Press Releases

DALLAS--(BUSINESS WIRE)--Feb. 15, 2023-- Energy Transfer LP (NYSE:ET) (“Energy Transfer” or the “Partnership”) today reported financial results for the quarter and year ended December 31, 2022.

Energy Transfer reported net income attributable to partners for the three months ended December 31, 2022 of $1.16 billion, an increase of $234 million compared to the same period last year. For the three months ended December 31, 2022, net income per common unit (basic) was $0.34 per unit.

Adjusted EBITDA for the three months ended December 31, 2022 was $3.44 billion compared to $2.81 billion for the same period last year.

Distributable Cash Flow attributable to partners, as adjusted, for the three months ended December 31, 2022 was $1.91 billion compared to $1.60 billion for the same period last year.

The improved results were primarily due to higher volumes across all of our core segments and the impacts of the acquisition of Enable Midstream.

Growth capital expenditures in 2022 were $1.93 billion while maintenance capital expenditures were $743 million.

2023 Outlook

• Energy Transfer expects its 2023 Adjusted EBITDA to range between $12.9 billion and $13.3 billion.
• For 2023, the Partnership expects its growth capital expenditures to range from $1.6 billion to $1.8 billion, which includes Fractionator VIII at Mont Belvieu, the Bear processing plant in the Permian Basin, compression and optimization projects on existing pipelines, new treating capacity in the Haynesville, additional gathering and compression buildout in the Permian, and improved efficiencies and emissions reduction work, as well as preliminary spending related to carbon capture projects. A significant amount of our 2023 growth capital will be spent on projects that are expected to be online and contributing cash flow before year-end. Maintenance capital expenditures for 2023 are expected to be between $725 million and $775 million.

Operational Highlights

• During the fourth quarter of 2022, Energy Transfer’s assets continued to reach new milestones, with volumes increasing across all segments compared to the same period last year.
  • NGL fractionation volumes were up 7% and set a new Partnership record. Single-day fractionation throughput at our Mont Belvieu fractionators reached more than one million barrels for the first time in the Partnership’s history.
  • NGL transportation volumes were up 5%, setting a new Partnership record.
  • Midstream throughput volumes increased 32%, setting a new Partnership record. Excluding the Enable and Woodford Express assets, legacy midstream volumes were up 8%.
  • Intrastate natural gas transportation volumes were up 13%.
  • Interstate natural gas transportation volumes were up 33%. Excluding the Enable assets, legacy interstate volumes were up 7% and reached a new record.
  • Crude transportation and terminal volumes were up 11% and 13%, respectively, driven primarily by higher volumes on our Texas pipeline systems, the impact of the Enable acquisition, and U.S. Strategic Petroleum Reserve releases.
• NGL exports at our Nederland terminal reached a new record in the fourth quarter.
• In December 2022, the Partnership placed the Gulf Run pipeline in service. The large diameter pipeline runs from the Haynesville Shale to the Carthage and Perryville natural gas hubs and to key markets along the Gulf Coast.
• In December 2022, the Partnership placed the Grey Wolf processing plant in service. The 200 MMcf/d plant is located in the Delaware Basin.
• In the fourth quarter of 2022, the Partnership placed a new three million barrel storage cavern online at our Mont Belvieu storage facilities, increasing total underground NGL storage capacity at Mont Belvieu to approximately 60 million barrels.
• The Partnership recently completed modernization and de-bottlenecking work on the Oasis Pipeline, which added at least 60,000 Mcf/d of incremental natural gas takeaway capacity out of the Permian Basin.

Strategic Highlights

• In the fourth quarter of 2022, the Partnership released its Corporate Responsibility Report, which highlights Energy Transfer’s safety and risk management achievements, emissions reduction programs, and community engagement programs.

Financial Highlights

• In January 2023, Energy Transfer announced a quarterly cash distribution of $0.305 per common unit ($1.22 annualized) for the quarter ended December 31, 2022.
• In December 2022, the Partnership issued $1.0 billion aggregate principal amount of 5.55% senior notes and $1.5 billion aggregate principal amount of 5.75% senior notes and used the net proceeds to reduce borrowings outstanding under the Partnership’s revolving credit facility.
• For the full year 2022, Energy Transfer reduced its long-term debt by approximately $800 million.
• As of December 31, 2022, the Partnership’s revolving credit facility had an aggregate $4.18 billion of available borrowing capacity.
• For the three months ended December 31, 2022, the Partnership invested approximately $605 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 30% of the Partnership’s consolidated Adjusted EBITDA for the three months or full year ended December 31, 2022. 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 15, 2023 to discuss its fourth quarter 2022 results and provide an update on the Partnership, including its outlook for 2023. 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 approximately 120,000 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 a growth-oriented Delaware limited partnership that is one of the nation’s largest independent providers of natural gas compression services in terms of total compression fleet horsepower. USAC partners with a broad customer base composed of producers, processors, gatherers, and transporters of natural gas and crude oil. USAC focuses on providing compression services to infrastructure applications primarily in high-volume gathering systems, processing facilities and transportation applications. For more information, visit the USAC website at www.usacompression.com.

Forward-Looking Statements

This news release may include certain statements concerning expectations for the future that are forward-looking statements as defined by federal law. Such forward-looking statements are subject to a variety of known and unknown risks, uncertainties, and other factors that are difficult to predict and many of which are beyond management’s control. An extensive list of factors 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.

ENERGY TRANSFER LP AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEETS (In millions) (unaudited)
	December 31, 2022				December 31, 2021
ASSETS
Current assets	$	12,081			$	10,537
Property, plant and equipment, net		80,311				81,607
Investments in unconsolidated affiliates		2,893				2,947
Lease right-of-use assets, net		819				838
Other non-current assets, net		1,558				1,645
Intangible assets, net		5,415				5,856
Goodwill		2,566				2,533
Total assets	$	105,643			$	105,963
LIABILITIES AND EQUITY
Current liabilities	$	10,368			$	10,835
Long-term debt, less current maturities		48,260				49,022
Non-current derivative liabilities		23				193
Non-current operating lease liabilities		798				814
Deferred income taxes		3,701				3,648
Other non-current liabilities		1,341				1,323
Commitments and contingencies
Redeemable noncontrolling interests		493				783
Equity:
Limited Partners:
Preferred Unitholders		6,051				6,051
Common Unitholders		26,960				25,230
General Partner		(2	)			(4	)
Accumulated other comprehensive income		16				23
Total partners’ capital		33,025				31,300
Noncontrolling interests		7,634				8,045
Total equity		40,659				39,345
Total liabilities and equity	$	105,643			$	105,963

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,
	2022				2021				2022				2021
REVENUES	$	20,501			$	18,657			$	89,876			$	67,417
COSTS AND EXPENSES:
Cost of products sold		16,063				14,754				72,232				50,395
Operating expenses		1,356				989				4,338				3,574
Depreciation, depletion and amortization		1,060				980				4,164				3,817
Selling, general and administrative		216				235				1,018				818
Impairment losses and other		—				10				386				21
Total costs and expenses		18,695				16,968				82,138				58,625
OPERATING INCOME		1,806				1,689				7,738				8,792
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized		(592	)			(554	)			(2,306	)			(2,267	)
Equity in earnings of unconsolidated affiliates		71				55				257				246
Losses on extinguishments of debt		—				(30	)			—				(38	)
Gains (losses) on interest rate derivatives		(10	)			(11	)			293				61
Other, net		207				32				90				77
INCOME BEFORE INCOME TAX EXPENSE (BENEFIT)		1,482				1,181				6,072				6,871
Income tax expense (benefit)		45				(50	)			204				184
NET INCOME		1,437				1,231				5,868				6,687
Less: Net income attributable to noncontrolling interest		268				297				1,061				1,167
Less: Net income attributable to redeemable noncontrolling interests		14				13				51				50
NET INCOME ATTRIBUTABLE TO PARTNERS		1,155				921				4,756				5,470
General Partner’s interest in net income		1				1				4				6
Preferred Unitholders’ interest in net income		105				100				422				285
Common Unitholders’ interest in net income	$	1,049			$	820			$	4,330			$	5,179
NET INCOME PER COMMON UNIT:
Basic	$	0.34			$	0.29			$	1.40			$	1.89
Diluted	$	0.34			$	0.29			$	1.40			$	1.89
WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING:
Basic		3,090.3				2,824.5				3,086.8				2,734.4
Diluted		3,103.2				2,830.6				3,097.0				2,739.6

ENERGY TRANSFER LP AND SUBSIDIARIES SUPPLEMENTAL INFORMATION (Dollars and units in millions) (unaudited)
	Three Months Ended December 31,								Year Ended December 31,
	2022				2021				2022				2021 (a)
Reconciliation of net income to Adjusted EBITDA and Distributable Cash Flow (b):
Net income	$	1,437			$	1,231			$	5,868			$	6,687
Interest expense, net of interest capitalized		592				554				2,306				2,267
Impairment losses and other		—				10				386				21
Income tax expense (benefit)		45				(50	)			204				184
Depreciation, depletion and amortization		1,060				980				4,164				3,817
Non-cash compensation expense		27				30				115				111
(Gains) losses on interest rate derivatives		10				11				(293	)			(61	)
Unrealized (gains) losses on commodity risk management activities		88				(88	)			(42	)			(162	)
Losses on extinguishments of debt		—				30				—				38
Inventory valuation adjustments (Sunoco LP)		76				(22	)			(5	)			(190	)
Equity in earnings of unconsolidated affiliates		(71	)			(55	)			(257	)			(246	)
Adjusted EBITDA related to unconsolidated affiliates		156				123				565				523
Other, net		17				57				82				57
Adjusted EBITDA (consolidated)		3,437				2,811				13,093				13,046
Adjusted EBITDA related to unconsolidated affiliates		(156	)			(123	)			(565	)			(523	)
Distributable Cash Flow from unconsolidated affiliates		89				78				359				346
Interest expense, net of interest capitalized		(592	)			(554	)			(2,306	)			(2,267	)
Preferred unitholders’ distributions		(118	)			(113	)			(471	)			(418	)
Current income tax expense		(17	)			(10	)			(18	)			(44	)
Transaction-related income taxes		—				—				(42	)			—
Maintenance capital expenditures		(294	)			(210	)			(821	)			(581	)
Other, net		3				18				20				68
Distributable Cash Flow (consolidated)		2,352				1,897				9,249				9,627
Distributable Cash Flow attributable to Sunoco LP (100%)		(152	)			(143	)			(648	)			(542	)
Distributions from Sunoco LP		42				41				166				165
Distributable Cash Flow attributable to USAC (100%)		(60	)			(52	)			(221	)			(209	)
Distributions from USAC		24				24				97				97
Distributable Cash Flow attributable to noncontrolling interests in other non-wholly-owned consolidated subsidiaries		(314	)			(327	)			(1,240	)			(1,113	)
Distributable Cash Flow attributable to the partners of Energy Transfer		1,892				1,440				7,403				8,025
Transaction-related adjustments (c)		18				160				44				194
Distributable Cash Flow attributable to the partners of Energy Transfer, as adjusted	$	1,910			$	1,600			$	7,447			$	8,219
Distributions to partners:
Limited Partners	$	944			$	540			$	3,089			$	1,777
General Partner		1				1				3				2
Total distributions to be paid to partners	$	945			$	541			$	3,092			$	1,779
Common Units outstanding – end of period		3,094.4				3,082.5				3,094.4				3,082.5

(a)	Winter Storm Uri, which occurred in February 2021, resulted in one-time impacts to the Partnership’s consolidated net income, Adjusted EBITDA, and Distributable Cash Flow.
(b)	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 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.
(c)	For the three months and year ended December 31, 2021, “Transaction-related adjustments” includes $143 million of Distributable Cash Flow attributable to the operations of Enable for October 1 through December 1, 2021, which represents amounts distributable to Energy Transfer’s common unitholders (including the holders of the common units issued in the Enable acquisition) with respect to the fourth quarter 2021 distribution.

ENERGY TRANSFER LP AND SUBSIDIARIES SUMMARY ANALYSIS OF QUARTERLY RESULTS BY SEGMENT (Tabular dollar amounts in millions) (unaudited)
	Three Months Ended December 31,
	2022			2021
Segment Adjusted EBITDA:
Intrastate transportation and storage	$	433		$	274
Interstate transportation and storage		494			397
Midstream		632			547
NGL and refined products transportation and services		928			739
Crude oil transportation and services		571			533
Investment in Sunoco LP		238			198
Investment in USAC		113			99
All other		28			24
Adjusted EBITDA (consolidated)	$	3,437		$	2,811

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 sections below include information on the components of segment margin by sales type, which components are included in order to provide additional disaggregated information to facilitate the analysis of segment margin and Segment Adjusted EBITDA. For example, these components include transportation margin, storage margin, and other margin. These components of segment margin are calculated consistent with the calculation of segment margin; therefore, these components also exclude charges for depreciation, depletion and amortization.

Intrastate Transportation and Storage
	Three Months Ended December 31,
	2022				2021
Natural gas transported (BBtu/d)		14,295				12,644
Withdrawals from storage natural gas inventory (BBtu)		5,425				—
Revenues	$	1,600			$	1,505
Cost of products sold		992				1,133
Segment margin		608				372
Unrealized gains on commodity risk management activities		(84	)			(28	)
Operating expenses, excluding non-cash compensation expense		(83	)			(69	)
Selling, general and administrative expenses, excluding non-cash compensation expense		(16	)			(11	)
Adjusted EBITDA related to unconsolidated affiliates		8				8
Other		—				2
Segment Adjusted EBITDA	$	433			$	274

Transported volumes increased primarily due to the acquisition of the Enable Oklahoma Intrastate Transmission system, as well as increased production in the Haynesville Shale.

Segment Adjusted EBITDA. For the three months ended December 31, 2022 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment increased due to the net impacts of the following:

• an increase of $114 million in realized natural gas sales and other primarily due to higher optimization;
• an increase of $47 million in storage margin primarily due to higher storage optimization; and
• an increase of $18 million in transportation fees primarily due to fees from the Enable Oklahoma Intrastate Transmission System and higher fees on assets in the Haynesville Shale; partially offset by
• an increase of $14 million in operating expenses primarily due to an $8 million increase from expenses related to the addition of Enable and a $6 million increase in utilities expense; and
• an increase of $5 million in selling, general and administrative expenses primarily due to the addition of Enable.

Interstate Transportation and Storage
	Three Months Ended December 31,
	2022				2021
Natural gas transported (BBtu/d)		15,821				11,913
Natural gas sold (BBtu/d)		26				36
Revenues	$	606			$	491
Cost of products sold		1				11
Segment margin		605				480
Operating expenses, excluding non-cash compensation, amortization, accretion and other non-cash expenses		(201	)			(151	)
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses		(31	)			(20	)
Adjusted EBITDA related to unconsolidated affiliates		115				82
Other		6				6
Segment Adjusted EBITDA	$	494			$	397

Transported volumes increased primarily due to the impact of the Enable acquisition, higher utilization on our Tiger system due to increased production in the Haynesville Shale, and higher volumes on our Panhandle and Trunkline systems due to increased demand.

Segment Adjusted EBITDA. For the three months ended December 31, 2022 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 $125 million in segment margin primarily due to a $99 million increase from recently acquired assets, a $25 million increase in transportation revenue from several of our interstate pipeline systems due to higher contracted volumes and higher rates, a $13 million increase due to higher rates from operational gas sales on Transwestern, and a $9 million increase due to higher parking and liquids revenue. These increases were partially offset by a $10 million decrease due to a shipper bankruptcy on Rover, a $9 million decrease due to lower rates on Panhandle resulting from developments in an ongoing rate case, and a $2 million decrease in interruptible usage resulting from lower utilization; and
• an increase of $33 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to a $21 million increase from our Midcontinent Express Pipeline joint venture as a result of higher revenue due to capacity sold at higher rates, an $8 million increase from recently acquired assets, and a $5 million increase from our Citrus joint venture resulting from higher revenues due to higher contracted volumes; partially offset by
• an increase of $50 million in operating expenses primarily due to a $38 million increase from recently acquired assets, a $7 million increase in transportation expense, and a $5 million increase in employee costs and other direct expenses; and
• an increase of $11 million in selling, general and administrative expenses primarily due to recently acquired assets.

Midstream
	Three Months Ended December 31,
	2022				2021
Gathered volumes (BBtu/d)		19,434				14,765
NGLs produced (MBbls/d)		813				705
Equity NGLs (MBbls/d)		43				40
Revenues	$	3,255			$	3,526
Cost of products sold		2,264				2,705
Segment margin		991				821
Unrealized gains on commodity risk management activities		—				(10	)
Operating expenses, excluding non-cash compensation expense		(319	)			(227	)
Selling, general and administrative expenses, excluding non-cash compensation expense		(46	)			(46	)
Adjusted EBITDA related to unconsolidated affiliates		5				9
Other		1				—
Segment Adjusted EBITDA	$	632			$	547

Gathered volumes and NGL production increased primarily due to recent acquisitions and increased production across all regions.

Segment Adjusted EBITDA. For the three months ended December 31, 2022 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 $74 million in non-fee-based margin due to recent acquisitions; and
• an increase of $206 million in fee-based margin due to recent acquisitions, as well as increased throughput across all regions; partially offset by
• a decrease of $99 million in non-fee-based margin due to unfavorable natural gas prices of $56 million and NGL prices of $43 million;
• an increase of $92 million in operating expenses primarily due to $47 million in incremental operating expenses from recent acquisitions, a $21 million increase in project-related costs and environmental remediation, a $10 million increase from pricing increases in materials and utilities, and a $12 million increase in employee costs and allocated expenses; and
• a decrease of $4 million in Adjusted EBITDA related to unconsolidated affiliates due to the sale of the Partnership’s membership interest in Ranch Westex JV LLC in 2022.

NGL and Refined Products Transportation and Services
	Three Months Ended December 31,
	2022				2021
NGL transportation volumes (MBbls/d)		1,970				1,872
Refined products transportation volumes (MBbls/d)		520				483
NGL and refined products terminal volumes (MBbls/d)		1,316				1,227
NGL fractionation volumes (MBbls/d)		962				895
Revenues	$	5,748			$	6,187
Cost of products sold		4,735				5,213
Segment margin		1,013				974
Unrealized (gains) losses on commodity risk management activities		174				(17	)
Operating expenses, excluding non-cash compensation expense		(254	)			(211	)
Selling, general and administrative expenses, excluding non-cash compensation expense		(31	)			(30	)
Adjusted EBITDA related to unconsolidated affiliates		26				22
Other		—				1
Segment Adjusted EBITDA	$	928			$	739

NGL transportation volumes increased primarily due to higher volumes from the Permian and Eagle Ford regions and higher volumes on our export pipelines into our Nederland Terminal.

Refined products transportation volumes increased due to recovery from COVID-19 related demand reduction in the prior period.

NGL and refined products terminal volumes increased primarily due to higher volumes on our export pipelines into our Nederland Terminal and refined product demand recovery.

Average fractionated volumes at our Mont Belvieu fractionation facility increased due to increased production to our system, primarily from the Permian and Eagle Ford regions.

Segment Adjusted EBITDA. For the three months ended December 31, 2022 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 $147 million in marketing margin primarily due to a $124 million increase related to higher gains from the optimization of NGL component products from our Gulf Coast NGL activities, a $19 million increase in Northeast region blending and optimization, and a $4 million intrasegment charge which is fully offset within our transportation margin;
• an increase of $53 million in transportation margin primarily due to a $54 million increase resulting from higher y-grade throughput and higher rates driven by contractual rate adjustments on our Texas pipeline system, and a $5 million increase from the timing of third-party deficiency payments on our Northeast region pipelines. These increases were partially offset by intrasegment charges of $4 million and $3 million which are fully offset in our marketing and fractionators margins, respectively;
• an increase of $21 million in fractionators and refinery services margin primarily due to a $27 million increase from higher volumes and higher rates driven by contractual rate adjustments and a $3 million intrasegment charge which is fully offset in our transportation margin. These increases were partially offset by a $9 million decrease from a less favorable pricing environment impacting our refinery services business;
• an increase of $6 million in terminal services margin primarily due to higher export volumes loaded at our Nederland Terminal; and
• an increase of $4 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to higher volumes on the Explorer pipeline; offset by
• an increase of $43 million in operating expenses primarily due to a $23 million increase in gas and power utility costs, a $6 million increase in employee costs, a $6 million increase in material and outside service costs, and a $5 million increase in ad valorem taxes; and
• an increase of $1 million in selling, general and administrative expenses primarily due to overhead expenses allocated to the segment.

Crude Oil Transportation and Services
	Three Months Ended December 31,
	2022				2021
Crude transportation volumes (MBbls/d)		4,272				3,839
Crude terminal volumes (MBbls/d)		2,954				2,606
Revenues	$	6,340			$	4,948
Cost of products sold		5,570				4,239
Segment margin		770				709
Unrealized gains on commodity risk management activities		(10	)			(16	)
Operating expenses, excluding non-cash compensation expense		(178	)			(133	)
Selling, general and administrative expenses, excluding non-cash compensation expense		(12	)			(33	)
Adjusted EBITDA related to unconsolidated affiliates		1				4
Other		—				2
Segment Adjusted EBITDA	$	571			$	533

Crude transportation volumes were higher primarily due to increases on our Texas pipeline systems, as well as the addition of Oklahoma and Bakken gathering assets through the Enable acquisition. Volumes on our Bayou Bridge pipeline were higher primarily due to increased crude supply from Strategic Petroleum Reserve releases during 2022. Additionally, volumes benefited from assets placed into service, primarily Cushing South and the Ted Collins Link. Volumes on our Bakken Pipeline were lower primarily due to Winter Storm Elliott impacting production. Crude Terminal volumes were higher due to Strategic Petroleum Reserve releases increasing throughput and export activity at our Gulf Coast terminals.

Adjusted EBITDA. For the three months ended December 31, 2022 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 $67 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $41 million increase from our Texas crude pipeline system due to higher volumes, a $17 million increase related to assets acquired in 2021, a $16 million increase in terminal throughput primarily at our Gulf Coast terminals due to Strategic Petroleum Reserve releases, stronger refinery utilization, and higher export demand, and a $5 million increase on our Bayou Bridge pipeline due to higher volumes, partially offset by a $4 million decrease due to lower volumes on our Bakken Pipeline due to Winter Storm Elliott and a $9 million decrease from our crude oil acquisition and marketing business primarily due to less favorable pricing conditions impacting our trading operations and unfavorable inventory valuation adjustments from crude oil prices; and
• a decrease of $21 million in selling, general and administrative expenses primarily due to a gain related to the resolution of a legal matter; partially offset by
• an increase of $45 million in operating expenses primarily due to higher volume-driven expenses, higher project expenses, and expenses related to assets acquired in 2021; and
• a decrease of $3 million in Adjusted EBITDA related to unconsolidated affiliates due to the consolidation of certain operations that were previously reflected in unconsolidated affiliates.

Investment in Sunoco LP
	Three Months Ended December 31,
	2022				2021
Revenues	$	5,918			$	4,954
Cost of products sold		5,647				4,615
Segment margin		271				339
Unrealized (gains) losses on commodity risk management activities		18				(9	)
Operating expenses, excluding non-cash compensation expense		(103	)			(93	)
Selling, general and administrative, excluding non-cash compensation expense		(33	)			(26	)
Adjusted EBITDA related to unconsolidated affiliates		3				2
Inventory fair value adjustments		76				(22	)
Other, net		6				7
Segment Adjusted EBITDA	$	238			$	198

The Investment in Sunoco LP segment reflects the consolidated results of Sunoco LP.

Segment Adjusted EBITDA. For the three months ended December 31, 2022 compared to the same period last year, Segment Adjusted EBITDA related to our investment in Sunoco LP increased primarily due to an increase in profit on motor fuel sales driven by higher gallons sold and higher profit per gallon sold.

Investment in USAC
	Three Months Ended December 31,
	2022				2021
Revenues	$	191			$	160
Cost of products sold		33				24
Segment margin		158				136
Operating expenses, excluding non-cash compensation expense		(33	)			(26	)
Selling, general and administrative, excluding non-cash compensation expense		(12	)			(11	)
Segment Adjusted EBITDA	$	113			$	99

The Investment in USAC segment reflects the consolidated results of USAC.

Segment Adjusted EBITDA. For the three months ended December 31, 2022 compared to the same period last year, Segment Adjusted EBITDA related to our investment in USAC increased primarily due to Consumer Price Index-based and other price increases on customer contracts that occur as market conditions permit and higher revenue generating horsepower.

All Other
	Three Months Ended December 31,
	2022				2021
Revenues	$	813			$	692
Cost of products sold		780				604
Segment margin		33				88
Unrealized gains on commodity risk management activities		(10	)			(8	)
Operating expenses, excluding non-cash compensation expense		(5	)			(33	)
Selling, general and administrative expenses, excluding non-cash compensation expense		(16	)			(39	)
Adjusted EBITDA related to unconsolidated affiliates		1				—
Other and eliminations		25				16
Segment Adjusted EBITDA	$	28			$	24

Segment Adjusted EBITDA. For the three months ended December 31, 2022 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment increased primarily due to a favorable environment for physical trading and gas storage, as well as decreases in acquisition-related and other expenses. These favorable changes were partially offset by the impact of the Energy Transfer Canada sale.

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, 2022			Maturity Date
Five-Year Revolving Credit Facility	$	5,000		$	4,175		April 11, 2027

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,
	2022				2021
Equity in earnings (losses) of unconsolidated affiliates:
Citrus	$	32			$	34
MEP		17				(5	)
White Cliffs		(9	)			—
Explorer		8				4
Other		23				22
Total equity in earnings of unconsolidated affiliates	$	71			$	55
Adjusted EBITDA related to unconsolidated affiliates:
Citrus	$	81			$	76
MEP		26				4
White Cliffs		5				5
Explorer		13				8
Other		31				30
Total Adjusted EBITDA related to unconsolidated affiliates	$	156			$	123
Distributions received from unconsolidated affiliates:
Citrus	$	—			$	44
MEP		13				3
White Cliffs		4				4
Explorer		7				6
Other		22				20
Total distributions received from unconsolidated affiliates	$	46			$	77

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,
	2022			2021
Adjusted EBITDA of non-wholly-owned subsidiaries (100%) (a)	$	613		$	656
Our proportionate share of Adjusted EBITDA of non-wholly-owned subsidiaries (b)		294			312
Distributable Cash Flow of non-wholly-owned subsidiaries (100%) (c)	$	593		$	611
Our proportionate share of Distributable Cash Flow of non-wholly-owned subsidiaries (d)		279			284

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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Energy Transfer
Investor Relations:
Bill Baerg, Brent Ratliff, Lyndsay Hannah, 214-981-0795
or
Media Relations:
Vicki Granado, 214-840-5820

Source: Energy Transfer LP