Energy Transfer LP
For the period ended Dec 31, 2024. Filed Feb 14, 2025.
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A company's yearly report to the SEC, with audited financial statements. It is the fullest account a company gives of its business, its finances and the risks it sees.
FY2024 · Filed Feb 14, 2025
ET$18.92-1.4%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-K
Period ended 2023-12-31; filed 2024-02-16.
0001276187-24-000024
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSCurrent report: 10-K
Period ended 2024-12-31; filed 2025-02-14.
0001276187-25-000018
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 321 previous paragraphs and 335 current paragraphs.
188 unchanged; 75 reworded; 67 added; 57 removed; 1 previous and 5 current paragraphs rearranged.
Tables are not compared: 24 previous and 24 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (67)
Current report
WTG Midstream Acquisition
Current report
On July 15, 2024, Energy Transfer completed the acquisition of 100% of the membership interest in WTG Midstream. Consideration for the transaction was comprised of $2.28 billion in cash and approximately 50.8 million newly issued Energy Transfer common units, which had a fair value of approximately $833 million.
Current report
The acquired assets include approximately 6,000 miles of complementary gas gathering pipelines that extended Energy Transfer’s network in the Midland Basin. Also, as part of the transaction, the Partnership added eight gas processing plants with a total capacity of approximately 1.3 Bcf/d, and two additional processing plants that were under construction at closing. Since closing the transaction, one of these 200 MMcf/d processing plants was placed into service.
Current report
Sunoco LP
Current report
NuStar Acquisition
Current report
Zenith European Terminals Acquisition
Current report
On March 13, 2024, Sunoco LP completed the acquisition of liquid fuels terminals in Amsterdam, Netherlands and Bantry Bay, Ireland from Zenith Energy for approximately €170 million ($185 million), including working capital. The acquisition is expected to supply optimization for Sunoco LP’s existing East Coast business and continues its focus on growing its portfolio of stable midstream income.
Current report
Other Acquisition
Current report
On August 30, 2024, Sunoco LP acquired a terminal in Portland, Maine for approximately $24 million, including working capital.
Current report
West Texas Sale
Current report
Joint Venture Transaction
Current report
ET-S Permian
Current report
Effective July 1, 2024, Energy Transfer and Sunoco LP formed ET-S Permian, a joint venture combining their respective crude oil and produced water gathering assets in the Permian Basin. Energy Transfer contributed its Permian crude oil and produced water gathering assets and operations to ET-S Permian. Sunoco LP contributed all of its Permian crude oil gathering assets and operations to ET-S Permian. Energy Transfer’s long-haul crude pipeline network that provides transportation of crude oil out of the Permian Basin to Nederland, Houston and Cushing is excluded from ET-S Permian.
Current report
ET-S Permian operates more than 5,000 miles of crude oil and water gathering pipelines with crude oil storage capacity in excess of 11 million barrels.
Current report
Energy Transfer holds a 67.5% interest, with Sunoco LP holding the remaining 32.5% interest in ET-S Permian. Energy Transfer is the operator of ET-S Permian.
Current report
Operators and industry groups have challenged the Plan in the D.C. Circuit, as well as the legal predicates to the individual upwind states’ inclusion in the Plan in the regional circuits. The effectiveness of the rule is currently stayed in the nine states within the Partnership’s footprint, by nature of judicial stays of the legal predicate to the Plan, by judicial stay of the Plan itself by the U.S. Supreme Court, or by the administrative stay issued by the EPA in October 2024. Proceedings as to both on the merits are ongoing. In the challenge to the Plan in the D.C. Circuit, oral argument is expected in early 2025 and a decision could take several months, projected late 2025.
Current report
For 2025 and beyond, we expect increased demand from new data centers, power plants and LNG exports to support increased production, while increased global demand for petrochemicals and NGL feedstocks is expected to support higher volumes of NGL production and exports on existing assets and assets currently being developed or under construction. In addition, in the United States, we expect a more constructive regulatory environment under the new presidential administration, which we anticipate being favorable for project development and our operations in general.
Current report
Net Income. For the year ended December 31, 2024 compared to the prior year, net income increased $1.27 billion, or approximately 24%, primarily due to the recognition of a $586 million gain on Sunoco LP’s sale of its West Texas assets in the current year, as well as the recognition of a $627 million non-operating litigation-related loss in the prior year. The change in net income also reflected higher segment margin from multiple segments, partially offset by increases in operating expenses, selling, general and administrative expenses, depreciation, depletion and amortization, impairment losses, interest expense and income tax expense; these changes are discussed in more detail below and in “Segment Operating Results.”
Current report
(Gains) Losses on Extinguishment of Debt. For the year ended December 31, 2024, losses on extinguishment of debt included a $5 million loss on Energy Transfer’s redemption of its $450 million aggregate principal amount of 8.00% senior notes due April 2029 and $500 million aggregate principal amount of 5.75% senior notes due April 2025, a $2 million loss recognized by Sunoco LP and a $5 million loss related to USAC’s redemption of its $725 million aggregate principal amount of 6.875% senior notes due 2026.
Current report
Gain on Sale of West Texas Assets (Sunoco LP). The gain on sale of West Texas assets relates to the gain recognized by Sunoco LP upon completion of the sale of convenience stores to 7-Eleven Inc. in April 2024. During the fourth quarter of 2024, Sunoco LP recorded a $12 million reduction to the gain to reflect adjustments to the cash proceeds and certain balance sheet accounts associated with the business sold.
Current report
Volumes. For the year ended December 31, 2024 compared to the prior year, transported volumes of gas on our Texas and Oklahoma intrastate pipelines decreased primarily due to less third-party transportation and decreased gas production from the Haynesville area. Transported volumes reported above exclude volumes attributable to purchases and sales of gas for our pipelines’ own accounts and the optimization of any unused capacity.
Current report
Segment Adjusted EBITDA. For the year ended December 31, 2024 compared to the prior year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment increased due to the net impact of the following:
Current report
•an increase of $14 million in transportation fees primarily due to the recovery of certain fees earned in a prior period on our Texas system; partially offset by
Current report
•an increase of $61 million in operating expenses primarily due to a $35 million increase in maintenance project costs, an aggregate $22 million increase in employee related costs, outside services, materials and office expense, and a $6 million increase from the revaluation of system gas;
Current report
•an increase of $14 million in selling, general and administrative expenses primarily due to higher professional fees and employee costs; and
Current report
Segment Adjusted EBITDA. For the year ended December 31, 2024 compared to the prior year, Segment Adjusted EBITDA related to our midstream segment increased due to the net impact of the following:
Current report
•an increase of $686 million in segment margin primarily due to recently acquired assets and higher volumes in the Permian region;
Current report
•an increase of $69 million in other primarily from the recognition of proceeds from a business interruption claim; and
Current report
•an increase of $3 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to recently acquired assets; partially offset by
Current report
•an increase of $346 million in operating expenses primarily due to a $297 million increase related to recent acquisitions and assets placed in service, a $30 million increase in employee costs and a $10 million increase in expense projects; and
Current report
•an increase of $92 million in terminal services margin primarily due to an $80 million increase in fees from loading volumes for export at our Nederland and Marcus Hook terminals and a $12 million increase from higher throughput and storage at our refined product terminals;
Current report
•an increase of $8 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to increased volume on our White Cliffs NGL Pipeline; partially offset by
Current report
•an increase of $65 million in operating expenses primarily due to a $24 million increase in employee costs, a $17 million increase resulting from the timing of project related expenses, a $15 million increase in outside services expenses, a $13 million increase in ad valorem taxes and increases totaling $13 million from various other operating expenses. These increases were partially offset by an $18 million decrease in gas and power utility costs; and
Current report
•an increase of $3 million in selling, general and administrative expenses primarily due to increased costs from recently acquired assets.
Current report
Volumes. For the year ended December 31, 2024 compared to the prior year, crude oil transportation volumes were higher due to continued growth on our gathering systems, as well as contributions from recently acquired assets and from assets contributed upon the recent formation of the ET-S Permian joint venture with Sunoco LP, partially offset by lower volumes on our Bakken Pipeline.
Current report
•an increase of $670 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $541 million increase from recently acquired assets and assets contributed upon the recent formation of the ET-S Permian joint venture, a $122 million increase in transportation revenues from existing assets and a $7 million increase in our crude oil acquisition and marketing business from more favorable market conditions; and
Current report
•an increase of $153 million in operating expenses primarily due to a $106 million increase from recently acquired assets and assets contributed upon the recent formation of the ET-S Permian joint venture, a $15 million increase in outside services, an $11 million increase in ad valorem taxes, a $10 million increase in employee expenses and various increases in volume-driven expenses; and
Current report
•an increase of $29 million in selling, general and administrative expenses primarily due to a $27 million increase from recently acquired assets and assets contributed upon the recent formation of the ET-S Permian joint venture, as well as higher employee costs.
Current report
Segment Adjusted EBITDA. For the year ended December 31, 2024 compared to the prior year, Segment Adjusted EBITDA related to the Investment in Sunoco LP segment increased due to the net impact of the following:
Current report
•an increase of $738 million in segment margin (excluding unrealized gains and losses on commodity risk management activities and inventory valuation adjustments) primarily due to the acquisitions of NuStar and Zenith European terminals; and
Showing the first 40 of 67 passages. Open the source sections for the rest.
Removed paragraphs (57)
Previous report
Crestwood Acquisition
Previous report
On November 3, 2023, Energy Transfer acquired Crestwood, which owns gathering and processing assets located in the Williston, Delaware and Powder River basins. Under the terms of the merger agreement, holders of Crestwood common units received 2.07 Energy Transfer common units for each Crestwood common unit held by them (the “Common Unit Merger Consideration”). Additionally, each outstanding Crestwood preferred unit was, at the election of the holder of such Crestwood preferred unit, either, (i) converted into a Series I Preferred Unit, which is a new preferred unit of Energy Transfer that has substantially similar terms, including with respect to economics and structural protections, as the Crestwood preferred units; (ii) redeemed in exchange for $9.857484 in cash plus accrued and unpaid distributions to the date of such redemption; or (iii) converted into a Crestwood common unit at the then-applicable conversion ratio of one Crestwood common unit for ten Crestwood preferred units, and such Crestwood common units then received the Common Unit Merger Consideration.
Previous report
In total, consideration issued in the transaction included approximately 216 million Energy Transfer common units, 41 million Series I Preferred Units and $300 million in cash. Concurrent with the closing of the Crestwood acquisition, the Partnership assumed $2.85 billion aggregate principal amount of Crestwood senior notes and terminated its revolving credit facility, which included the repayment of $613 million in outstanding borrowings.
Previous report
Lotus Midstream Acquisition
Previous report
On May 2, 2023, Energy Transfer acquired Lotus Midstream for total consideration of $1.50 billion, including working capital. Consideration included $930 million in cash and approximately 44.5 million newly issued Energy Transfer common units, which had an aggregate acquisition-date fair value of $574 million. Lotus Midstream owns and operates Centurion Pipeline Company LLC, an integrated crude midstream platform located in the Permian Basin.
Previous report
Sunoco LP’s Acquisitions and Divestiture
Previous report
On January 11, 2024, Sunoco LP also announced that it will acquire liquid fuels terminals in Amsterdam, Netherlands and Bantry Bay, Ireland from Zenith Energy for €170 million including working capital. The transaction is expected to close in the first quarter of 2024, subject to customary closing conditions.
Previous report
On May 1, 2023, Sunoco LP completed the acquisition of 16 refined product terminals located across the East Coast and Midwest from Zenith Energy for $111 million, including working capital.
Previous report
In addition, the U.S. economy has experienced higher-than-average inflation in recent years, which has resulted in higher costs for labor, services, and materials. Our suppliers and customers also face inflationary pressures, and our throughput volumes may be impacted if producers are constrained. While the rate and scope of various inflationary factors may increase our operating costs and capital expenditures materially, we anticipate that any such impacts would be recoverable in the prices of our services.
Previous report
Net Income. For the year ended December 31, 2023 compared to the prior year, net income decreased $574 million, or approximately 10%, primarily due tothe recognition of a$627 million non-operating litigation-related loss, as well as decreases in gains on interest rate derivatives and increases in interest expense, income tax expense and depreciation, depletion and amortization expense; each of these items is discussed further below. The impacts of these decreases were partially offset by an increase in equity in earnings of unconsolidated affiliates, as well as the impacts of impairment and other losses recognized in the prior period; these items are also discussed further below. The change to net income also reflects changes in Adjusted EBITDA, which are summarized below and discussed in more detail in “Segment Operating Results.”
Previous report
For the year ended December 31, 2022, impairment losses and other included an $85 million loss on the deconsolidation of Energy Transfer Canada, which was recorded upon the completion of the sale in August 2022. The amount also included a $300 million impairment related to Energy Transfer Canada’s assets recorded in March 2022 based on the anticipated proceeds from the expected sale of those assets. The remainder of the impairment losses were from USAC’s recognition of impairment losses related to its compression equipment.
Previous report
(1)For the year ended December 31, 2022, equity in earnings (losses) of unconsolidated affiliates included the impact of non-cash impairments recorded by White Cliffs, which reduced the Partnership’s equity in earnings by $9 million.
Previous report
Volumes. For the year ended December 31, 2023 compared to the prior year, transported volumes increased primarily due to increased utilization on our Texas intrastate assets, partially offset by decreased production from our Haynesville assets.
Previous report
Segment Adjusted EBITDA. For the year ended December 31, 2023 compared to the prior year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment decreased due to the net impacts of the following:
Previous report
•a decrease of $122 million in retained fuel revenues related to lower natural gas prices; partially offset by
Previous report
•a decrease of $55 million in operating expenses related to a decrease in cost of fuel consumption from lower natural gas prices;
Previous report
•an increase of $24 million in transportation fees primarily due to new contracts on our Texas system and Haynesville assets; and
Previous report
•a decrease of $45 million in operating expenses primarily due to a $65 million decrease from the revaluation of system gas and a $10 million decrease in ad valorem taxes due to lower assessments on several of our interstate pipelines. These decreases were partially offset by $25 million of incremental expenses from our Gulf Run system being placed in service in December 2022 and higher maintenance project costs of $4 million;
Previous report
•a decrease of $16 million in selling, general and administrative expenses primarily due to an $11 million decrease in M&A related expenses and a $7 million decrease in professional fees. These decreases were partially offset by $3 million of incremental expenses from our Gulf Run system being placed in service in December 2022; and
Previous report
Segment Adjusted EBITDA. For the year ended December 31, 2023 compared to the prior year, Segment Adjusted EBITDA related to our midstream segment decreased due to the net impacts of the following:
Previous report
•an increase in operating expenses of $117 million due to a $36 million increase in services and materials, including repairs, volume-driven consumables and maintenance, compliance and pricing, a $31 million increase in employee costs due to segment reallocations, increased headcount and wage and benefit costs, a $43 million increase from newly acquired and installed assets, and a $10 million increase in ad valorem taxes, partially offset by a $4 million decrease in utility costs;
Previous report
•an increase of $13 million in selling, general and administrative expenses primarily due to higher corporate allocations and M&A expenses;
Previous report
•a decrease of $5 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to the sale of the Partnership’s membership interest in Ranch Westex JV LLC in 2022; and
Previous report
•a decrease of $34 million in other Adjusted EBITDA primarily due to the realization in the previous period of certain amounts related to a shipper bankruptcy; partially offset by
Previous report
•an increase of $223 million due to newly acquired assets as well as higher volumes across all regions.
Previous report
•an increase of $193 million in terminal services margin primarily due to a $120 million increase from our Marcus Hook Terminal due to contractual rate escalations and higher throughput, a $65 million increase from higher export volumes loaded at our Nederland Terminal, a $4 million increase due to higher throughput from our refined product marketing terminals and a $3 million increase from tank leases at our Eagle Point Terminal;
Previous report
•a decrease of $70 million in operating expenses primarily due to an $87 million decrease in gas and power utility costs, partially offset by a $16 million increase in employee costs;
Previous report
•an increase of $35 million in storage margin associated with increased NGL export volumes; and
Previous report
•an increase of $30 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 $9 million increase in overhead expenses and a $6 million increase in insurance costs.
Previous report
Volumes. For the year ended December 31, 2023 compared to the prior year, 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.
Previous report
•an increase of $427 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $275 million increase from recently acquired assets, a $157 million increase from higher volumes on our Bakken Pipeline, a $71 million increase from higher volumes on our Texas crude pipeline system, a $31 million increase from our Nederland and Houston crude terminals due to higher throughput and exports and a $17 million increase from our Midcontinent gathering systems, partially offset by a $135 million decrease from our crude oil acquisition and marketing business due primarily to less favorable pricing and higher affiliate fees from higher volumes transported;
Previous report
•a decrease of $104 million in selling, general and administrative expenses primarily due to a charge related to a legal matter in the prior period; and
Previous report
•an increase of $54 million in operating expenses primarily due to a $66 million increase from recently acquired assets, a $13 million increase in volume-driven expenses and an $8 million increase in employee-related expenses, partially offset by a $4 million decrease in measurement expenses, a $5 million decrease in ad valorem taxes and a $20 million decrease in maintenance project expenses.
Previous report
Segment Adjusted EBITDA. For the year ended December 31, 2023 compared to the prior year, Segment Adjusted EBITDA related to the Investment in Sunoco LP segment decreased due to the net impacts of the following:
Previous report
•an increase in the gross profit on motor fuel sales of $34 million primarily due to an 8% increase in gallons sold; and
Previous report
•an increase in non-motor fuel sales and lease profit of $37 million primarily due to increased throughput and storage margin from the Gladieux and Zenith acquisitions and increased rental income; partially offset by
Previous report
•an increase in operating costs of $26 million, including other operating expense, general and administrative expense and lease expense. The increase was primarily due to higher costs as a result of the recent acquisitions of refined product terminals and the transmix processing and terminal facility.
Previous report
•our investment in coal handling facilities; and
Previous report
•our Canadian operations, until those assets were divested in August 2022.
Previous report
Segment Adjusted EBITDA. For the year ended December 31, 2023 compared to the prior year, Segment Adjusted EBITDA decreased primarily due to the net impacts of the following:
Showing the first 40 of 57 passages. Open the source sections for the rest.
Reworded paragraphs (75)
Previous wording
The following discussion of our consolidated financial condition and results of operations for the years ended December 31, 2023 and 2022 should be read in conjunction with our consolidated financial statements and accompanying notes thereto included in “Item 8. Financial Statements and Supplementary Data” of this report. This discussion includes forward-looking statements that are subject to risk and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed in “Item 1A. Risk Factors” of this report.
Current wording
The following discussion of our consolidated financial condition and results of operations for the years ended December 31, 2024 and 2023 should be read in conjunction with our consolidated financial statements and accompanying notes thereto included in “Item 8. Financial Statements and Supplementary Data” of this report. This discussion includes forward-looking statements that are subject to risks and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed in “Item 1A. Risk Factors” of this report.
Previous wording
•crude oil, NGL and refined products transportation, terminalling and acquisition and marketing activities as well as NGL storage and fractionation services.
Current wording
•crude oil, NGL and refined products transportation, terminalling services and acquisition and marketing activities, as well as NGL storage and fractionation services and LNG regasification.
Previous wording
Energy Transfer derives cash flows from distributions related to its investment in its subsidiaries, including Sunoco LP and USAC. The amount of cash that our subsidiaries distribute to us is based on earnings from their respective business activities and the amount of available cash. Energy Transfer’s primary cash requirements are for distributions to its partners, general and administrative expenses and debt service requirements. Energy Transfer distributes its available cash remaining after satisfaction of the aforementioned cash requirements to its Unitholders on a quarterly basis.
Current wording
Energy Transfer derives cash flows from distributions related to its investment in its subsidiaries, including Sunoco LP and USAC. The amount of cash that our subsidiaries distribute to us is based on earnings from their respective business activities and the amount of available cash. Energy Transfer’s primary cash requirements are for distributions to its partners, capital expenditures, general and administrative expenses and debt service requirements. Energy Transfer distributes its available cash remaining after satisfaction of the aforementioned cash requirements to its Unitholders on a quarterly basis.
Previous wording
On January 22, 2024, Sunoco LP entered into a definitive agreement with NuStar to acquire NuStar in an all-equity transaction valued at approximately $7.3 billion, including assumed debt. Under the terms of the agreement, NuStar common unitholders will receive 0.4 Sunoco common units for each NuStar common unit. NuStar has approximately 9,500 miles of pipeline and 63 terminal and storage facilities that store and distribute crude oil, refined products, renewable fuels, ammonia and specialty liquids. The transaction is expected to close in the second quarter of 2024, subject to customary closing conditions.
Current wording
On May 3, 2024, Sunoco LP completed the acquisition of all of the common units of NuStar. Under the terms of the merger agreement, NuStar common unitholders received 0.400 Sunoco LP common units for each NuStar common unit. In connection with the acquisition, Sunoco LP issued approximately 51.5 million common units, which had a fair value of approximately $2.85 billion, assumed debt totaling approximately $3.5 billion, including approximately $56 million of lease related financing obligations, and assumed preferred units with a fair value of approximately $800 million. Subsequent to the closing of the NuStar acquisition, Sunoco LP redeemed all outstanding NuStar preferred units totaling $784 million, redeemed NuStar's subordinated notes totaling $403 million and repaid and terminated the NuStar credit facility totaling $455 million. NuStar has approximately 9,500 miles of pipeline and 63 terminal and storage facilities that store and distribute crude oil, refined products, renewable fuels, ammonia and specialty liquids.
Previous wording
On January 11, 2024, Sunoco LP entered into a definitive agreement with 7-Eleven, Inc. to sell 204 convenience stores located in West Texas, New Mexico and Oklahoma for approximately $1.00 billion, including customary adjustments for fuel and merchandise inventory. As part of the sale, Sunoco LP will also amend its existing take-or-pay fuel supply agreement with 7-Eleven, Inc. to incorporate additional fuel gross profit. The transaction is expected to close promptly upon receipt of regulatory approvals and satisfaction of customary closing conditions.
Current wording
On April 16, 2024, Sunoco LP completed the sale of 204 convenience stores located in West Texas, New Mexico and Oklahoma to 7-Eleven, Inc. for approximately $1.00 billion, including customary adjustments for fuel and merchandise inventory. As part of the sale, Sunoco LP also amended its existing take-or-pay fuel supply agreement with 7-Eleven, Inc. to incorporate additional fuel gross profit.
Previous wording
On July 18, 2018, the FERC issued a final rule establishing procedures to evaluate rates charged by the FERC-jurisdictional gas pipelines in light of the Tax Act and the FERC’s Revised Policy Statement. By an order issued on January 16, 2019, the FERC initiated a review of Panhandle’s then existing rates pursuant to Section 5 of the NGA to determine whether the rates charged by Panhandle are just and reasonable and set the matter for hearing. On August 30, 2019, Panhandle filed a general rate proceeding under Section 4 of the NGA. The NGA Section 5 and Section 4 proceedings were consolidated by order of the Chief Judge on October 1, 2019. The initial decision by the administrative law judge was issued on March 26, 2021, and on December 16, 2022, the FERC issued its order on the initial decision. On January 17, 2023, Panhandle and the Michigan Public Service Commission each filed a request for rehearing of FERC’s order on the initial decision, which were denied by operation of law as of February 17, 2023. On March 23, 2023, Panhandle appealed these orders to the United States Court of Appeals for the District of Columbia Circuit (“Court of Appeals”), and the Michigan Public Service Commission also subsequently appealed these orders. On April 25, 2023, the Court of Appeals consolidated Panhandle’s and Michigan Public Service Commission’s appeals and stayed the consolidated appeal proceeding while the FERC further considered the requests for rehearing of its December 16, 2022 order. On September 25, 2023, the FERC issued its order addressing arguments raised on rehearing and compliance, which denied our requests for rehearing. Panhandle has timely filed its Petition for Review with the Court of Appeals regarding the September 25, 2023 order. On October 25, 2023, Panhandle filed a limited request for rehearing of the September 25 order addressing arguments raised on rehearing and compliance, which was subsequently denied by operation of law on November 27, 2023. On November 30, 2023, Panhandle submitted a refund report regarding the consolidated rate proceedings, which has been protested by several parties. On January 5, 2024, the FERC issued a second order addressing arguments raised on rehearing in which it modified certain discussion from its September 25, 2023 order and sustained its prior conclusions. Panhandle has timely filed its Petition for Review with the Court of Appeals regarding the January 5, 2024 order.
Current wording
On July 18, 2018, the FERC issued a final rule establishing procedures to evaluate rates charged by the FERC-jurisdictional gas pipelines in light of the Tax Act and the FERC’s Revised Policy Statement. By an order issued on January 16, 2019, the FERC initiated a review of Panhandle’s then existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates charged by Panhandle are just and reasonable and set the matter for hearing. On August 30, 2019, Panhandle filed a general rate proceeding under Section 4 of the Natural Gas Act. The Natural Gas Act Section 5 and Section 4 proceedings were consolidated by order of the Chief Judge on October 1, 2019. The initial decision by the administrative law judge was issued on March 26, 2021, and on December 16, 2022, the FERC issued its order on the initial decision. On January 17, 2023, Panhandle and the Michigan Public Service Commission each filed a request for rehearing of FERC’s order on the initial decision, which were denied by operation of law as of February 17, 2023. On March 23, 2023, Panhandle appealed these orders to the United States Court of Appeals for the District of Columbia Circuit (“Court of Appeals”), and the Michigan Public Service Commission also subsequently appealed these orders. On April 25, 2023, the Court of Appeals consolidated Panhandle’s and Michigan Public Service Commission’s appeals and stayed the consolidated appeal proceeding while the FERC further considered the requests for rehearing of its December 16, 2022 order. On September 25, 2023, the FERC issued its order addressing arguments raised on rehearing and compliance, which denied our requests for rehearing. Panhandle filed its Petition for Review with the Court of Appeals regarding the September 25, 2023 order. On October 25, 2023, Panhandle filed a limited request for rehearing of the September 25 order addressing arguments raised on rehearing and compliance, which was subsequently denied by operation of law on November 27, 2023. On November 17, 2023, Panhandle provided refunds to shippers and on November 30, 2023, Panhandle submitted a refund report regarding the consolidated rate proceedings, which was protested by several parties. On January 5, 2024, the FERC issued a second order addressing arguments raised on rehearing in which it modified certain discussion from its September 25, 2023 order and sustained its prior conclusions. Panhandle has timely filed its Petition for Review with the Court of Appeals regarding the January 5, 2024 order. On May 28, 2024, the FERC issued an order rejecting Panhandle’s refund report. On June 27, 2024, Panhandle filed a revised refund report in compliance with the FERC’s May 28, 2024 order rejecting Panhandle’s refund report and a request for rehearing of the FERC’s May 28, 2024 order rejecting Panhandle’s refund report, and provided revised refunds to shippers, or in the case of shippers whose revised refunds are less than the original amounts refunded, n…
Excerpt shortened here; the source contains the full paragraph.
Previous wording
The FERC issued a Notice of Inquiry on April 19, 2018 (“Pipeline Certification NOI”), thereby initiating a review of its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. On February 18, 2021, the FERC issued another NOI (“2021 NOI”), reopening its review of the 1999 Policy Statement. Comments on the 2021 NOI were due on May 26, 2021; we filed comments in the FERC proceeding. In September 2021, FERC issued a Notice of Technical Conference on Greenhouse Gas Mitigation related to natural gas infrastructure projects authorized under Sections 3 and 7 of the NGA. A technical conference was held on November 19, 2021, and post-technical conference comments were submitted to the FERC on January 7, 2022.
Current wording
The FERC issued a Notice of Inquiry (“NOI”) on April 19, 2018, thereby initiating a review of its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. On February 18, 2021, the FERC issued another NOI (“2021 NOI”), reopening its review of the 1999 Policy Statement. Comments on the 2021 NOI were due on May 26, 2021; we filed comments in the FERC proceeding. In September 2021, FERC issued a Notice of Technical Conference on Greenhouse Gas Mitigation related to natural gas infrastructure projects authorized under Sections 3 and 7 of the NGA. A technical conference was held on November 19, 2021, and post-technical conference comments were submitted to the FERC on January 7, 2022.
Previous wording
On February 18, 2022, the FERC issued two new policy statements: (1) an Updated Policy Statement on the Certification of New Interstate Natural Gas Facilities and (2) a Policy Statement on the Consideration of Greenhouse Gas Emissions in Natural Gas Infrastructure Project Reviews (“2022 Policy Statements”), to be effective that same day. On March 24, 2022, the FERC issued an order designating the 2022 Policy Statements as draft policy statements, and requested further comments. The FERC will not apply the now draft 2022 Policy Statements to pending applications or applications to be filed at FERC until it issues any final guidance on these topics. Comments on the 2022 Policy Statements were due on April 25, 2022, and reply comments were due on May 25, 2022. We are unable to predict what, if any, changes may be proposed as a result of the 2022 Policy Statements that might affect our natural gas pipeline or LNG facility projects, or when such new policies, if any, might become effective. We do not expect that any change in these policy statements would affect us in a materially different manner than any other natural gas pipeline company operating in the United States.
Current wording
Greenhouse Gas Emissions in Natural Gas Infrastructure Project Reviews (“GHG Policy Statement”), to be effective that same day. On March 24, 2022, the FERC issued an order designating the 2022 Certificate Policy Statement and the GHG Policy Statement as draft policy statements, and requested further comments. The FERC stated that it will not apply the now draft policy statements to pending applications or applications to be filed at FERC until it issues any final guidance on these topics. Comments on the 2022 Certificate Policy Statement and GHG Policy Statement were due on April 25, 2022, and reply comments were due on May 25, 2022. On January 24, 2025, the FERC issued an order withdrawing the draft GHG Policy Statement and terminating the proceeding. The FERC has taken no further action on the 2022 Certificate Policy Statement. We are unable to predict what, if any, changes may be proposed as a result of the 2022 Certificate Policy Statement that might affect our natural gas pipeline or LNG facility projects, or when such new policy, if any, might become effective. We do not expect that any change in this policy statement would affect us in a materially different manner than any other natural gas pipeline company operating in the United States.
Previous wording
Liquids pipelines transporting in interstate commerce are regulated by FERC as common carriers under the Interstate Commerce Act (“ICA”). Under the ICA, the FERC utilizes an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods, or PPI-FG. Many existing pipelines utilize the FERC liquids index to change transportation rates annually. The indexing methodology is applicable to existing rates, with the exclusion of market-based rates. The FERC’s indexing methodology is subject to review every five years.
Current wording
Liquids pipelines transporting in interstate commerce are regulated by FERC as common carriers under the ICA. Under the ICA, the FERC utilizes an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods, or PPI-FG. Many existing pipelines utilize the FERC liquids index to change transportation rates annually. The indexing methodology is applicable to existing rates, with the exclusion of market-based rates. The FERC’s indexing methodology is subject to review every five years.
Previous wording
On December 17, 2020, FERC issued an order establishing a new index of PPI-FG plus 0.78%. The FERC received requests for rehearing of its December 17, 2020 order and on January 20, 2022, granted rehearing and modified the oil index. Specifically, for the five-year period commencing July 1, 2021 and ending June 30, 2026, FERC-regulated liquids pipelines charging indexed rates are permitted to adjust their indexed ceilings annually by PPI-FG minus 0.21%. FERC directed liquids pipelines to recompute their ceiling levels for July 1, 2021 through June 30, 2022, as well as the ceiling levels for the period July 1, 2022 to June 30, 2023, based on the new index level. Where an oil pipeline’s filed rates exceed its ceiling levels, FERC ordered such oil pipelines to reduce the rate to bring it into compliance with the recomputed ceiling level to be effective March 1, 2022. Some parties sought rehearing of the January 20 order with FERC, which was denied by FERC on May 6, 2022. Certain parties have appealed the January 20 and May 6 orders. Such appeals remain pending at the D.C. Circuit.
Current wording
On December 17, 2020, FERC issued an order establishing a new index of PPI-FG plus 0.78%. The FERC received requests for rehearing of its December 17, 2020 order and on January 20, 2022, granted rehearing and modified the oil index. Specifically, for the five-year period commencing July 1, 2021 and ending June 30, 2026, FERC-regulated liquids pipelines charging indexed rates are permitted to adjust their indexed ceilings annually by PPI-FG minus 0.21%. FERC directed liquids pipelines to recompute their ceiling levels for July 1, 2021 through June 30, 2022, as well as the ceiling levels for the period July 1, 2022 to June 30, 2023, based on the new index level. Where an oil pipeline’s filed rates exceed its ceiling levels, FERC ordered such oil pipelines to reduce the rate to bring it into compliance with the recomputed ceiling level to be effective March 1, 2022. Some parties sought rehearing of the January 20 order with FERC, which was denied by FERC on May 6, 2022. Certain parties appealed the January 20 and May 6 orders. On July 26, 2024, the D.C. Circuit ruled in LEPA v. FERC that FERC violated the Administrative Procedure Act because the January 20 order modified the index without following notice and comment. As a result, the D.C. Circuit vacated the January 20 order and on September 17, 2024, the Commission reinstated the index level established by its original December 17 order, directed pipelines to file an informational filing to show their recomputed ceiling levels reflecting the reinstated index level and stated that pipelines may file to prospectively increase their indexed rates to their recomputed levels. On October 17, 2024, FERC issued a Supplemental NOPR that proposes a reduction to the currently effective index by one percent. The Supplemental NOPR, which remains pending before FERC, could result in the reimplementation through a notice-and-comment rulemaking of the same rulings that were vacated by the D.C. Circuit in LEPA v. FERC.
Previous wording
The EPA recently finalized its Good Neighbor Plan (the “Plan”) which seeks to reduce nitrogen oxide pollution from power plants and other industrial facilities from 23 upwind states which the EPA determined is contributing to National Ambient Air Quality Standards (NAAQS) nonattainment and interfering with maintenance of the 2015 ozone NAAQS in downwind states. As part of the Plan, the EPA announced that it would be issuing prescriptive emission standards for several sectors, including certain new and existing internal combustion engines of a certain size used in pipeline transportation of natural gas. The EPA’s final rule was to become effective on August 4, 2023, and the prescribed emission standards were scheduled to be effective in 2026; however, of the nine states impacted within the Partnership’s footprint, effectiveness of the rule is currently stayed in six states and pending a decision on a stay in three other states. Additionally, other operators and industry groups have challenged the Plan and sought a stay in the D.C. Circuit. Although the stay was denied, it was promptly followed by the filing of an emergency stay application with the U.S. Supreme Court, which will be heard on February 19, 2024, all while EPA has proposed adding five more states to the Plan. The Partnership currently estimates that the final rule would require retrofitting or replacement of approximately 192 engines in its interstate and intrastate natural gas transportation and storage operations. The Partnership is involved in challenging application of the Plan in the nine states impacted within its footprint. Compliance with the Plan (if implementation is not stayed or otherwise delayed) will still require substantial capital expenditures which could adversely affect our business in future periods. However, at this time, we are still assessing the potential costs of this rule and, given uncertainties resulting from the multiple legal challenges filed against the Plan in various states, in the DC Circuit and the U.S. Supreme Court, we cannot predict with any certainty what the final costs of compliance for the Plan for the Partnership ultimately may be.
Current wording
In 2023, the United States Environmental Protection Agency (“EPA”) finalized its Good Neighbor Plan (the “Plan”) which seeks to reduce nitrogen oxide pollution from power plants and other industrial facilities from 23 upwind states which the EPA determined is contributing to National Ambient Air Quality Standards (NAAQS) nonattainment and interfering with maintenance of the 2015 ozone NAAQS in downwind states. As part of the Plan, the EPA announced that it would be issuing prescriptive emission standards for several sectors, including certain new and existing internal combustion engines of a certain size used in pipeline transportation of natural gas. The EPA’s final rule was to become effective on August 4, 2023, and the prescribed emission standards were scheduled to be effective in 2026.
Previous wording
Overall, we believe the Partnership’s outlook is strong, as it has a stable business that has demonstrated its ability to manage through various market cycles. We expect future growth to be supported by production improvements, improved market conditions, and increased utilization of our existing assets, as well as strong domestic and international demand for our products.
Current wording
Overall, we continue to believe the Partnership’s outlook is strong, as it has a stable business that has demonstrated its ability to manage through various market cycles. We expect future growth to be supported by production improvements and increased utilization of our existing assets, as well as continued strong domestic and international demand for our products.
Previous wording
Ultimately, the extent to which our business will be impacted by future market developments depends on factors beyond our control, which are highly uncertain and cannot be predicted. In response to the recent market volatility and uncertainties, we have reduced growth capital spending in recent years, and we expect to continue to maintain a prudent level of growth capital spending going forward. See “Liquidity and Capital Resources” for additional information on our capital expenditures over the last two years and our forecasted capital expenditures for 2024.
Current wording
Ultimately, the extent to which our business will be impacted by future market developments depends on factors beyond our control, which are highly uncertain and cannot be predicted. In response to market volatility and other uncertainties, we have reduced growth capital spending in recent years. While we anticipate a healthy capital expenditure program in 2025 and beyond, we expect to continue to be prudent going forward as we allocate capital across our business segments. See “Liquidity and Capital Resources” for additional information on our capital expenditures over the last two years and our forecasted capital expenditures for 2025.
Previous wording
In addition to the trends and outlook discussed above with respect to the Partnership’s existing business and finances, we also anticipate that the Partnership will continue to increase its focus on the development of alternative energy projects. The Partnership has announced several such projects recently and will continue to pursue opportunities aimed at continuing to reduce its environmental footprint throughout its operations.
Current wording
In addition to the trends and outlook discussed above with respect to the Partnership’s existing business and finances, we also anticipate that the Partnership will continue to develop alternative energy projects. The Partnership has announced several such projects recently and will continue to pursue opportunities aimed at continuing to reduce its environmental footprint throughout its operations.
Previous wording
Adjusted EBITDA(consolidated). For the year ended December 31, 2023 compared to the prior year, Adjusted EBITDA increased $605 million primarily due to favorable results in multiple segments. The most significant increase was in our NGL and refined products transportation and services segment, which reflected higher throughput and contractual rates, as well as favorable impacts from optimization. Our crude oil transportation and services segment and our interstate transportation and storage segment also contributed to the increase in Adjusted EBITDA primarily due to higher volumes, as well as the impacts of recently acquired assets and assets recently placed in service. The increases from these segments were partially offset by a decrease in our midstream segment, primarily driven by the impacts of natural gas and NGL prices, and a decrease in our intrastate transportation and storage segment, which was impacted by lower pipeline optimization.
Current wording
Adjusted EBITDA(consolidated). For the year ended December 31, 2024 compared to the prior year, Adjusted EBITDA increased $1.79 billion, or approximately 13%, primarily due to favorable results in multiple segments. The most significant increases were in our midstream segment, our crude oil transportation and services segment and our Investment in Sunoco LP segment, each of which reflected increases from recently acquired assets. Our midstream segment also reflected increases from higher volumes, as did our NGL and refined products transportation and services segment. Our intrastate transportation and storage segment also reflected increases from higher pipeline optimization.
Previous wording
Interest Expense, Net of Interest Capitalized. Interest expense, net of interest capitalized, increased primarily due to higher interest rates on floating rate debt.
Current wording
Interest Expense, Net of Interest Capitalized. Interest expense, net of interest capitalized, increased primarily due to higher aggregate debt balances and higher interest rates on floating rate and recently refinanced debt.
Previous wording
Income Tax Expense. For the year ended December 31, 2023 compared to the same period last year, income tax expense increased due to higher earnings from the Partnership’s consolidated corporate subsidiaries.
Current wording
Income Tax Expense. For the year ended December 31, 2024 compared to the same period last year, income tax expense increased due to the taxable gain recognized by a corporate subsidiary of Sunoco LP on its sale of West Texas assets.
Previous wording
Impairment Losses and Other. For the year ended December 31, 2023, impairment losses and other consisted of impairment losses incurred by USAC related to its compression equipment.
Current wording
Impairment Losses and Other. For the year ended December 31, 2024, impairment losses and other were primarily related to Sunoco LP’s termination of a lease in June 2024. For the year ended December 31, 2023 impairment losses and other consisted of impairment losses incurred by USAC primarily related to its compression equipment.
Previous wording
Gains on Interest Rate Derivatives. Our interest rate derivatives are not designated as hedges for accounting purposes; therefore, changes in fair value are recorded in earnings each period. Gains on interest rate derivatives resulted from changes in forward interest rates, which caused our forward-starting swaps to change in value. The magnitude of the gains during the respective periods also reflected changes in the aggregate notional amount of interest rate swaps outstanding during the respective periods.
Current wording
Gains on Interest Rate Derivatives. Gains on interest rate derivatives resulted from changes in forward interest rates, which caused our forward-starting swaps to change in value.
Previous wording
Unrealized Gains on Commodity Risk Management Activities. The unrealized gains and losses on our commodity risk management activities include changes in fair value of commodity derivatives and the hedged inventory included in designated fair value hedging relationships. Information on the unrealized gains and losses within each segment are included in “Segment Operating Results” below, and additional information on the commodity-related derivatives, including notional volumes, maturities and fair values, is available in “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and in Note 14 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”
Current wording
Unrealized (Gains) Losses on Commodity Risk Management Activities. The unrealized gains and losses on our commodity risk management activities include changes in fair value of commodity derivatives and the hedged inventory included in designated fair value hedging relationships. Information on the unrealized gains and losses within each segment are included in “Segment Operating Results” below, and additional information on the commodity-related derivatives, including notional volumes, maturities and fair values, is available in “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and in Note 14 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”
Previous wording
Inventory Valuation Adjustments. Inventory valuation adjustments represent changes in lower of cost or market using the last-in, first-out method on Sunoco LP’s inventory. These amounts are unrealized valuation adjustments applied to fuel volumes remaining in inventory at the end of the period. For the year ended December 31, 2023, a decline in fuel prices caused the lower of cost or market reserve requirements to increase by $114 million, which reduced net income. For the year ended December 31, 2022, an increase in fuel prices caused the lower of cost or market reserve requirements to decrease by $5 million, which increased net income.
Current wording
Inventory Valuation Adjustments (Sunoco LP). Inventory valuation adjustments represent changes in lower of cost or market using the last-in, first-out method on Sunoco LP’s inventory. These amounts are unrealized valuation adjustments applied to fuel volumes remaining in inventory at the end of the period. For the years ended December 31, 2024 and 2023, decreases in fuel prices caused the lower of cost or market reserve requirements to increase by $86 million and $114 million, respectively, which reduced net income.
Previous wording
Non-Operating Litigation-Related Loss. Non-operating litigation-related loss recognized for the year ended December 31, 2023 represents the loss associated with the Williams Litigation, which is discussed in Note 11 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”
Current wording
Non-Operating Litigation-Related Loss. Non-operating litigation-related loss recognized for the year ended December 31, 2023 represents the loss associated with the The Williams Companies, Inc. litigation.
Previous wording
(2)These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or losses of our unconsolidated affiliates adjusted for our proportionate share of the unconsolidated affiliates’ interest, depreciation, depletion, amortization, non-cash items and taxes.
Current wording
(1)These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or losses of our unconsolidated affiliates adjusted for our proportionate share of the unconsolidated affiliates’ interest, depreciation, depletion, amortization, non-cash items and taxes.
Previous wording
•a decrease of $247 million in realized natural gas sales and other primarily due to lower pipeline optimization from both physical sales and settled derivatives; and
Current wording
•an increase of $265 million in realized natural gas sales and other primarily due to higher pipeline optimization from physical sales and settled derivatives; and
Previous wording
•an increase of $6 million in storage margin primarily due to higher storage optimization from hedged inventory activity.
Current wording
•a decrease of $34 million in storage margin primarily due to lower storage optimization from settled derivatives.
Previous wording
Volumes. For the year ended December 31, 2023 compared to the prior year, 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.
Current wording
Volumes. For the year ended December 31, 2024 compared to the prior year, transported volumes increased primarily due to more capacity sold and higher utilization on our Panhandle, Trunkline and Gulf Run systems due to increased demand.
Previous wording
Segment Adjusted EBITDA. For the year ended December 31, 2023 compared to the prior year, Segment Adjusted EBITDA related to our interstate transportation and storage segment increased due to the net impacts of the following:
Current wording
Segment Adjusted EBITDA. For the year ended December 31, 2024 compared to the prior year, Segment Adjusted EBITDA related to our interstate transportation and storage segment decreased due to the net impact of the following:
Previous wording
•an increase of $143 million in segment margin primarily due to a $141 million increase resulting from our Gulf Run system being placed in service in December 2022, a $47 million increase in transportation revenue from several of our interstate pipeline systems due to higher contracted volumes and higher rates, an $18 million increase related to a shipper bankruptcy, a $20 million increase in parking and storage revenue and a $5 million increase in interruptible utilization. These increases were partially offset by a $58 million decrease due to lower operational gas sales resulting from lower prices, a $23 million decrease due to lower rates on our Panhandle system resulting from a FERC rate case and an $8 million decrease in liquids revenue due to lower prices;
Current wording
•a decrease of $82 million in segment margin primarily due to a $36 million decrease due to lower operational gas sales resulting from lower prices, a $22 million decrease in parking revenue, a $21 million decrease due to lower volumes and a $10 million decrease due to lower rates on several of our interstate pipeline systems. These decreases were partially offset by an $8 million increase in storage revenue;
Previous wording
•an increase of $88 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to an increase of $76 million from our Midcontinent Express Pipeline joint venture due to capacity sold at higher rates, a $9 million increase from our Citrus joint venture due to revenues from new projects and lower operating expenses and an $8 million increase from our Southeast Supply Header joint venture due to increased capacity sold at higher rates. These increases were partially offset by a $6 million decrease from our Fayetteville Express Pipeline joint venture due to the expiration of a foundation shipper contract; partially offset by
Current wording
•a decrease of $19 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to a $23 million decrease from our Midcontinent Express Pipeline joint venture due to capacity sold at lower rates and a $6 million decrease from our Citrus joint venture primarily due to higher operating expenses. These decreases were partially offset by a $10 million increase from our Southeast Supply Header joint venture due to higher contracted volumes;
Previous wording
•a decrease of $36 million in other Adjusted EBITDA primarily due to the 2022 recognition of certain amounts related to shipper bankruptcies.
Current wording
•a decrease of $5 million in other primarily due to the prior period recognition of certain amounts related to a shipper bankruptcy.
Previous wording
Volumes. For the year ended December 31, 2023 compared to the prior year, gathered volumes and NGL production increased due to newly acquired assets and higher volumes from existing customers.
Current wording
Volumes. For the year ended December 31, 2024 compared to the prior year, gathered volumes increased primarily due to recently acquired assets and higher volumes in the Permian region. NGL production increased primarily due to recently acquired assets and increased Permian plant utilization.
Previous wording
•a decrease of $739 million due to lower natural gas prices of $478 million and lower NGL prices of $261 million;
Current wording
•a decrease of $27 million in segment margin due to lower natural gas prices of $59 million, partially offset by higher NGL prices of $32 million.
Previous wording
Volumes. For the year ended December 31, 2023 compared to the prior year, NGL transportation 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.
Current wording
Volumes. For the year ended December 31, 2024 compared to the prior year, NGL transportation volumes increased primarily due to higher volumes from the Permian and Eagle Ford regions and on our Mariner East pipeline system.
Previous wording
Segment Adjusted EBITDA. For the year ended December 31, 2023 compared to the prior year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to the net impacts of the following:
Current wording
Segment Adjusted EBITDA. For the year ended December 31, 2024 compared to the prior year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to the net impact of the following:
Previous wording
•an increase of $273 million in transportation margin primarily due to a $136 million increase resulting from higher throughput and contractual rate escalations on our Texas y-grade pipeline system, a $95 million increase resulting from higher throughput and contractual rate escalations on our Mariner East pipeline system, a $41 million increase from higher export volumes feeding into our Nederland Terminal, a $27 million increase from higher throughput and contractual rate escalations on our refined product pipelines, a $12 million increase from the timing of third-party deficiency payments on our Northeast region pipelines and a $7 million increase from higher throughput on our Mariner West pipeline. These increases were partially offset by intrasegment charges of $29 million and $17 million which were fully offset within our marketing and fractionation margins, respectively;
Current wording
•an increase of $183 million in transportation margin primarily due to a $161 million increase from higher throughput and contractual rate escalations on our Mariner East and our Gulf Coast pipeline systems and a $24 million increase on our refined products pipelines, as well as a $12 million increase in intrasegment margin which was fully offset within our fractionators margin. These increases were partially offset by an $12 million decrease in intrasegment margin which is fully offset within our marketing margin and a $5 million decrease from the timing of third-party deficiency payments on our Northeast region pipelines;
Previous wording
•an increase of $38 million in fractionators and refinery services margin primarily due to a $29 million increase resulting from higher volumes and $17 million in intrasegment margin which was fully offset within our transportation margin. These increases were partially offset by an $8 million decrease from our refinery services business;
Current wording
•an increase of $47 million in fractionators and refinery services margin primarily due to a $56 million increase resulting from higher throughput as our eighth fractionator was placed in service in August 2023 and a $3 million increase from our refinery services business. These increases were partially offset by a $12 million decrease in intrasegment margin which was fully offset within our transportation margin;
Previous wording
•an increase of $260 million in marketing margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to higher gains during 2023 from the optimization of hedged NGL and refined product inventories, as well as intrasegment margin of $29 million which was fully offset within our transportation margin;
Current wording
•an increase of $29 million in marketing margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to higher gains during 2024 from the optimization of hedged NGL and refined product inventories and an $12 million increase in intrasegment margin which is fully offset within our transportation margin; and
Previous wording
Segment Adjusted EBITDA. For the year ended December 31, 2023 compared to the prior year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased due to the net impacts of the following:
Current wording
Segment Adjusted EBITDA. For the year ended December 31, 2024 compared to the prior year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased due to the net impact of the following:
Previous wording
•an increase of $15 million in Adjusted EBITDA related to unconsolidated affiliates due to assets acquired and higher volumes on our White Cliffs crude pipeline; partially offset by
Current wording
•an increase of $9 million in Adjusted EBITDA related to unconsolidated affiliates due to recently acquired assets and higher volumes on our White Cliffs crude pipeline; partially offset by
Previous wording
•an increase of $29 million in Adjusted EBITDA related to unconsolidated affiliates due to higher volumes on certain joint venture pipelines; partially offset by
Current wording
•an increase of $91 million in Adjusted EBITDA related to unconsolidated affiliates due to the formation of the ET-S Permian joint venture; partially offset by
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Current report — wording carried from elsewhere
On February 18, 2022, the FERC issued two new policy statements: (1) an Updated Policy Statement on the Certification of New Interstate Natural Gas Facilities (“2022 Certificate Policy Statement”) and (2) a Policy Statement on the Consideration of
Current report — wording carried from elsewhere
The Partnership currently estimates that the final rule would require retrofitting or replacement of approximately 192 engines in its interstate and intrastate natural gas transportation and storage operations. The Partnership is involved in challenging application of the Plan in the nine states impacted within its footprint. Compliance with the Plan (if implementation is not stayed or otherwise delayed) will still require substantial capital expenditures which could adversely affect our business in future periods. However, at this time, we are still assessing the potential costs of this rule and, given uncertainties resulting from the multiple legal challenges filed against the Plan in various states, in the DC Circuit and the U.S. Supreme Court, we cannot predict with any certainty what the final costs of compliance for the Plan for the Partnership ultimately may be.
Current report — wording carried from elsewhere
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 NGL Complex.
Current report — wording carried from elsewhere
Cash provided by operating activities in 2023 was $9.56 billion and net income was $5.29 billion. The difference between net income and net cash provided by operating activities in 2023 primarily consisted of net changes in operating assets and liabilities (net of effects of acquisitions and divestitures) of $451 million and other items totaling $4.43 billion, which includes non-cash items and items related to financing activities that are included in net income.
Current report — wording carried from elsewhere
The percentage interests shown for common unitholders and IDR holder for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.
Rearranged previous paragraphs (1)
Previous report — wording carried elsewhere
Energy Transfer has a significant amount of interstate pipeline construction in progress. Changes in operating assets and liabilities between periods result from factors such as the changes in the value of derivative assets and liabilities, timing of accounts receivable collection, payments on accounts payable, the timing of purchases and sales of inventories, and the timing of advances and deposits received from customers.