EPD 10-K & 10-Q changes, risk factors and insider trading
Enterprise Products Partners L.p. (also EPDU) · NYSE · Natural Gas Transmission · CIK 1061219 · All filings on SEC.gov
At a glance
What changed in the latest 10-K
Risk Factors
New heading “Changes in U.S. trade policy and the impact of tariffs may have a material adverse effect on our business and results of operations.”
Removed heading “Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.”
Largest changes
“•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;”see in full comparison
“Changes in U.S. trade policy and the impact of tariffs may have a material adverse effect on our business and results of operations.”see in full comparison
“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. …”see in full comparison
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.see in full comparisonThe Infrastructure Investment and Jobs Act passed in November 2021 provides for, among other things, $7.5 billion to build out a national network of electric vehicle (“EV”) chargers in the U.S., as part of a plan to accelerate the adoption of EVs, as well as funding for electric school buses and low- and no-emission buses for public transit. The Inflation Reduction Act of 2022 passed in August 2022 includes multiple additional incentives to promote clean energy, EVs, and battery and energy storage as well as imposes a first-time fee on the emission of methane from sources required to report their greenhouse gas emissions under the EPA’s Greenhouse Gas Reporting Program Part 98 (Subpart W) regulations starting in 2024.Variousotherpolicies and approaches, including establishing a cap on emissions, requiring efficiency measures, or providing incentives forpollutionemissions reduction, use of renewable energy sources, or use of replacement fuels with lower carboncontentcontent,arehaveunderbeendiscussionconsidered andhavecouldresulted, and may continue to result,result in additional actions involving greenhouse gases.
“Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.”see in full comparison
“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. …”see in full comparison
Full comparison: every changed paragraph (81)
•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.
•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.
•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.
•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.
•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.
TheGlobal 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 hasby generally recovered from the negative economic impacts of the COVID-19 pandemic, which disrupteddisrupting global supply chains, reducedreducing consumer activity, disruptedlimiting travel and createdcreating significant volatility and disruption of financial and commodity markets. While the World Health Organization declared an end to the global public health emergency for COVID-19 in May 2023, aA 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.
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.
•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
•we may be more vulnerable to adverse economic and industry conditions as a result of our significant debt level.
We will require substantial new capital to finance the future development and acquisition of assets and businesses. For example, our capital investments for 20242025 reflected $5.5$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 2025,2026, net of contributions from jointnoncontrolling venture partners,interests, to approximate $4.5$3.1 billion to $5.0$3.5 billion, which includes organic growth capital projectsinvestments of $4.0$2.5 billion to $4.5$2.9 billion and sustaining capital expenditures of $525$580 million. These amounts do not include capital investments associated with our proposed deep-water offshore crude oil terminal (the Sea Port Oil Terminal or “SPOT”), which remains subject to a final investment decision. 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.
•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.
•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.
We rely on our IT and OT systems to conduct our business,systems, as well as systems of third-party vendors.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.
Management's Discussion & Analysis (MD&A)
New heading “Enterprise Announces Increase to 2019 Buyback Program”
New heading “Enterprise Acquires Oxy Affiliate, Enters into Service Agreements, and Expands Midland Basin Processing Capacity”
New heading “Enterprise Begins Initial Service at Neches River Ethane / Propane Export Facility”
New heading “Enterprise Begins Service at Mentone West 1 and Orion”
New heading “Operating costs and expenses”
New heading “General and administrative costs”
New heading “Equity in income of unconsolidated affiliates”
New heading “Operating income”
New heading “Interest expense”
Removed heading “Issuance of $2.5 Billion of Senior Notes in August 2024”
Removed heading “Enterprise to Expand LPG Export Capacity at EHT”
Removed heading “Enterprise to Build Mentone West 2; Mentone 3 and Leonidas Begin Service”
Removed heading “Enterprise Begins Service on TW Products System”
Removed heading “Enterprise Acquires Equity Interests from Western Midstream”
Removed heading “Asset impairment charges”
Largest changes
“Geopolitical conflicts can also impact hydrocarbon supply and demand. Sanctions imposed on Russia following its February 2022 invasion of Ukraine have largely been circumvented over time through the use of alternative trade routes to willing buyers. This evasion has led the U.S. Treasury Department to increase pressure on Russian energy revenue by imposing sanctions in January 2025 on certain oil-carrying vessels, Russian-based oilfield services providers and Russian energy officials. …”see in full comparison
Inflation rates in thesee in full comparisonU.S.U.S.,increasedwhichsignificantlyare 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 in2022futureand remained elevated in 2024 compared to recent historical levels. While pandemic-era supply chain disruptions have largely dissipated and measures taken by the U.S. Federal Reserve Bank helped slow the growth of inflation, the high-cost environment that began in 2022 generally remained intact in 2024.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.
“Global economic growth is arguably the most significant factor influencing overall hydrocarbon supply and demand. In its January 2025 World Economic Outlook, the International Monetary Fund (“IMF”) projected global growth at 3.3% for both 2025 and 2026. Growth in the U.S. is expected to be 2.7% in 2025 as underlying consumer demand remains robust, reflecting strong wealth effects, less restrictive monetary policy and supportive financial conditions. …”see in full comparison
“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. …”see in full comparison
“•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. …”see in full comparison
Full comparison: every changed paragraph (184)
•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 level of services we provide and the amount of volumeshydrocarbons we purchase and sell arecontinue affectedto be driven by changes in supply and demand fundamentals for hydrocarbon products. These fundamentalsdynamics impactaffect our financial position, results of operations and cash flows. DuringEntering 2024,2026, global liquid hydrocarbon supplymarkets andhave demandshifted wereinto relativelya balancedmodest surplus as crude oil production cuts maintained by members of the Organizationnon-Organization of the Petroleum Exporting Countries (“OPECnon-OPEC”) supply growth, together with the scheduled easing of OPEC and Russia (collectively, the “OPEC+” group) helpedproduction offsetcuts, increasedhave productioncontributed to inventory builds and placed downward pressure on liquid hydrocarbon prices relative to levels inseen theduring United States, Canada2024 and South America. Although crude oil prices were relatively stable and natural gas prices reflected some upward momentum in 2024, our Current Outlook acknowledges several factors that could affect the near-term balance in supply and demand.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.
Global economic growth is arguably the most significant factor influencing overall hydrocarbon supply and demand. In its January 2025 World Economic Outlook, the International Monetary Fund (“IMF”) projected global growth at 3.3% for both 2025 and 2026. Growth in the U.S. is expected to be 2.7% in 2025 as underlying consumer demand remains robust, reflecting strong wealth effects, less restrictive monetary policy and supportive financial conditions. In Europe, growth in 2025 is expected to accelerate but at a gradual pace of 1.0% with geopolitical tensions weighing on sentiment, weaker momentum in manufacturing due to higher energy costs and further political and policy uncertainty. China is expected to grow at 4.6% in 2025 as the fiscal stimulus package announced in November 2024 to address a slowdown in consumption largely offsets the adverse effects on investment from heightened trade policy uncertainty and the continued instability of the property market. The IMF expects global headline inflation to decline to 4.2% in 2025 and further to 3.5% in 2026 as the gradual cooling of labor markets is expected to keep consumer demand pressures in check.
Geopolitical conflicts can also impact hydrocarbon supply and demand. Sanctions imposed on Russia following its February 2022 invasion of Ukraine have largely been circumvented over time through the use of alternative trade routes to willing buyers. This evasion has led the U.S. Treasury Department to increase pressure on Russian energy revenue by imposing sanctions in January 2025 on certain oil-carrying vessels, Russian-based oilfield services providers and Russian energy officials. Attacks on vessels transiting the Gulf of Aden by Houthi rebels in Yemen have disrupted shipping routes causing delays and increased shipping costs as major ship operators avoid the area and transit longer routes. In December 2024, the U.S. Treasury Department expanded sanctions on Iran’s petroleum and petrochemical sectors to limit Iran’s revenue from energy exports and disrupt its ability to fund programs that threaten peace in the Middle East. In North Africa, the ongoing political instability and conflicts in Libya have periodically disrupted its oil production, refining operations and exports. Further escalation of these situations has the potential to affect a significant portion of hydrocarbon supplies from Russia, the Middle East and North Africa to global markets.
The OPEC+ group, which controls over 80%79% of the world’s proven crude oil reserves (as reported in the OPEC Annual Statistical Bulletin 20242025), continues to have a significant impactinfluence on the global balancebalances. of supply and demand through its decisions to cut, maintain or increase production levels. DuringIn 2024, the OPEC+ group announced that its originalbaseline and first layer of voluntary cuts oftotaling 3.66 MMBPD would be extended well into 2025, and certain of its members agreed to extend the second layer of voluntary incremental production cuts of 2.2 MMBPD until the end of March 2025. PerBeginning in April 2025, the agreement,OPEC+ thesegroup began unwinding the second layer of voluntary cuts will gradually be phased out onat a monthlyfaster basisthan fromannounced thatpace, pointcompleting forwarda untilfull restoration of the end2.2 MMBPD by the fall of September2025. 2026.On ShouldFebruary there1, be2026, discord amongeight OPEC+ group member nations,nations including an unwillingnessagreed to abidemaintain bytheir 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 extendin thefull, agreed-uponbut levelswould ofhappen only in a gradual manner depending on evolving market conditions. These OPEC+ group decisions will affect near-term balances and crude oil production,prices, globalwhich crudemay oilinfluence pricesthe andincentives for non-OPEC production couldthroughout bethe significantly affected.world.
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.
U.S. crude oil and natural gas producers have continued to increase production to record levels, particularly in the Permian Basin, thanks in part to innovations in both drilling and completion techniques. This growth has been dependent on the availability of both crude oil and natural gas export capacity due to limited growth in domestic consumption. As of January 28, 2025, the price of West Texas Intermediate (“WTI”) crude oil (as reported by New York Mercantile Exchange (“NYMEX”)) was $73.77 per barrel, slightly below the 2024 calendar year average of $75.76 per barrel. The price of natural gas, as measured by the NYMEX at Henry Hub, was $3.47 per MMBtu as of January 28, 2025, which is 44% higher than the 2024 calendar year average of $2.41 per MMBtu. The phase-out of certain voluntary OPEC+ group cuts starting in April 2025 could put downward pressure on crude oil prices while any delays in the start-up of facilities that are expected to expand U.S. LNG export capacity in 2025 could put downward pressure on natural gas prices.
Additional data from the EIA reinforces these trends. In its February 20252026 STEO, the EIA provided expectations of continued growth inprojects U.S. crude oil and liquid fuels production of 0.6 MMBPD to reach 23.323.7 MMBPD in 2026, an increase of approximately 0.1 MMBPD from 2025. Global production of petroleum and liquid fuels is expected to reach an average of 104.6107.9 MMBPD in 2025,2026, up from 102.8106.3 MMBPD in 2024, driven mostly by growth in U.S. and other non-OPEC production.2025. The EIA expectsalso domesticforecasts dryU.S. marketed natural gas production to growincrease aboutby 1.5approximately 2.5 Bcf/d in 20252026 to 120.8 Bcf/d, with LNG exports growing by 1.4 Bcf/d to reach 104.616.4 Bcf/d for the year. WithOn respectthe todemand demand,side, the EIA forecasts that global liquids fuel consumption will increase from 102.8103.6 MMBPD in 20242025 to 104.1104.8 MMBPD in 2025,2026, 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 fundamentals areremain constructive, particularly in the U.S.,U.S. basedand onmore risingso 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,Russia and Iran and Venezuela would likelycould further increasestrengthen global demand for U.S. crude oil.supplies. We also expect ancontinued increasegrowth in global demandelectricity for electricity,demand, including demand in theincremental U.S. demand associated with industrial reshoring and new data centers, which should help support natural gas-fired power generation demand over the medium to long-term. The global petrochemical industry willis continueexpected to beremain challenged in 2025 by oversupply largely2026 due to increasedoversupply, growthdriven inlargely by China’s continued expansion of its petrochemical production capacity as it focuses on export manufacturing to compensate for itsamid domestic economic challenges.pressures. This oversupply situation has led to the rationalization of petrochemical production capacity in Europe, Japan and other countries.regions. However,Even with ongoing industry headwinds, U.S. petrochemical producers are expected to continuemaintain a competitive advantage given their access to benefit from locally produced, lower-cost feedstocks and energy relative to their global peer group. LongerOver 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 generationgeneration, where it can be produced cost-effectively without permanent subsidy.
We believe that these anticipated additions to hydrocarbon production and consumption levels, along with favorable pricing trends,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.
•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.
Enterprise Announces AcquisitionExpansion and Extension of PinonBahia MidstreamNGL 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.
In August 2024, we announced that an affiliate of Enterprise entered into a definitive agreement to acquire Pinon Midstream, LLC (“Pinon Midstream”) in a debt-free transaction for $953 million in cash consideration (subject to adjustment in accordance with the agreement). Pinon Midstream’s assets include 43 miles of natural gas gathering and redelivery pipelines, five 3-stage compressor stations, 270 MMcf/d of hydrogen sulfide and carbon dioxide treating facilities and two high capacity acid gas injection wells. This transaction, which closed October 28, 2024, was funded using cash on hand.
Issuance of $2.5 Billion of Senior Notes in August 2024
In August 2024, EPO issued $2.5 billion aggregate principal amount of senior notes comprised of (i) $1.1 billion principal amount of senior notes due February 2035 (“Senior Notes JJJ”) and (ii) $1.4 billion principal amount of senior notes due February 2055 (“Senior Notes KKK”). Net proceeds from this offering were used by EPO for general company purposes, including for growth capital investments, and the repayment of debt (including the repayment of our $1.15 billion principal amount of 3.75% Senior Notes MM at their maturity in February 2025).
Senior Notes JJJ were issued at 99.400% of their principal amount and have a fixed interest rate of 4.95% per year. Senior Notes KKK were issued at 99.663% of their principal amount and have a fixed interest rate of 5.55% per year. The Partnership guaranteed these senior notes through an unconditional guarantee on an unsecured and unsubordinated basis.
Enterprise to Expand LPG Export Capacity at EHT
In July 2024, we announced plans to move forward with the construction of a fourth refrigeration train at our Enterprise Hydrocarbon Terminal (“EHT”). The addition of a fourth refrigeration train (“Ref 4”), which is expected to be placed into service by the end of 2026, will increase our propane and butane export capabilities by approximately 300 MBPD. In addition to providing incremental LPG export capacity, Ref 4 will increase the instantaneous loading rates for propane and butane at EHT, while also making additional capacity available for propylene exports.
Enterprise to Build Mentone West 2; Mentone 3 and Leonidas Begin Service
In April 2024, we announced plans to further expand our natural gas processing capabilities in the Delaware Basin with construction of a second natural gas processing train at our Mentone West location (“Mentone West 2”) in Loving County, Texas. This natural gas processing train, which will have the capacity to process more than 300 MMcf/d of natural gas and extract in excess of 40 MBPD of NGLs, is expected to begin service during the first half of 2026.
Additionally, we placed into service our third natural gas processing train at Mentone in the Delaware Basin (“Mentone 3”) and our seventh Midland Basin natural gas processing train (“Leonidas”). Both Mentone 3 and Leonidas are capable of processing over 300 MMcf/d of natural gas and extracting more than 40 MBPD of NGLs. Supported by a combination of long-term producer dedications and minimum volume commitments, Mentone 3 and Leonidas will support Permian Basin producers as they meet growing demand in the U.S. and internationally.
Enterprise Begins Service on TW Products System
In March 2024, we placed into service the first phase of our Texas Western Products System (“TW Products System”) and began truck loading operations at our new Permian terminal in Gaines County, Texas. Additionally, we placed into service and began truck loading operations at our Jal and Moriarty Terminals located in New Mexico during the second quarter of 2024 and our Grand Junction Terminal located in Utah in October 2024. On a combined basis, the four terminals offer 1.8 MMBbls of refined products storage capacity and can load up to 63 MBPD.
Enterprise Acquires Equity Interests from Western Midstream
In February 2024, we announced that we had acquired the remaining equity interests in Whitethorn Pipeline Company LLC (“Whitethorn”) and Enterprise EF78 LLC (“EF78”) from affiliates of Western Midstream Partners, LP (“Western Midstream”) for $375 million in total cash consideration. This transaction, which closed on February 16, 2024, was funded using cash on hand and proceeds from the issuance of short-term notes under our commercial paper program.
Additionally, on March 27, 2024, we acquired an additional 15% equity interest in Panola Pipeline Company, LLC (“Panola”) from an affiliate of Western Midstream for $25 million in cash consideration. We funded the cash consideration using cash on hand. As a result of this acquisition, we currently own a 70% equity interest in Panola.
Issuance of $2.0 Billion of Senior Notes in JanuaryJune 20242025 and November 2025
In JanuaryJune 2024,2025, EPO issued $2.0 billion aggregate principal amount of senior notes comprised of (i) $1.0$500 billionmillion principal amount of senior notes due June 2028 (“Senior Notes LLL”), (ii) $750 million principal amount of senior notes due January 20272031 (“Senior Notes HHHMMM”) and (iiiii) $1.0$750 billionmillion principal amount of senior notes due January 20342036 (“Senior Notes IIINNN”). Net proceeds from this offering were used by EPO for general company purposes, including for growth capital investments, and the repayment of debt (including the repayment of our $850 million principal amount of 3.90% Senior Notes JJ at their maturity in February 2024 and amounts outstanding under our commercial paper program).
Senior Notes HHHLLL were issued at 99.897%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 IIINNN were issued at 99.705%99.665% of their principal amount and have a fixed interest rate of 4.85%5.20% per year. TheNet Partnershipproceeds guaranteedfrom thesethis senioroffering noteswere throughused anby unconditionalEPO guaranteefor ongeneral ancompany unsecuredpurposes, including for growth capital investments, and unsubordinatedthe basis.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, 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.
(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 and 2023.2024.
What changed in the latest 10-Q
Risk Factors
An investment in our securities involves certain risks. Security holders and potential investors in our securities should carefully consider the risks described under “Risk Factors” set forth in Part I, Item 1A of our 2025 Form 10-K, in addition to other information in such annual report and this quarterly report. The risk factors set forth in our 2025 Form 10-K are important factors that could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us or on our behalf.
No wording changes found in this section.
Full comparison: every changed paragraph (0)
Management's Discussion & Analysis (MD&A)
New heading “Recent Developments”
New heading “Enterprise to Expand Permian Basin Processing and Mont Belvieu Area NGL Fractionation Capacity”
New heading “Enterprise Enters Into July 2026 $1.0 Billion Incremental Credit Agreement”
Largest changes
“In July 2026, EPO entered into an additional revolving credit agreement (the “July 2026 $1.0 Billion Incremental Credit Agreement”). Under the new agreement, EPO may borrow up to $1.0 billion at a variable interest rate, subject to its terms and conditions. The July 2026 $1.0 Billion Incremental Credit Agreement increases EPO’s aggregate borrowing capacity under its credit agreements to $5.2 billion and enhances our liquidity and financial flexibility to support our working capital requirements amid increased commodity price volatility. …”see in full comparison
“Enterprise to Expand Permian Basin Processing and Mont Belvieu Area NGL Fractionation Capacity”see in full comparison
“Enterprise Enters Into July 2026 $1.0 Billion Incremental Credit Agreement”see in full comparison
“Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025. Cost of sales for the six months ended June 30, 2026 increased a net $4.9 billion when compared to the six months ended June 30, 2025. The cost of sales associated with the marketing of crude oil and petrochemicals and refined products increased a combined $5.8 billion period-to-period primarily due to higher volumes, which accounted for a $3.0 billion increase, and higher average purchase prices, which accounted for an additional $2.8 billion increase. …”see in full comparison
“Revenues from the marketing of NGLs decreased $1.4 billion quarter-to-quarter primarily due to lower average sales prices. Revenues from the marketing of petrochemicals and refined products decreased $727 million quarter-to-quarter primarily due to lower sales volumes, which accounted for a $479 million decrease, and lower average sales prices, which accounted for an additional $248 million decrease. Revenues from the marketing of natural gas decreased $154 million quarter-to-quarter primarily due to lower average sales prices. …”see in full comparison
“Revenues from the marketing of crude oil and petrochemicals and refined products increased a combined $5.9 billion period-to-period primarily due to higher sales volumes, which accounted for a $3.1 billion increase, and higher average sales prices, which accounted for an additional $2.8 billion increase. Revenues from the marketing of NGLs increased $370 million period-to-period primarily due to higher sales volumes. Revenues from the marketing of natural gas decreased $620 million period-to-period primarily due to lower average sales prices.”see in full comparison
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For the Three and Six Months Ended MarchJune 31,30, 2026 and 2025
This quarterly report on Form 10-Q for the three and six months ended MarchJune 31,30, 2026 (our “quarterly 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 quarterly report) are reasonable, neither we nor our general partner can give any assurances that such expectations will prove to be correct.
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 MarchJune 31,30, 2026.
As used in this quarterly report, the phrase “quarter-to-quarter” means the firstsecond quarter of 2026 compared to the firstsecond quarter of 2025. Likewise, the phrase “period-to-period” means the six months ended June 30, 2026 compared to the six months ended June 30, 2025.
Recent Developments
Enterprise to Expand Permian Basin Processing and Mont Belvieu Area NGL Fractionation Capacity
To support ongoing production growth in the Permian Basin, we announced in April 2026 plans to construct a tenth natural gas processing train (“Athena 2”) in the Midland Basin and a twelfth natural gas processing train (“Delaware Basin Plant 12”) in the Delaware Basin and in July 2026 announced plans to construct an eleventh natural gas processing train (“Midland Basin Plant 11”) in the Midland Basin and a thirteenth natural gas processing train (“Delaware Basin Plant 13”) in the Delaware Basin.
In the Midland Basin, each of these processing trains will have a nameplate natural gas processing capacity of 300 MMcf/d and will be able to extract more than 40 MBPD of NGLs. Athena 2 and Midland Basin Plant 11, which are supported by long-term acreage dedication agreements, are expected to be placed into service in the third quarter of 2027 and first quarter of 2029, respectively.
In the Delaware Basin, each of these processing trains will have a nameplate natural gas processing capacity of 300 MMcf/d and will be able to extract more than 40 MBPD of NGLs. Delaware Basin Plant 12 and Delaware Basin Plant 13, which are supported by long-term acreage dedication agreements and minimum volume commitments, are expected to be placed into service in the fourth quarter of 2027 and third quarter of 2028, respectively.
To accommodate incremental NGL production from the Permian Basin, we plan to construct an additional NGL fractionator (“Frac 15”) at our Mont Belvieu area NGL fractionation complex. Frac 15 will have a nameplate capacity of 150 MBPD and is expected to be completed in the first quarter of 2028.
Enterprise Enters Into July 2026 $1.0 Billion Incremental Credit Agreement
In July 2026, EPO entered into an additional revolving credit agreement (the “July 2026 $1.0 Billion Incremental Credit Agreement”). Under the new agreement, EPO may borrow up to $1.0 billion at a variable interest rate, subject to its terms and conditions. The July 2026 $1.0 Billion Incremental Credit Agreement increases EPO’s aggregate borrowing capacity under its credit agreements to $5.2 billion and enhances our liquidity and financial flexibility to support our working capital requirements amid increased commodity price volatility. Proceeds from borrowings under the agreement may be used for working capital, capital expenditures, acquisitions and other company purposes. Amounts borrowed under the agreement mature on March 26, 2027, coinciding with the maturity date of EPO’s existing March 2026 $1.5 Billion 364-Day Revolving Credit Agreement.
The weighted-average indicative market price for NGLs was $0.57$0.68 per gallon in the firstsecond quarter of 2026 versus $0.67$0.58 per gallon in the firstsecond quarter of 2025. Likewise, the weighted-average indicative market price for NGLs was $0.63 per gallon during the six months ended June 30, 2026 compared to $0.63 during the six months ended June 30, 2025.
FirstSecond Quarter of 2026 Compared to FirstSecond Quarter of 2025. Total revenues for the firstsecond quarter of 2026 decreasedincreased $1.0$6.9 billion when compared to the firstsecond quarter of 2025 primarily due to lowerhigher marketing revenues.
Revenues from the marketing of crude oil, NGLs and petrochemicals and refined products increased a combined $7.2 billion quarter-to-quarter primarily due to higher average sales prices, which accounted for a $4.2 billion increase, and higher sales volumes, which accounted for an additional $3.0 billion increase. Revenues from the marketing of natural gas decreased $465 million quarter-to-quarter primarily due to lower average sales prices.
Revenues from midstream services for the second quarter of 2026 increased $129 million when compared to the second quarter of 2025. Revenues from our natural gas processing facilities increased $111 million quarter-to-quarter primarily due to higher market values for the equity NGL-equivalent production volumes we received as non-cash consideration for processing services. Revenues from our natural gas transportation assets increased $52 million quarter-to-quarter primarily due to higher demand for transportation services.
Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025. Total revenues for the six months ended June 30, 2026 increased $5.9 billion when compared to the six months ended June 30, 2025 primarily due to higher marketing revenues.
Revenues from the marketing of crude oil and petrochemicals and refined products increased a combined $5.9 billion period-to-period primarily due to higher sales volumes, which accounted for a $3.1 billion increase, and higher average sales prices, which accounted for an additional $2.8 billion increase. Revenues from the marketing of NGLs increased $370 million period-to-period primarily due to higher sales volumes. Revenues from the marketing of natural gas decreased $620 million period-to-period primarily due to lower average sales prices.
Revenues from midstream services for the six months ended June 30, 2026 increased $180 million when compared to the six months ended June 30, 2025. Revenues from our natural gas processing facilities increased $101 million period-to-period primarily due to higher market values for the equity NGL-equivalent production volumes we receive as non-cash consideration for processing services. Revenues from our natural gas transportation assets increased $91 million period-to-period primarily due to higher demand for transportation services.
Revenues from the marketing of NGLs decreased $1.4 billion quarter-to-quarter primarily due to lower average sales prices. Revenues from the marketing of petrochemicals and refined products decreased $727 million quarter-to-quarter primarily due to lower sales volumes, which accounted for a $479 million decrease, and lower average sales prices, which accounted for an additional $248 million decrease. Revenues from the marketing of natural gas decreased $154 million quarter-to-quarter primarily due to lower average sales prices. Revenues from the marketing of crude oil increased a net $1.2 billion quarter-to-quarter primarily due to higher sales volumes, which accounted for a $1.4 billion increase, partially offset by lower average sales prices, which accounted for a $259 million decrease.
Revenues from midstream services for the first quarter of 2026 increased $51 million when compared to the first quarter of 2025 primarily due to higher demand for transportation services on our NGL and natural gas transportation assets.
Total operating costs and expenses for the firstthree quarterand ofsix months ended June 30, 2026 decreasedincreased $1.2$6.5 billion and $5.3 billion, respectively, when compared to the firstsame quarterperiods ofin 2025.
FirstSecond Quarter of 2026 Compared to FirstSecond Quarter of 2025. Cost of sales for the firstsecond quarter of 2026 decreasedincreased a net $1.3$6.3 billion when compared to the firstsecond quarter of 2025. The cost of sales associated with the marketing of crude oil, NGLs decreased $1.9 billion quarter-to-quarter primarily due to lower average purchase prices. The cost of sales associated with the marketing ofand petrochemicals and refined products decreased $645 million quarter-to-quarter primarily due to lower volumes, which accounted for a $527 million decrease, and lower average purchase prices, which accounted for an additional $118 million decrease. The cost of sales associated with the marketing of crude oil increased a netcombined $1.2$6.3 billion quarter-to-quarter primarily due to higher volumes which accounted for a $1.4 billion increase, partially offset by lower average purchase prices, which accounted for a $163$3.3 millionbillion decrease.increase, and higher volumes, which accounted for an additional $3.0 billion increase.
Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025. Cost of sales for the six months ended June 30, 2026 increased a net $4.9 billion when compared to the six months ended June 30, 2025. The cost of sales associated with the marketing of crude oil and petrochemicals and refined products increased a combined $5.8 billion period-to-period primarily due to higher volumes, which accounted for a $3.0 billion increase, and higher average purchase prices, which accounted for an additional $2.8 billion increase. The cost of sales associated with the marketing of NGLs and natural gas decreased a combined net $850 million period-to-period primarily due to lower average purchase prices, which accounted for a $1.2 billion decrease, partially offset by higher volumes, which accounted for a $338 million increase.
Other operating costs and expenses for the firstthree quarterand ofsix months ended June 30, 2026 increased $75$130 million and $205 million, respectively, when compared to the firstsame quarterperiods ofin 2025 primarily due to higher employeecompensation, compensationchemical costs, ad valorem taxes, maintenance and chemicalother operating costs.
Depreciation, amortization and accretion expense for the firstthree quarterand ofsix months ended June 30, 2026 increased $64$79 million and $143 million, respectively, when compared to the firstsame quarterperiods ofin 2025 primarily due to higher depreciation expense on assets placed into full or limited service since the end of the firstrespective quarterperiods ofin 2025.
General and administrative costs for the firstthree quartermonths ofended June 30, 2026 increaseddecreased $4 million when compared to the firstsame quarterperiod ofin 2025 primarily due to higher employeelower compensation costs. General and administrative costs for the six months ended June 30, 2026 were flat when compared to the same period in 2025.
Equity income from our unconsolidated affiliates for the firstthree quartermonths ofended June 30, 2026 decreasedincreased $18$17 million when compared to the firstsame quarterperiod ofin 2025 primarily due to lowerhigher earnings from investments in crude pipelines. Equity income from our unconsolidated affiliates for the six months ended June 30, 2026 decreased $1 million when compared to the same period in 2025.
Operating income for the firstthree quarterand ofsix months ended June 30, 2026 increased $134$454 million and $588 million, respectively, when compared to the firstsame quarterperiods ofin 2025 due to the previously described quarter-to-quarter and period-to-period changes.
(1)The weighted-average interest rates on debt principal outstanding during the firstthree quartersand ofsix months ended June 30, 2026 were 4.66% and 4.68%, respectively. The weighted-average interest rates on debt principal outstanding during the three and six months ended June 30, 2025 were 4.71%4.67% and 4.70%,4.68%, respectively.
Interest charged on debt principal outstanding, which is a key driver of interest expense, increased a net $24$21 million quarter-to-quarter.quarter-to-quarter Thisand increasea wasnet $45 million period-to-period. These increases were primarily due to the issuance of $2.0 billion and $1.65 billion of fixed-rate senior notes in June 2025 and November 2025, respectively, which accounted for a combined increase of $44$41 million quarter-to-quarter,quarter-to-quarter and $85 million period-to-period. These increases were partially offset by the retirement of $1.15 billion, $750 million and $875 million of fixed-rate senior notes in February 2025, January 2026 and February 2026, respectively, which accounted for a combined decrease of $18 million quarter-to-quarter.quarter-to-quarter and $30 million period-to-period.
FirstSecond Quarter of 2026 Compared to FirstSecond Quarter of 2025. Gross operating margin from natural gas processing and related NGL marketing activities for the firstsecond quarter of 2026 increased $42$171 million when compared to the firstsecond quarter of 2025.
Gross operating margin from our Midland Basin natural gas processing facilities increased $25 million quarter-to-quarter primarily due to higher average processing margins (including the impact of hedging activities), which accounted for a $15 million increase, an 11 MBPD increase in equity NGL-equivalent production volumes, which accounted for a $7 million increase, and higher average processing fees, which accounted for an additional $4 million increase. Fee-based natural gas processing volumes at our Midland Basin natural gas processing facilities increased 31 MMcf/d quarter-to-quarter.
Gross operating margin from our Delaware Basin natural gas processing facilities increased a net $22 million quarter-to-quarter primarily due to higher average processing margins (including the impact of hedging activities), which accounted for a $35 million increase, and higher fee-based natural gas processing volumes, which accounted for a $12 million increase, partially offset by a 10 MBPD decrease in equity NGL-equivalent production volumes, which accounted for an $18 million decrease, and higher operating costs, which accounted for an additional $7 million decrease. Fee-based natural gas processing volumes at our Delaware Basin natural gas processing facilities increased 242 MMcf/d quarter-to-quarter.
Gross operating margin from our NGL marketing activities increased a net $10$83 million quarter-to-quarter primarily due to higher sales volumes, which accounted for a $20 million increase, partially offset by lower average sales margins, which accounted for a $5$51 million decrease,increase, and lowerhigher mark-to-market earnings, which accounted for a $19 million increase, and higher sales volumes, which accounted for an additional $4$13 million decrease.increase.
Gross operating margin from our RockiesMidland Basin natural gas processing facilities (Meeker,increased Pioneer and Chaco) decreased a combined $8$47 million quarter-to-quarter primarily due to lower average processing fees, which accounted for a $4 million decrease, and lowerhigher average processing margins (including the impact of hedging activities), which accounted for ana additional $2$27 million decrease. Onincrease, a combined10 basis,MBPD increase in equity NGL-equivalent production volumes, which accounted for a $7 million increase, a 218 MMcf/d increase in fee-based natural gas processing volumesvolumes, which accounted for a $7 million increase, and equityhigher NGL-equivalentaverage productionprocessing volumesfees, decreasedwhich 69accounted MMcf/dfor andan increasedadditional 8$4 MBPD,million respectively, quarter-to-quarter.increase.
Gross operating margin from our Delaware Basin natural gas processing facilities increased a net $36 million quarter-to-quarter primarily due to an 8 MBPD increase in equity NGL-equivalent production volumes, which accounted for a $20 million increase, higher average processing margins (including the impact of hedging activities), which accounted for a $15 million increase, and a 288 MMcf/d increase in fee-based natural gas processing volumes, which accounted for an additional $12 million increase, partially offset by higher operating costs, which accounted for an $11 million decrease.
Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025. Gross operating margin from natural gas processing and related NGL marketing activities for the six months ended June 30, 2026 increased $213 million when compared to the six months ended June 30, 2025.
Gross operating margin from our NGL marketing activities increased $93 million period-to-period primarily due to higher average sales margins, which accounted for a $44 million increase, higher sales volumes, which accounted for a $35 million increase, and higher mark-to-market earnings, which accounted for an additional $15 million increase.
Gross operating margin from our Midland Basin natural gas processing facilities increased $73 million period-to-period primarily due to higher average processing margins (including the impact of hedging activities), which accounted for a $42 million increase, a 10 MBPD increase in equity NGL-equivalent production volumes, which accounted for a $14 million increase, a 125 MMcf/d increase in fee-based natural gas processing volumes, which accounted for a $9 million increase, and higher average processing fees, which accounted for an additional $7 million increase.
Gross operating margin from our Delaware Basin natural gas processing facilities increased a net $59 million period-to-period primarily due to higher average processing margins (including the impact of hedging activities), which accounted for a $51 million increase, and a 265 MMcf/d increase in fee-based natural gas processing volumes, which accounted for an additional $25 million increase, partially offset by higher operating costs, which accounted for a $17 million decrease.
Gross operating margin from our South Texas natural gas processing facilities decreased $5 million quarter-to-quarter primarily due to higher operating costs. Fee-based natural gas processing volumes and equity NGL-equivalent production volumes decreased 12 MMcf/d and increased 3 MBPD, respectively, quarter-to-quarter.
FirstSecond Quarter of 2026 Compared to FirstSecond Quarter of 2025. Gross operating margin from our NGL pipelines, storage and terminal assets during the firstsecond quarter of 2026 increased $1$25 million when compared to the firstsecond quarter of 2025.
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 $22 million quarter-to-quarter primarily due to an increase in transportation volumes.
Gross operating margin from our Mont Belvieu area storage complex increased $11 million quarter-to-quarter primarily due to higher storage revenues.
Gross operating margin at our Morgan’s Point andPoint, Neches River Exportand Enterprise Hydrocarbons Terminals increased a combined net $6$27 million quarter-to-quarter primarily due to an increase in ethane export volumes, which accounted for a $23$32 million increase, and higheran otherincrease feein revenues,propane export volumes, which accounted for an additional $3$12 million increase, partially offset by lower average loading fees, which accounted for a $10 million decrease, and higher operating costs, which accounted for a $13 million decrease, and lower average ethane loading fees, which accounted for an additional $10$7 million decrease. Ethane export volumes at these terminals increased a combined 104143 MBPD quarter-to-quarter primarily due to contributions from the first phase of our Neches River export facility, which was placed into service in July 2025. Propane export volumes at these terminals increased 141 MBPD quarter-to-quarter due to contributions from the second phase of our Neches River export facility, which was placed into service in May 2026. LPG export volumes at Enterprise Hydrocarbons Terminal (“EHT”) were flat quarter-to-quarter.
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 a net $11 million quarter-to-quarter primarily due to higher average transportation fees, which accounted for a $10 million increase, an increase in transportation volumes, which accounted for a $7 million increase, and lower operating costs, which accounted for an additional $4 million increase, partially offset by lower other revenues, which accounted for a $10 million decrease.
Gross operating margin from LPG-related activities at our EnterpriseMont HydrocarbonsBelvieu Terminalarea (“EHT”)storage decreasedcomplex $42increased $10 million quarter-to-quarter primarily due to lowerhigher averagestorage loading fees. LPG export volumes at EHT decreased 1 MBPD quarter-to-quarter.revenues.
Gross operating margin from our South Texas NGL Pipeline System decreased $9 million quarter-to-quarter primarily due to lower capacity reservation revenues, which accounted for a $4 million decrease, and higher operating costs, which accounted for an additional $6 million decrease. Transportation volumes on this system decreased 7 MBPD quarter-to-quarter.
Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025. Gross operating margin from our NGL pipelines, storage and terminal assets during the six months ended June 30, 2026 increased $26 million when compared to the six months ended June 30, 2025.
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 $33 million period-to-period primarily due to an increase in transportation volumes, which accounted for a $23 million increase, and higher average transportation fees, which accounted for an additional $11 million increase.
Gross operating margin from our Mont Belvieu area storage complex increased $22 million period-to-period primarily due to higher storage revenues.
Gross operating margin from our South Texas NGL Pipeline System decreased $13 million period-to-period primarily due to lower capacity reservation revenues, which accounted for a $7 million decrease, and higher operating costs, which accounted for an additional $9 million decrease. Transportation volumes on this system decreased 5 MBPD period-to-period.
Gross operating margin at our Morgan’s Point, Neches River and Enterprise Hydrocarbons Terminals decreased a combined net $8 million period-to-period primarily due to lower average LPG loading fees, which accounted for a $42 million decrease, higher operating costs, which accounted for a $21 million decrease, and lower average ethane loading fees, which accounted for an additional $16 million decrease, partially offset by an increase in ethane export volumes, which accounted for a $54 million increase, and an increase in propane export volumes, which accounted for an additional $12 million increase. Ethane export volumes at these terminals increased a combined 123 MBPD period-to-period primarily due to contributions from the first phase of our Neches River export facility, which was placed into service in July 2025. Propane export volumes at these terminals increased 71 MBPD period-to-period due to contributions from the second phase of our Neches River export facility, which was placed into service in May 2026. LPG export volumes at EHT were flat period-to-period.
FirstSecond Quarter of 2026 Compared to FirstSecond Quarter of 2025. Gross operating margin from NGL fractionation during the firstsecond quarter of 2026 increased $42$52 million when compared to the firstsecond quarter of 2025.
Gross operating margin from our Mont Belvieu area NGL fractionation complex increased a net $33$54 million quarter-to-quarter primarily due to higher fractionation volumes, which accounted for a $46$42 million increase, and higher averageancillary fractionationservice fees (including the impact of hedging activities),revenues, which accounted for an additional $25$23 million increase, partially offset by higher operating costs, which accounted for a $29 million decrease, and lower ancillary service revenues, which accounted for an additional $9$13 million decrease. NGL fractionation volumes at our Mont Belvieu area NGL fractionation complex increased 220207 MBPD quarter-to-quarter primarily due to contributions from Frac 14, which was placed into service during the fourth quarter of 2025.
Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025. Gross operating margin from NGL fractionation during the six months ended June 30, 2026 increased $94 million when compared to the six months ended June 30, 2025.
Gross operating margin from our Mont Belvieu area NGL fractionation complex increased a net $87 million period-to-period primarily due to higher fractionation volumes, which accounted for an $87 million increase, higher average fractionation fees (including the impact of hedging activities), which accounted for a $27 million increase, and higher ancillary service revenues, which accounted for an additional $13 million increase, partially offset by higher operating costs, which accounted for a $42 million decrease. NGL fractionation volumes at our Mont Belvieu area NGL fractionation complex increased 214 MBPD period-to-period primarily due to contributions from Frac 14, which was placed into service during the fourth quarter of 2025.
FirstSecond Quarter of 2026 Compared to FirstSecond Quarter of 2025. Gross operating margin from our Crude Oil Pipelines & Services segment for the firstsecond quarter of 2026 decreasedincreased $45$82 million when compared to the firstsecond quarter of 2025.
Gross operating margin from our Texas crude oil pipelines, related terminals and marketing activities (excluding the Seaway Pipeline) decreasedincreased a combined net $46$69 million quarter-to-quarter primarily due to lowerhigher average sales margins from marketing activities, which accounted for a $34$52 million decrease,increase, higher sales volumes from marketing activities, which accounted for a $37 million increase, and higher mark-to-market earnings, which accounted for an additional $11 million increase, partially offset by lower transportation and related revenues, which accounted for a $24$19 million decrease and largely attributable to lower average transportation fees from our equity investment in the Eagle Ford Crude Oil Pipeline, and lowerhigher mark-to-marketoperating earnings,costs, which accounted for an additional $11$12 million decrease,decrease. partiallyThe offsetincreases byin marketing sales margins and volumes benefited from higher salesdemand volumesacross fromour marketingintegrated activities,crude whichoil accountedvalue forchain, reflected in a $23265 millionMBPD increase.(net Crudeto our interest) combined increase in crude oil transportation volumes on these pipelines increasedand a combined 83227 MBPD (netincrease toin crude oil marine terminal volumes at EHT, as well as corresponding market opportunities captured by our interest)marketing quarter-to-quarter.activities.
EPD insider buying and selling (Form 4)
Since 2026-04-11, insiders reported open-market purchases in 0 Form 4 filings and open-market sales in 0 filings. Totals add up every open-market (code P and S) line in those filings, using the prices reported in the filings. Awards, option exercises, tax withholding and gifts are listed below but not counted.
No Form 4 stock transactions in this period.
Well-known investors holding EPD (13F)
None of the 59 investors we track reported a position in their latest 13F.