NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Tabular dollar and unit amounts, except per unit data, are in millions)
(unaudited)
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1.
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ORGANIZATION AND BASIS OF PRESENTATION
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Organization
Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.
The consolidated financial statements of ETE presented herein include the results of operations of:
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•
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our controlled subsidiaries, ETP, Sunoco LP and, beginning April 2018, USAC;
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•
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consolidated subsidiaries of our controlled subsidiaries and our wholly-owned subsidiaries that own general partner interests and IDRs in ETP and Sunoco LP, and the general partner interests in USAC; and
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•
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our wholly-owned subsidiary, Lake Charles LNG.
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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.
On June 30, 2018, our interests in ETP, Sunoco LP and USAC consisted of
100%
of the respective general partner interests and IDRs in ETP and Sunoco LP, as well as approximately
27.5 million
ETP common units, approximately
2.3 million
Sunoco LP common units, and approximately
20.5 million
USAC common units. Additionally, ETE owns
100
ETP Class I Units, which are currently not entitled to any distributions.
In August 2018, ETE and ETP announced that they have entered into a definitive agreement providing for the merger of ETP with a wholly-owned subsidiary of ETE in a unit-for-unit exchange. In connection with the transaction, ETE’s IDRs in ETP will be cancelled. Under the terms of the transaction, ETP unitholders (other than ETE and its subsidiaries) will receive
1.28
common units of ETE for each common unit of ETP they own. The transaction is expected to close in the fourth quarter of 2018, subject to the approval by a majority of the unaffiliated unitholders of ETP and other customary closing conditions.
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, Sunoco LP, USAC and cash flows from the operations of Lake Charles LNG. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries. In order to understand the financial condition of the Parent Company on a stand-alone basis, see Note
16
for stand-alone financial information apart from that of the consolidated partnership information included herein.
Our financial statements reflect the following reportable business segments:
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•
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Investment in ETP, including the consolidated operations of ETP;
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•
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Investment in Sunoco LP, including the consolidated operations of Sunoco LP;
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•
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Investment in USAC, including the consolidated operations of USAC;
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•
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Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and
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•
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Corporate and Other, including the following:
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•
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activities of the Parent Company; and
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•
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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.
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Basis of Presentation
The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended
December 31, 2017
, filed with the SEC on
February 23, 2018
. In the opinion of the Partnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC.
For prior periods reported herein, certain transactions related to the business of legacy Sunoco Logistics have been reclassified from cost of products sold to operating expenses; these transactions include sales between operating subsidiaries and their marketing affiliate. Certain other prior period amounts were reclassified to conform to the
2018
presentation. Additionally, there are reclassifications of certain balances 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.
Change in Accounting Policy
Inventory Accounting Change
During the fourth quarter of 2017, we elected to change our method of inventory costing to weighted-average cost for certain inventory that had previously been accounted for using the last-in, first-out (“LIFO”) method. The inventory impacted by this change included the crude oil, refined product and NGL associated with the legacy Sunoco Logistics business. Our management believes that the weighted-average cost method is preferable to the LIFO method as it more closely aligns the accounting policies across the consolidated entity, given that the legacy ETP inventory has been accounted for using the weighted-average cost method.
As a result of this change in accounting policy, the consolidated statement of operations and comprehensive income in prior periods have been retrospectively adjusted, as follows:
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Three Months Ended June 30, 2017
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Six Months Ended June 30, 2017
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As Originally Reported*
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Effect of Change
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As Adjusted
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As Originally Reported*
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Effect of Change
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As Adjusted
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Cost of products sold
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$
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7,171
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|
$
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(4
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)
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$
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7,167
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$
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14,710
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$
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(33
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)
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$
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14,677
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Operating income
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739
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4
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743
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1,467
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33
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1,500
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Income before income tax expense
|
343
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4
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347
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682
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33
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715
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Net income
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117
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4
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121
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407
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33
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440
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Net loss attributable to noncontrolling interest
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(95
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)
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4
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(91
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)
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(44
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)
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33
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(11
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)
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Comprehensive income
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116
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4
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120
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406
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33
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439
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* Amounts reflect certain reclassifications made to conform to the current year presentation and include the impact of discontinued operations as discussed in Note 2.
As a result of this change in accounting policy, the consolidated statement of cash flows in prior periods have been retrospectively adjusted, as follows:
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Six Months Ended June 30, 2017
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As Originally Reported*
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Effect of Change
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As Adjusted
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Net income
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$
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407
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$
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33
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$
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440
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Inventory Valuation Adjustments
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98
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(56
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)
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42
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Net change in operating assets and liabilities (change in inventories)
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(605
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)
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23
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(582
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)
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* Amounts reflect certain reclassifications made to conform to the current year presentation and include the impact of discontinued operations as discussed in Note 2.
Revenue Recognition Standard
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 certain of ETP’s operations, as well as contracts deemed to be in-substance supply agreements in ETP’s midstream operations. 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.
The Partnership has elected to apply the modified retrospective method to adopt 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.
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:
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Balance at December 31, 2017
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Adjustments due to ASC 606
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Balance at January 1, 2018
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Assets:
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Other current assets
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$
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295
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$
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8
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$
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303
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Property and Equipment, net
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61,088
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—
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61,088
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Other non-current assets, net
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886
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39
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925
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Intangible assets, net
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6,116
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(100
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)
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6,016
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Liabilities and Equity:
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Other non-current liabilities
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$
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1,217
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$
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1
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$
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1,218
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Noncontrolling interest
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31,176
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(54
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)
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31,122
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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.
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Three Months Ended June 30, 2018
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Six Months Ended June 30, 2018
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As Reported
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Balances Without Adoption of ASC 606
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Effect of Change: Higher/(Lower)
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As Reported
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Balances Without Adoption of ASC 606
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Effect of Change: Higher/(Lower)
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Revenues:
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Natural gas sales
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$
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1,024
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$
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1,024
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$
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—
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$
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2,086
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$
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2,086
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$
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—
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NGL sales
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2,141
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2,134
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7
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4,171
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4,153
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18
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Crude sales
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4,241
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4,238
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3
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7,495
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7,488
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7
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Gathering, transportation and other fees
|
1,667
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1,814
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(147
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)
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3,097
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|
3,430
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(333
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)
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Refined product sales
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4,818
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4,831
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(13
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)
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8,628
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8,651
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(23
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)
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Other
|
227
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227
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—
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523
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|
|
523
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—
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Costs and expenses:
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Cost of products sold
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$
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11,343
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$
|
11,491
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$
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(148
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)
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$
|
20,588
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$
|
20,923
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$
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(335
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)
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Operating expenses
|
772
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|
764
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|
|
8
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|
1,496
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|
|
1,475
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|
|
21
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|
Depreciation and amortization
|
694
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|
|
701
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|
|
(7
|
)
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1,359
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|
|
1,372
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(13
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)
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June 30, 2018
|
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As Reported
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Balances Without Adoption of ASC 606
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Effect of Change: Higher/(Lower)
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Assets:
|
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Other current assets
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$
|
616
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$
|
607
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$
|
9
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|
Property and Equipment, net
|
64,880
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|
|
64,880
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|
|
—
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Intangible assets, net
|
6,088
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|
|
6,200
|
|
|
(112
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)
|
Other non-current assets, net
|
996
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|
|
950
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|
|
46
|
|
|
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Liabilities and Equity:
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|
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Other non-current liabilities
|
$
|
1,227
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|
|
$
|
1,226
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|
|
$
|
1
|
|
Noncontrolling interest
|
31,493
|
|
|
31,551
|
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|
(58
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)
|
Additional disclosures related to revenue are included in Note
12
.
Use of Estimates
The unaudited consolidated financial statements have been prepared in conformity with GAAP, which includes the use of estimates and assumptions made by management that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the consolidated financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates.
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 useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. 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 Topic 840. The Partnership expects to adopt ASU 2016-02 and elect the practical expedient under ASU 2018-01 in the first quarter of 2019 and is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.
ASU 2017-12
In August 2017, the FASB issued Accounting Standards Update No. 2017-12,
Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities.
The amendments in this update improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition, the amendments in this update make certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.
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.
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2.
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ACQUISITIONS AND OTHER INVESTING TRANSACTIONS
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USAC Transactions
On April 2, 2018, ETE acquired a controlling interest in USAC, a publicly traded partnership that provides compression services in the United States. Specifically ETE 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, ETP 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 newly authorized and established 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 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 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 CDM Contribution, the CDM entities were indirect wholly-owned subsidiaries of ETP.
Beginning April 2018, ETE’s consolidated financial statements reflected USAC as a consolidated subsidiary.
Summary of Assets Acquired and Liabilities Assumed
ETE accounted for the USAC Transaction 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:
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|
|
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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
|
|
|
|
2,721
|
|
|
|
|
Total current liabilities
|
|
110
|
|
Long-term debt, less current maturities
|
|
1,527
|
|
Other non-current liabilities
|
|
2
|
|
|
|
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.
HPC
ETP previously owned a
49.99%
interest in HPC, which owns RIGS.
In April 2018, ETP acquired the remaining
50.01%
interest in HPC. Prior to April 2018, HPC was reflected as an unconsolidated affiliate in the Partnership’s consolidated financial statements; beginning in April 2018, RIGS is reflected as a wholly-owned subsidiary in the Partnership’s consolidated financial statements.
Sunoco LP Retail Store and Real Estate Sales
On January 23, 2018, Sunoco LP completed the disposition of assets pursuant to the purchase agreement with 7-Eleven (“Amended and Restated Asset Purchase Agreement”). As a result of the purchase agreement and subsequent closing, 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 closing of the transactions contemplated by the Amended and Restated Asset Purchase Agreement, 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 three and six months ended June 30, 2017, Sunoco LP recorded sales to the sites that were subsequently sold to 7-Eleven of
$199 million
,
$757 million
and
$1.5 billion
, respectively, which were eliminated in consolidation. Sunoco LP recorded a cash inflow of
$979 million
and
$1.6 billion
from 7-Eleven in the three and six months ended June 30, 2018 since the sale related to payments on trade receivables.
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,
47
have been sold,
three
are under contract to be sold, and
six
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:
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|
|
|
|
|
|
|
|
|
June 30, 2018
|
|
December 31, 2017
|
Carrying amount of assets classified as held for sale:
|
|
|
|
Cash and cash equivalents
|
$
|
—
|
|
|
$
|
21
|
|
Inventories
|
—
|
|
|
149
|
|
Other current assets
|
—
|
|
|
16
|
|
Property, plant and equipment, net
|
6
|
|
|
1,851
|
|
Goodwill
|
—
|
|
|
796
|
|
Intangible assets, net
|
—
|
|
|
477
|
|
Other non-current assets, net
|
—
|
|
|
3
|
|
Total assets classified as held for sale in the Consolidated Balance Sheet
|
$
|
6
|
|
|
$
|
3,313
|
|
|
|
|
|
Carrying amount of liabilities classified as held for sale:
|
|
|
|
Other current and non-current 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
REVENUES
|
$
|
—
|
|
|
$
|
1,757
|
|
|
$
|
349
|
|
|
$
|
3,343
|
|
|
|
|
|
|
|
|
|
COSTS AND EXPENSES
|
|
|
|
|
|
|
|
Cost of products sold
|
—
|
|
|
1,453
|
|
|
305
|
|
|
2,792
|
|
Operating expenses
|
—
|
|
|
198
|
|
|
61
|
|
|
384
|
|
Depreciation, depletion and amortization
|
—
|
|
|
3
|
|
|
—
|
|
|
36
|
|
Impairment losses
|
—
|
|
|
231
|
|
|
—
|
|
|
231
|
|
Selling, general and administrative
|
5
|
|
|
36
|
|
|
7
|
|
|
69
|
|
Total costs and expenses
|
5
|
|
|
1,921
|
|
|
373
|
|
|
3,512
|
|
OPERATING LOSS
|
(5
|
)
|
|
(164
|
)
|
|
(24
|
)
|
|
(169
|
)
|
Interest expense, net
|
—
|
|
|
4
|
|
|
2
|
|
|
8
|
|
Loss on extinguishment of debt and other
|
—
|
|
|
—
|
|
|
20
|
|
|
—
|
|
Other, net
|
38
|
|
|
3
|
|
|
61
|
|
|
8
|
|
LOSS FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE
|
(43
|
)
|
|
(171
|
)
|
|
(107
|
)
|
|
(185
|
)
|
Income tax expense (benefit)
|
(17
|
)
|
|
22
|
|
|
156
|
|
|
19
|
|
LOSS FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES
|
(26
|
)
|
|
(193
|
)
|
|
(263
|
)
|
|
(204
|
)
|
LOSS FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX BENEFIT ATTRIBUTABLE TO ETE
|
$
|
(1
|
)
|
|
$
|
(7
|
)
|
|
$
|
(10
|
)
|
|
$
|
(7
|
)
|
3.
CASH AND CASH EQUIVALENTS
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.
Non-cash investing and financing activities were as follows:
|
|
|
|
|
|
|
|
|
|
Six Months Ended
June 30,
|
|
2018
|
|
2017
|
NON-CASH INVESTING ACTIVITIES:
|
|
|
|
Accrued capital expenditures
|
$
|
1,015
|
|
|
$
|
1,364
|
|
Losses from subsidiary common unit transactions
|
(125
|
)
|
|
(51
|
)
|
NON-CASH FINANCING ACTIVITIES:
|
|
|
|
Contribution of property, plant and equipment from noncontrolling interest
|
$
|
—
|
|
|
$
|
988
|
|
Conversion of Series A Convertible Preferred Units to common units
|
589
|
|
|
—
|
|
4.
INVENTORIES
Inventories consisted of the following:
|
|
|
|
|
|
|
|
|
|
June 30, 2018
|
|
December 31, 2017
|
Natural gas, NGLs, and refined products
|
$
|
873
|
|
|
$
|
1,120
|
|
Crude oil
|
571
|
|
|
551
|
|
Spare parts and other
|
358
|
|
|
351
|
|
Total inventories
|
$
|
1,802
|
|
|
$
|
2,022
|
|
ETP utilizes commodity derivatives to manage price volatility associated with its natural gas inventories. 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.
USAC’s inventory consists of serialized and non-serialized parts used primarily in the repair of compression units. All inventory is stated at the lower of cost or net realizable value. The cost of serialized parts inventory is determined using the specific identification cost method, while the cost of non-serialized parts inventory is determined using the weighted average cost method. Purchases of these assets are considered operating activities on the Consolidated Statements of Cash Flows.
5.
FAIR VALUE MEASURES
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
June 30, 2018
were
$44.47 billion
and
$44.63 billion
, respectively. As of
December 31, 2017
, the aggregate fair value and carrying amount of our consolidated debt obligations were
$45.62 billion
and
$44.08 billion
, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the respective debt obligations’ observable inputs used for similar liabilities.
We have commodity derivatives and interest rate derivatives 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
six months ended
June 30, 2018
,
no
transfers were made between any levels within the fair value hierarchy.
The following tables summarize the gross fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of
June 30, 2018
and
December 31, 2017
based on inputs used to derive their fair values:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at
June 30, 2018
|
|
Fair Value Total
|
|
Level 1
|
|
Level 2
|
Assets:
|
|
|
|
|
|
Commodity derivatives:
|
|
|
|
|
|
Natural Gas:
|
|
|
|
|
|
Basis Swaps IFERC/NYMEX
|
$
|
22
|
|
|
$
|
22
|
|
|
$
|
—
|
|
Swing Swaps IFERC
|
1
|
|
|
—
|
|
|
1
|
|
Fixed Swaps/Futures
|
11
|
|
|
11
|
|
|
—
|
|
Forward Physical Contracts
|
9
|
|
|
—
|
|
|
9
|
|
Power:
|
|
|
|
|
|
Forwards
|
69
|
|
|
—
|
|
|
69
|
|
Options — Puts
|
1
|
|
|
1
|
|
|
—
|
|
NGLs — Forwards/Swaps
|
301
|
|
|
301
|
|
|
—
|
|
Refined Products — Futures
|
3
|
|
|
3
|
|
|
—
|
|
Crude — Forwards/Swaps
|
1
|
|
|
1
|
|
|
—
|
|
Corn (Bushels)
|
1
|
|
|
1
|
|
|
—
|
|
Total commodity derivatives
|
419
|
|
|
340
|
|
|
79
|
|
Other non-current assets
|
21
|
|
|
14
|
|
|
7
|
|
Total assets
|
$
|
440
|
|
|
$
|
354
|
|
|
$
|
86
|
|
Liabilities:
|
|
|
|
|
|
Interest rate derivatives
|
$
|
(147
|
)
|
|
$
|
—
|
|
|
$
|
(147
|
)
|
Commodity derivatives:
|
|
|
|
|
|
Natural Gas:
|
|
|
|
|
|
Basis Swaps IFERC/NYMEX
|
(70
|
)
|
|
(70
|
)
|
|
—
|
|
Swing Swaps IFERC
|
(2
|
)
|
|
(1
|
)
|
|
(1
|
)
|
Fixed Swaps/Futures
|
(14
|
)
|
|
(14
|
)
|
|
—
|
|
Forward Physical Contracts
|
(5
|
)
|
|
—
|
|
|
(5
|
)
|
Power — Forwards
|
(57
|
)
|
|
—
|
|
|
(57
|
)
|
NGLs — Forwards/Swaps
|
(319
|
)
|
|
(319
|
)
|
|
—
|
|
Refined Products — Futures
|
(9
|
)
|
|
(9
|
)
|
|
—
|
|
Crude — Forwards/Swaps
|
(308
|
)
|
|
(308
|
)
|
|
—
|
|
Total commodity derivatives
|
(784
|
)
|
|
(721
|
)
|
|
(63
|
)
|
Total liabilities
|
$
|
(931
|
)
|
|
$
|
(721
|
)
|
|
$
|
(210
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at
December 31, 2017
|
|
Fair Value Total
|
|
Level 1
|
|
Level 2
|
Assets:
|
|
|
|
|
|
Commodity derivatives:
|
|
|
|
|
|
Natural Gas:
|
|
|
|
|
|
Basis Swaps IFERC/NYMEX
|
$
|
11
|
|
|
$
|
11
|
|
|
$
|
—
|
|
Swing Swaps IFERC
|
13
|
|
|
—
|
|
|
13
|
|
Fixed Swaps/Futures
|
70
|
|
|
70
|
|
|
—
|
|
Forward Physical Swaps
|
8
|
|
|
—
|
|
|
8
|
|
Power — Forwards
|
23
|
|
|
—
|
|
|
23
|
|
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 Swaps
|
(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
|
)
|
6.
NET INCOME PER LIMITED PARTNER UNIT
A reconciliation of income and weighted average units used in computing basic and diluted income per unit is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
2018
|
|
2017*
|
|
2018
|
|
2017*
|
Income from continuing operations
|
$
|
659
|
|
|
$
|
314
|
|
|
$
|
1,385
|
|
|
$
|
644
|
|
Less: Income from continuing operations attributable to noncontrolling interest
|
303
|
|
|
94
|
|
|
657
|
|
|
185
|
|
Income from continuing operations, net of noncontrolling interest
|
356
|
|
|
220
|
|
|
728
|
|
|
459
|
|
Less: Convertible Unitholders’ interest in income
|
12
|
|
|
8
|
|
|
33
|
|
|
14
|
|
Less: General Partner’s interest in income
|
1
|
|
|
—
|
|
|
2
|
|
|
1
|
|
Income from continuing operations available to Limited Partners
|
$
|
343
|
|
|
$
|
212
|
|
|
$
|
693
|
|
|
$
|
444
|
|
Basic Income from Continuing Operations per Limited Partner Unit:
|
|
|
|
|
|
|
|
Weighted average limited partner units
|
1,114.8
|
|
|
1,075.2
|
|
|
1,097.1
|
|
|
1,077.2
|
|
Basic income from continuing operations per Limited Partner unit
|
$
|
0.31
|
|
|
$
|
0.20
|
|
|
$
|
0.63
|
|
|
$
|
0.41
|
|
Basic income from discontinued operations per Limited Partner unit
|
$
|
0.00
|
|
|
$
|
(0.01
|
)
|
|
$
|
(0.01
|
)
|
|
$
|
(0.01
|
)
|
Diluted Income from Continuing Operations per Limited Partner Unit:
|
|
|
|
|
|
|
|
Income from continuing operations available to Limited Partners
|
$
|
343
|
|
|
$
|
212
|
|
|
$
|
693
|
|
|
$
|
444
|
|
Dilutive effect of equity-based compensation of subsidiaries and distributions to Convertible Unitholders
|
12
|
|
|
8
|
|
|
33
|
|
|
14
|
|
Diluted income from continuing operations available to Limited Partners
|
$
|
355
|
|
|
$
|
220
|
|
|
$
|
726
|
|
|
$
|
458
|
|
Weighted average limited partner units
|
1,114.8
|
|
|
1,075.2
|
|
|
1,097.1
|
|
|
1,077.2
|
|
Dilutive effect of unconverted unit awards and Convertible Units
|
43.4
|
|
|
66.1
|
|
|
61.1
|
|
|
66.5
|
|
Diluted weighted average limited partner units
|
1,158.2
|
|
|
1,141.3
|
|
|
1,158.2
|
|
|
1,143.7
|
|
Diluted income from continuing operations per Limited Partner unit
|
$
|
0.31
|
|
|
$
|
0.19
|
|
|
$
|
0.63
|
|
|
$
|
0.40
|
|
Diluted income from discontinued operations per Limited Partner unit
|
$
|
0.00
|
|
|
$
|
(0.01
|
)
|
|
$
|
(0.01
|
)
|
|
$
|
(0.01
|
)
|
* As adjusted. See Note 1.
7.
DEBT OBLIGATIONS
Parent Company Indebtedness
The Parent Company’s indebtedness, including its senior notes, senior secured term loan and senior secured revolving credit facility, is secured by all of its and certain of its subsidiaries’ tangible and intangible assets.
ETE Revolving Credit Facility
Pursuant to ETE’s revolving credit agreement, which matures on March 24, 2022, the lenders have committed to provide advances up to an aggregate principal amount of
$1.5 billion
at any one time outstanding, and the Parent Company has the option to request increases in the aggregate commitments by up to
$500 million
in additional commitments.
As of
June 30, 2018
, borrowings of
$956 million
were outstanding under the Parent Company revolving credit facility and the amount available for future borrowings was
$544 million
.
Subsidiary Indebtedness
ETP Senior Notes Offering and Redemption
In June 2018, ETP 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 ETP’s existing and future senior debt, and senior in right of payment to any future subordinated debt ETP may incur. The notes of each series will initially be fully and unconditionally guaranteed by ETP’s subsidiary, Sunoco Logistics Partners Operations L.P., on a senior unsecured basis so long as it guarantees any of ETP’s 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 ETP’s revolving credit facility, for general partnership purposes and to redeem all of the following senior notes:
•
ETP’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
•
ETP’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
.
ETP Five-Year Credit Facility
ETP’s revolving credit facility (the “ETP Five-Year Credit Facility”) allows for unsecured borrowings up to
$4.00 billion
and matures in December 2022. The ETP 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
June 30, 2018
, the ETP Five-Year Credit Facility had
$1.23 billion
outstanding, all of which
was commercial paper. The amount available for future borrowings was
$2.61 billion
after taking into account letters of credit of
$167 million
.
The weighted average interest rate on the total amount outstanding as of
June 30, 2018
was
2.87%
.
ETP 364-Day Facility
ETP’s 364-day revolving credit facility (the “ETP 364-Day Facility”) allows for unsecured borrowings up to
$1.0 billion
and matures on November 30, 2018.
As of
June 30, 2018
, the ETP 364-Day Facility had
no
outstanding borrowings.
Bakken Credit Facility
In August 2016, ETP 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
June 30, 2018
,
the Bakken Credit Facility had
$2.50 billion
of outstanding borrowings. The weighted average interest rate on the total amount outstanding as of
June 30, 2018
was
3.72%
.
Sunoco LP Senior Notes and Term Loan
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 the closing of the asset purchase agreement with 7-Eleven 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 the 7-Eleven transaction;
|
|
|
•
|
redeem the outstanding Sunoco LP Series A Preferred Units; and
|
|
|
•
|
repurchase
17,286,859
Sunoco LP common units owned by ETP.
|
Sunoco LP Credit Facility
Sunoco LP maintains a
$1.50 billion
revolving credit agreement, which matures in September 2019. As of
June 30, 2018
, the Sunoco LP credit facility had
$320 million
outstanding borrowings and
$8 million
in standby letters of credit. The unused availability on the revolver at
June 30, 2018
was
$1.2 billion
.
In July 2018, Sunoco LP amended its revolving credit agreement, including extending the expiration to July 27, 2023 (which may be extended in accordance with the terms of the credit agreement).
USAC Credit Facility
USAC currently has a
$1.6 billion
revolving credit facility, which matures on April 2, 2023 and permits up to
$400 million
of future increases in borrowing capacity.
As of June 30, 2018, USAC had
$950 million
of outstanding borrowings and no outstanding letters of credit under the credit agreement.
As of
June 30, 2018
, USAC had
$650 million
of availability under its credit facility.
USAC Senior Notes
USAC has outstanding
$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.
Compliance with Our Covenants
We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our respective credit agreements as of
June 30, 2018
.
8.
REDEEMABLE NONCONTROLLING INTERESTS
Certain redeemable noncontrolling interest in the Partnership’s subsidiaries are reflected as mezzanine equity on the consolidated balance sheet. Redeemable noncontrolling interests as of
June 30, 2018
include (i) a balance of
$465 million
related to the USAC Preferred Units described below and (ii) a balance of
$22 million
related to noncontrolling interest holders in one of ETP’s consolidated subsidiaries that have the option to sell their interests to ETP.
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 USAC Preferred Units are entitled to receive cumulative quarterly distributions equal to
$24.375
per USAC Preferred Unit, subject to increase in certain limited circumstances. The USAC Preferred Units will have a perpetual term, unless converted or redeemed. Certain portions of the USAC Preferred Units will 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 fifth anniversary of the issue date, USAC will have the option to redeem all or any portion of the
USAC Preferred Units for cash. In addition, at any time on or after the tenth anniversary of the issue date, the holders of the USAC Preferred Units will have the right to require USAC to redeem all or any portion of the USAC Preferred Units, and the Partnership may elect to pay up to 50% of such redemption amount in USAC common units.
9.
EQUITY
ETE
The changes in ETE common units and ETE Series A Convertible Preferred Units during the
six months ended
June 30, 2018
were as follows:
|
|
|
|
|
|
|
|
Number of ETE Series A Convertible Preferred Units
|
|
Number of Common Units
|
Outstanding at December 31, 2017
|
329.3
|
|
|
1,079.1
|
|
Conversion of ETE Series A Convertible Preferred Units to common units
|
(329.3
|
)
|
|
79.1
|
|
Outstanding at June 30, 2018
|
—
|
|
|
1,158.2
|
|
ETE Equity Distribution Program
In March 2017, the Partnership entered into an equity distribution agreement relating to at-the-market offerings of its common units with an aggregate offering price up to
$1 billion
. As of
June 30, 2018
, there have been
no
sales of common units under the equity distribution agreement.
ETE 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
ETE common units in accordance with the terms of ETE’s partnership agreement.
Repurchase Program
During the
six months ended
June 30, 2018
, ETE did not repurchase any ETE common units under its current buyback program. As of
June 30, 2018
,
$936 million
remained available to repurchase under the current program.
Subsidiary Equity Transactions
The Parent Company accounts for the difference between the carrying amount of its investment in ETP, Sunoco LP, and USAC and the underlying book value arising from the issuance or redemption of units by ETP, Sunoco LP, and USAC (excluding transactions with the Parent Company) as capital transactions. As a result of these transactions, during the
six months ended
June 30, 2018
, we recognized a decrease in partners’ capital of
$125 million
.
ETP Equity Distribution Program
During the
six months ended June 30,
2018
,
there were
no
ETP common units issued under ETP’s equity distribution agreements. As of
June 30, 2018
,
$752 million
of ETP’s common units remained available to be issued under ETP’s existing
$1.00 billion
equity distribution agreement.
ETP Distribution Reinvestment Program
In July 2017, ETP initiated a new distribution reinvestment plan. During the
six months ended
June 30, 2018
,
distributions of
$39 million
were reinvested under ETP’s distribution reinvestment plan.
ETP Preferred Units
ETP issued
950,000
ETP Series A Preferred Units and
550,000
ETP Series B Preferred Units in November 2017.
ETP Series C Preferred Units Issuance
In April 2018, ETP issued
18 million
of its
7.375%
ETP Series C Preferred Units at a price of
$25
p
er unit, resulting in total gross proceeds of
$450 million
. The proceeds were used to repay amounts outstanding under ETP’s revolving credit facility and for general partnership purposes.
Distributions on the ETP 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 ETP 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 ETP Series C Preferred Units are redeemable at ETP’s option on or after May 15, 2023 at a redemption price of
$25
per ETP Series C Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
ETP Series D Preferred Units Issuance
In July 2018, ETP issued
17.8 million
of its
7.625%
ETP Series D Preferred Units at a price of
$25
per unit, resulting in total gross proceeds of
$445 million
.
The proceeds were used to repay amounts outstanding under ETP’s revolving credit facility and for general partnership purposes.
Distributions on the ETP 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 ETP 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
4.378%
per annum. The ETP Series D Preferred Units are redeemable at ETP’s option on or after August 15, 2023 at a redemption price of
$25
per ETP Series D Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
Sunoco LP Common Unit Transactions
On February 7, 2018, subsequent to the record date for Sunoco LP’s fourth quarter 2017 cash distributions, Sunoco LP repurchased
17,286,859
Sunoco LP common units owned by ETP for aggregate cash consideration of approximately
$540 million
. ETP used the proceeds from the sale of the Sunoco LP common units to repay amounts outstanding under its revolving credit facility.
Sunoco LP Series A Preferred Units
On January 25, 2018, Sunoco LP redeemed all outstanding Sunoco LP Series A Preferred Units held by ETE for an aggregate redemption amount of approximately
$313 million
. The redemption amount includes the original consideration of
$300 million
and a
1%
call premium plus accrued and unpaid quarterly distributions.
USAC 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 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 Class B Units
The USAC Class B Units, all of which are owned by ETP, 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 quarter ending June 30, 2019.
USAC Distribution Reinvestment Program
During the three months ended June 30, 2018, distributions of
$0.2 million
were reinvested under the USAC distribution reinvestment program resulting in the issuance of approximately
11,776
USAC common units.
Parent Company Cash Distributions
Distributions declared and/or paid subsequent to
December 31, 2017
were as follows:
|
|
|
|
|
|
|
|
|
|
Quarter Ended
|
|
Record Date
|
|
Payment Date
|
|
Rate
|
December 31, 2017
(1)
|
|
February 8, 2018
|
|
February 20, 2018
|
|
$
|
0.3050
|
|
March 31, 2018
(1)
|
|
May 7, 2018
|
|
May 21, 2018
|
|
0.3050
|
|
June 30, 2018
|
|
August 6, 2018
|
|
August 20, 2018
|
|
0.3050
|
|
|
|
(1)
|
Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forgo their cash distributions on all or a portion of their common units, and in lieu of receiving cash distributions on these common units for each such quarter, such unitholder received Series A Convertible Preferred Units, and (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 Series A Convertible Preferred Unit. The quarter ended March 31, 2018 was the final quarter of participation in the plan.
|
Distributions declared and/or paid with respect to our Series A Convertible Preferred Units subsequent to
December 31, 2017
were as follows:
|
|
|
|
|
|
|
|
|
|
Quarter Ended
|
|
Record Date
|
|
Payment Date
|
|
Rate
|
December 31, 2017
|
|
February 8, 2018
|
|
February 20, 2018
|
|
$
|
0.1100
|
|
March 31, 2018
|
|
May 7, 2018
|
|
May 21, 2018
|
|
0.1100
|
|
ETP Cash Distributions
Distributions declared and/or paid by ETP subsequent to
December 31, 2017
were as follows:
|
|
|
|
|
|
|
|
|
|
Quarter Ended
|
|
Record Date
|
|
Payment Date
|
|
Rate
|
December 31, 2017
|
|
February 8, 2018
|
|
February 14, 2018
|
|
$
|
0.5650
|
|
March 31, 2018
|
|
May 7, 2018
|
|
May 15, 2018
|
|
0.5650
|
|
June 30, 2018
|
|
August 6, 2018
|
|
August 14, 2018
|
|
0.5650
|
|
ETE has agreed to relinquish its right to the following amounts of incentive distributions from ETP in future periods:
|
|
|
|
|
|
|
|
Year Ending December 31,
|
2018 (remainder)
|
|
$
|
69
|
|
2019
|
|
128
|
|
Each year beyond 2019
|
|
33
|
|
Distributions on preferred units declared and paid by ETP subsequent to
December 31, 2017
were as follows:
|
|
|
|
|
|
|
|
|
|
Period Ended
|
|
Record Date
|
|
Payment Date
|
|
Rate
|
ETP Series A Preferred Units
|
|
|
|
|
|
|
December 31, 2017
|
|
February 1, 2018
|
|
February 15, 2018
|
|
$
|
15.451
|
|
June 30, 2018
|
|
August 1, 2018
|
|
August 15, 2018
|
|
31.250
|
|
ETP Series B Preferred Units
|
|
|
|
|
|
|
December 31, 2017
|
|
February 1, 2018
|
|
February 15, 2018
|
|
16.378
|
|
June 30, 2018
|
|
August 1, 2018
|
|
August 15, 2018
|
|
33.125
|
|
ETP Series C Preferred Units
|
|
|
|
|
|
|
June 30, 2018
|
|
August 1, 2018
|
|
August 15, 2018
|
|
0.563
|
|
Sunoco LP Cash Distributions
The following are distributions declared and/or paid by Sunoco LP subsequent to
December 31, 2017
:
|
|
|
|
|
|
|
|
|
|
Quarter Ended
|
|
Record Date
|
|
Payment Date
|
|
Rate
|
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
|
|
USAC Cash Distributions
Subsequent to the USAC Transactions described in Note 2, ETE and its wholly-owned subsidiaries own an aggregate
20,466,912
USAC common units, and ETP owns
19,191,351
USAC common units and
6,397,965
USAC Class B units. As of
June 30, 2018
, USAC had
89,953,049
common units outstanding. USAC currently has a non-economic general partner interest and no outstanding incentive distribution rights.
The following are distributions declared and/or paid by USAC subsequent to the USAC transaction on April 2, 2018:
|
|
|
|
|
|
|
|
|
|
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
|
|
Accumulated Other Comprehensive Income
The following table presents the components of AOCI, net of tax:
|
|
|
|
|
|
|
|
|
|
June 30, 2018
|
|
December 31, 2017
|
Available-for-sale securities
(1)
|
$
|
4
|
|
|
$
|
8
|
|
Foreign currency translation adjustment
|
(5
|
)
|
|
(5
|
)
|
Actuarial loss related to pensions and other postretirement benefits
|
(7
|
)
|
|
(5
|
)
|
Investments in unconsolidated affiliates, net
|
12
|
|
|
5
|
|
Subtotal
|
4
|
|
|
3
|
|
Amounts attributable to noncontrolling interest
|
(4
|
)
|
|
(3
|
)
|
Total AOCI, net of tax
|
$
|
—
|
|
|
$
|
—
|
|
|
|
(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 ETP’s accumulated other comprehensive income related to available-for-sale securities to ETP’s common unitholders. The amount is reflected as a change in noncontrolling interest in the Partnership’s consolidated financial statements.
|
The Partnership’s effective tax rate differs 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. For the
three and six months ended
June 30, 2018
, the Partnership’s income tax benefit also reflected
$13 million
and
$51 million
, respectively, of deferred benefit adjustments as the result of a state statutory rate reduction.
11.
REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES
FERC Audit
In March 2016, the FERC commenced an audit of Trunkline for the period from January 1, 2013 to present to evaluate Trunkline’s compliance with the requirements of its FERC gas tariff, the accounting regulations of the Uniform System of Accounts as prescribed by the FERC, and the FERC’s annual reporting requirements. The audit is ongoing.
Commitments
In the normal course of business, ETP purchases, processes and sells natural gas pursuant to long-term contracts and enters into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. ETP believes that the terms of these agreements are commercially reasonable and will not have a material adverse effect on its financial position or results of operations.
ETP’s joint venture agreements require that they fund their proportionate share of capital contributions to their unconsolidated affiliates. Such contributions will depend upon their unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.
We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments with typical initial terms of
5
to
15
years, with some having a term of
40
years or more. The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Rental expense
(1)
|
$
|
42
|
|
|
$
|
41
|
|
|
$
|
74
|
|
|
$
|
81
|
|
Less: Sublease rental income
|
(11
|
)
|
|
(6
|
)
|
|
(17
|
)
|
|
(12
|
)
|
Rental expense, net
|
$
|
31
|
|
|
$
|
35
|
|
|
$
|
57
|
|
|
$
|
69
|
|
|
|
(1)
|
Includes contingent rentals totaling
$1 million
and
$6 million
for
three months ended June 30,
2018
and
2017
, respectively and
$2 million
and
$10 million
for the six months ended June 30, 2018 and 2017, respectively.
|
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 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 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 Tribes 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 was denied, and raised claims based on the religious rights of the Tribe.
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. 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. Following the completion of the remand process by the USACE, the Court will make a determination regarding the three discrete issues covered by the remand order.
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, respectfully.
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 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 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.
While ETP believes that the pending lawsuits are unlikely to halt or suspend operation of the pipeline, we cannot assure this outcome. ETP cannot determine when or how these lawsuits will be resolved or the impact they may have on the Dakota Access project.
Mont Belvieu Incident
On June 26, 2016, a hydrocarbon storage well located on another operator’s facility adjacent to Lone Star NGL Mont Belvieu’s (“Lone Star”) facilities in Mont Belvieu, Texas experienced an over-pressurization resulting in a subsurface release. The subsurface release caused a fire at Lone Star’s South Terminal and damage to Lone Star’s storage well operations at its South and North Terminals. Normal operations have resumed at the facilities with the exception of one of Lone Star’s storage wells.
Lone Star is still quantifying the extent of its incurred and ongoing damages and has or will be seeking reimbursement for these losses.
MTBE Litigation
Sunoco, Inc. and/or Sunoco, Inc. (R&M) (now known as Sunoco (R&M), LLC) are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability, nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices claims. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees.
As of June 30, 2018, Sunoco, Inc. is a defendant in
six
cases, including one case each initiated by the States of Maryland, Vermont and Rhode Island, one by the Commonwealth of Pennsylvania and two by the Commonwealth of Puerto Rico. The more recent Puerto Rico action is a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. The actions brought by the State of Maryland and Commonwealth of Pennsylvania have also named as defendants Energy Transfer Partners, L.P., ETP Holdco Corporation, and Sunoco Partners Marketing & Terminals, L.P.
Sunoco, Inc. and Sunoco, Inc. (R&M) have reached a settlement with the State of New Jersey. The Court approved the Judicial Consent Order on December 5, 2017. On April 5, 2018, the Court entered an Order dismissing the matter with prejudice.
It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. An adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any such adverse determination occurs, but such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position.
Regency Merger Litigation
Purported Regency unitholders filed lawsuits in state and federal courts in Dallas and Delaware asserting claims relating to the Regency-ETP merger (the “Regency Merger”). All but one Regency Merger-related lawsuits have been dismissed. On June 10, 2015, Adrian Dieckman (“Dieckman”), a purported Regency unitholder, filed a class action complaint in the Court of Chancery of the State of Delaware (the “Regency Merger Litigation”), on behalf of Regency’s common unitholders against Regency GP, LP; Regency GP LLC; ETE, ETP, ETP GP, and the members of Regency’s board of directors (“Defendants”).
The Regency Merger Litigation alleges that the Regency Merger breached the Regency partnership agreement because Regency’s conflicts committee was not properly formed, and the Regency Merger was not approved in good faith. On March 29, 2016, the Delaware Court of Chancery granted 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 Court of Chancery issued an Order granting in part and denying in part the motions to dismiss, dismissing the claims against all defendants other than Regency GP, LP and Regency GP LLC (the “Regency 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 23-27, 2019.
The Regency Defendants cannot predict the outcome of the Regency Merger Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can the Regency Defendants predict the amount of time and expense that will be required to resolve 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.
Enterprise Products Partners, L.P. and Enterprise Products Operating LLC Litigation
On January 27, 2014, a trial commenced between ETP against Enterprise Products Partners, L.P. and Enterprise Products Operating LLC (collectively, “Enterprise”) and Enbridge (US) Inc. Trial resulted in a verdict in favor of ETP against Enterprise that consisted of
$319 million
in compensatory damages and
$595 million
in disgorgement to ETP. The jury also found that ETP owed Enterprise
$1 million
under a reimbursement agreement. On July 29, 2014, the trial court entered a final judgment in favor of ETP and awarded ETP
$536 million
,
consisting of compensatory damages, disgorgement, and pre-judgment interest. The trial court also ordered that ETP shall be entitled to recover post-judgment interest and costs of court and that Enterprise is not entitled to any net recovery on its counterclaims. Enterprise filed a notice of appeal with the Court of Appeals. On July 18, 2017, the Court of Appeals issued its opinion and reversed the trial court’s judgment. ETP’s motion for rehearing to the Court of Appeals was denied. On June 8, 2018, the Texas Supreme Court ordered briefing on the merits. ETP’s petition for review remains under consideration by the Texas Supreme Court.
Litigation Filed By or Against Williams
On April 6, 2016, The Williams Companies, Inc. (“Williams”) filed a complaint against ETE and LE GP, LLC (“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 ETE’s partnership agreement that was adopted on March 8, 2016 as part of the Issuance.
On May 3, 2016, ETE and LE GP filed an answer and counterclaim in the First Delaware Williams Litigation. The counterclaim asserts in general that Williams materially breached its obligations under the ETE-Williams merger agreement (the “Merger Agreement”) by (a) blocking ETE’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 ETE and LE GP and added Energy Transfer Corp LP, ETE Corp GP, LLC, and Energy Transfer Equity GP, LLC as additional defendants (collectively, “Defendants”) (the “Second Delaware Williams Litigation”). In general, Williams alleged that Defendants breached the Merger Agreement by (a) failing to use commercially reasonable efforts to obtain from Latham & Watkins LLP (“Latham”) the delivery of a tax opinion concerning Section 721 of the Internal Revenue Code (“721 Opinion”), (b) breaching a representation and warranty in the Merger Agreement concerning Section 721 of the Internal Revenue Code, and (c) taking actions that allegedly delayed the SEC in declaring the Form S-4 filed in connection with the merger (the “Form S-4”) effective. Williams asked the Court, in general, to (a) issue a declaratory judgment that ETE breached the Merger Agreement, (b) enjoin ETE from terminating the Merger Agreement on the basis that it failed to obtain a 721 Opinion, (c) enjoin ETE from terminating the Merger Agreement on the basis that the transaction failed to close by the outside date, and (d) force ETE to close the merger or take various other affirmative actions.
ETE filed an answer and counterclaim in the Second Delaware Williams Litigation. In addition to the counterclaims previously asserted, ETE asserted that Williams materially breached the Merger Agreement by, among other things, (a) modifying or qualifying the Williams board of directors’ recommendation to its stockholders regarding the merger, (b) failing to provide material information to ETE for inclusion in the Form S-4 related to the merger, (c) failing to facilitate the financing of the merger, (d) failing to use its reasonable best efforts to consummate the merger, and (e) breaching the Merger Agreement’s forum-selection clause. ETE sought, among other things, a declaration that it could validly terminate the Merger Agreement after June 28, 2016 in the event that Latham was unable to deliver the 721 Opinion on or prior to June 28, 2016.
After a two-day trial on June 20 and 21, 2016, the Court ruled in favor of ETE on Williams’ claims in the Second Delaware Williams Litigation and issued a declaratory judgment that ETE could terminate the merger after June 28, 2016 because of Latham’s inability to provide the required 721 Opinion. The Court also denied Williams’ requests for injunctive relief. The Court did not reach a decision regarding Williams’ claims related to the Issuance or ETE’s counterclaims. Williams filed a notice of appeal to the Supreme Court of Delaware on June 27, 2016. 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. Trial is set for May 20, 2019.
Defendants cannot predict the outcome of the First Delaware Williams Litigation, the Second Delaware Williams Litigation, or any lawsuits that might be filed subsequent to the date of this filing; nor can Defendants predict the amount of time and expense that will be required to resolve these lawsuits. Defendants believe that Williams’ claims are without merit and intend to defend vigorously against them.
Unitholder Litigation Relating to the Issuance
On April 12, 2016, two purported ETE unitholders (the “Issuance Plaintiffs”) filed putative class action lawsuits against ETE, LE GP, Kelcy Warren, John McReynolds, Marshall McCrea, Matthew Ramsey, Ted Collins, K. Rick Turner, William Williams, Ray Davis, and Richard Brannon (collectively, the “Issuance Defendants”) in the Delaware Court of Chancery (the “Issuance
Litigation”). Another purported ETE unitholder, Chester County Employees’ Retirement Fund, later joined the Issuance Litigation.
The Issuance Plaintiffs allege that the Issuance breached various provisions of ETE’s partnership agreement. The Issuance Plaintiffs seek, among other things, preliminary and permanent injunctive relief that (a) prevents ETE from making distributions to holders of the Series A Convertible Preferred Units and (b) invalidates an amendment to ETE’s partnership agreement that was adopted on March 8, 2016 as part of the Issuance.
On August 29, 2016, the Issuance Plaintiffs filed a consolidated amended complaint, and in addition to the injunctive relief described above, seek class-wide damages allegedly resulting from the Issuance.
The 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 ETE’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.
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.
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. ETP, 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 and 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, 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.
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, 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. Defendants’ motions to dismiss are due on or before September 10, 2018.
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.
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
June 30, 2018
and
December 31, 2017
, accruals of approximately
$58 million
and
$53 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 Sunoco Pipeline L.P. (“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 West Whiteland 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 West Whiteland Township.
Following a hearing on May 7 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 (“DEP”) 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 West Whiteland Township with respect to all areas within the Township where the necessary environmental permits had been issued. 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.
Service on ME1 was resumed in accordance with PUC’s Opinion and Order. Senator Dinniman’s Complaint will proceed forward under a schedule to be determined by the ALJ. A prehearing conference with the ALJ is scheduled for August 28, 2018.
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 Pennsylvania Department of Environmental Protection (“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.
No
amounts have been recorded in our
June 30, 2018
or
December 31, 2017
consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.
Environmental Matters
Our operations are subject to extensive federal, tribal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations but there can be no assurance that such costs will not be material in the future or that such future compliance with existing, amended or new legal requirements will not have a material adverse effect on our business and operating results. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, the issuance of injunctions in affected areas and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.
Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.
Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs.
In February 2017, we received letters from the DOJ and Louisiana Department of Environmental Quality notifying SPLP and Mid-Valley Pipeline Company (“Mid-Valley”) that enforcement actions were being pursued for three crude oil releases: (a) an estimated 550 barrels released from the Colmesneil-to-Chester pipeline in Tyler County, Texas (“Colmesneil”) operated and owned by SPLP in February 2013; (b) an estimated 4,509 barrels released from the Longview-to-Mayersville pipeline in Caddo Parish, Louisiana (a/k/a Milepost 51.5) operated by SPLP and owned by Mid-Valley in October 2014; and (c) an estimated 40 barrels released from the Wakita 4-inch gathering line in Oklahoma operated and owned by SPLP in January 2015. In May 2017, we presented to the DOJ, EPA and Louisiana Department of Environmental Quality a summary of the emergency response and remedial efforts taken by SPLP after the releases occurred as well as operational changes instituted by SPLP to reduce the likelihood of future releases. In July 2017, we had a follow-up meeting with the DOJ, EPA and Louisiana Department of Environmental Quality during which the agencies presented their initial demand for civil penalties and injunctive relief. Sin
ce then, the parties have reached an agreement in principal to resolve all penalties. We are currently working on a counteroffer to the Louisiana Department of Environmental Quality, and we are involved in settlement discussion with the agencies.
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:
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•
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certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of polychlorinated biphenyls (“PCBs”). PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties.
|
|
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•
|
certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.
|
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•
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legacy sites related to Sunoco, Inc. that are subject to environmental assessments, including formerly owned terminals and other logistics assets, retail sites that Sunoco, Inc. no longer operates, closed and/or sold refineries and other formerly owned sites.
|
|
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•
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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
June 30, 2018
,
Sunoco, Inc. had been named as a PRP at approximately
41
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.
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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.
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June 30, 2018
|
|
December 31, 2017
|
Current
|
$
|
51
|
|
|
$
|
35
|
|
Non-current
|
352
|
|
|
337
|
|
Total environmental liabilities
|
$
|
403
|
|
|
$
|
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
three months ended June 30,
2018
and
2017
, the Partnership recorded
$9 million
and
$10 million
, respectively, of expenditures related to environmental cleanup programs. During the
six months ended June 30,
2018
and
2017
, the Partnership recorded
$15 million
and
$18 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, EPA issued a Finding of Violation (“FOV”) to TRC and, on September 30, 2013, EPA issued a Notice of Violation (“NOV”)/ FOV to TRC alleging Clean Air Act violations. To date, EPA has not issued an FOV or NOV/FOV to Sunoco, Inc. directly but some of EPA’s claims relate to the time period that Sunoco, Inc. operated the refinery. Specifically, EPA has claimed that the refinery flares were not operated in a manner consistent with good air pollution control practice for minimizing emissions and/or in conformance with their design, and that Sunoco, Inc. submitted semi-annual compliance reports in 2010 and 2011 to the EPA that failed to include all of the information required by the regulations. EPA has proposed penalties in excess of
$200,000
to resolve the allegations and discussions continue between the parties. The timing or outcome of this matter cannot be reasonably determined at this time, however, we do not expect there to be a material impact to our results of operations, cash flows or financial position.
Our pipeline operations are subject to regulation by the United States Department of Transportation under the PHMSA, pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures.
Our operations are also subject to the requirements of OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, the Occupational Health and Safety Administration’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our past costs for OSHA required activities, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances have not had a material adverse effect on our results of operations but there is no assurance that such costs will not be material in the future.
12.
REVENUE
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
three and six months ended
June 30, 2017
, were recorded under the Partnership’s previous accounting policies.
Disaggregation of revenue
The major types of revenue within our reportable segment, are as follows:
•
Investment in ETP
|
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•
|
intrastate transportation and storage
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•
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interstate transportation and storage
|
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•
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NGL and refined products transportation and services
|
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•
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crude oil transportation and services
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•
Investment in Sunoco LP
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•
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fuel distribution and marketing
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•
Investment in USAC
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•
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retail parts and services
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•
Investment in Lake Charles LNG
Note
15
depicts the disaggregation of revenue amounts by type for each of our reportable segments, with revenue amounts reflected in accordance with ASC Topic 606 for 2018 and ASC Topic 605 for 2017.
ETP’s intrastate transportation and storage revenue
ETP’s intrastate transportation and storage revenues are determined primarily by the volume of capacity ETP’s 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 ETP’s 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 ETP’s pipelines or inject/withdraw into or out of ETP’s 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 ETP accepts the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed.
ETP’s interstate transportation and storage revenue
ETP’s interstate transportation and storage revenues are determined primarily by the amount of capacity ETP’s 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 ETP’s storage facilities. ETP’s interstate transportation and storage 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, ETP 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 ETP’s pipelines or inject into or withdrawn out of ETP’s storage facilities. Consequently, ETP is 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 ETP accepts the customer’s request. Revenue is recognized for interruptible contracts at the time the services are performed.
ETP’s midstream revenue
ETP’s midstream revenues are derived primarily from margins ETP earns for natural gas volumes that are gathered, processed, and/or transported for ETP’s customers. The various types of revenue contracts ETP’s midstream operations enter into include:
Fixed fee gathering and processing:
Contracts under which ETP provides 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 ETP gathers raw natural gas from a third party producer, processes the gas to convert it to pipeline quality natural gas, and redeliver to the producer a thermal-equivalent amount of pipeline quality natural gas. In exchange for these services, ETP retains 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 ETP provides 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:
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•
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In-Kind POP:
ETP retains its POP percentage (non-cash consideration) and also any additional cash fees in exchange for providing the services. ETP recognizes revenue for the non-cash consideration and cash fees at the time the services are performed.
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•
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Mixed POP:
ETP purchases NGLs from the producer and retains a portion of the residue gas as non-cash consideration for services provided. ETP 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 NGL’s ETP purchased and customer agreements (for the services provided related to the product that was returned to the customer). Given that these are hybrid agreements, ETP 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.
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Payment for services under these contracts are typically due the month after the services have been performed.
The performance obligations with respect to ETP’s midstream 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 statement of operations; therefore, identification of separate performance obligations would not impact the timing or geography of revenue recognition.
Certain contracts of ETP’s midstream operations 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, ETP defers 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.
ETP’s NGL and refined products transportation and services revenue
ETP’s NGL and refined products 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 ETP accepts 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 ETP’s NGL’s and other related hydrocarbons at market rates. These contracts were not affected by ASC 606.
ETP’s crude oil transportation and services revenue
ETP’s crude oil operations 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 ETP’s 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.
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 ETP accepts 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 ETP’s crude oil at market rates. These contracts were not affected by ASC 606.
ETP’s all other revenue
ETP’s other operations primarily include ETP’s 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. ETP also earns 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 related to these operations are recorded under the new standard.
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).
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 take-or-pay 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.
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.
There are typically no material obligations for returns or refunds. USAC’s standard contracts do not usually include material variable or 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.
USAC’s station installations revenue
USAC’s revenue from station installations is earned on stations USAC builds on behalf of, and sell to, its customers and such revenue is recognized over time as services are provided. A station typically consists of compressor equipment combined with other equipment ancillary to compression, such as slug catchers, pipe racks, tanks, dehydration units, valves, and control rooms, which together assist in the treating, processing, pressurization and transportation of natural gas. USAC’s performance enhances an asset that the customer controls and does not create an asset with alternative use to USAC. Revenue is recognized over time based on the progress-toward-completion method and progress is measured using the efforts-expended input method. In applying the efforts-expended input method, USAC uses the percentage of total completed workflows to date relative to estimated total workflows to determine the amount of revenue and profit to recognize for each contract. The amount of consideration USAC receives and revenue it recognizes varies in accordance with each contractual agreement negotiated with its customers.
The progress-toward-completion method of revenue recognition requires USAC to make estimates of contract revenues and costs to complete its projects. In making such estimates, management judgments are required to evaluate significant assumptions including the cost of materials and labor, expected labor productivity, the impact of potential variances in schedule completion, the amount of net contract revenues and the impact of any penalties, claims, change orders, or performance incentives.
USAC’s payment terms vary in accordance with each contractual agreement negotiated with its customers. The term between invoicing and when payment is due is not significant. USAC retains the right to payment for performance completed to date at any point during the contract term. There are no material obligations for returns, refunds, or warranties.
Lake Charles LNG revenue
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.
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. The Partnership recognizes a contract liability when the upfront payment is received and recognizes revenue over the term of the license. As of
June 30, 2018
, the Partnership had
$271 million
in deferred revenues representing the current value of our future performance obligations.
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:
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Balance at
January 1, 2018
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Balance at June 30, 2018
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Increase/ (Decrease)
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Contract Balances
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Contract Asset
|
$
|
51
|
|
|
$
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59
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|
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$
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8
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|
Accounts receivable from contracts with customers
|
445
|
|
|
487
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|
|
42
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|
Contract Liability
|
1
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|
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1
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—
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The amount of revenue recognized for the
three and six months ended
June 30, 2018
that was included in the deferred revenue liability balance as of January 1, 2018 was
$28 million
and
$63 million
, respectively.
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 contacts, 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 minimum volume of fuel 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
June 30, 2018
, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations is
$41.9 billion
and the Partnership expects to recognize this amount as revenue within the time bands illustrated below:
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2018 (remainder)
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2019
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2020
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Thereafter
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Total
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Revenue expected to be recognized on contracts with customers existing as of June 30, 2018
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$
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2,694
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|
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$
|
5,240
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|
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$
|
4,732
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|
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$
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29,258
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|
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$
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41,924
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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 three and six months ended
June 30, 2018
was
$3 million
and
$6 million
, respectively. 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:
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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.
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•
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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.
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•
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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.
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•
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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.
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•
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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.
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•
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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).
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•
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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.
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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 operations and operational gas sales on our interstate transportation and storage operations. These contracts are not designated as hedges for accounting purposes.
We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream operations whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes.
We utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes.
We use futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales and transportation costs in our retail marketing operations. These contracts are not designated as hedges for accounting purposes.
We use financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our transportation and storage operations’ and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing activities related to power and natural gas in our all other operations which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our transportation and storage operations, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy.
The following table details our outstanding commodity-related derivatives:
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June 30, 2018
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December 31, 2017
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Notional Volume
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Maturity
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Notional Volume
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Maturity
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Mark-to-Market Derivatives
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(Trading)
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Natural Gas (BBtu):
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Fixed Swaps/Futures
|
465
|
|
|
2018
|
|
1,078
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|
|
2018
|
Basis Swaps IFERC/NYMEX
(1)
|
102,328
|
|
|
2018-2020
|
|
48,510
|
|
|
2018-2020
|
Options – Puts
|
(3,043
|
)
|
|
2018
|
|
13,000
|
|
|
2018
|
Power (Megawatt):
|
|
|
|
|
|
|
|
Forwards
|
3,196,100
|
|
|
2018-2019
|
|
435,960
|
|
|
2018-2019
|
Futures
|
(42,768
|
)
|
|
2018
|
|
(25,760
|
)
|
|
2018
|
Options — Puts
|
(30,532
|
)
|
|
2018
|
|
(153,600
|
)
|
|
2018
|
Options — Calls
|
996,172
|
|
|
2018
|
|
137,600
|
|
|
2018
|
(Non-Trading)
|
|
|
|
|
|
|
|
Natural Gas (BBtu):
|
|
|
|
|
|
|
|
Basis Swaps IFERC/NYMEX
|
6,600
|
|
|
2018-2020
|
|
4,650
|
|
|
2018-2020
|
Swing Swaps IFERC
|
52,413
|
|
|
2018-2019
|
|
87,253
|
|
|
2018-2019
|
Fixed Swaps/Futures
|
5,460
|
|
|
2018-2019
|
|
(4,390
|
)
|
|
2018-2019
|
Forward Physical Contracts
|
(174,465
|
)
|
|
2018-2020
|
|
(145,105
|
)
|
|
2018-2020
|
NGL (MBbls) – Forwards/Swaps
|
(1,590
|
)
|
|
2018-2019
|
|
(2,493
|
)
|
|
2018-2019
|
Crude (MBbls) – Forwards/Swaps
|
44,335
|
|
|
2018-2019
|
|
9,237
|
|
|
2018-2019
|
Refined Products (MBbls) – Futures
|
(776
|
)
|
|
2018-2021
|
|
(3,901
|
)
|
|
2018-2019
|
Corn (thousand bushels)
|
(3,320
|
)
|
|
2018-2019
|
|
1,870
|
|
|
2018
|
Fair Value Hedging Derivatives
|
|
|
|
|
|
|
|
(Non-Trading)
|
|
|
|
|
|
|
|
Natural Gas (BBtu):
|
|
|
|
|
|
|
|
Basis Swaps IFERC/NYMEX
|
(21,475
|
)
|
|
2018
|
|
(39,770
|
)
|
|
2018
|
Fixed Swaps/Futures
|
(21,475
|
)
|
|
2018
|
|
(39,770
|
)
|
|
2018
|
Hedged Item — Inventory
|
21,475
|
|
|
2018
|
|
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 to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of anticipated debt issuances.
The following table summarizes our interest rate swaps outstanding, none of which were designated as hedges for accounting purposes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional Amount Outstanding
|
Term
|
|
Type
(1)
|
|
June 30, 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 based on a 3-month LIBOR and receive a fixed rate of 1.53%
|
|
1,200
|
|
|
1,200
|
|
March 2019
|
|
Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42%
|
|
300
|
|
|
300
|
|
|
|
(1)
|
Floating rates are based on 3-month LIBOR.
|
|
|
(2)
|
Represents the effective date. These forward-starting swaps have a term of 30 years with a mandatory termination date the same as the effective date.
|
Credit Risk
Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern ETP’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, motor fuel distributors, municipalities, utilities and midstream companies. ETP’s overall exposure may be affected positively or negatively by macroeconomic factors or regulatory changes that could 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 our pre-established credit limit with the counterparty. Margin deposits are returned to ETP on or about 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Derivative Instruments
|
|
Asset Derivatives
|
|
Liability Derivatives
|
|
June 30, 2018
|
|
December 31, 2017
|
|
June 30, 2018
|
|
December 31, 2017
|
Derivatives designated as hedging instruments:
|
|
|
|
|
|
|
|
Commodity derivatives (margin deposits)
|
$
|
—
|
|
|
$
|
14
|
|
|
$
|
(2
|
)
|
|
$
|
(2
|
)
|
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
|
Commodity derivatives (margin deposits)
|
307
|
|
|
262
|
|
|
(352
|
)
|
|
(281
|
)
|
Commodity derivatives
|
112
|
|
|
45
|
|
|
(430
|
)
|
|
(58
|
)
|
Interest rate derivatives
|
—
|
|
|
—
|
|
|
(147
|
)
|
|
(219
|
)
|
|
419
|
|
|
307
|
|
|
(929
|
)
|
|
(558
|
)
|
Total derivatives
|
$
|
419
|
|
|
$
|
321
|
|
|
$
|
(931
|
)
|
|
$
|
(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
|
|
|
Balance Sheet Location
|
|
June 30, 2018
|
|
December 31, 2017
|
|
June 30, 2018
|
|
December 31, 2017
|
Derivatives without offsetting agreements
|
|
Derivative liabilities
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(147
|
)
|
|
$
|
(219
|
)
|
Derivatives in offsetting agreements:
|
|
|
|
|
|
|
|
|
OTC contracts
|
|
Derivative assets (liabilities)
|
|
112
|
|
|
45
|
|
|
(430
|
)
|
|
(58
|
)
|
Broker cleared derivative contracts
|
|
Other current assets (liabilities)
|
|
307
|
|
|
276
|
|
|
(354
|
)
|
|
(283
|
)
|
Total gross derivatives
|
|
419
|
|
|
321
|
|
|
(931
|
)
|
|
(560
|
)
|
Offsetting agreements:
|
|
|
|
|
|
|
|
|
Counterparty netting
|
|
Derivative assets (liabilities)
|
|
(49
|
)
|
|
(21
|
)
|
|
49
|
|
|
21
|
|
Counterparty netting
|
|
Other current assets (liabilities)
|
|
(306
|
)
|
|
(263
|
)
|
|
306
|
|
|
263
|
|
Total net derivatives
|
|
$
|
64
|
|
|
$
|
37
|
|
|
$
|
(576
|
)
|
|
$
|
(276
|
)
|
We disclose the non-exchange traded financial derivative instruments as price risk management assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date.
The following tables summarize the amounts recognized with respect to our derivative financial instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Location of Gain/(Loss)
Recognized in Income
on Derivatives
|
|
Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
|
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Derivatives in fair value hedging relationships (including hedged item):
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
Cost of products sold
|
|
$
|
6
|
|
|
$
|
6
|
|
|
$
|
9
|
|
|
$
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Location of Gain/(Loss)
Recognized in Income
on Derivatives
|
|
Amount of Gain/(Loss) Recognized in Income on Derivatives
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
|
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
|
|
Commodity derivatives — Trading
|
|
Cost of products sold
|
|
$
|
16
|
|
|
$
|
15
|
|
|
$
|
33
|
|
|
$
|
26
|
|
Commodity derivatives — Non-trading
|
|
Cost of products sold
|
|
(295
|
)
|
|
17
|
|
|
(366
|
)
|
|
19
|
|
Interest rate derivatives
|
|
Gains (losses) on interest rate derivatives
|
|
20
|
|
|
(25
|
)
|
|
72
|
|
|
(20
|
)
|
Embedded derivatives
|
|
Other, net
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
Total
|
|
|
|
$
|
(259
|
)
|
|
$
|
7
|
|
|
$
|
(261
|
)
|
|
$
|
26
|
|
14.
RELATED PARTY TRANSACTIONS
Revenues reported in ETE’s consolidated statements of operations included sales with affiliates of
$120 million
and
$46 million
during the
three months ended
June 30, 2018
and
2017
, respectively, and
$222 million
and
$96 million
during the
six months ended
June 30, 2018
and
2017
, respectively.
15.
REPORTABLE SEGMENTS
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 USAC, including the consolidated operations of USAC;
|
|
|
•
|
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.
|
The Investment in USAC segment reflects the results of USAC beginning April 2018, the date that ETE obtained control of USAC. Also beginning April 2018, ETP holds an equity method investment in USAC, the equity in earnings from which is eliminated in ETE’s consolidated financial statements.
The CDM entities were consolidated subsidiaries of ETP prior to April 2018 and are consolidated subsidiaries of USAC beginning April 2018. Therefore, the results of the CDM entities are included in the Investment in ETP segment prior to April 2018 and in the Investment in USAC segment thereafter.
We define Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, losses on extinguishments of debt, gain on deconsolidation and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership’s proportionate ownership and amounts for less than wholly owned subsidiaries based on 100% of the subsidiaries’ results of operations.
The following tables present financial information by segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
2018
|
|
2017*
|
|
2018
|
|
2017*
|
Segment Adjusted EBITDA:
|
|
|
|
|
|
|
|
Investment in ETP
|
$
|
2,051
|
|
|
$
|
1,545
|
|
|
$
|
3,932
|
|
|
$
|
2,990
|
|
Investment in Sunoco LP
|
140
|
|
|
220
|
|
|
249
|
|
|
375
|
|
Investment in USAC
|
95
|
|
|
—
|
|
|
95
|
|
|
—
|
|
Investment in Lake Charles LNG
|
45
|
|
|
44
|
|
|
88
|
|
|
88
|
|
Corporate and Other
|
(9
|
)
|
|
(9
|
)
|
|
(8
|
)
|
|
(22
|
)
|
Adjustments and Eliminations
|
(60
|
)
|
|
(83
|
)
|
|
(92
|
)
|
|
(137
|
)
|
Total
|
2,262
|
|
|
1,717
|
|
|
4,264
|
|
|
3,294
|
|
Depreciation, depletion and amortization
|
(694
|
)
|
|
(607
|
)
|
|
(1,359
|
)
|
|
(1,235
|
)
|
Interest expense, net of interest capitalized
|
(510
|
)
|
|
(477
|
)
|
|
(976
|
)
|
|
(950
|
)
|
Impairment losses
|
—
|
|
|
(89
|
)
|
|
—
|
|
|
(89
|
)
|
Gains (losses) on interest rate derivatives
|
20
|
|
|
(25
|
)
|
|
72
|
|
|
(20
|
)
|
Non-cash compensation expense
|
(32
|
)
|
|
(20
|
)
|
|
(55
|
)
|
|
(47
|
)
|
Unrealized gains (losses) on commodity risk management activities
|
(265
|
)
|
|
29
|
|
|
(352
|
)
|
|
98
|
|
Losses on extinguishments of debt
|
—
|
|
|
—
|
|
|
(106
|
)
|
|
(25
|
)
|
Inventory valuation adjustments
|
32
|
|
|
(29
|
)
|
|
57
|
|
|
(42
|
)
|
Equity in earnings of unconsolidated affiliates
|
92
|
|
|
49
|
|
|
171
|
|
|
136
|
|
Adjusted EBITDA related to unconsolidated affiliates
|
(168
|
)
|
|
(164
|
)
|
|
(324
|
)
|
|
(349
|
)
|
Adjusted EBITDA related to discontinued operations
|
5
|
|
|
(72
|
)
|
|
25
|
|
|
(103
|
)
|
Other, net
|
(15
|
)
|
|
35
|
|
|
26
|
|
|
47
|
|
Income from continuing operations before income tax expense
|
727
|
|
|
347
|
|
|
1,443
|
|
|
715
|
|
Income tax expense from continuing operations
|
(68
|
)
|
|
(33
|
)
|
|
(58
|
)
|
|
(71
|
)
|
Income from continuing operations
|
659
|
|
|
314
|
|
|
1,385
|
|
|
644
|
|
Loss from discontinued operations, net of income taxes
|
(26
|
)
|
|
(193
|
)
|
|
(263
|
)
|
|
(204
|
)
|
Net income
|
$
|
633
|
|
|
$
|
121
|
|
|
$
|
1,122
|
|
|
$
|
440
|
|
* As adjusted. See Note 1.
|
|
|
|
|
|
|
|
|
|
June 30, 2018
|
|
December 31, 2017
|
Assets:
|
|
|
|
Investment in ETP
|
$
|
78,570
|
|
|
$
|
77,965
|
|
Investment in Sunoco LP
|
5,006
|
|
|
8,344
|
|
Investment in USAC
|
3,785
|
|
|
—
|
|
Investment in Lake Charles LNG
|
1,710
|
|
|
1,646
|
|
Corporate and Other
|
585
|
|
|
598
|
|
Adjustments and Eliminations
|
(2,239
|
)
|
|
(2,307
|
)
|
Total assets
|
$
|
87,417
|
|
|
$
|
86,246
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
2018
|
|
2017*
|
|
2018
|
|
2017*
|
Revenues:
|
|
|
|
|
|
|
|
Investment in ETP:
|
|
|
|
|
|
|
|
Revenues from external customers
|
$
|
9,298
|
|
|
$
|
6,485
|
|
|
$
|
17,383
|
|
|
$
|
13,292
|
|
Intersegment revenues
|
112
|
|
|
91
|
|
|
307
|
|
|
179
|
|
|
9,410
|
|
|
6,576
|
|
|
17,690
|
|
|
13,471
|
|
Investment in Sunoco LP:
|
|
|
|
|
|
|
|
Revenues from external customers
|
4,606
|
|
|
2,892
|
|
|
8,354
|
|
|
5,697
|
|
Intersegment revenues
|
1
|
|
|
—
|
|
|
2
|
|
|
3
|
|
|
4,607
|
|
|
2,892
|
|
|
8,356
|
|
|
5,700
|
|
Investment in USAC:
|
|
|
|
|
|
|
|
Revenues from external customers
|
165
|
|
|
—
|
|
|
165
|
|
|
—
|
|
Intersegment revenues
|
2
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
167
|
|
|
—
|
|
|
167
|
|
|
—
|
|
Investment in Lake Charles LNG:
|
|
|
|
|
|
|
|
Revenues from external customers
|
49
|
|
|
50
|
|
|
98
|
|
|
99
|
|
|
|
|
|
|
|
|
|
Adjustments and Eliminations
|
(115
|
)
|
|
(91
|
)
|
|
(311
|
)
|
|
(182
|
)
|
Total revenues
|
$
|
14,118
|
|
|
$
|
9,427
|
|
|
$
|
26,000
|
|
|
$
|
19,088
|
|
* As adjusted. See Note 1.
The following tables provide revenues, grouped by similar products and services, for our reportable segments. These amounts include intersegment revenues for transactions between ETP, Sunoco LP, USAC and Lake Charles LNG.
Investment in ETP
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
2018
|
|
2017*
|
|
2018
|
|
2017*
|
Intrastate transportation and storage
|
$
|
761
|
|
|
$
|
699
|
|
|
$
|
1,578
|
|
|
$
|
1,467
|
|
Interstate transportation and storage
|
323
|
|
|
201
|
|
|
636
|
|
|
432
|
|
Midstream
|
594
|
|
|
633
|
|
|
1,034
|
|
|
1,198
|
|
NGL and refined products transportation and services
|
2,472
|
|
|
1,767
|
|
|
4,930
|
|
|
3,885
|
|
Crude oil transportation and services
|
4,789
|
|
|
2,460
|
|
|
8,520
|
|
|
5,035
|
|
All Other
|
471
|
|
|
816
|
|
|
992
|
|
|
1,454
|
|
Total revenues
|
9,410
|
|
|
6,576
|
|
|
17,690
|
|
|
13,471
|
|
Less: Intersegment revenues
|
112
|
|
|
91
|
|
|
307
|
|
|
179
|
|
Revenues from external customers
|
$
|
9,298
|
|
|
$
|
6,485
|
|
|
$
|
17,383
|
|
|
$
|
13,292
|
|
* As adjusted. See Note 1.
The amounts included in ETP’s NGL and refined products transportation and services operation and the crude oil transportation and services operation have been retrospectively adjusted as a result of the Sunoco Logistics Merger.
Investment in Sunoco LP
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Fuel distribution and marketing
|
$
|
4,350
|
|
|
$
|
2,318
|
|
|
$
|
7,489
|
|
|
$
|
4,615
|
|
All other
|
257
|
|
|
574
|
|
|
867
|
|
|
1,085
|
|
Total revenues
|
4,607
|
|
|
2,892
|
|
|
8,356
|
|
|
5,700
|
|
Less: Intersegment revenues
|
1
|
|
|
—
|
|
|
2
|
|
|
3
|
|
Revenues from external customers
|
$
|
4,606
|
|
|
$
|
2,892
|
|
|
$
|
8,354
|
|
|
$
|
5,697
|
|
Investment in USAC
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Contract operations
|
$
|
160
|
|
|
$
|
—
|
|
|
$
|
160
|
|
|
$
|
—
|
|
Retail parts and services
|
6
|
|
|
—
|
|
|
6
|
|
|
—
|
|
Station installations revenue
|
1
|
|
|
—
|
|
|
1
|
|
|
—
|
|
Total revenues
|
167
|
|
|
—
|
|
|
167
|
|
|
—
|
|
Less: Intersegment revenues
|
2
|
|
|
—
|
|
|
2
|
|
|
—
|
|
Revenues from external customers
|
$
|
165
|
|
|
$
|
—
|
|
|
$
|
165
|
|
|
$
|
—
|
|
USAC’s revenues for all periods presented were related to the compression services business.
Investment in Lake Charles LNG
Lake Charles LNG’s revenues for all periods presented were related to LNG terminalling.
16.
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
(unaudited)
|
|
|
|
|
|
|
|
|
|
June 30, 2018
|
|
December 31, 2017
|
ASSETS
|
|
|
|
Current assets:
|
|
|
|
Cash and cash equivalents
|
$
|
1
|
|
|
$
|
1
|
|
Accounts receivable from related companies
|
58
|
|
|
65
|
|
Other current assets
|
—
|
|
|
1
|
|
Total current assets
|
59
|
|
|
67
|
|
Property, plant and equipment, net
|
27
|
|
|
27
|
|
Advances to and investments in unconsolidated affiliates
|
6,042
|
|
|
6,082
|
|
Goodwill
|
9
|
|
|
9
|
|
Other non-current assets, net
|
7
|
|
|
8
|
|
Total assets
|
$
|
6,144
|
|
|
$
|
6,193
|
|
LIABILITIES AND PARTNERS’ DEFICIT
|
|
|
|
Current liabilities:
|
|
|
|
Interest payable
|
$
|
70
|
|
|
$
|
66
|
|
Accrued and other current liabilities
|
8
|
|
|
4
|
|
Total current liabilities
|
78
|
|
|
70
|
|
Long-term debt, less current maturities
|
6,472
|
|
|
6,700
|
|
Long-term notes payable – related companies
|
702
|
|
|
617
|
|
Other non-current liabilities
|
2
|
|
|
2
|
|
Commitments and contingencies
|
|
|
|
Partners’ deficit:
|
|
|
|
Limited Partners:
|
|
|
|
Series A Convertible Preferred Units
|
—
|
|
|
450
|
|
Common Unitholders
|
(1,106
|
)
|
|
(1,643
|
)
|
General Partner
|
(4
|
)
|
|
(3
|
)
|
Total partners’ deficit
|
(1,110
|
)
|
|
(1,196
|
)
|
Total liabilities and partners’ deficit
|
$
|
6,144
|
|
|
$
|
6,193
|
|
STATEMENTS OF OPERATIONS
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES
|
$
|
(9
|
)
|
|
$
|
(9
|
)
|
|
$
|
(11
|
)
|
|
$
|
(22
|
)
|
OTHER INCOME (EXPENSE):
|
|
|
|
|
|
|
|
Interest expense, net
|
(90
|
)
|
|
(86
|
)
|
|
(176
|
)
|
|
(169
|
)
|
Equity in earnings of unconsolidated affiliates
|
454
|
|
|
308
|
|
|
902
|
|
|
669
|
|
Losses on extinguishments of debt
|
—
|
|
|
—
|
|
|
—
|
|
|
(25
|
)
|
Other, net
|
—
|
|
|
(1
|
)
|
|
3
|
|
|
(2
|
)
|
NET INCOME
|
355
|
|
|
212
|
|
|
718
|
|
|
451
|
|
Convertible Unitholders’ interest in income
|
12
|
|
|
8
|
|
|
33
|
|
|
14
|
|
General Partner’s interest in net income
|
1
|
|
|
—
|
|
|
2
|
|
|
1
|
|
Limited Partners’ interest in net income
|
$
|
342
|
|
|
$
|
204
|
|
|
$
|
683
|
|
|
$
|
436
|
|
STATEMENTS OF CASH FLOWS
(unaudited)
|
|
|
|
|
|
|
|
|
|
Six Months Ended
June 30,
|
|
2018
|
|
2017
|
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES
|
$
|
626
|
|
|
$
|
405
|
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
Contributions to unconsolidated affiliate
|
(250
|
)
|
|
(861
|
)
|
Capital expenditures
|
—
|
|
|
(1
|
)
|
Contributions in aid of construction costs
|
—
|
|
|
6
|
|
Sunoco LP Series A Preferred Units redemption
|
303
|
|
|
—
|
|
Net cash provided by (used in) investing activities
|
53
|
|
|
(856
|
)
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
Proceeds from borrowings
|
355
|
|
|
2,072
|
|
Principal payments on debt
|
(587
|
)
|
|
(1,740
|
)
|
Proceeds from affiliate
|
85
|
|
|
87
|
|
Distributions to partners
|
(532
|
)
|
|
(501
|
)
|
Units issued for cash
|
—
|
|
|
568
|
|
Debt issuance costs
|
—
|
|
|
(35
|
)
|
Net cash provided by (used in) financing activities
|
(679
|
)
|
|
451
|
|
CHANGE IN CASH AND CASH EQUIVALENTS
|
—
|
|
|
—
|
|
CASH AND CASH EQUIVALENTS, beginning of period
|
1
|
|
|
2
|
|
CASH AND CASH EQUIVALENTS, end of period
|
$
|
1
|
|
|
$
|
2
|
|