UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
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
| Date of Report (Date of earliest event reported) | ||||||||
| PANHANDLE EASTERN PIPE LINE COMPANY, LP | ||||||||
| (Exact name of Registrant as specified in its charter) | ||||||||
| (State or other jurisdiction of incorporation) | (Commission File Number) | (IRS Employer Identification No.) | ||||||
(Address of principal executive offices) (zip code)
(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:
Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).
Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
| Item 7.01 | Regulation FD Disclosure. | ||||
On February 16, 2022, Energy Transfer LP (the "Partnership"), which owns 100% of Energy Transfer Interstate Holdings, LLC, which indirectly owns 100% of the equity interests of Panhandle Eastern Pipe Line Company, LP (the “Company”), issued a press release announcing the financial and operating results of Energy Transfer LP, including certain financial results of the Company, for the fiscal year and fourth fiscal quarter ended December 31, 2021. A copy of the Partnership's 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 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.
| 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.
| Exhibit Number | Description of the Exhibit | ||||
| 104 | Cover Page Interactive Data File (embedded within the Inline XBRL document) | ||||
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 thereunto duly authorized.
| PANHANDLE EASTERN PIPE LINE COMPANY, LP | |||||||||||
| (Registrant) | |||||||||||
| Date: February 16, 2022 | By: | /s/ Bradford D. Whitehurst | |||||||||
| Bradford D. Whitehurst | |||||||||||
| Chief Financial Officer (duly authorized to sign on behalf of the registrant) | |||||||||||
ENERGY TRANSFER REPORTS FOURTH QUARTER 2021 RESULTS
Dallas - February 16, 2022 - Energy Transfer LP (NYSE:ET) (“Energy Transfer” or the “Partnership”) today reported financial results for the quarter and year ended December 31, 2021.
Energy Transfer reported net income attributable to partners for the three months ended December 31, 2021 of $921 million, an increase of $412 million compared to the same period last year. For the three months ended December 31, 2021, net income per limited partner unit (basic and diluted) was $0.29 per unit.
Adjusted EBITDA for the three months ended December 31, 2021 was $2.81 billion compared to $2.59 billion for the same period last year. The improved results were primarily driven by increased NGL transportation and export volumes, higher realized commodity prices, and the Enable acquisition. Energy Transfer’s NGL business also had record transportation and fractionation volumes in the fourth quarter.
Distributable Cash Flow attributable to partners, as adjusted, for the three months ended December 31, 2021 was $1.60 billion compared to $1.36 billion for the same period last year.
Growth capital expenditures in 2021 were $1.40 billion, which was $200 million less than expected due to project deferrals into 2022. Maintenance capital expenditures were $522 million. Looking ahead, Energy Transfer is updating its 2022 growth and maintenance capital expenditures outlook as a result of the recently closed Enable acquisition and rapidly growing demand for midstream infrastructure. The Partnership expects its 2022 growth capital expenditures to range from $1.6 billion to $1.9 billion, which includes the addition of several new capital projects expected to be completed by year end. Maintenance capital expenditures are expected to range between $615 million and $665 million for 2022. Energy Transfer is also providing an outlook for 2022 Adjusted EBITDA which is expected to range between $11.8 billion and $12.2 billion.
Key accomplishments and recent developments:
Operational
•In February 2022, construction of the final phase of the Mariner East project was completed and commissioning is in progress. Energy Transfer’s Mariner East franchise will now include multiple pipelines across Pennsylvania connecting the prolific Marcellus/Utica Basins in the west to markets throughout the state and the broader region, including Energy Transfer’s Marcus Hook terminal on the east coast.
•During the first quarter 2022, construction began on the Gulf Run Pipeline project. The 42-inch pipeline with 1.65 Bcf/d of capacity is expected to be completed by year-end and will provide natural gas transportation between the Haynesville Shale Basin and the gulf coast.
•During the fourth quarter 2021, Phase II of the Cushing South Pipeline project was launched and is expected to nearly double the project’s oil pipeline capacity to 120,000 barrels per day. This project primarily utilizes existing facilities to provide additional connectivity across Energy Transfer’s mid-continent and gulf coast crude oil network.
•In October 2021, Energy Transfer brought online a three million barrel high-rate storage well at its Mont Belvieu facility, which now includes 24 wells with NGL storage capacity of approximately 53 million barrels.
•In the fourth quarter of 2021, Energy Transfer reached its highest ever volume of NGL transportation and fractionation.
•In October 2021, Energy Transfer completed its Permian Bridge project, providing increased connectivity and efficiency between the Partnership’s natural gas gathering and processing assets in the Delaware Basin and its assets in the Midland Basin.
Strategic
•Energy Transfer is evaluating a new Permian Basin natural gas takeaway project that would utilize existing Partnership assets and a new pipeline to connect Permian supply to markets along the gulf coast, including the Houston Ship Channel, Katy, Carthage, and Henry Hub.
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•In December 2021, Energy Transfer successfully closed the Enable Midstream Partners, LP (“Enable”) acquisition and integration of combined operations is ongoing. The merger is expected to generate annual run-rate cost efficiencies in excess of $100 million.
•In December 2021, subsequent to the Enable acquisition, the Partnership and its affiliates purchased more than 20 million Energy Transfer common units in connection with a secondary offering executed by one of Enable’s prior sponsors.
•In the fourth quarter of 2021, the Partnership released its Corporate Responsibility Report, which highlights Energy Transfer’s business achievements and safety and risk management and emissions reduction programs.
Financial
•In January 2022, Energy Transfer announced a 15% increase in its quarterly distribution on common units. For the quarter ended December 31, 2021, Energy Transfer will pay a quarterly distribution of $0.175 per common unit ($0.70 annualized). Future increases to the distribution level will be evaluated quarterly with the ultimate goal of returning distributions to the previous level of $0.305 per common unit per quarter ($1.22 annualized) while balancing the Partnership’s leverage target, growth opportunities and unit buybacks.
•During the fourth quarter of 2021, the Partnership reduced outstanding debt by approximately $400 million (excluding debt assumed in the Enable acquisition), utilizing cash from operations. For the full year 2021, Energy Transfer reduced its existing long-term debt by approximately $6.3 billion.
•As of December 31, 2021, the Partnership’s $5.00 billion revolving credit facilities had an aggregate $2.03 billion of available capacity, and the leverage ratio, as defined by its credit agreement, was 3.07x.
Energy Transfer benefits from a portfolio of assets with exceptional product and geographic diversity. The Partnership’s multiple segments generate high-quality, balanced earnings with no single segment contributing more than 30% of the Partnership’s consolidated Adjusted EBITDA for the three months or full year ended December 31, 2021. The vast majority of the Partnership’s segment margins are fee-based and therefore have limited commodity price sensitivity.
Conference call information:
The Partnership has scheduled a conference call for 3:30 p.m. Central Time/4:30 p.m. Eastern Time on Wednesday, February 16, 2022 to discuss its fourth quarter 2021 results and provide an update on the Partnership, including its outlook for 2022. The conference call will be broadcast live via an internet webcast, which can be accessed through www.energytransfer.com and will also be available for replay on the Partnership’s website for a limited time.
Energy Transfer LP (NYSE: ET) owns and operates one of the largest and most diversified portfolios of energy assets in North America, with a strategic footprint in all of the major U.S. production basins. Energy Transfer is a publicly traded limited partnership with core operations that include complementary natural gas midstream, intrastate and interstate transportation and storage assets; crude oil, natural gas liquids (“NGL”) and refined product transportation and terminalling assets; and NGL fractionation. Energy Transfer also owns Lake Charles LNG Company, as well as the general partner interests, the incentive distribution rights and 28.5 million common units of Sunoco LP (NYSE: SUN), and the general partner interests and 46.1 million common units of USA Compression Partners, LP (NYSE: USAC). For more information, visit the Energy Transfer LP website at www.energytransfer.com.
Sunoco LP (NYSE: SUN) is a master limited partnership with core operations that include the distribution of motor fuel to approximately 10,000 convenience stores, independent dealers, commercial customers and distributors located in more than 40 U.S. states and territories, as well as refined product transportation and terminalling assets. SUN’s general partner is owned by Energy Transfer LP (NYSE: ET). For more information, visit the Sunoco LP website at www.sunocolp.com.
USA Compression Partners, LP (NYSE: USAC) is a growth-oriented Delaware limited partnership that is one of the nation’s largest independent providers of natural gas compression services in terms of total compression fleet horsepower. USAC partners with a broad customer base composed of producers, processors, gatherers and transporters of natural gas and crude oil. USAC focuses on providing compression services to infrastructure applications primarily in high-volume gathering systems, processing facilities and transportation applications. For more information, visit the USAC website at www.usacompression.com.
Forward-Looking Statements
This news 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
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that can affect future results, including future distribution levels and leverage ratio, are discussed in the Partnership’s Annual Report on Form 10-K and other documents filed from time to time with the Securities and Exchange Commission. In addition to the risks and uncertainties previously disclosed, the Partnership has also been, or may in the future be, impacted by new or heightened risks related to the COVID-19 pandemic, and we cannot predict the length and ultimate impact of those risks. 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 website at www.energytransfer.com.
Contacts
Energy Transfer
Investor Relations:
Bill Baerg, Brent Ratliff, Lyndsay Hannah, 214-981-0795
or
Media Relations:
Vicki Granado, 214-840-5820
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ENERGY TRANSFER LP AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(In millions)
(unaudited)
| December 31, 2021 | December 31, 2020 | ||||||||||
| ASSETS | |||||||||||
| Current assets | $ | 10,537 | $ | 6,317 | |||||||
| Property, plant and equipment, net | 81,607 | 75,107 | |||||||||
Advances to and investments in unconsolidated affiliates | 2,947 | 3,060 | |||||||||
Lease right-of-use assets, net | 838 | 866 | |||||||||
| Other non-current assets, net | 1,645 | 1,657 | |||||||||
| Intangible assets, net | 5,856 | 5,746 | |||||||||
| Goodwill | 2,533 | 2,391 | |||||||||
| Total assets | $ | 105,963 | $ | 95,144 | |||||||
| LIABILITIES AND EQUITY | |||||||||||
Current liabilities (1) | $ | 10,835 | $ | 5,923 | |||||||
| Long-term debt, less current maturities | 49,022 | 51,417 | |||||||||
| Non-current derivative liabilities | 193 | 237 | |||||||||
Non-current operating lease liabilities | 814 | 837 | |||||||||
| Deferred income taxes | 3,648 | 3,428 | |||||||||
| Other non-current liabilities | 1,323 | 1,152 | |||||||||
| Commitments and contingencies | |||||||||||
| Redeemable noncontrolling interests | 783 | 762 | |||||||||
| Equity: | |||||||||||
| Limited Partners: | |||||||||||
| Preferred Unitholders | 6,051 | — | |||||||||
| Common Unitholders | 25,230 | 18,531 | |||||||||
| General Partner | (4) | (8) | |||||||||
| Accumulated other comprehensive income | 23 | 6 | |||||||||
| Total partners’ capital | 31,300 | 18,529 | |||||||||
| Noncontrolling interest | 8,045 | 12,859 | |||||||||
| Total equity | 39,345 | 31,388 | |||||||||
| Total liabilities and equity | $ | 105,963 | $ | 95,144 | |||||||
(1)As of December 31, 2021, current liabilities included $680 million of current maturities of long-term debt. This total includes all of the $650 million of senior notes due in April 2022 from the Bakken Pipeline entities, for which our proportional ownership is 36.4%.
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ENERGY TRANSFER LP AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per unit data)
(unaudited)
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||||||||||
| 2021 | 2020 | 2021 | 2020 | ||||||||||||||||||||
| REVENUES | $ | 18,657 | $ | 10,034 | $ | 67,417 | $ | 38,954 | |||||||||||||||
| COSTS AND EXPENSES: | |||||||||||||||||||||||
| Cost of products sold | 14,754 | 6,703 | 50,395 | 25,487 | |||||||||||||||||||
| Operating expenses | 989 | 796 | 3,574 | 3,218 | |||||||||||||||||||
| Depreciation, depletion and amortization | 980 | 963 | 3,817 | 3,678 | |||||||||||||||||||
| Selling, general and administrative | 235 | 156 | 818 | 711 | |||||||||||||||||||
| Impairment losses | 10 | 77 | 21 | 2,880 | |||||||||||||||||||
| Total costs and expenses | 16,968 | 8,695 | 58,625 | 35,974 | |||||||||||||||||||
| OPERATING INCOME | 1,689 | 1,339 | 8,792 | 2,980 | |||||||||||||||||||
| OTHER INCOME (EXPENSE): | |||||||||||||||||||||||
| Interest expense, net of interest capitalized | (554) | (577) | (2,267) | (2,327) | |||||||||||||||||||
| Equity in earnings of unconsolidated affiliates | 55 | 73 | 246 | 119 | |||||||||||||||||||
| Impairment of investments in unconsolidated affiliates | — | — | — | (129) | |||||||||||||||||||
| Losses on extinguishments of debt | (30) | (13) | (38) | (75) | |||||||||||||||||||
| Gains (losses) on interest rate derivatives | (11) | 74 | 61 | (203) | |||||||||||||||||||
| Other, net | 32 | 6 | 77 | 12 | |||||||||||||||||||
| INCOME BEFORE INCOME TAX EXPENSE (BENEFIT) | 1,181 | 902 | 6,871 | 377 | |||||||||||||||||||
| Income tax expense (benefit) | (50) | 69 | 184 | 237 | |||||||||||||||||||
| NET INCOME | 1,231 | 833 | 6,687 | 140 | |||||||||||||||||||
| Less: Net income attributable to noncontrolling interest | 297 | 312 | 1,167 | 739 | |||||||||||||||||||
| Less: Net income attributable to redeemable noncontrolling interests | 13 | 12 | 50 | 49 | |||||||||||||||||||
| NET INCOME (LOSS) ATTRIBUTABLE TO PARTNERS | 921 | 509 | 5,470 | (648) | |||||||||||||||||||
| General Partner’s interest in net income (loss) | 1 | — | 6 | (1) | |||||||||||||||||||
| Preferred Unitholders’ interest in net income | 100 | — | 285 | — | |||||||||||||||||||
| Limited Partners’ interest in net income (loss) | $ | 820 | $ | 509 | $ | 5,179 | $ | (647) | |||||||||||||||
| NET INCOME (LOSS) PER LIMITED PARTNER UNIT: | |||||||||||||||||||||||
Basic | $ | 0.29 | $ | 0.19 | $ | 1.89 | $ | (0.24) | |||||||||||||||
Diluted | $ | 0.29 | $ | 0.19 | $ | 1.89 | $ | (0.24) | |||||||||||||||
WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING: | |||||||||||||||||||||||
Basic | 2,824.5 | 2,699.1 | 2,734.4 | 2,695.6 | |||||||||||||||||||
Diluted | 2,830.6 | 2,699.1 | 2,739.6 | 2,695.6 | |||||||||||||||||||
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ENERGY TRANSFER LP AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION
(Dollars and units in millions)
(unaudited)
| Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||||||||||
| 2021 | 2020 | 2021 (a) | 2020 | ||||||||||||||||||||
Reconciliation of net income to Adjusted EBITDA and Distributable Cash Flow (b): | |||||||||||||||||||||||
Net income | $ | 1,231 | $ | 833 | $ | 6,687 | $ | 140 | |||||||||||||||
Interest expense, net of interest capitalized | 554 | 577 | 2,267 | 2,327 | |||||||||||||||||||
Impairment losses | 10 | 77 | 21 | 2,880 | |||||||||||||||||||
| Income tax expense (benefit) | (50) | 69 | 184 | 237 | |||||||||||||||||||
Depreciation, depletion and amortization | 980 | 963 | 3,817 | 3,678 | |||||||||||||||||||
Non-cash compensation expense | 30 | 28 | 111 | 121 | |||||||||||||||||||
(Gains) losses on interest rate derivatives | 11 | (74) | (61) | 203 | |||||||||||||||||||
| Unrealized (gains) losses on commodity risk management activities | (88) | 44 | (162) | 71 | |||||||||||||||||||
Losses on extinguishments of debt | 30 | 13 | 38 | 75 | |||||||||||||||||||
| Inventory valuation adjustments (Sunoco LP) | (22) | (44) | (190) | 82 | |||||||||||||||||||
| Impairment of investment in an unconsolidated affiliate | — | — | — | 129 | |||||||||||||||||||
| Equity in earnings of unconsolidated affiliates | (55) | (73) | (246) | (119) | |||||||||||||||||||
Adjusted EBITDA related to unconsolidated affiliates | 123 | 148 | 523 | 628 | |||||||||||||||||||
| Other, net | 57 | 31 | 57 | 79 | |||||||||||||||||||
Adjusted EBITDA (consolidated) | 2,811 | 2,592 | 13,046 | 10,531 | |||||||||||||||||||
Adjusted EBITDA related to unconsolidated affiliates | (123) | (148) | (523) | (628) | |||||||||||||||||||
Distributable Cash Flow from unconsolidated affiliates | 78 | 99 | 346 | 452 | |||||||||||||||||||
Interest expense, net of interest capitalized | (554) | (577) | (2,267) | (2,327) | |||||||||||||||||||
| Preferred unitholders’ distributions | (113) | (96) | (418) | (378) | |||||||||||||||||||
| Current income tax (expense) benefit | (10) | (19) | (44) | (27) | |||||||||||||||||||
Maintenance capital expenditures | (210) | (152) | (581) | (520) | |||||||||||||||||||
| Other, net | 18 | 17 | 68 | 74 | |||||||||||||||||||
Distributable Cash Flow (consolidated) | 1,897 | 1,716 | 9,627 | 7,177 | |||||||||||||||||||
Distributable Cash Flow attributable to Sunoco LP (100%) | (143) | (97) | (542) | (516) | |||||||||||||||||||
Distributions from Sunoco LP | 41 | 42 | 165 | 165 | |||||||||||||||||||
Distributable Cash Flow attributable to USAC (100%) | (52) | (51) | (209) | (221) | |||||||||||||||||||
Distributions from USAC | 24 | 25 | 97 | 97 | |||||||||||||||||||
Distributable Cash Flow attributable to noncontrolling interest in other non-wholly-owned consolidated subsidiaries | (327) | (282) | (1,113) | (1,015) | |||||||||||||||||||
| Distributable Cash Flow attributable to the partners of Energy Transfer | 1,440 | 1,353 | 8,025 | 5,687 | |||||||||||||||||||
Transaction-related adjustments (c) | 160 | 9 | 194 | 55 | |||||||||||||||||||
| Distributable Cash Flow attributable to the partners of Energy Transfer, as adjusted | $ | 1,600 | $ | 1,362 | $ | 8,219 | $ | 5,742 | |||||||||||||||
| Distributions to partners: | |||||||||||||||||||||||
| Limited Partners | $ | 540 | $ | 412 | $ | 1,777 | $ | 2,468 | |||||||||||||||
General Partner | 1 | 1 | 2 | 3 | |||||||||||||||||||
| Total distributions to be paid to partners | $ | 541 | $ | 413 | $ | 1,779 | $ | 2,471 | |||||||||||||||
Common Units outstanding – end of period | 3,082.5 | 2,702.3 | 3,082.5 | 2,702.3 | |||||||||||||||||||
| Distribution coverage ratio | 2.96x | 3.30x | 4.62x | 2.32x | |||||||||||||||||||
(a)Winter Storm Uri, which occurred in February 2021, resulted in one-time impacts to the Partnership’s consolidated net income, Adjusted EBITDA and Distributable Cash Flow. Please see additional discussion of these impacts, as well as the potential impacts to future periods, included in the “Summary Analysis of Quarterly Results by Segment” below.
(b)Adjusted EBITDA, Distributable Cash Flow and distribution coverage ratio are non-GAAP financial measures used by industry analysts, investors, lenders and rating agencies to assess the financial performance and the operating results of
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Energy Transfer’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, Distributable Cash Flow and distribution coverage ratio, including the difficulty associated with using any such measure 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, Distributable Cash Flow and distribution coverage ratio 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 operating income, net income and cash flow from operating activities.
Definition of Adjusted EBITDA
We define Adjusted EBITDA as total partnership 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, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Inventory adjustments that are excluded from the calculation of Adjusted EBITDA represent only the changes in lower of cost or market reserves on inventory that is carried at last-in, first-out (“LIFO”). These amounts are unrealized valuation adjustments applied to Sunoco LP’s fuel volumes remaining in inventory at the end of the period.
Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates. The use of Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly.
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
We define Distributable Cash Flow as net income, adjusted for certain non-cash items, less distributions to preferred unitholders and maintenance capital expenditures. Non-cash items include depreciation, depletion and amortization, non-cash compensation expense, amortization included in interest 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, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and deferred income taxes. For unconsolidated affiliates, Distributable Cash Flow reflects the Partnership’s proportionate share of the investee’s distributable cash flow.
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 Energy Transfer’s consolidated subsidiaries. However, to the extent that noncontrolling interests exist among our subsidiaries, the Distributable Cash Flow generated by our subsidiaries may not be available to be distributed to our partners. In order to reflect the cash flows available for distributions to our partners, we have reported Distributable Cash Flow attributable to partners, which is calculated by adjusting Distributable Cash Flow (consolidated), as follows:
•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 our partners includes distributions to be received by the parent company with respect to the periods presented.
•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 subsidiaries, but
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Distributable Cash Flow attributable to partners reflects only the amount of Distributable Cash Flow of such subsidiaries that is attributable to our ownership interest.
For Distributable Cash Flow attributable to partners, as adjusted, certain transaction-related adjustments and non-recurring expenses that are included in net income are excluded.
Definition of Distribution Coverage Ratio
Distribution coverage ratio for a period is calculated as Distributable Cash Flow attributable to partners, as adjusted, divided by distributions expected to be paid to the partners of Energy Transfer in respect of such period.
(c) For the three months and year ended December 31, 2021, “Transaction-related adjustments” includes $143 million of Distributable Cash Flow attributable to the operations of Enable for October 1 through December 1, 2021, which represents amounts distributable to Energy Transfer’s common unitholders (including the holders of the common units issued in the Enable acquisition) with respect to the fourth quarter 2021 distribution.
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ENERGY TRANSFER LP AND SUBSIDIARIES
SUMMARY ANALYSIS OF QUARTERLY RESULTS BY SEGMENT
(Tabular dollar amounts in millions)
(unaudited)
| Three Months Ended December 31, | |||||||||||
| 2021 | 2020 | ||||||||||
Segment Adjusted EBITDA: | |||||||||||
| Intrastate transportation and storage | $ | 274 | $ | 233 | |||||||
| Interstate transportation and storage | 397 | 448 | |||||||||
| Midstream | 547 | 390 | |||||||||
| NGL and refined products transportation and services | 739 | 703 | |||||||||
| Crude oil transportation and services | 533 | 517 | |||||||||
| Investment in Sunoco LP | 198 | 159 | |||||||||
| Investment in USAC | 99 | 99 | |||||||||
| All other | 24 | 43 | |||||||||
Total Segment Adjusted EBITDA | $ | 2,811 | $ | 2,592 | |||||||
In the following analysis of segment operating results, a measure of segment margin is reported for segments with sales revenues. Segment margin is a non-GAAP financial measure and is presented herein to assist in the analysis of segment operating results and particularly to facilitate an understanding of the impacts that changes in sales revenues have on the segment performance measure of Segment Adjusted EBITDA. Segment margin is similar to the GAAP measure of gross margin, except that segment margin excludes charges for depreciation, depletion and amortization. Among the GAAP measures reported by the Partnership, the most directly comparable measure to segment margin is Segment Adjusted EBITDA; a reconciliation of segment margin to Segment Adjusted EBITDA is included in the following tables for each segment where segment margin is presented.
In addition, for certain segments, the sections below include information on the components of segment margin by sales type, which components are included in order to provide additional disaggregated information to facilitate the analysis of segment margin and Segment Adjusted EBITDA. For example, these components include transportation margin, storage margin, and other margin. These components of segment margin are calculated consistent with the calculation of segment margin; therefore, these components also exclude charges for depreciation, depletion and amortization.
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Intrastate Transportation and Storage
| Three Months Ended December 31, | |||||||||||
| 2021 | 2020 | ||||||||||
Natural gas transported (BBtu/d) | 12,644 | 11,542 | |||||||||
Withdrawals from storage natural gas inventory (BBtu) | — | 7,233 | |||||||||
Revenues | $ | 1,505 | $ | 781 | |||||||
Cost of products sold | 1,133 | 493 | |||||||||
Segment margin | 372 | 288 | |||||||||
| Unrealized gains on commodity risk management activities | (28) | (9) | |||||||||
Operating expenses, excluding non-cash compensation expense | (69) | (46) | |||||||||
Selling, general and administrative expenses, excluding non-cash compensation expense | (11) | (6) | |||||||||
Adjusted EBITDA related to unconsolidated affiliates | 8 | 6 | |||||||||
Other | 2 | — | |||||||||
Segment Adjusted EBITDA | $ | 274 | $ | 233 | |||||||
For the three months ended December 31, 2021 compared to the same period last year, transported volumes increased primarily due to volume ramp-ups in the Permian and Haynesville regions, as well as incremental volumes from the Enable assets acquired in December 2021.
Segment Adjusted EBITDA. For the three months ended December 31, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment increased due to the net impacts of the following:
•an increase of $39 million in transportation fees due to increased firm transportation volumes from the Permian and the recognition of certain revenues related to Winter Storm Uri, and incremental revenues from the Enable assets acquired in December 2021;
•an increase of $19 million in retained fuel revenues primarily due to higher natural gas prices; and
•an increase of $16 million in realized natural gas sales and other primarily due to the recognition of certain revenues related to Winter Storm Uri, partially offset by lower optimization volumes with shifts to long-term third-party contracts from the Permian to the Gulf Coast; partially offset by
•an increase of $23 million in operating expenses primarily due to increases of $11 million in cost of fuel consumption due to higher gas prices, $5 million in maintenance project costs, $5 million in ad valorem taxes, and $3 million in incremental expenses from operation of the Enable assets acquired in December 2021; and
•a decrease of $8 million in realized storage margin due to lower storage optimization.
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Interstate Transportation and Storage
| Three Months Ended December 31, | |||||||||||
| 2021 | 2020 | ||||||||||
Natural gas transported (BBtu/d) | 11,913 | 10,052 | |||||||||
Natural gas sold (BBtu/d) | 36 | 18 | |||||||||
Revenues | $ | 491 | $ | 481 | |||||||
Cost of products sold | 11 | — | |||||||||
Segment margin | 480 | 481 | |||||||||
| Operating expenses, excluding non-cash compensation, amortization, accretion and other non-cash expenses | (151) | (138) | |||||||||
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses | (20) | (2) | |||||||||
Adjusted EBITDA related to unconsolidated affiliates | 82 | 108 | |||||||||
Other | 6 | (1) | |||||||||
Segment Adjusted EBITDA | $ | 397 | $ | 448 | |||||||
For the three months ended December 31, 2021 compared to the same period last year, transported volumes increased primarily due to the impact of the Enable acquisition, higher utilization on our Tiger system and a reduced impact on our Transwestern system from maintenance of third-party facilities, partially offset by lower utilization of contracted capacity on our Trunkline system.
Segment Adjusted EBITDA. For the three months ended December 31, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment decreased due to the net impacts of the following:
•a decrease of $1 million in segment margin primarily due to a $31 million decrease resulting from shipper contract expirations on our Tiger system, a $17 million decrease due to a shipper bankruptcy during 2020 also on our Tiger system, and a $7 million decrease due to lower utilization on our Panhandle and Trunkline systems. These decreases were partially offset by a $39 million impact from the Enable acquisition, an $8 million increase due to higher utilization on our Rover and Tiger systems, a $5 million increase due to increased capacity sold on our Transwestern and Tiger systems and a $3 million increase in operational gas sales on our Transwestern system;
•an increase of $13 million in operating expenses primarily due to a $15 million increase due to the impact of the Enable acquisition, a $20 million increase in ad valorem taxes due to refunds received in the prior period on Transwestern and a $3 million increase in employee related costs. These increases were partially offset by a $14 million decrease due to bad debt expense recorded in the prior period in connection with a shipper bankruptcy, a $7 million decrease in transportation expense and a $4 million decrease resulting from a write-off of obsolete inventory in the prior period;
•an increase of $18 million in selling, general and administrative expenses primarily due to a $12 million impact resulting from a settlement related to excise taxes on Rover in the prior period and a $5 million increase in allocated overhead costs; and
•a decrease of $26 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to a $19 million decrease from our Fayetteville Express Pipeline joint venture as a result of the expiration of foundation shipper contracts, an $8 million decrease from our Citrus joint venture due to a contractual rate adjustment and higher operating expenses, and a $2 million decrease from our Midcontinent Express Pipeline joint venture due to capacity sold at lower rates; partially offset by
•an increase of $7 million in other Adjusted EBITDA primarily due to certain one-time fees received in connection with the operation of a joint venture.
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Midstream
| Three Months Ended December 31, | |||||||||||
| 2021 | 2020 | ||||||||||
Gathered volumes (BBtu/d) | 14,765 | 12,634 | |||||||||
NGLs produced (MBbls/d) | 705 | 596 | |||||||||
Equity NGLs (MBbls/d) | 40 | 32 | |||||||||
Revenues | $ | 3,526 | $ | 1,461 | |||||||
Cost of products sold | 2,705 | 882 | |||||||||
Segment margin | 821 | 579 | |||||||||
Unrealized losses on commodity risk management activities | (10) | — | |||||||||
Operating expenses, excluding non-cash compensation expense | (227) | (177) | |||||||||
Selling, general and administrative expenses, excluding non-cash compensation expense | (46) | (20) | |||||||||
Adjusted EBITDA related to unconsolidated affiliates | 9 | 8 | |||||||||
Segment Adjusted EBITDA | $ | 547 | $ | 390 | |||||||
For the three months ended December 31, 2021 compared to the same period last year, gathered volumes and NGL production increased during the three months ended December 31, 2021 compared to the same period last year primarily due to the Enable acquisition and volume increases in the South Texas, Permian, and Northeast regions, partially offset by volume declines in the Ark-La-Tex and Mid-Continent/Panhandle regions.
Segment Adjusted EBITDA. For the three months ended December 31, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment increased due to the net impacts of the following:
•an increase of $147 million in non fee-based margin due to favorable NGL prices of $100 million and natural gas prices of $47 million;
•an increase of $15 million in non fee-based margin due to volume growth in the South Texas, Permian, and Northeast regions; and
•an increase of $69 million in fee-based margin due to volume growth in the South Texas, Permian, and Northeast regions and the Enable acquisition; partially offset by
•an increase of $50 million in operating expenses due to $22 million in incremental operating expenses from operation of the Enable assets acquired in December 2021, an increase of $10 million in maintenance project costs and an increase of $10 million in employee costs; and
•an increase of $26 million in selling, general and administrative expenses primarily due to $15 million in incremental selling, general and administrative expenses from the Enable assets acquired in December 2021 and an increase of $8 million in allocated overhead costs.
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NGL and Refined Products Transportation and Services
| Three Months Ended December 31, | |||||||||||
| 2021 | 2020 | ||||||||||
NGL transportation volumes (MBbls/d) | 1,872 | 1,449 | |||||||||
Refined products transportation volumes (MBbls/d) | 483 | 463 | |||||||||
NGL and refined products terminal volumes (MBbls/d) | 1,227 | 859 | |||||||||
NGL fractionation volumes (MBbls/d) | 895 | 825 | |||||||||
Revenues | $ | 6,187 | $ | 3,056 | |||||||
Cost of products sold | 5,213 | 2,223 | |||||||||
Segment margin | 974 | 833 | |||||||||
| Unrealized gains (losses) on commodity risk management activities | (17) | 44 | |||||||||
Operating expenses, excluding non-cash compensation expense | (211) | (175) | |||||||||
Selling, general and administrative expenses, excluding non-cash compensation expense | (30) | (18) | |||||||||
Adjusted EBITDA related to unconsolidated affiliates | 22 | 19 | |||||||||
Other | 1 | — | |||||||||
Segment Adjusted EBITDA | $ | 739 | $ | 703 | |||||||
For the three months ended December 31, 2021 compared to the same period last year, NGL transportation volumes increased primarily due to the initiation of service on our propane and ethane export pipelines into our Nederland Terminal in the fourth quarter of 2020, higher volumes from the Permian and Eagle Ford regions and higher volumes on our Mariner East pipeline system.
Refined products transportation volumes increased for the three months ended December 31, 2021 compared to the same period last year due to recovery from COVID-19 related demand reduction in the prior period.
NGL and refined products terminal volumes increased for the three months ended December 31, 2021 compared to the same period last year primarily due to the previously mentioned start of new pipelines and refined product demand recovery.
Average fractionated volumes at our Mont Belvieu, Texas fractionation facility increased for the three months ended December 31, 2021 compared to the same period last year primarily due to lower throughput in the prior period caused by maintenance related downtime at our Mont Belvieu fractionation facility.
Segment Adjusted EBITDA. For the three months ended December 31, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to net impacts of the following:
•an increase of $46 million in transportation margin primarily due to a $29 million increase from higher export volumes feeding into our Nederland Terminal, a $6 million increase resulting from increased utilization of our ethane optimization strategy, a $6 million intrasegment gain related to cavern withdrawals which is offset in our fractionators margin, and a $5 million increase from volumetric gains on our Texas y-grade pipeline system;
•an increase of $41 million in terminal services margin primarily due to a $45 million increase from fees for loading export cargos at our Nederland Terminal. These increases were partially offset by a $5 million decrease resulting from lower rates at our Marcus Hook Terminal due to the decrease in the producer price index effective January 2021; and
•an increase of $17 million in fractionators and refinery services margin primarily due to a $12 million increase resulting from higher volumes in the fourth quarter of 2021, a $6 million increase from operational blending and a $6 million increase due to a more favorable pricing environment impacting our refinery services business. These increases were partially offset by a $6 million intrasegment charge related to cavern withdrawals which is offset in our transportation margin; partially offset by
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•an increase of $36 million in operating expenses primarily due to a $20 million increase in utilities cost resulting from higher power and gas prices, a $9 million increase due to the timing of maintenance related expenses, a $5 million increase in allocated corporate overhead costs and a $4 million increase in employee related costs;
•a decrease of $26 million in marketing margin primarily due to a $28 million decrease from the optimization of NGL component products at our Gulf Coast NGL activities, partially offset by an increase of $3 million from our northeast blending and optimization activities; and
•an increase of $12 million in selling, general and administrative expenses primarily due to corporate cost reductions in 2020.
Crude Oil Transportation and Services
| Three Months Ended December 31, | |||||||||||
| 2021 | 2020 | ||||||||||
| Crude transportation volumes (MBbls/d) | 3,839 | 3,532 | |||||||||
| Crude terminals volumes (MBbls/d) | 2,606 | 2,223 | |||||||||
| Revenues | $ | 4,948 | $ | 2,802 | |||||||
| Cost of products sold | 4,239 | 2,134 | |||||||||
Segment margin | 709 | 668 | |||||||||
| Unrealized gains (losses) on commodity risk management activities | (16) | 3 | |||||||||
Operating expenses, excluding non-cash compensation expense | (133) | (125) | |||||||||
Selling, general and administrative expenses, excluding non-cash compensation expense | (33) | (36) | |||||||||
Adjusted EBITDA related to unconsolidated affiliates | 4 | 5 | |||||||||
Other | 2 | 2 | |||||||||
Segment Adjusted EBITDA | $ | 533 | $ | 517 | |||||||
For the three months ended December 31, 2021 compared to the same period last year, crude transportation volumes were higher on our Texas pipeline system and Bakken pipeline, driven by a recovery in crude oil production in these regions as a result of higher crude oil prices as well as higher refinery demand. Additionally, volumes benefited from higher demand on our Bayou Bridge pipeline, the impact of the Cushing South pipeline entering service in 2021, and contributions from assets acquired. Crude terminal volumes were higher due to increased refinery and export activity at our Gulf Coast terminals.
Adjusted EBITDA. For the three months ended December 31, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased due to the net impacts of the following:
•an increase of $23 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $58 million increase due to higher volumes on our Bakken Pipeline, a $9 million increase due to higher volumes on our Bayou Bridge pipeline, and a $6 million increase related to assets acquired in 2021, partially offset by a $16 million decrease from our Texas crude pipeline system due to lower average tariff rates realized and a $37 million decrease from our crude oil acquisition and marketing business due to unfavorable crude inventory valuation adjustments and less favorable pricing conditions impacting our Bakken to Gulf Coast trading operations; and
•a decrease of $3 million in selling, general and administrative expenses primarily due to lower legal expenses, partially offset by higher employee expenses and higher overhead allocations to the crude segment as a result of assets acquired; partially offset by
•an increase of $8 million in operating expenses primarily due to higher ad valorem taxes, higher employee expenses, and expenses related to assets acquired in 2021.
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Investment in Sunoco LP
| Three Months Ended December 31, | |||||||||||
| 2021 | 2020 | ||||||||||
| Revenues | $ | 4,954 | $ | 2,553 | |||||||
| Cost of products sold | 4,615 | 2,271 | |||||||||
Segment margin | 339 | 282 | |||||||||
Unrealized (gains) losses on commodity risk management activities | (9) | 6 | |||||||||
Operating expenses, excluding non-cash compensation expense | (93) | (71) | |||||||||
Selling, general and administrative, excluding non-cash compensation expense | (26) | (22) | |||||||||
Adjusted EBITDA related to unconsolidated affiliates | 2 | 3 | |||||||||
Inventory fair value adjustments | (22) | (44) | |||||||||
Other, net | 7 | 5 | |||||||||
Segment Adjusted EBITDA | $ | 198 | $ | 159 | |||||||
The Investment in Sunoco LP segment reflects the consolidated results of Sunoco LP.
Segment Adjusted EBITDA. For the three months ended December 31, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our investment in Sunoco LP increased due to the net impacts of the following:
•an increase in the gross profit on motor fuel sales of $47 million primarily due to a 31.1% increase in gross profit per gallon sold and a 3.1% increase in gallons sold; and
•an increase of $20 million in non motor fuel gross profit and lease income primarily due to an increase in storage tanks and terminals gross profit; partially offset by
•an increase in operating expenses and in selling, general and administrative expenses, primarily attributable to higher employee costs, acquisition costs, general liability insurance and credit card costs, as well as a change in expected credit losses, partially offset by a decrease in consulting costs.
Investment in USAC
| Three Months Ended December 31, | |||||||||||
| 2021 | 2020 | ||||||||||
| Revenues | $ | 160 | $ | 158 | |||||||
| Cost of products sold | 24 | 20 | |||||||||
Segment margin | 136 | 138 | |||||||||
Operating expenses, excluding non-cash compensation expense | (26) | (30) | |||||||||
Selling, general and administrative, excluding non-cash compensation expense | (11) | (10) | |||||||||
Other, net | — | 1 | |||||||||
Segment Adjusted EBITDA | $ | 99 | $ | 99 | |||||||
The Investment in USAC segment reflects the consolidated results of operations for USAC.
Segment Adjusted EBITDA. For the three months ended December 31, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our investment in USAC was unchanged due to the offsetting impacts of a slight decrease in margin due to a decrease in demand for compression services driven by a decline in U.S. crude oil and natural gas activity resulting in a decrease in average revenue generating horsepower per month, which was offset by favorable variances in operating expenses.
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All Other
| Three Months Ended December 31, | |||||||||||
| 2021 | 2020 | ||||||||||
Revenues | $ | 692 | $ | 466 | |||||||
Cost of products sold | 604 | 417 | |||||||||
Segment margin | 88 | 49 | |||||||||
| Unrealized gains (losses) on commodity risk management activities | (8) | 1 | |||||||||
Operating expenses, excluding non-cash compensation expense | (33) | (33) | |||||||||
Selling, general and administrative expenses, excluding non-cash compensation expense | (39) | (21) | |||||||||
Adjusted EBITDA related to unconsolidated affiliates | — | 1 | |||||||||
Other and eliminations | 16 | 46 | |||||||||
Segment Adjusted EBITDA | $ | 24 | $ | 43 | |||||||
Segment Adjusted EBITDA. For the three months ended December 31, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment decreased due to the net impacts of the following:
•a decrease of $15 million due to higher merger and acquisition expenses related to the Enable acquisition; and
•a decrease of $22 million due to insurance proceeds received in the prior period on settled claims related to our MTBE litigation; partially offset by
•an increase of $6 million from Energy Transfer Canada due to the aggregate impact of multiple smaller changes;
•an increase of $6 million due to higher compressor sales and lower operating expenses in our compressor business; and
•an increase of $4 million in revenues earned by our dual drive compression business.
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ENERGY TRANSFER LP AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ON LIQUIDITY
(In millions)
(unaudited)
The following table summarizes the status of our revolving credit facility. We also have consolidated subsidiaries with revolving credit facilities which are not included in this table.
| Facility Size | Funds Available at December 31, 2021 | Maturity Date | |||||||||||||||
| Five-Year Revolving Credit Facility | $ | 5,000 | $ | 2,030 | December 1, 2024 | ||||||||||||
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ENERGY TRANSFER LP AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ON UNCONSOLIDATED AFFILIATES
(In millions)
(unaudited)
The table below provides information on an aggregated basis for our unconsolidated affiliates, which are accounted for as equity method investments in the Partnership’s financial statements for the periods presented.
| Three Months Ended December 31, | |||||||||||
| 2021 | 2020 | ||||||||||
| Equity in earnings (losses) of unconsolidated affiliates: | |||||||||||
Citrus | $ | 34 | $ | 35 | |||||||
FEP | — | 19 | |||||||||
MEP | (5) | (3) | |||||||||
| White Cliffs | — | 1 | |||||||||
Other | 26 | 21 | |||||||||
Total equity in earnings of unconsolidated affiliates | $ | 55 | $ | 73 | |||||||
Adjusted EBITDA related to unconsolidated affiliates: | |||||||||||
Citrus | $ | 76 | $ | 83 | |||||||
FEP | — | 19 | |||||||||
MEP | 4 | 5 | |||||||||
| White Cliffs | 5 | 6 | |||||||||
Other | 38 | 35 | |||||||||
Total Adjusted EBITDA related to unconsolidated affiliates | $ | 123 | $ | 148 | |||||||
Distributions received from unconsolidated affiliates: | |||||||||||
Citrus | $ | 44 | $ | 36 | |||||||
FEP | — | 20 | |||||||||
MEP | 3 | 4 | |||||||||
| White Cliffs | 4 | 4 | |||||||||
Other | 26 | 23 | |||||||||
Total distributions received from unconsolidated affiliates | $ | 77 | $ | 87 | |||||||
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ENERGY TRANSFER LP AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ON NON-WHOLLY-OWNED JOINT VENTURE SUBSIDIARIES
(In millions)
(unaudited)
The table below provides information on an aggregated basis for our non-wholly-owned joint venture subsidiaries, which are reflected on a consolidated basis in our financial statements. The table below excludes Sunoco LP and USAC, which are non-wholly-owned subsidiaries that are publicly traded.
| Three Months Ended December 31, | |||||||||||
| 2021 | 2020 | ||||||||||
Adjusted EBITDA of non-wholly-owned subsidiaries (100%) (a) | $ | 656 | $ | 584 | |||||||
Our proportionate share of Adjusted EBITDA of non-wholly-owned subsidiaries (b) | 312 | 288 | |||||||||
Distributable Cash Flow of non-wholly-owned subsidiaries (100%) (c) | $ | 611 | $ | 543 | |||||||
Our proportionate share of Distributable Cash Flow of non-wholly-owned subsidiaries (d) | 284 | 270 | |||||||||
Below is our ownership percentage of certain non-wholly-owned subsidiaries:
| Non-wholly-owned subsidiary: | Energy Transfer Percentage Ownership (e) | ||||
Bakken Pipeline | 36.4 | % | |||
Bayou Bridge | 60.0 | % | |||
| Maurepas | 51.0 | % | |||
Ohio River System | 75.0 | % | |||
Permian Express Partners | 87.7 | % | |||
Red Bluff Express | 70.0 | % | |||
Rover | 32.6 | % | |||
| Energy Transfer Canada | 51.0 | % | |||
Others | various | ||||
(a)Adjusted EBITDA of non-wholly-owned subsidiaries reflects the total Adjusted EBITDA of our non-wholly-owned subsidiaries on an aggregated basis. This is the amount of EBITDA included in our consolidated non-GAAP measure of Adjusted EBITDA.
(b)Our proportionate share of Adjusted EBITDA of non-wholly-owned subsidiaries reflects the amount of Adjusted EBITDA of such subsidiaries (on an aggregated basis) that is attributable to our ownership interest.
(c)Distributable Cash Flow of non-wholly-owned subsidiaries reflects the total Distributable Cash Flow of our non-wholly-owned subsidiaries on an aggregated basis.
(d)Our proportionate share of Distributable Cash Flow of non-wholly-owned subsidiaries reflects the amount of Distributable Cash Flow of such subsidiaries (on an aggregated basis) that is attributable to our ownership interest. This is the amount of Distributable Cash Flow included in our consolidated non-GAAP measure of Distributable Cash Flow attributable to the partners of Energy Transfer.
(e)Our ownership reflects the total economic interest held by us and our subsidiaries. In some cases, this percentage comprises ownership interests held in (or by) multiple entities.
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