UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
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August 5, 2015 |
Date of Report (Date of earliest event reported) |
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ENERGY TRANSFER PARTNERS, L.P. |
(Exact name of Registrant as specified in its charter) |
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Delaware | 1-11727 | 73-1493906 |
(State or other jurisdiction of incorporation) | (Commission File Number) | (IRS Employer Identification No.) |
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3738 Oak Lawn Avenue,
Dallas, Texas 75219 |
(Address of principal executive offices) (Zip Code) |
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(214) 981-0700 |
(Registrant’s telephone number, including area code) |
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
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¨ | Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) |
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¨ | Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) |
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¨ | Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) |
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¨ | Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
Item 2.02. Results of Operations and Financial Condition.
On August 5, 2015, Energy Transfer Partners, L.P. (the “Partnership”) issued a press release announcing its financial and operating results for the second quarter ended June 30, 2015. A copy of this press release is furnished as Exhibit 99.1 to this report and is incorporated herein by reference.
In accordance with General Instruction B.2 of Form 8-K, the information set forth in this Item 2.02 and in the attached exhibit shall be deemed to be “furnished” and not be deemed to be “filed” for purposes of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).
Item 9.01. Financial Statements and Exhibits.
(d) Exhibits. In accordance with General Instruction B.2 of Form 8-K, the information set forth in the attached Exhibit 99.1 is deemed to be “furnished” and shall not be deemed to be “filed” for purposes of Section 18 of the Exchange Act.
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Exhibit Number | | Description of the Exhibit |
99.1 | | Energy Transfer Partners, L.P. Press Release dated August 5, 2015 |
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
Energy Transfer Partners, L.P.
By: Energy Transfer Partners GP, L.P., its general partner
By: Energy Transfer Partners, L.L.C., its general partner
By: /s/ Thomas E. Long
Thomas E. Long
Chief Financial Officer
Dated: August 5, 2015
EXHIBIT INDEX
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Exhibit Number | | Description of the Exhibit |
99.1 | | Energy Transfer Partners, L.P. Press Release dated August 5, 2015 |
ENERGY TRANSFER PARTNERS
REPORTS SECOND QUARTER RESULTS
Dallas – August 5, 2015 – Energy Transfer Partners, L.P. (NYSE: ETP) (“ETP” or the “Partnership”) today reported its financial results for the quarter ended June 30, 2015. Adjusted EBITDA for ETP for the three months ended June 30, 2015 totaled $1.49 billion, an increase of $95 million compared to the same period last year. Distributable Cash Flow attributable to the partners of ETP, as adjusted, for the three months ended June 30, 2015 totaled $894 million, an increase of $149 million compared to the same period last year. Income from continuing operations for the three months ended June 30, 2015 was $839 million, an increase of $334 million compared to the same period last year.
On April 30, 2015, a wholly-owned subsidiary of the Partnership merged with Regency Energy Partners LP (“Regency”), with Regency continuing as the surviving entity (the “Regency Merger”). Each Regency common unit and Class F unit was converted into the right to receive 0.4124 Partnership common units. ETP issued 172.2 million Partnership common units to Regency unitholders, including 15.5 million units issued to Partnership subsidiaries. The 1.9 million outstanding Regency series A preferred units were converted into corresponding new Partnership Series A Preferred Units on a one-for-one basis.
In connection with the Regency Merger, Energy Transfer Equity, L.P. (“ETE”) will reduce the incentive distributions it receives from the Partnership by a total of $320 million over a five-year period. The IDR subsidy in connection with the Regency Merger will be $80 million in the first year post-closing and $60 million per year for the following four years.
The Regency Merger was a combination of entities under common control; therefore Regency’s assets and liabilities were not adjusted. The Partnership’s consolidated financial statements have been retrospectively adjusted to reflect consolidation of Regency for all prior periods subsequent to May 26, 2010 (the date ETE acquired Regency’s general partner). Predecessor equity included on the consolidated financial statements represents Regency’s equity prior to the Regency Merger.
In July 2015, ETP announced an increase in its quarterly distribution to $1.035 per Partnership common unit ($4.14 annualized) for the quarter ended June 30, 2015, representing an increase of $0.32 per Partnership common unit on an annualized basis, or 8.4%, compared to the second quarter of 2014. For the quarter ended June 30, 2015, ETP’s distribution coverage ratio was 1.03x, and its distributable cash flow per common unit was $1.23.
ETP’s other recent key accomplishments include the following:
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• | In July 2015, ETP, Sunoco Logistics Partners L.P. (“Sunoco Logistics”) and Phillips 66 announced they have formed a joint venture to construct the Bayou Bridge pipeline that will deliver crude oil from the Phillips 66 and Sunoco Logistics terminals in Nederland, Texas to Lake Charles, Louisiana. Phillips 66 holds a 40% interest in the joint venture and ETP and Sunoco Logistics each hold a 30% interest. |
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• | In July 2015, Sunoco LP acquired 100% of Susser Holdings Corporation (“Susser”) from ETP in a transaction valued at $1.93 billion. Sunoco LP paid approximately $997 million in cash (including payment for working capital) and issued 22 million Sunoco LP common units, valued at approximately $967 million, to ETP. In addition, there will be an exchange for 11 million Sunoco LP units owned by Susser for another 11 million new Sunoco LP units to a subsidiary of ETP. |
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• | In July 2015, ETE entered into an exchange and repurchase agreement with ETP, pursuant to which ETE would acquire 100% of the membership interests of Sunoco GP LLC, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from ETP, in exchange for the repurchase of 21 million ETP common units owned by ETE. In connection with ETP’s 2014 acquisition of Susser, ETE agreed to provide ETP a $35 million annual IDR subsidy for 10 years, which would terminate upon ETE’s acquisition of Sunoco GP. In connection with the exchange and repurchase, ETE agreed to provide ETP a $35 million annual IDR subsidy for two years. Following this transaction, Sunoco LP will no longer be consolidated for accounting purposes by ETP. This transaction is expected to close in August 2015. |
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• | During the second quarter 2015, progress on Lake Charles LNG Export Company, LLC (“Lake Charles LNG”), an entity owned 60% by ETE and 40% by ETP, continued as we purchased the land for the project from Alcoa Inc. and as we received the draft Environmental Impact Statement (“EIS”) and filed the additional data and information requests required thereunder. We have also continued our work with the short-listed EPC contractors as we continue to refine the cost structure for the project. We expect to receive the final EIS next week on August 14th. The next milestone after that will be the Federal Energy Regulatory Commission (“FERC”) authorization. With the expected emphasis on capital discipline and overall cost, we |
continue to believe that Lake Charles LNG is one of the most attractive pre-final investment decision (“FID”) projects for both Royal Dutch Shell plc and BG Group plc and that as a result, we remain on track to sanction FID of the project in 2016.
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• | Subsequent to the Regency Merger, ETP has undertaken a series of liability management steps, including (i) the repayment of $2.3 billion under Regency’s credit facility and cancellation of the facility upon the closing of the Regency Merger, (ii) the redemption in June 2015 of all of the outstanding $499 million aggregate principal amount of Regency’s 8.375% senior notes due 2019, (iii) the issuance in June 2015 of $3.0 billion aggregate principal amount of ETP senior notes with coupons ranging from 2.50% to 6.125% and maturities ranging from 2018 to 2045, and (iv) the repayment of outstanding borrowings under the ETP Credit Facility. |
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• | As of June 30, 2015, the ETP Credit Facility had no outstanding borrowings and its credit ratio, as defined by the credit agreement, was 4.59x. |
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• | In the second quarter of 2015, ETP issued 8.9 million common units through its at-the-market equity program, generating net proceeds of $493 million. |
An analysis of ETP’s segment results and other supplementary data is provided after the financial tables shown below. ETP has scheduled a conference call for 8:00 a.m. Central Time, Thursday, August 6, 2015 to discuss the second quarter 2015 results. The conference call will be broadcast live via an internet web cast, which can be accessed through www.energytransfer.com and will also be available for replay on ETP’s web site for a limited time.
Energy Transfer Partners, L.P. (NYSE: ETP) is a master limited partnership owning and operating one of the largest and most diversified portfolios of energy assets in the United States. ETP’s subsidiaries include Panhandle Eastern Pipe Line Company, LP (the successor of Southern Union Company) and Lone Star NGL LLC, which owns and operates natural gas liquids storage, fractionation and transportation assets. In total, ETP currently owns and operates more than 62,000 miles of natural gas and natural gas liquids pipelines. ETP also owns the general partner, 100% of the incentive distribution rights, and approximately 67.1 million common units in Sunoco Logistics Partners L.P. (NYSE: SXL), which operates a geographically diverse portfolio of crude oil and refined products pipelines, terminalling and crude oil acquisition and marketing assets. ETP owns 100% of Sunoco, Inc. Additionally, ETP owns the general partner, 100% of the incentive distribution rights and approximately 66% of the limited partner interests in Sunoco LP (formerly Susser Petroleum Partners LP) (NYSE: SUN), a wholesale fuel distributor and convenience store operator. ETP’s general partner is owned by ETE. For more information, visit the Energy Transfer Partners, L.P. web site at www.energytransfer.com.
Energy Transfer Equity, L.P. (NYSE: ETE) is a master limited partnership which owns the general partner and 100% of the incentive distribution rights (IDRs) of Energy Transfer Partners, L.P. (NYSE: ETP) and approximately 23.6 million ETP Common Units and 81.0 million ETP Class H Units, which track 90% of the underlying economics of the general partner interest and the IDRs of Sunoco Logistics Partners L.P. (NYSE: SXL), and 100 ETP Class I Units. On a consolidated basis, ETE’s family of companies owns and operates approximately 71,000 miles of natural gas, natural gas liquids, refined products, and crude oil pipelines. For more information, visit the Energy Transfer Equity, L.P. web site at www.energytransfer.com.
Sunoco Logistics Partners L.P. (NYSE: SXL) is a master limited partnership that owns and operates a logistics business consisting of a geographically diverse portfolio of complementary crude oil, refined products, and natural gas liquids pipeline, terminalling and acquisition and marketing assets which are used to facilitate the purchase and sale of crude oil, refined products, and natural gas liquids. Sunoco Logistics’ general partner is owned by Energy Transfer Partners, L.P. (NYSE: ETP). For more information, visit the Sunoco Logistics Partners, L.P. web site at www.sunocologistics.com.
Sunoco LP (NYSE: SUN) is a growth-oriented master limited partnership that primarily distributes motor fuel to convenience stores, independent dealers, commercial customers and distributors. Sunoco LP also operates more than 830 convenience stores and retail fuel sites. Sunoco LP conducts its business through wholly-owned subsidiaries, as well as through its 31.58% interest in Sunoco LLC, in partnership with its parent company, ETP. Sunoco LP’s general partner is owned by Energy Transfer Partners, L.P. (NYSE: ETP). For more information, visit the Sunoco LP web site at www.sunocolp.com.
Forward-Looking Statements
This press release may include certain statements concerning expectations for the future that are forward-looking statements as defined by federal law. Such forward-looking statements are subject to a variety of known and unknown risks, uncertainties, and other factors that are difficult to predict and many of which are beyond management’s control. An extensive list of factors that can affect future results are discussed in the Partnership’s Annual Reports on Form 10-K and other documents filed from time to time with the Securities and Exchange Commission. The Partnership undertakes no obligation to update or revise any forward-looking statement to reflect new information or events.
The information contained in this press release is available on our web site at www.energytransfer.com.
Contacts
Investor Relations:
Energy Transfer
Brent Ratliff
214-981-0700 (office)
Energy Transfer
Lyndsay Hannah
214-840-5477 (office)
Media Relations:
Vicki Granado
Granado Communications Group
214-599-8785 (office)
214-498-9272 (cell)
ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(In millions)
(unaudited)
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| June 30,
2015 | | December 31,
2014 |
ASSETS | | | |
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CURRENT ASSETS | $ | 7,259 |
| | $ | 6,043 |
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PROPERTY, PLANT AND EQUIPMENT, net | 42,857 |
| | 38,907 |
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ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES | 3,667 |
| | 3,760 |
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NON-CURRENT DERIVATIVE ASSETS | 1 |
| | 10 |
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OTHER NON-CURRENT ASSETS, net | 801 |
| | 786 |
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INTANGIBLE ASSETS, net | 5,526 |
| | 5,526 |
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GOODWILL | 7,440 |
| | 7,642 |
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Total assets | $ | 67,551 |
| | $ | 62,674 |
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LIABILITIES AND EQUITY | | | |
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CURRENT LIABILITIES | $ | 5,161 |
| | $ | 6,684 |
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LONG-TERM DEBT, less current maturities | 29,058 |
| | 24,973 |
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NON-CURRENT DERIVATIVE LIABILITIES | 109 |
| | 154 |
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DEFERRED INCOME TAXES | 4,104 |
| | 4,246 |
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OTHER NON-CURRENT LIABILITIES | 1,220 |
| | 1,258 |
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COMMITMENTS AND CONTINGENCIES | | | |
SERIES A PREFERRED UNITS | 33 |
| | 33 |
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REDEEMABLE NONCONTROLLING INTERESTS | 15 |
| | 15 |
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EQUITY: | | | |
Total partners’ capital | 21,313 |
| | 12,070 |
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Noncontrolling interest | 6,538 |
| | 5,153 |
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Predecessor equity | — |
| | 8,088 |
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Total equity | 27,851 |
| | 25,311 |
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Total liabilities and equity | $ | 67,551 |
| | $ | 62,674 |
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ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per unit data)
(unaudited)
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| Three Months Ended
June 30, | | Six Months Ended
June 30, |
| 2015 | | 2014 | | 2015 | | 2014 |
REVENUES | $ | 11,540 |
| | $ | 14,088 |
| | $ | 21,866 |
| | $ | 27,115 |
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COSTS AND EXPENSES | | | | | | | |
Cost of products sold | 9,338 |
| | 12,352 |
| | 17,825 |
| | 23,794 |
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Operating expenses | 651 |
| | 417 |
| | 1,270 |
| | 831 |
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Depreciation, depletion and amortization | 501 |
| | 436 |
| | 980 |
| | 796 |
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Selling, general and administrative | 162 |
| | 115 |
| | 295 |
| | 220 |
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Total costs and expenses | 10,652 |
| | 13,320 |
| | 20,370 |
| | 25,641 |
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OPERATING INCOME | 888 |
| | 768 |
| | 1,496 |
| | 1,474 |
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OTHER INCOME (EXPENSE) | | | | | | | |
Interest expense, net of interest capitalized | (336 | ) | | (295 | ) | | (646 | ) | | (569 | ) |
Equity in earnings of unconsolidated affiliates | 117 |
| | 77 |
| | 174 |
| | 181 |
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Gain on sale of AmeriGas common units | — |
| | 93 |
| | — |
| | 163 |
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Gains (losses) on interest rate derivatives | 127 |
| | (46 | ) | | 50 |
| | (48 | ) |
Other, net | (16 | ) | | (21 | ) | | (9 | ) | | (21 | ) |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE | 780 |
| | 576 |
| | 1,065 |
| | 1,180 |
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Income tax expense (benefit) from continuing operations | (59 | ) | | 71 |
| | (42 | ) | | 216 |
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INCOME FROM CONTINUING OPERATIONS | 839 |
| | 505 |
| | 1,107 |
| | 964 |
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Income from discontinued operations | — |
| | 42 |
| | — |
| | 66 |
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NET INCOME | 839 |
| | 547 |
| | 1,107 |
| | 1,030 |
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Less: Net income attributable to noncontrolling interest | 212 |
| | 87 |
| | 206 |
| | 141 |
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Less: Net income (loss) attributable to predecessor | (27 | ) | | (11 | ) | | (34 | ) | | 3 |
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NET INCOME ATTRIBUTABLE TO PARTNERS | 654 |
| | 471 |
| | 935 |
| | 886 |
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General Partner’s interest in net income | 260 |
| | 125 |
| | 502 |
| | 238 |
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Class H Unitholder’s interest in net income | 64 |
| | 51 |
| | 118 |
| | 100 |
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Class I Unitholder’s interest in net income | 32 |
| | — |
| | 65 |
| | — |
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Common Unitholders’ interest in net income | $ | 298 |
| | $ | 295 |
| | $ | 250 |
| | $ | 548 |
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INCOME FROM CONTINUING OPERATIONS PER COMMON UNIT: | | | | | | | |
Basic | $ | 0.67 |
| | $ | 0.79 |
| | $ | 0.63 |
| | $ | 1.47 |
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Diluted | $ | 0.67 |
| | $ | 0.79 |
| | $ | 0.63 |
| | $ | 1.47 |
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NET INCOME PER COMMON UNIT: | | | | | | | |
Basic | $ | 0.67 |
| | $ | 0.92 |
| | $ | 0.63 |
| | $ | 1.67 |
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Diluted | $ | 0.67 |
| | $ | 0.92 |
| | $ | 0.63 |
| | $ | 1.67 |
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WEIGHTED AVERAGE NUMBER OF COMMON UNITS OUTSTANDING: | | | | | | | |
Basic | 434.8 |
| | 318.5 |
| | 379.6 |
| | 321.4 |
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Diluted | 436.3 |
| | 319.5 |
| | 381.2 |
| | 322.4 |
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SUPPLEMENTAL INFORMATION
(Tabular dollar amounts in millions)
(unaudited)
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| Three Months Ended
June 30, | | Six Months Ended
June 30, |
| 2015 | | 2014 | | 2015 | | 2014 |
Reconciliation of net income to Adjusted EBITDA and Distributable Cash Flow (a): | | | | | | | |
Net income | $ | 839 |
| | $ | 547 |
| | $ | 1,107 |
| | $ | 1,030 |
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Interest expense, net of interest capitalized | 336 |
| | 295 |
| | 646 |
| | 569 |
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Gain on sale of AmeriGas common units | — |
| | (93 | ) | | — |
| | (163 | ) |
Income tax expense (benefit) from continuing operations (b) | (59 | ) | | 71 |
| | (42 | ) | | 216 |
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Depreciation, depletion and amortization | 501 |
| | 436 |
| | 980 |
| | 796 |
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Non-cash compensation expense | 23 |
| | 15 |
| | 43 |
| | 32 |
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(Gains) losses on interest rate derivatives | (127 | ) | | 46 |
| | (50 | ) | | 48 |
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Unrealized losses on commodity risk management activities | 42 |
| | 1 |
| | 119 |
| | 33 |
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Inventory valuation adjustments | (184 | ) | | (20 | ) | | (150 | ) | | (34 | ) |
Equity in earnings of unconsolidated affiliates | (117 | ) | | (77 | ) | | (174 | ) | | (181 | ) |
Adjusted EBITDA related to unconsolidated affiliates | 215 |
| | 190 |
| | 361 |
| | 400 |
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Other, net | 19 |
| | (18 | ) | | 14 |
| | (15 | ) |
Adjusted EBITDA (consolidated) | 1,488 |
| | 1,393 |
| | 2,854 |
| | 2,731 |
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Adjusted EBITDA related to unconsolidated affiliates | (215 | ) | | (190 | ) | | (361 | ) | | (400 | ) |
Distributions from unconsolidated affiliates (c) | 125 |
| | 123 |
| | 236 |
| | 232 |
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Interest expense, net of interest capitalized | (336 | ) | | (295 | ) | | (646 | ) | | (569 | ) |
Amortization included in interest expense | (8 | ) | | (19 | ) | | (21 | ) | | (33 | ) |
Current income tax (expense) benefit from continuing operations | 112 |
| | (74 | ) | | 121 |
| | (327 | ) |
Transaction-related income taxes (d) | — |
| | 41 |
| | — |
| | 347 |
|
Maintenance capital expenditures | (100 | ) | | (74 | ) | | (184 | ) | | (138 | ) |
Other, net | 3 |
| | (1 | ) | | 7 |
| | — |
|
Distributable Cash Flow (consolidated) | 1,069 |
| | 904 |
| | 2,006 |
| | 1,843 |
|
Distributable Cash Flow attributable to SXL (100%) | (264 | ) | | (222 | ) | | (424 | ) | | (379 | ) |
Distributions from SXL to ETP | 98 |
| | 68 |
| | 188 |
| | 130 |
|
Distributable Cash Flow attributable to Sunoco LP (100%) | (35 | ) | | — |
| | (68 | ) | | — |
|
Distributions from Sunoco LP to ETP | 12 |
| | — |
| | 24 |
| | — |
|
Distributable cash flow attributable to noncontrolling interest in Edwards Lime Gathering LLC | (5 | ) | | (5 | ) | | (10 | ) | | (9 | ) |
Distributable Cash Flow attributable to the partners of ETP | 875 |
| | 745 |
| | 1,716 |
| | 1,585 |
|
Transaction-related expenses | 19 |
| | — |
| | 30 |
| | — |
|
Distributable Cash Flow attributable to the partners of ETP, as adjusted | $ | 894 |
| | $ | 745 |
| | $ | 1,746 |
| | $ | 1,585 |
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| | | | | | | |
Distributions to the partners of ETP (e): | | | | | | | |
Limited Partners: | | | | | | | |
Common Units held by public | $ | 485 |
| | $ | 280 |
| | $ | 950 |
| | $ | 546 |
|
Common Units held by ETE | 24 |
| | 29 |
| | 48 |
| | 58 |
|
Class H Units held by ETE and ETE Common Holdings, LLC (“ETE Holdings”) (f) | 62 |
| | 53 |
| | 118 |
| | 103 |
|
General Partner interests held by ETE | 7 |
| | 5 |
| | 15 |
| | 10 |
|
Incentive Distribution Rights (“IDRs”) held by ETE | 317 |
| | 178 |
| | 617 |
| | 346 |
|
IDR relinquishments net of Class I Unit distributions | (28 | ) | | (58 | ) | | (55 | ) | | (115 | ) |
Total distributions to be paid to the partners of ETP | $ | 867 |
| | $ | 487 |
| | $ | 1,693 |
| | $ | 948 |
|
Distribution coverage ratio (g) | 1.03x |
| | 1.53x |
| | 1.03x |
| | 1.67x |
|
| | | | | | | |
Distributable Cash Flow per Common Unit (h) | $ | 1.23 |
| | $ | 1.78 |
| | $ | 2.77 |
| | $ | 3.86 |
|
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(a) | Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures used by industry analysts, investors, lenders, and rating agencies to assess the financial performance and the operating results of ETP’s fundamental business activities and should not be considered in isolation or as a substitute for net income, income from operations, cash flows from operating activities, or other GAAP measures. |
There are material limitations to using measures such as Adjusted EBITDA and Distributable Cash Flow, including the difficulty associated with using either as the sole measure to compare the results of one company to another, and the inability to analyze certain significant items that directly affect a company’s net income or loss or cash flows. In addition, our calculations of Adjusted EBITDA and Distributable Cash Flow may not be consistent with similarly titled measures of other companies and should be viewed in conjunction with measurements that are computed in accordance with GAAP, such as gross margin, operating income, net income, and cash flow from operating activities.
Definition of Adjusted EBITDA
ETP defines Adjusted EBITDA as total partnership earnings before interest, taxes, depreciation, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Adjusted EBITDA reflects amounts for less than wholly-owned subsidiaries based on 100% of the subsidiaries’ results of operations and for unconsolidated affiliates based on ETP’s proportionate ownership.
Adjusted EBITDA is used by management to determine our operating performance and, along with other financial and volumetric data, as internal measures for setting annual operating budgets, assessing financial performance of our numerous business locations, as a measure for evaluating targeted businesses for acquisition and as a measurement component of incentive compensation.
Definition of Distributable Cash Flow
ETP defines Distributable Cash Flow as net income, adjusted for certain non-cash items, less maintenance capital expenditures. Non-cash items include depreciation and amortization, non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities and deferred income taxes. Unrealized gains and losses on commodity risk management activities includes unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Distributable Cash Flow reflects earnings from unconsolidated affiliates on a cash basis.
Distributable Cash Flow is used by management to evaluate our overall performance. Our partnership agreement requires us to distribute all available cash, and Distributable Cash Flow is calculated to evaluate our ability to fund distributions through cash generated by our operations.
On a consolidated basis, Distributable Cash Flow includes 100% of the Distributable Cash Flow of ETP’s consolidated subsidiaries. However, to the extent that noncontrolling interests exist among ETP’s subsidiaries, the Distributable Cash Flow generated by ETP’s subsidiaries may not be available to be distributed to the partners of ETP. In order to reflect the cash flows available for distributions to the partners of ETP, ETP has reported Distributable Cash Flow attributable to the partners of ETP, which is calculated by adjusting Distributable Cash Flow (consolidated), as follows:
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• | For subsidiaries with publicly traded equity interests, Distributable Cash Flow (consolidated) includes 100% of Distributable Cash Flow attributable to such subsidiary, and Distributable Cash Flow attributable to the partners of ETP includes distributions to be received by the parent company with respect to the periods presented. |
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• | For consolidated joint ventures or similar entities, where the noncontrolling interest is not publicly traded, Distributable Cash Flow (consolidated) includes 100% of Distributable Cash Flow attributable to such subsidiary, but Distributable Cash Flow attributable to the partners of ETP is net of distributions to be paid by the subsidiary to the noncontrolling interests. |
For Distributable Cash Flow attributable to the partners of ETP, as adjusted, certain transaction-related and non-recurring expenses that are included in net income are excluded.
| |
(b) | For the three and six months ended June 30, 2015, the Partnership’s income tax expense from continuing operations decreased primarily due to a decrease in earnings among the Partnership’s consolidated corporate subsidiaries, which resulted in decreases in income tax expense of $75 million and $135 million, respectively. The Partnership’s income tax expense also decreased for the three and six months ended June 30, 2015 by $12 million due to the exclusion of a portion of the dividend income |
received by certain of our consolidated corporate subsidiaries. For the three and six months ended June 30, 2015, the Partnership’s income tax expense was favorably impacted by $11 million due to a reduction in the statutory Texas franchise tax rate which was enacted by the Texas legislature during the second quarter of 2015. In addition, for the six months ended June 30, 2015, the Partnership’s income tax expense from continuing operations also decreased due to unfavorable income tax adjustments of $87 million in the prior period related to the Lake Charles LNG Transaction, which occurred in the first quarter of 2014 and was treated as a sale for tax purposes.
| |
(c) | Distributions from unconsolidated affiliates for the six months ended June 30, 2015 include $16 million of distributions paid to a subsidiary of ETP. Distributions from unconsolidated affiliates for the three and six months ended June 30, 2014 include $15 million and $30 million, respectively, of distributions paid to a subsidiary of ETP. |
| |
(d) | Transaction-related income taxes primarily included income tax expense related to the Lake Charles LNG Transaction. For the three and six months ended June 30, 2014, amounts previously reported for each of the interim periods have been adjusted to reflect income taxes related to other transactions, which amounts had not previously been reflected in the calculation of Distributable Cash Flow for such interim periods. |
| |
(e) | Distributions on ETP Common Units, as reflected above, exclude cash distributions on Partnership common units held by subsidiaries of ETP. |
| |
(f) | Distributions on the Class H Units for the three and six months ended June 30, 2015 and 2014 were calculated as follows: |
|
| | | | | | | | | | | | | | | |
| Three Months Ended
June 30, | | Six Months Ended
June 30, |
| 2015 | | 2014 | | 2015 | | 2014 |
General partner distributions and incentive distributions from SXL | $ | 69 |
| | $ | 43 |
| | $ | 131 |
| | $ | 82 |
|
| 90.05 | % | | 50.05 | % | | 90.05 | % | | 50.05 | % |
Share of SXL general partner and incentive distributions payable to Class H Unitholder | 62 |
| | 21 |
| | 118 |
| | 41 |
|
Incremental distributions payable to Class H Unitholder (IDR subsidy offset)* | — |
| | 32 |
| | — |
| | 62 |
|
Total Class H Unit distributions | $ | 62 |
| | $ | 53 |
| | $ | 118 |
| | $ | 103 |
|
| |
* | Incremental distributions previously paid to the Class H Unitholder were eliminated in Amendment No. 9 to ETP’s Amended and Restated Agreement of Limited Partnership effective in the first quarter of 2015. |
| |
(g) | Distribution coverage ratio for a period is calculated as Distributable Cash Flow attributable to the partners of ETP, as adjusted, divided by net distributions expected to be paid to the partners of ETP in respect of such period. |
| |
(h) | The Partnership defines Distributable Cash Flow per Common Unit for a period as the quotient of Distributable Cash Flow attributable to the partners of ETP, as adjusted, net of distributions related to the Class H Units, Class I Units and the General Partner and IDR interests, divided by the weighted average number of Common Units outstanding. |
Similar to Distributable Cash Flow as described above, Distributable Cash Flow per Common Unit is a significant liquidity measure used by the Partnership’s senior management to compare net cash flows generated by the Partnership to the distributions the Partnership expects to pay to its unitholders. Using this measure, the Partnership’s management can compare Distributable Cash Flow attributable to the partners of ETP, as adjusted, among different periods on a per-unit basis.
Distributable Cash Flow per Common Unit is calculated as follows:
|
| | | | | | | | | | | | | | | |
| Three Months Ended
June 30, | | Six Months Ended
June 30, |
| 2015 | | 2014 | | 2015 | | 2014 |
Distributable Cash Flow attributable to the partners of ETP, as adjusted | $ | 894 |
| | $ | 745 |
| | $ | 1,746 |
| | $ | 1,585 |
|
Less: | | | | | | | |
Class H Units held by ETE and ETE Holdings | (62 | ) | | (53 | ) | | (118 | ) | | (103 | ) |
General Partner interests held by ETE | (7 | ) | | (5 | ) | | (15 | ) | | (10 | ) |
IDRs held by ETE | (317 | ) | | (178 | ) | | (617 | ) | | (346 | ) |
IDR relinquishments net of Class I Unit distributions | 28 |
| | 58 |
| | 55 |
| | 115 |
|
| $ | 536 |
| | $ | 567 |
| | $ | 1,051 |
| | $ | 1,241 |
|
Weighted average Common Units outstanding – basic | 434.8 |
| | 318.5 |
| | 379.6 |
| | 321.4 |
|
Distributable Cash Flow per Common Unit | $ | 1.23 |
| | $ | 1.78 |
| | $ | 2.77 |
| | $ | 3.86 |
|
SUMMARY ANALYSIS OF QUARTERLY RESULTS BY SEGMENT
(Tabular dollar amounts in millions)
(unaudited)
Our segment results were presented based on the measure of Segment Adjusted EBITDA. The tables below identify the components of Segment Adjusted EBITDA, which was calculated as follows:
| |
• | Gross margin, operating expenses, and selling, general and administrative expenses. These amounts represent the amounts included in our consolidated financial statements that are attributable to each segment. |
| |
• | Unrealized gains or losses on commodity risk management activities and inventory valuation adjustments. These are the unrealized amounts that are included in cost of products sold to calculate gross margin. These amounts are not included in Segment Adjusted EBITDA; therefore, the unrealized losses are added back and the unrealized gains are subtracted to calculate the segment measure. |
| |
• | Non-cash compensation expense. These amounts represent the total non-cash compensation recorded in operating expenses and selling, general and administrative expenses. This expense is not included in Segment Adjusted EBITDA and therefore is added back to calculate the segment measure. |
| |
• | Adjusted EBITDA related to unconsolidated affiliates. These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates. Amounts reflected are calculated consistently with our definition of Adjusted EBITDA. |
|
| | | | | | | |
| Three Months Ended
June 30, |
| 2015 | | 2014 |
Segment Adjusted EBITDA: | | | |
Midstream | $ | 376 |
| | $ | 356 |
|
Liquids transportation and services | 151 |
| | 141 |
|
Interstate transportation and storage | 285 |
| | 291 |
|
Intrastate transportation and storage | 117 |
| | 124 |
|
Investment in Sunoco Logistics | 326 |
| | 280 |
|
Retail marketing | 140 |
| | 136 |
|
All other | 93 |
| | 65 |
|
| $ | 1,488 |
| | $ | 1,393 |
|
Midstream
|
| | | | | | | |
| Three Months Ended
June 30, |
| 2015 | | 2014 |
Gathered volumes (MMBtu/d) | 10,161,338 |
| | 8,042,365 |
|
NGLs produced (Bbls/d) | 399,662 |
| | 292,880 |
|
Equity NGLs (Bbls/d) | 30,160 |
| | 26,761 |
|
Revenues | $ | 1,244 |
| | $ | 1,798 |
|
Cost of products sold | 797 |
| | 1,339 |
|
Gross margin | 447 |
| | 459 |
|
Unrealized losses on commodity risk management activities | 71 |
| | — |
|
Operating expenses, excluding non-cash compensation expense | (147 | ) | | (101 | ) |
Selling, general and administrative expenses, excluding non-cash compensation expense | (3 | ) | | (6 | ) |
Adjusted EBITDA related to unconsolidated affiliates | 7 |
| | 4 |
|
Other | 1 |
| | — |
|
Segment Adjusted EBITDA | $ | 376 |
| | $ | 356 |
|
Gathered volumes, NGLs produced and equity NGLs produced increased primarily due to the Eagle Rock and King Ranch acquisitions, as well as increased gathering and processing capacities in the Eagle Ford Shale, Permian Basin and Cotton Valley regions.
Segment Adjusted EBITDA for the midstream segment reflected a decrease in gross margin as follows:
|
| | | | | | | |
| Three Months Ended
June 30, |
| 2015 | | 2014 |
Gathering and processing fee-based revenues | $ | 384 |
| | $ | 311 |
|
Non fee-based contracts and processing | 63 |
| | 148 |
|
Total gross margin | $ | 447 |
| | $ | 459 |
|
Midstream gross margin reflected an increase in fee-based revenues of $48 million primarily due to increased production and increased capacity from assets recently placed in service in the Eagle Ford Shale, Permian Basin and Cotton Valley. Fee-based revenues also increased $5 million due to a change in contract terms on our Southeast Texas system where certain contracts were converted from non fee-based terms to fee-based. Additionally, the acquisition of Eagle Rock midstream assets in July 2014 also increased fee-based margin by $21 million. Lower commodity prices and changes in contract terms resulted in decreases of non fee-based margins of $70 million and $9 million, respectively. These decreases were partially offset by an increase from the acquisition of Eagle Rock midstream assets of $11 million.
Segment Adjusted EBITDA for the midstream segment reflected higher operating expenses primarily due to additional expense from assets recently placed in service and the acquisition of Eagle Rock midstream assets in July 2014.
Segment Adjusted EBITDA for the midstream segment also reflected lower selling, general and administrative expenses primarily due to a reduction in employee-related costs.
Liquids Transportation and Services
|
| | | | | | | |
| Three Months Ended
June 30, |
| 2015 | | 2014 |
Liquids transportation volumes (Bbls/d) | 482,351 |
| | 367,564 |
|
NGL fractionation volumes (Bbls/d) | 253,987 |
| | 191,255 |
|
Revenues | $ | 824 |
| | $ | 903 |
|
Cost of products sold | 628 |
| | 731 |
|
Gross margin | 196 |
| | 172 |
|
Unrealized gains on commodity risk management activities | (5 | ) | | — |
|
Operating expenses, excluding non-cash compensation expense | (39 | ) | | (29 | ) |
Selling, general and administrative expenses, excluding non-cash compensation expense | (4 | ) | | (4 | ) |
Adjusted EBITDA related to unconsolidated affiliates | 3 |
| | 2 |
|
Segment Adjusted EBITDA | $ | 151 |
| | $ | 141 |
|
NGL transportation volumes increased due to an increase in volumes transported on our Lone Star Gateway pipeline system of 67,000 BBls/d. These increased volumes were primarily out of west Texas as producers ramped up volumes. Additionally, we commissioned a crude transportation pipeline at the end of 2014 that transported 36,000 Bbls/d during the three months ended June 30, 2015. The remainder of the increase related to volumes on our NGL pipelines from our plants in southeast Texas and in the Eagle Ford region.
Average daily fractionated volumes increased due to the ramp-up of our second 100,000 Bbls/d fractionator at Mont Belvieu, Texas, which was commissioned in October 2013. These volumes include all physical and contractual volumes where we collected a fractionation fee.
Segment Adjusted EBITDA for the liquids transportation and services segment reflected an increase in gross margin as follows:
|
| | | | | | | |
| Three Months Ended
June 30, |
| 2015 | | 2014 |
Transportation margin | $ | 91 |
| | $ | 69 |
|
Processing and fractionation margin | 76 |
| | 57 |
|
Storage margin | 39 |
| | 37 |
|
Other margin | (10 | ) | | 9 |
|
Total gross margin | $ | 196 |
| | $ | 172 |
|
Transportation margin increased $16 million due to higher volumes transported out of west Texas on our Lone Star Gateway pipeline system, as noted in the volume discussion above. In addition, the increase in transportation margin also reflected an increase in volumes transported from our processing plants in southeast Texas and in the Eagle Ford region on our NGL pipeline system to Mont Belvieu, Texas, which increased $3 million. The commissioning of our crude transportation pipeline in south Texas also contributed an additional $3 million to the increase.
Processing and fractionation margin increased $18 million due to the ramp-up of Lone Star’s second fractionator at Mont Belvieu, Texas, which was commissioned in October 2013. Additionally, the commissioning of the Mariner South LPG export project during February 2015 contributed an additional $12 million for the three months ended June 30, 2015.
Storage margin reflected increases of approximately $7 million due to increased demand for leased storage capacity as a result of favorable market conditions. These increases in fee based storage margin were offset by a decrease of $4 million from lower non fee-based storage activities, including blending activities of $1 million, and $3 million of lower financial gains recognized on the withdrawal of inventory from our storage facilities.
Other margin decreased primarily due to the accounting treatment of NGL storage inventory and the timing of declines in the market price of component NGL products, resulting in losses realized during the three months ended June 30, 2015.
Segment Adjusted EBITDA for the liquids transportation and services segment also reflected an increase in operating expenses for the three months ended June 30, 2015 compared to the same period last year primarily due to the commissioning of the Mariner South LPG export project during February 2015 and the ramp-up of Lone Star’s second fractionator at Mont Belvieu, Texas, which was commissioned in October 2013.
Interstate Transportation and Storage
|
| | | | | | | |
| Three Months Ended
June 30, |
| 2015 | | 2014 |
Natural gas transported (MMBtu/d) | 5,873,424 |
| | 5,745,746 |
|
Natural gas sold (MMBtu/d) | 14,827 |
| | 15,733 |
|
Revenues | $ | 243 |
| | $ | 249 |
|
Operating expenses, excluding non-cash compensation, amortization and accretion expenses | (71 | ) | | (67 | ) |
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses | (14 | ) | | (16 | ) |
Adjusted EBITDA related to unconsolidated affiliates | 127 |
| | 125 |
|
Segment Adjusted EBITDA | $ | 285 |
| | $ | 291 |
|
| | | |
Distributions from unconsolidated affiliates | $ | 83 |
| | $ | 76 |
|
Transported volumes increased primarily due to favorable throughput on the Tiger and Transwestern pipelines, resulting in increases of 183,446 MMBtu/d and 115,648 MMBtu/d, respectively. These increases were partially offset by a decrease of 96,255 MMBtu/d on the Trunkline Gas pipeline as a result of lower customer demand due to lower price spreads.
Segment Adjusted EBITDA for the interstate transportation and storage segment decreased primarily due to the expiration of a transportation rate schedule on the Transwestern pipeline.
The increase in cash distributions from unconsolidated affiliates reflected an increase in cash distributions from Citrus due to an increase in revenues from the sale of additional Phase VIII capacity.
Intrastate Transportation and Storage
|
| | | | | | | |
| Three Months Ended
June 30, |
| 2015 | | 2014 |
Natural gas transported (MMBtu/d) | 8,666,363 |
| | 9,069,215 |
|
Revenues | $ | 569 |
| | $ | 712 |
|
Cost of products sold | 383 |
| | 551 |
|
Gross margin | 186 |
| | 161 |
|
Unrealized gains on commodity risk management activities | (34 | ) | | (3 | ) |
Operating expenses, excluding non-cash compensation expense | (42 | ) | | (43 | ) |
Selling, general and administrative expenses, excluding non-cash compensation expense | (8 | ) | | (5 | ) |
Adjusted EBITDA related to unconsolidated affiliates | 15 |
| | 14 |
|
Segment Adjusted EBITDA | $ | 117 |
| | $ | 124 |
|
| | | |
Distributions from unconsolidated affiliates | $ | 14 |
| | $ | 12 |
|
Transported volumes declined compared to the same period last year primarily due to lower production from certain key shippers in the Barnett Shale region, offset by the ramp up of volumes related to significant new long-term transportation contracts.
Intrastate transportation and storage gross margin increased $10 million from natural gas sales and other primarily due to an increase in margin from the purchase and sale of natural gas on our system and an increase of $13 million in transportation fees primarily due to increased revenue from renegotiated and newly initiated long-term fixed capacity fee contracts on our Houston
pipeline system. Additionally, storage margin increased $13 million primarily due to an increase in the volume of natural gas we own in the Bammel storage facility. These increases were partially offset by a decrease of $11 million in retained fuel revenues primarily due to significantly lower market prices.
Investment in Sunoco Logistics
|
| | | | | | | |
| Three Months Ended
June 30, |
| 2015 | | 2014 |
Revenues | $ | 3,203 |
| | $ | 4,821 |
|
Cost of products sold | 2,721 |
| | 4,517 |
|
Gross margin | 482 |
| | 304 |
|
Unrealized losses on commodity risk management activities | 7 |
| | 8 |
|
Operating expenses, excluding non-cash compensation expense | (53 | ) | | (26 | ) |
Selling, general and administrative expenses, excluding non-cash compensation expense | (23 | ) | | (20 | ) |
Inventory valuation adjustments | (100 | ) | | — |
|
Adjusted EBITDA related to unconsolidated affiliates | 13 |
| | 14 |
|
Segment Adjusted EBITDA | $ | 326 |
| | $ | 280 |
|
| | | |
Distributions from unconsolidated affiliates | $ | 5 |
| | $ | 4 |
|
Segment Adjusted EBITDA related to Sunoco Logistics increased due to the net impacts of the following:
| |
• | an increase of $43 million from terminal facilities, primarily attributable to higher results from Sunoco Logistics’ products acquisition and marketing activities, which were positively impacted by inventory accounting resulting from the liquidation of certain inventories that were stored during the first quarter to capture the contango market structure. Improved operating results from Sunoco Logistics’ Marcus Hook and Nederland terminals also contributed to the increase. These positive impacts were partially offset by lower results from Sunoco Logistics’ refined products terminals; and |
| |
• | an increase of $30 million from products pipelines, primarily due to higher throughput volumes and higher average pipeline revenue per barrel associated with Sunoco Logistics’ Mariner NGL pipeline projects. These positive impacts were partially offset by lower contributions from Sunoco Logistics’ joint venture interests; partially offset by |
| |
• | a decrease of $15 million from crude oil pipelines, primarily due to lower average pipeline revenue per barrel primarily driven by reduced volumes on higher-priced tariff movements. Increased operating expenses, which included lower pipeline operating gains and higher line testing costs, and selling, general and administrative expenses on growth also contributed to the decrease. These impacts were partially offset by additional throughput volumes largely attributable to expansion projects placed into service in 2014; and |
| |
• | a decrease of $12 million from crude oil acquisition and marketing activities, primarily attributable to lower realized crude oil margins, which were negatively impacted by narrowing crude oil differentials compared to the prior year period. This impact was partially offset by increased crude oil volumes resulting from 2014 acquisitions and the expansion of Sunoco Logistics’ crude oil trucking fleet. |
Retail Marketing
|
| | | | | | | |
| Three Months Ended
June 30, |
| 2015 | | 2014 |
Motor fuel outlets and convenience stores, end of period: | | | |
Retail | 1,276 |
| | 568 |
|
Third-party wholesale | 5,481 |
| | 4,584 |
|
Total | 6,757 |
| | 5,152 |
|
Total motor fuel gallons sold (in millions): | | | |
Retail | 639 |
| | 328 |
|
Third-party wholesale | 1,285 |
| | 1,129 |
|
Total | 1,924 |
| | 1,457 |
|
Motor fuel gross profit (cents/gallon): | | | |
Retail | 21.0 |
| | 28.5 |
|
Third-party wholesale | 8.1 |
| | 10.1 |
|
Volume-weighted average for all gallons | 12.4 |
| | 14.3 |
|
Merchandise sales (in millions) | $ | 559 |
| | $ | 175 |
|
Retail merchandise margin % | 31.5 | % | | 26.6 | % |
| | | |
Revenues | $ | 5,537 |
| | $ | 5,568 |
|
Cost of products sold | 5,003 |
| | 5,260 |
|
Gross margin | 534 |
| | 308 |
|
Unrealized (gains) losses on commodity risk management activities | 1 |
| | (1 | ) |
Operating expenses, excluding non-cash compensation expense | (281 | ) | | (135 | ) |
Selling, general and administrative expenses, excluding non-cash compensation expense | (57 | ) | | (17 | ) |
Inventory valuation adjustments | (57 | ) | | (20 | ) |
Adjusted EBITDA related to unconsolidated affiliates | — |
| | 1 |
|
Segment Adjusted EBITDA | $ | 140 |
| | $ | 136 |
|
Retail marketing gross margin increased due to the net impacts of the following:
| |
• | an increase of $199 million from the acquisition of Susser in August 2014; |
| |
• | favorable impact of $26 million from other recent acquisitions; |
| |
• | an increase of $36 million from non-retail margins; |
| |
• | an increase of $6 million from other retail margins; |
| |
• | favorable impact of $37 million related to non-cash inventory valuation adjustments; partially offset by |
| |
• | unfavorable impact of $77 million in fuel margins and volumes of $3 million. |
Segment Adjusted EBITDA for the retail marketing segment also reflected an increase in operating expenses and in selling, general and administrative expenses primarily due to recent acquisitions.
All Other
|
| | | | | | | |
| Three Months Ended
June 30, |
| 2015 | | 2014 |
Revenues | $ | 721 |
| | $ | 825 |
|
Cost of products sold | 617 |
| | 735 |
|
Gross margin | 104 |
| | 90 |
|
Unrealized (gains) losses on commodity risk management activities | 2 |
| | (3 | ) |
Operating expenses, excluding non-cash compensation expense | (22 | ) | | (20 | ) |
Selling, general and administrative expenses, excluding non-cash compensation expense | (47 | ) | | (48 | ) |
Adjusted EBITDA related to unconsolidated affiliates | 53 |
| | 31 |
|
Other | 19 |
| | 19 |
|
Eliminations | (16 | ) | | (4 | ) |
Segment Adjusted EBITDA | $ | 93 |
| | $ | 65 |
|
| | | |
Distributions from unconsolidated affiliates | $ | 19 |
| | $ | 13 |
|
Amounts reflected in our all other segment primarily include:
| |
• | our natural gas marketing and compression operations; |
| |
• | an approximate 33% non-operating interest in PES, a refining joint venture; |
| |
• | Regency’s investment in Coal Handling, an entity that owns and operates end-user coal handling facilities; and |
| |
• | our investment in AmeriGas until August 2014. |
Segment Adjusted EBITDA increased primarily due to an increase of $22 million in Adjusted EBITDA related to unconsolidated affiliates. The increase in Adjusted EBITDA related to unconsolidated affiliates was primarily due to higher earnings driven by stronger refining crack spreads from our investment in PES of $29 million, partially offset by a decrease of $5 million related to our investment in AmeriGas driven by a reduction in our investment due to the sale of AmeriGas common units in 2014.
In connection with the Lake Charles LNG Transaction, ETP agreed to continue to provide management services for ETE through 2015 in relation to both Lake Charles LNG’s regasification facility and the development of a liquefaction project at Lake Charles LNG’s facility, for which ETE has agreed to pay incremental management fees to ETP of $75 million per year for the years ending December 31, 2014 and 2015. These fees were reflected in “Other” in the “All other” segment and for the three months ended June 30, 2015 were reflected as an offset to operating expenses of $7 million and selling, general and administrative expenses of $12 million in the consolidated statements of operations.
The increase in cash distributions from unconsolidated affiliates was primarily due to an increase of $19 million in cash distribution from our ownership in PES, partially offset by a decrease of $11 million in cash distribution from our ownership in AmeriGas as a result of selling our interests in AmeriGas in 2014.
SUPPLEMENTAL INFORMATION ON CAPITAL EXPENDITURES
(Tabular amounts in millions)
(unaudited)
The following is a summary of capital expenditures (net of contributions in aid of construction costs) for the six months ended June 30, 2015:
|
| | | | | | | | | | | |
| Growth | | Maintenance | | Total |
Direct(1): | | | | | |
Midstream | $ | 1,014 |
| | $ | 32 |
| | $ | 1,046 |
|
Liquids transportation and services(2) | 1,117 |
| | 8 |
| | 1,125 |
|
Interstate transportation and storage(2) | 586 |
| | 47 |
| | 633 |
|
Intrastate transportation and storage | 28 |
| | 8 |
| | 36 |
|
Retail marketing(3) | 134 |
| | 33 |
| | 167 |
|
All other (including eliminations) | 183 |
| | 18 |
| | 201 |
|
Total direct capital expenditures | 3,062 |
| | 146 |
| | 3,208 |
|
Indirect(1): | | | | | |
Investment in Sunoco Logistics | 898 |
| | 31 |
| | 929 |
|
Investment in Sunoco LP(3) | 83 |
| | 7 |
| | 90 |
|
Total indirect capital expenditures | 981 |
| | 38 |
| | 1,019 |
|
Total capital expenditures | $ | 4,043 |
| | $ | 184 |
| | $ | 4,227 |
|
| |
(1) | Indirect capital expenditures comprise those funded by our publicly traded subsidiaries; all other capital expenditures are reflected as direct capital expenditures. |
| |
(2) | Includes capital expenditures related to our proportionate ownership of the Bakken and Rover pipeline projects. |
| |
(3) | The retail marketing segment includes the investment in Sunoco LP, as well as ETP’s wholly-owned retail marketing operations. Capital expenditures by Sunoco LP are reflected as indirect because Sunoco LP is a publicly traded subsidiary. |
We currently expect capital expenditures (net of contributions in aid of construction costs) for the full year 2015 to be within the following ranges:
|
| | | | | | | | | | | | | | | |
| Growth | | Maintenance |
| Low | | High | | Low | | High |
Direct(1): | | | | | | | |
Midstream | $ | 1,900 |
| | $ | 2,000 |
| | $ | 90 |
| | $ | 110 |
|
Liquids transportation and services: | | | | | | | |
NGL | 1,550 |
| | 1,600 |
| | 20 |
| | 25 |
|
Crude(2) | 800 |
| | 850 |
| | — |
| | — |
|
Interstate transportation and storage(2) | 700 |
| | 750 |
| | 130 |
| | 140 |
|
Intrastate transportation and storage | 130 |
| | 180 |
| | 30 |
| | 35 |
|
Retail marketing(3) | 160 |
| | 210 |
| | 55 |
| | 75 |
|
All other (including eliminations) | 200 |
| | 250 |
| | 35 |
| | 45 |
|
Total direct capital expenditures | 5,440 |
| | 5,840 |
| | 360 |
| | 430 |
|
Indirect(1): | | | | | | | |
Investment in Sunoco Logistics | 2,400 |
| | 2,600 |
| | 65 |
| | 75 |
|
Investment in Sunoco LP(3) | 220 |
| | 270 |
| | 40 |
| | 50 |
|
Total indirect capital expenditures | 2,620 |
| | 2,870 |
| | 105 |
| | 125 |
|
Total projected capital expenditures | $ | 8,060 |
| | $ | 8,710 |
| | $ | 465 |
| | $ | 555 |
|
| |
(1) | Indirect capital expenditures comprise those funded by our publicly traded subsidiaries; all other capital expenditures are reflected as direct capital expenditures. |
| |
(2) | Includes capital expenditures related to our proportionate ownership of the Bakken and Rover pipeline projects. |
| |
(3) | The retail marketing segment includes the investment in Sunoco LP, as well as ETP’s wholly-owned retail marketing operations. Capital expenditures by Sunoco LP are reflected as indirect because Sunoco LP is a publicly traded subsidiary. |
SUPPLEMENTAL INFORMATION ON UNCONSOLIDATED AFFILIATES
(In millions)
(unaudited)
|
| | | | | | | |
| Three Months Ended
June 30, |
| 2015 | | 2014 |
Equity in earnings (losses) of unconsolidated affiliates: | | | |
Citrus | $ | 29 |
| | $ | 26 |
|
FEP | 13 |
| | 13 |
|
PES | 47 |
| | 18 |
|
MEP | 11 |
| | 11 |
|
HPC | 6 |
| | 8 |
|
AmeriGas | (2 | ) | | (8 | ) |
Other | 13 |
| | 9 |
|
Total equity in earnings of unconsolidated affiliates | $ | 117 |
| | $ | 77 |
|
| | | |
Adjusted EBITDA related to unconsolidated affiliates: | | | |
Citrus | $ | 85 |
| | $ | 81 |
|
FEP | 18 |
| | 18 |
|
PES | 54 |
| | 25 |
|
MEP | 24 |
| | 26 |
|
HPC | 15 |
| | 14 |
|
AmeriGas | — |
| | 5 |
|
Other | 19 |
| | 21 |
|
Total Adjusted EBITDA related to unconsolidated affiliates | $ | 215 |
| | $ | 190 |
|
| | | |
Distributions received from unconsolidated affiliates: | | | |
Citrus | $ | 47 |
| | $ | 41 |
|
FEP | 16 |
| | 16 |
|
PES | 19 |
| | — |
|
MEP | 20 |
| | 18 |
|
HPC | 14 |
| | 11 |
|
AmeriGas | — |
| | 11 |
|
Other | 9 |
| | 11 |
|
Total distributions received from unconsolidated affiliates – actual | $ | 125 |
| | $ | 108 |
|
Sunoco Logistics Partners L.P. (NYSE:ETP)
Historical Stock Chart
From Mar 2024 to Apr 2024
Sunoco Logistics Partners L.P. (NYSE:ETP)
Historical Stock Chart
From Apr 2023 to Apr 2024
