ENERGY TRANSFER REPORTS SECOND QUARTER 2023 RESULTS
Dallas - August 2, 2023 - Energy Transfer LP (NYSE:ET) (“Energy Transfer” or the “Partnership”) today reported financial results for the quarter ended June 30, 2023.
Energy Transfer reported net income attributable to partners for the three months ended June 30, 2023 of $911 million. For the three months ended June 30, 2023, net income per common unit (basic) was $0.25 per unit.
Adjusted EBITDA for the three months ended June 30, 2023 was $3.12 billion compared to $3.23 billion for the three months ended June 30, 2022.
Distributable Cash Flow attributable to partners, as adjusted, for the three months ended June 30, 2023 was $1.55 billion compared to $1.88 billion for the three months ended June 30, 2022.
Growth capital expenditures in the second quarter of 2023 were $387 million while maintenance capital expenditures were $216 million.
Operational Highlights
•During the second quarter of 2023, Energy Transfer’s assets continued to reach new milestones, with volumes increasing across most segments compared to the same period last year.
•NGL fractionation volumes were up 5%, setting a new Partnership record.
•NGL transportation volumes were up 13%, setting a new Partnership record.
•Midstream gathered volumes increased 8%, setting a new Partnership record.
•Intrastate natural gas transportation volumes were up 3%, setting a new Partnership record.
•Interstate natural gas transportation volumes were up 17%.
•Crude transportation and terminal volumes were up 23% and 15%, respectively.
•Total NGL exports out of both the Nederland and Marcus Hook Terminals reached another record in the second quarter.
•In June 2023, the 200 MMcf/d Bear cryogenic processing plant, which is located in the Delaware Basin, was placed into service.
Strategic Highlights
•In May 2023, the Partnership completed the acquisition of Lotus Midstream Operations, LLC, and integration of operations is ongoing.
•In July 2023, Lake Charles LNG entered into three non-binding Heads of Agreements (“HOAs”) related to long-term LNG offtake for an aggregate of 3.6 million tonnes per annum.
Financial Highlights
•Energy Transfer expects its full-year 2023 Adjusted EBITDA to range between $13.1 billion and $13.4 billion, which is slightly tighter than the previous range ($13.05 billion to $13.45 billion) while keeping the midpoint the same.
•In July 2023, Energy Transfer announced a quarterly cash distribution of $0.31 per common unit ($1.24 annualized) for the quarter ended June 30, 2023.
•As of June 30, 2023, the Partnership’s revolving credit facility had an aggregate $2.36 billion of available borrowing capacity.
•For the three months ended June 30, 2023, the Partnership invested approximately $387 million on growth capital expenditures.
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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 ended June 30, 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, August 2, 2023 to discuss its second quarter 2023 results and provide an update on the Partnership. 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 nearly 125,000 miles of pipeline and associated energy infrastructure. Energy Transfer’s strategic network spans 41 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 47% 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 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.
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
(Dollars in millions)
(unaudited)
| June 30, 2023 | December 31, 2022 | ||||||||||
| ASSETS | |||||||||||
| Current assets | $ | 10,598 | $ | 12,081 | |||||||
| Property, plant and equipment, net | 81,149 | 80,311 | |||||||||
| Investments in unconsolidated affiliates | 3,007 | 2,893 | |||||||||
| Lease right-of-use assets, net | 826 | 819 | |||||||||
| Non-current derivative assets | 3 | — | |||||||||
| Other non-current assets, net | 1,684 | 1,558 | |||||||||
| Intangible assets, net | 5,301 | 5,415 | |||||||||
| Goodwill | 2,564 | 2,566 | |||||||||
Total assets | $ | 105,132 | $ | 105,643 | |||||||
| LIABILITIES AND EQUITY | |||||||||||
Current liabilities (1) | $ | 13,013 | $ | 10,368 | |||||||
| Long-term debt, less current maturities | 44,672 | 48,260 | |||||||||
| Non-current derivative liabilities | 23 | 23 | |||||||||
| Non-current operating lease liabilities | 786 | 798 | |||||||||
| Deferred income taxes | 3,839 | 3,701 | |||||||||
| Other non-current liabilities | 1,342 | 1,341 | |||||||||
| Commitments and contingencies | |||||||||||
| Redeemable noncontrolling interests | 495 | 493 | |||||||||
| Equity: | |||||||||||
Limited Partners: | |||||||||||
| Preferred Unitholders | 6,042 | 6,051 | |||||||||
| Common Unitholders | 27,487 | 26,960 | |||||||||
General Partner | (2) | (2) | |||||||||
| Accumulated other comprehensive income | 24 | 16 | |||||||||
Total partners’ capital | 33,551 | 33,025 | |||||||||
Noncontrolling interests | 7,411 | 7,634 | |||||||||
Total equity | 40,962 | 40,659 | |||||||||
Total liabilities and equity | $ | 105,132 | $ | 105,643 | |||||||
(1) As of June 30, 2023, current liabilities include a total of $3.45 billion of current maturities of long-term debt; this total comprises (i) $2.45 billion, representing the amount of Energy Transfer senior notes maturing on or before June 30, 2024, less the current available capacity on the Partnership’s Five-Year Credit Facility and (ii) $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
(Dollars and units in millions, except per unit data)
(unaudited)
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
| REVENUES | $ | 18,320 | $ | 25,945 | $ | 37,315 | $ | 46,436 | |||||||||||||||
| COSTS AND EXPENSES: | |||||||||||||||||||||||
Cost of products sold | 14,092 | 21,515 | 28,702 | 37,653 | |||||||||||||||||||
Operating expenses | 1,094 | 1,060 | 2,119 | 2,009 | |||||||||||||||||||
Depreciation, depletion and amortization | 1,061 | 1,046 | 2,120 | 2,074 | |||||||||||||||||||
Selling, general and administrative | 228 | 211 | 466 | 441 | |||||||||||||||||||
| Impairment losses | 10 | — | 11 | 300 | |||||||||||||||||||
Total costs and expenses | 16,485 | 23,832 | 33,418 | 42,477 | |||||||||||||||||||
| OPERATING INCOME | 1,835 | 2,113 | 3,897 | 3,959 | |||||||||||||||||||
| OTHER INCOME (EXPENSE): | |||||||||||||||||||||||
Interest expense, net of interest capitalized | (641) | (578) | (1,260) | (1,137) | |||||||||||||||||||
| Equity in earnings of unconsolidated affiliates | 95 | 62 | 183 | 118 | |||||||||||||||||||
| Gains on interest rate derivatives | 35 | 129 | 15 | 243 | |||||||||||||||||||
Other, net | 17 | (18) | 24 | 3 | |||||||||||||||||||
| INCOME BEFORE INCOME TAX EXPENSE | 1,341 | 1,708 | 2,859 | 3,186 | |||||||||||||||||||
| Income tax expense | 108 | 86 | 179 | 77 | |||||||||||||||||||
| NET INCOME | 1,233 | 1,622 | 2,680 | 3,109 | |||||||||||||||||||
| Less: Net income attributable to noncontrolling interests | 308 | 284 | 629 | 489 | |||||||||||||||||||
Less: Net income attributable to redeemable noncontrolling interests | 14 | 12 | 27 | 25 | |||||||||||||||||||
| NET INCOME ATTRIBUTABLE TO PARTNERS | 911 | 1,326 | 2,024 | 2,595 | |||||||||||||||||||
| General Partner’s interest in net income | 1 | 1 | 2 | 2 | |||||||||||||||||||
| Preferred Unitholders’ interest in net income | 113 | 105 | 222 | 211 | |||||||||||||||||||
| Common Unitholders’ interest in net income | $ | 797 | $ | 1,220 | $ | 1,800 | $ | 2,382 | |||||||||||||||
| NET INCOME PER COMMON UNIT: | |||||||||||||||||||||||
Basic | $ | 0.25 | $ | 0.40 | $ | 0.58 | $ | 0.77 | |||||||||||||||
Diluted | $ | 0.25 | $ | 0.39 | $ | 0.57 | $ | 0.77 | |||||||||||||||
WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING: | |||||||||||||||||||||||
Basic | 3,126.9 | 3,085.9 | 3,111.3 | 3,084.7 | |||||||||||||||||||
Diluted | 3,148.2 | 3,105.7 | 3,133.0 | 3,104.2 | |||||||||||||||||||
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ENERGY TRANSFER LP AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION
(Dollars and units in millions)
(unaudited)
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
Reconciliation of net income to Adjusted EBITDA and Distributable Cash Flow(a): | |||||||||||||||||||||||
| Net income | $ | 1,233 | $ | 1,622 | $ | 2,680 | $ | 3,109 | |||||||||||||||
| Interest expense, net of interest capitalized | 641 | 578 | 1,260 | 1,137 | |||||||||||||||||||
| Impairment losses | 10 | — | 11 | 300 | |||||||||||||||||||
| Income tax expense | 108 | 86 | 179 | 77 | |||||||||||||||||||
| Depreciation, depletion and amortization | 1,061 | 1,046 | 2,120 | 2,074 | |||||||||||||||||||
| Non-cash compensation expense | 27 | 25 | 64 | 61 | |||||||||||||||||||
| Gains on interest rate derivatives | (35) | (129) | (15) | (243) | |||||||||||||||||||
| Unrealized (gains) losses on commodity risk management activities | (55) | (99) | 75 | (54) | |||||||||||||||||||
| Inventory valuation adjustments (Sunoco LP) | 57 | (1) | 28 | (121) | |||||||||||||||||||
| Equity in earnings of unconsolidated affiliates | (95) | (62) | (183) | (118) | |||||||||||||||||||
| Adjusted EBITDA related to unconsolidated affiliates | 171 | 137 | 332 | 262 | |||||||||||||||||||
| Other, net | (1) | 25 | 4 | 84 | |||||||||||||||||||
| Adjusted EBITDA (consolidated) | 3,122 | 3,228 | 6,555 | 6,568 | |||||||||||||||||||
| Adjusted EBITDA related to unconsolidated affiliates | (171) | (137) | (332) | (262) | |||||||||||||||||||
| Distributable cash flow from unconsolidated affiliates | 115 | 82 | 233 | 168 | |||||||||||||||||||
| Interest expense, net of interest capitalized | (641) | (578) | (1,260) | (1,137) | |||||||||||||||||||
| Preferred unitholders’ distributions | (127) | (117) | (247) | (235) | |||||||||||||||||||
| Current income tax expense | (26) | (11) | (44) | 30 | |||||||||||||||||||
Transaction-related income taxes(b) | — | — | — | (42) | |||||||||||||||||||
| Maintenance capital expenditures | (237) | (162) | (399) | (280) | |||||||||||||||||||
| Other, net | 5 | 7 | 10 | 12 | |||||||||||||||||||
| Distributable Cash Flow (consolidated) | 2,040 | 2,312 | 4,516 | 4,822 | |||||||||||||||||||
| Distributable Cash Flow attributable to Sunoco LP (100%) | (173) | (159) | (333) | (301) | |||||||||||||||||||
| Distributions from Sunoco LP | 44 | 42 | 87 | 83 | |||||||||||||||||||
| Distributable Cash Flow attributable to USAC (100%) | (67) | (56) | (130) | (106) | |||||||||||||||||||
| Distributions from USAC | 24 | 24 | 48 | 48 | |||||||||||||||||||
| Distributable Cash Flow attributable to noncontrolling interests in other non-wholly-owned consolidated subsidiaries | (324) | (294) | (638) | (611) | |||||||||||||||||||
| Distributable Cash Flow attributable to the partners of Energy Transfer | 1,544 | 1,869 | 3,550 | 3,935 | |||||||||||||||||||
| Transaction-related adjustments | 10 | 9 | 12 | 21 | |||||||||||||||||||
| Distributable Cash Flow attributable to the partners of Energy Transfer, as adjusted | $ | 1,554 | $ | 1,878 | $ | 3,562 | $ | 3,956 | |||||||||||||||
| Distributions to partners: | |||||||||||||||||||||||
| Limited Partners | $ | 974 | $ | 710 | $ | 1,940 | $ | 1,327 | |||||||||||||||
| General Partner | 1 | — | 2 | 1 | |||||||||||||||||||
| Total distributions to be paid to partners | $ | 975 | $ | 710 | $ | 1,942 | $ | 1,328 | |||||||||||||||
| Common Units outstanding – end of period | 3,143.2 | 3,086.8 | 3,143.2 | 3,086.8 | |||||||||||||||||||
(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.
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
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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 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 ended June 30, 2022, the amount reflected for transaction-related income taxes was related to an amended return from a previous transaction.
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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 June 30, | |||||||||||
| 2023 | 2022 | ||||||||||
Segment Adjusted EBITDA: | |||||||||||
| Intrastate transportation and storage | $ | 216 | $ | 218 | |||||||
| Interstate transportation and storage | 441 | 397 | |||||||||
| Midstream | 579 | 903 | |||||||||
| NGL and refined products transportation and services | 837 | 763 | |||||||||
| Crude oil transportation and services | 674 | 562 | |||||||||
| Investment in Sunoco LP | 250 | 214 | |||||||||
| Investment in USAC | 125 | 106 | |||||||||
| All other | — | 65 | |||||||||
| Adjusted EBITDA (consolidated) | $ | 3,122 | $ | 3,228 | |||||||
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.
In addition, for certain segments, the following sections 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 June 30, | |||||||||||
| 2023 | 2022 | ||||||||||
| Natural gas transported (BBtu/d) | 15,207 | 14,834 | |||||||||
| Withdrawals from storage natural gas inventory (BBtu) | 2,400 | — | |||||||||
| Revenues | $ | 807 | $ | 2,203 | |||||||
| Cost of products sold | 470 | 1,843 | |||||||||
| Segment margin | 337 | 360 | |||||||||
| Unrealized gains on commodity risk management activities | (44) | (41) | |||||||||
| Operating expenses, excluding non-cash compensation expense | (74) | (95) | |||||||||
| Selling, general and administrative expenses, excluding non-cash compensation expense | (11) | (13) | |||||||||
| Adjusted EBITDA related to unconsolidated affiliates | 7 | 7 | |||||||||
| Other | 1 | — | |||||||||
| Segment Adjusted EBITDA | $ | 216 | $ | 218 | |||||||
Transported volumes increased primarily due to increased utilization on our Enable Oklahoma Intrastate Transmission system and higher production in the Haynesville Shale.
Segment Adjusted EBITDA. For the three months ended June 30, 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 $44 million in retained fuel revenues related to lower natural gas prices; and
•a decrease of $5 million in realized natural gas sales and other primarily due to lower pipeline optimization; partially offset by
•a decrease of $21 million in operating expenses primarily due to lower cost of fuel consumption from lower natural gas prices;
•an increase of $13 million in transportation fees primarily due to new contracts on our Texas system and Haynesville assets; and
•an increase of $10 million in storage margin primarily due to favorable storage optimization.
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Interstate Transportation and Storage
| Three Months Ended June 30, | |||||||||||
| 2023 | 2022 | ||||||||||
Natural gas transported (BBtu/d) | 16,224 | 13,833 | |||||||||
Natural gas sold (BBtu/d) | 18 | 21 | |||||||||
Revenues | $ | 550 | $ | 530 | |||||||
Cost of products sold | 1 | 2 | |||||||||
Segment margin | 549 | 528 | |||||||||
| Operating expenses, excluding non-cash compensation, amortization, accretion and other non-cash expenses | (203) | (200) | |||||||||
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses | (28) | (32) | |||||||||
Adjusted EBITDA related to unconsolidated affiliates | 124 | 99 | |||||||||
Other | (1) | 2 | |||||||||
Segment Adjusted EBITDA | $ | 441 | $ | 397 | |||||||
Transported volumes increased primarily due to our Gulf Run system being placed in service in December 2022, as well as more capacity sold and higher utilization on our Transwestern, Tiger, Panhandle and Trunkline systems due to increased demand.
Segment Adjusted EBITDA. For the three months ended June 30, 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 $21 million in segment margin primarily due to a $24 million increase resulting from our Gulf Run system being placed in service in December 2022 and a $9 million increase in transportation revenue from several of our interstate pipeline systems due to higher contracted volumes and higher rates. These increases were partially offset by a $14 million decrease in operational gas sales resulting from lower prices;
•a decrease of $4 million 9in selling, general and administrative expenses primarily due to a decrease in mergers and acquisitions expense; and
•an increase of $25 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to an increase from our Midcontinent Express Pipeline joint venture due to capacity sold at higher rates; partially offset by
•an increase of $3 million in operating expenses primarily due to $9 million in incremental expenses from our Gulf Run system being placed in service in December 2022, partially offset by a $4 million decrease in electricity expenses.
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Midstream
| Three Months Ended June 30, | |||||||||||
| 2023 | 2022 | ||||||||||
Gathered volumes (BBtu/d) | 19,847 | 18,332 | |||||||||
NGLs produced (MBbls/d) | 863 | 813 | |||||||||
Equity NGLs (MBbls/d) | 42 | 46 | |||||||||
Revenues | $ | 2,468 | $ | 5,050 | |||||||
Cost of products sold | 1,535 | 3,855 | |||||||||
Segment margin | 933 | 1,195 | |||||||||
| Unrealized losses on commodity risk management activities | — | 2 | |||||||||
Operating expenses, excluding non-cash compensation expense | (308) | (259) | |||||||||
Selling, general and administrative expenses, excluding non-cash compensation expense | (52) | (41) | |||||||||
Adjusted EBITDA related to unconsolidated affiliates | 4 | 6 | |||||||||
Other | 2 | — | |||||||||
Segment Adjusted EBITDA | $ | 579 | $ | 903 | |||||||
Gathered volumes and NGL production increased primarily due to increases across most regions, including from the Woodford Express acquisition.
Segment Adjusted EBITDA. For the three months ended June 30, 2023 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment decreased due to the net impacts of the following:
•a decrease of $323 million in non-fee-based margin due to unfavorable natural gas prices of $187 million and NGL prices of $136 million;
•an increase of $49 million in operating expenses primarily due to a $17 million increase in maintenance, repairs and projects, including trucking and compression needs coupled with pricing increases, an $11 million increase related to environmental reserves, an $8 million increase in employee costs, a $5 million increase from the Woodford Express acquisition and our new plants coming online, and a $3 million increase in ad valorem taxes; and
•an increase of $11 million in selling, general and administrative expenses primarily due to higher insurance expenses attributable to refunds and credits in 2022; partially offset by
•an increase of $45 million in fee-based margin due to increases across most regions including from the Woodford Express acquisition; and
•an increase of $14 million in non-fee based margin due to increased processed volumes across most regions.
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NGL and Refined Products Transportation and Services
| Three Months Ended June 30, | |||||||||||
| 2023 | 2022 | ||||||||||
| NGL transportation volumes (MBbls/d) | 2,155 | 1,912 | |||||||||
| Refined products transportation volumes (MBbls/d) | 554 | 526 | |||||||||
| NGL and refined products terminal volumes (MBbls/d) | 1,453 | 1,311 | |||||||||
| NGL fractionation volumes (MBbls/d) | 989 | 938 | |||||||||
Revenues | $ | 5,001 | $ | 7,557 | |||||||
Cost of products sold | 3,929 | 6,521 | |||||||||
Segment margin | 1,072 | 1,036 | |||||||||
| Unrealized gains on commodity risk management activities | (19) | (27) | |||||||||
Operating expenses, excluding non-cash compensation expense | (211) | (241) | |||||||||
Selling, general and administrative expenses, excluding non-cash compensation expense | (35) | (28) | |||||||||
Adjusted EBITDA related to unconsolidated affiliates | 30 | 23 | |||||||||
Segment Adjusted EBITDA | $ | 837 | $ | 763 | |||||||
NGL transportation and terminal volumes increased primarily due to higher volumes from the Permian region, on our Mariner East pipeline system and on our export pipelines into our Nederland Terminal.
The increase in transportation volumes also led to higher fractionated volumes at our Mont Belvieu, Texas fractionation facility.
Segment Adjusted EBITDA. For the three months ended June 30, 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 $57 million in transportation margin primarily due to a $28 million increase resulting from higher throughput on our Mariner East pipelines, a $23 million increase resulting from higher y-grade throughput and higher rates on our Texas pipeline system, a $7 million increase from higher throughput on our Mariner West pipeline, a $7 million increase from higher exported volumes feeding into our Nederland Terminal and a $5 million increase from higher throughput on our refined product pipelines. These increases were partially offset by intrasegment charges of $7 million and $6 million which are fully offset within our marketing margin and fractionators margin, respectively;
•an increase of $38 million in terminal services margin primarily due to a $30 million increase from our Marcus Hook Terminal due to higher rates and higher throughput and an $8 million increase from higher export volumes loaded at our Nederland Terminal;
•a decrease of $30 million in operating expenses primarily due to a $41 million decrease in gas and power utility cost. This decrease was partially offset by a $5 million increase due to higher headcount, a $3 million increase in outside service expenses related to higher volumes and inflation, and a $3 million increase in ad valorem taxes;
•an increase of $8 million in storage margin primarily due to fees generated from exported volumes; and
•an increase of $7 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to higher volumes on the Explorer and White Cliffs pipelines; partially offset by
•a decrease of $30 million in marketing margin primarily due to lower gains of $37 million from the optimization of NGL and refined product inventories including a $51 million write-down to hedged inventory during the second quarter of 2023, which we expect will be fully offset with hedge gains in future periods. This decrease was partially offset by intrasegment charges of $7 million which are fully offset within our transportation margin;
•a decrease of $29 million in fractionators and refinery services margin, despite higher volumes, primarily due to a $26 million decrease resulting from lower rates tied to lower gas prices in the current period and a $7 million decrease from a less favorable pricing environment impacting our refinery services business. These decreases were partially offset by a $6 million intrasegment charge which is fully offset in our transportation margin; and
•an increase of $7 million in selling, general and administrative expenses primarily due to a $3 million increase in overhead expenses and a $2 million increase in insurance costs.
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Crude Oil Transportation and Services
| Three Months Ended June 30, | |||||||||||
| 2023 | 2022 | ||||||||||
| Crude transportation volumes (MBbls/d) | 5,294 | 4,318 | |||||||||
| Crude terminal volumes (MBbls/d) | 3,520 | 3,056 | |||||||||
| Revenues | $ | 5,953 | $ | 7,300 | |||||||
| Cost of products sold | 5,092 | 6,541 | |||||||||
Segment margin | 861 | 759 | |||||||||
| Unrealized (gains) losses on commodity risk management activities | 10 | (17) | |||||||||
Operating expenses, excluding non-cash compensation expense | (172) | (154) | |||||||||
Selling, general and administrative expenses, excluding non-cash compensation expense | (30) | (27) | |||||||||
Adjusted EBITDA related to unconsolidated affiliates | 5 | 1 | |||||||||
Segment Adjusted EBITDA | $ | 674 | $ | 562 | |||||||
Crude transportation volumes were higher on our Texas pipeline system due to higher Permian crude oil production and contributions from assets acquired in 2023. Volumes were also higher on our Bakken Pipeline and our Bayou Bridge Pipeline. Crude terminal volumes were higher due to growth in Permian volumes, stronger Gulf Coast refinery utilization and contributions from assets acquired in 2023.
Segment Adjusted EBITDA. For the three months ended June 30, 2023 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased primarily due to the net impacts of the following:
•an increase of $129 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $69 million increase from higher volumes on our Bakken Pipeline, a $51 million increase from recently acquired assets, a $30 million increase from higher gathered volumes and new assets placed into service on our Texas crude pipeline system, a $17 million increase in throughput at our Gulf Coast and Permian terminals and a $3 million increase on our Bayou Bridge Pipeline due to higher volumes, partially offset by a $40 million decrease from our crude oil acquisition and marketing business due primarily to lower margins on refined product sales; partially offset by
•an increase of $18 million in operating expenses primarily due to a $15 million increase from recently acquired assets and a $7 million increase in ad valorem taxes, partially offset by a $5 million decrease in maintenance project costs.
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Investment in Sunoco LP
| Three Months Ended June 30, | |||||||||||
| 2023 | 2022 | ||||||||||
Revenues | $ | 5,745 | $ | 7,815 | |||||||
Cost of products sold | 5,431 | 7,470 | |||||||||
Segment margin | 314 | 345 | |||||||||
| Unrealized (gains) losses on commodity risk management activities | 1 | (11) | |||||||||
Operating expenses, excluding non-cash compensation expense | (103) | (98) | |||||||||
| Selling, general and administrative, excluding non-cash compensation expense | (30) | (27) | |||||||||
Adjusted EBITDA related to unconsolidated affiliates | 3 | 3 | |||||||||
| Inventory fair value adjustments | 57 | (1) | |||||||||
| Other, net | 8 | 3 | |||||||||
Segment Adjusted EBITDA | $ | 250 | $ | 214 | |||||||
The Investment in Sunoco LP segment reflects the consolidated results of Sunoco LP.
Segment Adjusted EBITDA. For the three months ended June 30, 2023 compared to the same period last year, Segment Adjusted EBITDA related to our investment in Sunoco LP segment increased primarily due to the net impacts of the following:
•an increase in the profit on motor fuel sales of $37 million, primarily due to a 3% increase in profit per gallon sold and a 5% increase in gallons sold; and
•an increase in non-motor fuel sales and lease profit of $7 million, primarily due to increased rental income, higher merchandise gross profit and increased throughput and storage margin from the Gladieux and Zenith acquisitions; partially offset by
•an increase in operating costs of $9 million, including other operating expense, general and administrative expense and lease expense, primarily due to higher costs as a result of acquisitions of refined product terminals and the transmix processing and terminal facility.
Investment in USAC
| Three Months Ended June 30, | |||||||||||
| 2023 | 2022 | ||||||||||
Revenues | $ | 207 | $ | 172 | |||||||
Cost of products sold | 35 | 25 | |||||||||
Segment margin | 172 | 147 | |||||||||
Operating expenses, excluding non-cash compensation expense | (36) | (30) | |||||||||
Selling, general and administrative expenses, excluding non-cash compensation expense | (11) | (11) | |||||||||
Segment Adjusted EBITDA | $ | 125 | $ | 106 | |||||||
The Investment in USAC segment reflects the consolidated results of USAC.
Segment Adjusted EBITDA. For the three months ended June 30, 2023 compared to the same period last year, Segment Adjusted EBITDA related to our investment in USAC segment increased primarily due to the net impacts of the following:
•an increase of $25 million in segment margin 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; partially offset by
•an increase of $6 million in operating expenses primarily due to higher employee costs.
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All Other
| Three Months Ended June 30, | |||||||||||
| 2023 | 2022 | ||||||||||
| Revenues | $ | 399 | $ | 962 | |||||||
| Cost of products sold | 395 | 882 | |||||||||
| Segment margin | 4 | 80 | |||||||||
| Unrealized gains on commodity risk management activities | (3) | (5) | |||||||||
| Operating expenses, excluding non-cash compensation expense | (4) | (24) | |||||||||
| Selling, general and administrative expenses, excluding non-cash compensation expense | (11) | (16) | |||||||||
| Adjusted EBITDA related to unconsolidated affiliates | 1 | 1 | |||||||||
| Other and eliminations | 13 | 29 | |||||||||
| Segment Adjusted EBITDA | $ | — | $ | 65 | |||||||
For the three months ended June 30, 2023 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment decreased primarily due to the net impacts of the following:
•a decrease of $39 million due to the sale of Energy Transfer Canada in 2022;
•a decrease of $11 million from our natural gas marketing subsidiary;
•a decrease of $8 million from our dual drive compression business; and
•an increase of $7 million in mergers and acquisition expense; partially offset by
•an increase of $10 million due to higher margin from sales in our compressor business.
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ENERGY TRANSFER LP AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ON LIQUIDITY
(Dollars 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 June 30, 2023 | Maturity Date | |||||||||||||||
| Five-Year Revolving Credit Facility | $ | 5,000 | $ | 2,356 | April 11, 2027 | ||||||||||||
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ENERGY TRANSFER LP AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ON UNCONSOLIDATED AFFILIATES
(Dollars 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 June 30, | |||||||||||
| 2023 | 2022 | ||||||||||
Equity in earnings (losses) of unconsolidated affiliates: | |||||||||||
Citrus | $ | 37 | $ | 39 | |||||||
MEP | 22 | (2) | |||||||||
White Cliffs | 2 | 1 | |||||||||
| Explorer | 9 | 5 | |||||||||
Other | 25 | 19 | |||||||||
| Total equity in earnings of unconsolidated affiliates | $ | 95 | $ | 62 | |||||||
Adjusted EBITDA related to unconsolidated affiliates: | |||||||||||
Citrus | $ | 85 | $ | 82 | |||||||
MEP | 30 | 6 | |||||||||
White Cliffs | 6 | 5 | |||||||||
| Explorer | 13 | 9 | |||||||||
Other | 37 | 35 | |||||||||
Total Adjusted EBITDA related to unconsolidated affiliates | $ | 171 | $ | 137 | |||||||
Distributions received from unconsolidated affiliates: | |||||||||||
Citrus | $ | 22 | $ | 21 | |||||||
MEP | 31 | 6 | |||||||||
White Cliffs | 6 | 5 | |||||||||
| Explorer | 11 | 9 | |||||||||
Other | 22 | 23 | |||||||||
Total distributions received from unconsolidated affiliates | $ | 92 | $ | 64 | |||||||
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ENERGY TRANSFER LP AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ON NON-WHOLLY-OWNED JOINT VENTURE SUBSIDIARIES
(Dollars 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 June 30, | |||||||||||
| 2023 | 2022 | ||||||||||
Adjusted EBITDA of non-wholly-owned subsidiaries (100%) (a) | $ | 640 | $ | 601 | |||||||
Our proportionate share of Adjusted EBITDA of non-wholly-owned subsidiaries (b) | 307 | 293 | |||||||||
Distributable Cash Flow of non-wholly-owned subsidiaries (100%) (c) | $ | 609 | $ | 564 | |||||||
Our proportionate share of Distributable Cash Flow of non-wholly-owned subsidiaries (d) | 285 | 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 | % | |||
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.
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