Energy Transfer LP

Previous wording

•general economic, financial and political conditions, including the impact of tariffs, to the extent enacted;

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•general economic, financial and political conditions, including the impact of tariffs;

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•any increased costs or reduced demand for crude oil and natural gas as a result of the Inflation Reduction Act of 2022 (“IRA 2022”) or otherwise;

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•any increased costs or reduced demand for crude oil and natural gas as a result of policy changes or otherwise;

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•failure to execute our growth strategy due to increased competition within any of our core businesses;

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•failure to execute our growth strategy due to increased competition within any of our core businesses; and

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•failure to attract and retain qualified employees; and

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•failure to attract and retain qualified employees.

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•failure to recover the full amount of increases in the costs of our pipeline operations;

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•failure to recover the full amount of increases in the costs of our pipeline or refinery operations;

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•fiduciary duties owed to Sunoco LP, USAC and their respective unitholders by their general partners; and

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•fiduciary duties owed to SunocoCorp, Sunoco LP, USAC and their respective unitholders by their managing member or general partners, as applicable; and

Previous wording

The following discussion provides additional information regarding each of our risk factors listed above. In addition, Sunoco LP and USAC file Annual Reports on Form 10-K that include risk factors that can be reviewed for further information.

Current wording

The following discussion provides additional information regarding each of our risk factors listed above. In addition, SunocoCorp, Sunoco LP and USAC file Annual Reports on Form 10-K that include risk factors that can be reviewed for further information.

Previous wording

•the level of competition from other midstream, transportation and storage and retail marketing companies and other energy providers;

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•the level of competition from other midstream, transportation and storage and retail marketing companies, refinery operators and other energy providers;

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•the level of domestic natural gas, NGL, refined products and oil production;

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•the level of domestic natural gas, NGLs, refined products and oil production;

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•the level of natural gas, NGL, refined products and oil imports and exports, including liquefied natural gas;

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•the level of natural gas, NGLs, refined products and oil imports and exports, including liquefied natural gas;

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•the impact of weather, geopolitical events such as the armed conflict in Ukraine and political instability in the Middle East, public health crises, and other events of nature on the demand for natural gas, NGLs, refined products and oil;

Current wording

•the impact of weather, geopolitical events such as the conflicts in Ukraine and Venezuela, political instability in the Middle East, including Iran, public health crises, and other events of nature on the demand for natural gas, NGLs, refined products and oil;

Previous wording

General economic, financial, and political conditions, including the impact of tariffs to the extent enacted, may materially adversely affect our results of operations and financial condition.

Current wording

General economic, financial, and political conditions, including the impact of tariffs, may materially adversely affect our results of operations and financial condition.

Previous wording

General economic, financial, and political conditions may have a material adverse effect on our results of operations and financial condition. For example, following the election of President Trump and the implementation of certain tariffs, it is possible that our operations may be affected by volatility in pricing and demand. Similarly, declines in consumer confidence and/or consumer spending, changes in unemployment, significant inflationary or deflationary changes or disruptive regulatory or geopolitical events could contribute to increased volatility and diminished expectations for the economy and our markets, including the market for our goods and services, and lead to demand or cost pressures that could negatively and adversely impact our business. These conditions could affect both of our business segments.

Current wording

General economic, financial, and political conditions may have a material adverse effect on our results of operations and financial condition. For example, on March 12, 2025, the U.S. government imposed a 25% tariff on steel imports, which was increased to 50% on June 4, 2025, and on April 2, 2025, the U.S. government announced a 10% tariff on product imports from almost all foreign countries and individualized higher tariffs on certain other countries. Several tariff announcements have been followed by announcements of limited exemptions and temporary pauses. These actions have caused uncertainty and volatility in financial markets and may result in retaliatory measures on U.S. goods. It is possible that our operations may be affected by the resulting volatility in pricing and demand. Similarly, declines in consumer confidence and/or consumer spending, changes in unemployment, significant inflationary or deflationary changes or disruptive regulatory or geopolitical events could contribute to increased volatility and diminished expectations for the economy and our markets, including the market for our goods and services, and lead to demand or cost pressures that could negatively and adversely impact our business. These conditions could affect each of our business segments.

Previous wording

We own and operate pipelines and terminals and, like others in our industry, we use significant amounts of steel in our projects and rely on our ability to obtain that steel in an affordable way to maintain our operating margins. Any imposition of or increase in tariffs on steel and/or other raw materials could increase our growth project costs, which may impact the profitability of new projects.

Current wording

We own and operate pipelines and terminals and, like others in our industry, we use significant amounts of steel in our projects and rely on our ability to obtain that steel in an affordable way to maintain our operating margins. Any imposition of or increase in tariffs on steel and/or other raw materials could increase our growth project costs, which may impact the profitability of new projects, and our maintenance capital expenditures, potentially in excess of budgeted amounts.

Previous wording

Recently, the Trump Administration announced plans to implement or increase tariffs, and on February 10, confirmed extension of 25 percent import tariffs on steel globally to go into effect on March 12. The ultimate impact of this tariff is unknown at this time. Additionally, ongoing changes in U.S. and foreign government trade policies, including potential modifications to existing trade agreements and further restrictions on free trade, could introduce additional uncertainty. Any escalation of trade tensions, additional tariffs, retaliatory measures by foreign governments or shifts in U.S. or international trade policies could adversely impact our supply chain and increase costs, particularly on our expansion projects. A trade war or other significant changes in trade regulations could have an adverse effect on our business and results of operations.

Current wording

On March 12, 2025 the U.S government imposed a 25% tariff on steel imports, which was increased to 50% on June 4, 2025, and on April 2, 2025, the U.S government announced a 10% tariff on product imports from almost all countries and individualized higher tariffs on certain other countries. Several tariff announcements have been followed by announcements of limited exemptions and temporary pauses. These actions have caused uncertainty and volatility in financial markets and may result in retaliatory measures on U.S goods. The ultimate impact of these tariffs is unknown at this time. Additionally, ongoing changes in U.S. and foreign government trade policies, including potential modifications to existing trade agreements and further restrictions on free trade, could introduce additional uncertainty. Any escalation of trade tensions, additional tariffs, retaliatory measures by foreign governments or shifts in U.S. or international trade policies could adversely impact our supply chain and increase costs, particularly on our expansion projects. A trade war or other significant changes in trade regulations could have an adverse effect on our business and results of operations.

Previous wording

The U.S. inflation rate steadily rose in 2021 and into 2022 before eventually declining modestly throughout 2023 and 2024. A sustained increase in inflation may continue to increase our costs for labor, services, and materials, which, in turn, could cause our operating costs and capital expenditures to increase. Further, our producer suppliers and customers face inflationary pressures and resulting impacts, such as the tight labor market, availability of drilling and hydraulic fracturing equipment, and supply chain disruptions, which could increase the cost of production which in turn may limit the level of drilling activity in the regions in which we operate. Our throughput volumes may be impacted if producers are constrained. The rate and scope of these various inflationary factors may increase our operating costs and capital expenditures materially, which may not be readily recoverable in the prices of our services and may have an adverse effect on our results of operations and financial condition.

Current wording

The U.S. inflation rate remained relatively stable through 2024 and 2025, after an extended period of rising rates, which began in 2022. A sustained increase in inflation may continue to increase our costs for labor, services and materials, which, in turn, could cause our operating costs and capital expenditures to increase. Further, our customers face inflationary pressures and resulting impacts, such as the tight labor market and supply chain disruptions. The rate and scope of these various inflationary factors may increase our operating costs and capital expenditures materially, which may not be readily recoverable in the prices of our services and may have an adverse effect on our costs, operating margins, results of operations and financial condition.

Previous wording

Additionally, the Federal Reserve and other central banks have implemented policies in an effort to curb inflationary pressure on the costs of goods and services across the U.S., including the significant increases in prevailing interest rates that occurred during 2022 and 2023 as a result of the 525 aggregate basis point increase in the federal funds rate, and the associated macroeconomic impact on slowdown in economic growth could negatively impact our business. While the Federal Reserve reduced benchmark interest rates by 75 basis points in late 2024, the continuation of rates at the current level could have the effects of raising the cost of capital and depressing economic growth, either of which—or the combination thereof—could hurt the financial and operating results of our business.

Current wording

Additionally, the Federal Reserve and other central banks have implemented policies in an effort to curb inflationary pressure on the costs of goods and services across the U.S., including the significant increases in prevailing interest rates that occurred during 2022 and 2023 as a result of the 525 aggregate basis point increase in the federal funds rate, and the associated macroeconomic impact on slowdown in economic growth could negatively impact our business. While the Federal Reserve reduced benchmark interest rates by 100 basis points in late 2024, and 75 basis points in late 2025, the prospect of additional interest rate cuts remains uncertain and the continuation of rates at the current level could have the effects of raising the cost of capital and depressing economic growth, either of which—or the combination thereof—could hurt the financial and operating results of our business.

Previous wording

As of December 31, 2024, our consolidated balance sheet reflected $3.90 billion of goodwill and $5.97 billion of intangible assets. Goodwill is recorded when the purchase price of a business exceeds the fair value of the tangible and separately measurable intangible net assets. Accounting principles generally accepted in the United States require us to test goodwill for impairment on an annual basis or when events or circumstances occur, indicating that goodwill might be impaired. Long-lived assets such as intangible assets with finite useful lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If we determine that any of our goodwill or intangible assets were impaired, we would be required to take an immediate charge to earnings with a correlative effect on partners’ capital and balance sheet leverage as measured by debt to total capitalization.

Current wording

As of December 31, 2025, our consolidated balance sheet reflected $5.45 billion of goodwill and $7.44 billion of intangible assets. Goodwill is recorded when the purchase price of a business exceeds the fair value of the tangible and separately measurable intangible net assets. Accounting principles generally accepted in the United States require us to test goodwill for impairment on an annual basis or when events or circumstances occur, indicating that goodwill might be impaired. Long-lived assets such as intangible assets with finite useful lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If we determine that any of our goodwill or intangible assets were impaired, we would be required to take an immediate charge to earnings with a correlative effect on partners’ capital and balance sheet leverage as measured by debt to total capitalization.

Previous wording

During 2024, two customers accounted for approximately 23% of our intrastate transportation and storage revenues. During 2024, four customers collectively accounted for 29% of our interstate transportation and storage revenues.

Current wording

During 2025, two customers accounted for approximately 29% of our intrastate transportation and storage revenues. During 2025, four customers collectively accounted for 27% of our interstate transportation and storage revenues.

Previous wording

Protections.” Our ability to secure extensions of existing agreements, permits and licenses is essential to our continuing business operations, and securing additional rights-of-way will be critical to our ability to pursue expansion projects. We cannot provide any assurance that we will be able to maintain access to existing rights-of-way upon the expiration of the current grants, that all of the rights-of-way will be obtained in a timely fashion or that we will acquire new rights-of-way as needed.

Current wording

Our ability to operate our pipeline systems on certain lands owned by third parties will depend on our success in maintaining existing rights-of-way and obtaining new rights-of-way on those lands. We are parties to rights-of-way agreements, permits and licenses authorizing land use with numerous parties, including, private land owners, governmental entities, Native American tribes, rail carriers, public utilities and others. For more information, see our regulatory disclosure titled “Indigenous Protections.” Our ability to secure extensions of existing agreements, permits and licenses is essential to our continuing business operations, and securing additional rights-of-way will be critical to our ability to pursue expansion projects. We cannot provide any assurance that we will be able to maintain access to existing rights-of-way upon the expiration of the current grants, that all of the rights-of-way will be obtained in a timely fashion or that we will acquire new rights-of-way as needed.

Previous wording

As of December 31, 2024, approximately 9% of our workforce is covered by a number of collective bargaining agreements with various terms and dates of expiration. There can be no assurances that we will not experience a work stoppage in the future as a result of labor disagreements. Any work stoppage could, depending on the affected operations and the length of the work stoppage, have a material adverse effect on our business, financial position, results of operations or cash flows.

Current wording

As of December 31, 2025, approximately 6% of our workforce is covered by a number of collective bargaining agreements with various terms and dates of expiration. There can be no assurances that we will not experience a work stoppage in the future as a result of labor disagreements. Any work stoppage could, depending on the affected operations and the length of the work stoppage, have a material adverse effect on our business, financial position, results of operations or cash flows.

Previous wording

Our Gulf Coast facilities are strategically situated on prime real estate located in the Houston Ship Channel, which is in close proximity to both supply sources and demand sources. In recent years, the success of the Port of Houston has led to an increase in vessel traffic driven in part by the growing overseas demand for U.S. crude, gasoline, liquefied natural gas and petrochemicals and in part by the Port of Houston’s recent decision to accept large container vessels, which can restrict the flow of other cargo. Increasing congestion in the Port of Houston, which is currently the busiest port in the U.S. by waterborne tonnage and which has increased volumes in each of the last two years, could cause our customers or potential customers to divert their business to smaller ports in the Gulf of America, which could result in lower utilization of our facilities.

Current wording

Our Gulf Coast facilities are strategically situated on prime real estate located in the Houston Ship Channel, which is in close proximity to both supply sources and demand sources. In recent years, the success of the Port of Houston has led to an increase in vessel traffic driven in part by the growing overseas demand for U.S. crude, gasoline, liquefied natural gas and petrochemicals and in part by the Port of Houston’s expansions to accept large container vessels, which can restrict the flow of other cargo. Increasing congestion in the Port of Houston, which is currently the busiest port in the U.S. by waterborne tonnage and which has increased volumes in the last few years, could cause our customers or potential customers to divert their business to smaller ports in the Gulf of America, which could result in lower utilization of our facilities.

Previous wording

As of December 31, 2024, we had approximately $59.76 billion of consolidated debt, excluding the debt of our unconsolidated joint ventures. Our level of indebtedness affects our operations in several ways, including, among other things:

Current wording

As of December 31, 2025, we had approximately $68.33 billion of consolidated debt, excluding the debt of our unconsolidated joint ventures. Our level of indebtedness affects our operations in several ways, including, among other things:

Previous wording

In addition to our exposure to commodity prices, we have significant exposure to changes in interest rates, including the significant increases in prevailing interest rates as a result of changes in federal monetary and fiscal policy. Approximately $4.33 billion of our consolidated debt as of December 31, 2024 bears interest at variable interest rates and the remainder bears interest at fixed rates. To the extent that we have debt with floating interest rates, our results of operations, cash flows and financial condition could be materially adversely affected by increases in interest rates.

Current wording

In addition to our exposure to commodity prices, we have significant exposure to changes in interest rates, including the significant increases in prevailing interest rates as a result of changes in federal monetary and fiscal policy. Approximately $4.25 billion of our consolidated debt as of December 31, 2025 bears interest at variable interest rates and the remainder bears interest at fixed rates. To the extent that we have debt with floating interest rates, our results of operations, cash flows and financial condition could be materially adversely affected by increases in interest rates.

Previous wording

In August 2022, President Biden signed the IRA 2022, which contains hundreds of billions in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles and supporting infrastructure and carbon capture and sequestration, amongst other provisions. In addition, the IRA 2022 imposes the first-ever federal fee on the emission of GHGs through a methane emissions charge. The IRA 2022 amends the federal Clean Air Act to impose a fee on the emission of methane from sources required to report their GHG emissions to the EPA, including those sources in the onshore petroleum and natural gas production categories. The methane emissions charge started in calendar year 2024 at $900 per ton of methane, increased to $1,200 in 2025, and will be set at $1,500 for 2026 and each year after. Calculation of the fee is based on certain thresholds established in the IRA 2022. In addition, the multiple incentives offered for various clean energy industries referenced above could decrease demand for crude oil and natural gas, increase our compliance and operating costs and consequently adversely affect our business. We cannot predict if Congress may take action to repeal or revise the IRA 2022, including with respect to the methane emissions charge. Thus, at this time, it is currently uncertain which programs will be affected and what impact such changes may have.

Current wording

In August 2022, President Biden signed the Inflation Reduction Act of 2022 (“IRA 2022”), which contains hundreds of billions in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles and supporting infrastructure and carbon capture and sequestration, amongst other provisions. In addition, the IRA 2022 amended the Clean Air Act to impose a fee on the emission of methane from sources required to report their GHG emissions to the EPA, including those sources in the onshore petroleum and natural gas production categories. However, the One Big Beautiful Bill Act (“OBBBA”) amended the Clean Air Act to postpone the implementation of the fee until 2034. Although the OBBBA made various changes to the incentives created under the IRA 2022, including elimination of electric vehicle credits, if the incentives offered for various clean energy industries referenced above are pursued in the future, it could further accelerate the transition of the economy away from the use of fossil fuels and decrease demand for gasoline and diesel, increase our compliance and operating costs and consequently adversely affect our business.

Previous wording

Our crude oil and refined petroleum products pipelines face significant competition from other pipelines for large volume shipments. These operations also face competition from trucks for incremental and marginal volumes in the areas we serve. Further, our crude and refined product terminals compete with terminals owned by integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading operations.

Current wording

Our crude oil and refined petroleum products pipelines face significant competition from other pipelines for large volume shipments. These operations also face competition from trucks for incremental and marginal volumes in the areas we serve.

Previous wording

The hydraulic fracturing process has come under considerable scrutiny from sections of the public as well as environmental and other groups asserting that chemicals used in the hydraulic fracturing process could adversely affect drinking water supplies and may have other detrimental impacts on public health, safety, welfare and the environment. In addition, the water disposal process has come under scrutiny from sections of the public as well as environmental and other groups asserting that the operation of certain water disposal wells has caused increased seismic activity. Additionally, several candidates for political office in both state and federal government have announced intentions to impose greater restrictions on hydraulic fracturing or produced water disposal. For example, on January 27, 2021, the Biden Administration issued an executive order temporarily suspending the issuance of new authorizations, and suspending the issuance of new leases pending completion of a review of current practices, for oil and gas development on federal lands and waters (but not tribal lands that the federal government merely holds in trust). The suspension of these federal leasing activities prompted legal action by several states against the Biden Administration, resulting in issuance of a nationwide preliminary injunction by a federal district judge in Louisiana in June 2021, followed by a permanent injunction in August 2022, effectively halting implementation of the leasing suspension. Relatedly, the Department of the Interior (“DOI”) released its report on federal gas leasing and permitting practices in November 2021, referencing a number of recommendations and an overarching intent to modernize the federal oil and gas leasing program, including by adjusting royalty and bonding rates, prioritizing leasing in areas with known resource potential, and avoiding leasing that conflicts with recreation, wildlife habitat, conservation, and historical and cultural resources. In 2022, the recommendations in this report resulted in a reduction in the volume of onshore land held for lease and an increased royalty rate, and in 2024, the DOI finalized a rule to modernize the fiscal terms of the leasing program. Implementation of many of the recommendations in the DOI report will require Congressional action and we cannot predict the extent to which the recommendations may be implemented now or in the future, but restrictions on federal oil and gas activities have the potential to result in increased costs on us and our customers, decrease demand for our services on federal lands, and adversely impact our business. Separately, in March 2024, the Bureau of Land Management (“BLM”) finalized a rule that requires operators to limit flaring from well sites on federal lands, as well as allow the delay or denial of permits if the BLM finds that an operator’s methane waste minimization plan is insufficient. The rule was challenged by various states in the District Court for …

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Current wording

Relatedly, the Department of the Interior (“DOI”) released its report on federal gas leasing and permitting practices in November 2021, referencing a number of recommendations and an overarching intent to modernize the federal oil and gas leasing program, including by adjusting royalty and bonding rates, prioritizing leasing in areas with known resource potential, and avoiding leasing that conflicts with recreation, wildlife habitat, conservation, and historical and cultural resources. In 2022, the recommendations in this report resulted in a reduction in the volume of onshore land held for lease and an increased royalty rate, and in 2024, the DOI finalized a rule to modernize the fiscal terms of the leasing program. Implementation of many of the recommendations in the DOI report will require Congressional action and we cannot predict the extent to which the recommendations may be implemented now or in the future, but restrictions on federal oil and gas activities have the potential to result in increased costs on us and our customers, decrease demand for our services on federal lands, and adversely impact our business. Separately, in March 2024, the Bureau of Land Management (“BLM”) finalized a rule that requires operators to limit flaring from well sites on federal lands, as well as allow the delay or denial of permits if the BLM finds that an operator’s methane waste minimization plan is insufficient. The rule was challenged by various states in the District Court for the District of North Dakota and, in September 2024, the court ordered that the rule cannot be enforced against the plaintiff states pending the outcome of the litigation, and the BLM announced in December 2025 that it would delay enforcement of certain compliance deadlines under the rule through December 2026. Although the rule is currently being implemented against leases not covered by the order, the future of the rule is uncertain. Additionally, on January 28, 2026, the U.S. Department of Agriculture issued a final rule clarifying and streamlining the process for identifying and permitting federal lands managed by the U.S. Forest Service available for oil and gas leasing. In addition, the Colorado Energy and Carbon Management Commission (“CECMC”) (formerly the Colorado Oil and Gas Conservation Commission) adopted new rules to cover a variety of matters related to public health, safety, welfare, wildlife, and environmental resources, and has issued new rules regarding the cumulative impacts of oil and gas projects; most significantly, these rule changes establish more stringent setbacks (2,000-foot, instead of the prior 500-foot) on new oil and gas development and eliminate routine flaring and venting of natural gas at new or existing wells across the state, each subject to only limited exceptions. CECMC also adopted regulations in March 2025 requiring companies to reduce the amount of fresh water used for oil and gas operations and increase the use of recycled produced water.…

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Previous wording

The District Court scheduled a status conference for February 10, 2021 to discuss the impact of the Court of Appeals’ ruling on the pending motion for injunctive relief, as well as USACE’s expectations as to how it will proceed in light of the Court of Appeals’ recent vacatur ruling. USACE filed a motion for a continuance of the status conference until April 9, 2021, and this motion was approved by the District Court on February 9, 2021. Dakota Access and the Tribes filed their supplemental declarations on April 19, 2021 and April 26, 2021, respectively. On April 26, 2021, the District Court requested that USACE advise it by May 3, 2021 as to USACE’s current position, if it has one, with respect to the motion. On May 3, 2021, USACE advised the District Court that it had not changed its position with respect to its opposition to the Tribes’ motion for injunction. The USACE also advised the District Court that it expected that the EIS will be completed by March 2022. On May 21, 2021 the District Court denied the plaintiffs’ request for an injunction. The District Court further directed the parties to file a joint status report by June 11, 2021 concerning potential next steps in the litigation. On June 22, 2021, the District Court terminated the consolidated lawsuits and dismissed all remaining outstanding counts without prejudice. On January 20, 2022, the Standing Rock Sioux Tribe withdrew as a cooperating agency on the draft EIS, prompting the USACE to temporarily pause on the draft EIS. On September 8, 2023, the USACE published the Draft EIS. Comments to the Draft EIS were due on December 13, 2023. The USACE anticipates that a Final EIS will be issued in December 2025 and a Record of Decision will be issued in early 2026. For further information, see Note 11 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” in this annual report.

Current wording

The District Court scheduled a status conference for February 10, 2021 to discuss the impact of the Court of Appeals’ ruling on the pending motion for injunctive relief, as well as USACE’s expectations as to how it will proceed in light of the Court of Appeals’ recent vacatur ruling. USACE filed a motion for a continuance of the status conference until April 9, 2021, and this motion was approved by the District Court on February 9, 2021. Dakota Access and the Tribes filed their supplemental declarations on April 19, 2021 and April 26, 2021, respectively. On April 26, 2021, the District Court requested that USACE advise it by May 3, 2021 as to USACE’s current position, if it has one, with respect to the motion. On May 3, 2021, USACE advised the District Court that it had not changed its position with respect to its opposition to the Tribes’ motion for injunction. The USACE also advised the District Court that it expected that the EIS will be completed by March 2022. On May 21, 2021 the District Court denied the plaintiffs’ request for an injunction. The District Court further directed the parties to file a joint status report by June 11, 2021 concerning potential next steps in the litigation. On June 22, 2021, the District Court terminated the consolidated lawsuits and dismissed all remaining outstanding counts without prejudice. On January 20, 2022, the Standing

Previous wording

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, notices of upcoming debits. One party protested Panhandle’s revised refund report, and Panhandle submitted a response to the protest on July 24, 2024. By notice issued July 29, 2024, Panhandle’s rehearing…

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Current wording

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 D.C. Circuit, and the Michigan Public Service Commission also subsequently appealed these orders. On April 25, 2023, the D.C. Circuit 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 D.C. Circuit 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 D.C. Circuit 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, notices of upcoming debits. One party protested Panhandle’s revised refund report, and Panhandle submitted a response to the protest on July 24, 2024. By notice issued July 29, 2024, Panhandle’s rehearing request was deemed denied. In an ordered issued September 9, 2024, FERC addressed arguments raised on rehearing, modified t…

Excerpt shortened here; the source contains the full paragraph.

Previous wording

The FERC issued a Notice of Inquiry (“NOI”) on April 19, 2018 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 (“1999 Policy Statement”), 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. 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. On February 18, 2022, the FERC issued two new policy statements: (1) an Updated Policy Statement on the Certificate of New Interstate Natural Gas Facilities (“2022 Certificate Policy Statement”) and (2) a Policy Statement on the Consideration of 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 the 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.

Current wording

The FERC issued a Notice of Inquiry (“NOI”) on April 19, 2018 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 (“1999 Policy Statement”), 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. 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. On February 18, 2022, the FERC issued two new policy statements: (1) an Updated Policy Statement on the Certificate of New Interstate Natural Gas Facilities (“2022 Certificate Policy Statement”) and (2) a Policy Statement on the Consideration of 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 the 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. On September 12, 2025, the FERC issued an order withdrawing the draft 2022 Certificate Policy Statement and terminating the proceeding.

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. 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.

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 have 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 proposed a reduction to the currently effective index by one percent. On November 20, 2025, FERC withdrew the Supplemental NOPR and confirmed that the PPI-FG-0.78% index established in December 2020 will remain in place through June 30, 2026. On the same day, FERC approved limited relief for pipelines. Oil pipelines with index-based rates may recover applicable rate differences from March 1, 2022 to September 17, 2024 but only if such pipelines charged the maximum rate allowed under the applicable index ceiling during the relevant time period. Parties have since filed requests for clarification or rehearing, as well as court appeals, to determine whether pipelines may recover rate differences in other scenarios. Also on November 20, 2025, FERC issued a Notice of Proposed Rulemaking for the Five-Year Review of the Oil Pipeline Index proposing an index level of Producer Price Index for Finished Goods (PPI-FG) minus 1.42% for the period from July 1, 2026 to June 30, 2031.

Previous wording

Our midstream and intrastate transportation and storage operations are generally exempt from FERC regulation under the NGA, but FERC regulation still significantly affects our business and the market for our products. The rates, terms and conditions of service for the interstate services we provide in our intrastate gas pipelines and gas storage are subject to FERC regulation under Section 311 of the NGPA. Our pipeline systems of Enable Oklahoma Intrastate Transmission, LLC, Oasis Pipeline, LP, Houston Pipe Line Company LP, ETC Katy Pipeline, LLC, Energy Transfer Fuel, LP, Lobo Pipeline Company, LLC, Pelico Pipeline, LLC, Regency Intrastate Gas LP, Red Bluff Express Pipeline, LLC, Trans-Pecos Pipeline, LLC and Comanche Trail Pipeline, LLC provide such services. Under Section 311, rates charged for transportation and storage must be fair and equitable. Amounts collected that are determined to be in excess of fair and equitable rates are subject to refund with interest, and the terms and conditions of service, set forth in the pipeline’s statement of operating conditions, are subject to FERC review and approval. Should the FERC determine not to authorize rates equal to or greater than our costs of service, our cash flow would be negatively affected.

Current wording

Pipeline, LLC, Regency Intrastate Gas LP, Red Bluff Express Pipeline, LLC, Trans-Pecos Pipeline, LLC and Comanche Trail Pipeline, LLC provide such services. Under Section 311, rates charged for transportation and storage must be fair and equitable. Amounts collected that are determined to be in excess of fair and equitable rates are subject to refund with interest, and the terms and conditions of service, set forth in the pipeline’s statement of operating conditions, are subject to FERC review and approval. Should the FERC determine not to authorize rates equal to or greater than our costs of service, our cash flow would be negatively affected.

Previous wording

The NGPSA and HLPSA were amended by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”). Among other things, the 2011 Pipeline Safety Act increased the penalties for safety violations and directed the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, testing to confirm that the material strength of certain pipelines are above 30% of specified minimum yield strength, and operator verification of records confirming the MAOP of certain interstate natural gas transmission pipelines. PHMSA is required to adjust the maximum penalties it may impose for violations for inflation; these maximum civil penalties were most recently increased in December 2023 to $266,015 per violation per day, with a maximum of $2,660,135 for a related series of violations. Upon reauthorization of PHMSA, Congress directed the agency to move forward with several regulatory actions, including the “Pipeline Safety: Class Location Change Requirements” and the “Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines” proposed rulemaking, To that end, PHMSA issued the three final rules discussed above, significantly expanding reporting and safety requirements of operators of gas gathering pipelines, imposing safety regulations on approximately 400,000 miles of previously unregulated onshore gas gathering lines that, among other things, will impose criteria for inspection and repair of fugitive emissions, extend reporting requirements to all gas gathering operators, and apply a set of minimum safety requirements to certain gas gathering pipelines with large diameters and high operating pressures. The safety enhancement requirements and other provisions of Congressional mandates to PHMSA, as well as any implementation of PHMSA rules thereunder or any issuance or reinterpretation of guidance by PHMSA or any state agencies with respect thereto, could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could be significant and have a material adverse effect on our results of operations or financial condition.

Current wording

The NGPSA and HLPSA were amended by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”). Among other things, the 2011 Pipeline Safety Act increased the penalties for safety violations and directed the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, testing to confirm that the material strength of certain pipelines are above 30% of specified minimum yield strength, and operator verification of records confirming the MAOP of certain interstate natural gas transmission pipelines. PHMSA is required to adjust the maximum penalties it may impose for violations for inflation; these maximum civil penalties were most recently increased in December 2024 to $272,926 per violation per day, with a maximum of $2,729,245 for a related series of violations. Upon reauthorization of PHMSA, Congress directed the agency to move forward with several regulatory actions, including the “Pipeline Safety: Class Location Change Requirements” and the “Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines” proposed rulemaking, To that end, PHMSA issued the three final rules discussed above, significantly expanding reporting and safety requirements of operators of gas gathering pipelines, imposing safety regulations on approximately 400,000 miles of previously unregulated onshore gas gathering lines that, among other things, will impose criteria for inspection and repair of fugitive emissions, extend reporting requirements to all gas gathering operators, and apply a set of minimum safety requirements to certain gas gathering pipelines with large diameters and high operating pressures. In October 2025, members of Congress introduced the Pipeline Safety Act of 2025, which would reauthorize appropriations for PHMSA and modernize pipeline safety regulations.

Previous wording

Our business is subject to stringent federal, tribal, state, and local laws and regulations governing the discharge of materials into the environment, worker health and safety and protection of the environment. These laws and regulations may require the acquisition of permits for the construction and operation of our pipelines, plants and facilities, result in capital expenditures to manage, limit or prevent emissions, discharges or releases of various materials from our pipelines, plants and facilities, impose specific health and safety standards addressing worker protection, and impose substantial liabilities for pollution resulting from our construction and operations activities. Several governmental authorities, such as the EPA and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them and frequently mandate difficult and costly remediation measures and other actions. Failure to comply with these laws, regulations and permits may result in the assessment of significant administrative, civil and criminal penalties, the imposition of investigatory remedial and corrective action obligations, suspension and debarment from federal contracting opportunities, the occurrence of delays in permitting and completion of projects, and the issuance of injunctive relief. For example, following a state grand jury investigation and the filing of charges alleging criminal misconduct involving the construction and related activities of the Mariner East 2 pipeline (“Mariner 2”), in August 2022 we entered into a plea of no contest with the Pennsylvania Attorney General’s Office that requires us to pay fines to the Commonwealth, pay for independent evaluations of potential water quality impacts to residential water supplies and compensate any affected homeowners, and to also pay $10 million to support water quality improvement projects. Any additional requirements from the PADEP regarding Mariner 2 or other of our pipeline projects may result in delays in the completion of these projects. Subsequently, the EPA issued a Notice of Proposed Debarment (“NPD”) on October 28, 2022, arising from SPLP’s and ETC Northeast Pipeline, LLC’snolo contendere plea agreements and convictions for violations of Pennsylvania’s Clean Streams Law related to the Revolution and Mariner 2 pipelines. The following entities were proposed for debarment: (1) SPLP (pleading entity); (2) ETC Northeast Pipeline, LLC (pleading entity); (3) Energy Transfer LP; (4) SemGroup LLC; and (5) LE GP, LLC. The NPD presently prevents the named entities from pursuing or renewing Federal government contracts or Federal financial assistance agreements. While we are engaging with the EPA to attempt to resolve the matter, at this time there can be no assurance that the EPA will not finalize a debarment applicable to the named entities for a set period of time, or expand the debarment to other Energy Transfer affiliates. Currently, none of t…

Excerpt shortened here; the source contains the full paragraph.

Current wording

Our business is subject to stringent federal, tribal, state, and local laws and regulations governing the discharge of materials into the environment, worker health and safety and protection of the environment. These laws and regulations may require the acquisition of permits for the construction and operation of our pipelines, plants and facilities, result in capital expenditures to manage, limit or prevent emissions, discharges or releases of various materials from our pipelines, plants and facilities, impose specific health and safety standards addressing worker protection, and impose substantial liabilities for pollution resulting from our construction and operations activities. Several governmental authorities, such as the EPA and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them and frequently mandate difficult and costly remediation measures and other actions. Failure to comply with these laws, regulations and permits may result in the assessment of significant administrative, civil and criminal penalties, the imposition of investigatory remedial and corrective action obligations, suspension and debarment from federal contracting opportunities, the occurrence of delays in permitting and completion of projects, and the issuance of injunctive relief. For example, following a state grand jury investigation and the filing of charges alleging criminal misconduct involving the construction and related activities of the Mariner East 2 pipeline (“Mariner 2”), in August 2022 we entered into a plea of no contest with the Pennsylvania Attorney General’s Office that requires us to pay fines to the Commonwealth, pay for independent evaluations of potential water quality impacts to residential water supplies and compensate any affected homeowners, and to also pay $10 million to support water quality improvement projects.

Previous wording

Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes and GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. In the United States, no comprehensive climate change legislation has been implemented at the federal level to date. However, Canada has implemented a federal carbon pricing regime. In August 2022, the IRA 2022 was signed into law, which appropriates significant federal funding for renewable energy initiatives and amends the federal Clean Air Act to impose a first-time fee on the emission of methane from sources required to report their GHG emissions to the EPA. The IRA 2022 imposes a methane emissions charge on sources required to report their GHG emissions to the EPA, which started in calendar year 2024 at $900 per ton of methane, increased to $1,200 in 2025, and will be set at $1,500 for 2026 and each year after. Calculation of the fee is based on certain thresholds established in the IRA 2022. We cannot predict if Congress may take actions to repeal or revise the IRA 2022, including with respect to the methane emissions charge. Additionally, the EPA has adopted rules under authority of the Clean Air Act that, among other things, establish PSD construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are also potential major sources of certain principal, or criteria, pollutant emissions, which reviews could require securing PSD permits at covered facilities emitting GHGs and meeting “best available control technology” standards for those GHG emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, including, among others, onshore processing, transmission, storage and distribution facilities. In October 2015, the EPA amended and expanded the GHG reporting requirements to all segments of the oil and natural gas industry, including gathering and boosting facilities and blowdowns of natural gas transmission.

Current wording

Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes and GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. In the United States, no comprehensive climate change legislation has been implemented at the federal level to date. However, Canada has implemented a federal carbon pricing regime. Congress previously passed the IRA 2022 in August 2022, which, in addition to significant incentives for renewable energy and low carbon projects, also imposed a fee on methane emissions from certain sources in the oil and gas sector. In November 2024, the EPA finalized the methane emissions charge rule, although the rule was repealed in March 2025 by a Joint Resolution of Disapproval under the Congressional Review Act, and the EPA subsequently issued a final rule removing it from the Code of Federal Regulations. Additionally, OBBBA, passed by Congress in July 2025, delays implementation of the charge until 2034. We cannot predict if Congress may take further actions to repeal or revise the IRA 2022, including with respect to the methane emissions charge. Notwithstanding the EPA’s recent proposal to revoke the “Endangerment Finding” that underlies that majority of its GHG-related regulations, the EPA under previous administrations has adopted rules under authority of the Clean Air Act that, among other things, establish PSD construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are also potential major sources of certain principal, or criteria, pollutant emissions, which reviews could require securing PSD permits at covered facilities emitting GHGs and meeting “best available control technology” standards for those GHG emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, including, among others, onshore processing, transmission, storage and distribution facilities. We cannot predict whether the current Administration’s deregulatory actions will ultimately be successful or if future administrations may seek to re-impose similar requirements.

Previous wording

December 2023, the EPA issued a final rule that established OOOOb new source and OOOOc first-time existing source standards of performance for GHG and VOC emissions for crude oil and natural gas well sites, natural gas gathering and boosting compressor stations, natural gas processing plants, and transmission and storage facilities, Owners or operators of affected emission units or processes will have to comply with specific standards of performance that may include leak detection using optical gas imaging and subsequent repair requirements, reduction of emissions by 95% through capture and control systems, zero-emission requirements, operations and maintenance requirements, and so-called “green well” completion requirements. The December 2023 rule also revises requirements for fugitive emissions monitoring and repair as well as equipment leaks and the frequency of monitoring surveys, establishes a “super-emitter” response program to timely mitigate emissions events, triggering certain response and repair requirements, and provides additional options for the use of advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions. Fines and penalties for violations of these rules can be substantial. However, the EPA’s final rule is currently being challenged by 23 states and a coalition of industry groups in the U.S. Circuit Court of Appeals for the D.C. Circuit. Several states have also adopted, or are considering, adopting, regulations related to GHG emissions, some of which are more stringent than those implemented by the federal government. Methane emission standards imposed on the oil and gas sector could result in increased costs to our operations or those of our customers as well as result in delays or curtailment in such operations, which costs, delays or curtailment could adversely affect our business.

Current wording

Recent climate change regulations have focused on methane emissions from oil and gas operations. In June 2016, the EPA published NSPS, known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and VOC emissions, building on previous requirements for certain equipment-specific emissions control practices, requiring additional controls for pneumatic controllers and pumps as well as compressors, and imposing leak detection and repair requirements for natural gas compressor and booster stations. Additionally, in December 2023, the EPA issued a final rule that established OOOOb new source and OOOOc first-time existing source standards of performance for GHG and VOC emissions for crude oil and natural gas well sites, natural gas gathering and boosting compressor stations, natural gas processing plants, and transmission and storage facilities, owners or operators of affected emission units or processes will have to comply with specific standards of performance that may include leak detection using optical gas imaging and subsequent repair requirements, reduction of emissions by 95% through capture and control systems, zero-emission requirements, operations and maintenance requirements, and so-called “green well” completion requirements. The December 2023 rule also revises requirements for fugitive emissions monitoring and repair as well as equipment leaks and the frequency of monitoring surveys, establishes a “super-emitter” response program to timely mitigate emissions events, triggering certain response and repair requirements, and provides additional options for the use of advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions. Fines and penalties for violations of these rules can be substantial. However, the EPA’s final rule is currently being challenged by 23 states and a coalition of industry groups in the U.S. Circuit Court of Appeals for the D.C. Circuit, and we cannot predict the ultimate outcome. Further, in March 2025, the EPA announced plans to reconsider Subparts OOOOb and OOOOc and, in November 2025, the EPA finalized an interim final rule extending certain compliance deadlines for certain provisions provided in the rules. Several states have also adopted, or are considering, adopting, regulations related to GHG emissions, some of which are more stringent than those implemented by the federal government. Methane emission standards imposed on the oil and gas sector could result in increased costs to our operations or those of our customers as well as result in delays or curtailment in such operations, which costs, delays or curtailment could adversely affect our business.

Previous wording

At the international level, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France in signing the “Paris Agreement,” a treaty that requires member countries to submit individually-determined, non-binding GHG emission reduction goals every five years beginning in 2020. Although the United States withdrew from the Agreement under the Trump Administration, President Biden recommitted the United States in February 2021, and, in April 2021, announced a new, more rigorous nationally determined emissions reduction level of 50-52% reduction from 2005 levels in economy-wide net GHG emissions by 2030. However, in January 2025, President Trump signed an executive order once again withdrawing the United States from the Paris Agreement and from any other commitments made under the United Nations Framework Convention on Climate Change. Additionally, President Trump revoked any purported financial commitments made by the United States pursuant to the same. The full impact of these recent developments is uncertain at this time

Current wording

At the international level, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France in signing the “Paris Agreement,” a treaty that requires member countries to submit individually-determined, non-binding GHG emission reduction goals every five years beginning in 2020. However, in January 2025, President Trump signed an executive order withdrawing the United States from the Paris Agreement and from any other commitments made under the United Nations Framework Convention on Climate Change. Additionally, President Trump revoked any purported financial commitments made by the United States pursuant to the same. The full impact of these developments is uncertain at this time.

Previous wording

There are also increasing financing risks for fossil fuel energy companies, as various investors become increasingly concerned about the potential effects of climate change and may elect in the future to shift some or all of their investments into other sectors. Institutional lenders who provide financing for fossil fuel energy companies also have become more attentive to sustainable lending practices that favor “clean” power sources such as wind and solar photovoltaic, making those sources more attractive for investment, and some of them may elect not to provide funding for fossil fuel energy companies. Such efforts could make it more difficult for exploration and production companies and midstream companies, like us, to secure funding as well as negatively affect the cost of, and terms for, financings to fund growth projects or other aspects of our business. Additionally, in March 2024 the SEC released a final rule requiring climate disclosures. However, the future of the rule is uncertain at this time given that its implementation has been stayed pending the outcome of legal challenges. Moreover, the SEC may, under the current administration, seek to change or revoke the rule, though we cannot predict whether such action will occur or its timing.

Current wording

There are also increasing financing risks for fossil fuel energy companies, as various investors become increasingly concerned about the potential effects of climate change and may elect in the future to shift some or all of their investments into other sectors. Institutional lenders who provide financing for fossil fuel energy companies also have become more attentive to sustainable lending practices that favor “clean” power sources such as wind and solar photovoltaic, making those sources more attractive for investment, and some of them may elect not to provide funding for fossil fuel energy companies. Such efforts could make it more difficult for exploration and production companies and midstream companies, like us, to secure funding as well as negatively affect the cost of, and terms for, financings to fund growth projects or other aspects of our business. Additionally, in March 2024 the SEC released a final rule requiring climate disclosures. However, the future of the rule is uncertain at this time given that its implementation has been stayed pending the outcome of legal challenges, with such litigation held in abeyance until the SEC reconsiders, repeals, or otherwise modifies the rule. In March 2025, the SEC voted to end its defense of the rule, though no further action has been taken at this time to repeal the rule. Meanwhile, several states have also either adopted or are considering similar rules; however legal challenges have been brought related to such rules and a final decision remains pending at this time.

Previous wording

“global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict how the market for our products could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business.

Current wording

Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for our NGLs and natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we transport, and thus demand for our services. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict how the market for our products could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business.

Previous wording

Supply and demand for crude oil, natural gas and other hydrocarbon products we handle is dependent upon a variety of factors, many of which are beyond our control. These factors include, among others, the potential adoption of new government regulations, including those related to fuel conservation measures and climate change regulations, technological advances in fuel economy and energy generation devices. For example, legislative, regulatory or executive actions intended to reduce emissions of GHGs could increase the cost of consuming crude oil, natural gas and other hydrocarbon products, thereby potentially causing a reduction in the demand for such products. A broader transition to alternative fuels or energy sources, whether resulting from potential new government regulation, carbon taxes, governmental incentives and funding such as those provided in the IRA 2022, or consumer preferences could result in decreased demand for hydrocarbon products like crude oil, natural gas and NGLs that we handle. Any decrease in demand for these products could consequently reduce demand for our services and could have a negative effect on our business.

Current wording

Supply and demand for crude oil, natural gas and other hydrocarbon products we handle is dependent upon a variety of factors, many of which are beyond our control. These factors include, among others, the potential adoption of new government regulations, including those related to fuel conservation measures and climate change regulations, technological advances in fuel economy and energy generation devices. For example, legislative, regulatory or executive actions intended to reduce emissions of GHGs could increase the cost of consuming crude oil, natural gas and other hydrocarbon products, thereby potentially causing a reduction in the demand for such products. A broader transition to alternative fuels or energy sources, whether resulting from potential new government regulation, carbon taxes, governmental incentives and funding or consumer preferences could result in decreased demand for hydrocarbon products like crude oil, natural gas and NGLs that we handle. Any decrease in demand for these products could consequently reduce demand for our services and could have a negative effect on our business.