EPD Enterprise Products Partners L.P. - 10-K

ITEM 1A. RISK FACTORS.

Summary of Key Risk Factors

An investment in our common units or debt securities involves certain risks. If any of the following key risks were to occur, it could have a material adverse effect on our financial position, results of operations and cash flows, as well as our ability to maintain or increase distribution levels. In any such circumstance and others described below, the trading price of our securities could decline and you could lose part or all of your investment.

Risks Relating to Our Business

• The impact of a global public health crisis or foreign conflict on global oil and gas markets may have material adverse consequences for general economic, financial and business conditions, and could materially and adversely affect our business, financial condition, results of operations and liquidity and those of our customers, suppliers and other counterparties.

• Changes in price levels could negatively impact our revenue, our expenses, or both, which could adversely affect our business.

• Changes in U.S. trade policy and the impact of tariffs may have a material adverse effect on our business and results of operations.

• Changes in demand for and prices and production of hydrocarbon products could have a material adverse effect on our financial position, results of operations and cash flows.

• Our debt level may limit our future financial and operating flexibility.

• We may not be able to fully execute our growth strategy if we encounter illiquid capital markets or increased competition for investment opportunities.

• Our construction of new assets is subject to operational, regulatory, environmental, political, geopolitical, legal and economic risks, which may result in delays, increased costs or decreased cash flows.

• Several of our assets have been in service for many years and require significant expenditures to maintain them. As a result, an increase in future maintenance or repair costs or delays in completing necessary maintenance or repair activities could have a material adverse effect on our financial position, results of operations and cash flows.

• The inability to continue to access lands owned by third parties and governmental bodies could adversely affect our operations and have a material adverse effect on our financial position, results of operations and cash flows.

• Our growth strategy may adversely affect our results of operations if we do not successfully integrate and manage the businesses that we acquire or if we substantially increase our indebtedness and contingent liabilities to make acquisitions.

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• A natural disaster, catastrophe, terrorist attack or other extraordinary event could result in severe personal injury, property damage and environmental damage, which could curtail our operations and have a material adverse effect on our financial position, results of operations and cash flows.

• A cyber-attack on our information technology (“IT”) or operational technology (“OT”) systems could affect our business and assets, and have a material adverse effect on our financial position, results of operations and cash flows.

• Our business requires extensive credit risk management that may not be adequate to protect against customer nonpayment.

• The use of derivative financial instruments could result in material financial losses by us.

• Our risk management policies cannot eliminate all commodity price risks. In addition, any noncompliance with our risk management policies could result in significant financial losses.

• Federal, state or local regulatory measures (including those related to climate, environmental, health, safety and pipeline integrity matters) could have a material adverse effect on our financial position, results of operations and cash flows.

• The rates of our regulated assets are subject to review and possible adjustment by federal and state regulators, which could adversely affect our revenues.

• Our standalone operating cash flow is derived primarily from cash distributions we receive from EPO.

• Changes in management’s estimates and assumptions may have a material impact on our financial statements and financial performance.

Risks Relating to Our Partnership Structure

• We may not have sufficient operating cash flows to pay cash distributions at the current level following establishment of cash reserves and payments of fees and expenses.

• Our general partner and its affiliates have limited fiduciary responsibilities to, and conflicts of interest with respect to, our partnership, which may permit it to favor its own interests to your detriment.

• Unitholders have limited voting rights and are not entitled to elect our general partner or its directors. In addition, even if unitholders are dissatisfied, they cannot easily remove our general partner.

• Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

• Our general partner has a limited call right that may require common unitholders to sell their common units at an undesirable time or price.

• Our common unitholders may not have limited liability if a court finds that limited partner actions constitute control of our business.

• Unitholders may have a liability to repay distributions.

• Our general partner’s interest in us and the control of our general partner may be transferred to a third party without unitholder consent.

Tax Risks to Common Unitholders

• Our tax treatment depends on our status as a partnership for federal income tax purposes, which could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

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• A successful IRS contest of the federal income tax positions we take and certain valuation methodologies we adopt in determining a unitholder’s allocation of income, gain, loss and deductions may adversely impact the market for our common units and the cost of any IRS contest will reduce our cash available for distribution to unitholders.

• If the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case we would pay the taxes directly to the IRS and our cash available for distribution to our unitholders might be substantially reduced.

• Our unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

• Tax gains or losses on the disposition of our common units could be more or less than expected.

• We treat each purchaser of our common units as having the same tax benefits without regard to the common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.

• Our common unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of an investment in our common units.

Discussion of Key Risk Factors

The following discussion provides additional information regarding each of our key risk factors by category: Risks Relating to Our Business, Risks Relating to Our Partnership Structure and Tax Risks to Common Unitholders.

Risks Relating to Our Business

The impact of a global public health crisis or foreign conflict on global oil and gas markets may have material adverse consequences for general economic, financial and business conditions, and could materially and adversely affect our business, financial condition, results of operations and liquidity and those of our customers, suppliers and other counterparties.

Changes in the supply of and demand for hydrocarbon products impacts both the volume of products that we purchase and sell and the level of services that we provide to customers, which in turn impacts our financial position, results of operations and cash flows.

Global public health crises, such as the COVID-19 pandemic, and measures taken by governmental authorities, businesses and consumers in response to such crises, have previously adversely impacted the global and U.S. economy by disrupting global supply chains, reducing consumer activity, limiting travel and creating significant volatility and disruption of financial and commodity markets. A future global public health crisis could lead to similar disruptions and related economic repercussions. Any resumed period of economic slowdown or recession, or the return to a period of depressed demand or prices for hydrocarbons that we handle, could have significant adverse consequences on our financial condition and the financial condition of our customers, suppliers and other counterparties, and could diminish our liquidity and negatively affect the volumes of products handled by our pipelines and other facilities.

Similarly, foreign conflicts, including the ongoing war in Ukraine and related sanctions imposed on Russia and the ongoing conflicts in the Middle East may significantly disrupt supply chains for crude oil, natural gas and hydrocarbon products. Although we have not experienced any material adverse effect on our results of operations, financial condition or cash flows as a result of these conflicts as of the date of this report, we cannot predict how the continuation of these wars or other foreign conflicts will impact the level of future demand, effects on domestic pricing, and impacts on U.S. oil and gas production. Any economic slowdown or recession in major international markets, including as a result of such supply chain disruptions or sanctions, may also impact demand and depress the price for crude oil, natural gas or other products that we handle, which could have significant adverse consequences on our financial condition and the financial condition of our customers, suppliers and other counterparties, and could diminish our liquidity and negatively affect the volumes of products handled by our pipelines and other facilities.

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The potential impact of these types of events on our financial condition, results of operations and cash flows depends largely on developments outside our control, including the duration of and response to a public health crisis, the related impact on overall economic activity and the potential long-term impacts on demand for crude oil and other products, all of which cannot be predicted with certainty.

Changes in price levels could negatively impact our revenue, our expenses, or both, which could adversely affect our business.

The operation of our assets and the execution of capital projects require significant expenditures for labor, materials, property, equipment and services. As a result, such costs may increase during periods of general business inflation, including as a result of higher commodity prices, supply chain disruptions, tight labor markets or tariffs imposed on imports. Recent inflationary pressures affecting the general economy and the energy industry have increased our expenses and capital costs, and those costs may continue to increase. Similarly, new tariffs imposed on imports could increase materials cost. While the majority of long-term contracts for our services contain index-based changes and inflation adjustments, we may not be able to pass all of these increased costs to our customers in the form of higher fees for our services. In addition, we use the FERC’s PPI-based price indexing methodology to establish tariff rates in certain markets served by our pipelines. In periods of general price deflation, the ceiling level provided by the FERC’s PPI-based price indexing methodology could decrease, requiring us to reduce our index-based rates, even if the actual costs we incur to operate our assets increase. As such, our revenues and operating margins are impacted by changes in price levels. Prior to adjustments to our applicable rates, material cost increases may affect our operating margins, even if margins in subsequent periods may be normalized following applicable rate adjustments. Accordingly, increased costs during periods of general business inflation that are not passed through to customers or offset by other factors may have a material adverse effect on our financial position, results of operations and cash flows.

Changes in U.S. trade policy and the impact of tariffs may have a material adverse effect on our business and results of operations.

Our business and results of operations may be adversely affected by uncertainty and changes in U.S. trade policies, including tariffs, trade agreements or other trade restrictions imposed by the U.S. or other governments. These actions have caused uncertainty and volatility in financial markets, may result in retaliatory measures on U.S. goods and may adversely impact both the U.S. and global economies.

Our business requires access to steel and other materials to construct and maintain our pipelines. While our practice is to source steel through domestic producers in the U.S. in most instances, any imposition of or increase in tariffs on imports of steel or other materials, as well as corresponding price increases for such materials available domestically, could increase our construction costs and our costs to maintain our assets. To the extent that we are unable to pass all or any such cost increases on to our customers, such cost increases could adversely affect our returns on investment. Higher materials costs could also diminish our ability to develop new projects at acceptable returns, particularly during times of economic uncertainty, and limit our ability to pursue growth opportunities.

Tariffs or other trade restrictions may lead to continuing uncertainty and volatility in U.S. and global financial and economic conditions and commodity markets, inflation, and reduced demand for our and our customers’ products and services. Such conditions could have a material adverse impact on our business, results of operations and cash flows. Also, disruptions and volatility in the financial markets may lead to adverse changes in the availability, terms and cost of capital. Such adverse changes could increase our costs of capital and limit our access to external financing sources to fund acquisitions, capital projects, or refinancing of debt maturities on similar terms, which could in turn reduce our cash flows and limit our ability to pursue growth opportunities.

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Changes in demand for and prices and production of hydrocarbon products could have a material adverse effect on our financial position, results of operations and cash flows.

We operate predominantly in the midstream energy industry, which includes gathering, transporting, processing, fractionating and storing natural gas, NGLs, crude oil, petrochemical and refined products. As such, changes in the prices of hydrocarbon products and in the relative price levels among hydrocarbon products could have a material adverse effect on our financial position, results of operations and cash flows. Changes in prices may impact demand for hydrocarbon products, which in turn may impact production, demand and the volumes of products for which we provide services. In addition, decreases in demand may be caused by other factors, including prevailing economic conditions, reduced demand by consumers for the end products made with hydrocarbon products, increased competition, adverse weather conditions, public health emergencies, foreign conflicts, retaliatory tariffs on U.S. hydrocarbons by importing countries and government regulations affecting prices and production levels. We may also incur credit and price risk to the extent customers do not fulfill their obligations to us in connection with our marketing of natural gas, NGLs, propylene, refined products and/or crude oil and long-term take-or-pay agreements.

Crude oil and natural gas prices have been volatile in recent years. For example, crude oil prices (based on WTI as measured by the NYMEX) ranged from a high of $93.68 per barrel to a low of $55.27 per barrel in the three-year period ended December 31, 2025. For the period January 1, 2026 through January 31, 2026, WTI prices ranged from a high of $65.42 per barrel to a low of $55.99 per barrel. Natural gas prices (based on Henry Hub as measured by the NYMEX) ranged from a high of $5.29 per MMBtu to a low of $1.58 per MMBtu over the three-year period ended December 31, 2025. Henry Hub natural gas prices ranged from a high of $7.46 per MMBtu to a low of $3.10 per MMBtu from January 1, 2026 through January 31, 2026.

Generally, prices of hydrocarbon products are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of other uncontrollable factors, such as: (i) the level of domestic production and consumer product demand; (ii) the availability of imported crude oil and natural gas and actions taken by foreign crude oil and natural gas producing nations, including members of the Organization of Petroleum Exporting Countries (“OPEC”) and Russia (collectively, the “OPEC+” group); (iii) the availability of transportation systems with adequate capacity; (iv) the availability of competitive fuels; (v) fluctuating and seasonal demand for crude oil, natural gas, NGLs and other hydrocarbon products, including demand for NGL products by the petrochemical, refining and heating industries; (vi) the impact of conservation efforts; (vii) governmental regulation and taxation of production; (viii) reduced demand for hydrocarbons attributable to public health emergencies and (ix) prevailing economic conditions.

We are exposed to natural gas and NGL commodity price risks under certain of our natural gas processing and gathering and NGL fractionation contracts that provide for fees to be calculated based on a regional natural gas or NGL price index, or to be paid in-kind by taking title to natural gas or NGLs. A decrease in natural gas and NGL prices can result in lower margins from these contracts, which could have a material adverse effect on our financial position, results of operations and cash flows. Volatility in the prices of natural gas and NGLs can lead to ethane rejection, which results in a reduction in volumes available for transportation, fractionation, storage and marketing. Volatility in these commodity prices may also have an impact on many of our customers, which in turn could have a negative impact on their ability to fulfill their obligations to us.

The crude oil, natural gas and NGLs currently transported, gathered or processed at our facilities originate primarily from existing domestic resource basins, which naturally deplete over time. To offset this natural decline, our facilities need access to production from newly discovered properties. Many economic and business factors beyond our control can adversely affect the decision by producers to explore for and develop new reserves. These factors could include relatively low crude oil and natural gas prices, cost and availability of equipment and labor, regulatory changes, capital budget limitations, the lack of available capital or the probability of success in finding hydrocarbons. A decrease in exploration and development activities in the regions where our facilities and other energy logistic assets are located could result in a decrease in volumes handled by our assets, which could have a material adverse effect on our financial position, results of operations and cash flows.

For a discussion regarding our current outlook on industry fundamentals for 2026 , please read “ Management’s Discussion and Analysis of Financial Condition and Results of Operations – Current Outlook ” included under Part II, Item 7 of this annual report.

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We face competition from third parties in our midstream energy businesses.

Even if crude oil and natural gas reserves exist in the areas served by our assets, we may not be chosen by producers in these areas to gather, transport, process, fractionate, store or otherwise handle the hydrocarbons extracted. We compete with other companies, including producers of crude oil and natural gas, for any such production on the basis of many factors, including but not limited to geographic proximity to the production, costs of connection, available capacity, rates and access to markets.

Our NGL, refined products and marine transportation businesses may compete with other pipelines and marine transportation companies in the areas they serve. We also compete with railroads and third party trucking operations in certain of the areas we serve. Competitive pressures may adversely affect our tariff rates or volumes shipped. Also, substantial new construction of inland marine vessels could create an oversupply and intensify competition for our marine transportation business.

The crude oil gathering and marketing business can be characterized by intense competition for supplies of crude oil at the wellhead. A decline in domestic crude oil production could intensify this competition among gatherers and marketers. Our crude oil transportation business competes with common carriers and proprietary pipelines owned and operated by major oil companies, large independent pipeline companies, financial institutions with commodity trading platforms and other companies in the areas where such pipeline systems deliver crude oil.

In our natural gas gathering business, we encounter competition in obtaining contracts to gather natural gas supplies, particularly new supplies. Competition in natural gas gathering is based in large part on reputation, efficiency, system reliability, gathering system capacity and pricing arrangements. Our key competitors in the natural gas gathering business include independent gas gatherers and major integrated energy companies. Alternate gathering facilities are available to producers we serve, and those producers may also elect to construct proprietary gas gathering systems.

Both we and our competitors make significant investments in new energy infrastructure to meet anticipated market demand. The success of our projects depends on utilization of our assets. Demand for our new projects may change during construction, and our competitors may make additional investments or redeploy assets that compete with our projects and existing assets. If either our investments or construction by competitors in the markets we serve result in excess capacity, our facilities and assets could be underutilized, which could cause us to reduce rates for our services. A reduction in rates may result in lower returns on our investments and, as a result, lower the value of our assets.

A significant increase in competition in the midstream energy industry, including construction of new assets or redeployment of existing assets by our competitors, could have a material adverse effect on our financial position, results of operations and cash flows.

Our debt level may limit our future financial and operating flexibility.

As of December 31, 2025 , we had $32.4 billion in principal amount of consolidated senior long-term debt outstanding and $2.3 billion in principal amount of junior subordinated debt outstanding. The amount of our future debt could have significant effects on our operations, including, among other things:

• a substantial portion of our cash flow could be dedicated to the payment of principal and interest on our future debt and may not be available for other purposes, including the payment of distributions on our common units and for capital investments;

• credit rating agencies may take a negative view of the energy sector or our consolidated debt level;

• covenants contained in our existing and future credit and debt agreements will require us to continue to meet financial tests that may adversely affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;

• our ability to obtain additional financing, if necessary, for working capital, capital investments, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

• we may be at a competitive disadvantage relative to similar companies that have less debt; and

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• we may be more vulnerable to adverse economic and industry conditions as a result of our significant debt level.

Our public debt indentures currently do not limit the amount of future indebtedness that we can incur, assume or guarantee. Although our credit agreements restrict our ability to incur additional debt above certain levels, any debt we may incur in compliance with these restrictions may still be substantial. For information regarding our long-term debt, see Note 7 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Our credit agreements and each of the indentures related to our public debt instruments include traditional financial covenants and other restrictions. For example, we are prohibited from making distributions to our partners if such distributions would cause an event of default or otherwise violate a covenant under our credit agreements. A breach of any of these restrictions by us could permit our lenders or noteholders, as applicable, to declare all amounts outstanding under these debt agreements to be immediately due and payable and, in the case of our credit agreements, terminate all commitments to extend further credit.

Our ability to access capital markets to raise capital on favorable terms could be affected by our debt level, when such debt matures, and by prevailing market conditions. Moreover, if the rating agencies were to downgrade the energy sector or our credit ratings, we could experience an increase in our borrowing costs, difficulty assessing capital markets and/or a reduction in the market price of our securities. Such a development could adversely affect our ability to obtain financing for working capital, capital investments or acquisitions, or to refinance existing indebtedness. If we are unable to access the capital markets on favorable terms in the future, we might be forced to seek extensions for some of our short-term debt obligations or to refinance some of our debt obligations through bank credit, as opposed to long-term public debt securities or equity securities. The price and terms upon which we might receive such extensions or additional bank credit, if at all, could be more onerous than those contained in existing debt agreements. Any such arrangements could, in turn, increase the risk that our leverage may adversely affect our future financial and operating flexibility and thereby impact our ability to pay cash distributions at expected levels.

We may not be able to fully execute our growth strategy if we encounter illiquid capital markets or increased competition for investment opportunities.

Our growth strategy contemplates the development and acquisition of a wide range of midstream and other energy infrastructure assets while maintaining a strong balance sheet. This strategy includes constructing and acquiring additional assets and businesses that enhance our ability to compete effectively and to diversify our asset portfolio, thereby providing us with more stable cash flows. We consider and pursue potential joint ventures, acquisitions, standalone projects and other transactions that we believe may present opportunities to expand our business, increase our market position and realize operational synergies.

We will require substantial new capital to finance the future development and acquisition of assets and businesses. For example, our capital investments for 2025 reflected $5.6 billion of cash payments for capital projects, acquisitions and other investments. Based on information currently available, we expect our total organic capital investments for 2026, net of contributions from noncontrolling interests, to approximate $3.1 billion to $3.5 billion, which includes organic growth capital investments of $2.5 billion to $2.9 billion and sustaining capital expenditures of $580 million. Any limitations on our access to capital may impair our ability to execute this growth strategy. If our cost of debt or equity capital becomes too expensive, our ability to develop or acquire accretive assets will be limited. We also may not be able to raise the necessary funds on satisfactory terms, if at all.

Any sustained tightening of the credit markets may have a material adverse effect on us by, among other things, decreasing our ability to finance growth capital projects or business acquisitions on favorable terms and by the imposition of increasingly restrictive borrowing covenants. In addition, the distribution yields of any new equity we may issue may be higher than historical levels, making additional equity issuances more expensive. Accordingly, increased costs of equity and debt will make returns on capital expenditures with proceeds from such capital less accretive on a per unit basis.

We also may compete with third parties in the acquisition of energy infrastructure assets that complement our existing asset base. Increased competition for a limited pool of assets could result in our losing to other bidders more often than in the past or acquiring assets at less attractive prices. Either occurrence could limit our ability to fully execute our growth strategy. Our inability to execute our growth strategy may materially adversely affect our ability to maintain or pay higher cash distributions in the future.

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Our actual construction, development and acquisition costs could materially exceed forecasted amounts.

We have announced and are engaged in multiple significant construction projects involving existing and new assets for which we have expended or will expend significant capital. These projects entail significant logistical, technological and staffing challenges. We may not be able to complete our projects at the costs we estimated at the time of each project’s initiation or that we currently estimate. Similarly, force majeure events such as hurricanes along the U.S. Gulf Coast may cause delays, shortages of skilled labor and additional expenses for these construction and development projects.

If capital investments materially exceed expected amounts, then our future cash flows could be reduced, which, in turn, could reduce the amount of cash we expect to have available for distribution. In addition, a material increase in project costs could result in decreased overall profitability of the newly constructed asset once it is placed into service.

Our construction of new assets is subject to operational, regulatory, environmental, political, geopolitical, legal and economic risks, which may result in delays, increased costs or decreased cash flows.

One of the ways we intend to grow our business is through the construction of new midstream energy infrastructure assets. The construction of new assets involves numerous operational, regulatory, environmental, political, geopolitical, legal and economic risks beyond our control and may require the expenditure of significant amounts of capital. These potential risks include, among other things, the following:

• we may be unable to complete construction projects on schedule or at the budgeted cost due to the unavailability of required construction personnel, the unavailability of or delays in obtaining necessary materials as a result of supply chain disruptions (including those caused by public health emergency restrictions or geopolitical events, such as the Russian invasion of Ukraine or ongoing conflicts in the Middle East), accidents, weather conditions or an inability to obtain necessary permits;

• we will not receive any material increase in operating cash flows until the project is completed, even though we may have expended considerable funds during the construction phase, which may be prolonged;

• we may construct facilities to capture anticipated future production growth in a region in which such growth does not materialize;

• since we are not engaged in the exploration for and development of crude oil or natural gas reserves, we may not have access to third-party estimates of reserves in an area prior to our constructing facilities in the area. As a result, we may construct facilities in an area where the reserves are materially lower than we anticipate;

• in those situations where we do rely on third-party reserve estimates in making a decision to construct assets, these estimates may prove inaccurate;

• the completion or success of our construction project may depend on the completion of a third-party construction project (e.g., a downstream crude oil refinery expansion or construction of a new petrochemical facility) that we do not control and that may be subject to numerous of its own potential risks, delays and complexities; and

• we may be unable to obtain rights-of-way to construct additional pipelines or the cost to do so may be uneconomical.

A materialization of any of these risks could adversely affect our ability to achieve growth in the level of our cash flows or realize benefits from expansion opportunities or construction projects, which could impact the level of cash distributions we pay to our unitholders.

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Several of our assets have been in service for many years and require significant expenditures to maintain them. As a result, an increase in future maintenance or repair costs or delays in completing necessary maintenance or repair activities could have a material adverse effect on our financial position, results of operations and cash flows.

Our pipelines, terminals and storage assets are generally long-lived assets, and many of them have been in service for many years. The age and condition of our assets could result in increased maintenance or repair expenditures in the future. Additionally, we may be unable to complete maintenance or repairs due to the unavailability of necessary materials as a result of supply chain disruptions (including those caused by public health emergency restrictions or geopolitical events, such as the Russian invasion of Ukraine or ongoing conflicts in the Middle East), which may result in the suspension of operations of the impacted assets until such activities can be completed. Any significant increase in these expenditures or delays in completing necessary maintenance or repairs could adversely affect our results of operations, financial position or cash flows, as well as our ability to make cash distributions to our unitholders.

The inability to continue to access lands owned by third parties and governmental bodies could adversely affect our operations and have a material adverse effect on our financial position, results of operations and cash flows.

Our ability to operate our pipeline systems on certain lands owned by third parties will depend on our 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. 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 all 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.

In particular, various federal agencies within the U.S. Department of the Interior, particularly the Bureau of Indian Affairs, Bureau of Land Management, and the Office of Natural Resources Revenue, along with each Native American tribe, promulgate and enforce regulations pertaining to natural gas and oil operations on Native American tribal lands. These regulations and approval requirements relate to such matters as drilling and production requirements and environmental standards. In addition, each Native American tribe is a sovereign nation having the right to enforce laws and regulations and to grant approvals independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees, requirements to employ Native American tribal members and other conditions that apply to operators and contractors conducting operations on Native American tribal lands. One or more of these factors may increase our cost of doing business on Native American tribal lands and impact the viability of, or prevent or delay our ability to conduct our operations on such lands.

Furthermore, whether we have the power of eminent domain for our pipelines varies from state to state, depending upon the type of pipeline, the laws of the particular state and the ownership of the land to which we seek access. When we exercise eminent domain rights or negotiate private agreements, we must compensate landowners for the use of their property and, in eminent domain actions, such compensation may be determined by a court. The inability to exercise the power of eminent domain could negatively affect our business if we were to lose the right to use or occupy the property on which our pipelines are located.

We may face opposition to the construction and operation of our pipelines and facilities from various groups.

We may face opposition to the operation of our pipelines and facilities from environmental groups, landowners, tribal groups, local groups and other advocates. Such opposition could take many forms, including organized protests, attempts to block or sabotage our construction activities and operations, intervention in regulatory or administrative proceedings involving our assets, or lawsuits or other actions designed to prevent, disrupt or delay the operation of our assets and business. For example, repairing our pipelines often involves securing consent from individual landowners to access their property; one or more landowners may resist our efforts to make needed repairs, which could lead to an interruption in the operation of the affected pipeline or facility for a period of time that is significantly longer than would have otherwise been the case. In addition, acts of sabotage or eco-terrorism could cause significant damage or injury to people, property or the environment or lead to extended interruptions of our operations. Any such event that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying distributions to our partners and, accordingly, adversely affect our financial condition and the market price of our securities.

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Our growth strategy may adversely affect our results of operations if we do not successfully integrate and manage the businesses that we acquire or if we substantially increase our indebtedness and contingent liabilities to make acquisitions.

Our growth strategy includes making accretive acquisitions. From time to time, we evaluate and acquire additional assets and businesses that we believe complement our existing operations. We may be unable to successfully integrate and manage the businesses we acquire in the future. We may incur substantial expenses or encounter delays or other problems in connection with our growth strategy that could have a material adverse effect on our financial position, results of operations and cash flows. Moreover, acquisitions and business expansions involve numerous risks, such as:

• difficulties in the assimilation of the operations, technologies, services and products of the acquired assets or businesses;

• establishing the internal controls and procedures we are required to maintain under the Sarbanes-Oxley Act of 2002;

• managing relationships with new joint venture partners with whom we have not previously partnered;

• experiencing unforeseen operational interruptions or the loss of key employees, customers or suppliers;

• inefficiencies and complexities that can arise because of unfamiliarity with new assets and the businesses associated with them, including with their markets; and

• diversion of the attention of management and other personnel from day-to-day business to the development or acquisition of new businesses and other business opportunities.

If consummated, any acquisition or investment would also likely result in the incurrence of indebtedness and contingent liabilities and an increase in interest expense and depreciation, amortization and accretion expenses. As a result, our capitalization and results of operations may change significantly following a material acquisition. A substantial increase in our indebtedness and contingent liabilities could have a material adverse effect on our financial position, results of operations and cash flows. In addition, any anticipated benefits of a material acquisition, such as expected cost savings or other synergies, may not be fully realized, if at all.

Acquisitions that appear to increase our operating cash flows may nevertheless reduce our operating cash flows on a per unit basis.

Even if we make acquisitions that we believe will increase our operating cash flows, these acquisitions may ultimately result in a reduction of operating cash flow on a per unit basis, such as if our assumptions regarding a newly acquired asset or business did not materialize or unforeseen risks occurred. As a result, an acquisition initially deemed accretive based on information available at the time could turn out not to be. Examples of risks that could cause an acquisition to ultimately not be accretive include our inability to achieve anticipated operating and financial projections or to integrate an acquired business successfully, the assumption of unknown liabilities for which we become liable, and the loss of key employees or key customers. If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and our unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will in making such decisions. As a result of the risks noted above, we may not realize the full benefits we expect from a material acquisition, which could have a material adverse effect on our financial position, results of operations and cash flows.

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A natural disaster, catastrophe, terrorist attack or other extraordinary event could result in severe personal injury, property damage and environmental damage, which could curtail our operations and have a material adverse effect on our financial position, results of operations and cash flows.

Some of our operations involve risks of personal injury, property damage and environmental damage, which could curtail our operations and otherwise materially adversely affect our cash flow. For example, natural gas facilities operate at high pressures, sometimes in excess of 1,100 pounds per square inch. In addition, our marine transportation business is subject to additional risks, including the possibility of marine accidents and spill events. From time to time, our octane enhancement facility may produce MTBE for export, which could expose us to additional risks from spill events. Virtually all of our operations are exposed to potential natural disasters and severe weather, including hurricanes, tornadoes, storms, extreme winter events, floods and/or earthquakes. The location of our assets and our customers’ assets in the U.S. Gulf Coast region makes them particularly vulnerable to hurricane or tropical storm risk. In addition, terrorists may target our physical facilities and computer hackers may attack our electronic systems.

If one or more facilities or electronic systems that we own or that deliver products to us or that supply our facilities are damaged by severe weather or any other disaster, accident, catastrophe, terrorist attack or other extraordinary event, our operations could be significantly interrupted. These interruptions could involve significant damage to people, property or the environment, and repairs could take from a week or less for a minor incident to six months or more for a major interruption. Additionally, some of the storage contracts that we are a party to obligate us to indemnify our customers for any damage or injury occurring during the period in which the customers’ product is in our possession. Any event that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying distributions and, accordingly, adversely affect the market price of our common units.

We believe that EPCO maintains adequate insurance coverage on our behalf; however, insurance will not cover all types of interruptions that might occur, will not cover amounts up to applicable deductibles and will not cover all risks associated with the nature and extent of our operations. As a result of market conditions, premiums and deductibles for certain types of insurance (e.g., general liability policies) can increase substantially, and in some instances, such insurance may become unavailable or available only for reduced amounts of coverage.

In the future, circumstances may arise whereby EPCO may not be able to renew existing insurance policies on our behalf or procure other desirable insurance on commercially reasonable terms, if at all. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position, results of operations and cash flows. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.

A cyber-attack on our IT or OT systems could affect our business and assets, and have a material adverse effect on our financial position, results of operations and cash flows.

We rely on our IT and OT systems, as well as systems of third-party vendors, to conduct our business. These systems include information used to operate our assets, as well as cloud-based services. These systems are subject to possible security breaches and cyber-attacks.

Cyber-attacks are becoming more sophisticated, and U.S. government warnings have indicated that infrastructure assets, including pipelines, may be specifically targeted by certain groups. These attacks include, without limitation, malicious software, ransomware, attempts to gain unauthorized access to data, and other electronic security breaches. These attacks, which could increase as a result of geopolitical events (including the Russian invasion of Ukraine or ongoing conflicts in the Middle East), may be perpetrated by state-sponsored groups, “hacktivists”, criminal organizations or private individuals (including employee malfeasance). These cybersecurity risks include cyber-attacks on both us and third parties who provide material services to us. In addition to disrupting operations, cyber security breaches could also affect our ability to operate or control our facilities, render data or systems unusable, or result in the theft of sensitive, confidential or customer information. These events could also damage our reputation, and result in losses from remedial actions, loss of business or potential liability to third parties.

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We do not carry insurance specifically for cybersecurity events; however, certain of our insurance policies may allow for coverage of associated damages resulting from such events. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position, results of operations and cash flows. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.

Failure of our critical IT or OT systems could have an adverse impact on our business, financial condition, results of operations and cash flows, as well as our ability to pay cash distributions.

We rely on IT and OT systems to operate our assets and manage our businesses. We depend on these systems to process, transmit and store electronic information, including financial records and personally identifiable information such as employee, customer, investor and payroll data, and to manage or support a variety of business processes, including our supply chain, pipeline and storage operations, gathering and processing operations, financial transactions, banking and numerous other processes and transactions. Some of these IT and OT systems are proprietary and custom designed for our business, while others are based upon or reside on commercially available technologies.

We have policies and procedures in place designed to protect our critical systems. Our cybersecurity approach is strategically layered with people, technology and processes such as disaster recovery, incident response and business continuity. However, the risk of critical systems failing due to an unforeseen major disruption cannot be eliminated.

Failures of these IT or OT systems, whether due to power failures, a cybersecurity event or other reason, could result in a breach of critical operational or financial controls and lead to unanticipated costs and a disruption of our operations, commercial activities or financial processes. Such failures could adversely affect our results of operations, financial position or cash flow, as well as our ability to pay cash distributions in a timely manner. State and federal cybersecurity legislation could also impose new requirements on us, which could increase our cost of doing business.

Our business requires extensive credit risk management that may not be adequate to protect against customer nonpayment.

We may incur credit risk to the extent customers do not fulfill their obligations to us in connection with our marketing of natural gas, NGLs, crude oil, petrochemicals and refined products and long-term contracts with minimum volume commitments or fixed demand charges. Risks of nonpayment and nonperformance by customers are a major consideration in our businesses, and our credit procedures and policies may not be adequate to sufficiently eliminate customer credit risk. Further, adverse economic conditions in our industry may increase the risk of nonpayment and nonperformance by customers, particularly customers that have sub-investment grade credit ratings or small-scale companies. We manage our exposure to credit risk through customer diversification, credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions may utilize letters of credit, prepayments, net out agreements and guarantees. However, these procedures and policies do not fully eliminate customer credit risk.

The primary markets for our services are the Gulf Coast, Southwest, Rocky Mountains, Northeast and Midwest regions of the U.S. We have a concentration of trade receivable balances due from domestic and international major integrated oil and gas companies, independent oil and gas companies and other pipelines and wholesalers operating in these markets. These concentrations of market areas may affect our overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors.

See Note 2 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report for information regarding our allowance for credit losses.

The use of derivative financial instruments could result in material financial losses by us.

Historically, we have sought to limit a portion of the adverse effects resulting from changes in energy commodity prices and interest rates by using derivative instruments. Derivative instruments typically include futures, forward contracts, swaps, options and other instruments with similar characteristics. Substantially all of our derivatives are used for non-trading activities.

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To the extent that we hedge our commodity price and interest rate exposures, we will forego the benefits we would otherwise experience if commodity prices or interest rates were to change in our favor. In addition, hedging activities can result in losses that might be material to our financial condition, results of operations and cash flows. Such losses could occur under various circumstances, including those situations where a counterparty does not perform its obligations under a hedge arrangement, the hedge is not effective in mitigating the underlying risk, or our risk management policies and procedures are not followed. Adverse economic conditions (e.g., a significant decline in energy commodity prices that negatively impact the cash flows of oil and gas producers) increase the risk of nonpayment or performance by our hedging counterparties.

See Part II, Item 7A of this annual report and Note 14 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report for a discussion of our derivative instruments and related hedging activities.

Our risk management policies cannot eliminate all commodity price risks. In addition, any noncompliance with our risk management policies could result in significant financial losses.

When engaged in marketing activities, it is our policy to maintain physical commodity positions that are substantially balanced with respect to price risks between purchases, on the one hand, and sales or future delivery obligations, on the other hand. Through these transactions, we seek to earn a margin for the commodity purchased by selling the commodity for physical delivery to third party users, such as producers, wholesalers, local distributors, independent refiners, marketing companies or major integrated oil and gas companies. These policies and practices cannot, however, eliminate all price risks. For example, any event that disrupts our anticipated physical supply could expose us to risk of loss resulting from price changes if we are required to obtain alternative supplies to cover our sales transactions. We are also exposed to basis risks when a commodity is purchased against one pricing index and sold against a different index. Moreover, we are exposed to some risks that are not hedged, including price risks on product we own, such as pipeline linefill, which must be maintained in order to facilitate transportation of the commodity in our pipelines. In addition, our marketing operations involve the risk of non-compliance with our risk management policies. We cannot assure you that our processes and procedures will detect and prevent all violations of our risk management policies, particularly if deception or other intentional misconduct is involved. If we were to incur a material loss related to commodity price risks, including non-compliance with our risk management policies, it could have a material adverse effect on our financial position, results of operations and cash flows.

Our variable-rate debt, including those fixed-rate debt obligations that may be converted to variable-rate through the use of interest rate swaps, make us vulnerable to increases in interest rates, which could have a material adverse effect on our financial position, results of operation and cash flows.

At December 31, 2025 , we had $34.1 billion in principal amount of consolidated fixed-rate debt outstanding, including current maturities thereof. Additionally, at December 31, 2025 , we had $582 million of variable-rate debt.

After increasing benchmark interest rates in 2022 and 2023, the Board of Governors of the Federal Reserve System lowered benchmark interest rates during 2024 and 2025, and such rates may fall further in 2026. However, should interest rates increase significantly, the amount of cash required to service our debt (including any future refinancing of our fixed-rate debt instruments) would increase. Additionally, from time to time, we may enter into interest rate swap arrangements, which could increase our exposure to variable interest rates. As a result, significant increases in interest rates could have a material adverse effect on our financial position, results of operations and cash flows.

An increase in interest rates may also cause a corresponding decline in demand for equity securities in general, and in particular, for yield-based equity securities such as our common units. A reduction in demand for our common units may cause their trading price to decline.

Our pipeline integrity program as well as compliance with pipeline safety laws and regulations may impose significant costs and liabilities on us.

If we were to incur material costs in connection with our pipeline integrity program or pipeline safety laws and regulations, those costs could have a material adverse effect on our financial condition, results of operations and cash flows.

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The DOT requires pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in HCAs. The majority of the costs to comply with this integrity management rule are associated with pipeline integrity testing and any repairs found to be necessary as a result of such testing. Changes such as advances in pipeline inspection tools, identification of additional threats to a pipeline’s integrity and changes to the amount of pipe determined to be located in HCAs can have a significant impact on the costs to perform integrity testing and repairs. We will continue our pipeline integrity testing programs to assess and maintain the integrity of our pipelines. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.

In total, our pipeline integrity costs for the years ended December 31, 2025, 2024 and 2023 were $144 million, $126 million and $104 million, respectively. Of these annual totals, we charged $66 million, $70 million and $55 million to operating costs and expenses during the years ended December 31, 2025, 2024 and 2023 , respectively. The remaining annual pipeline integrity costs were capitalized and treated as sustaining capital projects. We expect the cost of our pipeline integrity program, regardless of whether such costs are capitalized or expensed, to approximate $150 million for 2026 .

For additional information regarding the pipeline safety regulations, see “ Regulatory Matters – Environmental, Safety and Conservation – Pipeline Safety ” included under Part I, Items 1 and 2 of this annual report.

Environmental, health and safety costs and liabilities, and changing environmental, health and safety regulation, could have a material adverse effect on our financial position, results of operations and cash flows.

Our operations are subject to various environmental, health and safety requirements and potential liabilities under extensive federal, state and local laws and regulations. Further, we cannot ensure that existing environmental, health and safety regulations will not be revised or that new regulations will not be adopted or become applicable to us. Governmental authorities have the power to enforce compliance with applicable regulations and permits and to subject violators to civil and criminal penalties, including substantial fines, injunctions or both. Certain environmental laws, including CERCLA and analogous state laws and regulations, may impose strict, joint and several liability for costs required to clean-up and restore sites where hazardous substances or hydrocarbons have been disposed or otherwise released. Moreover, third parties, including neighboring landowners, may also have the right to pursue legal actions to enforce compliance or to recover for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Failure to comply with these requirements may expose us to fines, penalties and/or interruptions in our operations that could have a material adverse effect on our financial position, results of operations and cash flows.

In addition, future environmental, health and safety law developments, such as stricter laws, regulations, permits or enforcement policies, could significantly increase some costs of our operations. Areas of potential future environmental, health and safety law developments include the following items.

Climate Change . Responding to reports regarding global warming and climate change matters, the U.S. Congress from time to time has considered and adopted legislation intended to reduce emissions of greenhouse gases or require fees related to greenhouse gas emissions or carbon taxes. In addition, certain states, including states in which our facilities or operations are located, have, individually or in regional cooperation, taken or proposed measures to reduce emissions of greenhouse gases. Various policies and approaches, including establishing a cap on emissions, requiring efficiency measures, or providing incentives for emissions reduction, use of renewable energy sources, or use of replacement fuels with lower carbon content, have been considered and could result in additional actions involving greenhouse gases.

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The adoption and implementation of any federal, state or local regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur significant costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the crude oil, natural gas or other hydrocarbon products that we transport, store or otherwise handle in connection with our midstream services. The potential increase in our operating costs could include costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize greenhouse gas emissions (whether emitted by our operations or associated with fuel that we supply into the markets), pay taxes or fees related to greenhouse gas emissions, and administer and manage a greenhouse gas emissions program. We may not be able to recover such increased costs through customer prices or rates, which may limit our access to, or otherwise cause us to reduce our participation in, certain market activities. In addition, changes in regulatory policies that result in a reduction in the demand for hydrocarbon products that are deemed to contribute to greenhouse gases, or restrictions on their use, may reduce volumes available to us for processing, transportation, marketing and storage. These developments could have a material adverse effect on our financial position, results of operations and cash flows.

In addition, numerous countries around the world have adopted, or are considering adopting laws or regulations to reduce greenhouse gas emissions. It is not possible to know how quickly renewable energy technologies may advance, but if significant additional legislation and regulation were enacted, the increased use of renewable energy could ultimately reduce future demand for hydrocarbons. These developments could have a material adverse effect on our financial position, results of operations and cash flows.

We are in the process of exploring and developing opportunities to capitalize on changes in law and market dynamics relating to greenhouse gas emissions, such as projects related to carbon capture and sequestration and the production and use of hydrogen. These types of projects pose a variety of risks to us, including: (i) we could overestimate the timing or extent of market demand for such services, and therefore divert capital from more profitable opportunities; (ii) we could rely on temporary subsidies or similar market distortions for an increasing portion of our revenue, which reliance could reduce the long-term economic sustainability of our associated operations; (iii) counterparties to projects considered may not have the same credit profiles as many of our existing customers; and (iv) such projects may involve shorter-term contracts than employed with traditional opportunities, thereby involving greater risk to us.

In addition to direct regulation of emissions as described above, there has been an expansion of requirements and incentives relating to reporting greenhouse gas emissions and other climate change-related matters. We currently file greenhouse gas emission reports for certain facilities and equipment subject to EPA reporting regulations. However, we do not publicly report our total direct or indirect greenhouse gas emissions, and it may not be feasible to quantify all types of emissions without relying on estimates. If we are required to determine comprehensively and report publicly our full direct and indirect greenhouse gas emissions, or certain other climate change-related matters, then such determinations and disclosures could entail significant costs and administrative burdens and be a source of potential liability and negative publicity. Alternatively, if we do not make such determinations or public disclosures, we may be prevented from operating or supplying products into certain markets or dealing with certain counterparties.

Hydraulic Fracturing. Substantially all of our producer customers employ hydraulic fracturing techniques (commonly referred to as “fracking”) to stimulate natural gas and crude oil production from unconventional geological formations (including shale formations), which entails the injection of pressurized fracturing fluids (consisting of water, sand and certain chemicals) into a well bore. The U.S. federal government, and some states and localities, have adopted, and others are considering adopting, regulations or ordinances that could restrict hydraulic fracturing in certain circumstances, or that would impose higher taxes, fees or royalties on such activities. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to crude oil and natural gas drilling activities using hydraulic fracturing techniques, including increased litigation. Additional legislation or regulation could also lead to operational delays and/or increased operating costs in the production of crude oil and natural gas (including natural gas produced from shale plays like the Permian, Eagle Ford, Haynesville, Barnett, Marcellus and Utica Shales) incurred by our customers or could make it more difficult to perform hydraulic fracturing. If these legislative and regulatory initiatives cause a material decrease in the drilling of new wells and related servicing activities, it may affect the volume of hydrocarbon products available to our midstream businesses and have a material adverse effect on our financial position, results of operations and cash flows.

See “ Regulatory Matters ” under Part I, Items 1 and 2 of this annual report for more information and specific disclosures relating to environmental, health and safety laws and regulations, and costs and liabilities.

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Federal, state or local regulatory measures could have a material adverse effect on our financial position, results of operations and cash flows.

The FERC regulates interstate transportation services provided by our liquids pipelines under the ICA. State regulatory agencies regulate many of our assets, including intrastate natural gas and NGL pipelines, intrastate storage facilities and gathering lines.

Our intrastate liquids and natural gas pipelines are subject to regulation in many states, including Illinois, Kansas, Louisiana, Minnesota, New Mexico and Texas. To the extent our intrastate natural gas pipelines engage in interstate transportation, they are also subject to regulation by the FERC pursuant to Section 311 of the NGPA and required to provide service on a not unduly discriminatory basis and pursuant to fair and equitable rates. We also have natural gas underground storage facilities in Louisiana and Texas. Although state regulation is typically less comprehensive in scope than regulation by the FERC, our services are typically required to be provided on a nondiscriminatory basis and are also subject to challenge by protest and complaint.

Although our natural gas gathering systems are generally exempt from FERC regulation under the NGA, our natural gas gathering operations could be adversely affected should they become subject to federal regulation of rates and services, or, if the states in which we operate adopt policies imposing more onerous regulation on gas gathering operations. Additional rules, decisions and legislation pertaining to our assets are considered and adopted from time to time at both state and federal levels. We cannot predict what effect, if any, such regulatory changes and legislation might have on our operations, but we could be required to incur additional capital expenditures.

For a general overview of federal, state and local regulation applicable to our assets, see “ Regulatory Matters ” included within Part I, Items 1 and 2 of this annual report. This regulatory oversight can affect certain aspects of our business and the market for our products and could have a material adverse effect on our financial position, results of operations and cash flows.

The rates of our regulated assets are subject to review and possible adjustment by federal and state regulators, which could adversely affect our revenues.

The FERC, pursuant to the ICA (as amended), the Energy Policy Act of 1992 and rules and orders promulgated thereunder, regulates the tariff rates and terms and conditions of service for our interstate common carrier liquids pipeline operations. To be lawful under the ICA, interstate tariff rates, terms and conditions of service must be just and reasonable and not unduly discriminatory and must be on file with the FERC. In addition, pipelines may not confer any undue preference upon any shipper. Shippers may protest (and the FERC may investigate) the lawfulness of new or changed tariff rates. The FERC can suspend those tariff rates for up to seven months. It can also require refunds of amounts collected pursuant to rates that are ultimately found to be unlawful and prescribe new rates prospectively. The FERC and interested parties can also challenge tariff rates that have become final and effective. The FERC can also order new rates to take effect prospectively and order reparations for past rates that exceed the just and reasonable level up to two years prior to the date of a complaint. Due to the complexity of rate making, the lawfulness of any rate is never assured. A successful challenge of our rates could adversely affect our revenues.

The FERC uses prescribed rate methodologies for approving regulated tariff rate changes for interstate liquids pipelines. The FERC’s indexing methodology currently allows a pipeline to charge rates up to a prescribed ceiling level that changes annually based upon the index adjustment promulgated by FERC for the year. The annual index adjustment that is prescribed by FERC reflects the year-to-year change in the U.S. Producer Price Index for Finished Goods (“PPI”) plus or minus a predetermined percentage (“Index Level”). The Index Level is subject to review and revision every five years.

As an alternative to this indexing methodology, we may also choose to support changes in our rates based on a cost-of-service methodology, or by obtaining advance approval from FERC to charge “market-based rates,” or by charging “settlement rates” agreed to by all affected shippers. The requirements imposed by these methodologies may limit our ability to set rates based on our actual costs or may delay our ability to charge rates reflecting increased costs. Adverse decisions by the FERC related to our rates could adversely affect our financial position, results of operations and cash flows.

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With respect to our intrastate natural gas pipelines that provide service pursuant to Section 311 of the NGPA, FERC regulates the statement of operating conditions related to such service under the NGPA, which requires fair and equitable rates and not unduly discriminatory terms and conditions of service. FERC requires pipelines providing Section 311 service to support their filed rates on a fair and equitable basis every five years. Shippers may protest a rate filing or file a complaint at any time (and the FERC may investigate at any time) the lawfulness of new or changed terms and conditions of service and Section 311 rates, which can be subject to refund if ultimately found to be unlawful. Due to the complexity of rate making, the lawfulness of any rate is never assured. A successful challenge of our rates could adversely affect our financial position, results of operations and cash flows.

The intrastate liquids and natural gas pipeline transportation services we provide are subject to various state laws and regulations that apply to the rates we charge and the terms and conditions of the services we offer. The rates we charge and the provision of our services may be subject to challenge at the state level and any adverse decisions could adversely affect our financial position, results of operations and cash flows.

The adoption and implementation of new statutory and regulatory requirements for derivative transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.

The Dodd-Frank Wall Street Reform and Consumer Protection Act enacted in 2010 (the “Dodd-Frank Act”) provides for statutory and regulatory requirements for swaps and other derivative transactions, including financial and certain physical oil and gas hedging transactions. Under the Dodd-Frank Act, the CFTC has adopted regulations requiring registration of swap dealers and major swap participants, mandatory clearing of swaps, election of the end-user exception for any uncleared swaps by certain qualified companies, recordkeeping and reporting requirements, business conduct standards and position limits among other requirements. Several of these requirements, including position limits rules, allow the CFTC to impose controls that could have an adverse impact on our ability to hedge risks associated with our business and could increase our working capital requirements to conduct these activities.

Based on an assessment of final rules promulgated by the CFTC, we have determined that we are not a swap dealer, major swap participant or a financial entity, and therefore have determined that we currently qualify as an end-user. In addition, the vast majority of our derivative transactions are currently transacted through a Derivatives Clearing Organization, and we believe our use of the end-user exception will likely not be necessary on a routine basis. We will also seek to retain our status as an end-user by taking reasonable measures necessary to avoid becoming a swap dealer, major swap participant or financial entity, and other measures to preserve our ability to elect the end-user exception should it become necessary. However, derivative transactions that are not clearable, and transactions that are clearable but for which we choose to elect the end-user exception, are subject to recordkeeping and reporting requirements and potentially additional credit support arrangements including cash margin or collateral. Posting of additional cash margin or collateral could affect our liquidity and reduce our ability to use cash for capital investments or other company purposes.

While we believe that the majority of our hedging transactions would meet one or more of the enumerated categories for bona fide hedges under the Dodd-Frank Act, the rules could have an adverse impact on our ability to hedge certain risks associated with our business and could potentially affect our profitability.

Over time, the Executive Branch, the U.S. Congress and the CFTC itself may express interest in amending some of the statutory and regulatory provisions impacting financial markets and institutions and in reevaluating some of the existing regulations and regulatory proposals. In addition, the make-up of the CFTC, and its Chairman, changes periodically, often year-to-year, since the term for one CFTC seat expires each year. Those personnel changes can also impact the regulatory agenda. It is not clear what, if any, changes in the law may gain sufficient support to be enacted or what, if any, changes in the existing regulations might move forward and be adopted, or how any such changes would impact our hedging activity.

Our standalone operating cash flow is derived primarily from cash distributions we receive from EPO.

On a standalone basis, the Partnership is a holding company with no business operations and conducts all of its business through its wholly owned subsidiary, EPO. As a result, we depend upon the earnings and cash flows of EPO and its subsidiaries and unconsolidated affiliates, and the distribution of their cash flows to us in order to meet our obligations and to allow us to make cash distributions to our unitholders.

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The amount of cash EPO and its subsidiaries and unconsolidated affiliates can distribute to us depends primarily on cash flows generated from their operations. These operating cash flows fluctuate based on, among other things, the: (i) volume of hydrocarbon products transported on their gathering and transmission pipelines; (ii) throughput volumes in their processing and treating operations; (iii) fees charged and the margins realized for their various storage, terminaling, processing and transportation services; (iv) price of natural gas, crude oil, NGLs and other products; (v) relationships among natural gas, crude oil, NGL and other product prices, including differentials between regional markets; (vi) fluctuations in their working capital needs; (vii) level of their operating costs; (viii) prevailing economic conditions; and (ix) level of competition encountered by their businesses. In addition, the actual amount of cash EPO and its subsidiaries and unconsolidated affiliates will have available for distribution will depend on factors such as: (i) the level of sustaining capital expenditures incurred; (ii) their cash outlays for expansion (or growth) capital projects and acquisitions; and (iii) their debt service requirements and restrictions included in the provisions of existing and future indebtedness, organizational documents, applicable state business organization laws and other applicable laws and regulations. Due to these factors, we may not have sufficient available cash each quarter to continue paying distributions at our current levels.

Changes in management’s estimates and assumptions may have a material impact on our financial statements and financial performance.

In preparing our financial statements and periodic reports filed under the Exchange Act, our management is required under applicable rules and regulations, including accounting standards, to make estimates and assumptions as of a specified date. These estimates and assumptions are based on management’s best estimates and experience as of that date and are subject to substantial risk and uncertainty. Actual results may differ materially as circumstances change and other information becomes known. Areas requiring significant estimates and assumptions by management include: the useful economic lives and residual values of our assets; the economic life of contract-based intangible assets; impairments of property, plant and equipment and investments in affiliates; accruals for estimated liabilities, including reserves for litigation; and routine estimates involving revenues and costs of certain natural gas processing facilities, pipeline transportation revenues, fractionation revenues, marketing revenues and related purchases, and power and utility costs. Changes in estimates or assumptions or information underlying assumptions, such as changes in the Partnership’s business plans, general market conditions and changes in management’s outlook on commodity prices could materially affect reported amounts of assets, liabilities, revenues or expenses.

Risks Relating to Our Partnership Structure

We may issue additional securities without the approval of our common unitholders.

At any time, we may issue an unlimited number of limited partner interests of any type (to parties other than our affiliates) without the approval of our unitholders. Our partnership agreement does not give our common unitholders the right to approve the issuance of equity securities, including equity securities ranking senior to our common units. The issuance of additional common units or other equity securities of equal or senior rank will have the following effects: (i) the ownership interest of a unitholder immediately prior to the issuance will decrease; (ii) the amount of cash available for distribution on each common unit may decrease; (iii) the ratio of taxable income to distributions may increase; (iv) the relative voting strength of each previously outstanding common unit may be diminished; and (v) the market price of our common units may decline.

We may not have sufficient operating cash flows to pay cash distributions at the current level following establishment of cash reserves and payments of fees and expenses.

Because cash distributions on our common units are dependent on the amount of cash we generate, distributions may fluctuate based on our performance and capital needs. We cannot guarantee that we will continue to pay distributions at the current level each quarter. The actual amount of cash that is available to be distributed each quarter will depend upon numerous factors, some of which are beyond our control and the control of our general partner. These factors include, but are not limited to: (i) the volume of the products that we handle and the prices we receive for our services; (ii) the level of our operating costs; (iii) the level of competition in our business; (iv) prevailing economic conditions, including the price of and demand for crude oil, natural gas, NGLs and other products we transport, store and market; (v) the level of capital investments we make; (vi) the amount and cost of capital we can raise compared to the amount of our capital investments and debt service requirements; (vii) restrictions contained in our debt agreements; (viii) fluctuations in our working capital needs; (ix) weather volatility; (x) cash outlays for acquisitions, if any; and (xi) the amount, if any, of cash reserves required by our general partner in its sole discretion.

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Furthermore, the amount of cash that we have available for distribution is not solely a function of profitability, which will be affected by non-cash items such as depreciation, amortization and provisions for asset impairments. Our cash flows are also impacted by borrowings under credit agreements and similar arrangements. As a result, we may be able to make cash distributions during periods when we record losses and may not be able to make cash distributions during periods when we record net income. An inability on our part to pay cash distributions to our unitholders could have a material adverse effect on our financial position, results of operations and cash flows.

Our general partner and its affiliates have limited fiduciary responsibilities to, and conflicts of interest with respect to, our partnership, which may permit it to favor its own interests to your detriment.

The directors and officers of our general partner and its affiliates have duties to manage our general partner in a manner that is beneficial to its members. At the same time, our general partner has duties to manage our partnership in a manner that is beneficial to us. Therefore, our general partner’s duties to us may conflict with the duties of its officers and directors to its members. Such conflicts may include, among others, the following:

• neither our partnership agreement nor any other agreement requires our general partner or EPCO to pursue a business strategy that favors us;

• decisions of our general partner regarding the amount and timing of asset purchases and sales, cash expenditures, borrowings, issuances of additional units, and the establishment of additional reserves in any quarter may affect the level of cash available to pay quarterly distributions to our unitholders;

• under our partnership agreement, our general partner determines which costs incurred by it and its affiliates are reimbursable by us;

• our general partner is allowed to resolve any conflicts of interest involving us and our general partner and its affiliates, and may take into account the interests of parties other than us, such as EPCO, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;

• any resolution of a conflict of interest by our general partner not made in bad faith and that is fair and reasonable to us is binding on the partners and is not a breach of our partnership agreement;

• affiliates of our general partner may compete with us in certain circumstances;

• our general partner has limited its liability and reduced its fiduciary duties and has also restricted the remedies available to our unitholders for actions that might, without the limitations, constitute breaches of fiduciary duty. As a result of purchasing our units, you are deemed to consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law;

• we do not have any employees and we rely solely on employees of EPCO and its affiliates;

• in some instances, our general partner may cause us to borrow funds in order to permit the payment of distributions;

• our general partner may cause us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

• our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, may be entitled to be indemnified by us;

• our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates; and

• our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

We have significant business relationships with entities controlled by EPCO and Dan Duncan LLC. For information regarding these relationships and related party transactions with EPCO and its affiliates, see Note 15 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. Additional information regarding our relationship with EPCO and its affiliates can also be found under Part III, Item 13 of this annual report.

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The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.

We currently list our common units on the NYSE under the symbol “EPD.” Because we are a publicly traded limited partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s Board or to establish a compensation committee or a nominating and corporate governance committee. Additionally, any future issuance of additional common units or other securities, including to affiliates, will not be subject to the NYSE’s shareholder approval rules that apply to a corporation. Accordingly, unitholders do not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. See Part III, Item 10 of this annual report for additional information.

Unitholders have limited voting rights and are not entitled to elect our general partner or its directors. In addition, even if unitholders are dissatisfied, they cannot easily remove our general partner.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders did not elect our general partner or its directors and will have no right to elect our general partner or its directors on an annual or other continuing basis. The owners of our general partner choose the directors of our general partner.

Furthermore, if unitholders are dissatisfied with the performance of our general partner, they currently have no practical ability to remove our general partner or its officers or directors. Our general partner may not be removed except upon the vote of the holders of at least 60% of our outstanding units voting together as a single class. Since affiliates of our general partner currently own approximately 32.5% of our outstanding common units, the removal of Enterprise GP as our general partner is highly unlikely without the consent of both our general partner and its affiliates. As a result of this provision, the trading price of our common units may be lower than other forms of equity ownership because of the absence of a takeover premium in the trading price.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Unitholders’ voting rights are further restricted by a provision in our partnership agreement stating that any units held by a person that owns 20% or more of any class of our common units then outstanding, other than our general partner and its affiliates, cannot be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our unitholders’ ability to influence our management. As a result of this provision, the trading price of our common units may be lower than other forms of equity ownership because of the absence of a takeover premium in the trading price.

Our general partner has a limited call right that may require common unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates own 85% or more of the common units then outstanding, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the remaining common units held by unaffiliated persons at a price not less than the then current market price. As a result, common unitholders may be required to sell their common units at an undesirable time or price and may therefore not receive any return on their investment. Unitholders may also incur a tax liability upon the sale of their common units.

Our common unitholders may not have limited liability if a court finds that limited partner actions constitute control of our business.

Under Delaware law, common unitholders could be held liable for our obligations to the same extent as a general partner if a court determined that the right of limited partners to remove our general partner or to take other action under our partnership agreement constituted participation in the “control” of our business. Under Delaware law, our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those of our contractual obligations that are expressly made without recourse to our general partner.

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The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the states in which we do business. You could have unlimited liability for our obligations if a court or government agency determined that (i) we were conducting business in a state, but had not complied with that particular state’s partnership statute; or (ii) your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constituted “control” of our business.

Unitholders may have a liability to repay distributions.

Under certain circumstances, our unitholders may have to repay amounts wrongfully distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the Partnership are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. A purchaser of common units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to the Partnership that are known to such purchaser of common units at the time it became a limited partner, and for unknown obligations if the liabilities could be determined from our partnership agreement.

Our general partner’s interest in us and the control of our general partner may be transferred to a third party without unitholder consent.

Our general partner, in accordance with our partnership agreement, may transfer its general partner interest without the consent of unitholders. In addition, our general partner may transfer its general partner interest to a third party in a merger or consolidation or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the sole member of our general partner, currently Dan Duncan LLC, to transfer its equity interests in our general partner to a third party. The new equity owner of our general partner would then be in a position to replace the Board and officers of our general partner with their own choices and to influence the decisions taken by the Board and officers of our general partner.

We do not have the same flexibility as other types of organizations to accumulate cash and issue equity to protect against illiquidity in the future.

Unlike a corporation, our partnership agreement requires us to make quarterly distributions to our unitholders of all available cash, after taking into account reserves for commitments and contingencies, including capital and operating costs and debt service requirements. The value of our common units and other limited partner interests may decrease in correlation with any reduction in our cash distributions per unit. Accordingly, if we experience a liquidity problem in the future, we may not be able to issue more equity to recapitalize.

Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service were to treat us as a corporation for federal income tax purposes or if we were otherwise subject to a material amount of entity-level taxation by individual states, then cash available for distribution to our unitholders would be reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. Despite the fact that we are organized as a limited partnership under Delaware law, we will be treated as a corporation for federal income tax purposes unless we satisfy a “qualifying income” requirement. Based on our current operations, we believe we satisfy the qualifying income requirement. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service (“IRS”) with respect to our classification as a partnership for federal income tax purposes.

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If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate and we would also likely pay additional state and local income taxes at varying rates. Distributions to our unitholders would generally be taxed again as corporate dividends, and no income, gains, losses or deductions would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, the cash available for distribution to our unitholders would be reduced. Thus, treatment of us as a corporation could result in a reduction in the anticipated cash-flow and after-tax return to our unitholders, which may cause a reduction in the value of our common units.

At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, capital, and other forms of business taxes, as well as subjecting nonresident partners to taxation through the imposition of withholding obligations and composite, combined, group, block, or similar filing obligations on nonresident partners receiving a distributive share of state “sourced” income. We currently own property or do business in a substantial number of states. Imposition on us of any of these taxes in jurisdictions in which we own assets or conduct business or an increase in the existing tax rates could result in a reduction in the anticipated cash-flow and after-tax return to our unitholders, which may cause a reduction in the value of our common units.

Over the last decade, legislative and regulatory changes and lower demand and related liquidity for midstream energy companies (including those structured as publicly traded partnerships), led to a number of publicly traded partnerships converting to corporations through mergers or voluntarily electing to be taxed as corporations, all of which have materially reduced the number of publicly traded partnerships and the total market capitalization and the depth of capital available for the publicly traded partnership sector.

While we currently believe that our classification as a partnership for federal income tax purposes continues to provide a net benefit for our unitholders, should we continue to see (i) additional publicly traded partnerships elect to be taxed as corporations, which could result in a further decrease in the total market capitalization of the publicly traded partnership sector, (ii) lower demand for equity capital in the publicly traded partnership sector, (iii) the absence of a historic premium in the market valuation of publicly traded partnerships compared to midstream energy companies taxed as corporations (or if we see any discount in the valuation of our partnership compared to such companies), or (iv) a combination thereof that results in a material difference in our cost of capital or limits our access to capital, the board of directors of our general partner may determine it is in our unitholders’ best interest to change our classification as a partnership for federal income tax purposes. Should the general partner recommend that we change our tax classification, such change would be subject to the approval of our common unitholders.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units, may be modified by administrative, legislative or judicial interpretation. From time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships or an investment in our common units, including elimination of partnership tax treatment for certain publicly traded partnerships.

Any changes to federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible for us to be treated as a partnership for federal income tax purposes or otherwise adversely affect our business, financial condition or results of operations. Any such changes or interpretations thereof could adversely impact the value of an investment in our common units.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred.

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of the units on the first day of each month, instead of on the basis of the date a particular unit is transferred. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to successfully challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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A successful IRS contest of the federal income tax positions we take may adversely impact the market for our common units and the cost of any IRS contest will reduce our cash available for distribution to unitholders.

The IRS has made no determination as to our status as a partnership for U.S. federal income tax purposes. The IRS may adopt positions that differ from the positions we take, even positions taken with advice of counsel. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of the positions we take. As a result, any such contest with the IRS may materially and adversely impact the market for our common units and the price at which our common units trade. In addition, our costs of any contest with the IRS, principally legal, accounting and related fees, will be indirectly borne by our unitholders because the costs will reduce our cash available for distribution.

If the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case we would pay the taxes directly to the IRS. If we bear such payment, our cash available for distribution to our unitholders might be substantially reduced.

Under current law, if the IRS makes audit adjustments to our income tax returns for open tax years, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. Our general partner would cause us to pay the taxes (including any applicable penalties and interest) directly to the IRS. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own common units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced.

Our unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount from the cash that we distribute, our unitholders may be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive any cash distributions from us. Our common unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability resulting from their share of our taxable income.

Tax gains or losses on the disposition of our common units could be more or less than expected.

If our unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income decrease the unitholder’s tax basis in the unitholder’s common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if the unitholder sells such common units at a price greater than the unitholder’s tax basis in those common units, even if the price received is less than the unitholder’s original cost. A substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items such as depreciation. In addition, because the amount realized may include a unitholder’s share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of the cash received from the sale.

Tax-exempt entities face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investments in our common units by tax-exempt entities, such as individual retirement accounts (“IRAs”) or other retirement plans, raise issues unique to them. For example, virtually all of our income allocated to unitholders who are organizations exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Generally, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). Thus, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor regarding the impact of these rules on an investment in our common units.

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Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our common units.

Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business (“effectively connected income”). Income allocated to our unitholders and any gain from the sale of our common units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a common unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that common unit.

Moreover, upon the sale, exchange or other disposition of a common unit by a non-U.S. unitholder, the transferee is generally required to withhold 10% of the amount realized on such sale, exchange or other disposition if any portion of the gain on such sale, exchange or other disposition would be treated as effectively connected with a U.S. trade or business. The U.S. Department of the Treasury and the IRS have issued final regulations providing guidance on the application of these rules for transfers of certain publicly traded partnership interests, including transfers of our common units. Under these regulations, the “amount realized” on a transfer of our common units will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and such broker will generally be responsible for the relevant withholding obligations. The U.S. Department of the Treasury and the IRS have provided that these rules generally apply to transfers of and distributions on our common units occurring on or after January 1, 2023. Distributions to non-U.S. unitholders may also be subject to additional withholding under these rules to the extent a portion of a distribution is attributable to an amount in excess of our cumulative net income that has not previously been distributed. We currently anticipate all of our distributions will be in excess of the amount of our cumulative net income that has not previously been distributed. Accordingly, a distribution to a non-U.S. unitholder is expected to be subject to withholding at the highest applicable effective tax rate. Under these final regulations, we are required to issue qualified notices regarding these matters. Our qualified notices can be found on our public company website. Non-U.S. unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common units.

We treat each purchaser of our common units as having the same tax benefits without regard to the common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.

Because we cannot match transferors and transferees of common units, we adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to a common unitholder. It also could affect the timing of these tax benefits or the amount of gain from a sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to the unitholder’s tax returns.

Our common unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of an investment in our common units.

In addition to federal income taxes, our common unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes imposed by the various jurisdictions in which we do business or own property now or in the future, even if the unitholder does not live in any of those jurisdictions. Our common unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently own property or conduct business in a substantial number of states, many of which impose an income tax on individuals, corporations and other entities. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal or corporate income tax. It is the responsibility of each unitholder to file its own federal, state and local tax returns, as applicable.

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A unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of common units) may be considered as having disposed of those common units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered to have disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from lending their common units.

We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methods or the resulting allocations and such a challenge could adversely affect the value of our common units.

In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our respective assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our respective assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

A successful IRS challenge to these methods or allocations could adversely affect the amount, character and timing of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

For the Years Ended December 31, 2025, 2024 and 2023

The following discussion and analysis of our financial condition, results of operations and related information for the years ended December 31, 2025 and 2024 , including applicable year-to-year comparisons, should be read in conjunction with our Consolidated Financial Statements and accompanying notes included under Part II, Item 8 of this annual report. Our financial statements have been prepared in accordance with generally accepted accounting principles (“GAAP”) in the United States (“U.S.”).

Discussion and analysis of matters pertaining to the year ended December 31, 2023 and year-to-year comparisons between the years ended December 31, 2024 and 2023 are not included in this Form 10-K, but can be found under Part II, Item 7 of our annual report on Form 10-K for the year ended December 31, 2024 that was filed on February 28, 2025 .

Key References Used in this Management’s Discussion and Analysis

Unless the context requires otherwise, references to “we,” “us” or “our” within this annual report are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries.

References to the “Partnership” or “Enterprise” mean Enterprise Products Partners L.P. on a standalone basis.

References to “EPO” mean Enterprise Products Operating LLC, which is an indirect wholly owned subsidiary of the Partnership, and its consolidated subsidiaries, through which the Partnership conducts its business. We are managed by our general partner, Enterprise Products Holdings LLC (“Enterprise GP”), which is a wholly owned subsidiary of Dan Duncan LLC, a privately held Texas limited liability company.

The membership interests of Dan Duncan LLC are owned by a voting trust, the current trustees (“DD LLC Trustees”) of which are: (i) Randa Duncan Williams, who is also a director and Chairman of the Board of Directors of Enterprise GP (the “Board”); (ii) Richard H. Bachmann, who is also a director and Vice Chairman of the Board; and (iii) W. Randall Fowler, who is also a director and a Co-Chief Executive Officer of Enterprise GP. Ms. Duncan Williams and Messrs. Bachmann and Fowler also currently serve as managers of Dan Duncan LLC.

References to “EPCO” mean Enterprise Products Company, a privately held Texas corporation, and its privately held affiliates. The outstanding voting capital stock of EPCO is owned by a voting trust, the current trustees (“EPCO Trustees”) of which are: (i) Ms. Duncan Williams, who serves as Chairman of EPCO; (ii) Mr. Bachmann, who serves as the President and Chief Executive Officer of EPCO; and (iii) Mr. Fowler, who serves as an Executive Vice President and the Chief Financial Officer of EPCO. Ms. Duncan Williams and Messrs. Bachmann and Fowler also currently serve as directors of EPCO.

We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates under the collective common control of the DD LLC Trustees and the EPCO Trustees. EPCO, together with its privately held affiliates, owned approximately 32.5% of the Partnership’s common units outstanding at December 31, 2025 .

As generally used in the energy industry and in this annual report, the acronyms below have the following meanings:

per day

MMBPD

million barrels per day

BBtus

billion British thermal units

MMBtus

million British thermal units

Bcf

billion cubic feet

MMcf

million cubic feet

BPD

barrels per day

MWac

megawatts, alternating current

MBPD

thousand barrels per day

MWdc

megawatts, direct current

MMBbls

million barrels

TBtus

trillion British thermal units

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This annual report on Form 10-K for the year ended December 31, 2025 (our “annual report”) contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us. When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “seek,” “goal,” “estimate,” “forecast,” “intend,” “could,” “should,” “would,” “will,” “believe,” “may,” “scheduled,” “pending,” “potential” and similar expressions and statements regarding our plans and objectives for future operations are intended to identify forward-looking statements. Although we and our general partner believe that our expectations reflected in such forward-looking statements (including any forward-looking statements/expectations of third parties referenced in this annual report) are reasonable, neither we nor our general partner can give any assurances that such expectations will prove to be correct.

Forward-looking statements are subject to a variety of risks, uncertainties and assumptions as described in more detail under Part I, Item 1A of this annual report. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. You should not put undue reliance on any forward-looking statements. The forward-looking statements in this annual report speak only as of the date hereof. Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason.

Overview of Business

We are a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.” Our preferred units are not publicly traded. We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO and are a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, petrochemicals and refined products. We are owned by our limited partners (preferred and common unitholders) from an economic perspective. Enterprise GP, which owns a non-economic general partner interest in us, manages our Partnership. We conduct substantially all of our business operations through EPO and its consolidated subsidiaries.

Our fully integrated, midstream energy asset network (or “value chain”) links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the U.S., Canada and the Gulf of Mexico with domestic consumers and international markets. Our midstream energy operations include:

• natural gas gathering, treating, processing, transportation and storage;

• NGL transportation, fractionation, storage, and marine terminals (including those used to export liquefied petroleum gases (“LPG”) and ethane);

• crude oil gathering, transportation, storage, and marine terminals;

• propylene production facilities (including propane dehydrogenation (“PDH”) facilities), butane isomerization, octane enhancement, isobutane dehydrogenation (“iBDH”) and high purity isobutylene (“HPIB”) production facilities;

• petrochemical and refined products transportation, storage, and marine terminals (including those used to export ethylene and polymer grade propylene (“PGP”)); and

• a marine transportation business that operates on key U.S. inland and intracoastal waterway systems.

The safe operation of our assets is a top priority. We are committed to protecting the environment and the health and safety of the public and those working on our behalf by conducting our business activities in a safe and environmentally responsible manner. For additional information, see “ Regulatory Matters - Environmental, Safety and Conservation ” within Part I, Items 1 and 2 of this annual report.

Like many publicly traded partnerships, we have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement (the “ASA”) or by other service providers.

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Each of our business segments benefits from the supporting role of our marketing activities. The main purpose of our marketing activities is to support the utilization and expansion of assets across our midstream energy asset network by increasing the volumes handled by such assets, which results in additional fee-based earnings for each business segment. In performing these support roles, our marketing activities also seek to participate in supply and demand opportunities as a supplemental source of segment gross operating margin for us. The financial results of our marketing efforts fluctuate due to changes in volumes handled and overall market conditions, which are influenced by current and forward market prices for the products bought and sold.

Our financial position, results of operations and cash flows are subject to certain risks. For information regarding such risks, see “ Risk Factors ” included under Part I, Item 1A of this annual report.

Current Outlook

As noted previously, this annual report on Form 10-K, including this update to our outlook on business conditions, contains forward-looking statements that are based on our beliefs and those of Enterprise GP. In addition, it reflects assumptions made by us and information currently available to us, which includes forecast information published by third parties. See “Cautionary Statement Regarding Forward-Looking Information” within this Part II, Item 7 and “Risk Factors” in Part I, Item 1A, for additional information. The following information in this Current Outlook presents our current views on key midstream energy supply and demand fundamentals, and is qualified in all respects as forward-looking statements whether or not expressly qualified as such in particular sentences. All references to U.S. Energy Information Administration (“EIA”) forecasts and expectations are derived from its February 2026 Short-Term Energy Outlook (“February 2026 STEO”), which was published on February 10, 2026.

The level of services we provide and the amount of hydrocarbons we purchase and sell continue to be driven by supply and demand fundamentals for hydrocarbon products. These dynamics affect our financial position, results of operations and cash flows. Entering 2026, global liquid hydrocarbon markets have shifted into a modest surplus as non-Organization of the Petroleum Exporting Countries (“non-OPEC”) supply growth, together with the scheduled easing of OPEC and Russia (collectively, the “OPEC+” group) production cuts, have contributed to inventory builds and placed downward pressure on liquid hydrocarbon prices relative to levels seen during 2024 and 2025.

Against this backdrop, broader macroeconomic conditions remain a key determinant of hydrocarbon demand. Global economic growth, an important driver of demand, remains resilient but moderate. In its January 2026 World Economic Outlook, the International Monetary Fund (“IMF”) projects global economic growth of 3.3% in 2026 and 3.2% in 2027 as headline inflation continues to ease. The IMF notes that the U.S. remains a key contributor to near-term global growth amid ongoing technology investment, while Europe and other advanced economies are expected to experience more measured recoveries. The IMF projects China’s economy to grow by 4.5% in 2026 as ongoing government-driven fiscal support, along with relative stabilization in trade conditions, help mitigate the effects of longer-term structural challenges. Despite signs of resilience, the IMF continues to highlight risks associated with geopolitics, trade policy and uncertainty regarding productivity gains from artificial intelligence.

In addition to macroeconomic factors, policy developments and security considerations remain important factors affecting global energy markets. Sanctions, political instability affecting certain crude oil‑exporting countries and security risks in key shipping corridors have contributed to ongoing uncertainty in global trade flows and may influence the availability, cost and routing of hydrocarbon supplies to global markets.

The OPEC+ group, which controls over 79% of the world’s proven crude oil reserves (as reported in the OPEC Annual Statistical Bulletin 2025), continues to have significant influence on global balances. In 2024, the OPEC+ group announced that its baseline and first layer of voluntary cuts totaling 3.66 MMBPD would be extended well into 2025, and certain members agreed to extend the second layer of voluntary cuts of 2.2 MMBPD until the end of March 2025. Beginning in April 2025, the OPEC+ group began unwinding the second layer of voluntary cuts at a faster than announced pace, completing a full restoration of the 2.2 MMBPD by the fall of 2025. On February 1, 2026, eight OPEC+ group member nations agreed to maintain their pause of the ongoing restoration of the baseline cut and the first layer of voluntary cuts. The group reiterated that these volumes could still return to the market either partially or in full, but would happen only in a gradual manner depending on evolving market conditions. These OPEC+ group decisions will affect near-term balances and crude oil prices, which may influence the incentives for non-OPEC production throughout the world.

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While these global factors shape the broader market, U.S. supply trends continue to play an important role. U.S. producers achieved a new crude oil production record of 13.6 MMBPD in 2025, with the Permian Basin remaining the primary contributor to supply growth. The EIA projects that 2026 U.S. crude oil output will be roughly flat due to softer prices and slower drilling activity, followed by a modest decline in 2027. As of January 29, 2026, the price of West Texas Intermediate (“WTI”) crude oil (as reported by New York Mercantile Exchange (“NYMEX”)) was $65.42 per barrel, largely in line with the 2025 calendar year average of $64.83 per barrel. The EIA expects WTI crude oil to average $53.42 per barrel in 2026, reflecting production growth outpacing consumption and inventory builds that are expected to persist into 2027.

The EIA expects Permian Basin crude oil production in 2026 and 2027 to remain largely unchanged from its record level of 6.6 MMBPD in 2025 as impacts from reduced rig counts are offset by increases in production efficiency out of maturing wells. Despite this forecast, we believe that natural gas and NGL production volumes will continue to grow due to rising gas-to-oil ratios (ratio of natural gas production to crude oil production) in the basin.

For natural gas, the EIA forecasts U.S. dry natural gas production to increase approximately 2% in 2026 to 110 Bcf/d, with additional growth of approximately 1% expected in 2027, driven primarily by Permian Basin and Haynesville growth supported by midstream additions. The price of natural gas, as measured by the NYMEX at Henry Hub, was $3.92 per MMBtu as of January 29, 2026, approximately 8% above the 2025 calendar year average of $3.62 per MMBtu. The EIA forecasts Henry Hub to average $4.31 per MMBtu in 2026, with prices expected to increase further in 2027 as LNG exports and power sector demand outpace supply growth. U.S. LNG remains the structural growth lever for gas demand, supported by incremental capacity additions including Plaquemines LNG, Corpus Christi Stage 3 and Golden Pass.

Additional data from the EIA reinforces these trends. In its February 2026 STEO, the EIA projects U.S. liquid fuels production to reach 23.7 MMBPD in 2026, an increase of approximately 0.1 MMBPD from 2025. Global production of liquid fuels is expected to average 107.9 MMBPD in 2026, up from 106.3 MMBPD in 2025. The EIA also forecasts U.S. marketed natural gas production to increase by approximately 2.5 Bcf/d in 2026 to 120.8 Bcf/d, with LNG exports growing by 1.4 Bcf/d to reach 16.4 Bcf/d for the year. On the demand side, the EIA forecasts that global liquids fuel consumption will increase from 103.6 MMBPD in 2025 to 104.8 MMBPD in 2026, driven primarily by growth from Southeast Asia and other non-Organization for Economic Cooperation and Development (“OECD”) countries.

We believe the fundamentals for crude oil and natural gas remain constructive, particularly in the U.S. and more so in the Permian Basin, supported by growing supply and sufficient export capacity necessary to satisfy rising global demand. The potential for additional sanctions on crude oil exports from Russia and Iran could further strengthen global demand for U.S. crude supplies. We also expect continued growth in global electricity demand, including incremental U.S. demand associated with industrial reshoring and new data centers, which should support natural gas-fired power generation over the medium to long-term. The global petrochemical industry is expected to remain challenged in 2026 due to oversupply, driven largely by China’s continued expansion of its petrochemical production capacity as it focuses on export manufacturing amid domestic economic pressures. This oversupply has led to the rationalization of petrochemical production capacity in Europe, Japan and other regions. Even with ongoing industry headwinds, U.S. petrochemical producers are expected to maintain a competitive advantage given their access to locally produced, lower-cost feedstocks and energy relative to their global peer group. Over the longer term, growth in overall energy demand, stemming from a rise in global populations, improved living standards and technological advancements, will require continued growth in the level of hydrocarbons produced, in addition to growth in alternative forms of energy, including wind and solar generation, where it can be produced cost-effectively without permanent subsidy.

We believe that these anticipated additions to hydrocarbon production and demand will create additional opportunities for us to provide midstream services to our customers while leveraging the strengths of our portfolio, which include:

• Our Assets – Our employees find innovative ways to optimize our large, integrated and diversified asset base both to provide incremental services to customers and to respond to market opportunities. Additional production volumes could lead to higher demand for processing, transportation, fractionation and export terminaling services. Our storage services provide valuable flexibility for customers seeking to balance supply and demand while enabling us to capture potential contango and other marketing opportunities. U.S. energy and feedstock advantages position our assets well to compete effectively for incremental production and processing volumes. To the extent a rising operating cost environment impacts our results, there are typically offsetting benefits either inherent in our business or that result from other steps we proactively take to reduce the impact of inflation on our net operating results. These benefits include inflation-based revenue rate escalations, fuel and electricity rebills or surcharges, and increased volumetric throughput often achieved during periods of higher commodity prices.

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• Our Quality Customers – We have contracted with a large number of high-quality customers in order to achieve revenue diversification. In 2025, our top 200 customers represented 96.7% of our consolidated revenues, and no single customer accounted for 10% or more of our consolidated revenues. Based on their year-end 2025 debt ratings, approximately 89% of revenues from these customers were attributable to companies that were investment grade rated or backed by letters of credit. Approximately 2% of the revenues from our top 200 customers were attributable to independent producers that are non-rated or sub-investment grade.

• Our Balance Sheet and Liquidity – We currently maintain investment grade credit ratings on EPO’s long-term senior unsecured debt of A-, A3 and A- by Standard and Poor’s, Moody’s and Fitch Ratings, respectively. Based on current market conditions, we believe that we have sufficient consolidated liquidity as of December 31, 2025, which was comprised of $4.2 billion of available borrowing capacity under EPO’s revolving credit facilities and $969 million of unrestricted cash on hand. As of December 31, 2025, approximately 98.3% of our debt portfolio is fixed-rate debt at a weighted-average cost of 4.7% and weighted-average maturity of 16.8 years.

• Our Access to Capital Markets – In 2025, EPO successfully issued $3.65 billion in aggregate principal amount of senior notes. Based on current market conditions, we believe we will have sufficient liquidity and access to debt capital markets to fund our operations, capital investments and the remaining principal amount of senior notes maturing over the next twelve months and beyond.

Recent Developments

Enterprise Announces Expansion and Extension of Bahia NGL Pipeline; ExxonMobil Acquires Joint Interest

In December 2025, we completed the sale of a 40% undivided interest in our Bahia NGL Pipeline to ExxonMobil, for cash proceeds of approximately $655 million.

The 550-mile Bahia NGL Pipeline, which began commercial operations in December 2025, has an initial capacity to transport up to 600 MBPD of NGLs from the Midland and Delaware basins of West Texas to our Mont Belvieu area fractionation and storage complex.

In addition, Enterprise and ExxonMobil plan to increase the pipeline’s capacity to 1.0 MMBPD by adding incremental pumping capacity and construct a 92-mile extension to ExxonMobil’s Cowboy natural gas processing plant in Eddy County, New Mexico (the “Cowboy Extension”). The Cowboy Extension will also connect to multiple Enterprise-owned processing facilities in the Delaware Basin. We will own a 30% undivided joint interest in the Cowboy Extension. The expansion and Cowboy Extension are expected to be completed in the fourth quarter of 2027. Enterprise will serve as operator of the combined system.

Issuance of Senior Notes in June 2025 and November 2025

In June 2025, EPO issued $2.0 billion aggregate principal amount of senior notes comprised of (i) $500 million principal amount of senior notes due June 2028 (“Senior Notes LLL”), (ii) $750 million principal amount of senior notes due January 2031 (“Senior Notes MMM”) and (iii) $750 million principal amount of senior notes due January 2036 (“Senior Notes NNN”).

Senior Notes LLL were issued at 99.869% of their principal amount and have a fixed interest rate of 4.30% per year. Senior Notes MMM were issued at 99.816% of their principal amount and have a fixed interest rate of 4.60% per year. Senior Notes NNN were issued at 99.665% of their principal amount and have a fixed interest rate of 5.20% per year. Net proceeds from this offering were used by EPO for general company purposes, including for growth capital investments, and the repayment of amounts outstanding under our commercial paper program.

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In November 2025, EPO issued $1.65 billion aggregate principal amount of senior notes comprised of (i) $300 million principal amount of reopened Senior Notes LLL, (ii) $600 million principal amount of reopened Senior Notes MMM and (iii) $750 million principal amount of reopened Senior Notes NNN. The reopened Senior Notes LLL, reopened Senior Notes MMM and reopened Senior Notes NNN were issued at 100.630%, 100.693% and 101.185% of their respective principal amounts, plus accrued interest from June 20, 2025. Each of the reopened Senior Notes LLL, the reopened Senior Notes MMM and the reopened Senior Notes NNN constitutes a further issuance of, and forms a single series with, the original notes of the corresponding series issued in June 2025, and has the same terms as to interest, status, redemption or otherwise as such original notes. Net proceeds from this offering were used by EPO for general company purposes, including for growth capital investments and acquisitions, and the repayment of debt (including the repayment of all or a portion of $750 million principal amount of 5.05% Senior Notes FFF that matured in January 2026, $875 million principal amount of 3.70% Senior Notes PP that matured in February 2026 and amounts outstanding under our commercial paper program).

The Partnership guaranteed the senior notes issued in June 2025 and November 2025 through an unconditional guarantee on an unsecured and unsubordinated basis.

Enterprise Announces Increase to 2019 Buyback Program

In October 2025, we announced that the Board approved an increase to the authorized maximum aggregate purchase price (excluding fees, commissions and other ancillary expenses) of the Partnership’s common units that may be repurchased under the 2019 Buyback Program from $2.0 billion to $5.0 billion. After giving effect to this increase, the remaining available capacity under the 2019 Buyback Program is $3.6 billion.

Enterprise Acquires Oxy Affiliate, Enters into Service Agreements, and Expands Midland Basin Processing Capacity

In July 2025, an affiliate of Enterprise agreed to acquire an affiliate of Occidental Petroleum Corporation (“Oxy”), which owns approximately 200 miles of natural gas gathering pipelines in the Midland Basin, in a debt-free transaction for $581 million in cash consideration. In addition, an affiliate of Enterprise agreed to provide Oxy with natural gas gathering and processing services, supported by a long-term dedication of approximately 73,000 acres across four counties in the Midland Basin. This transaction closed on August 22, 2025.

In order to accommodate this production growth in the Midland Basin, we also announced plans to expand our natural gas gathering and processing capabilities in the Midland Basin with the construction of a ninth natural gas processing train (“Athena”) and further expansion of our Midland Basin gathering system. This natural gas processing train, which will have the capacity to process approximately 300 MMcf/d of natural gas and extract up to 40 MBPD of NGLs, is expected to begin service in the fourth quarter of 2026.

Enterprise Begins Initial Service at Neches River Ethane / Propane Export Facility

In July 2025, we placed into service the first phase of our new ethane / propane export facility located on the Neches River in Orange County, Texas (“Neches River Ethane / Propane Export Facility”). This phase included the completion of a loading dock and an ethane refrigeration train with a nameplate capacity of 120 MBPD. The second phase of the project, which will add a second refrigeration train capable of loading up to 180 MBPD of ethane, 360 MBPD of propane, or a combination thereof, is expected to begin service in the first half of 2026.

Enterprise Begins Service at Mentone West 1 and Orion

In July 2025, we placed our first natural gas processing train at our Mentone West location in the Delaware Basin (“Mentone West 1”) and our eighth Midland Basin natural gas processing train (“Orion”) into commercial service. Both Mentone West 1 and Orion are capable of processing over 300 MMcf/d of natural gas and extracting more than 40 MBPD of NGLs and are supported by long-term acreage dedication agreements and minimum volume commitments.

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Selected Energy Commodity Price Data

The following table presents selected average index prices for natural gas and selected NGL and petrochemical products for the periods indicated:

Natural

Gas,

$/MMBtu

Ethane,

$/gallon

Propane,

$/gallon

Normal

Butane,

$/gallon

Isobutane,

$/gallon

Natural

Gasoline,

$/gallon

Polymer

Grade

Propylene,

$/pound

Refinery

Grade

Propylene,

$/pound

Indicative Gas

Processing

Gross Spread

$/gallon

2024 by quarter:

1st Quarter

2nd Quarter

3rd Quarter

4th Quarter

2024 Averages

2025 by quarter:

1st Quarter

2nd Quarter

3rd Quarter

4th Quarter

2025 Averages

(1) Natural gas prices are based on Henry-Hub Inside FERC commercial index prices as reported by Platts, which is a division of S&P Global, Inc.

(2) NGL prices for ethane, propane, normal butane, isobutane and natural gasoline are based on Mont Belvieu, Texas Non-TET commercial index prices as reported by Oil Price Information Service, which is a division of Dow Jones.

(3) Polymer grade propylene prices represent average contract pricing for such product as reported by IHS Markit (“IHS”), which is a division of S&P Global, Inc. Refinery grade propylene (“RGP”) prices represent weighted-average spot prices for such product as reported by IHS.

(4) The “Indicative Gas Processing Gross Spread” represents our generic estimate of the gross economic benefit from extracting NGLs from natural gas production based on certain pricing assumptions. Specifically, it is the amount by which the assumed economic value of a composite gallon of NGLs in Chambers County, Texas exceeds the value of the equivalent amount of energy in natural gas at Henry Hub, Louisiana. Our estimate of the indicative spread does not consider the operating costs incurred by a natural gas processing facility to extract the NGLs nor the transportation and fractionation costs to deliver the NGLs to market. In addition, the actual gas processing spread earned at each plant is further influenced by regional pricing and extraction dynamics.

The weighted-average indicative market price for NGLs was $0.59 per gallon in 2025 compared to $0.60 per gallon in 2024 .

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The following table presents selected average index prices for crude oil for the periods indicated:

WTI

Crude Oil,

$/barrel

Midland

Crude Oil,

$/barrel

Houston

Crude Oil,

$/barrel

2024 by quarter:

1st Quarter

2nd Quarter

3rd Quarter

4th Quarter

2024 Averages

2025 by quarter:

1st Quarter

2nd Quarter

3rd Quarter

4th Quarter

2025 Averages

(1) WTI prices are based on commercial index prices at Cushing, Oklahoma as measured by the NYMEX.

(2) Midland and Houston crude oil prices are based on commercial index prices as reported by Argus.

Fluctuations in our consolidated revenues and cost of sales amounts are explained in large part by changes in energy commodity prices. An increase in our consolidated marketing revenues due to higher energy commodity sales prices may not result in an increase in gross operating margin or cash available for distribution, since our consolidated cost of sales amounts would also be expected to increase due to comparable increases in the purchase prices of the underlying energy commodities. The same type of relationship would be true in the case of lower energy commodity sales prices and purchase costs.

We attempt to mitigate commodity price exposure through our hedging activities and the use of fee-based arrangements. See Note 14 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report and “ Quantitative and Qualitative Disclosures About Market Risk ” under Part II, Item 7A of this annual report for information regarding our commodity hedging activities.

Impact of Inflation

Inflation rates in the U.S., which are generally influenced by a variety of macroeconomic and policy-related factors, have moderated from prior levels, but remain a relevant consideration for the overall cost environment. In addition, there is uncertainty of what effect, if any, trade tariffs and other policy actions may have on inflation in future periods. However, to the extent that a rising cost environment impacts our results, there are typically offsetting benefits either inherent in our business or that result from other steps we take proactively to reduce the impact of inflation on our net operating results. These benefits include: (1) provisions included in our long-term fee-based revenue contracts that offset cost increases in the form of rate escalations based on positive changes in the U.S. Consumer Price Index, Producer Price Index for Finished Goods or other factors; (2) provisions in other revenue contracts that enable us to pass through higher energy costs to customers in the form of gas, electricity and fuel rebills or surcharges; and (3) higher commodity prices, which generally enhance our results in the form of increased volumetric throughput and demand for our services. Additionally, we take measures to mitigate the impact of cost increases in certain commodities, including a portion of our electricity needs, using fixed-price, term purchase agreements, or financial derivatives. For these reasons, the increased cost environment, caused in part by inflation, has not had a material impact on our historical results of operations for the periods presented in this report. However, a significant or prolonged period of high inflation could adversely impact our results if costs were to increase at a rate greater than the increase in the revenues we receive.

See “ Capital Investments ” within this Part II, Item 7 for a discussion of the impact of inflation on our capital investment decisions. Additionally, see Part I, Item 1A “ Risk Factors -Changes in price levels could negatively impact our revenue, our expenses, or both, which could adversely affect our business. ”

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Income Statement Highlights

The following table summarizes the key components of our consolidated results of operations for the years indicated (dollars in millions):

For the Year

Ended December 31,

Revenues

Costs and expenses:

Operating costs and expenses:

Cost of sales

Other operating costs and expenses

Depreciation, amortization and accretion expenses

Asset impairment charges

Net losses (gains) attributable to asset sales and related matters

Total operating costs and expenses

General and administrative costs

Total costs and expenses

Equity in income of unconsolidated affiliates

Operating income

Other income (expense):

Interest expense

Other, net

Total other expense, net

Income before income taxes

Provision for income taxes

Net income

Net income attributable to noncontrolling interests

Net income attributable to preferred units

Net income attributable to common unitholders

Revenues

The following table presents each business segment’s contribution to consolidated revenues for the years indicated (dollars in millions):

For the Year

Ended December 31,

NGL Pipelines & Services:

Sales of NGLs and related products

Midstream services

Total

Crude Oil Pipelines & Services:

Sales of crude oil

Midstream services

Total

Natural Gas Pipelines & Services:

Sales of natural gas

Midstream services

Total

Petrochemical & Refined Products Services:

Sales of petrochemicals and refined products

Midstream services

Total

Total consolidated revenues

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Total revenues for 2025 decreased a net $3.6 billion when compared to 2024 primarily due to lower marketing revenues.

Revenues from the marketing of NGLs, crude oil and petrochemicals and refined products decreased a combined net $4.8 billion year-to-year primarily due to lower average sales prices, which accounted for a $7.9 billion decrease, partially offset by higher sales volumes, which accounted for a $3.1 billion increase. Revenues from the marketing of natural gas increased $897 million year-to-year primarily due to higher average sales prices.

Revenues from midstream services for 2025 increased a net $294 million when compared to 2024 . Revenues from our NGL and natural gas transportation assets increased a combined $408 million year-to-year primarily due to higher demand for transportation services. R evenues from our natural gas processing facilities decreased $97 million year-to-year primarily due to lower market values for the equity NGL-equivalent production volumes we receive as non-cash consideration for processing services. Lastly, revenues from our octane enhancement and related plant operations decreased $32 million year-to-year primarily due to lower deficiency fee revenues.

For additional information regarding our revenues, see Note 9 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Operating costs and expenses

Total operating costs and expenses for 2025 decreased a net $3.6 billion when compared to 2024 .

Cost of sales

Cost of sales for 2025 decreased a net $4.0 billion when compared to 2024 . The cost of sales associated with the marketing of NGLs and crude oil decreased a combined net $3.4 billion year-to-year primarily due to lower average purchase prices, which accounted for a $6.0 billion decrease, partially offset by higher volumes, which accounted for a $2.6 billion increase. The cost of sales associated with the marketing of petrochemicals and refined products decreased $985 million year-to-year primarily due to lower volumes, which accounted for a $691 million decrease, and lower average purchase prices, which accounted for an additional $294 million decrease. The cost of sales associated with the marketing of natural gas increased $346 million year-to-year primarily due to higher average purchase prices.

Other operating costs and expenses

Other operating costs and expenses increased $283 million year-to-year primarily due to higher employee compensation, utility, and rental costs.

Depreciation, amortization and accretion expenses

Depreciation, amortization and accretion expense increased a combined $149 million year-to-year primarily due to higher depreciation expense on assets placed into full or limited service since the first quarter of 2024 (e.g., two natural gas processing trains and related gathering system expansions in the Permian Basin, the natural gas gathering system and treating facilities acquired in October 2024 through our acquisition of Pinon Midstream, LLC (“Pinon Midstream”) and the Neches River Terminal).

General and administrative costs

General and administrative costs for 2025 increased $7 million when compared to 2024 primarily due to higher employee compensation costs.

Equity in income of unconsolidated affiliates

Equity income from our unconsolidated affiliates for 2025 decreased $47 million when compared to 2024 primarily due to lower earnings from investments in crude oil and NGL pipelines.

Operating income

Operating income for 2025 decreased $72 million when compared to 2024 due to the previously described year-to-year changes in revenues, operating costs and expenses, general and administrative costs and equity in income of unconsolidated affiliates.

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Interest expense

The following table presents the components of our consolidated interest expense for the years indicated (dollars in millions):

For the Year

Ended December 31,

Interest charged on debt principal outstanding (1)

Impact of interest rate hedging program, including related amortization

Interest costs capitalized in connection with construction projects (2)

Other

Total

(1) The weighted-average interest rates on debt principal outstanding were 4.65% and 4.54% during the years ended December 31, 2025 and 2024, respectively.

(2) We capitalize interest costs incurred on funds used to construct property, plant and equipment while the asset is in its construction phase. Capitalized interest amounts become part of the historical cost of an asset and are charged to earnings (as a component of depreciation expense) on a straight-line basis over the estimated useful life of the asset once the asset enters its intended service. When capitalized interest is recorded, it reduces interest expense from what it would be otherwise. Capitalized interest amounts fluctuate based on the timing of when projects are placed into service, our capital investment levels and the interest rates charged on borrowings.

Interest charged on debt principal outstanding, which is a key driver of interest expense, increased a net $106 million year-to-year. This increase was primarily due to the issuance of $2.5 billion, $2.0 billion and $1.65 billion of fixed-rate senior notes in August 2024, June 2025 and November 2025, respectively, which accounted for a combined $142 million increase, partially offset by the retirement of $1.15 billion of fixed-rate senior notes in February 2025, which accounted for a $38 million decrease.

For information regarding our debt obligations, see Note 7 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Income taxes

Our income taxes are primarily comprised of our state tax obligations under the Revised Texas Franchise Tax (“Texas Margin Tax”). Our provision for income taxes for 2025 decreased $42 million when compared to 2024.

For information regarding our income taxes, see Note 16 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

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Business Segment Highlights

Our operations are reported under four business segments: (i) NGL Pipelines & Services, (ii) Crude Oil Pipelines & Services, (iii) Natural Gas Pipelines & Services and (iv) Petrochemical & Refined Products Services. Our business segments are generally organized and managed according to the types of services rendered (or technologies employed) and products produced and/or sold.

The following information summarizes the assets and operations of each business segment:

• Our NGL Pipelines & Services business segment includes our natural gas processing and related NGL marketing activities, NGL pipelines, NGL fractionation facilities, NGL and related product storage facilities, and NGL marine terminals.

• Our Crude Oil Pipelines & Services business segment includes our crude oil pipelines, crude oil storage and marine terminals, and related crude oil marketing activities.

• Our Natural Gas Pipelines & Services business segment includes our natural gas pipeline systems that provide for the gathering, treating and transportation of natural gas. This segment also includes our natural gas marketing activities.

• Our Petrochemical & Refined Products Services business segment includes our (i) propylene production facilities, which include propylene fractionation units and PDH facilities, and related pipelines and marketing activities, (ii) butane isomerization complex and related DIB operations, (iii) octane enhancement, iBDH and HPIB production facilities, (iv) refined products pipelines, terminals and related marketing activities, (v) an ethylene export terminal and related operations; and (vi) marine transportation business.

We evaluate segment performance based on our financial measure of gross operating margin. Gross operating margin is an important performance measure of the core profitability of our operations and forms the basis of our internal financial reporting. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results.

The following table presents gross operating margin by segment and total gross operating margin, a non-generally accepted accounting principle (“non-GAAP”) financial measure, for the years indicated (dollars in millions):

For the Year

Ended December 31,

Gross operating margin by segment:

NGL Pipelines & Services

Crude Oil Pipelines & Services

Natural Gas Pipelines & Services

Petrochemical & Refined Products Services

Total segment gross operating margin (1)

Net adjustment for shipper make-up rights

Total gross operating margin (non-GAAP)

(1) Within the context of this table, total segment gross operating margin represents a subtotal and corresponds to measures similarly titled within our business segment disclosures found under Note 10 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Gross operating margin includes equity in the earnings of unconsolidated affiliates, but is exclusive of other income and expense transactions, income taxes, the cumulative effect of changes in accounting principles and extraordinary charges. Gross operating margin is presented on a 100% basis before any allocation of earnings to noncontrolling interests. Our calculation of gross operating margin may or may not be comparable to similarly titled measures used by other companies. Segment gross operating margin for NGL Pipelines & Services and Crude Oil Pipelines & Services reflect adjustments for shipper make-up rights that are included in management’s evaluation of segment results. However, these adjustments are excluded from non-GAAP total gross operating margin.

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The GAAP financial measure most directly comparable to total gross operating margin is operating income. For a discussion of operating income and its components, see the previous section titled “ Income Statement Highlights ” within this Part II, Item 7. The following table presents a reconciliation of operating income to total gross operating margin for the years indicated (dollars in millions):

For the Year

Ended December 31,

Operating income

Adjustments to reconcile operating income to total gross operating margin (addition or subtraction indicated by sign):

Depreciation, amortization and accretion expense in operating costs and expenses (1)

Asset impairment charges in operating costs and expenses

Net losses (gains) attributable to asset sales and related matters in operating costs and expenses

General and administrative costs

Total gross operating margin (non-GAAP)

(1) Excludes amortization of major maintenance costs for reaction-based plants and amortization of finance lease right-of-use assets, which are components of gross operating margin.

Each of our business segments benefits from the supporting role of our marketing activities. The main purpose of our marketing activities is to support the utilization and expansion of assets across our midstream energy asset network by increasing the volumes handled by such assets, which results in additional fee-based earnings for each business segment. In performing these support roles, our marketing activities also seek to participate in supply and demand opportunities as a supplemental source of gross operating margin for us. The financial results of our marketing efforts fluctuate due to changes in volumes handled and overall market conditions, which are influenced by current and forward market prices for the products bought and sold.

NGL Pipelines & Services

The following table presents segment gross operating margin and selected volumetric data for the NGL Pipelines & Services segment for the years indicated (dollars in millions, volumes as noted):

For the Year

Ended December 31,

Segment gross operating margin:

Natural gas processing and related NGL marketing activities

NGL pipelines, storage and terminals

NGL fractionation

Total

Selected volumetric data:

NGL pipeline transportation volumes (MBPD)

NGL marine terminal volumes (MBPD)

NGL fractionation volumes (MBPD)

Equity NGL-equivalent production volumes (MBPD) (1)

Fee-based natural gas processing volumes (MMcf/d) (2,3)

(1) Primarily represents the NGL and condensate volumes we earn and take title to in connection with our processing activities. The total equity NGL-equivalent production volumes also include residue natural gas volumes from our natural gas processing business.

(2) Volumes reported correspond to the revenue streams earned by our natural gas processing plants.

(3) Fee-based natural gas processing volumes are measured at either the wellhead or plant inlet in MMcf/d.

Natural gas processing and related NGL marketing activities

Gross operating margin from natural gas processing and related NGL marketing activities for the year ended December 31, 2025 decreased $91 million when compared to the year ended December 31, 2024 .

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Gross operating margin from our NGL marketing activities decreased a net $94 million year-to-year primarily due to lower average sales margins, which accounted for a $167 million decrease, partially offset by higher sales volumes, which accounted for a $65 million increase, and higher mark-to-market earnings, which accounted for an additional $10 million increase.

Gross operating margin from our Rockies natural gas processing facilities (Meeker, Pioneer and Chaco) decreased a combined $22 million year-to-year primarily due to lower average processing margins (including the impact of hedging activities). On a combined basis, fee-based natural gas processing volumes and equity NGL-equivalent production volumes decreased 40 MMcf/d and increased 2 MBPD, respectively, year-to-year.

Gross operating margin from our Midland Basin natural gas processing facilities increased a net $17 million year-to-year primarily due to higher fee-based natural gas processing volumes, which accounted for a $32 million increase, and a 5 MBPD increase in equity NGL-equivalent production volumes, which accounted for an additional $9 million increase, partially offset by higher operating costs, which accounted for a $24 million decrease. Fee-based natural gas processing volumes at our Midland Basin natural gas processing facilities increased 270 MMcf/d year-to-year primarily due to contributions from our Leonidas and Orion natural gas processing trains, which were placed into service in late first quarter of 2024 and the third quarter of 2025, respectively.

Gross operating margin from our Delaware Basin natural gas processing facilities increased a net $15 million year-to-year primarily due to higher fee-based natural gas processing volumes, which accounted for a $44 million increase, and a 5 MBPD increase in equity NGL-equivalent production volumes, which accounted for an additional $26 million increase, partially offset by lower average processing margins (including the impact of hedging activities), which accounted for a $41 million decrease, and higher operating costs, which accounted for an additional $14 million decrease. Fee-based natural gas processing volumes at our Delaware Basin natural gas processing facilities increased 282 MMcf/d year-to-year, primarily due to contributions from our Mentone 3 and Mentone West 1 natural gas processing trains, which were placed into service in late first quarter of 2024 and the third quarter of 2025, respectively.

NGL pipelines, storage and terminals

Gross operating margin from our NGL pipelines, storage and terminal assets for the year ended December 31, 2025 increased $181 million when compared to the year ended December 31, 2024 .

A number of our pipelines, including the Mid-America Pipeline System, Seminole NGL Pipeline, Chaparral Pipeline, Shin Oak NGL Pipeline, and Bahia NGL Pipeline, serve Permian Basin and/or Rocky Mountain producers. On a combined basis, gross operating margin from these pipelines increased $85 million year-to-year primarily due to a 51 MBPD increase in transportation volumes, which accounted for a $55 million increase, and higher other revenues, which accounted for an additional $28 million increase.

Gross operating margin for our Eastern ethane pipelines, which include our ATEX and Aegis pipelines, increased a combined $76 million year-to-year primarily due to a 65 MBPD increase in transportation volumes, which accounted for a $49 million increase, and higher average transportation fees, which accounted for an additional $31 million increase.

Gross operating margin from LPG-related activities at EHT decreased $135 million year-to-year primarily due to lower average loading fees, which accounted for a $123 million decrease, and higher operating costs, which accounted for an additional $11 million decrease. Gross operating margin at our Morgan’s Point and Neches River Export Terminals increased a combined $60 million year-to-year primarily due to higher ethane export volumes. The combined 60 MBPD year-to-year increase in ethane export volumes at these terminals included contributions from the first phase of our Neches River export facility, which was placed into service in July 2025. Gross operating margin from our related Houston Ship Channel Pipeline System increased $11 million year-to-year primarily due to a 54 MBPD increase in transportation volumes.

Gross operating margin from our Dixie Pipeline and related terminals increased $27 million year-to-year primarily due to higher average transportation fees, which accounted for a $13 million increase, and higher loading and other fee revenues, which accounted for an additional $14 million increase. Transportation volumes on our Dixie Pipeline increased 7 MBPD year-to-year .

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Gross operating margin from our Tri-States NGL Pipeline increased $24 million year-to-year primarily due to a 9 MBPD increase in transportation volumes, which accounted for a $12 million increase, and higher average transportation fees, which accounted for an additional $7 million increase.

Gross operating margin from our Mont Belvieu area storage complex increased a net $19 million year-to-year primarily due to higher storage revenues, which accounted for a $32 million increase, partially offset by higher operating costs, which accounted for a $13 million decrease.

Gross operating margin from our South Texas NGL Pipeline System increased $14 million year-to-year primarily due to higher capacity reservation revenues, which accounted for an $8 million increase, and lower operating costs, which accounted for an additional $3 million increase. Transportation volumes on this system increased 16 MBPD year-to-year .

NGL fractionation

Gross operating margin from NGL fractionation during the year ended December 31, 2025 decreased $79 million when compared to the year ended December 31, 2024 .

Gross operating margin from our Mont Belvieu area NGL fractionation complex decreased a net $52 million year-to-year primarily due to higher operating costs, which accounted for a $51 million decrease, and lower ancillary service revenues, which accounted for an additional $37 million decrease, partially offset by higher fractionation volumes, which accounted for a $29 million increase, and higher average fractionation fees, which accounted for an additional $7 million increase. NGL fractionation volumes at our Mont Belvieu area NGL fractionation complex increased 38 MBPD primarily due to contributions fro m Frac 14, which was placed into service during the fourth quarter of 2025.

On a combined basis, gross operating margin from NGL fractionators other than our Mont Belvieu area complex decreased a net $24 million year-to-year primarily due to lower ancillary service revenues, which accounted for a $21 million decrease, and higher operating costs, which accounted for an additional $11 million decrease, partially offset by higher average fractionation fees, which accounted for an $8 million increase. NGL fractionation volumes from these NGL fractionators increased a combined 1 MBPD (net to our interest) year-to-year.

Crude Oil Pipelines & Services

The following table presents segment gross operating margin and selected volumetric data for the Crude Oil Pipelines & Services segment for the years indicated (dollars in millions, volumes as noted):

For the Year

Ended December 31,

Segment gross operating margin

Selected volumetric data:

Crude oil pipeline transportation volumes (MBPD)

Crude oil marine terminal volumes (MBPD)

Gross operating margin from our Crude Oil Pipelines & Services segment for the year ended December 31, 2025 decreased $145 million when compared to the year ended December 31, 2024 .

Gross operating margin from our Texas crude oil pipelines, related terminals and marketing activities (excluding the Seaway Pipeline) decreased a combined net $170 million year-to-year primarily due to lower average sales margins from marketing activities, which accounted for a $147 million decrease, lower mark-to-market earnings, which accounted for a $25 million decrease, lower transportation-related revenues, which accounted for a $21 million decrease, and higher operating costs, which accounted for an additional $17 million decrease, partially offset by a combined 59 MBPD (net to our interest) increase in crude oil transportation volumes, which accounted for a $48 million increase.

Gross operating margin from crude oil activities at EHT increased $29 million year-to-year primarily due to higher loading revenues, which accounted for a $15 million increase, and lower operating costs, which accounted for an additional $13 million increase. Crude oil marine terminal volumes at EHT decreased 168 MBPD year-to-year.

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Natural Gas Pipelines & Services

The following table presents segment gross operating margin and selected volumetric data for the Natural Gas Pipelines & Services segment for the years indicated (dollars in millions, volumes as noted):

For the Year

Ended December 31,

Segment gross operating margin

Selected volumetric data:

Natural gas pipeline transportation volumes (BBtus/d)

Gross operating margin from our Natural Gas Pipelines & Services segment for the year ended December 31, 2025 increased $281 million when compared to the year ended December 31, 2024 .

Gross operating margin from our Delaware Basin Gathering System, which includes the natural gas gathering system acquired in October 2024 through our acquisition of Pinon Midstream, increased a net $86 million year-to-year primarily due to higher treating and other revenues, which accounted for a $71 million increase, a 603 BBtus/d increase in natural gas gathering volumes, which accounted for a $47 million increase, and higher average gathering fees, which accounted for an additional $17 million increase, partially offset by higher operating costs, which accounted for a $49 million decrease.

Gross operating margin from our Texas Intrastate System increased a net $76 million year-to-year primarily due to higher capacity reservation fees and other revenues, which accounted for a $74 million increase, and a 255 BBtus/d increase in transportation volumes, which accounted for an additional $12 million increase, partially offset by lower average transportation fees, which accounted for a $9 million decrease.

Gross operating margin from our natural gas marketing activities increased a net $65 million year-to-year primarily due to higher average sales margins, which accounted for a $68 million increase, and higher sales volumes, which accounted for an additional $12 million increase, partially offset by lower mark-to-market earnings, which accounted for a $15 million decrease.

Gross operating margin from our Midland Basin Gathering System increased a net $31 million year-to-year primarily due to a 364 BBtus/d increase in natural gas gathering volumes, which accounted for a $51 million increase, and higher other revenues, which accounted for an additional $8 million increase, partially offset by higher operating costs, which accounted for a $28 million decrease.

Gross operating margin from our Acadian Gas System increased $18 million year-to-year primarily due to a 231 BBtus/d increase in transportation volumes.

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Petrochemical & Refined Products Services

The following table presents segment gross operating margin and selected volumetric data for the Petrochemical & Refined Products Services segment for the years indicated (dollars in millions, volumes as noted):

For the Year

Ended December 31,

Segment gross operating margin:

Propylene production and related activities

Butane isomerization and related operations

Octane enhancement and related plant operations

Refined products pipelines and related activities

Ethylene exports and related activities

Marine transportation and other services

Total

Selected volumetric data:

Propylene production volumes (MBPD)

Butane isomerization volumes (MBPD)

Standalone deisobutanizer (“DIB”) processing volumes (MBPD)

Octane enhancement and related plant sales volumes (MBPD) (1)

Pipeline transportation volumes, primarily refined products and petrochemicals (MBPD)

Marine terminal volumes, primarily refined products and petrochemicals (MBPD)

(1) Reflects aggregate sales volumes for our octane enhancement and iBDH facilities located at our Mont Belvieu area complex and our HPIB facility located adjacent to the Houston Ship Channel.

Propylene production and related activities

Gross operating margin from propylene production and related activities for the year ended December 31, 2025 decreased $49 million when compared to the year ended December 31, 2024 .

On a combined basis, gross operating margin from our Mont Belvieu area propylene production facilities decreased a net $30 million year-to-year primarily due to higher operating costs, which accounted for a $76 million decrease, and lower average propylene sales margins, which accounted for an additional $32 million decrease, partially offset by higher propylene sales volumes, which accounted for a $61 million increase, and higher other revenues, which accounted for an additional $18 million increase. Propylene and associated by-product production volumes at these facilities increased a combined 3 MBPD .

Gross operating margin from our propylene pipeline systems decreased a combined $13 million year-to-year primarily due to a 10 MBPD decrease in transportation volumes, which accounted for a $4 million decrease, lower other revenues, which accounted for a $4 million decrease and lower average transportation fees, which accounted for an additional $3 million decrease.

Butane isomerization and related operations

Gross operating margin from butane isomerization and related operations decreased a net $6 million year-to-year primarily due to higher operating costs, which accounted for an $11 million decrease, partially offset by higher ancillary service revenues, which accounted for a $7 million increase.

Octane enhancement and related plant operations

Gross operating margin from our octane enhancement and related plant operations decreased a net $142 million year-to-year primarily due to lower average sales margins, which accounted for a $126 million decrease, lower deficiency revenues, which accounted for a $30 million decrease, and higher operating costs, which accounted for an additional $5 million decrease, partially offset by higher sales volumes, which accounted for a $21 million increase.

Refined products pipelines and related activities

Gross operating margin from refined products pipelines and related activities for the year ended December 31, 2025 increased $98 million when compared to the year ended December 31, 2024 .

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Gross operating margin from our TE Products Pipeline System increased a net $61 million year-to-year primarily due to a 70 MBPD increase in transportation volumes, which accounted for a $56 million increase, higher other revenues, which accounted for a $19 million increase, and higher average transportation fees, which accounted for an additional $16 million increase, partially offset by higher operating costs, which accounted for a $30 million decrease.

Gross operating margin from o ur TW Products System increased $44 million year-to-year primarily due to the full start-up of the system, which was placed into service in stages during 2024 and was fully operational in October 2024.

Gross operating margin from our refined products marketing activities decreased $15 million year-to-year primarily due to lower average sales margins.

Ethylene exports and related activities

Gross operating margin from ethylene exports and related activities for the year ended December 31, 2025 decreased a net $20 million when compared to the year ended December 31, 2024 primarily due to lower deficiency fee revenues from our ethylene pipelines and ethylene export terminal, which accounted for a $21 million decrease, and higher operating costs, which accounted for an additional $14 million decrease, partially offset by a 4 MBPD increase in ethylene export volumes, which accounted for an $8 million increase, and higher storage and other revenues, which accounted for an additional $6 million increase.

Marine transportation and other services

Gross operating margin from marine transportation and other services increased a net $8 million year-to-year primarily due to higher average fees, which accounted for a $12 million increase, partially offset by higher operating costs, which accounted for a $5 million decrease.

Liquidity and Capital Resources

Based on current market conditions (as of the filing date of this annual report), we believe that the Partnership and its consolidated businesses will have sufficient liquidity, cash flow from operations and access to capital markets to fund their capital investments and working capital needs for the reasonably foreseeable future. At December 31, 2025 , we had $5.2 billion of consolidated liquidity. This amount was comprised of $4.2 billion of available borrowing capacity under EPO’s revolving credit facilities and $969 million of unrestricted cash on hand.

We may issue debt and equity securities to assist us in meeting our future funding and liquidity requirements, including those related to capital investments. We have a universal shelf registration statement on file with the SEC that allows the Partnership and EPO to issue an unlimited amount of equity and debt securities, respectively. In addition, we have a registration statement on file with the SEC covering the issuance of up to $2.5 billion of the Partnership’s common units in amounts, at prices and on terms based on market conditions and other factors at the time of such offerings (referred to as the Partnership’s at-the-market (“ATM”) program).

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Cash Flow Statement Highlights

The following table summarizes our consolidated cash flows from operating, investing and financing activities for the years indicated (dollars in millions).

For the Year

Ended December 31,

Net cash flow provided by operating activities

Net cash flow used in investing activities

Net cash flow used in financing activities

Net cash flow provided by operating activities are largely dependent on earnings from our consolidated business activities. Changes in energy commodity prices may impact the demand for natural gas, NGLs, crude oil, petrochemicals and refined products, which could impact sales of our products and the demand for our midstream services. Changes in demand for our products and services may be caused by other factors, including prevailing economic conditions, reduced demand by consumers for the end products made with hydrocarbon products, increased competition, public health emergencies, adverse weather conditions and government regulations affecting prices and production levels. We may also incur credit and price risk to the extent customers do not fulfill their contractual obligations to us in connection with our marketing activities and long-term take-or-pay and dedication agreements. For a more complete discussion of these and other risk factors pertinent to our business, see Part I, Item 1A of this annual report.

For additional information regarding our cash flow amounts, please refer to the Statements of Consolidated Cash Flows included under Part II, Item 8 of this annual report.

The following information highlights significant year-to-year fluctuations in our consolidated cash flow amounts:

Operating activities

Net cash flow provided by operating activities for the year ended December 31, 2025 increased $470 million when compared to the year ended December 31, 2024 primarily due to changes in operating accounts primarily due to the use of working capital employed in our marketing activities, which includes the impact of (i) fluctuations in commodity prices, (ii) timing of our inventory purchase and sale strategies, and (iii) changes in margin deposit requirements associated with our commodity derivative instruments.

For information regarding significant year-to-year changes in our consolidated net income and underlying segment results, see “ Income Statement Highlights ” and “ Business Segment Highlights ” within this Part II, Item 7.

Investing activities

Net cash flow used in investing activities for the year ended December 31, 2025 increased a net $58 million when compared to the year ended December 31, 2024 primarily due to:

• a $1.1 billion year-to-year increase in investments for property, plant and equipment (see “ Capital Investments ” within this Part II, Item 7 for additional information); partially offset by

• a net $949 million cash outflow in October 2024 in connection with the acquisition of Pinon Midstream; and

• a $68 million increase in proceeds from asset sales and other matters primarily attributable to the $60 million first installment payment received in December 2025 related to our sale of a 40% undivided joint interest in the Bahia NGL Pipeline.

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Financing activities

Net cash flow used in financing activities for the year ended December 31, 2025 increased a net $523 million when compared to the year ended December 31, 2024 primarily due to:

• a net cash inflow of $2.5 billion related to debt transactions that occurred during the year ended December 31, 2025 compared to a net cash inflow of $3.1 billion related to debt transactions that occurred during the year ended December 31, 2024 . In 2025 , we issued $3.65 billion aggregate principal amount of senior notes, partially offset by the repayment of $1.15 billion principal amount of senior notes. In 2024 we issued $4.5 billion aggregate principal amount of senior notes, partially offset by the repayment of $850 million principal amount of senior notes and net repayments of $450 million under EPO’s commercial paper program;

• a $166 million year-to-year increase in cash distributions paid to common unitholders primarily attributable to increases in the quarterly cash distribution rate per unit;

• an $81 million year-to-year increase in the repurchase of common units under the 2019 Buyback Program; partially offset by

• a $400 million cash outflow during the first quarter of 2024 in connection with the acquisition of noncontrolling interests from affiliates of Western Midstream Partners, LP.

Non-GAAP Cash Flow Measures

Distributable Cash Flow and Operational Distributable Cash Flow

Our partnership agreement requires us to make quarterly distributions to our common unitholders of all available cash, after any cash reserves established by Enterprise GP in its sole discretion. Cash reserves include those for the proper conduct of our business, including those for capital investments, debt service, working capital, operating expenses, common unit repurchases, commitments and contingencies and other amounts. The retention of cash allows us to reinvest in our growth and reduce our future reliance on the equity and debt capital markets.

We measure available cash by reference to distributable cash flow (“DCF”), which is a non-GAAP cash flow measure. DCF is an important financial measure for our common unitholders since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flows at a level that can sustain our declared quarterly cash distributions. DCF is also a quantitative standard used by the investment community with respect to publicly traded partnerships since the value of a partnership unit is, in part, measured by its yield, which is based on the amount of cash distributions a partnership can pay to a unitholder. Our management compares the DCF we generate to the cash distributions we expect to pay our common unitholders. Using this metric, management computes our distribution coverage ratio. Our calculation of DCF may or may not be comparable to similarly titled measures used by other companies.

Based on the level of available cash each quarter, management proposes a quarterly cash distribution rate to the Board, which has sole authority in approving such matters. Enterprise GP has a non-economic ownership interest in the Partnership and is not entitled to receive any cash distributions from it based on incentive distribution rights or other equity interests.

Operational distributable cash flow (“Operational DCF”), which is defined as DCF excluding the impact of proceeds from asset sales and other matters and monetization of interest rate derivative instruments, is a supplemental non-GAAP liquidity measure that quantifies the portion of cash available for distribution to common unitholders that was generated from our normal operations. We believe that it is important to consider this non-GAAP measure as it provides an enhanced perspective of our assets’ ability to generate cash flows without regard for certain items that do not reflect our core operations.

Our use of DCF and Operational DCF for the limited purposes described above and in this report is not a substitute for net cash flow provided by operating activities, which is the most comparable GAAP measure to DCF and Operational DCF. For a discussion of net cash flow provided by operating activities, see “ Cash Flow Statement Highlights ” within this Part II, Item 7.

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The following table summarizes our calculation of DCF and Operational DCF for the years indicated (dollars in millions):

For the Year

Ended December 31,

Net income attributable to common unitholders (GAAP) (1)

Adjustments to net income attributable to common unitholders to derive DCF and Operational DCF (addition or subtraction indicated by sign):

Depreciation, amortization and accretion expenses

Cash distributions received from unconsolidated affiliates (2)

Equity in income of unconsolidated affiliates

Asset impairment charges

Change in fair market value of derivative instruments

Deferred income tax expense

Sustaining capital expenditures (3)

Other, net

Operational DCF (non-GAAP)

Proceeds from asset sales and other matters

Monetization of interest rate derivative instruments accounted for as cash flow hedges

DCF (non-GAAP)

Cash distributions paid to common unitholders with respect to period, including distribution equivalent rights on phantom unit awards

Cash distribution per common unit declared by Enterprise GP with respect to period (4)

Total DCF retained by the Partnership with respect to period (5)

Distribution coverage ratio (6)

(1) For a discussion of the primary drivers of changes in our comparative income statement amounts, see “ Income Statement Highlights ” within this Part II, Item 7.

(2) Reflects aggregate distributions received from unconsolidated affiliates attributable to both earnings and the return of capital.

(3) Sustaining capital expenditures include cash payments and accruals applicable to the period.

(4) See Note 8 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report for information regarding our quarterly cash distributions declared with respect to the years indicated.

(5) Cash retained by the Partnership may be used for capital investments, debt service, working capital, operating expenses, common unit repurchases, commitments and contingencies and other amounts. The retention of cash reduces our reliance on the capital markets.

(6) Distribution coverage ratio is determined by dividing DCF by total cash distributions paid to common unitholders and in connection with distribution equivalent rights with respect to the period.

The following table presents a reconciliation of net cash flow provided by operating activities to DCF and Operational DCF for the years indicated (dollars in millions):

For the Year

Ended December 31,

Net cash flow provided by operating activities (GAAP)

Adjustments to reconcile net cash flow provided by operating activities to DCF and Operational DCF (addition or subtraction indicated by sign):

Net effect of changes in operating accounts

Sustaining capital expenditures

Distributions received from unconsolidated affiliates attributable to the return of capital

Net income attributable to noncontrolling interests

Other, net

Operational DCF (non-GAAP)

Proceeds from asset sales and other matters

Monetization of interest rate derivative instruments accounted for as cash flow hedges

DCF (non-GAAP)

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Capital Investments

Since the beginning of 2025, we have placed into service two natural gas processing trains in the Permian Basin, the first phase of our Neches River Ethane / Propane Export Facility, an NGL fractionator (“Frac 14”) and associated DIB unit at our Mont Belvieu area NGL fractionation complex, the Bahia NGL Pipeline and the second phase of enhancements at our Morgan’s Point terminal. We have approximately $4.8 billion of growth capital projects scheduled to be completed by the end of 2027, including the following projects (including their respective scheduled completion dates):

• natural gas gathering, compression and treating expansion projects in the Delaware and Midland Basins (2026 and 2027);

• our second natural gas processing train at our Mentone West location in the Delaware Basin (first quarter of 2026);

• the second phase of our Neches River Ethane / Propane Export Facility located in Orange County, Texas (first half of 2026);

• the expansion of our LPG export capacity at EHT, including Ref 4 (fourth quarter of 2026);

• a ninth natural gas processing train (“Athena”) in the Midland Basin (fourth quarter of 2026); and

• the expansion and extension of the Bahia NGL Pipeline (fourth quarter of 2027).

Based on information currently available, we expect our total organic capital investments for 2026 , net of contributions from noncontrolling interests, to approximate $3.1 billion to $3.5 billion, which reflects organic growth capital investments of $2.5 billion to $2.9 billion and sustaining capital expenditures of $580 million. In addition, we expect approximately $600 million in cash proceeds from asset sales and other matters during 2026, primarily from the second installment payment received in January 2026 related to the sale of a 40% undivided joint interest in our Bahia NGL Pipeline, which may be used to offset a portion of our forecasted organic growth capital investments.

Our forecast of capital investments is dependent upon our ability to generate the required funds from either operating cash flows or other means, including borrowings under debt agreements, the issuance of additional equity and debt securities, and potential divestitures. We may revise our forecast of capital investments due to factors beyond our control, such as adverse economic conditions, weather-related issues and changes in supplier prices resulting from raw material or labor shortages, supply chain disruptions or inflation. Furthermore, our forecast of capital investments may change over time based on future decisions by management, which may include changing the scope or timing of projects or cancelling projects altogether. Our success in raising capital, having the ability to increase revenues commensurate with cost increases and our ability to partner with other companies to share project costs and risks continue to be significant factors in determining how much capital we can invest. We believe our access to capital resources is sufficient to meet the demands of our current and future growth needs, and although we currently expect to make the forecast capital investments noted above, we may revise our plans in response to changes in economic and capital market conditions.

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The following table summarizes our capital investments for the years indicated (dollars in millions):

For the Year

Ended December 31,

Capital investments: (1)

Growth capital projects (2)

Sustaining capital projects (3)

Asset acquisitions (4)

Total

Cash used for business combinations, net of cash received (5)

(1) Growth and sustaining capital amounts presented in the table above are presented on a cash basis. In total, these amounts represent “Capital expenditures” as presented on our Statements of Consolidated Cash Flows.

(2) Growth capital projects either (a) result in new sources of cash flow due to enhancements of or additions to existing assets (e.g., additional revenue streams, cost savings resulting from debottlenecking of a facility, etc.) or (b) expand our asset base through construction of new facilities that will generate additional revenue streams and cash flows.

(3) Sustaining capital projects are capital expenditures (as defined by GAAP) resulting from improvements to existing assets. Such expenditures serve to maintain existing operations but do not generate additional revenues or result in significant cost savings. Sustaining capital expenditures include the costs of major maintenance activities at our reaction-based plants, which are accounted for using the deferral method.

(4) Amount for the year ended December 31, 2025 primarily represents the total cost of the acquisition of the Oxy natural gas gathering affiliate, which closed in August 2025. For additional information, see Note 12 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

(5) Amount for the year ended December 31, 2024 represents net cash used for the acquisition of Pinon Midstream, which closed in October 2024. For additional information, see Note 12 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Comparison of Year Ended December 31, 2025 with Year Ended December 31, 2024

In total, investments in growth capital projects increased a net $503 million year-to-year primarily due to the following:

• higher investments in our Bahia NGL Pipeline (placed into service in December 2025), which accounted for a $393 million increase;

• higher investments in the construction of natural gas processing trains and related gathering system expansions in the Delaware and Midland Basins, which accounted for an additional $343 million increase; partially offset by

• lower investments in our TW Products System (placed into service in phases during 2024), which accounted for a $158 million decrease.

Investments attributable to sustaining capital projects decreased $59 million year-to-year primarily due to lower major maintenance activities performed at certain of our reaction-based plants (e.g., our PDH 1 and iBDH facilities) and fluctuations in timing and costs of pipeline integrity and similar projects.

Consolidated Debt

At December 31, 2025 , the average maturity of EPO’s consolidated debt obligations was approximately 16.8 years. The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations and associated estimated cash payments for interest at December 31, 2025 for the years indicated (dollars in millions):

Total

Thereafter

Principal amount of debt obligations

Estimated cash payments for interest (1)

(1) Estimated cash payments for interest are based on the principal amount of our consolidated debt obligations outstanding at December 31, 2025, the contractually scheduled maturities of such balances, and the applicable interest rates. Our estimated cash payments for interest are influenced by the long-term maturities of our $2.3 billion in junior subordinated notes (due June 2067 through February 2078). The estimated cash payments assume that (i) the junior subordinated notes are not repaid prior to their respective maturity dates and (ii) the amount of interest paid on the junior subordinated notes is based on either (a) the current fixed interest rate charged or (b) the weighted-average variable rate paid in 2025, as applicable, for each note through the respective maturity date.

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In March 2025, EPO entered into a new 364-Day Revolving Credit Agreement (the “March 2025 $1.5 Billion 364-Day Revolving Credit Agreement”) that replaced its prior 364-day revolving credit agreement. The March 2025 $1.5 Billion 364-Day Revolving Credit Agreement matures in March 2026. EPO expects to renew this credit agreement during the first quarter of 2026. As of December 31, 2025 , there are no principal amounts outstanding under this new revolving credit agreement.

Also in March 2025, EPO amended its Multi-Year Revolving Credit Agreement (the “March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement”) to extend its maturity date from March 2028 to March 2030. The remaining material terms of the March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement, as amended, remain unchanged. As of December 31, 2025 , there are no principal amounts outstanding under this revolving credit agreement.

In June 2025, EPO issued $2.0 billion aggregate principal amount of senior notes comprised of (i) $500 million principal amount of senior notes due June 2028 (“Senior Notes LLL”), (ii) $750 million principal amount of senior notes due January 2031 (“Senior Notes MMM”) and (iii) $750 million principal amount of senior notes due January 2036 (“Senior Notes NNN”). Senior Notes LLL were issued at 99.869% of their principal amount and have a fixed interest rate of 4.30% per year. Senior Notes MMM were issued at 99.816% of their principal amount and have a fixed interest rate of 4.60% per year. Senior Notes NNN were issued at 99.665% of their principal amount and have a fixed interest rate of 5.20% per year. Net proceeds from this offering were used by EPO for general company purposes, including for growth capital investments, and the repayment of amounts outstanding under our commercial paper program.

In November 2025, EPO issued $1.65 billion aggregate principal amount of senior notes comprised of (i) $300 million principal amount of reopened Senior Notes LLL, (ii) $600 million principal amount of reopened Senior Notes MMM and (iii) $750 million principal amount of reopened Senior Notes NNN. The reopened Senior Notes LLL, reopened Senior Notes MMM and reopened Senior Notes NNN were issued at 100.630%, 100.693% and 101.185% of their respective principal amounts, plus accrued interest from June 20, 2025. Each of the reopened Senior Notes LLL, the reopened Senior Notes MMM and the reopened Senior Notes NNN constitutes a further issuance of, and forms a single series with, the original notes of the corresponding series issued in June 2025, trades under the same CUSIP number as the applicable original notes, and has the same terms as to interest, status, redemption or otherwise as such original notes. Net proceeds from this offering were used by EPO for general company purposes, including for growth capital investments and acquisitions, and the repayment of debt (including the repayment of all or a portion of $750 million principal amount of 5.05% Senior Notes FFF that matured in January 2026, $875 million principal amount of 3.70% Senior Notes PP that matured in February 2026 and amounts outstanding under our commercial paper program).

For additional information regarding our consolidated debt obligations, see Note 7 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Credit Ratings

As of February 27, 2026 , the investment-grade credit ratings of EPO’s long-term senior unsecured debt securities were A- from Standard and Poor’s, A3 from Moody’s and A- from Fitch Ratings. In addition, the credit ratings of EPO’s short-term senior unsecured debt securities were A-2 from Standard and Poor’s, P-2 from Moody’s and F-2 from Fitch Ratings. EPO’s credit ratings reflect only the view of a rating agency and should not be interpreted as a recommendation to buy, sell or hold any of our securities. A credit rating can be revised upward or downward or withdrawn at any time by a rating agency, if it determines that circumstances warrant such a change. A credit rating from one rating agency should be evaluated independently of credit ratings from other rating agencies.

Product Purchase Commitments

The following table presents our unconditional product purchase commitments at December 31, 2025 for the years indicated (dollars in millions):

Total

Thereafter

Product purchase commitments

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We have unconditional, long-term product purchase commitments for NGLs and crude oil with third party suppliers. The prices that we are obligated to pay under these contracts approximate market prices at the time we take delivery of the volumes. The preceding table presents our estimated future payment obligations under these contracts based on the contractual price in each agreement at December 31, 2025 applied to all future volume commitments. Actual future payment obligations may vary depending on prices at the time of delivery.

For additional information regarding our product purchase commitments, see Note 17 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Enterprise Declares Cash Distribution for Fourth Quarter of 2025

On January 8, 2026 , we announced that the Board declared a quarterly cash distribution of $0.55 per common unit, or $2.20 per common unit on an annualized basis, to be paid to the Partnership’s common unitholders with respect to the fourth quarter of 2025 . The quarterly distribution was paid on February 13, 2026 to unitholders of record as of the close of business on January 30, 2026 . The total amount paid was $1.2 billion , which includes $11 million for distribution equivalent rights on phantom unit awards.

The payment of quarterly cash distributions is subject to management’s evaluation of our financial condition, results of operations and cash flows in connection with such payments and Board approval. Management will evaluate any future increases in cash distributions on a quarterly basis.

Common Unit Repurchases Under 2019 Buyback Program

In January 2019, we announced that the Board had approved a $2.0 billion multi-year unit buyback program (the “2019 Buyback Program”), which provides the Partnership with an additional method to return capital to investors. In October 2025, we announced that the Board approved an increase to the authorized maximum aggregate purchase price (excluding fees, commissions and other ancillary expenses) of the Partnership’s common units that may be repurchased under the 2019 Buyback Program from $2.0 billion to $5.0 billion. The 2019 Buyback Program authorizes the Partnership to repurchase its common units from time to time, including through open market purchases and negotiated transactions. The timing and pace of buy backs under the program will be determined by a number of factors including (i) our financial performance and flexibility, (ii) organic growth and acquisition opportunities with higher potential returns on investment, (iii) the market price of the Partnership’s common units and implied cash flow yield and (iv) maintaining targeted financial leverage, which is currently a debt-to-normalized adjusted EBITDA (earnings before interest, taxes, depreciation and amortization) ratio in the range of 2.75 to 3.25 times. No time limit has been set for completion of the 2019 Buyback Program, and it may be suspended or discontinued at any time.

The Partnership repurchased an aggregate 9,496,536 common units under the 2019 Buyback Program during the year ended December 31, 2025 . The total cost of these repurchases, including commissions and fees, was $300 million . Common units repurchased under the 2019 Buyback Program are immediately cancelled upon acquisition. As of December 31, 2025 , the remaining available capacity under the 2019 Buyback Program was $3.6 billion.

Critical Accounting Policies and Estimates

In our financial reporting processes, we employ methods, estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of our financial statements. These methods, estimates and assumptions also affect the reported amounts of revenues and expenses for each reporting period. Investors should be aware that actual results could differ from these estimates if the underlying assumptions prove to be incorrect. The following sections discuss the use of estimates within our critical accounting policies:

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Depreciation Methods and Estimated Useful Lives of Property, Plant and Equipment

In general, depreciation is the systematic and rational allocation of an asset’s cost, less its residual value (if any), to the periods it benefits. The majority of our property, plant and equipment is depreciated using the straight-line method, which results in depreciation expense being incurred evenly over the life of an asset. Depreciation expense incorporates management estimates regarding the useful economic lives and residual values of our assets. At the time we place our assets into service, we believe such assumptions are reasonable; however, circumstances may develop that cause us to change these assumptions, which would change our depreciation amounts prospectively. Examples of such circumstances include (i) changes in laws and regulations that limit the estimated economic life of an asset, (ii) changes in technology that render an asset obsolete, (iii) changes in expected salvage values or (iv) significant changes in our forecast of the remaining life for the associated resource basins, if applicable.

At December 31, 2025 and 2024 , the net carrying value of our property, plant and equipment was $51.4 billion and $49.1 billion , respectively. We recorded $2.1 billion and $2.0 billion of depreciation expense during the years ended December 31, 2025 and 2024 , respectively. For information regarding our property, plant and equipment, see Note 4 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Measuring Recoverability of Long-Lived Assets and Fair Value of Equity Method Investments

Long-lived assets, which consist of intangible assets with finite useful lives and property, plant and equipment, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Examples of such events or changes might be production declines that are not replaced by new discoveries or long-term decreases in the demand for or price of natural gas, NGLs, crude oil, petrochemicals or refined products.

The carrying value of a long-lived asset is deemed not recoverable if it exceeds the sum of undiscounted estimated cash flows expected to result from the use and eventual disposition of the asset. Estimates of undiscounted cash flows are based on a number of assumptions including anticipated operating margins and volumes; estimated useful life of the asset or asset group; and estimated residual values. If the carrying value of a long-lived asset is not recoverable, an impairment charge would be recorded for the excess of the asset’s carrying value over its estimated fair value, which is derived from an analysis of the asset’s estimated future discounted cash flows, the market value of similar assets and replacement cost of the asset less any applicable depreciation or amortization. In addition, fair value estimates also include the usage of probabilities when there is a range of possible outcomes.

We evaluate our equity method investments for impairment when there are events or changes in circumstances that indicate there is a potential loss in value of the investment attributable to an other-than-temporary decline. Examples of such events or changes in circumstances include continuing operating losses of the entity and/or long-term negative changes in the entity’s industry. In the event we determine that the value of an investment is not recoverable due to an other-than-temporary decline, we record a non-cash impairment charge to adjust the carrying value of the investment to its estimated fair value. We assess the fair value of our equity method investments using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party sales and discounted estimated cash flow models. Estimates of discounted cash flows are based on a number of assumptions including discount rates; probabilities assigned to different cash flow scenarios; anticipated margins and volumes and estimated useful lives of the investment’s underlying assets.

A significant change in the assumptions we use to measure recoverability of long-lived assets and the fair value of equity method investments could result in our recording a non-cash impairment charge. Any write-down of the carrying values of such assets would increase operating costs and expenses at that time.

In 2025 and 2024 , we recognized non-cash asset impairment charges attributable to assets other than goodwill totaling $50 million and $57 million , respectively. For information regarding impairment charges involving property, plant and equipment see Note 4 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. We did not recognize any impairment charges in connection with our equity-method investments during the years ended December 31, 2025 and December 31, 2024 .

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Amortization Methods of Customer Relationships and Contract-Based Intangible Assets

The specific, identifiable intangible assets of an acquired business depend largely upon the nature of its operations and include items such as customer relationships and contracts.

Customer relationship intangible assets represent the estimated economic value assigned to commercial relationships acquired in connection with business combinations. In certain instances, the acquisition of these intangible assets provides us with access to customers in a defined resource basin and is analogous to having a franchise in a particular area. Efficient operation of the acquired assets (e.g., a natural gas gathering system) helps to support the commercial relationships with existing producers and provides us with opportunities to establish new ones within our existing asset footprint. The duration of this type of customer relationship is limited by the estimated economic life of the associated resource basin that supports the customer group. When estimating the economic life of a resource basin, we consider a number of factors, including reserve estimates and the economic viability of production and exploration activities.

In other situations, the acquisition of a customer relationship intangible asset provides us with access to customers whose hydrocarbon volumes are not attributable to specific resource basins. As with basin-specific customer relationships, efficient operation of the associated assets (e.g., a marine terminal that handles volumes originating from multiple sources) helps to support the commercial relationships with existing customers and provides us with opportunities to establish new ones. The duration of this type of customer relationship is typically limited to the term of the underlying service contracts, including assumed renewals.

The value we assign to customer relationships is amortized to earnings using methods that closely resemble the pattern in which the estimated economic benefits will be consumed (i.e., the manner in which the intangible asset is expected to contribute directly or indirectly to our cash flows). For example, the amortization period for a basin-specific customer relationship asset is limited by the estimated finite economic life of the associated hydrocarbon resource basin.

Contract-based intangible assets represent specific commercial rights we own arising from discrete contractual agreements. A contract-based intangible asset with a finite life is amortized over its estimated economic life, which is the period over which the contract is expected to contribute directly or indirectly to our cash flows. Our estimates of the economic life of contract-based intangible assets are based on a number of factors, including (i) the expected useful life of the related tangible assets (e.g., a marine terminal, pipeline or other asset), (ii) any legal or regulatory developments that would impact such contractual rights and (iii) any contractual provisions that enable us to renew or extend such arrangements.

If our assumptions regarding the estimated economic life of an intangible asset were to change, then the amortization period for such asset would be adjusted accordingly. Changes in the estimated useful life of an intangible asset would impact operating costs and expenses prospectively from the date of change.

At December 31, 2025 and 2024 , the carrying value of our customer relationship and contract-based intangible asset portfolio was $4.2 billion and $4.0 billion , respectively. We recorded $216 million and $207 million of amortization expense attributable to intangible assets during the years ended December 31, 2025 and 2024 , respectively. For information regarding our intangible assets, see Note 6 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Methods We Employ to Measure the Fair Value of Goodwill and Related Assets

Our goodwill balance was $5.7 billion at December 31, 2025 and 2024 . Goodwill, which represents the cost of an acquired business in excess of the fair value of its net assets at the acquisition date, is subject to annual impairment testing in the fourth quarter of each year or when events or changes in circumstances indicate that the carrying amount of the goodwill may not be recoverable. Goodwill impairment charges represent the amount by which a reporting unit’s carrying value (including its respective goodwill) exceeds its fair value, not to exceed the carrying amount of the reporting unit’s goodwill.

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We determine the fair value of each reporting unit using accepted valuation techniques, primarily through the use of discounted cash flows (i.e., an income approach to fair value) supplemented by market-based assessments, if available. The estimated fair values of our reporting units incorporate assumptions regarding the future economic prospects of the assets and operations that comprise each reporting unit including: (i) discrete financial forecasts for the assets comprising the reporting unit, which, in turn, rely on management’s estimates of long-term operating margins, throughput volumes, capital investments and similar factors; (ii) long-term growth rates for the reporting unit’s cash flows beyond the discrete forecast period; and (iii) appropriate discount rates. The fair value estimates are based on Level 3 inputs of the fair value hierarchy. We believe that the assumptions we use in estimating reporting unit fair values are consistent with those that market participants would use in their fair value estimation process. However, due to uncertainties in the estimation process and volatility in the supply and demand for hydrocarbons and similar risk factors, actual results could differ significantly from our estimates.

We did not record any goodwill impairment charges during the year ended December 31, 2025 . Based on our most recent goodwill impairment test at December 31, 2025 , the estimated fair value of each of our reporting units was substantially in excess of its carrying value (i.e., by at least 10%).

For information regarding our goodwill, see Note 6 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Use of Estimates for Revenues and Expenses

As noted previously, preparing our consolidated financial statements in conformity with GAAP requires us to make estimates that affect amounts presented in the financial statements. Due to the time required to compile actual billing information and receive third party data needed to record transactions, we routinely employ estimates in connection with revenue and expense amounts in order to meet our accelerated financial reporting deadlines.

Our most significant routine estimates involve revenues and costs of certain natural gas processing facilities, pipeline transportation revenues, fractionation revenues, marketing revenues and related purchases, and power and utility costs. These types of transactions must be estimated since the actual amounts are generally unavailable at the time we complete our accounting close process. The estimates subsequently reverse in the next accounting period when the corresponding actual customer billing or vendor-invoiced amounts are recorded.

Changes in facts and circumstances may result in revised estimates, which could affect our reported financial statements and accompanying disclosures. Prior to issuing our financial statements, we review our revenue and expense estimates based on currently available information to determine if adjustments are required.

Other Matters

Parent-Subsidiary Guarantor Relationship

The Partnership (the “Parent Guarantor”) has guaranteed the payment of principal and interest on the consolidated debt obligations of EPO (the “Subsidiary Issuer”) (collectively, the “Guaranteed Debt”). If EPO were to default on any of its Guaranteed Debt, the Partnership would be responsible for full and unconditional repayment of such obligations. At December 31, 2025 , the total amount of Guaranteed Debt was $35.3 billion , which was comprised of $32.4 billion of EPO’s senior notes, $2.3 billion of EPO’s junior subordinated notes and $566 million of related accrued interest.

The Partnership’s guarantees of EPO’s senior note obligations, commercial paper notes and borrowings under bank credit facilities represent unsecured and unsubordinated obligations of the Partnership that rank equal in right of payment to all other existing or future unsecured and unsubordinated indebtedness of the Partnership. In addition, these guarantees effectively rank junior in right of payment to any existing or future indebtedness of the Partnership that is secured and unsubordinated, to the extent of the assets securing such indebtedness.

The Partnership’s guarantees of EPO’s junior subordinated notes represent unsecured and subordinated obligations of the Partnership that rank equal in right of payment to all other existing or future subordinated indebtedness of the Partnership and senior in right of payment to all existing or future equity securities of the Partnership. The Partnership’s guarantees of EPO’s junior subordinated notes effectively rank junior in right of payment to (i) any existing or future indebtedness of the Partnership that is secured, to the extent of the assets securing such indebtedness and (ii) all other existing or future unsecured and unsubordinated indebtedness of the Partnership.

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The Partnership may be released from its guarantee obligations only in connection with EPO’s exercise of its legal or covenant defeasance options as described in the underlying agreements.

Selected Financial Information of Obligor Group

The following tables present summarized financial information of the Partnership (as Parent Guarantor) and EPO (as Subsidiary Issuer) on a combined basis (collectively, the “Obligor Group”), after the elimination of intercompany balances and transactions among the Obligor Group.

In accordance with Rule 13.01 of Regulation S-X, the summarized financial information of the Obligor Group excludes the Obligor Group’s equity in income and investments in the consolidated subsidiaries of EPO that are not party to the guarantee obligations (the “Non-Obligor Subsidiaries”). The total carrying value of the Obligor Group’s investments in the Non-Obligor Subsidiaries was $54.9 billion at December 31, 2025 . The Obligor Group’s equity in the earnings of the Non-Obligor Subsidiaries for the year ended December 31, 2025 was $6.9 billion . Although the net assets and earnings of the Non-Obligor Subsidiaries are not directly available to the holders of the Guaranteed Debt to satisfy the repayment of such obligations, there are no significant restrictions on the ability of the Non-Obligor Subsidiaries to pay distributions or make loans to EPO or the Partnership. EPO exercises control over the Non-Obligor Subsidiaries. We continue to believe that the consolidated financial statements of the Partnership presented under Item 8 of this annual report provide a more appropriate view of our credit standing. Our investment grade credit ratings are based on the Partnership’s consolidated financial statements and not the Obligor Group’s financial information presented below.

The following table presents summarized balance sheet information for the combined Obligor Group at December 31, 2025 (dollars in millions):

Selected asset information:

Current receivables from Non-Obligor Subsidiaries

Other current assets

Long-term receivables from Non-Obligor Subsidiaries

Other noncurrent assets, excluding investments in Non-Obligor Subsidiaries of $54.9 billion

Selected liability information:

Current portion of Guaranteed Debt, including interest of $566 million

Current payables to Non-Obligor Subsidiaries

Other current liabilities

Noncurrent portion of Guaranteed Debt, principal only

Noncurrent payables to Non-Obligor Subsidiaries

Other noncurrent liabilities

Mezzanine equity of Obligor Group:

Preferred units

The following table presents summarized income statement information for the combined Obligor Group for the year ended December 31, 2025 (dollars in millions):

Revenues from Non-Obligor Subsidiaries

Revenues from other sources

Operating income of Obligor Group

Net loss of Obligor Group excluding equity in earnings of Non-Obligor Subsidiaries of $6.9 billion

Related Party Transactions

For information regarding our related party transactions, see Note 15 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report as well as Part III, Item 13 of this annual report.

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Income Taxes

During 2021, 2022 and 2024, the Internal Revenue Service (“IRS”) issued a Notice of Selection for Examination to EPO and the Partnership, respectively, stating that the IRS selected their 2019, 2020 and 2021 partnership tax returns for examination. These are routine compliance examinations of various items of income, gain, deductions, losses and credits of EPO and the Partnership during the years under examination.

Insurance

For information regarding insurance matters, see Note 18 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.