 million common units were issued for net proceeds of $82 million related to the exercise of an option in connection with the March 2015 offering.
In September 2014, Sunoco Logistics completed an overnight public offering of 7.7 million common units for net proceeds of $362 million were used to repay outstanding borrowings under the Sunoco Logistics Credit Facility and for general partnership purposes.
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 Cash to our Unitholdersavailable cash quarterly. The Parent Company’s only cash-generating assets currently consist of distributions from its interest in ETO.
Our distributions declared and our General Partner within forty-five 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,paid with respect to any of our fiscal quarters, 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 Partner in its sole discretion to providecommon units for the proper conduct of our business, to comply with applicable laws or any debt instrument or other agreement, or to provide funds for futureperiods presented were as follows: | | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | 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 |
| March 31, 2018 | | May 7, 2018 | | May 21, 2018 | | 0.3050 |
| June 30, 2018 | | August 6, 2018 | | August 20, 2018 | | 0.3050 |
| September 30, 2018 | | November 8, 2018 | | November 19, 2018 | | 0.3050 |
| December 31, 2018 | | February 8, 2019 | | February 19, 2019 | | 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 to partnersdeclared and paid with respect to any one or more ofour Convertible Unit during the next four quarters. Available Cash is more fully defined in our Partnership Agreement.years ended December 31, 2016 and 2017 were as follows: Our distributions of Available Cash from operating surplus, excluding 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 are determined based | | | | | | | | | | 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 |
| March 31, 2018 | | May 7, 2018 | | May 21, 2018 | | 0.1100 |
|
ETO Preferred Unit Distributions Distributions on the amountPartnership’s Series A, Series B, Series C and Series D preferred units declared and/or paid by which quarterly distribution to common Unitholders exceed certain specified target levels, as set forth in ourthe Partnership Agreement.
Distributions declared during the periods presented were as follows:
| | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | 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 |
| March 31, 2015 | | May 8, 2015 | | May 15, 2015 | | 1.0150 |
| June 30, 2015 | | August 6, 2015 | | August 14, 2015 | | 1.0350 |
| September 30, 2015 | | November 5, 2015 | | November 16, 2015 | | 1.0550 |
| December 31, 2015 | | February 8, 2016 | | February 16, 2016 | | 1.0550 |
|
| | | | | | | | | | | | | | | | | | | | | | | Period Ended | | Record Date | | Payment Date | | Series A (1) | | Series B (1) | | Series C | | Series D | | December 31, 2017 | | February 1, 2018 | | February 15, 2018 | | $ | 15.4510 |
| * | $ | 16.3780 |
| * | $ | — |
| | $ | — |
| | June 30, 2018 | | August 1, 2018 | | August 15, 2018 | | 31.2500 |
| | 33.1250 |
| | 0.5634 |
| * | — |
| | September 30, 2018 | | November 1, 2018 | | November 15, 2018 | | — |
| | — |
| | 0.4609 |
| | 0.5931 |
| * | December 31, 2018 | | February 1, 2019 | | February 15, 2019 | | 31.2500 |
| | 33.1250 |
| | 0.4609 |
| | 0.4766 |
| |
ETE agreed* Represent prorated initial distributions.
(1) Series A and Series B preferred unit distributions are paid on a bi-annual basis. Sunoco LP Cash Distributions 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 relinquish its rightClass 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 followingcorresponding 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 of incentive distributions in future periods, including distributions on Class I Units:that are less than the minimum quarterly distribution. | | | | | | | | Total Year | 2016 | | $ | 137 |
| 2017 | | 128 |
| 2018 | | 105 |
| 2019 | | 95 |
|
| | | | | | | | | | | | 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 on Sunoco Logistics Quarterly Distributions of Available Cash DistributionsLP’s units declared during the periods presentedand/or paid by Sunoco LP 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 |
| March 31, 2015 | | May 11, 2015 | | May 15, 2015 | | 0.4190 |
| June 30, 2015 | | August 10, 2015 | | August 14, 2015 | | 0.4380 |
| September 30, 2015 | | November 9, 2015 | | November 13, 2015 | | 0.4580 |
| December 31, 2015 | | February 8, 2016 | | February 12, 2016 | | 0.4790 |
|
| | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | 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 6, 2018 | | February 14, 2018 | | 0.8255 |
| March 31, 2018 | | May 7, 2018 | | May 15, 2018 | | 0.8255 |
| June 30, 2018 | | August 7, 2018 | | August 15, 2018 | | 0.8255 |
| September 30, 2018 | | November 6, 2018 | | November 14, 2018 | | 0.8255 |
| December 31, 2018 | | February 6, 2019 | | February 14, 2019 | | 0.8255 |
|
USAC Cash Distributions Subsequent to the Energy Transfer Merger and USAC Transactions described in Note 1 and Note 3, respectively, ETO owns approximately 39.7 million USAC common units and 6.4 million USAC Class B units. As of December 31, 2018, USAC had approximately 96.4 million common units outstanding. USAC currently has a non-economic general partner interest and no outstanding incentive distribution rights. Distributions on USAC’s units declared and/or paid by USAC subsequent to the USAC transaction on April 2, 2018 were as follows:
Table of Contents | | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | March 31, 2018 | | May 1, 2018 | | May 11, 2018 | | $ | 0.5250 |
| June 30, 2018 | | July 30, 2018 | | August 10, 2018 | | 0.5250 |
| September 30, 2018 | | October 29, 2018 | | November 09, 2018 | | 0.5250 |
| December 31, 2018 | | January 28, 2019 | | February 8, 2019 | | 0.5250 |
|
Accumulated Other Comprehensive Income (Loss) The following table presents the components of AOCI, net of tax: | | | December 31, | December 31, | | 2015 | | 2014 | 2018 | | 2017 | Available-for-sale securities(1) | $ | — |
| | $ | 3 |
| $ | 2 |
| | $ | 8 |
| Foreign currency translation adjustment | (4 | ) | | (3 | ) | (5 | ) | | (5 | ) | Net loss on commodity related hedges | — |
| | (1 | ) | | Actuarial gain (loss) related to pensions and other postretirement benefits | 8 |
| | (57 | ) | (48 | ) | | (5 | ) | Investments in unconsolidated affiliates, net | — |
| | 2 |
| 9 |
| | 5 |
| Total AOCI, net of tax | $ | 4 |
| | $ | (56 | ) | (42 | ) | | 3 |
| Amounts attributable to noncontrolling interest | | — |
| | (3 | ) | Total AOCI included in partners’ capital, net of tax | | $ | (42 | ) | | $ | — |
|
| | (1) | Effective January 1, 2018, the Partnership adopted Accounting Standards Update No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, which resulted in the reclassification of $2 million from accumulated other comprehensive income related to available-for-sale equity securities to common unitholders. |
The table below sets forth the tax amounts included in the respective components of other comprehensive income (loss): | | | December 31, | December 31, | | 2015 | | 2014 | 2018 | | 2017 | Available-for-sale securities | $ | (2 | ) | | $ | (1 | ) | $ | (1 | ) | | $ | (2 | ) | Foreign currency translation adjustment | 4 |
| | 2 |
| 2 |
| | 3 |
| Actuarial loss (gain) relating to pension and other postretirement benefits | 7 |
| | (37 | ) | | Actuarial loss relating to pension and other postretirement benefits | | 12 |
| | 3 |
| Total | $ | 9 |
| | $ | (36 | ) | $ | 13 |
| | $ | 4 |
|
| | 9. | UNIT-BASEDNON-CASH COMPENSATION PLANS: |
ETP Unit-BasedET Non-Cash Compensation Plan
We, Sunoco LP and USAC, 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 Unitcommon unit appreciation rights, cash restricted units and other unit-basednon-cash compensation awards. As of December 31, 2015,2018, an aggregate total of 5.315.1 million ETPET Common Units remain available to be awarded under our equity incentive plans. Restricted UnitsET Long-Term Incentive Plan
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, ETPET Common Units are issued. These unit awards entitle the recipients of the unit awards to receive, with respect to each Common Unit subject to such award that has not either vested or been forfeited, a cash payment equal to each cash distribution per Common Unit made by us on our Common Units promptly following each such distribution by us to our Unitholders. We refer to these rights as “distribution equivalent rights.” Under our equity incentive plans, our non-employee directors each receive grants with a five-year service vesting requirement. The following table shows the activity of the awards granted to employees and non-employee directors: | | | Number of Units | | Weighted Average Grant-Date Fair Value Per Unit | Number of Units | | Weighted Average Grant-Date Fair Value Per Unit | Unvested awards as of December 31, 2014 | 3.5 |
| | $ | 53.83 |
| | Unvested awards as of December 31, 2017 (1) | | 19.5 |
| | $ | 18.03 |
| Awards granted | 2.1 |
| | 35.21 |
| 7.8 |
| | 13.00 |
| Awards vested | (1.2 | ) | | 48.67 |
| (3.5 | ) | | 21.35 |
| Awards forfeited | (0.4 | ) | | 55.44 |
| (1.4 | ) | | 15.16 |
| Conversion of RGP unit awards to ETP unit awards | 0.8 |
| | 58.88 |
| | Unvested awards as of December 31, 2015 | 4.8 |
| | 47.61 |
| | Unvested awards as of December 31, 2018 | | 22.4 |
| | 15.94 |
|
| | (1) | In connection with the Energy Transfer Merger, ET assumed the former ETO plans, including the related unvested awards. Outstanding awards under the former ETO plans are reflected for the entire period above. Amounts related to the period prior to the Energy Transfer Merger are adjusted for the 1.28 to 1 conversion ratio that was applied in the merger. |
During the years ended December 31, 2015, 2014,2018, 2017, and 2013,2016, the weighted average grant-date fair value per unit award granted was $35.21, $60.85$13.00, $17.01 and $50.54,$16.37, respectively. The total fair value of awards vested was $49 million, $26$40 million, and $29$40 million, respectively, based on the market price of ETPthe respective Common Units as of the vesting date. As of December 31, 2015,2018, a total of 4.822 million unit awards remain unvested, for which ETPET expects to recognize a total of $147$228 million in compensation expense over a weighted average period of 2.12.7 years. Cash Restricted Units. The Partnership has alsoWe previously granted cash restricted units, which vest 100% at the end of the third year of service. A cash restricted unit entitlesentitled the award recipient to receive cash equal to the market value of one ETPET Common Unit upon vesting. The Partnership does not currently have any cash restricted units outstanding. Subsidiary Non-Cash Compensation Plans Each of Sunoco LP and USAC 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 three or five-year period, that entitles 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: | | | | | | | | | | | | | | | | Sunoco LP | | USAC | | 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, 2017 | 1.7 |
| | $ | 31.89 |
| | 1.0 |
| | $ | 14.24 |
| Awards granted | 1.1 |
| | 27.67 |
| | 1.1 |
| | 15.47 |
| Awards vested | (0.4 | ) | | 32.92 |
| | (0.6 | ) | | 14.79 |
| Awards forfeited | (0.3 | ) | | 31.26 |
| | (0.1 | ) | | 17.85 |
| Unvested awards as of December 31, 2018 | 2.1 |
| | 29.15 |
| | 1.4 |
| | 14.98 |
|
The following table summarizes the weighted average grant-date fair value per unit award granted: | | | | | | | | | | | | | | Years Ended December 31, | | 2018 | | 2017 | | 2016 | Sunoco LP | $ | 27.67 |
| | $ | 28.31 |
| | $ | 26.95 |
| USAC | 15.47 |
| | N/A |
| | N/A |
|
The total fair value of Subsidiary Unit Awards vested for the years ended December 31, 2018, 2017 and 2016 was $22 million, $9 million, and $0.1 million, respectively, based on the market price of Sunoco LP and USAC common units as of the vesting date for the years ended December 31, 2018 and Sunoco LP for the years ended December 31, 2017 and 2016. As of December 31, 2015, a total of 0.6 million unvested cash restricted units were outstanding. Based on the trading price of ETP Common Units at December 31, 2015, the Partnership expects to recognize $7 million of unit-based2018, estimated compensation expensecost related to non-vested cash restricted units over a period of 1.3 years.
Sunoco Logistics Unit-Based Compensation Plan
Sunoco Logistics’ general partner has a long-term incentive plan for employeesSubsidiary Unit Awards not yet recognized was $45 million, and directors, which permits the grant of restricted units and unit options of Sunoco Logistics. As of December 31, 2015, a total of 2.5 million Sunoco Logistics restricted units were outstanding for which Sunoco Logistics expects to recognize $52 million of expense over a weighted average period of 3over which this cost is expected to be recognized in expense is 3.3 years.
As a partnership, we are not subject to U.S.United States federal income tax and most state income taxes. However, the Partnership conducts certain activities through corporate subsidiaries which are subject to federal and state income taxes. The components of the federal and state income tax expense (benefit) areof our taxable subsidiaries were summarized as follows: | | | Years Ended December 31, | Years Ended December 31, | | 2015 | | 2014 | | 2013 | 2018 | | 2017 | | 2016 | Current expense (benefit): | | | | | | | | | | | Federal | $ | (274 | ) | | $ | 321 |
| | $ | 51 |
| $ | (8 | ) | | $ | 54 |
| | $ | (47 | ) | State | (51 | ) | | 86 |
| | (2 | ) | 19 |
| | (16 | ) | | (34 | ) | Total | (325 | ) | | 407 |
| | 49 |
| 11 |
| | 38 |
| | (81 | ) | Deferred expense (benefit): | | | | | | | | | | | Federal | 231 |
| | (50 | ) | | (6 | ) | 181 |
| | (2,055 | ) | | (189 | ) | State | (29 | ) | | 1 |
| | 54 |
| (188 | ) | | 184 |
| | 12 |
| Total | 202 |
| | (49 | ) | | 48 |
| (7 | ) | | (1,871 | ) | | (177 | ) | Total income tax expense (benefit) from continuing operations | $ | (123 | ) | | $ | 358 |
| | $ | 97 |
| $ | 4 |
| | $ | (1,833 | ) | | $ | (258 | ) |
Historically, our effective tax rate has differed from the statutory rate primarily due to Partnershippartnership earnings that are not subject to U.S.United States federal and most state income taxes at the partnership level. The completion of the Southern Union Merger, Sunoco Merger, ETP Holdco Transaction and Susser Merger (see Note 3) significantly increased the activities conducted through corporate subsidiaries. A reconciliation of income tax expense (benefit) at the U.S.United States statutory rate to the income tax expense (benefit)benefit attributable to continuing operations for the years ended December 31, 2015, 20142018, 2017 and 20132016 is as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2015 | | December 31, 2014 | | December 31, 2013 | | Corporate Subsidiaries(1) | | Consolidated (2) | | Corporate Subsidiaries(1) | | Consolidated (2) | | Corporate Subsidiaries(1) | | Consolidated (2) | Income tax expense (benefit) at U.S. statutory rate of 35 percent | $ | (25 | ) | | $ | (25 | ) | | $ | 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) | (56 | ) | | (37 | ) | | 9 |
| | 54 |
| | 31 |
| | 36 |
| Dividend Received Deduction | (24 | ) | | (24 | ) | | — |
| | — |
| | — |
| | — |
| Premium on debt retirement | — |
| | — |
| | (10 | ) | | (10 | ) | | — |
| | — |
| Audit Settlement | (7 | ) | | (7 | ) | | — |
| | — |
| | — |
| | — |
| Foreign | — |
| | — |
| | (8 | ) | | (8 | ) | | — |
| | — |
| Other | (30 | ) | | (30 | ) | | — |
| | — |
| | (13 | ) | | (14 | ) | Income tax expense (benefit) from continuing operations | $ | (142 | ) |
| $ | (123 | ) | | $ | 313 |
| | $ | 358 |
| | $ | 93 |
| | $ | 97 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2018 | | 2017 | | 2016 | Income tax expense at United States statutory rate | $ | 763 |
| | $ | 248 |
| | $ | 71 |
| Increase (reduction) in income taxes resulting from: | | | | | | Partnership earnings not subject to tax | (635 | ) | | (477 | ) | | (576 | ) | Goodwill impairment | — |
| | 207 |
| | 278 |
| State tax, net of federal tax benefit | (125 | ) | | 124 |
| | (10 | ) | Dividend received deduction | (5 | ) | | (14 | ) | | (15 | ) | Federal rate change | — |
| | (1,812 | ) | | — |
| Change in tax status of subsidiary | — |
| | (124 | ) | | — |
| Other | 6 |
| | 15 |
| | (6 | ) | Income tax expense (benefit) from continuing operations | $ | 4 |
| | $ | (1,833 | ) | | $ | (258 | ) |
| | (1)
| Includes ETP Holdco, Susser Holdings Corporation, Oasis Pipeline Company, Susser Petroleum Property Company LLC, Aloha Petroleum Ltd., Inland Corporation, Mid-Valley Pipeline Company and West Texas Gulf Pipeline Company. Susser Holding Corporation, Susser Petroleum Property Company LLC and Aloha Petroleum Ltd. were deconsolidated from these financial statements in July 2015 due to the contribution of Susser Holding Corporation to Sunoco LP and the acquisition by ETE of 100% of the membership interest of Sunoco GP, the general partner of Sunoco LP (See Note 3). |
| | (2)
| Includes ETP and its subsidiaries that are classified as pass-through entities for federal income tax purposes, as well as corporate subsidiaries. |
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, | | 2015 | | 2014 | 2018 | | 2017 | Deferred income tax assets: | | | | | | | Net operating losses and alternative minimum tax credit | $ | 155 |
| | $ | 116 |
| | Net operating losses, alternative minimum tax credit and other carryforwards | | $ | 768 |
| | $ | 683 |
| Pension and other postretirement benefits | 36 |
| | 47 |
| 34 |
| | 21 |
| Long term debt | 61 |
| | 53 |
| | Long-term debt | | 13 |
| | 14 |
| Other | 142 |
| | 111 |
| 181 |
| | 191 |
| Total deferred income tax assets | 394 |
| | 327 |
| 996 |
| | 909 |
| Valuation allowance | (121 | ) | | (84 | ) | (96 | ) | | (189 | ) | Net deferred income tax assets | $ | 273 |
| | $ | 243 |
| 900 |
| | 720 |
| | | | | | | | Deferred income tax liabilities: | | | | | | | Properties, plants and equipment | $ | (1,305 | ) | | $ | (1,506 | ) | | Inventory | — |
| | (153 | ) | | Investment in unconsolidated affiliates | (2,889 | ) | | (2,528 | ) | | Property, plant and equipment | | (782 | ) | | (1,036 | ) | Investments in unconsolidated affiliates | | (2,872 | ) | | (2,726 | ) | Trademarks | (112 | ) | | (355 | ) | (63 | ) | | (173 | ) | Other | (49 | ) | | (32 | ) | (109 | ) | | (100 | ) | Total deferred income tax liabilities | (4,355 | ) | | (4,574 | ) | (3,826 | ) | | (4,035 | ) | Accumulated deferred income taxes | $ | (4,082 | ) | | $ | (4,331 | ) | | Net deferred income taxes | | $ | (2,926 | ) | | $ | (3,315 | ) |
As a result of the early adoption and retrospective application of ASU 2015-17 (see Note 2), $85 million of deferred tax liability previously presented as an other current liability as of December 31, 2014 has been reclassified to other non-current liabilities in our consolidated financial statements. The deconsolidation of Susser Holding Corporation, Susser Petroleum Property Company LLC and Aloha Petroleum Ltd. in July 2015 due to the contribution of Susser Holding Corporation to Sunoco LP and the acquisition by ETE of 100% of the membership interest of Sunoco GP, the general partner of Sunoco LP (see Note 3) significantly decreased the deferred tax assets (liabilities). The table below provides a rollforward of the net deferred income tax liability as follows:
| | | | | | | | | | December 31, | | 2015 | | 2014 | Net deferred income tax liability, beginning of year | $ | (4,331 | ) | | $ | (3,903 | ) | Susser acquisition | — |
| | (488 | ) | ETE Acquisition of general partner of Sunoco LP | 490 |
| | — |
| Tax provision (including discontinued operations) | (202 | ) | | 60 |
| Other | (39 | ) | | — |
| Net deferred income tax liability, end of year | $ | (4,082 | ) | | $ | (4,331 | ) |
2018, ETP Holdco and other corporate subsidiaries havehad a federal net operating loss carryforward tax benefits of $6 million, all$2.60 billion, of which $1.80 billion will expire in 20322031 through 2034. 2037 while the remaining can be carried forward indefinitely. As of December 31, 2017, Sunoco Property Company LLC, a corporate subsidiary of Sunoco LP, had a federal net operating loss carryforward of $364 million. The entire net operating loss carryforward will be fully utilized to offset the taxable gain associated with the retail divestment in 2018. Our corporate subsidiaries have $27$31 million of federal alternative minimum tax credits at December 31, 2015.2018, of which $16 million is expected to be reclassified to current income tax receivable in 2019 pursuant to the Tax Cuts and Jobs Act. Our corporate subsidiaries have state net operating loss carryforward benefits of $122$168 million, net of federal tax, which expire between 20162019 and 2035. The2037. A valuation allowance of $121$98 million is applicable to the state net operating loss carryforward benefits primarily attributable to Sunoco, Inc.’s pre-acquisition periods.
The following table sets forth the changes in unrecognized tax benefits: | | | Years Ended December 31, | Years Ended December 31, | | 2015 | | 2014 | | 2013 | 2018 | | 2017 | | 2016 | Balance at beginning of year | $ | 440 |
| | $ | 429 |
| | $ | 27 |
| $ | 609 |
| | $ | 615 |
| | $ | 610 |
| Additions attributable to tax positions taken in the current year | — |
| | 20 |
| | — |
| 8 |
| | — |
| | 8 |
| Additions attributable to tax positions taken in prior years | 178 |
| | (1 | ) | | 406 |
| 7 |
| | 28 |
| | 18 |
| Settlements | — |
| | (5 | ) | | — |
| | Reduction attributable to tax positions taken in prior years | | — |
| | (25 | ) | | (20 | ) | Lapse of statute | (8 | ) | | (3 | ) | | (4 | ) | — |
| | (9 | ) | | (1 | ) | Balance at end of year | $ | 610 |
| | $ | 440 |
| | $ | 429 |
| $ | 624 |
| | $ | 609 |
| | $ | 615 |
|
As of December 31, 2015,2018, we have $588$620 million ($550588 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 ($3 million, net of federal tax) within the next twelve months due to settlement of certain positions. Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During 2015,2018, we recognized interest and penalties of less than $1$6 million. At December 31, 2015,2018, we have interest and penalties accrued of $5$15 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 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 for the 2004 through 2009 years. Sunoco, Inc.’s 2010 and 2011 years are extended for this issue with the IRS. In November 2016, the CFC ruled against Sunoco, Inc., and the United States Court of Appeals for the Federal Circuit (the “Federal Circuit”) affirmed the CFC’s ruling on November 1, 2018. Sunoco, Inc. subsequently filed a petition for rehearing with the Federal Circuit, and this was denied on January 24, 2019. Sunoco, Inc. is considering further review of the Federal Circuit’s affirmation of the CFC’s ruling. If Sunoco, Inc. is ultimately fully successful with its claims,in this litigation, it will receive tax refunds of approximately $519$530 million. However, due to the uncertainty surrounding the claims,litigation, a reserve of $519$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 financial statementsbalance sheets as of December 31, 2015.2018 and 2017. In December ofNovember 2015, Thethe Pennsylvania Commonwealth Court determined in Nextel Communications v. Commonwealth (“Nextel”Nextel”) that the Pennsylvania limitation on NOL carryforwardscarryforward deductions violated the uniformity clause of the Pennsylvania Constitution. Based uponConstitution and struck the NOL limitation in its entirety. In October 2017, the Pennsylvania Supreme Court affirmed the decision 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 subsequently filed a petition for writ of certiorari with the United States Supreme Court, and this was denied on June 11, 2018. Now certain Pennsylvania taxpayers are proceeding with litigation in Pennsylvania state courts on issues not addressed by the Pennsylvania Supreme Court in Nextel,, specifically, whether the Due Process and Equal Protection Clauses of the United States Constitution and the Remedies Clause of the Pennsylvania Constitution require a court to grant the taxpayer relief. Sunoco, Inc. is recognizinghas recognized approximately $46$67 million ($3053 million after federal income tax benefits) in tax benefit based on previously filed tax returns and certain previously filed protective claims.claims as relates to its cases currently held pending the Nextel matter. However, asbased upon the NextelPennsylvania Supreme Court’s October 2017 decision, is subject to appeal, and because of uncertainty in the breadth of the application of the decision, we have reserved $9$34 million ($627 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 2012 and prior tax years. However, Sunoco, Inc.ET and its subsidiaries are no longer subject to examination by the IRS, and most state jurisdictions, for the 2013 and prior tax years. However, Sunoco, Inc. and its subsidiaries remain subject to examination by the IRS for tax years prior tobeginning in 2007. Sunoco, Inc. has been examined by the IRS for tax years through October 4, 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 was under examination by the IRS for the tax years 2004 through 2009. In July 2015, we and the IRS settled all issues related to the IRS examination of the 2004 through 2009 tax years. As a result of the settlement, we recognized a net tax benefit of $7 million.
ETPET 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 $1.81 billion in December 2017. For the year ended December 31, 2018, the Partnership recorded an income tax expense due to pre-tax income at its corporate subsidiaries, partially offset by a state statutory rate reduction. S - 51
| | 11. | REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES: |
Contingent Matters Potentially ImpactingFERC Proceedings
In March 2016, the PartnershipFERC commenced an audit of Trunkline for the period from Our Investment in Citrus Florida Gas Pipeline Relocation Costs. The Florida DepartmentJanuary 1, 2013 to present to evaluate Trunkline’s compliance with the requirements 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 areits FERC gas tariff, the subject of litigation in Broward County, Florida. On November 16, 2012, FDOT paid to FGT the sum of approximately $100 million, representing the amountaccounting regulations of the judgment, plus interest,Uniform System of Accounts as prescribed by the FERC, and the FERC’s annual reporting requirements. The FERC issued an audit report in a case triedOctober 2018. In response to the findings in 2011.the audit report, the Company expects to make certain changes to its processes, policies and procedures; however, the Company does not expect the findings to result in any changes to its financial statements.
On April 14, 2011, FGT filed suit againstBy order issued January 16, 2019, the FDOT/FTE and other defendants in Broward County, Florida seeking an injunction and damages as the resultFERC initiated a review of Panhandle’s existing rates pursuant to Section 5 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 pursuantNatural Gas Act to which, among other things, FDOT/FTE paid FGT approximately $19 million in September 2013 in settlement of FGT’s claims with respect todetermine whether 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 reimbursedrates currently charged 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.
Guarantee of Collection
Panhandle previously guaranteed the collections of the payment of $600 million of Regency 4.50% senior notes due 2023. On May 28, 2015, ETP entered into a supplemental indenture relating to the senior notes pursuant to which it has agreed to become a co-obligor with respect to the payment obligations thereunder. Accordingly, pursuant to the terms of the senior notes, Panhandle’s obligations under the Panhandle Guarantee have been released. On April 30, 2015, in connection with the Regency Merger, ETP entered into various supplemental indentures pursuant to which ETP had agreed to fully and unconditionally guarantee all payment obligations of Regency for all of its outstanding senior notes.
On May 28, 2015, ETP entered into a supplemental indenture relating to the senior notes pursuant to which it has agreed to become a co-obligor with respect to the payment obligations thereunder. Accordingly, pursuant to the terms of the senior notes, Panhandle’s obligations under the Panhandle Guarantee have been released.
ETP Retail Holdings Guarantee of Sunoco LP Notes
In April 2015, Sunoco LP acquired a 31.58% equity interest in Sunoco, LLC from Retail Holdings for $775 million of cash and $41 million of Sunoco LP common units. The cash portion of the consideration was financed through Sunoco LP’s issuance of $800 million principal amount of 6.375% senior notes due 2023. Retail Holdings entered into a guarantee of collection with Sunoco LP and Sunoco Finance Corp., a wholly owned subsidiary of Sunoco LP, pursuant to which Retail Holdings has agreed to provide a guarantee of collection, but not of payment, to Sunoco LP with respect to the principal amount of the senior notes issued by Sunoco LP.
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 beare just and reasonable and not unduly discriminatoryset the matter for hearing. Panhandle must file a cost and pipelines may not confer any undue preference. The tariff rates established for interstate services were basedrevenue study on a negotiated agreement; however,or before April 1, 2019. An initial decision is expected to be issued in the FERC’s rate-making methodologies may limit our ability to set rates basedfirst quarter of 2020.In addition, 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, TranswesternNovember 30, 2018, Sea Robin filed a general NGA Section 4 rate case pursuant to a 2011 settlement agreement with its shippers. On December 2, 2014,Section 4 of the Natural Gas Act. A hearing date is scheduled for October 23, 2019 and an initial decision is expected to be issued in the first quarter of 2020.
By order issued February 19, 2019, the FERC issued an order accepting and suspendinginitiated a review of Southwest Gas Storage Company’s existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates tocurrently charged by Southwest Gas Storage Company are just and reasonable and set the matter for hearing. Southwest Gas Storage Company must file a cost and revenue study on or before May 6, 2019. The FERC is directing that an initial decision be effective April 1, 2015, subject to refund,issued within 47 weeks of the date the cost and setting a procedural schedule with a hearing scheduled in late 2015. On June 22, 2015, Transwestern filed a settlement with the FERC which resolved or provided for the resolution of all issues set for hearing in the case. On October 15, 2015, the FERC issued an order approving the rate case settlement without condition. 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 no earlier than May 1, 2015, subject to refund. On September 11, 2015, FGT filed a settlement with the FERC which resolved or provided for the resolution of all issues set for hearing in the case. On December 4, 2015, the FERC issued an order approving the rate case settlement without condition.
Sea Robin Rate Case
On December 2, 2013, Sea Robin filed a general NGA Section 4 rate case at the FERC as required by a previous rate case settlement. In the filing, Sea Robin sought to increase its authorized rates to recover costs related to asset retirement obligations, depreciation, and return and taxes. Filed rates were put into effect June 1, 2014 and estimated settlement rates were put into effect September 1, 2014, subject to refund. A settlement was reached with the shippers and a stipulation and agreement was filed with the FERC on July 23, 2014. The settlement was certified to the FERC by the administrative law judge on October 7, 2014 and the settlement, as modified on January 16, 2015, was approved by the FERC on June 26, 2015. In September 2015, related to the final settlement, Sea Robin made refunds to customers totaling $11 million, including interest.revenue study is due.
Commitments In the normal course of our business, we purchase, processETO purchases, processes and sellsells natural gas pursuant to long-term contracts and we enterenters into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. We believeETO believes that the terms of these agreements are commercially reasonable and will not have a material adverse effect on ourits financial position or results of operations. Our joint venture agreements require that we funds our proportionate share of capital contributions to its unconsolidated affiliates. Such contributions will depend upon our 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 2058.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, | | | 2015 | | 2014 | | 2013 | Rental expense(1) | | $ | 176 |
| | $ | 159 |
| | $ | 151 |
| Less: Sublease rental income | | (16 | ) | | (26 | ) | | (24 | ) | Rental expense, net | | $ | 160 |
| | $ | 133 |
| | $ | 127 |
|
| | | | | | | | | | | | | | | | Years Ended December 31, | | | 2018 | | 2017 | | 2016 | Rental expense(1) | | $ | 139 |
| | $ | 171 |
| | $ | 161 |
| Sublease rental income(2) | | 40 |
| | 25 |
| | 26 |
| Net | | $ | 99 |
| | $ | 146 |
| | $ | 135 |
|
| | (1) | Includes contingent rentals totaling $26$4 million, $24$16 million and $22$18 million for the years ended December 31, 2015, 20142018, 2017 and 2013,2016, respectively. |
| | (2) | Sublease rental income is included in other revenues in the accompanying statements of operations. |
Future minimum lease commitments for such leases are: | | | | | Years Ending December 31: | | 2016 | $ | 57 |
| 2017 | 53 |
| 2018 | 44 |
| 2019 | 39 |
| 2020 | 40 |
| Thereafter | 252 |
| Future minimum lease commitments | 485 |
| Less: Sublease rental income | (34 | ) | Net future minimum lease commitments | $ | 451 |
|
Our joint venture agreements require that we fund our proportionate share of capital contributions to our unconsolidated affiliates. Such contributions will depend upon our unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations. | | | | | Years Ending December 31: | | 2019 | $ | 104 |
| 2020 | 95 |
| 2021 | 74 |
| 2022 | 58 |
| 2023 | 50 |
| Thereafter | 220 |
| Future minimum lease commitments | 601 |
| Less: Sublease rental income | (111 | ) | Net future minimum lease commitments | $ | 490 |
|
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, LLC (“Dakota Access”) to make two crossings of the Missouri River in North Dakota. The USACE also issued easements to allow the pipeline to cross land owned by the USACE adjacent to the Missouri River. On July 27, 2016, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia (“the Court”) against the USACE and challenged the legality of these permits 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 was pending, which the court denied on September 9, 2016. Dakota Access intervened in the case. The Cheyenne River Sioux Tribe (“CRST”) also intervened. The SRST filed an amended complaint and added claims based on treaties between the SRST and the CRST and the United States and statutes governing the use of government property. In February 2017, in response to a Presidential memorandum, the Department of the Army delivered an easement to Dakota Access allowing the pipeline to cross Lake Oahe. The CRST moved for a preliminary injunction and temporary restraining order (“TRO”) to block operation of the pipeline, which motion was denied. In June, 2017, 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 concluded that the USACE had not violated 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. 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.
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 third-party to review its compliance with the conditions and regulations governing its easements and to assess integrity threats to the pipeline. The assessment report was filed with the Court. 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 filed the revised plan with the Court. 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 and second reports were filed with the court on December 29, 2017 and February 28, 2018, respectively. On February 8, 2018, the Court docketed a motion by CRST to “compel meaningful consultation on remand.” SRST then made a similar motion for “clarification re remand process and remand conditions.” The motions seek an order from the Court directing the USACE as to how it should conduct its additional review on remand. Dakota Access pipeline and the USACE opposed both motions. On April 16, 2018, the Court denied both motions. On March 19, 2018, the District Court denied YST’s motion for partial summary judgment and instead granted judgment in favor of Dakota Access pipeline and the USACE on the claims raised in YST’s motion. The Court concluded that YST’s NHPA claims are moot because construction of the pipeline is complete and that the government’s review process did not violate NEPA or the various treaties cited by the YST. On May 3, 2018, the District Court ordered the USACE to file a status report by June 8, 2018 informing the Court when the USACE expects the remand process to be complete. On June 8, 2018, the USACE filed a status report stating that they will conclude the remand process by August 10, 2018. On August 7, 2018, the USACE informed the Court that they will need until August 31, 2018 to finish the remand process. On August 31, 2018, the USACE informed the Court that it had completed the remand process and that it had determined that the three issues remanded by the Court had been correctly decided. On October 1, 2018, the USACE produced a detailed remand analysis document supporting that determination. The plaintiff Tribes and certain of the individuals have sought leave of the Court to amend their complaints to challenge the remand process and the USACE’s decision on remand. The Court is currently considering proposed schedules for a final round of summary judgment briefing, and ETO expects that the Court will issue a final determination once that briefing is concluded. On January 3, 2019, the Court granted the Tribes’ requests to supplement their respective complaints challenging the remand process, subject to defendants’ right to argue later that such supplementation may be overbroad and not permitted by law. On January 10, 2019, the Court denied the Oglala Sioux Tribe’s motion to amend its complaint to expand one of its pre-remand claims. On January 17, 2019, the DOJ, on behalf of the USACE, moved to stay the litigation in light of the lapse in appropriations for the DOJ. The Tribes’ and individual plaintiffs have opposed that request. The motion is currently pending before the Court. While Energy Transfer believes that the pending lawsuits are unlikely to halt or suspend operation of the pipeline, we cannot assure this outcome. Energy Transfer 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 Sunoco, Inc. (R&M) (now known as Sunoco (R&M), along with other refiners, manufacturers and sellers of gasoline, is a defendantLLC) (collectively, “Sunoco”) 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 plaintiffsentities, assert primarily product liability, claims and additional claims including nuisance, trespass, negligence, violation of environmental laws, andand/or deceptive business practices.practices claims. The plaintiffs in all of the cases seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees.
As of December 31, 2015,2018, Sunoco Inc. is a defendant in six cases, including casesone case each initiated by the States of New Jersey,Maryland, Vermont and 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 and one caseaction. The actions brought by the CityState of Breaux BridgeMaryland and Commonwealth of Pennsylvania have also named as defendants Energy Transfer Partners, L.P., ETP Holdco Corporation, and Sunoco Partners Marketing & Terminals, L.P. In late July 2018, the Court in the USDC inVermont matter denied the Western DistrictState of Louisiana. FourVermont’s motion to amend its complaint to add specific allegations regarding some of these cases are venued in a multidistrict litigation proceeding in a New York federal court.the sites the court previously dismissed. The New Jersey, Puerto Rico,State of 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. In November 2015, Sunoco along with other co-defendants agreed todefendants reached a global settlement in principle to resolve the remaining statewide Vermont Case in September 2018. The parties are in the process of the City of Breaux Bridge MTBE 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 of Sunoco, Inc. in these matters. finalizing settlement documents.
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 Following the January 26, 2015 announcement of the definitive merger agreement with Regency, purportedPurported Regency unitholders filed lawsuits in state and federal courts in Dallas Texas and Delaware state court asserting claims relating to the proposed transaction.
On February 3, 2015, William Engel and Enno Seago, purported Regency unitholders, filed a class action petition on behalf of Regency’s common unitholders and a derivative suit on behalf of Regency in the 162nd Judicial District Court of Dallas County, TexasRegency-ETP merger (the “Engel Lawsuit”“Regency Merger”). The lawsuit names as defendants theAll but one Regency General Partner, the members of the Regency General Partner’s board of directors, ETP, ETP GP, ETE, and, as a nominal party, Regency. The Engel Lawsuit alleges that (1) the Regency General Partner’s directors breached duties to Regency and the Regency’s unitholders by employing a conflicted and unfair process and failing to maximize the merger consideration; (2) the Regency 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 alreadyMerger-related lawsuits have been completed. The plaintiffs also seek money damages and court costs, including attorney’s fees.
dismissed. On February 9,June 10, 2015, Stuart Yeager,Adrian Dieckman (“Dieckman”), a purported Regency unitholder, filed a class action petition on behalf of the Regency’s common unitholders and a derivative suit on behalf of Regency 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 Regency unitholder, filed a class action petition on behalf of Regency’s common unitholders and a derivative suit on behalf of Regency 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 Regency unitholder, filed a class action complaint on behalf of the Regency’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 Regency as a defendant rather than a nominal party. The lawsuit also omits one of the Regency General Partner’s directors, Richard Brannon, who was named in the Engel Lawsuit. The Blankman Lawsuit alleges that the Regency General Partner’s directors breached their fiduciary duties to the unitholders by failing to maximize the value of Regency, failing to properly value Regency, 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 Regency unitholder, filed a class action complaint on behalf of Regency’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 March 27, 2015, Plaintiff Bazini filed an amended complaint asserting additional claims under Sections 14(a) and 20(a) of the Securities Exchange Act of 1934.
On February 11, 2015, Mark Hinnau, a purported Regency unitholder, filed a class action complaint on behalf of Regency’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 Regency unitholder, filed a class action complaint on behalf of Regency’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 Regency unitholder, filed a class action complaint on behalf of Regency’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 Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Berlin Lawsuit”). The allegations, claims, and relief sought in the Berlin Lawsuit are similar to those in the Blankman Lawsuit.
On March 13, 2015, the Court in the 95th Judicial District Court of Dallas County, Texas transferred and consolidated the Yeager and Coggia Lawsuits into the Engel Lawsuit and captioned the consolidated lawsuit as Engel v. Regency GP, LP, et al. (the “Consolidated State Lawsuit”).
On March 30, 2015, Leonard Cooperman, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the United States District Court for the Northern District of Texas (the “Cooperman Lawsuit”). The allegations, claims, and relief sought in the Cooperman Lawsuit are similar to those in the Blankman Lawsuit.
On March 31, 2015, the Court in United States District Court for the Northern District of Texas consolidated the Blankman, Bazini, Hinnau, Weaver, Dieckman, and Berlin Lawsuits into a consolidated lawsuit captioned Bazini v. Bradley, et al. (the “Consolidated Federal Lawsuit”). On April 1, 2015, plaintiffs in the Consolidated Federal Lawsuit filed an Emergency Motion to Expedite Discovery. On April 9, 2015, by order of the Court, the parties submitted a joint submission wherein defendants opposed plaintiffs’ request to expedite discovery. On April 17, 2015, the Court denied plaintiffs’ motion to expedite discovery.
On June 10, 2015, Adrian Dieckman, a purported Regency unitholder, filed a class action complaint on behalf of Regency’s common unitholders in the Court of Chancery of the State of Delaware (the “Dieckman DE Lawsuit”“Regency Merger Litigation”), on behalf of Regency’s common unitholders against Regency GP, LP; Regency GP LLC; ET, ETO, ETP GP, and the members of Regency’s board of directors (“Defendants”).
The lawsuitRegency Merger Litigation alleges that the transaction did not comply withRegency Merger breached the Regency partnership agreement because the Conflicts CommitteeRegency’s conflicts committee was not properly formed.formed, and the Regency Merger was not approved in good faith. On July 6, 2015,March 29, 2016, the Delaware Court of Chancery granted 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. Defendants then filed Motions to Dismiss the Amended Complaint and a Motion to Stay Discovery on May 19, 2017. On February 20, 2018, the briefing has since been completed. Oral argument onCourt of Chancery issued an Order granting in part and denying in part the Motions was held in December 2015.motions to dismiss, dismissing the claims against all defendants other than Regency GP, LP and Regency GP LLC (the “Regency Defendants”). On March 6, 2018, the Regency Defendants filed their Answer to Plaintiff’s Verified Amended Class Action Complaint. Trial is currently set for September 29, 2015, Chancellor Bouchard ordered discovery stayed, pending a ruling on Defendants’ Motions to Dismiss.23-27, 2019. On June 5, 2015, the Dieckman Lawsuit was dismissed. On July 23, 2015, the Blankman, Bazini, Hinnau, Weaver and Berlin Lawsuits were dismissed. On August 20, 2015, the Cooperman Lawsuit was dismissed. The Consolidated Federal Lawsuit was terminated once all named plaintiffs voluntarily dismissed.
On January 8, 2016, the plaintiffs in the Consolidated State Lawsuit filed a notice of non-suit without prejudice. The Dieckman DE Lawsuit is the only lawsuit that remains. TheRegency Defendants cannot predict the outcome of the Regency Merger Litigation or any lawsuits that might be filed subsequent to the date of this lawsuit, orfiling; nor can the Regency Defendants predict the amount of time and expense that will be required to resolve it.the Regency Merger Litigation. The Regency 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.
Energy Transfer Merger Litigation On September 17, 2018, William D. Warner (“Plaintiff”), a purported Energy Transfer Partners, L.P. unitholder, filed a putative class action asserting violations of various provisions of the Securities Exchange Act of 1934 and various rules promulgated thereunder in connection with the Energy Transfer Merger against Energy Transfer Partners, L.P., Kelcy L. Warren, Michael K. Grimm, Marshall S. McCrea, Matthew S. Ramsey, David K. Skidmore, and W. Brett Smith (“Defendants”). Plaintiff specifically alleged that the proxy statement related to the Energy Transfer Merger omitted and/or misrepresented material information. On December 17, 2018, Plaintiff voluntarily dismissed his lawsuit. Enterprise Products Partners, L.P. and Enterprise Products Operating LLC Litigation On January 27, 2014, a trial commenced between ETPETO 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 ETPETO against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETP.ETO. The jury also found that ETPETO owed Enterprise $1 million under a reimbursement agreement. On July 29, 2014, the trial court entered a final judgment in favor of ETPETO and awarded ETPETO $536 million, consisting of compensatory damages, disgorgement, and pre-judgment interest. The trial court also ordered that ETPETO shall be entitled to recover post-judgment interest and costs of court and that Enterprise is not entitled to any net recovery on its counterclaims. Enterprise has filed a notice of appeal with the TexasCourt of Appeals. On July 18, 2017, the Court of Appeals issued its opinion and reversed the trial court’s judgment. ETO’s
motion for rehearing to the Court of Appeals was denied. On June 8, 2018, the Texas Supreme Court ordered briefing on the merits. ETO’s petition for review remains under consideration by Enterprisethe Texas Supreme Court. Litigation Filed By or Against Williams On April 6, 2016, The Williams Companies, Inc. (“Williams”) filed a complaint against ET and ETP is complete. Oral argument has not been scheduled.LE GP in the Delaware Court of Chancery (the “First Delaware Williams Litigation”). Williams sought, among other things, to (a) rescind the issuance of the Partnership’s Series A Convertible Preferred Units (the “Issuance”) and (b) invalidate an amendment to ET’s partnership agreement that was adopted on March 8, 2016 as part of the Issuance. On May 3, 2016, ET 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 ET-Williams merger agreement (the “Merger Agreement”) by (a) blocking ET’s attempts to complete a public offering of the Series A Convertible Preferred 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 ET and LE GP and added Energy Transfer Corp LP, ETE Corp GP, LLC, and Energy Transfer Equity GP, LLC as additional defendants (collectively, “Defendants”) (the “Second Delaware Williams Litigation”). In accordancegeneral, 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 GAAP, no amountsthe merger (the “Form S-4”) effective. Williams asked the Court, in general, to (a) issue a declaratory judgment that ET breached the Merger Agreement, (b) enjoin ET from terminating the Merger Agreement on the basis that it failed to obtain a 721 Opinion, (c) enjoin ET from terminating the Merger Agreement on the basis that the transaction failed to close by the outside date, and (d) force ET to close the merger or take various other affirmative actions. ET filed an answer and counterclaim in the Second Delaware Williams Litigation. In addition to the counterclaims previously asserted, ET 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 ET 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. ET 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 July 29, 2014 finalCourt ruled in favor of ET on Williams’ claims in the Second Delaware Williams Litigation and issued a declaratory judgment that ET 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 ET’s counterclaims. Williams filed a notice of appeal to the Supreme Court of Delaware on June 27, 2016. Williams filed an amended complaint on September 16, 2016 and sought a $410 million termination fee, and Defendants filed amended counterclaims and affirmative defenses. In response, Williams filed a motion to dismiss Defendants’ amended counterclaims and to strike certain of Defendants’ affirmative defenses. On March 23, 2017, the Delaware Supreme Court affirmed the Court’s ruling on the June trial, and as a result, Williams has conceded that its $10 billion damages claim is foreclosed, although its $410 million termination fee claim remains pending. On December 1, 2017, the Court issued a Memorandum Opinion granting Williams’ motion to dismiss in part and denying Williams’ motion to dismiss in part. 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 On April 12, 2016, two purported ET unitholders (the “Issuance Plaintiffs”) filed putative class action lawsuits against ET, 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 statementsthe Delaware Court of Chancery (the “Issuance Litigation”). Another purported ET unitholder, Chester County Employees’ Retirement Fund, later joined the Issuance Litigation. The Issuance Plaintiffs allege that the Issuance breached various provisions of ET’s partnership agreement. The Issuance Plaintiffs seek, among other things, preliminary and permanent injunctive relief that (a) prevents ET from making distributions to holders of the Series A Convertible Preferred Units and (b) invalidates an amendment to ET’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 matter was tried in front of Vice Chancellor Glasscock on February 19-21, 2018. Post-trial arguments were heard on April 16, 2018. In a post-trial opinion dated May 17, 2018, the Court found that one provision of the Issuance breached ET’s partnership agreement but that this breach caused no damages. The Court denied Plaintiffs’ requests for injunctive relief and declined to award damages other than nominal damages. Plaintiffs subsequently filed a motion seeking $8.5 million in attorneys’ fees and expenses from the Issuance Defendants, which the Issuance Defendants have opposed. 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. Rover On November 3, 2017, the State of Ohio and the Ohio Environmental Protection Agency (“Ohio EPA”) filed suit against Rover and Pretec Directional Drilling, LLC (“Pretec”) seeking to recover approximately $2.6 million in civil penalties allegedly owed and certain injunctive relief related to permit compliance. Laney Directional Drilling Co., Atlas Trenchless, LLC, Mears Group, Inc., D&G Directional Drilling, Inc. d/b/a D&G Directional Drilling, LLC, and B&T Directional Drilling, Inc. (collectively, with Rover and Pretec, “Defendants”) were added as defendants on April 17, 2018 and July 18, 2018. Ohio EPA alleges that the Defendants illegally discharged millions of gallons of drilling fluids into Ohio’s waters that caused pollution and degraded water quality, and that the Defendants harmed pristine wetlands in Stark County. Ohio EPA further alleges that the Defendants caused the degradation of Ohio’s waters by discharging pollution in the form of sediment-laden storm water into Ohio’s waters and that Rover violated its hydrostatic permits by discharging effluent with greater levels of pollutants than those permits allowed and by not properly sampling or monitoring effluent for required parameters or reporting those alleged violations. Rover and other Defendants filed several motions to dismiss and Ohio EPA filed a motion in opposition. The State’s opposition to those motions was filed on October 12, 2018. Rover and other Defendants filed their replies on November 2, 2018. The court has not yet ruled on the motion. The State requested oral argument on the motion, but no argument has been scheduled to date. In January 2018, Ohio EPA sent a letter to the FERC to express concern regarding drilling fluids lost down a hole during horizontal directional drilling (“HDD”) operations as part of the Rover Pipeline construction. Rover sent a January 24 response to the FERC and stated, among other things, that as Ohio EPA conceded, Rover was conducting its drilling operations in accordance with specified procedures that had been approved by the FERC and reviewed by the Ohio EPA. In addition, although the HDD operations were crossing the same resource as that which led to an inadvertent release of drilling fluids in April 2017, the drill in 2018 had been redesigned since the original crossing. Ohio EPA expressed concern that the drilling fluids could deprive organisms in the wetland of oxygen. Rover, however, has now fully remediated the site, a fact with which Ohio EPA concurs. Construction of Rover is now complete and the pipeline is fully operational. Bayou Bridge On January 11, 2018, environmental groups and a trade association filed suit against the USACE in the United States District Court for the Middle District of Louisiana. Plaintiffs allege that the USACE’s issuance of permits authorizing the construction of the Bayou Bridge Pipeline through the Atchafalaya Basin (“Basin”) violated the National Environmental Policy Act, the Clean Water Act, and the Rivers and Harbors Act. They asked the district court to vacate these permits and to enjoin construction of the project through the Basin until the USACE corrects alleged deficiencies in its decision-making process.
ETO, through its subsidiary Bayou Bridge Pipeline, LLC (“Bayou Bridge”), intervened on January 26, 2018. On March 27, 2018, Bayou Bridge filed an answer to the complaint. On January 29, 2018, Plaintiffs filed motions for a preliminary injunction and TRO. United States District Court Judge Shelly Dick denied the TRO on January 30, 2018, but subsequently granted the preliminary injunction on February 23, 2018. On February 26, 2018, Bayou Bridge filed a notice of appeal processand a motion to stay the February 23, 2018 preliminary injunction order. On February 27, 2018, Judge Dick issued an opinion that clarified her February 23, 2018 preliminary injunction order and denied Bayou Bridge’s February 26, 2018 motion to stay as moot. On March 1, 2018, Bayou Bridge filed a new notice of appeal and motion to stay the February 27, 2018 preliminary injunction order in the district court. On March 5, 2018, the district court denied the March 1, 2018 motion to stay the February 27, 2018 order. On March 2, 2018, Bayou Bridge filed a motion to stay the preliminary injunction in the Fifth Circuit. On March 15, 2018, the Fifth Circuit granted a stay of injunction pending appeal and found that Bayou Bridge “is likely to succeed on the merits of its claim that the district court abused its discretion in granting a preliminary injunction.” Oral arguments were heard on the merits of the appeal, that is, completed.whether the district court erred in granting the preliminary injunction in the Fifth Circuit on April 30, 2018. The district court has stayed the merits case pending decision of the Fifth Circuit. On May 10, 2018, the District Court stayed the litigation pending a decision from the Fifth Circuit. On July 6, 2018, the Fifth Circuit vacated the Preliminary Injunction and remanded the case back to the District Court. Construction is ongoing. On August 14, 2018, Plaintiffs sought leave of court to amend their complaint to add an “as applied” challenge to the USACE’s application of the Louisiana Rapid Assessment Method to Bayou Bridge’s permits. Defendants’ filed motions in opposition on September 18, 2018. On September 11, 2018, Plaintiffs filed a motion for partial summary judgment on the issue of the USACE’s analysis of the risks of an oil spill once the pipeline is in operation. On November 6, 2018 the court struck plaintiffs’ motion as premature. At an October 2, 2018 scheduling conference, the USACE agreed to lodge the administrative record for Plaintiffs’ original complaint, which it has done. Challenges to the completeness of the record have been briefed and are currently pending before the Court. At the October 18 conference, the Court also scheduled summary judgment briefing on Plaintiffs’ original complaint; briefing is scheduled to conclude by Spring of 2019. On December 28, 2018, Judge Dick issued a General Order for the Middle District of Louisiana holding in abeyance all civil matters where the United States is a party. Notwithstanding the General Order, on January 11, 2019, Plaintiffs filed a Motion for Summary Judgment on their National Environmental Policy Act and Clean Waters Act claims. On January 11, 2019, Plaintiffs filed a Motion for Summary Judgment on its National Environmental Policy Act and Coastal Water Authority claims. On January 23, 2019, Plaintiffs filed a Second Motion for Preliminary Injunction based on the alleged permit violations in the January 7, 2019 letter, which the Court later denied. On February 11, 2019, the Court denied Plaintiffs’ August 14, 2018 motion for leave to amend their complaint. 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, 20152018 and 2014,2017, accruals of approximately $40$55 million and $37$56 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. On April 25, 2018, and as amended on April 30, 2018, State Senator Andrew Dinniman filed a Formal Complaint and Petition for Interim Emergency Relief (“Complaint”) against SPLP before the Pennsylvania Public Utility Commission (“PUC”). Specifically, the Complaint alleges that (i) the services and facilities provided by the Mariner East Pipeline (“ME1,” “ME2” or “ME2x”) in West Whiteland Township (“the Township”) are unreasonable, unsafe, inadequate, and insufficient for, among
other reasons, selecting an improper and unsafe route through densely populated portions of the Township with homes, schools, and infrastructure and causing inadvertent returns and sinkholes during construction because of unstable geology in the Township; (ii) SPLP failed to warn the public of the dangers of the pipeline; (iii) the construction of ME2 and ME2x increases the risk of damage to the existing co-located ME1 pipeline; and (iv) ME1, ME2 and ME2x are not public utility facilities. Based on these allegations, Senator Dinniman’s Complaint seeks emergency relief by way of an order (i) prohibiting construction of ME2 and ME2x in the Township; (ii) prohibiting operation of ME1; (iii) in the alternative to (i) and (ii) prohibiting the construction of ME2 and ME2x and the operation of ME1 until SPLP fully assesses and the PUC approves the condition, adequacy, efficiency, safety, and reasonableness of those pipelines and the geology in which they sit; (iv) requiring SPLP to release to the public its written integrity management plan and risk analysis for these pipelines; and (v) finding that these pipelines are not public utility facilities. In short, the relief, if granted, would continue the suspension of operation of ME1 and suspend further construction of ME2 and ME2x in the Township. Following a hearing on May 7, 2018 and 10, 2018, Administrative Law Judge Elizabeth H. Barnes (“ALJ”) issued an Order on May 24, 2018 that granted Senator Dinniman’s petition for interim emergency relief and required SPLP to shut down ME1, to discontinue construction of ME2 and ME2x within the Township, and required SPLP to provide various types of information and perform various geotechnical and geophysical studies within the Township. The ALJ’s Order was immediately effective, and SPLP complied by shutting down service on ME1 and discontinuing all construction in the Township on ME2 and ME2x. The ALJ’s Order was automatically certified as a material question to the PUC, which issued an Opinion and Order on June 15, 2018 (following a public meeting on June 14, 2018) that reversed in part and affirmed in part the ALJ’s Order. PUC’s Opinion and Order permitted SPLP to resume service on ME1, but continued the shutdown of construction on ME2 and ME2x pending the submission of the following three types of information to PUC: (i) inspection and testing protocols; (ii) comprehensive emergency response plan; and (iii) safety training curriculum for employees and contractors. SPLP submitted the required information on June 22, 2018. On July 2, 2018, Senator Dinniman and intervenors responded to the submission. SPLP is also required to provide an affidavit that the Pennsylvania Department of Environmental Protection (“PADEP”) has issued appropriate approvals for construction of ME2 and ME2x in the Township before recommencing construction of ME2 and ME2x locations within the Township. SPLP submitted all necessary affidavits. On August 2, 2018 the PUC entered an Order lifting the stay of construction on ME2 and ME2x in the Township with respect to four of the eight areas within the Township where the necessary environmental permits had been issued. Subsequently, after PADEP’s issuance of permit modifications for two of the four remaining construction sites, the PUC lifted the construction stay on those two sites as well. Also on August 2, 2018, the PUC ratified its prior action by notational voting of certifying for interlocutory appeal to the Pennsylvania Commonwealth Court the legal issue of whether Senator Dinniman has standing to pursue this matter. Sunoco submitted a petition for permission to appeal on this issue of standing. Senator Dinniman and intervenors opposed that petition. On September 27, 2018, the Commonwealth Court issued an Order that certified for appeal the issue of Senator Dinniman’s standing. The Order stays all proceedings in the PUC. Also on August 2, 2018, the PUC ratified its prior action by notational voting of certifying for interlocutory appeal to the Pennsylvania Commonwealth Court the legal issue of whether Senator Dinniman has standing to pursue the action. SPLP submitted a petition for permission to appeal on this issue of standing. Senator Dinniman and intervenors opposed that petition. On September 27, 2018, the Commonwealth Court issued an Order that certified for appeal the issue of Senator Dinniman’s standing. The Order stays all proceedings in the PUC. On July 25, 2017, the Pennsylvania Environmental Hearing Board (“EHB”) issued an order to SPLP to cease HDD activities in Pennsylvania related to the Mariner East 2 project. On August 1, 2017 the EHB lifted the order as to two drill locations. On August 3, 2017, the EHB lifted the order as to 14 additional locations. The EHB issued the order in response to a complaint filed by environmental groups against SPLP and the PADEP. The EHB Judge encouraged the parties to pursue a settlement with respect to the remaining HDD locations and facilitated a settlement meeting. On August 7, 2017 a final settlement was reached. A stipulated order has been submitted to the EHB Judge with respect to the settlement. The settlement agreement requires that SPLP reevaluate the design parameters of approximately 26 drills on the Mariner East 2 project and approximately 43 drills on the Mariner East 2X project. The settlement agreement also provides a defined framework for approval by PADEP for these drills to proceed after reevaluation. Additionally, the settlement agreement requires modifications to several of the HDD plans that are part of the PADEP permits. Those modifications have been completed and agreed to by the parties and the reevaluation of the drills has been initiated by the company. On July 31, 2018 the underlying permit appeals in which the above settlements occurred were withdrawn in a settlement between the appellants and PADEP. That settlement did not involve SPLP. In addition, on June 27, 2017 and July 25, 2017, the PADEP entered into a Consent Order and Agreement with SPLP regarding inadvertent returns of drilling fluids at three HDD locations in Pennsylvania related to the Mariner East 2 project. Those agreements require SPLP to cease HDD activities at those three locations until PADEP reauthorizes such activities and to submit a corrective action plan for agency review and approval. SPLP has fulfilled the requirements of those agreements and has been authorized by PADEP to resume drilling the locations.
On September 10, 2018, a pipeline release and fire occurred on the Revolution Pipeline in the vicinity of Ivy Lane located in Center Township, Beaver County, Pennsylvania. There were no injuries but there were evacuations of local residents as a precautionary measure. The Pennsylvania Department of Environmental Protection (“PADEP”) and the Pennsylvania Public Utility Commission (“PUC”) are investigating the incident. On October 29, 2018, PADEP issued a Compliance Order requiring our subsidiary, ETC Northeast, to cease all earth disturbance activities at the site (except as necessary to repair and maintain existing Best Management Practices (“BMPs”) and temporarily stabilize disturbed areas), implement and/or maintain the Erosion and Sediment BMPs at the site, stake the limit of disturbance, identify and report all areas of non-compliance, and submit an updated Erosion and Sediment Control Plan, a Temporary Stabilization Plan, and an updated Post Construction Stormwater Management Plan. The scope of the Compliance Order has been expanded to include the disclosure to PADEP of alleged violations of environmental permits with respect to various construction and post-construction activities and restoration obligations along the 42-mile route of the Revolution line. ETC Northeast filed an appeal of the Compliance Order with the Pennsylvania Environmental Hearing Board. On February 8, 2019, PADEP filed a Petition to Enforce the Compliance Order with Pennsylvania’s Commonwealth Court. The Court issued an Order on February 14, 2019 requiring the submission of an answer to the Petition on or before March 12, 2019, and scheduling a hearing on the Petition for March 26, 2019. PADEP has also and issued a Permit Hold on any requests for approvals/permits or permit amendments made by us or any of our subsidiaries for any projects in Pennsylvania pursuant to the state’s water laws. We continue to work through these issues with PADEP. No amounts have been recorded in our December 31, 20152018 or 20142017 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.
Compliance Orders from the New Mexico Environmental Department
Regency received a Notice of Violation from the New Mexico Environmental Department on September 23, 2015 for allegations of violations of New Mexico air regulations related to Jal #3. The Partnership has accrued $250,000 related to the claims and will continue to assess its potential exposure to the allegations as the matter progresses.
Lone Star NGL Fractionators Notice of Enforcement
Lone Star NGL Fractionators received a Notice of Enforcement from the Texas Commission on Environmental Quality on August 28, 2015 for allegations of violations of Texas air regulations related to Mont Belvieu Gas Plant. The Partnership has accrued $300,000 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, natural resource damages, 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.
TableIn February 2017, we received letters from the DOJ on behalf of ContentsEPA and LDEQ notifying SPLP and Mid-Valley that enforcement actions were being pursued for three separate crude oil releases: (a) an estimated 550 barrels released from the Colmesneil-to-Chester pipeline in Tyler County, Texas (“Colmesneil”) which allegedly occurred 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) which allegedly occurred in October of 2014; and (c) an estimated 40 barrels released from the Wakita 4-inch gathering line in Oklahoma which allegedly occurred in January of 2015. In January of 2019, an Consent Decree approved by all parties as well as an accompanying Complaint was filed in the United States District Court for the Western District of Louisiana seeking public comment and final court approval to resolve all penalties with DOJ and LDEQ for the three releases. The Consent Decree requires certain injunctive relief to be completed on the Longview-to-Mayersville pipeline within three years but the injunctive relief is not expected to have any material impact on operations. In addition to resolution of the civil penalty and injunctive relief, we continue to discuss natural resource damages with the Louisiana trustees.On January 3, 2018, PADEP issued an Administrative Order to SPLP 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
2017, during the construction of the project. SPLP 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 SPLP took an appeal of the Administrative Order to the Pennsylvania Environmental Hearing Board on February 2, 2018. On February 8, 2018, SPLP entered into a Consent Order and Agreement with PADEP that (i) withdraws the Administrative Order; (ii) establishes requirements for compliance with permits on a going forward basis; (iii) resolves the non-compliance alleged in the Administrative Order; and (iv) conditions restart of work on an agreement by SPLP to pay a $12.6 million civil penalty to the Commonwealth of Pennsylvania. In the Consent Order and agreement, SPLP 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 SPLP had adequately addressed the issues raised in the Administrative Order and demonstrated an ability to comply with the permits. SPLP 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: Certaincertain 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. Certaincertain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons. Currently operating Sunoco, Inc. retail sites.
Legacylegacy 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, 2015,2018, , Sunoco, Inc. had been named as a PRP at approximately 5041 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, | | 2015 | | 2014 | 2018 | | 2017 | Current | $ | 41 |
| | $ | 41 |
| $ | 42 |
| | $ | 35 |
| Non-current | 326 |
| | 360 |
| 295 |
| | 337 |
| Total environmental liabilities | $ | 367 |
| | $ | 401 |
| $ | 337 |
| | $ | 372 |
|
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, 20152018 and 2014,2017, the Partnership had $38recorded $48 million and $48$37 million, respectively, of expenditures related to environmental cleanup programs. On December 2, 2010, Sunoco, Inc. entered an Asset Sale and Purchase Agreement to sell the Toledo Refinery to Toledo Refining Company LLC (TRC) wherein Sunoco, Inc. retained certain liabilities associated with the pre-Closing time period. On January 2, 2013, USEPA issued a Finding of Violation (FOV) to TRC and, on September 30, 2013, EPA issued an NOV/FOV to TRC alleging Clean Air Act violations. To date, EPA has not issued an FOV or NOV/FOV to Sunoco, Inc. directly but some of EPA’s claims relate to the time period that Sunoco, Inc. operated the refinery. Specifically, EPA has claimed that the refinery flares were not operated in a manner consistent with good air pollution control practice for minimizing emissions and/or in conformance with their design, and that Sunoco, Inc. submitted semi-annual compliance reports in 2010 and 2011 and EPA that failed to include all of the information required by the regulations. EPA has proposed penalties in excess of $200,000 to resolve the allegations and discussions continue between the parties. The timing or outcome of this matter cannot be reasonably determined at this time, however, we do not expect there to be a material impact to its results of operations, cash flows or financial position.
Our pipeline operations are subject to regulation by the U.S.United States Department of Transportation under the PHMSA,Pipeline Hazardous Materials Safety Administration (“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’sthe 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. The following disclosures discuss the Partnership’s revised revenue recognition policies upon the adoption of ASU 2014-09 on January 1, 2018, as discussed in Note 1. These policies were applied to the current period only, and the amounts reflected in the Partnership’s consolidated financial statements for the years ended December 31, 2017 and 2016 were recorded under the Partnership’s previous accounting policies. Disaggregation of revenue The major types of revenue within our reportable segment, are as follows: •intrastate transportation and storage; •interstate transportation and storage; •midstream; •NGL and refined products transportation and services; •crude oil transportation and services; •investment in Sunoco LP; fuel distribution and marketing; all other; •investment in USAC; contract operations; retail parts and services; and •all other. Note 16 depicts the disaggregation of revenue by segment, with revenue amounts reflected in accordance with ASC Topic 606 for 2018 and ASC Topic 605 for 2017 and 2016. Intrastate transportation and storage revenue Our intrastate transportation and storage segment’s revenues are determined primarily by the volume of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines or that is injected or withdrawn into or out of our storage facilities. Firm transportation and storage contracts require customers to pay certain minimum fixed
fees regardless of the volume of commodity they transport or store. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected/withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject/withdraw into or out of our storage facilities. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Interstate transportation and storage revenue Our interstate transportation and storage segment’s revenues 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 or that is injected into or withdrawn out of our storage facilities. Our interstate transportation and storage segment’s contracts can be firm or interruptible. Firm transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity transported or stored. In exchange for such fees, we must stand ready to perform a contractually agreed-upon minimum volume of services whenever the customer requests such services. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected or withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject into or withdraw out of our storage facilities. Consequently, we are not required to stand ready to provide any contractually agreed-upon volume of service, but instead provides the services based on existing capacity at the time the customer requests the services. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of services, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Lake Charles LNG’s revenues are primarily derived from terminalling services for shippers by receiving LNG at the facility for storage and delivering such LNG to shippers, either in liquid state or gaseous state after regasification. Lake Charles LNG derives all of its revenue from a series of long term contracts with a wholly-owned subsidiary of Royal Dutch Shell plc (“Shell”). Terminalling revenue is generated from fees paid by Shell for storage and other associated services at the terminal. Payment for services under these contracts are typically due the month after the services have been performed. The terminalling agreements are considered to be firm agreements, because they include fixed fee components that are charged regardless of the volumes transported by Shell or services provided at the terminal. The performance obligation with respect to firm contracts is a promise to provide a single type of service (terminalling) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously
receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. Midstream revenue Our midstream segment’s revenues are derived primarily from margins we earn for natural gas volumes that are gathered, processed, and/or transported for our customers. The various types of revenue contracts our midstream segment enters into include: Fixed fee gathering and processing: Contracts under which we provide gathering and processing services in exchange for a fixed cash fee per unit of volume. Revenue for cash fees is recognized when the service is performed. Keepwhole: Contracts under which we gather raw natural gas from a third party producer, process the gas to convert it to pipeline quality natural gas, and redeliver to the producer a thermal-equivalent volume of pipeline quality natural gas. In exchange for these services, we retain the NGLs extracted from the raw natural gas received from the producer as well as cash fees paid by the producer. The value of NGLs retained as well as cash fees is recognized as revenue when the services are performed. Percent of Proceeds (“POP”): Contracts under which we provide gathering and processing services in exchange for a specified percentage of the producer’s commodity (“POP percentage”) and also in some cases additional cash fees. The two types of POP revenue contracts are described below: In-Kind POP: We retain our POP percentage (non-cash consideration) and also any additional cash fees in exchange for providing the services. We recognize revenue for the non-cash consideration and cash fees at the time the services are performed. Mixed POP: We purchase NGLs from the producer and retain a portion of the residue gas as non-cash consideration for services provided. We may also receive cash fees for such services. Under Topic 606, these agreements were determined to be hybrid agreements which were partially supply agreements (for the NGLs we purchased) and customer agreements (for the services provided related to the product that was returned to the customer). Given that these are hybrid agreements, we split the cash and non-cash consideration between revenue and a reduction of costs based on the value of the service provided vs. the value of the supply received. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligations with respect to our midstream segment’s contracts are to provide gathering, transportation and processing services, each of which would be completed on or about the same time, and each of which would be recognized on the same line item on the income statement, therefore identification of separate performance obligations would not impact the timing or geography of revenue recognition. Certain contracts of our midstream segment include throughput commitments under which customers commit to purchasing a certain minimum volume of service over a specified time period. If such volume of service is not purchased by the customer, deficiency fees are billed to the customer. In some cases, the customer is allowed to apply any deficiency fees paid to future purchases of services. In such cases, we defer revenue recognition until the customer uses the deficiency fees for services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints. NGL and refined products transportation and services revenue Our NGL and refined products segment’s revenues are primarily derived from transportation, fractionation, blending, and storage of NGL and refined products as well as acquisition and marketing activities. Revenues are generated utilizing a complementary network of pipelines, storage and blending facilities, and strategic off-take locations that provide access to multiple NGL markets. Transportation, fractionation, and storage revenue is generated from fees charged to customers under a combination of firm and interruptible contracts. Firm contracts are in the form of take-or-pay arrangements where certain fees will be charged to customers regardless of the volume of service they request for any given period. Under interruptible contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of service provided for any given period. Payment for services under these contracts are typically due the month after the services have been performed. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation, fractionation, blending, or storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination
are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of services, but such promise is made on a case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Acquisition and marketing contracts are in most cases short-term agreements involving purchase and/or sale of NGLs and other related hydrocarbons at market rates. These contracts were not affected by ASC 606. Crude oil transportation and services revenue Our crude oil transportation and service segment are primarily derived from provide transportation, terminalling and acquisition and marketing services to crude oil markets throughout the southwest, midwest and northeastern United States. Crude oil transportation revenue is generated from tariffs paid by shippers utilizing our transportation services and is generally recognized as the related transportation services are provided. Crude oil terminalling revenue is generated from fees paid by customers for storage and other associated services at the terminal. Crude oil acquisition and marketing revenue is generated from sale of crude oil acquired from a variety of suppliers to third parties. Payment for services under these contracts are typically due the month after the services have been performed. Certain transportation and terminalling agreements are considered to be firm agreements, because they include fixed fee components that are charged regardless of the volume of crude oil transported by the customer or services provided at the terminal. For these agreements, any fixed fees billed in excess of services provided are not recognized as revenue until the earlier of (i) the time at which the customer applies the fees against cost of service provided in a later period, or (ii) the customer becomes unable to apply the fees against cost of future service due to capacity constraints or contractual terms. The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or terminalling) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is performed. The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a case-by-case basis at the time the customer requests the service and/or product and we accept the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed. Acquisition and marketing contracts are in most cases short-term agreements involving purchase and/or sale of crude oil at market rates. These contracts were not affected by ASC 606. Sunoco LP’s fuel distribution and marketing revenue Sunoco LP’s fuel distribution and marketing operations earn revenue from the following channels: sales to Dealers, sales to Distributors, Unbranded Wholesale Revenue, Commission Agent Revenue, Rental Income and Other Income. Motor fuel revenue consists primarily of the sale of motor fuel under supply agreements with third party customers and affiliates. Fuel supply contracts with Sunoco LP’s customers generally provide that Sunoco LP distribute motor fuel at a formula price based on published rates, volume-based profit margin, and other terms specific to the agreement. The customer is invoiced the agreed-upon price with most payment terms ranging less than 30 days. If the consideration promised in a contract includes a variable amount, Sunoco LP estimates the variable consideration amount and factors in such an estimate to determine the transaction price under the expected value method. Revenue is recognized under the motor fuel contracts at the point in time the customer takes control of the fuel. At the time control is transferred to the customer the sale is considered final, because the agreements do not grant customers the right to return motor fuel. Under the new standard, to determine when control transfers to the customer, the shipping terms of the contract are assessed as shipping terms are considered a primary indicator of the transfer of control. For FOB shipping point terms, revenue is recognized at the time of shipment. The performance obligation with respect to the sale of goods is satisfied
at the time of shipment since the customer gains control at this time under the terms. Shipping and/or handling costs that occur before the customer obtains control of the goods are deemed to be fulfillment activities and are accounted for as fulfillment costs. Once the goods are shipped, Sunoco LP is precluded from redirecting the shipment to another customer and revenue is recognized. Commission agent revenue consists of sales from commission agent agreements between Sunoco LP and select operators. Sunoco LP supplies motor fuel to sites operated by commission agents and sells the fuel directly to the end customer. In commission agent arrangements, control of the product is transferred at the point in time when the goods are sold to the end customer. To reflect the transfer of control, Sunoco LP recognizes commission agent revenue at the point in time fuel is sold to the end customer. Sunoco LP receives rental income from leased or subleased properties. Revenue from leasing arrangements for which Sunoco LP is the lessor are recognized ratably over the term of the underlying lease. Sunoco LP’s all other revenue Sunoco LP’s all other operations earn revenue from the following channels: Motor Fuel Sales, Rental Income and Other Income. Motor Fuel Sales consist of fuel sales to consumers at company-operated retail stores. Other income includes merchandise revenue that comprises the in-store merchandise and food service sales at company-operated retail stores, and other revenue that represents a variety of other services within Sunoco LP’s all other operations including credit card processing, car washes, lottery, automated teller machines, money orders, prepaid phone cards and wireless services. Revenue from all other operations is recognized when (or as) the performance obligations are satisfied (i.e. when the customer obtains control of the good or the service is provided). USAC’s contract operations revenue USAC’s revenue from contracted compression, station, gas treating and maintenance services is recognized ratably under its fixed-fee contracts over the term of the contract as services are provided to its customers. Initial contract terms typically range from six months to five years, however USAC usually continues to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-to-month or longer basis. USAC primarily enters into fixed-fee contracts whereby its customers are required to pay the monthly fee even during periods of limited or disrupted throughput. Services are generally billed monthly, one month in advance of the commencement of the service month, except for certain customers who are billed at the beginning of the service month, and payment is generally due 30 days after receipt of the invoice. Amounts invoiced in advance are recorded as deferred revenue until earned, at which time they are recognized as revenue. The amount of consideration USAC receives and revenue it recognizes is based upon the fixed fee rate stated in each service contract.
Variable consideration exists in select contracts when billing rates vary based on actual equipment availability or volume of total installed horsepower. USAC’s contracts with customers may include multiple performance obligations. For such arrangements, USAC allocates revenues to each performance obligation based on its relative standalone service fee. USAC generally determine standalone service fees based on the service fees charged to customers or using expected cost plus margin. The majority of USAC’s service performance obligations are satisfied over time as services are rendered at selected customer locations on a monthly basis and based upon specific performance criteria identified in the applicable contract. The monthly service for each location is substantially the same service month to month and is promised consecutively over the service contract term. USAC measures progress and performance of the service consistently using a straight-line, time-based method as each month passes, because its performance obligations are satisfied evenly over the contract term as the customer simultaneously receives and consumes the benefits provided by its service. If variable consideration exists, it is allocated to the distinct monthly service within the series to which such variable consideration relates. USAC has elected to apply the invoicing practical expedient to recognize revenue for such variable consideration, as the invoice corresponds directly to the value transferred to the customer based on its performance completed to date. There are typically no material obligations for returns or refunds. USAC’s standard contracts do not usually include material non-cash consideration. USAC’s retail parts and services revenue USAC’s retail parts and service revenue is earned primarily on freight and crane charges that are directly reimbursable by USAC’s customers and maintenance work on units at its customers’ locations that are outside the scope of its core maintenance
activities. Revenue from retail parts and services is recognized at the point in time the part is transferred or service is provided and control is transferred to the customer. At such time, the customer has the ability to direct the use of the benefits of such part or service after USAC has performed its services. USAC bills upon completion of the service or transfer of the parts, and payment is generally due 30 days after receipt of the invoice. The amount of consideration USAC receives and revenue it recognizes is based upon the invoice amount. There are typically no material obligations for returns, refunds, or warranties. USAC’s standard contracts do not usually include material variable or non-cash consideration. All other revenue Our all other segment primarily includes our compression equipment business which provides full-service compression design and manufacturing services for the oil and gas industry. It also includes the management of coal and natural resources properties and the related collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities, and collecting oil and gas royalties. These operations also include end-user coal handling facilities. There were no material changes to the manner in which revenues within this segment are recorded under the new standard. Contract Balances with Customers The Partnership satisfies its obligations by transferring goods or services in exchange for consideration from customers. The timing of performance may differ from the timing the associated consideration is paid to or received from the customer, thus resulting in the recognition of a contract asset or a contract liability. The Partnership recognizes a contract asset when making upfront consideration payments to certain customers or when providing services to customers prior to the time at which the Partnership is contractually allowed to bill for such services. The Partnership recognizes a contract liability if the customer's payment of consideration precedes the Partnership’s fulfillment of the performance obligations. Certain contracts contain provisions requiring customers to pay a fixed fee for a right to use our assets, but allows customers to apply such fees against services to be provided at a future point in time. These amounts are reflected as deferred revenue until the customer applies the deficiency fees to services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints. Additionally, Sunoco LP maintains some franchise agreements requiring dealers to make one-time upfront payments for long term license agreements. Sunoco LP recognizes a contract liability when the upfront payment is received and recognizes revenue over the term of the license. As of December 31, 2018, the Partnership had $405 million in deferred revenues representing the current value of our future performance obligations. The amount of revenue recognized for the year ended December 31, 2018 that was included in the deferred revenue liability balance as of January 1, 2018 was $85 million. The balances of receivables from contracts with customers listed in the table below include both current trade receivables and long-term receivables, net of allowance for doubtful accounts. The allowance for receivables represents Sunoco LP’s best estimate of the probable losses associated with potential customer defaults. Sunoco LP determines the allowance based on historical experience and on a specific identification basis. The opening and closing balances of Sunoco LP’s contract assets and contract liabilities are as follows: | | | | | | | | | | | | | | Balance at January 1, 2018 | | Balance at December 31, 2018 | | Increase | Contract Balances | | | | | | Contract asset | $ | 51 |
| | $ | 75 |
| | $ | 24 |
| Accounts receivable from contracts with customers | 445 |
| | 347 |
| | (98 | ) | Contract liability | 1 |
| | 1 |
| | — |
|
Performance Obligations At contract inception, the Partnership assesses the goods and services promised in its contracts with customers and identifies a performance obligation for each promise to transfer a good or service (or bundle of goods or services) that is distinct. To identify the performance obligations, the Partnership considers all the goods or services promised in the contract, whether explicitly stated or implied based on customary business practices. For a contract that has more than one performance obligation, the Partnership allocates the total contract consideration it expects to be entitled to, to each distinct performance obligation
based on a standalone-selling price basis. Revenue is recognized when (or as) the performance obligations are satisfied, that is, when the customer obtains control of the good or service. Certain of our contracts contain variable components, which, when combined with the fixed component are considered a single performance obligation. For these types of contracts, only the fixed component of the contracts are included in the table below. Sunoco LP distributes fuel under long-term contracts to branded distributors, branded and unbranded third party dealers, and branded and unbranded retail fuel outlets. Sunoco LP branded supply contracts with distributors generally have both time and volume commitments that establish contract duration. These contracts have an initial term of approximately nine years, with an estimated, volume-weighted term remaining of approximately four years. As part of the asset purchase agreement with 7-Eleven, Sunoco LP and 7-Eleven and SEI Fuel (collectively, the “Distributor”) have entered into a 15-year take-or-pay fuel supply agreement in which the Distributor is required to purchase a volume of fuel that provides Sunoco LP a minimum amount of gross profit annually. Sunoco LP expects to recognize this revenue in accordance with the contract as Sunoco LP transfers control of the product to the customer. However, in case of annual shortfall Sunoco LP will recognize the amount payable by the Distributor at the sooner of the time at which the Distributor makes up the shortfall or becomes contractually or operationally unable to do so. The transaction price of the contract is variable in nature, fluctuating based on market conditions. The Partnership has elected to take the practical expedient not to estimate the amount of variable consideration allocated to wholly unsatisfied performance obligations. In some contractual arrangements, Sunoco LP grants dealers a franchise license to operate Sunoco LP’s retail stores over the life of a franchise agreement. In return for the grant of the retail store license, the dealer makes a one-time nonrefundable franchise fee payment to Sunoco LP plus sales based royalties payable to Sunoco LP at a contractual rate during the period of the franchise agreement. Under the requirements of ASC Topic 606, the franchise license is deemed to be a symbolic license for which recognition of revenue over time is the most appropriate measure of progress toward complete satisfaction of the performance obligation. Revenue from this symbolic license is recognized evenly over the life of the franchise agreement. As of December 31, 2018, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations is $42.35 billion and the Partnership expects to recognize this amount as revenue within the time bands illustrated below: | | | | | | | | | | | | | | | | | | | | | | | | Years Ending December 31, | | | | | | | 2019 | | 2020 | | 2021 | | Thereafter | | Total | Revenue expected to be recognized on contracts with customers existing as of December 31, 2018 | | $ | 5,529 |
| | $ | 4,955 |
| | $ | 4,413 |
| | $ | 27,452 |
| | $ | 42,349 |
|
Costs to Obtain or Fulfill a Contract Sunoco LP recognizes an asset from the costs incurred to obtain a contract (e.g. sales commissions) only if it expects to recover those costs. On the other hand, the costs to fulfill a contract are capitalized if the costs are specifically identifiable to a contract, would result in enhancing resources that will be used in satisfying performance obligations in future and are expected to be recovered. These capitalized costs are recorded as a part of Other Assets and are amortized on a systematic basis consistent with the pattern of transfer of the goods or services to which such costs relate. The amount of amortization expense that the Sunoco LP recognized for the year ended December 31, 2018 was $14 million. Sunoco LP has also made a policy election of expensing the costs to obtain a contract, as and when they are incurred, in cases where the expected amortization period is one year or less. Practical Expedients Utilized by the Partnership The Partnership elected the following practical expedients in accordance with Topic 606: Right to invoice: The Partnership elected to utilize an output method to recognize revenue that is based on the amount to which the Partnership has a right to invoice a customer for services performed to date, if that amount corresponds directly with the value provided to the customer for the related performance or its obligation completed to date. As such, the Partnership recognized revenue in the amount to which it had the right to invoice customers. Significant financing component: The Partnership elected not to adjust the promised amount of consideration for the effects of significant financing component if the Partnership expects, at contract inception, that the period between the transfer of a promised good or service to a customer and when the customer pays for that good or service will be one year or less.
Unearned variable consideration: The Partnership elected to only disclose the unearned fixed consideration associated with unsatisfied performance obligations related to our various customer contracts which contain both fixed and variable components. Incremental costs of obtaining a contract: The Partnership generally expenses sales commissions when incurred because the amortization period would have been less than one year. We record these costs within general and administrative expenses. The Partnership elected to expense the incremental costs of obtaining a contract when the amortization period for such contracts would have been one year or less. Shipping and handling costs:The Partnership elected to account for shipping and handling activities that occur after the customer has obtained control of a good as fulfillment activities (i.e., an expense) rather than as a promised service. Measurement of transaction price: The Partnership has elected to exclude from the measurement of transaction price all taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction and collected by the Partnership from a customer (i.e., sales tax, value added tax, etc.). Variable consideration of wholly unsatisfied performance obligations:The Partnership has elected to exclude the estimate of variable consideration to the allocation of wholly unsatisfied performance obligations. | | 13. | DERIVATIVE ASSETS AND LIABILITIES: |
Commodity Price Risk We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets. We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge inception, we lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract. Changes in the spreads between the forward natural gas prices and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized. We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage segment and operational gas sales on our interstate transportation and storage segment. These contracts are not designated as hedges for accounting purposes. We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream segment whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes. We use derivativesutilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in our liquids transportationthe price of refined products and services segmentNGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes. Sunoco Logistics utilizes swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs. 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 segment.sales. 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, 2015 | | December 31, 2014 | December 31, 2018 | | December 31, 2017 | | 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 | (602,500 | ) | | 2016-2017 | | (232,500 | ) | | 2015 | 468 |
| | 2019 | | 1,078 |
| | 2018 | Basis Swaps IFERC/NYMEX(1) | (31,240,000 | ) | | 2016-2017 | | (13,907,500 | ) | | 2015-2016 | 16,845 |
| | 2019-2020 | | 48,510 |
| | 2018-2020 | Options – Calls | — |
| | — | | 5,000,000 |
| | 2015 | | Options – Puts | | 10,000 |
| | 2019 | | 13,000 |
| | 2018 | Power (Megawatt): | | | | | | | | | Forwards | 357,092 |
| | 2016-2017 | | 288,775 |
| | 2015 | 3,141,520 |
| | 2019 | | 435,960 |
| | 2018-2019 | Futures | (109,791 | ) | | 2016 | | (156,000 | ) | | 2015 | 56,656 |
| | 2019-2021 | | (25,760 | ) | | 2018 | Options – Puts | 260,534 |
| | 2016 | | (72,000 | ) | | 2015 | 18,400 |
| | 2019 | | (153,600 | ) | | 2018 | Options – Calls | 1,300,647 |
| | 2016 | | 198,556 |
| | 2015 | 284,800 |
| | 2019 | | 137,600 |
| | 2018 | Crude (Bbls) – Futures | (591,000 | ) | | 2016-2017 | | — |
| | — | | (Non-Trading) | | | | | | | | | Natural Gas (MMBtu): | | | | | | Natural Gas (BBtu): | | | | | | Basis Swaps IFERC/NYMEX | (6,522,500 | ) | | 2016-2017 | | 57,500 |
| | 2015 | (30,228 | ) | | 2019-2021 | | 4,650 |
| | 2018-2020 | Swing Swaps IFERC | 71,340,000 |
| | 2016-2017 | | 46,150,000 |
| | 2015 | 54,158 |
| | 2019-2020 | | 87,253 |
| | 2018-2019 | Fixed Swaps/Futures | (14,380,000 | ) | | 2016-2018 | | (34,304,000 | ) | | 2015-2016 | (1,068 | ) | | 2019-2021 | | (4,390 | ) | | 2018-2019 | Forward Physical Contracts | 21,922,484 |
| | 2016-2017 | | (9,116,777 | ) | | 2015 | (123,254 | ) | | 2019-2020 | | (145,105 | ) | | 2018-2020 | Natural Gas Liquid (Bbls) – Forwards/Swaps | (8,146,800 | ) | | 2016-2018 | | (4,417,400 | ) | | 2015 | | Refined Products (Bbls) – Futures | (993,000 | ) | | 2016-2017 | | 13,745,755 |
| | 2015 | | Corn (Bushels) – Futures | 1,185,000 |
| | 2016 | | — |
| | — | | NGL (MBbls) – Forwards/Swaps | | (2,135 | ) | | 2019 | | (2,493 | ) | | 2018-2019 | Crude (MBbls) – Forwards/Swaps | | 20,888 |
| | 2019 | | 9,237 |
| | 2018-2019 | Refined Products (MBbls) – Futures | | (1,403 | ) | | 2019 | | (3,901 | ) | | 2018-2019 | Corn (thousand bushels) | | (1,920 | ) | | 2019 | | 1,870 |
| | 2018 | Fair Value Hedging Derivatives | | | | | | | | | (Non-Trading) | | | | | | | | | Natural Gas (MMBtu): | | | | | | Natural Gas (BBtu): | | | | | | Basis Swaps IFERC/NYMEX | (37,555,000 | ) | | 2016 | | (39,287,500 | ) | | 2015 | (17,445 | ) | | 2019 | | (39,770 | ) | | 2018 | Fixed Swaps/Futures | (37,555,000 | ) | | 2016 | | (39,287,500 | ) | | 2015 | (17,445 | ) | | 2019 | | (39,770 | ) | | 2018 | Hedged Item – Inventory | 37,555,000 |
| | 2016 | | 39,287,500 |
| | 2015 | 17,445 |
| | 2019 | | 39,770 |
| | 2018 |
| | (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 including forward-startingto achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock-inlock in the rate on a portion of our anticipated debt issuances.
The following table summarizes our interest rate swaps outstanding, none of which wereare designated as hedges for accounting purposes: | | | | | | | | | | | | Term | | Type(1) | | Notional Amount Outstanding | December 31, 2015 | | December 31, 2014 | July 2015(2) | | Forward-starting to pay a fixed rate of 3.38% and receive a floating rate | | $ | — |
| | $ | 200 |
| July 2016(3) | | Forward-starting to pay a fixed rate of 3.80% and receive a floating rate | | 200 |
| | 200 |
| July 2017(4) | | Forward-starting to pay a fixed rate of 3.84% and receive a floating rate | | 300 |
| | 300 |
| July 2018(4) | | Forward-starting to pay a fixed rate of 4.00% and receive a floating rate | | 200 |
| | 200 |
| July 2019(4) | | Forward-starting to pay a fixed rate of 3.25% and receive a floating rate | | 200 |
| | 300 |
| December 2018 | | Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% | | 1,200 |
| | — |
| March 2019 | | Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% | | 300 |
| | — |
| February 2023 | | Pay a floating rate plus a spread of 1.73% and receive a fixed rate of 3.60% | | — |
| | 200 |
|
| | | | | | | | | | | | Term | | Type (1) | | Notional Amount Outstanding | December 31, 2018 | | December 31, 2017 | July 2018 (2) | | Forward-starting to pay a fixed rate of 3.76% and receive a floating rate | | $ | — |
| | $ | 300 |
| July 2019 (2) | | Forward-starting to pay a fixed rate of 3.56% and receive a floating rate | | 400 |
| | 300 |
| July 2020 (2) | | Forward-starting to pay a fixed rate of 3.52% and receive a floating rate | | 400 |
| | 400 |
| July 2021 (2) | | Forward-starting to pay a fixed rate of 3.55% and receive a floating rate | | 400 |
| | — |
| December 2018 | | Pay a floating rate and receive a fixed rate of 1.53% | | — |
| | 1,200 |
| March 2019 | | Pay a floating rate and receive a fixed rate of 1.42% | | 300 |
| | 300 |
|
| | (1) | Floating rates are based on 3-month LIBOR. |
| | (2) | Represents the effective date. These forward-starting swaps have terms of 10 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 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,industrial end-users, 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 with independent system operators and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on or about the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets.
For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.
Derivative Summary The following table provides a summary of our derivative assets and liabilities: | | | Fair Value of Derivative Instruments | Fair Value of Derivative Instruments | | Asset Derivatives | | Liability Derivatives | Asset Derivatives | | Liability Derivatives | | December 31, 2015 | | December 31, 2014 | | December 31, 2015 | | December 31, 2014 | December 31, 2018 | | December 31, 2017 | | December 31, 2018 | | December 31, 2017 | Derivatives designated as hedging instruments: | | | | | | | | | | | | | | | Commodity derivatives (margin deposits) | $ | 38 |
| | $ | 43 |
| | $ | (3 | ) | | $ | — |
| $ | — |
| | $ | 14 |
| | $ | (13 | ) | | $ | (2 | ) | | 38 |
| | 43 |
| | (3 | ) | | — |
| — |
| | 14 |
| | (13 | ) | | (2 | ) | Derivatives not designated as hedging instruments: | | | | | | | | | | | | | | | Commodity derivatives (margin deposits) | 353 |
| | 617 |
| | (306 | ) | | (577 | ) | 402 |
| | 262 |
| | (397 | ) | | (281 | ) | Commodity derivatives | 57 |
| | 107 |
| | (41 | ) | | (23 | ) | 158 |
| | 45 |
| | (173 | ) | | (58 | ) | Interest rate derivatives | — |
| | 3 |
| | (171 | ) | | (155 | ) | — |
| | — |
| | (163 | ) | | (219 | ) | Embedded derivatives in ETP Preferred Units | — |
| | — |
| | (5 | ) | | (16 | ) | | | 410 |
| | 727 |
| | (523 | ) | | (771 | ) | 560 |
| | 307 |
| | (733 | ) | | (558 | ) | Total derivatives | $ | 448 |
| | $ | 770 |
| | $ | (526 | ) | | $ | (771 | ) | $ | 560 |
| | $ | 321 |
| | $ | (746 | ) | | $ | (560 | ) |
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, 2015 | | December 31, 2014 | | December 31, 2015 | | December 31, 2014 | | Balance Sheet Location | | December 31, 2018 | | December 31, 2017 | | December 31, 2018 | | December 31, 2017 | Derivatives without offsetting agreements | | Derivative assets (liabilities) | | $ | — |
| | $ | 3 |
| | $ | (176 | ) | | $ | (171 | ) | | Derivative liabilities | | $ | — |
| | $ | — |
| | $ | (163 | ) | | $ | (219 | ) | Derivatives in offsetting agreements: | Derivatives in offsetting agreements: | | | | | | | | | Derivatives in offsetting agreements: | | | | | | | | | OTC contracts | | Derivative assets (liabilities) | | 57 |
| | 107 |
| | (41 | ) | | (23 | ) | | Derivative assets (liabilities) | | 158 |
| | 45 |
| | (173 | ) | | (58 | ) | Broker cleared derivative contracts | | Other current assets | | 391 |
| | 660 |
| | (309 | ) | | (577 | ) | | Other current assets (liabilities) | | 402 |
| | 276 |
| | (410 | ) | | (283 | ) | | | | 448 |
| | 770 |
| | (526 | ) | | (771 | ) | | | 560 |
| | 321 |
| | (746 | ) | | (560 | ) | Offsetting agreements: | Offsetting agreements: | | | | | | | | | Offsetting agreements: | | | | | | | | | Counterparty netting | | Derivative assets (liabilities) | | (17 | ) | | (19 | ) | | 17 |
| | 19 |
| | Derivative assets (liabilities) | | (47 | ) | | (21 | ) | | 47 |
| | 21 |
| Payments on margin deposit | | Other current assets | | (309 | ) | | (577 | ) | | 309 |
| | 577 |
| | Counterparty netting | | | Other current assets (liabilities) | | (397 | ) | | (263 | ) | | 397 |
| | 263 |
| Total net derivatives | Total net derivatives | | $ | 122 |
| | $ | 174 |
| | $ | (200 | ) | | $ | (175 | ) | Total net derivatives | | $ | 116 |
| | $ | 37 |
| | $ | (302 | ) | | $ | (276 | ) |
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: | | | | | | | | | | | | | | Change in Value Recognized in OCI on Derivatives (Effective Portion) | | Years Ended December 31, | | 2015 | | 2014 | | 2013 | Derivatives in cash flow hedging relationships: | | | | | | Commodity derivatives | $ | — |
| | $ | — |
| | $ | (1 | ) | Total | $ | — |
| | $ | — |
| | $ | (1 | ) |
| | | | | | | | | | | | | | | | 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, | | | | 2018 | | 2017 | | 2016 | Derivatives in fair value hedging relationships (including hedged item): | | | | | | | | Commodity derivatives | Cost of products sold | | $ | (3 | ) | | $ | 26 |
| | $ | 14 |
|
| | | | | | | | | | | | | | | | 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, | | | | 2015 | | 2014 | | 2013 | Derivatives in cash flow hedging relationships: | | | | | | | | Commodity derivatives | Cost of products sold | | $ | — |
| | $ | (3 | ) | | $ | 4 |
| Total | | | $ | — |
| | $ | (3 | ) | | $ | 4 |
|
| | | | | | | | | | | | | | | | 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, | | | | 2015 | | 2014 | | 2013 | Derivatives in fair value hedging relationships (including hedged item): | | | | | | | | Commodity derivatives | Cost of products sold | | $ | 21 |
| | $ | (8 | ) | | $ | 8 |
| Total | | | $ | 21 |
| | $ | (8 | ) | | $ | 8 |
|
| | | Location of Gain/(Loss) Recognized in Income on Derivatives | | Amount of Gain (Loss) Recognized in Income on Derivatives | Location of Gain (Loss) Recognized in Income on Derivatives | | Amount of Gain (Loss) Recognized in Income on Derivatives | | | Years Ended December 31, | | Years Ended December 31, | | | 2015 | | 2014 | | 2013 | | 2018 | | 2017 | | 2016 | Derivatives not designated as hedging instruments: | | | | | | | | | | | | | Commodity derivatives – Trading | Cost of products sold | | $ | (11 | ) | | $ | (6 | ) | | $ | (11 | ) | Cost of products sold | | $ | 32 |
| | $ | 31 |
| | $ | (35 | ) | Commodity derivatives – Non-trading | Cost of products sold | | 23 |
| | 199 |
| | (21 | ) | Cost of products sold | | (102 | ) | | 5 |
| | (177 | ) | Commodity contracts – Non-trading | Deferred gas purchases | | — |
| | — |
| | (3 | ) | | Interest rate derivatives | Gains (losses) on interest rate derivatives | | (18 | ) | | (157 | ) | | 44 |
| Gains (losses) on interest rate derivatives | | 47 |
| | (37 | ) | | (12 | ) | Embedded derivatives | Other, net | | 12 |
| | 3 |
| | 6 |
| Other, net | | — |
| | 1 |
| | 4 |
| Total | | $ | 6 |
| | $ | 39 |
| | $ | 15 |
| | $ | (23 | ) | | $ | — |
| | $ | (220 | ) |
| | 13.14. | 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.employees, including those of ETO, Lake Charles LNG, Sunoco LP and USAC. Employer matching contributions are calculated using a formula based on employee contributions. We and our subsidiaries made matching contributions of $39$62 million, $50$59 million and $45$65 million to these 401(k) savings plans for the years ended December 31, 2015, 2014,2018, 2017 and 20132016, respectively. Pension and Other Postretirement Benefit Plans Panhandle Postretirement benefits expense for the years ended December 31, 20152018, 2017, and 20142016 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. Effective January 1, 2018, the plan was amended to extend coverage to a new closed group of former employees based on certain criteria. 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, 2015 | | December 31, 2014 | December 31, 2018 | | December 31, 2017 | | 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 | $ | 718 |
| | $ | 65 |
| | $ | 202 |
| | $ | 632 |
| | $ | 61 |
| | $ | 223 |
| $ | 1 |
| | $ | 47 |
| | $ | 156 |
| | $ | 18 |
| | $ | 51 |
| | $ | 166 |
| Service cost | | — |
| | — |
| | 1 |
| | — |
| | — |
| | — |
| Interest cost | 23 |
| | 2 |
| | 4 |
| | 28 |
| | 3 |
| | 5 |
| — |
| | 1 |
| | 5 |
| | 1 |
| | 1 |
| | 4 |
| Amendments | — |
| | — |
| | — |
| | — |
| | — |
| | 1 |
| — |
| | — |
| | 60 |
| | — |
| | — |
| | 7 |
| Benefits paid, net | (46 | ) | | (8 | ) | | (20 | ) | | (45 | ) | | (9 | ) | | (28 | ) | — |
| | (7 | ) | | (17 | ) | | (2 | ) | | (6 | ) | | (20 | ) | Actuarial (gain) loss and other | 16 |
| | (2 | ) | | (6 | ) | | 130 |
| | 10 |
| | 2 |
| — |
| | (4 | ) | | (7 | ) | | 2 |
| | 1 |
| | (1 | ) | Settlements | (691 | ) | | — |
| | — |
| | (27 | ) | | — |
| | — |
| — |
| | — |
| | — |
| | (18 | ) | | — |
| | — |
| Dispositions | — |
| | — |
| | — |
| | — |
| | — |
| | (1 | ) | | Benefit obligation at end of period | 20 |
| | 57 |
| | 180 |
| | 718 |
| | 65 |
| | 202 |
| 1 |
| | 37 |
| | 198 |
| | 1 |
| | 47 |
| | 156 |
| | | | | | | | | | | | | | | | | | | | | | | | Change in plan assets: | | | | | | | | | | | | | | | | | | | | | | | Fair value of plan assets at beginning of period | 598 |
| | — |
| | 265 |
| | 600 |
| | — |
| | 284 |
| 1 |
| | — |
| | 257 |
| | 12 |
| | — |
| | 256 |
| Return on plan assets and other | 16 |
| | — |
| | — |
| | 70 |
| | — |
| | 6 |
| — |
| | — |
| | (8 | ) | | 3 |
| | — |
| | 11 |
| Employer contributions | 138 |
| | — |
| | 8 |
| | — |
| | — |
| | 8 |
| — |
| | — |
| | 9 |
| | 6 |
| | — |
| | 10 |
| Benefits paid, net | (46 | ) | | — |
| | (20 | ) | | (45 | ) | | — |
| | (28 | ) | — |
| | — |
| | (17 | ) | | (2 | ) | | — |
| | (20 | ) | Settlements | (691 | ) | | — |
| | — |
| | (27 | ) | | — |
| | — |
| — |
| | — |
| | — |
| | (18 | ) | | — |
| | — |
| Dispositions | — |
| | — |
| | — |
| | — |
| | — |
| | (5 | ) | | Fair value of plan assets at end of period | 15 |
| | — |
| | 253 |
| | 598 |
| | — |
| | 265 |
| 1 |
| | — |
| | 241 |
| | 1 |
| | — |
| | 257 |
| | | | | | | | | | | | | | | | | | | | | | | | Amount underfunded (overfunded) at end of period | $ | 5 |
| | $ | 57 |
| | $ | (73 | ) | | $ | 120 |
| | $ | 65 |
| | $ | (63 | ) | $ | — |
| | $ | 37 |
| | $ | (43 | ) | | $ | — |
| | $ | 47 |
| | $ | (101 | ) | | | | | | | | | | | | | | | | | | | | | | | | Amounts recognized in the consolidated balance sheets consist of: | | | | | | | | | | | | | | | | | | | | | | | Non-current assets | $ | — |
| | $ | — |
| | $ | 97 |
| | $ | — |
| | $ | — |
| | $ | 90 |
| $ | — |
| | $ | — |
| | $ | 68 |
| | $ | — |
| | $ | — |
| | $ | 127 |
| Current liabilities | — |
| | (9 | ) | | (2 | ) | | — |
| | (9 | ) | | (2 | ) | — |
| | (6 | ) | | (2 | ) | | — |
| | (8 | ) | | (2 | ) | Non-current liabilities | (5 | ) | | (48 | ) | | (22 | ) | | (120 | ) | | (56 | ) | | (25 | ) | — |
| | (31 | ) | | (23 | ) | | — |
| | (39 | ) | | (24 | ) | | $ | (5 | ) | | $ | (57 | ) | | $ | 73 |
| | $ | (120 | ) | | $ | (65 | ) | | $ | 63 |
| $ | — |
| | $ | (37 | ) | | $ | 43 |
| | $ | — |
| | $ | (47 | ) | | $ | 101 |
| | | | | | | | | | | | | | | | | | | | | | | | Amounts recognized in accumulated other comprehensive income (loss) (pre-tax basis) consist of: | | | | | | | | | | | | | | | | | | | | | | | Net actuarial gain | $ | 2 |
| | $ | 4 |
| | $ | (17 | ) | | $ | 18 |
| | $ | 7 |
| | $ | (20 | ) | | Net actuarial gain (loss) | | $ | — |
| | $ | 1 |
| | $ | (7 | ) | | $ | — |
| | $ | 5 |
| | $ | (18 | ) | Prior service cost | — |
| | — |
| | 15 |
| | — |
| | — |
| | 17 |
| — |
| | — |
| | 66 |
| | — |
| | — |
| | 21 |
| | $ | 2 |
| | $ | 4 |
| | $ | (2 | ) | | $ | 18 |
| | $ | 7 |
| | $ | (3 | ) | $ | — |
| | $ | 1 |
| | $ | 59 |
| | $ | — |
| | $ | 5 |
| | $ | 3 |
|
The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets: | | | December 31, 2015 | | December 31, 2014 | December 31, 2018 | | December 31, 2017 | | 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 | $ | 20 |
| | $ | 57 |
| | N/A |
| | $ | 718 |
| | $ | 65 |
| | N/A |
| $ | — |
| | $ | 37 |
| | N/A |
| | $ | 1 |
| | $ | 47 |
| | N/A |
| Accumulated benefit obligation | 20 |
| | 57 |
| | $ | 180 |
| | 718 |
| | 65 |
| | $ | 202 |
| 1 |
| | 37 |
| | $ | 198 |
| | 1 |
| | 47 |
| | $ | 156 |
| Fair value of plan assets | 15 |
| | — |
| | 253 |
| | 598 |
| | — |
| | 265 |
| 1 |
| | — |
| | 241 |
| | 1 |
| | — |
| | 257 |
|
Components of Net Periodic Benefit Cost | | | December 31, 2015 | | December 31, 2014 | December 31, 2018 | | December 31, 2017 | | 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 | | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| Interest cost | $ | 25 |
| | $ | 4 |
| | $ | 31 |
| | $ | 5 |
| 1 |
| | 5 |
| | 2 |
| | 4 |
| Expected return on plan assets | (16 | ) | | (8 | ) | | (40 | ) | | (8 | ) | — |
| | (10 | ) | | — |
| | (9 | ) | Prior service cost amortization | — |
| | 1 |
| | — |
| | 1 |
| — |
| | 16 |
| | — |
| | 2 |
| Actuarial loss amortization | — |
| | — |
| | (1 | ) | | (1 | ) | | Settlements | 32 |
| | — |
| | (4 | ) | | — |
| | Net periodic benefit cost | $ | 41 |
| | $ | (3 | ) | | $ | (14 | ) | | $ | (3 | ) | $ | 1 |
| | $ | 12 |
| | $ | 2 |
| | $ | (3 | ) |
Assumptions The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below: | | | December 31, 2015 | | December 31, 2014 | December 31, 2018 | | December 31, 2017 | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Discount rate | 3.59 | % | | 2.38 | % | | 3.62 | % | | 2.24 | % | 4.02 | % | | 3.40 | % | | 3.27 | % | | 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, 2015 | | December 31, 2014 | December 31, 2018 | | December 31, 2017 | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Discount rate | 3.65 | % | | 2.79 | % | | 4.65 | % | | 3.02 | % | 3.52 | % | | 3.51 | % | | 3.52 | % | | 3.10 | % | Expected return on assets: | | | | | | | | | | | | | | | Tax exempt accounts | 7.50 | % | | 7.00 | % | | 7.50 | % | | 7.00 | % | 3.26 | % | | 6.63 | % | | 3.50 | % | | 7.00 | % | Taxable accounts | N/A |
| | 4.50 | % | | N/A |
| | 4.50 | % | N/A |
| | 4.50 | % | | N/A |
| | 4.50 | % | Rate of compensation increase | N/A |
| | N/A |
| | N/A |
| | N/A |
| N/A |
| | N/A |
| | N/A |
| | N/A |
|
The long-term expected rate of return on plan assets was estimated based on a variety of factors including the historical investment return achieved over a long-term period, the targeted allocation of plan assets and expectations concerning future returns in the marketplace for both equity and fixed income securities. Current market factors such as inflation and interest rates are evaluated before long-term market assumptions are determined. Peer data and historical returns are reviewed to ensure reasonableness and appropriateness. The assumed health care cost trend rates used to measure the expected cost of benefits covered by PanhandlePanhandle’s and Sunoco, Inc.’s other postretirement benefit plans are shown in the table below: | | | | December 31, | December 31, | | | 2015 | | 2014 | 2018 | | 2017 | Health care cost trend rate | | 7.16 | % | | 7.09 | % | 7.15 | % | | 7.20 | % | Rate to which the cost trend is assumed to decline (the ultimate trend rate) | | 5.39 | % | | 5.41 | % | 4.82 | % | | 4.99 | % | Year that the rate reaches the ultimate trend rate | | 2018 |
| | 2018 |
| 2024 |
| | 2023 |
|
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, 2015 Using Fair Value Hierarchy | | Fair Value as of December 31, 2015 | | Level 1 | | Level 2 | | Level 3 | Asset category: | | | | | | | | Mutual funds(1) | $ | 15 |
| | — |
| | 15 |
| | — |
| Total | $ | 15 |
| | $ | — |
| | $ | 15 |
| | $ | — |
|
| | | | | | | | | | | | | | | | | | | | | | Fair Value Measurements at December 31, 2018 | | | Fair Value Total | | Level 1 | | Level 2 | | Level 3 | Mutual funds (1) | | $ | 1 |
| | $ | 1 |
| | $ | — |
| | $ | — |
|
| | (1) | Comprised of 100% equities as of December 31, 2018. |
| | | | | | | | | | | | | | | | | | | | | | Fair Value Measurements at December 31, 2017 | | | Fair Value Total | | Level 1 | | Level 2 | | Level 3 | Mutual funds (1) | | $ | 1 |
| | $ | 1 |
| | $ | — |
| | $ | — |
|
| | (1) | Comprised of approximately 100% equities as of December 31, 2015.2017. |
| | | | | | | | | | | | | | | | | | | | 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 |
| | $ | — |
|
| | (1)
| Comprised of approximately 100% equities as of December 31, 2014. |
The fair value of other postretirement plan assets by asset category at the dates indicated is as follows: | | | | | Fair Value Measurements at December 31, 2015 Using Fair Value Hierarchy | | | Fair Value Measurements at December 31, 2018 | | Fair Value as of December 31, 2015 | | Level 1 | | Level 2 | | Level 3 | Fair Value Total | | Level 1 | | Level 2 | | Level 3 | Asset category: | | | | | | | | | | | | | | | Cash and cash equivalents | $ | 18 |
| | $ | 18 |
| | $ | — |
| | $ | — |
| $ | 20 |
| | $ | 20 |
| | $ | — |
| | $ | — |
| Mutual funds(1) | 133 |
| | 133 |
| | — |
| | — |
| 144 |
| | 144 |
| | — |
| | — |
| Fixed income securities | 102 |
| | — |
| | 102 |
| | — |
| 77 |
| | — |
| | 77 |
| | — |
| Total | $ | 253 |
| | $ | 151 |
| | $ | 102 |
| | $ | — |
| $ | 241 |
| | $ | 164 |
| | $ | 77 |
| | $ | — |
|
| | (1) | Primarily comprised of approximately 56%53% equities, 33%46% fixed income securities and 11%1% cash as of December 31, 2015.2018. |
| | | | | 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) | 131 |
| | 131 |
| | — |
| | — |
| 154 |
| | 154 |
| | — |
| | — |
| Fixed income securities | 125 |
| | — |
| | 125 |
| | — |
| 70 |
| | — |
| | 70 |
| | — |
| Total | $ | 265 |
| | $ | 140 |
| | $ | 125 |
| | $ | — |
| $ | 257 |
| | $ | 187 |
| | $ | 70 |
| | $ | — |
|
| | (1) | Primarily comprised of approximately 56%38% equities, 38%61% fixed income securities and 6%2% cash as of December 31, 2014.2017. |
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 $16$6 million to pension plans and $10 million to other postretirement plans in 2016.2019. 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) | 2016 | | $ | 20 |
| | $ | 9 |
| | $ | 21 |
| 2017 | | — |
| | 7 |
| | 20 |
| 2018 | | — |
| | 7 |
| | 19 |
| 2019 | | — |
| | 6 |
| | 17 |
| 2020 | | — |
| | 6 |
| | 16 |
| 2021 – 2025 | | — |
| | 2 |
| | 58 |
|
| | | | | | | | | | Years | | Pension Benefits - Unfunded Plans (1) | | Other Postretirement Benefits (Gross, Before Medicare Part D) | 2019 | | $ | 6 |
| | $ | 20 |
| 2020 | | 6 |
| | 20 |
| 2021 | | 5 |
| | 20 |
| 2022 | | 4 |
| | 18 |
| 2023 | | 4 |
| | 17 |
| 2024 – 2028 | | 12 |
| | 66 |
|
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. | | 14.15. | RELATED PARTY TRANSACTIONS: |
ETE has agreements with subsidiaries to provide or receive various generalIn June 2017, the Partnership acquired all of the publicly held PennTex common units through a tender offer and administrative services. ETE pays usexercise of a limited call right, as further discussed in Note 8.
ET previously paid ETO to provide services on its behalf and on behalf of other subsidiaries of ETE,ET, which includesincluded the reimbursement of various operating and general and administrative expenses incurred by usETO on behalf of ETEET and its subsidiaries. These agreements expired in 2016. In connection with the Lake Charles LNG Transaction, 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.
In January 2016, ETE and ETP agreed to extend the $95 million annual management fee paid to ETP through 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, | | 2015 | | 2014 | | 2013 | Affiliated revenues | $ | 417 |
| | $ | 965 |
| | $ | 1,442 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2018 | | 2017 | | 2016 | Affiliated revenues | $ | 431 |
| | $ | 303 |
| | $ | 221 |
|
The following table summarizes the related company balances on our consolidated balance sheets: | | | | | | | | | | December 31, | | 2015 | | 2014 | Accounts receivable from related companies: | | | | Sunoco LP | $ | 3 |
| | $ | — |
| ETE | 110 |
| | 11 |
| PES | 10 |
| | 6 |
| FGT | 13 |
| | 9 |
| Lake Charles LNG | 36 |
| | 3 |
| Trans-Pecos Pipeline, LLC | 29 |
| | — |
| Comanche Trail Pipeline, LLC | 22 |
| | — |
| Other | 45 |
| | 110 |
| Total accounts receivable from related companies | $ | 268 |
| | $ | 139 |
| | | | | Accounts payable to related companies: | | | | Sunoco LP | $ | 5 |
| | $ | — |
| FGT | 1 |
| | 2 |
| Lake Charles LNG | 3 |
| | 2 |
| Other | 16 |
| | 21 |
| Total accounts payable to related companies | $ | 25 |
| | $ | 25 |
|
| | | | | | | | | | December 31, | | 2018 | | 2017 | Accounts receivable from related companies: | | | | FGT | 25 |
| | 11 |
| Phillips 66 | 42 |
| | 20 |
| Other | 44 |
| | 22 |
| Total accounts receivable from related companies | $ | 111 |
| | $ | 53 |
|
As of December 31, 2018 and 2017, accounts payable with related companies in the Partnership’s consolidated balance sheets totaled $59 million and $31 million, respectively.
| | 15.16. | REPORTABLE SEGMENTS: |
Our financial statementsAs a result of the Energy Transfer Merger in October 2018, our reportable segments were reevaluated and currently reflect the following reportable segments, which conduct their business primarily in the United States, as follows:States:
•intrastate transportation and storage; •interstate transportation and storage; •midstream; •liquidsNGL and refined products transportation and services; •crude oil transportation and services; •investment in Sunoco Logistics;LP; •retail marketing;investment in USAC; and •all other. Intersegment and intrasegment transactions are generally based on transactions made at market-related rates. Consolidated revenues and expenses reflectThe investment in USAC segment reflects the eliminationresults of all material intercompany transactions.USAC beginning April 2018, the date that the Partnership obtained control of USAC.
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 marketinginvestment in Sunoco LP segment are primarily reflected in refined product sales. In connection with the Regency Merger, Regency’s operations were aggregated into ETP’s existing segments. Regency’s Revenues from our investment in USAC segment are primarily reflected in gathering, and processing operations were aggregated into our midstream segment. Regency’s natural gas transportation operations were aggregated into our intrastate transportation and storage and interstate transportation and storage segments. Regency’s contract services and natural resources operations were aggregated intoother fees. Revenues from our all other segment. Additionally,segment are primarily reflected in June 2015, Regency’s 30% equity interest in Lone Star was transferred to ETC OLP.natural gas 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, | | 2015 | | 2014 | | 2013 | Revenues: | | | | | | Intrastate transportation and storage: | | | | | | Revenues from external customers | $ | 1,912 |
| | $ | 2,645 |
| | $ | 2,242 |
| Intersegment revenues | 338 |
| | 212 |
| | 210 |
| | 2,250 |
| | 2,857 |
| | 2,452 |
| Interstate transportation and storage: | | | | | | Revenues from external customers | 1,008 |
| | 1,057 |
| | 1,270 |
| Intersegment revenues | 17 |
| | 15 |
| | 39 |
| | 1,025 |
| | 1,072 |
| | 1,309 |
| Midstream: | | | | | | Revenues from external customers | 2,622 |
| | 4,770 |
| | 3,220 |
| Intersegment revenues | 2,449 |
| | 2,053 |
| | 1,056 |
| | 5,071 |
| | 6,823 |
| | 4,276 |
| Liquids transportation and services: | | | | | | Revenues from external customers | 3,232 |
| | 3,730 |
| | 2,025 |
| Intersegment revenues | 249 |
| | 181 |
| | 101 |
| | 3,481 |
| | 3,911 |
| | 2,126 |
| Investment in Sunoco Logistics: | | | | | | Revenues from external customers | 10,302 |
| | 17,920 |
| | 16,480 |
| Intersegment revenues | 184 |
| | 168 |
| | 159 |
| | 10,486 |
| | 18,088 |
| | 16,639 |
| Retail marketing: | | | | | | Revenues from external customers | 12,478 |
| | 22,484 |
| | 21,004 |
| Intersegment revenues | 4 |
| | 3 |
| | 8 |
| | 12,482 |
| | 22,487 |
| | 21,012 |
| All other: | | | | | | Revenues from external customers | 2,738 |
| | 2,869 |
| | 2,094 |
| Intersegment revenues | 554 |
| | 462 |
| | 503 |
| | 3,292 |
| | 3,331 |
| | 2,597 |
| Eliminations | (3,795 | ) | | (3,094 | ) | | (2,076 | ) | Total revenues | $ | 34,292 |
| | $ | 55,475 |
| | $ | 48,335 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2018 | | 2017 | | 2016 | Revenues: | | | | | | Intrastate transportation and storage: | | | | | | Revenues from external customers | $ | 3,428 |
| | $ | 2,891 |
| | $ | 2,155 |
| Intersegment revenues | 309 |
| | 192 |
| | 458 |
| | 3,737 |
| | 3,083 |
| | 2,613 |
| Interstate transportation and storage: | | | | | | Revenues from external customers | 1,664 |
| | 1,112 |
| | 1,143 |
| Intersegment revenues | 18 |
| | 19 |
| | 23 |
| | 1,682 |
| | 1,131 |
| | 1,166 |
| Midstream: | | | | | | Revenues from external customers | 2,090 |
| | 2,510 |
| | 2,342 |
| Intersegment revenues | 5,432 |
| | 4,433 |
| | 2,837 |
| | 7,522 |
| | 6,943 |
| | 5,179 |
| NGL and refined products transportation and services: | | | | | | Revenues from external customers | 10,119 |
| | 7,885 |
| | 5,764 |
| Intersegment revenues | 1,004 |
| | 763 |
| | 645 |
| | 11,123 |
| | 8,648 |
| | 6,409 |
| Crude oil transportation and services: | | | | | | Revenues from external customers | 17,236 |
| | 11,672 |
| | 7,539 |
| Intersegment revenues | 96 |
| | 31 |
| | — |
| | 17,332 |
| | 11,703 |
| | 7,539 |
| Investment in Sunoco LP: | | | | | | Revenues from external customers | 16,982 |
| | 11,713 |
| | 9,977 |
| Intersegment revenues | 12 |
| | 10 |
| | 9 |
| | 16,994 |
| | 11,723 |
| | 9,986 |
| Investment in USAC: | | | | | | Revenues from external customers | 495 |
| | — |
| | — |
| Intersegment revenues | 13 |
| | — |
| | — |
| | 508 |
| | — |
| | — |
| All other: | | | | | | Revenues from external customers | 2,073 |
| | 2,740 |
| | 2,872 |
| Intersegment revenues | 155 |
| | 161 |
| | 400 |
| | 2,228 |
| | 2,901 |
| | 3,272 |
| Eliminations | (7,039 | ) | | (5,609 | ) | | (4,372 | ) | Total revenues | $ | 54,087 |
| | $ | 40,523 |
| | $ | 31,792 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2015 | | 2014 | | 2013 | Cost of products sold: | | | | | | Intrastate transportation and storage | $ | 1,554 |
| | $ | 2,169 |
| | $ | 1,737 |
| Midstream | 3,266 |
| | 4,893 |
| | 3,130 |
| Liquids transportation and services | 2,595 |
| | 3,166 |
| | 1,654 |
| Investment in Sunoco Logistics | 9,307 |
| | 17,135 |
| | 15,600 |
| Retail marketing | 11,174 |
| | 21,154 |
| | 20,150 |
| All other | 2,855 |
| | 2,975 |
| | 2,337 |
| Eliminations | (3,722 | ) | | (3,078 | ) | | (2,028 | ) | Total cost of products sold | $ | 27,029 |
| | $ | 48,414 |
| | $ | 42,580 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2015 | | 2014 | | 2013 | Depreciation, depletion and amortization: | | | | | | Intrastate transportation and storage | $ | 129 |
| | $ | 125 |
| | $ | 122 |
| Interstate transportation and storage | 210 |
| | 203 |
| | 244 |
| Midstream | 720 |
| | 569 |
| | 335 |
| Liquids transportation and services | 126 |
| | 113 |
| | 91 |
| Investment in Sunoco Logistics | 382 |
| | 296 |
| | 265 |
| Retail marketing | 190 |
| | 189 |
| | 114 |
| All other | 172 |
| | 174 |
| | 125 |
| Total depreciation, depletion and amortization | $ | 1,929 |
| | $ | 1,669 |
| | $ | 1,296 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2018 | | 2017 | | 2016 | Cost of products sold: | | | | | | Intrastate transportation and storage | $ | 2,665 |
| | $ | 2,327 |
| | $ | 1,897 |
| Midstream | 5,145 |
| | 4,761 |
| | 3,381 |
| NGL and refined products transportation and services | 8,462 |
| | 6,508 |
| | 4,553 |
| Crude oil transportation and services | 14,439 |
| | 9,826 |
| | 6,416 |
| Investment in Sunoco LP | 15,872 |
| | 10,615 |
| | 8,830 |
| Investment in USAC | 67 |
| | — |
| | — |
| All other | 2,006 |
| | 2,509 |
| | 2,942 |
| Eliminations | (6,998 | ) | | (5,580 | ) | | (4,326 | ) | Total cost of products sold | $ | 41,658 |
| | $ | 30,966 |
| | $ | 23,693 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2015 | | 2014 | | 2013 | Equity in earnings (losses) of unconsolidated affiliates: | | | | | | Intrastate transportation and storage | $ | 32 |
| | $ | 27 |
| | $ | 30 |
| Interstate transportation and storage | 197 |
| | 196 |
| | 182 |
| Midstream | (19 | ) | | 10 |
| | 1 |
| Liquids transportation and services | (2 | ) | | (3 | ) | | (2 | ) | Investment in Sunoco Logistics | 21 |
| | 23 |
| | 18 |
| Retail marketing | 194 |
| | 2 |
| | 2 |
| All other | 46 |
| | 77 |
| | 5 |
| Total equity in earnings of unconsolidated affiliates | $ | 469 |
| | $ | 332 |
| | $ | 236 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2015 | | 2014 | | 2013 | Segment Adjusted EBITDA: | | | | | | Intrastate transportation and storage | $ | 543 |
| | $ | 559 |
| | $ | 521 |
| Interstate transportation and storage | 1,155 |
| | 1,212 |
| | 1,368 |
| Midstream | 1,250 |
| | 1,318 |
| | 757 |
| Liquids transportation and services | 731 |
| | 591 |
| | 350 |
| Investment in Sunoco Logistics | 1,153 |
| | 971 |
| | 871 |
| Retail marketing | 583 |
| | 731 |
| | 325 |
| All other | 299 |
| | 328 |
| | 212 |
| Total Segment Adjusted EBITDA | 5,714 |
| | 5,710 |
| | 4,404 |
| Depreciation, depletion and amortization | (1,929 | ) | | (1,669 | ) | | (1,296 | ) | Interest expense, net of interest capitalized | (1,291 | ) | | (1,165 | ) | | (1,013 | ) | Gain on sale of AmeriGas common units | — |
| | 177 |
| | 87 |
| Impairment losses | (339 | ) | | (370 | ) | | (689 | ) | Gains (losses) on interest rate derivatives | (18 | ) | | (157 | ) | | 44 |
| Non-cash unit-based compensation expense | (79 | ) | | (68 | ) | | (54 | ) | Unrealized gains (losses) on commodity risk management activities | (65 | ) | | 112 |
| | 42 |
| Inventory valuation adjustments | (104 | ) | | (473 | ) | | 3 |
| Losses on extinguishments of debt | (43 | ) | | (25 | ) | | (7 | ) | Non-operating environmental remediation | — |
| | — |
| | (168 | ) | Adjusted EBITDA related to discontinued operations | — |
| | (27 | ) | | (76 | ) | Adjusted EBITDA related to unconsolidated affiliates | (937 | ) | | (748 | ) | | (722 | ) | Equity in earnings of unconsolidated affiliates | 469 |
| | 332 |
| | 236 |
| Other, net | 20 |
| | (36 | ) | | 19 |
| Income from continuing operations before income tax expense | $ | 1,398 |
| | $ | 1,593 |
| | $ | 810 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2018 | | 2017 | | 2016 | Depreciation, depletion and amortization: | | | | | | Intrastate transportation and storage | $ | 169 |
| | $ | 147 |
| | $ | 144 |
| Interstate transportation and storage | 334 |
| | 254 |
| | 246 |
| Midstream | 1,006 |
| | 954 |
| | 840 |
| NGL and refined products transportation and services | 466 |
| | 401 |
| | 355 |
| Crude oil transportation and services | 445 |
| | 402 |
| | 251 |
| Investment in Sunoco LP | 167 |
| | 169 |
| | 176 |
| Investment in USAC | 169 |
| | — |
| | — |
| All other | 103 |
| | 227 |
| | 204 |
| Total depreciation, depletion and amortization | $ | 2,859 |
| | $ | 2,554 |
| | $ | 2,216 |
|
| | | | | | | | | | | | | | December 31, | | 2015 | | 2014 | | 2013 | Assets: | | | | | | Intrastate transportation and storage | $ | 4,882 |
| | $ | 4,983 |
| | $ | 5,048 |
| Interstate transportation and storage | 11,345 |
| | 10,779 |
| | 11,537 |
| Midstream | 17,111 |
| | 15,562 |
| | 7,847 |
| Liquids transportation and services | 7,235 |
| | 4,568 |
| | 4,321 |
| Investment in Sunoco Logistics | 15,423 |
| | 13,619 |
| | 11,650 |
| Retail marketing | 3,218 |
| | 8,917 |
| | 3,936 |
| All other | 5,959 |
| | 4,090 |
| | 5,561 |
| Total assets | $ | 65,173 |
| | $ | 62,518 |
| | $ | 49,900 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2018 | | 2017 | | 2016 | Equity in earnings (losses) of unconsolidated affiliates: | | | | | | Intrastate transportation and storage | $ | 19 |
| | $ | (156 | ) | | $ | 35 |
| Interstate transportation and storage | 227 |
| | 236 |
| | 193 |
| Midstream | 26 |
| | 20 |
| | 19 |
| NGL and refined products transportation and services | 64 |
| | 33 |
| | 41 |
| Crude oil transportation and services | 6 |
| | 4 |
| | (4 | ) | All other | 2 |
| | 7 |
| | (14 | ) | Total equity in earnings of unconsolidated affiliates | $ | 344 |
| | $ | 144 |
| | $ | 270 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2015 | | 2014 | | 2013 | Additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (accrual basis): | | | | | | Intrastate transportation and storage | $ | 105 |
| | $ | 169 |
| | $ | 47 |
| Interstate transportation and storage | 860 |
| | 411 |
| | 152 |
| Midstream | 2,172 |
| | 1,298 |
| | 1,114 |
| Liquids transportation and services | 2,109 |
| | 427 |
| | 448 |
| Investment in Sunoco Logistics | 2,126 |
| | 2,510 |
| | 1,018 |
| Retail marketing | 412 |
| | 259 |
| | 176 |
| All other | 383 |
| | 420 |
| | 372 |
| Total additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (accrual basis) | $ | 8,167 |
| | $ | 5,494 |
| | $ | 3,327 |
|
| | | | | | | | | | | | | | December 31, | | 2015 | | 2014 | | 2013 | Advances to and investments in unconsolidated affiliates: | | | | | | Intrastate transportation and storage | $ | 406 |
| | $ | 423 |
| | $ | 443 |
| Interstate transportation and storage | 2,516 |
| | 2,649 |
| | 2,588 |
| Midstream | 117 |
| | 138 |
| | 36 |
| Liquids transportation and services | 32 |
| | 31 |
| | 29 |
| Investment in Sunoco Logistics | 247 |
| | 226 |
| | 125 |
| Retail marketing | 1,541 |
| | 19 |
| | 22 |
| All other | 144 |
| | 274 |
| | 807 |
| Total advances to and investments in unconsolidated affiliates | $ | 5,003 |
| | $ | 3,760 |
| | $ | 4,050 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2018 | | 2017 | | 2016 | Segment Adjusted EBITDA: | | | | | | Intrastate transportation and storage | $ | 927 |
| | $ | 626 |
| | $ | 613 |
| Interstate transportation and storage | 1,680 |
| | 1,274 |
| | 1,297 |
| Midstream | 1,627 |
| | 1,481 |
| | 1,133 |
| NGL and refined products transportation and services | 1,979 |
| | 1,641 |
| | 1,496 |
| Crude oil transportation and services | 2,330 |
| | 1,379 |
| | 834 |
| Investment in Sunoco LP | 638 |
| | 732 |
| | 665 |
| Investment in USAC | 289 |
| | — |
| | — |
| All Other | 40 |
| | 187 |
| | 97 |
| Total Segment Adjusted EBITDA | 9,510 |
| | 7,320 |
| | 6,135 |
| Depreciation, depletion and amortization | (2,859 | ) | | (2,554 | ) | | (2,216 | ) | Interest expense, net | (2,055 | ) | | (1,922 | ) | | (1,804 | ) | Gains on acquisitions | — |
| | — |
| | 83 |
| Impairment losses | (431 | ) | | (1,039 | ) | | (1,040 | ) | Gains (losses) on interest rate derivatives | 47 |
| | (37 | ) | | (12 | ) | Non-cash compensation expense | (105 | ) | | (99 | ) | | (70 | ) | Unrealized gains (losses) on commodity risk management activities | (11 | ) | | 59 |
| | (136 | ) | Inventory valuation adjustments | (85 | ) | | 24 |
| | 97 |
| Losses on extinguishments of debt | (112 | ) | | (89 | ) | | — |
| Adjusted EBITDA related to unconsolidated affiliates | (655 | ) | | (716 | ) | | (675 | ) | Equity in earnings of unconsolidated affiliates | 344 |
| | 144 |
| | 270 |
| Impairment of investments in unconsolidated affiliates | — |
| | (313 | ) | | (308 | ) | Adjusted EBITDA related to discontinued operations | 25 |
| | (223 | ) | | (199 | ) | Other, net | 21 |
| | 155 |
| | 79 |
| Income from continuing operations before income tax (expense) benefit | 3,634 |
| | 710 |
| | 204 |
| Income tax (expense) benefit from continuing operations | (4 | ) | | 1,833 |
| | 258 |
| Income from continuing operations | 3,630 |
| | 2,543 |
| | 462 |
| Loss from discontinued operations, net of income taxes | (265 | ) | | (177 | ) | | (462 | ) | Net income | $ | 3,365 |
| | $ | 2,366 |
| | $ | — |
|
| | | | | | | | | | | | | | December 31, | | 2018 | | 2017 | | 2016 | Total assets: | | | | | | Intrastate transportation and storage | $ | 6,365 |
| | $ | 5,020 |
| | $ | 5,174 |
| Interstate transportation and storage | 15,081 |
| | 15,316 |
| | 12,492 |
| Midstream | 19,745 |
| | 20,004 |
| | 17,873 |
| NGL and refined products transportation and services | 19,227 |
| | 17,600 |
| | 14,074 |
| Crude oil transportation and services | 17,062 |
| | 17,730 |
| | 15,908 |
| Investment in Sunoco LP | 4,879 |
| | 8,344 |
| | 8,701 |
| Investment in USAC | 3,775 |
| | — |
| | — |
| All other and eliminations | 2,112 |
| | 2,232 |
| | 4,703 |
| Total | $ | 88,246 |
| | $ | 86,246 |
| | $ | 78,925 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2018 | | 2017 | | 2016 | 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 | $ | 344 |
| | $ | 175 |
| | $ | 76 |
| Interstate transportation and storage | 812 |
| | 728 |
| | 280 |
| Midstream | 1,161 |
| | 1,308 |
| | 1,255 |
| NGL and refined products transportation and services | 2,381 |
| | 2,971 |
| | 2,198 |
| Crude oil transportation and services | 474 |
| | 453 |
| | 1,841 |
| Investment in Sunoco LP | 103 |
| | 103 |
| | 119 |
| Investment in USAC | 205 |
| | — |
| | — |
| All other | 150 |
| | 268 |
| | 160 |
| Total additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (accrual basis) | $ | 5,630 |
| | $ | 6,006 |
| | $ | 5,929 |
|
| | | | | | | | | | | | | | December 31, | | 2018 | | 2017 | | 2016 | Advances to and investments in affiliates: | | | | | | Intrastate transportation and storage | $ | 83 |
| | $ | 85 |
| | $ | 387 |
| Interstate transportation and storage | 2,070 |
| | 2,118 |
| | 2,149 |
| Midstream | 124 |
| | 126 |
| | 111 |
| NGL and refined products transportation and services | 243 |
| | 234 |
| | 235 |
| Crude oil transportation and services | 28 |
| | 22 |
| | 18 |
| All other | 94 |
| | 120 |
| | 140 |
| Total | $ | 2,642 |
| | $ | 2,705 |
| | $ | 3,040 |
|
| | 16.17. | QUARTERLY FINANCIAL DATA (UNAUDITED): |
Summarized unaudited quarterly financial data is presented below. The sum of net incomeEarnings per Limited Partner unit byare computed on a stand-alone basis for each 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.total year. | | | | | | | | | | | | | | | | | | | | | | | | Quarters Ended | | | | | March 31 | | June 30 | | September 30 | | December 31 | | Total Year | 2015: | | | | | | | | | | | Revenues | | $ | 10,326 |
| | $ | 11,540 |
| | $ | 6,601 |
| | $ | 5,825 |
| | $ | 34,292 |
| Operating income | | 608 |
| | 888 |
| | 576 |
| | 187 |
| | 2,259 |
| Net income | | 268 |
| | 839 |
| | 393 |
| | 21 |
| | 1,521 |
| Common Unitholders’ interest in net income (loss) | | (48 | ) | | 298 |
| | 59 |
| | (327 | ) | | (18 | ) | Basic net income (loss) per Common Unit | | $ | (0.17 | ) | | $ | 0.67 |
| | $ | 0.11 |
| | $ | (0.68 | ) | | $ | (0.09 | ) | Diluted net income (loss) per Common Unit | | $ | (0.17 | ) | | $ | 0.67 |
| | $ | 0.10 |
| | $ | (0.68 | ) | | $ | (0.10 | ) |
| | | | | | | | | | | | | | | | | | | | | | Quarters Ended | | | | March 31 | | June 30 | | September 30 | | December 31 | | Total Year | 2018: | | | | | | | | | | Revenues | $ | 11,882 |
| | $ | 14,118 |
| | $ | 14,514 |
| | $ | 13,573 |
| | $ | 54,087 |
| Operating income | 1,100 |
| | 1,126 |
| | 1,703 |
| | 1,419 |
| | 5,348 |
| Income from continuing operations | 726 |
| | 659 |
| | 1,393 |
| | 852 |
| | 3,630 |
| Net income | 489 |
| | 633 |
| | 1,391 |
| | 852 |
| | 3,365 |
| Limited Partners’ interest in net income | 341 |
| | 330 |
| | 370 |
| | 617 |
| | 1,658 |
| Income from continuing operations per limited partner unit: | | | | | | | | | | Basic | $ | 0.32 |
| | $ | 0.30 |
| | $ | 0.32 |
| | $ | 0.26 |
| | $ | 1.17 |
| Diluted | $ | 0.32 |
| | $ | 0.30 |
| | $ | 0.32 |
| | $ | 0.26 |
| | $ | 1.16 |
| Net income per limited partner unit: | | | | | | | | | | Basic | $ | 0.31 |
| | $ | 0.30 |
| | $ | 0.32 |
| | $ | 0.26 |
| | $ | 1.16 |
| Diluted | $ | 0.31 |
| | $ | 0.30 |
| | $ | 0.32 |
| | $ | 0.26 |
| | $ | 1.15 |
|
| | | | | | | | | | | | | | | | | | | | | | | | Quarters Ended | | | | | March 31 | | June 30 | | September 30 | | December 31 | | Total Year | 2014: | | | | | | | | | | | Revenues | | $ | 13,027 |
| | $ | 14,088 |
| | $ | 14,933 |
| | $ | 13,427 |
| | $ | 55,475 |
| Operating income | | 706 |
| | 769 |
| | 809 |
| | 159 |
| | 2,443 |
| Net income (loss) | | 483 |
| | 548 |
| | 513 |
| | (245 | ) | | 1,299 |
| Common Unitholders’ interest in net income (loss) | | 253 |
| | 295 |
| | 148 |
| | (90 | ) | | 606 |
| Basic net income (loss) per Common Unit | | $ | 0.76 |
| | $ | 0.92 |
| | $ | 0.44 |
| | $ | (0.28 | ) | | $ | 1.77 |
| Diluted net income (loss) per Common Unit | | $ | 0.76 |
| | $ | 0.92 |
| | $ | 0.44 |
| | $ | (0.28 | ) | | $ | 1.77 |
|
| | | | | | | | | | | | | | | | | | | | | | Quarters Ended | | | | March 31 | | June 30 | | September 30 | | December 31 | | Total Year | 2017: | | | | | | | | | | Revenues | $ | 9,661 |
| | $ | 9,427 |
| | $ | 9,984 |
| | $ | 11,451 |
| | $ | 40,523 |
| Operating income | 758 |
| | 743 |
| | 931 |
| | 289 |
| | 2,721 |
| Income from continuing operations | 330 |
| | 314 |
| | 741 |
| | 1,158 |
| | 2,543 |
| Net income | 319 |
| | 121 |
| | 758 |
| | 1,168 |
| | 2,366 |
| Limited Partners’ interest in net income | 232 |
| | 204 |
| | 240 |
| | 239 |
| | 915 |
| Income from continuing operations per limited partner unit: | | | | | | | | | | Basic | $ | 0.22 |
| | $ | 0.20 |
| | $ | 0.22 |
| | $ | 0.22 |
| | $ | 0.86 |
| Diluted | $ | 0.21 |
| | $ | 0.19 |
| | $ | 0.22 |
| | $ | 0.22 |
| | $ | 0.84 |
| Net income per limited partner unit: | | | | | | | | | | Basic | $ | 0.22 |
| | $ | 0.19 |
| | $ | 0.22 |
| | $ | 0.22 |
| | $ | 0.85 |
| Diluted | $ | 0.21 |
| | $ | 0.18 |
| | $ | 0.22 |
| | $ | 0.22 |
| | $ | 0.83 |
|
The three months ended December 31, 20152018 and 2014 reflected the unfavorable impacts of $120 million and $456 million, respectively, related to non-cash inventory valuation adjustments primarily in our investment in Sunoco Logistics and retail marketing segments. The three months ended December 31, 2015 and 20142017 reflected the recognition of impairment losses of $339$431 million and $370 million,$1.04 billion, respectively. Impairment losses in 20152018 were primarily related to our Lone Star Refinery Services operations and our Transwestern pipeline, andmidstream segment. Impairment losses in 2014, impairment losses2017 were primarily related to Regency’s Permian Basin gatheringour interstate transportation and processing operations. For thestorage segment, NGL and refined products segment, all other segment as well as investment in Sunoco LP segment. The three months ended December 31, 20152017 also reflected the recognition of a non-cash impairment of our investments in subsidiaries of $313 million in our interstate transportation and 2014, distributions paid forstorage segment.
| | 18. | SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION: |
Following are the period exceeded net income attributablefinancial statements of the Parent Company, which are included to partners by $934 million and $544 million, respectively. Accordingly, the distributions paidprovide additional information with respect to the General Partner, including incentive distributions, further exceeded net income,Parent Company’s financial position, results of operations and ascash flows on a result, a net loss was allocated to the Limited Partners for the period.stand-alone basis: BALANCE SHEETS | | | | | | | | | | December 31, | | 2018 | | 2017 | ASSETS | | | | CURRENT ASSETS: | | | | Cash and cash equivalents | $ | 2 |
| | $ | 1 |
| Accounts receivable from related companies | 65 |
| | 65 |
| Other current assets | 1 |
| | 1 |
| Total current assets | 68 |
| | 67 |
| PROPERTY, PLANT AND EQUIPMENT, net | 23 |
| | 27 |
| ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES | 26,581 |
| | 6,082 |
| GOODWILL | — |
| | 9 |
| OTHER NON-CURRENT ASSETS, net | — |
| | 8 |
| Total assets | $ | 26,672 |
| | $ | 6,193 |
| LIABILITIES AND PARTNERS’ CAPITAL | | | | CURRENT LIABILITIES: | | | | Accounts payable | $ | 2 |
| | $ | — |
| Accounts payable to related companies | 65 |
| | — |
| Interest payable | 76 |
| | 66 |
| Accrued and other current liabilities | 3 |
| | 4 |
| Total current liabilities | 146 |
| | 70 |
| LONG-TERM DEBT, less current maturities | 5,519 |
| | 6,700 |
| NOTE PAYABLE TO AFFILIATE | 445 |
| | 617 |
| OTHER NON-CURRENT LIABILITIES | 3 |
| | 2 |
| | | | | COMMITMENTS AND CONTINGENCIES |
| |
| | | | | PARTNERS’ CAPITAL (DEFICIT): | | | | General Partner | (5 | ) | | (3 | ) | Limited Partners: | | | | Common Unitholders (2,619,368,605 and 1,079,145,561 units authorized, issued and outstanding as of December 31, 2018 and 2017, respectively) | 20,606 |
| | (1,643 | ) | Series A Convertible Preferred Units (329,295,770 units authorized, issued and outstanding as of December 31, 2017) | — |
| | 450 |
| Accumulated other comprehensive income (loss) | (42 | ) | | — |
| Total partners’ capital (deficit) | 20,559 |
| | (1,196 | ) | Total liabilities and partners’ capital (deficit) | $ | 26,672 |
| | $ | 6,193 |
|
STATEMENTS OF OPERATIONS | | | | | | | | | | | | | | Years Ended December 31, | | 2018 | | 2017 | | 2016 | DEPRECIATION, DEPLETION AND AMORTIZATION | $ | (4 | ) | | $ | — |
| | $ | — |
| SELLING, GENERAL AND ADMINISTRATIVE EXPENSES | (37 | ) | | (31 | ) | | (185 | ) | OTHER INCOME (EXPENSE): | | | | | | Interest expense, net of interest capitalized | (346 | ) | | (347 | ) | | (327 | ) | Interest expense - affiliates | (8 | ) | | — |
| | — |
| Equity in earnings of unconsolidated affiliates | 2,092 |
| | 1,381 |
| | 1,511 |
| Loss on extinguishment of debt | — |
| | (47 | ) | | — |
| Other, net | (3 | ) | | (2 | ) | | (4 | ) | INCOME BEFORE INCOME TAX EXPENSE | 1,694 |
| | 954 |
| | 995 |
| Income tax expense | — |
| | — |
| | — |
| NET INCOME | 1,694 |
| | 954 |
| | 995 |
| General Partner’s interest in net income | 3 |
| | 2 |
| | 3 |
| Convertible Unitholders’ interest in income | 33 |
| | 37 |
| | 9 |
| Limited Partners’ interest in net income | $ | 1,658 |
| | $ | 915 |
| | $ | 983 |
|
STATEMENTS OF CASH FLOWS | | | | | | | | | | | | | | Years Ended December 31, | | 2018 | | 2017 | | 2016 | OPERATING ACTIVITIES | $ | 2,245 |
| | $ | 831 |
| | $ | 918 |
| INVESTING ACTIVITIES: | | | | | | Contributions to unconsolidated affiliates | (250 | ) | | (861 | ) | | (70 | ) | Capital expenditures | — |
| | (1 | ) | | (16 | ) | Contributions in aid of construction costs | — |
| | 7 |
| | — |
| Sunoco LP Series A Preferred Units redemption | 303 |
| | — |
| | — |
| Net cash provided by (used in) investing activities | 53 |
| | (855 | ) | | (86 | ) | FINANCING ACTIVITIES: | | | | | | Proceeds from borrowings | 463 |
| | 2,219 |
| | 225 |
| Principal payments on debt | (1,651 | ) | | (1,881 | ) | | (210 | ) | Distributions to partners | (1,684 | ) | | (1,010 | ) | | (1,022 | ) | Proceeds from affiliate | 575 |
| | 174 |
| | 176 |
| Common Units issued for cash | — |
| | 568 |
| | — |
| Debt issuance costs | — |
| | (47 | ) | | — |
| Net cash (used in) provided by financing activities | (2,297 | ) | | 23 |
| | (831 | ) | Increase (decrease) in cash and cash equivalents | 1 |
| | (1 | ) | | 1 |
| Cash and cash equivalents, beginning of period | 1 |
| | 2 |
| | 1 |
| Cash and cash equivalents, end of period | $ | 2 |
| | $ | 1 |
| | $ | 2 |
|
|