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
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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:
Securities registered pursuant to Section 12(b) of the Act:
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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 2.02. Results of Operations and Financial Condition.
On February 14, 2024, Energy Transfer LP (the “Partnership”) issued a press release announcing its financial and operating results for the fiscal year and fourth fiscal quarter ended December 31, 2023. 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.
| Exhibit Number | Description of the Exhibit | |||||||
| 104 | Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101) | |||||||
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 LP | |||||||||||
| By: | LE GP, LLC, its general partner | ||||||||||
| Date: | February 14, 2024 | By: | /s/ Dylan A. Bramhall | ||||||||
| Dylan A. Bramhall | |||||||||||
| Group Chief Financial Officer | |||||||||||
ENERGY TRANSFER REPORTS STRONG FOURTH QUARTER 2023 RESULTS
AND ANNOUNCES 2024 OUTLOOK
Dallas – February 14, 2024 – Energy Transfer LP (NYSE:ET) (“Energy Transfer” or the “Partnership”) today reported financial results for the quarter and year ended December 31, 2023.
Energy Transfer reported net income attributable to partners for the three months ended December 31, 2023 of $1.33 billion, an increase of $172 million compared to the same period last year. For the three months ended December 31, 2023, net income per common unit (basic) was $0.37.
Adjusted EBITDA for the three months ended December 31, 2023 was $3.60 billion compared to $3.44 billion for the same period last year, an increase of $165 million.
Distributable Cash Flow attributable to partners, as adjusted, for the three months ended December 31, 2023 was $2.03 billion compared to $1.91 billion for the same period last year.
Growth capital expenditures in 2023 were $1.59 billion while maintenance capital expenditures were $762 million.
2024 Outlook
•Energy Transfer expects its 2024 Adjusted EBITDA to range between $14.5 billion and $14.8 billion.
◦The midpoint of this range represents a 7% increase from 2023 Adjusted EBITDA of $13.7 billion, which was $100 million above the high end of Energy Transfer 2023 estimates.
•For 2024, the Partnership expects its growth capital expenditures to range from $2.4 billion to $2.6 billion, including approximately $300 million of spending that was deferred from Energy Transfer’s previous 2023 growth capital guidance. Maintenance capital expenditures for 2024 are expected to be between $835 million and $865 million.
Fourth Quarter 2023 Operational Highlights
•With the addition of new growth projects and acquisitions, Energy Transfer’s assets continued to reach new milestones during the fourth quarter of 2023.
◦NGL fractionation volumes were up 16%, setting a new Partnership record.
◦NGL transportation volumes were up 10%, setting a new Partnership record.
◦NGL exports were up more than 13%.
◦Interstate natural gas transportation volumes were up 5%.
◦Midstream gathered volumes increased 5%.
◦Crude oil transportation and terminal volumes were up 39% and 16%, respectively.
Fourth Quarter 2023 Strategic Highlights
•In November 2023, Energy Transfer completed its previously announced merger with Crestwood Equity Partners LP (“Crestwood”) and integration of the combined operations is ongoing. The merger is now expected to generate $80 million of annual cost synergies by 2026 with $65 million in 2024, before additional anticipated benefits from financial and commercial synergies.
•In November 2023, Energy Transfer announced its entry into a non-binding Heads of Agreement (“HOA”) with TotalEnergies related to term crude oil offtake from its proposed Blue Marlin Offshore Port for four million barrels per month.
Financial Highlights
•In January 2024, Energy Transfer announced a quarterly cash distribution of $0.3150 per common unit ($1.26 annualized) for the quarter ended December 31, 2023, which is an increase of 3.3% compared to the fourth quarter of 2022.
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•In January 2024, the Partnership issued $1.25 billion aggregate principal amount of 5.55% senior notes due 2034, $1.75 billion aggregate principal amount of 5.95% senior notes due 2054 and $800 million aggregate principal amount of 8.00% fixed-to-fixed reset rate junior subordinated notes due 2054. The Partnership used the net proceeds to refinance existing indebtedness, to redeem certain of its outstanding preferred units (as detailed below) and for general partnership purposes.
•In February 2024, the Partnership redeemed all of its outstanding Series C preferred units and Series D preferred units. The Partnership also intends to redeem all of its outstanding Series E preferred units in May 2024.
•As of December 31, 2023, the Partnership’s revolving credit facility had an aggregate $3.56 billion of available borrowing capacity.
•For the three months ended December 31, 2023, the Partnership invested approximately $379 million on growth capital expenditures.
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 one-third of the Partnership’s consolidated Adjusted EBITDA for the three months or full year ended December 31, 2023. 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 14, 2024 to discuss its fourth quarter 2023 results and provide an update on the Partnership, including its outlook for 2024. 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 the United States, with more than 125,000 miles of pipeline and associated energy infrastructure. Energy Transfer’s strategic network spans 44 states with assets 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 approximately 34% of the outstanding common units of Sunoco LP (NYSE: SUN), and the general partner interests and approximately 45% of the outstanding 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. For more information, visit the Sunoco LP website at www.sunocolp.com.
USA Compression Partners, LP (NYSE: USAC) 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 midstream natural gas 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 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. 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.
| Investor Relations: | Media Relations: | |||||||
| Bill Baerg, Brent Ratliff, Lyndsay Hannah, 214-981-0795 | Vicki Granado, 214-840-5820 | |||||||
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ENERGY TRANSFER LP AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(In millions)
(unaudited)
| December 31, 2023 | December 31, 2022 | ||||||||||
| ASSETS | |||||||||||
| Current assets | $ | 12,433 | $ | 12,081 | |||||||
| Property, plant and equipment, net | 85,351 | 80,311 | |||||||||
| Investments in unconsolidated affiliates | 3,097 | 2,893 | |||||||||
Lease right-of-use assets, net | 826 | 819 | |||||||||
| Other non-current assets, net | 1,733 | 1,558 | |||||||||
| Intangible assets, net | 6,239 | 5,415 | |||||||||
| Goodwill | 4,019 | 2,566 | |||||||||
| Total assets | $ | 113,698 | $ | 105,643 | |||||||
| LIABILITIES AND EQUITY | |||||||||||
Current liabilities (1) | $ | 11,277 | $ | 10,368 | |||||||
| Long-term debt, less current maturities | 51,380 | 48,260 | |||||||||
| Non-current derivative liabilities | 4 | 23 | |||||||||
Non-current operating lease liabilities | 778 | 798 | |||||||||
| Deferred income taxes | 3,931 | 3,701 | |||||||||
| Other non-current liabilities | 1,611 | 1,341 | |||||||||
| Commitments and contingencies | |||||||||||
| Redeemable noncontrolling interests | 778 | 493 | |||||||||
| Equity: | |||||||||||
| Limited Partners: | |||||||||||
| Preferred Unitholders | 6,459 | 6,051 | |||||||||
| Common Unitholders | 30,197 | 26,960 | |||||||||
| General Partner | (2) | (2) | |||||||||
| Accumulated other comprehensive income | 28 | 16 | |||||||||
| Total partners’ capital | 36,682 | 33,025 | |||||||||
| Noncontrolling interests | 7,257 | 7,634 | |||||||||
| Total equity | 43,939 | 40,659 | |||||||||
| Total liabilities and equity | $ | 113,698 | $ | 105,643 | |||||||
(1) As of December 31, 2023, current liabilities includes $1.00 billion of senior notes issued by the Bakken Pipeline entities, which mature in April 2024. The Partnership’s proportional ownership in the Bakken Pipeline entities 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, | ||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
| REVENUES | $ | 20,532 | $ | 20,501 | $ | 78,586 | $ | 89,876 | |||||||||||||||
| COSTS AND EXPENSES: | |||||||||||||||||||||||
| Cost of products sold | 15,780 | 16,063 | 60,541 | 72,232 | |||||||||||||||||||
| Operating expenses | 1,144 | 1,356 | 4,368 | 4,338 | |||||||||||||||||||
| Depreciation, depletion and amortization | 1,158 | 1,060 | 4,385 | 4,164 | |||||||||||||||||||
| Selling, general and administrative | 285 | 216 | 985 | 1,018 | |||||||||||||||||||
| Impairment losses and other | — | — | 12 | 386 | |||||||||||||||||||
| Total costs and expenses | 18,367 | 18,695 | 70,291 | 82,138 | |||||||||||||||||||
| OPERATING INCOME | 2,165 | 1,806 | 8,295 | 7,738 | |||||||||||||||||||
| OTHER INCOME (EXPENSE): | |||||||||||||||||||||||
| Interest expense, net of interest capitalized | (686) | (592) | (2,578) | (2,306) | |||||||||||||||||||
| Equity in earnings of unconsolidated affiliates | 97 | 71 | 383 | 257 | |||||||||||||||||||
| Gains on extinguishments of debt | 2 | — | 2 | — | |||||||||||||||||||
| Gains (losses) on interest rate derivatives | (11) | (10) | 36 | 293 | |||||||||||||||||||
| Non-operating litigation related loss | (2) | — | (627) | — | |||||||||||||||||||
| Other, net | 49 | 207 | 86 | 90 | |||||||||||||||||||
| INCOME BEFORE INCOME TAX EXPENSE | 1,614 | 1,482 | 5,597 | 6,072 | |||||||||||||||||||
| Income tax expense | 47 | 45 | 303 | 204 | |||||||||||||||||||
| NET INCOME | 1,567 | 1,437 | 5,294 | 5,868 | |||||||||||||||||||
| Less: Net income attributable to noncontrolling interest | 219 | 268 | 1,299 | 1,061 | |||||||||||||||||||
| Less: Net income attributable to redeemable noncontrolling interests | 21 | 14 | 60 | 51 | |||||||||||||||||||
| NET INCOME ATTRIBUTABLE TO PARTNERS | 1,327 | 1,155 | 3,935 | 4,756 | |||||||||||||||||||
| General Partner’s interest in net income | 1 | 1 | 3 | 4 | |||||||||||||||||||
| Preferred Unitholders’ interest in net income | 123 | 105 | 463 | 422 | |||||||||||||||||||
| Common Unitholders’ interest in net income | $ | 1,203 | $ | 1,049 | $ | 3,469 | $ | 4,330 | |||||||||||||||
| NET INCOME PER COMMON UNIT: | |||||||||||||||||||||||
| Basic | $ | 0.37 | $ | 0.34 | $ | 1.10 | $ | 1.40 | |||||||||||||||
| Diluted | $ | 0.37 | $ | 0.34 | $ | 1.09 | $ | 1.40 | |||||||||||||||
| WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING: | |||||||||||||||||||||||
| Basic | 3,278.6 | 3,090.3 | 3,161.7 | 3,086.8 | |||||||||||||||||||
| Diluted | 3,295.3 | 3,103.2 | 3,177.2 | 3,097.0 | |||||||||||||||||||
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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, | ||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
Reconciliation of net income to Adjusted EBITDA and Distributable Cash Flow (a): | |||||||||||||||||||||||
| Net income | $ | 1,567 | $ | 1,437 | $ | 5,294 | $ | 5,868 | |||||||||||||||
| Interest expense, net of interest capitalized | 686 | 592 | 2,578 | 2,306 | |||||||||||||||||||
| Impairment losses and other | — | — | 12 | 386 | |||||||||||||||||||
| Income tax expense | 47 | 45 | 303 | 204 | |||||||||||||||||||
| Depreciation, depletion and amortization | 1,158 | 1,060 | 4,385 | 4,164 | |||||||||||||||||||
| Non-cash compensation expense | 31 | 27 | 130 | 115 | |||||||||||||||||||
| (Gains) losses on interest rate derivatives | 11 | 10 | (36) | (293) | |||||||||||||||||||
| Unrealized (gains) losses on commodity risk management activities | (185) | 88 | (3) | (42) | |||||||||||||||||||
| Gains on extinguishments of debt | (2) | — | (2) | — | |||||||||||||||||||
| Inventory valuation adjustments (Sunoco LP) | 227 | 76 | 114 | (5) | |||||||||||||||||||
| Equity in earnings of unconsolidated affiliates | (97) | (71) | (383) | (257) | |||||||||||||||||||
| Adjusted EBITDA related to unconsolidated affiliates | 177 | 156 | 691 | 565 | |||||||||||||||||||
| Non-operating litigation related loss | 2 | — | 627 | — | |||||||||||||||||||
| Other, net | (20) | 17 | (12) | 82 | |||||||||||||||||||
| Adjusted EBITDA (consolidated) | 3,602 | 3,437 | 13,698 | 13,093 | |||||||||||||||||||
| Adjusted EBITDA related to unconsolidated affiliates | (177) | (156) | (691) | (565) | |||||||||||||||||||
| Distributable Cash Flow from unconsolidated affiliates | 121 | 89 | 485 | 359 | |||||||||||||||||||
| Interest expense, net of interest capitalized | (686) | (592) | (2,578) | (2,306) | |||||||||||||||||||
| Preferred unitholders’ distributions | (135) | (118) | (511) | (471) | |||||||||||||||||||
| Current income tax expense | (31) | (17) | (100) | (18) | |||||||||||||||||||
| Transaction-related income taxes | — | — | — | (42) | |||||||||||||||||||
| Maintenance capital expenditures | (259) | (294) | (860) | (821) | |||||||||||||||||||
| Other, net | 20 | 3 | 41 | 20 | |||||||||||||||||||
| Distributable Cash Flow (consolidated) | 2,455 | 2,352 | 9,484 | 9,249 | |||||||||||||||||||
| Distributable Cash Flow attributable to Sunoco LP (100%) | (145) | (152) | (659) | (648) | |||||||||||||||||||
| Distributions from Sunoco LP | 43 | 42 | 173 | 166 | |||||||||||||||||||
| Distributable Cash Flow attributable to USAC (100%) | (80) | (60) | (281) | (221) | |||||||||||||||||||
| Distributions from USAC | 24 | 24 | 97 | 97 | |||||||||||||||||||
| Distributable Cash Flow attributable to noncontrolling interests in other non-wholly owned consolidated subsidiaries | (369) | (314) | (1,352) | (1,240) | |||||||||||||||||||
| Distributable Cash Flow attributable to the partners of Energy Transfer | 1,928 | 1,892 | 7,462 | 7,403 | |||||||||||||||||||
Transaction-related adjustments (b) | 102 | 18 | 116 | 44 | |||||||||||||||||||
| Distributable Cash Flow attributable to the partners of Energy Transfer, as adjusted | $ | 2,030 | $ | 1,910 | $ | 7,578 | $ | 7,447 | |||||||||||||||
| Distributions to partners: | |||||||||||||||||||||||
| Limited Partners | $ | 1,061 | $ | 944 | $ | 3,984 | $ | 3,089 | |||||||||||||||
| General Partner | 1 | 1 | 3 | 3 | |||||||||||||||||||
| Total distributions to be paid to partners | $ | 1,062 | $ | 945 | $ | 3,987 | $ | 3,092 | |||||||||||||||
Common Units outstanding – end of period | 3,367.5 | 3,094.4 | 3,367.5 | 3,094.4 | |||||||||||||||||||
(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 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.
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There are material limitations to using measures such as Adjusted EBITDA and Distributable Cash Flow, 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 and Distributable Cash Flow may not be consistent with similarly titled measures of other companies and should be viewed in conjunction with measures that are computed in accordance with GAAP, such as operating income, net income and cash flows 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 investees’ 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 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.
(b) For the three months and year ended December 31, 2023, transaction-related adjustments includes $49 million of Distributable Cash Flow attributable to the operations of Crestwood for October 1, 2023 through the acquisition date, which represents amounts distributable to Energy Transfer’s common unitholders (including the holders of the common units issued in the Crestwood acquisition) with respect to the fourth quarter 2023 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, | |||||||||||
| 2023 | 2022 | ||||||||||
| Segment Adjusted EBITDA: | |||||||||||
| Intrastate transportation and storage | $ | 242 | $ | 433 | |||||||
| Interstate transportation and storage | 541 | 494 | |||||||||
| Midstream | 674 | 632 | |||||||||
| NGL and refined products transportation and services | 1,042 | 928 | |||||||||
| Crude oil transportation and services | 775 | 571 | |||||||||
| Investment in Sunoco LP | 236 | 238 | |||||||||
| Investment in USAC | 139 | 113 | |||||||||
| All other | (47) | 28 | |||||||||
| Adjusted EBITDA (consolidated) | $ | 3,602 | $ | 3,437 | |||||||
The following analysis of segment operating results, includes a measure of segment margin. 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.
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Intrastate Transportation and Storage
| Three Months Ended December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| Natural gas transported (BBtu/d) | 14,229 | 14,295 | |||||||||
| Withdrawals from storage natural gas inventory (BBtu) | 6,440 | 5,425 | |||||||||
| Revenues | $ | 892 | $ | 1,600 | |||||||
| Cost of products sold | 497 | 992 | |||||||||
| Segment margin | 395 | 608 | |||||||||
| Unrealized gains on commodity risk management activities | (78) | (84) | |||||||||
| Operating expenses, excluding non-cash compensation expense | (72) | (83) | |||||||||
| Selling, general and administrative expenses, excluding non-cash compensation expense | (13) | (16) | |||||||||
| Adjusted EBITDA related to unconsolidated affiliates | 6 | 8 | |||||||||
| Other | 4 | — | |||||||||
| Segment Adjusted EBITDA | $ | 242 | $ | 433 | |||||||
Transported volumes decreased primarily due to decreased production from our Haynesville assets.
Segment Adjusted EBITDA. For the three months ended December 31, 2023 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment decreased due to the net impacts of the following:
•a decrease of $134 million in realized natural gas sales and other primarily due to lower pipeline optimization from both physical sales and settled derivatives;
•a decrease of $53 million in storage margin primarily due to lower storage optimization from hedged inventory activity; and
•a decrease of $20 million in retained fuel revenues related to lower natural gas prices; partially offset by
•a decrease of $11 million in operating expenses related to a decrease in cost of fuel consumption from lower natural gas prices.
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Interstate Transportation and Storage
| Three Months Ended December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| Natural gas transported (BBtu/d) | 16,651 | 15,821 | |||||||||
| Natural gas sold (BBtu/d) | 31 | 26 | |||||||||
| Revenues | $ | 620 | $ | 606 | |||||||
| Cost of products sold | 1 | 1 | |||||||||
| Segment margin | 619 | 605 | |||||||||
| Operating expenses, excluding non-cash compensation, amortization, accretion and other non-cash expenses | (179) | (201) | |||||||||
| Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses | (26) | (31) | |||||||||
| Adjusted EBITDA related to unconsolidated affiliates | 122 | 115 | |||||||||
| Other | 5 | 6 | |||||||||
| Segment Adjusted EBITDA | $ | 541 | $ | 494 | |||||||
Transported volumes increased primarily due to our Gulf Run system going in service in December 2022, as well as more capacity sold and higher utilization on our Transwestern, Rover and Trunkline systems.
Segment Adjusted EBITDA. For the three months ended December 31, 2023 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment increased due to the net impacts of the following:
•an increase of $14 million in segment margin primarily due to a $44 million increase resulting from our Gulf Run system being placed in service in December 2022, an $8 million increase in transportation revenue from several of our interstate pipeline systems due to higher contracted volumes and higher rates, and a $6 million increase due to higher parking and storage. These increases were partially offset by a $34 million decrease due to lower operational gas sales resulting from lower prices and a $6 million decrease due to lower rates on our Panhandle system resulting from a FERC rate case;
•a decrease of $22 million in operating expenses primarily due to a $15 million decrease from the revaluation of system gas and an aggregate $11 million decrease in various other operating costs. These decreases were partially offset by $4 million of incremental expenses from our Gulf Run system being placed in service in December 2022;
•a decrease of $5 million in selling, general and administrative expenses primarily due to lower M&A costs; and
•an increase of $7 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to a $4 million increase from our Citrus joint venture as a result of revenue from new projects and lower operating expenses and a $3 million increase from our Southeast Supply Header joint venture due to increased capacity sold at higher rates.
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Midstream
| Three Months Ended December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| Gathered volumes (BBtu/d) | 20,322 | 19,434 | |||||||||
| NGLs produced (MBbls/d) | 976 | 813 | |||||||||
| Equity NGLs (MBbls/d) | 49 | 43 | |||||||||
| Revenues | $ | 2,407 | $ | 3,255 | |||||||
| Cost of products sold | 1,379 | 2,264 | |||||||||
| Segment margin | 1,028 | 991 | |||||||||
| Operating expenses, excluding non-cash compensation expense | (314) | (319) | |||||||||
| Selling, general and administrative expenses, excluding non-cash compensation expense | (47) | (46) | |||||||||
| Adjusted EBITDA related to unconsolidated affiliates | 6 | 5 | |||||||||
| Other | 1 | 1 | |||||||||
| Segment Adjusted EBITDA | $ | 674 | $ | 632 | |||||||
Gathered volumes and NGL production increased primarily due to newly acquired assets and higher volumes from existing customers.
Segment Adjusted EBITDA. For the three months ended December 31, 2023 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 $95 million due to newly acquired assets and increased processing volumes in the Permian, South Texas and Midcontinent/Panhandle regions; and
•a decrease of $5 million in operating expenses primarily due to a $12 million decrease in environmental reserve adjustments and a $14 million decrease due to lower maintenance project costs, partially offset by a $21 million increase due to newly acquired assets; partially offset by
•a decrease of $58 million due to lower natural gas prices of $45 million and lower NGL prices of $13 million.
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NGL and Refined Products Transportation and Services
| Three Months Ended December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| NGL transportation volumes (MBbls/d) | 2,162 | 1,970 | |||||||||
| Refined products transportation volumes (MBbls/d) | 552 | 520 | |||||||||
| NGL and refined products terminal volumes (MBbls/d) | 1,446 | 1,316 | |||||||||
| NGL fractionation volumes (MBbls/d) | 1,137 | 982 | |||||||||
| Revenues | $ | 6,039 | $ | 5,748 | |||||||
| Cost of products sold | 4,684 | 4,735 | |||||||||
| Segment margin | 1,355 | 1,013 | |||||||||
| Unrealized (gains) losses on commodity risk management activities | (72) | 174 | |||||||||
| Operating expenses, excluding non-cash compensation expense | (225) | (254) | |||||||||
| Selling, general and administrative expenses, excluding non-cash compensation expense | (51) | (31) | |||||||||
| Adjusted EBITDA related to unconsolidated affiliates | 34 | 26 | |||||||||
| Other | 1 | — | |||||||||
| Segment Adjusted EBITDA | $ | 1,042 | $ | 928 | |||||||
NGL transportation and terminal volumes increased primarily due to higher volumes from the Permian region, on our Mariner East pipeline system and on our Gulf Coast export pipelines. The increase in transportation volumes and the commissioning of our eighth fractionator in August 2023 also led to higher fractionated volumes at our Mont Belvieu, Texas fractionation facility.
Segment Adjusted EBITDA. For the three months ended December 31, 2023 compared to the same period last year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to the net impacts of the following:
•an increase of $50 million in terminal services margin primarily due to a $31 million increase from our Marcus Hook Terminal due to contractual rate escalations and higher throughput, an increase of $17 million from higher export volumes loaded at our Nederland Terminal and a $2 million increase due to increased tank leases and throughput at our Eagle Point Terminal;
•an increase of $47 million in transportation margin primarily due to a $25 million increase resulting from higher throughput and contractual rate escalations on our Mariner East pipeline system, a $19 million increase resulting from higher throughput and contractual rate escalations on our Texas y-grade pipeline system, an $11 million increase from higher throughput and contractual rate escalations on our refined product pipelines and an $8 million increase from higher exported volumes feeding into our Nederland Terminal. These increases were partially offset by intrasegment charges of $10 million and $5 million which were fully offset within our marketing and fractionation margins, respectively;
•a decrease of $29 million in operating expenses primarily due to a $17 million decrease in gas and power utility costs, a $3 million decrease in office expenses and decreases totaling $7 million from various other operating expenses;
•an increase of $18 million in fractionators and refinery services margin primarily due to a $10 million increase resulting from higher volumes, $5 million in intrasegment margin which was fully offset within our transportation margin and a $3 million increase from a more favorable pricing environment impacting our refinery services business;
•an increase of $13 million in storage margin primarily due to a $7 million increase in fees generated from export related activity, a $4 million increase in throughput fees and a $2 million increase in blending activity; and
•an increase of $8 million in adjusted EBITDA related to unconsolidated affiliates due to higher volumes on certain joint venture pipelines; partially offset by
•a decrease of $32 million in marketing margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $42 million decrease in gains from the optimization of hedged NGL and refined product inventories. This decrease was partially offset by intrasegment margin of $10 million which was fully offset within our transportation margin; and
•an increase of $20 million in selling, general and administrative expenses primarily due to a $13 million increase resulting from a one-time charge related to regulatory expenses, a $3 million increase in insurance costs and a $2 million increase in overhead expenses.
11
Crude Oil Transportation and Services
| Three Months Ended December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| Crude oil transportation volumes (MBbls/d) | 5,949 | 4,272 | |||||||||
| Crude oil terminal volumes (MBbls/d) | 3,430 | 2,954 | |||||||||
| Revenues | $ | 7,214 | $ | 6,340 | |||||||
| Cost of products sold | 6,213 | 5,570 | |||||||||
| Segment margin | 1,001 | 770 | |||||||||
| Unrealized gains on commodity risk management activities | (13) | (10) | |||||||||
| Operating expenses, excluding non-cash compensation expense | (191) | (178) | |||||||||
| Selling, general and administrative expenses, excluding non-cash compensation expense | (30) | (12) | |||||||||
| Adjusted EBITDA related to unconsolidated affiliates | 7 | 1 | |||||||||
| Other | 1 | — | |||||||||
| Segment Adjusted EBITDA | $ | 775 | $ | 571 | |||||||
Crude oil transportation volumes were higher on our Texas pipeline system due to higher Permian crude oil production, higher gathered volumes and contributions from assets acquired in 2023. Bakken Pipeline volumes were also higher. Volumes on our Bayou Bridge Pipeline were higher due to continuing strong Gulf Coast refinery demand. Midcontinent systems were higher, driven by contributions from assets acquired in 2023. We also realized higher Bakken gathering volumes. Crude terminal volumes were higher due to growth in Permian and Bakken volumes, stronger Gulf Coast refinery utilization and contributions from assets acquired in 2023.
Adjusted EBITDA. For the three months ended December 31, 2023 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 $228 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $144 million increase from recently acquired assets, a $72 million increase from higher volumes on our Bakken Pipeline, a $25 million increase from higher throughput and exports at our Gulf Coast terminals as well as the recognition of a customer deficiency, a $12 million increase from higher volumes on our Midcontinent gathering systems, a $5 million increase from higher volumes on our Texas crude pipeline system and a $3 million increase from our Bayou Bridge Pipeline, partially offset by a $35 million decrease from our crude oil acquisition and marketing business primarily due to less favorable pricing and higher affiliate fees from higher volumes; and
•an increase of $6 million in Adjusted EBITDA related to unconsolidated affiliates due to assets acquired and higher volumes on our White Cliffs crude pipeline; partially offset by
•an increase of $18 million in selling, general and administrative expenses primarily due to a settlement related to a legal matter in the prior period; and
•an increase of $13 million in operating expenses primarily due to a $30 million increase from assets acquired, partially offset by a $5 million decrease in volume-driven expenses and an $11 million decrease in maintenance project expenses.
12
Investment in Sunoco LP
| Three Months Ended December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| Revenues | $ | 5,641 | $ | 5,918 | |||||||
| Cost of products sold | 5,492 | 5,647 | |||||||||
| Segment margin | 149 | 271 | |||||||||
| Unrealized (gains) losses on commodity risk management activities | (10) | 18 | |||||||||
| Operating expenses, excluding non-cash compensation expense | (110) | (103) | |||||||||
| Selling, general and administrative expenses, excluding non-cash compensation expense | (30) | (33) | |||||||||
| Adjusted EBITDA related to unconsolidated affiliates | 2 | 3 | |||||||||
| Inventory fair value adjustments | 227 | 76 | |||||||||
| Other, net | 8 | 6 | |||||||||
| Segment Adjusted EBITDA | $ | 236 | $ | 238 | |||||||
The Investment in Sunoco LP segment reflects the consolidated results of Sunoco LP.
Segment Adjusted EBITDA. For the three months ended December 31, 2023 compared to the same period last year, Segment Adjusted EBITDA related to our investment in Sunoco LP decreased primarily due to an increase in operating expenses.
In January 2024, Sunoco LP announced a definitive agreement to acquire NuStar Energy L.P. in an all-equity unit-for-unit exchange. The transaction is expected to close in the second quarter of 2024, subject to customary closing conditions.
Investment in USAC
| Three Months Ended December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| Revenues | $ | 225 | $ | 191 | |||||||
| Cost of products sold | 33 | 33 | |||||||||
| Segment margin | 192 | 158 | |||||||||
| Operating expenses, excluding non-cash compensation expense | (40) | (33) | |||||||||
| Selling, general and administrative expenses, excluding non-cash compensation expense | (14) | (12) | |||||||||
| Other, net | 1 | — | |||||||||
| Segment Adjusted EBITDA | $ | 139 | $ | 113 | |||||||
The Investment in USAC segment reflects the consolidated results of USAC.
Segment Adjusted EBITDA. For the three months ended December 31, 2023 compared to the same period last year, Segment Adjusted EBITDA related to our investment in USAC increased primarily due to higher revenue-generating horsepower as a result of increased demand for compression services, higher market-based rates on newly deployed and redeployed compression units and higher average rates on existing customer contracts.
13
All Other
| Three Months Ended December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| Revenues | $ | 411 | $ | 813 | |||||||
| Cost of products sold | 386 | 780 | |||||||||
| Segment margin | 25 | 33 | |||||||||
| Unrealized gains on commodity risk management activities | (11) | (10) | |||||||||
| Operating expenses, excluding non-cash compensation expense | (22) | (5) | |||||||||
| Selling, general and administrative expenses, excluding non-cash compensation expense | (52) | (16) | |||||||||
| Adjusted EBITDA related to unconsolidated affiliates | 1 | 1 | |||||||||
| Other and eliminations | 12 | 25 | |||||||||
| Segment Adjusted EBITDA | $ | (47) | $ | 28 | |||||||
Segment Adjusted EBITDA. For the three months ended December 31, 2023 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment decreased primarily due to:
•a decrease of $40 million due to higher M&A related expenses;
•a decrease of $12 million in storage gains;
•a decrease of $6 million from our dual drive compression business due to lower gas prices and increased electricity costs; and
•a decrease of $5 million from our power trading business; partially offset by
•an increase of $7 million due to increased sales in our compressor business.
14
ENERGY TRANSFER LP AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ON LIQUIDITY
(In millions)
(unaudited)
The table below provides information on 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, 2023 | Maturity Date | |||||||||||||||
| Five-Year Revolving Credit Facility | $ | 5,000 | $ | 3,559 | April 11, 2027 | ||||||||||||
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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, | |||||||||||
| 2023 | 2022 | ||||||||||
| Equity in earnings (losses) of unconsolidated affiliates: | |||||||||||
Citrus | $ | 36 | $ | 32 | |||||||
MEP | 19 | 17 | |||||||||
| White Cliffs | 5 | (9) | |||||||||
| Explorer | 10 | 8 | |||||||||
Other | 27 | 23 | |||||||||
Total equity in earnings of unconsolidated affiliates | $ | 97 | $ | 71 | |||||||
Adjusted EBITDA related to unconsolidated affiliates: | |||||||||||
Citrus | $ | 85 | $ | 81 | |||||||
MEP | 27 | 26 | |||||||||
| White Cliffs | 10 | 5 | |||||||||
| Explorer | 15 | 13 | |||||||||
Other | 40 | 31 | |||||||||
Total Adjusted EBITDA related to unconsolidated affiliates | $ | 177 | $ | 156 | |||||||
Distributions received from unconsolidated affiliates: | |||||||||||
Citrus | $ | 12 | $ | — | |||||||
MEP | 26 | 13 | |||||||||
| White Cliffs | 7 | 4 | |||||||||
| Explorer | 9 | 7 | |||||||||
Other | 31 | 22 | |||||||||
Total distributions received from unconsolidated affiliates | $ | 85 | $ | 46 | |||||||
16
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, | |||||||||||
| 2023 | 2022 | ||||||||||
Adjusted EBITDA of non-wholly owned subsidiaries (100%) (a) | $ | 709 | $ | 613 | |||||||
Our proportionate share of Adjusted EBITDA of non-wholly owned subsidiaries (b) | 334 | 294 | |||||||||
Distributable Cash Flow of non-wholly owned subsidiaries (100%) (c) | $ | 682 | $ | 593 | |||||||
Our proportionate share of Distributable Cash Flow of non-wholly owned subsidiaries (d) | 313 | 279 | |||||||||
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 | % | |||
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 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 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. In addition to the ownership reflected in the table above, the Partnership also owned a 51% interest in Energy Transfer Canada until August 2022.
17