ENTERPRISE PRODUCTS PARTNERS L.P.
For the period ended Dec 31, 2025. Filed Feb 27, 2026.
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A company's yearly report to the SEC, with audited financial statements. It is the fullest account a company gives of its business, its finances and the risks it sees.
FY2025 · Filed Feb 27, 2026
EPD$37.03+1.1%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-K
Period ended 2024-12-31; filed 2025-02-28.
0001061219-25-000006
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-K
Period ended 2025-12-31; filed 2026-02-27.
0001061219-26-000006
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 241 previous paragraphs and 293 current paragraphs.
135 unchanged; 70 reworded; 84 added; 34 removed; 2 previous and 4 current paragraphs rearranged.
Tables are not compared: 61 previous and 20 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (84)
Current report
•propylene production facilities (including propane dehydrogenation (“PDH”) facilities), butane isomerization, octane enhancement, isobutane dehydrogenation (“iBDH”) and high purity isobutylene (“HPIB”) production facilities;
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
•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.
Current report
•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.
Current report
•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.
Current report
•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.
Current report
Enterprise Announces Expansion and Extension of Bahia NGL Pipeline; ExxonMobil Acquires Joint Interest
Current report
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.
Current report
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.
Current report
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.
Current report
Issuance of Senior Notes in June 2025 and November 2025
Current report
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”).
Current report
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.
Current report
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).
Current report
Enterprise Announces Increase to 2019 Buyback Program
Current report
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.
Current report
Enterprise Acquires Oxy Affiliate, Enters into Service Agreements, and Expands Midland Basin Processing Capacity
Current report
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.
Current report
Enterprise Begins Initial Service at Neches River Ethane / Propane Export Facility
Current report
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.
Current report
Enterprise Begins Service at Mentone West 1 and Orion
Current report
(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.
Current report
(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.
Current report
(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.
Current report
(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.
Current report
(1)WTI prices are based on commercial index prices at Cushing, Oklahoma as measured by the NYMEX.
Current report
(2)Midland and Houston crude oil prices are based on commercial index prices as reported by Argus.
Current report
Other operating costs and expenses increased $283 million year-to-year primarily due to higher employee compensation, utility, and rental costs.
Current report
(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.
Current report
(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.
Current report
•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.
Current report
•Our Crude Oil Pipelines & Services business segment includes our crude oil pipelines, crude oil storage and marine terminals, and related crude oil marketing activities.
Current report
•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.
Current report
•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.
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Removed paragraphs (34)
Previous report
The level of services we provide and the amount of volumes we purchase and sell are affected by changes in supply and demand fundamentals for hydrocarbon products. These fundamentals impact our financial position, results of operations and cash flows. During 2024, hydrocarbon supply and demand were relatively balanced as crude oil production cuts maintained by members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (collectively, the “OPEC+” group) helped offset increased production levels in the United States, Canada 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.
Previous report
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.
Previous report
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.
Previous report
The OPEC+ group, which controls over 80% of the world’s proven crude oil reserves (as reported in the OPEC Annual Statistical Bulletin 2024), continues to have a significant impact on the global balance of supply and demand through its decisions to cut, maintain or increase production levels. During 2024, the OPEC+ group announced that its original cuts of 3.66 MMBPD would be extended well into 2025, and certain of its members agreed to extend the voluntary incremental production cuts of 2.2 MMBPD until the end of March 2025. Per the agreement, these voluntary cuts will gradually be phased out on a monthly basis from that point forward until the end of September 2026. Should there be discord among OPEC+ group member nations, including an unwillingness to abide by or extend the agreed-upon levels of crude oil production, global crude oil prices and production could be significantly affected.
Previous report
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.
Previous report
Enterprise Announces Acquisition of Pinon Midstream
Previous report
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.
Previous report
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).
Previous report
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.
Previous report
Enterprise to Build Mentone West 2; Mentone 3 and Leonidas Begin Service
Previous report
Enterprise Begins Service on TW Products System
Previous report
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.
Previous report
Enterprise Acquires Equity Interests from Western Midstream
Previous report
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.
Previous report
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. Wefunded the cash consideration using cash on hand. As a result of this acquisition, we currently own a 70% equity interest in Panola.
Previous report
Issuance of $2.0 Billion of Senior Notes in January 2024
Previous report
In January 2024, EPO issued $2.0 billion aggregate principal amount of senior notes comprised of (i) $1.0 billion principal amount of senior notes due January 2027 (“Senior Notes HHH”) and (ii) $1.0 billion principal amount of senior notes due January 2034 (“Senior Notes III”). 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).
Previous report
Senior Notes HHH were issued at 99.897% of their principal amount and have a fixed interest rate of 4.60% per year. Senior Notes III were issued at 99.705% of their principal amount and have a fixed interest rate of 4.85% per year. The Partnership guaranteed these senior notes through an unconditional guarantee on an unsecured and unsubordinated basis.
Previous report
Other operating costs and expenses increased a net $309 million year-to-year primarily due to higher maintenance, employee compensation, rental, chemical and other operating costs, which accounted for a $364 million increase, partially offset by lower utility costs, which accounted for a $55 million decrease.
Previous report
Asset impairment charges
Previous report
Non-cash asset impairment charges increased $27 million year-to-year. The asset impairment charges recognized during 2024 and 2023 are attributable to the write-off of assets that are no longer expected to be used or constructed. For information regarding these charges, see Note 4 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.
Previous report
Gross operating margin from our NGL marketing activities increased a net $75 million year-to-year primarily due to higher sales volumes, which accounted for a $93 million increase, and higher non-cash, mark-to-market earnings, which accounted for an additional $17 million increase, partially offset by lower average sales margins, which accounted for a $34 million decrease.
Previous report
Gross operating margin from our South Texas natural gas processing facilities increased $17 million year-to-year primarily due to higher average processing margins (including the impact of hedging activities), which accounted for a $10 million increase, higher average processing fees, which accounted for a $4 million increase, and a 33 MMcf/d increase in fee-based natural gas processing volumes, which accounted for an additional $2 million increase.
Previous report
Gross operating margin at our Morgan’s Point Ethane Export Terminal decreased a net $15 million year-to-year primarily due to lower average loading fees, which accounted for a $22 million decrease, and a higher operating costs, which accounted for an additional $6 million decrease, partially offset by a 15 MBPD increase in export volumes, which accounted for a $15 million increase.
Previous report
Gross operating margin from our Texas in-basin crude oil pipelines, terminals and other marketing activities (excluding our Midland-to-ECHO System and Seaway Pipeline) decreased a combined net $101 million year-to-year primarily due to lower average sales margins, which accounted for a $104 million decrease, and higher operating costs, which accounted for an additional $37 million decrease, partially offset by higher non-cash, mark-to-market earnings, which accounted for a $37 million increase. Crude oil transportation volumes on these pipelines increased a combined 2 MBPD (net to our interest) year-to-year.
Previous report
Gross operating margin from our Midland-to-ECHO System and related business activities increased a net $38 million year-to-year primarily due to higher deficiency and other fee revenues, which accounted for a $69 million increase, and lower operating costs, which accounted for an additional $38 million increase, partially offset by lower margins from marketing activities, which accounted for a $46 million decrease, lower transportation revenues, which accounted for a $12 million decrease, and lower non-cash, mark-to-market earnings, which accounted for an additional $11 million decrease. Crude oil transportation volumes on these pipelines increased a combined 56 MBPD (net to our interest) year-to-year.
Previous report
Gross operating margin from our Natural Gas Pipelines & Services segment for the year ended December 31, 2024 increased $200 million when compared to the year ended December 31, 2023.
Previous report
On a combined basis, gross operating margin from our Jonah Gathering System, Piceance Basin Gathering System, and San Juan Gathering System in the Rocky Mountains decreased $50 million year-to-year primarily due to lower average gathering fees. The gathering fees on these systems are indexed to regional gas prices, which were lower during 2024 compared to 2023. Gathering volumes on our Rocky Mountain gathering systems decreased a combined 117 BBtus/d year-to-year.
Previous report
Gross operating margin from our Haynesville Gathering System decreased $18 million year-to-year primarily due to lower deficiency fees, which accounted for a $9 million decrease, and a 72 BBtus/d decrease in gathering volumes, which accounted for an additional $4 million decrease.
Previous report
Gross operating margin from our refined products terminal in Beaumont, Texas decreased $20 million year-to-year primarily due to lower loading and other fee revenues. Refined product marine terminal volumes at Beaumont increased 3 MBPD year-to-year.
Previous report
Our TW Products System, which was placed into service during 2024, generated gross operating margin of $19 million.
Previous report
Net cash flow provided by operating activities for the year ended December 31, 2024 increased $546 million when compared to the year ended December 31, 2023 primarily due to higher partnership earnings (determined by adjusting our $313 million increase in net income for changes in the non-cash items identified on our Statements of Consolidated Cash Flows).
Previous report
Based on information currently available, we expect our total capital investments for 2025, net of contributions from noncontrolling interests, to approximate $4.5 billion to $5.0 billion, which reflects growth capital investments of $4.0 billion to $4.5 billion and sustaining capital expenditures of $525 million. These amounts do not include capital investments associated with SPOT, our proposed deep-water offshore crude oil terminal, which remains subject to a final investment decision.
Previous report
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”). 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. 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).
Reworded paragraphs (70)
Previous wording
The following discussion and analysis of our financial condition, results of operations and related information for the years ended December 31, 2024 and 2023, 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.”).
Current wording
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.”).
Previous wording
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 32.4% of the Partnership’s common units outstanding at December 31, 2024.
Current wording
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.
Previous wording
This annual report on Form 10-K for the year ended December 31, 2024 (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.
Current wording
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.
Previous wording
In its February 2025 STEO, the EIA provided expectations of continued growth in U.S. crude oil and liquid fuels production of 0.6 MMBPD to reach 23.3 MMBPD in 2025. Global production of petroleum and liquid fuels is expected to reach an average of 104.6 MMBPD in 2025, up from 102.8 MMBPD in 2024, driven mostly by growth in U.S. and other non-OPEC production. The EIA expects domestic dry natural gas production to grow about 1.5 Bcf/d in 2025 to reach 104.6 Bcf/d for the year. With respect to demand, the EIA forecasts that global liquids fuel consumption will increase from 102.8 MMBPD in 2024 to 104.1 MMBPD in 2025, driven primarily by growth from Southeast Asia and other non-Organization for Economic Cooperation and Development (“OECD”) countries.
Current wording
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.
Previous wording
We believe crude oil and natural gas fundamentals are constructive, particularly in the U.S., based on rising supply and sufficient export capacity necessary to satisfy rising global demand. The potential for additional sanctions on crude oil exports from Russia, Iran and Venezuela would likely further increase global demand for U.S. crude oil. We also expect an increase in global demand for electricity, including demand in the U.S. associated with new data centers, which should help support natural gas-fired generation demand over the medium to long-term. The global petrochemical industry will continue to be challenged in 2025 by oversupply largely due to increased growth in China’s petrochemical production capacity as it focuses on export manufacturing to compensate for its domestic economic challenges. This oversupply situation has led to the rationalization of petrochemical production capacity in Europe, Japan and other countries. However, U.S. petrochemical producers are expected to continue to benefit from locally produced, lower-cost feedstocks and energy relative to their global peer group. 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.
Current wording
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.
Previous wording
We believe that these anticipated additions to hydrocarbon production and consumption levels, along with favorable pricing trends, will create additional opportunities for us to provide midstream services to our customers while leveraging the strengths of our portfolio, which include:
Current wording
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:
Previous wording
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.
Current wording
The Partnership guaranteed the senior notes issued in June 2025 and November 2025 through an unconditional guarantee on an unsecured and unsubordinated basis.
Previous wording
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.
Current wording
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.
Previous wording
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.
Current wording
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.
Previous wording
The weighted-average indicative market price for NGLs was $0.60 per gallon in 2024 and 2023.
Current wording
The weighted-average indicative market price for NGLs was$0.59 per gallon in 2025 compared to $0.60 per gallon in 2024.
Previous wording
Inflation rates in the U.S. increased significantly in 2022 and 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. 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.
Current wording
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.
Previous wording
Total revenues for 2024 increased a net $6.5 billion when compared to 2023 primarily due to higher marketing revenues.
Current wording
Total revenues for 2025 decreased a net $3.6 billion when compared to 2024 primarily due tolower marketing revenues.
Previous wording
Revenues from the marketing of NGLs, crude oil and petrochemicals and refined products increased a combined $7.1 billion year-to-year primarily due to higher sales volumes. Revenues from the marketing of natural gas decreased $915 million year-to-year primarily due to lower average sales prices.
Current wording
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.
Previous wording
Revenues from midstream services for 2024 increased $340 million when compared to 2023. Revenues from our natural gas transportation assets increased $138 million year-to-year primarily due to higher transportation revenues from our Texas Intrastate System. Revenues from our natural gas processing facilities increased $72 million year-to-year primarily due to an increase in equity NGL-equivalent production volumes we receive as non-cash consideration for processing services. Revenues from our Mont Belvieu area propylene production facilities increased $50 million year-to-year primarily due to higher propylene processing revenues as a result of contributions from our PDH 2 facility, which was placed into service in July 2023. Lastly, revenues from our Midland-to-ECHO System and related business activities increased $35 million year-to-year primarily due to higher demand for transportation services.
Current wording
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. Revenues 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.
Previous wording
Total operating costs and expenses for 2024 increased $6.0 billion when compared to 2023.
Current wording
Total operating costs and expenses for 2025 decreased a net $3.6 billion when compared to 2024.
Previous wording
Cost of sales for 2024 increased a net $5.6 billion when compared to 2023. The cost of sales associated with the marketing of NGLs, crude oil and petrochemicals and refined products increased a combined net $5.7 billion year-to-year primarily due to higher volumes, which accounted for a $6.6 billion increase, partially offset by lower average purchase prices, which accounted for an $896 million decrease. The cost of sales associated with the marketing of natural gas decreased $158 million year-to-year primarily due to lower average purchase prices.
Current wording
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.
Previous wording
Depreciation, amortization and accretion expense increased a combined $123 million year-to-year primarily due to higher depreciation expense on assets placed into full or limited service since the first quarter of 2023 (e.g., PDH 2, four natural gas processing trains in the Permian Basin, and Frac 12).
Current wording
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).
Previous wording
General and administrative costs for 2024 increased $13 million when compared to 2023 primarily due to higher employee compensation costs.
Current wording
General and administrative costs for 2025 increased $7 million when compared to 2024 primarily due to higher employee compensation costs.
Previous wording
Equity income from our unconsolidated affiliates for 2024 decreased $54 million when compared to 2023 primarily due to lower earnings from investments in crude oil and NGL pipelines.
Current wording
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.
Previous wording
Operating income for the year ended December 31, 2024 increased $409 million when compared to the year ended December 31, 2023 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.
Current wording
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.
Previous wording
Interest charged on debt principal outstanding, which is a key driver of interest expense, increased a net $96 million year-to-year. This increase was primarily due to the issuance of $2.0 billion and $2.5 billion of fixed-rate senior notes in January 2024 and August 2024, respectively, which accounted for a combined $144 million increase, partially offset by the retirement of $1.25 billion and $850 million of fixed-rate senior notes in March 2023 and February 2024, respectively, which accounted for a combined $38 million decrease, and a reduction in outstanding commercial paper notes, which accounted for an additional $14 million decrease.
Current wording
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.
Previous wording
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 2024 increased $21 million when compared to 2023 primarily due to changes in the valuation allowance on deferred taxes attributable to OTA in 2023.
Current wording
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.
Previous wording
Gross operating margin from natural gas processing and related NGL marketing activities for the year ended December 31, 2024 increased $298 million when compared to the year ended December 31, 2023.
Current wording
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.
Previous wording
Gross operating margin from our refined products marketing activities decreased a net $64 million year-to-year primarily due to lower average sales margins, which accounted for a $71 million decrease, partially offset by higher sales volumes, which accounted for a $7 million increase.
Current wording
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.
Previous wording
Gross operating margin from our Rockies natural gas processing facilities (Meeker, Pioneer and Chaco) decreased a combined $60 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 increased 240 MMcf/d and 7 MBPD, respectively, year-to-year.
Current wording
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.
Previous wording
Gross operating margin from our Midland Basin natural gas processing facilities increased a net $202 million year-to-year primarily due to higher average processing margins (including the impact of hedging activities), which accounted for a $111 million increase, a 19 MBPD increase inequity NGL-equivalent production volumes, which accounted for a $54 million increase, higher fee-based natural gas processing volumes, which accounted for a $51 million increase, and higher average processing fees, which accounted for an additional $11 million increase, partially offset by higher operating costs, which accounted for a $27 million decrease. Fee-based natural gas processing volumes at our Midland Basin natural gas processing facilities increased 349 MMcf/d year-to-year primarily due to contributions from our Poseidon and Leonidas natural gas processing trains, which were placed into service in the third quarter of 2023 and late first quarter of 2024, respectively.
Current wording
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.
Previous wording
Gross operating margin from our Delaware Basin natural gas processing facilities increased a net $64 million year-to-year primarily due to higher fee-based natural gas processing volumes, which accounted for a $58 million increase, and higher average processing margins (including the impact of hedging activities), which accounted for an additional $38 million increase, partially offset by lower average processing fees, which accounted for a $23 million decrease. Fee-based natural gas processing volumes at our Delaware Basin natural gas processing facilities increased 374 MMcf/d year-to-year, primarily due to processing volumes contributed by our Mentone 2 and Mentone 3 natural gas processing trains, which were placed into service in the fourth quarter of 2023 and late first quarter of 2024, respectively.
Current wording
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 tocontributions 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.
Previous wording
Gross operating margin from our NGL pipelines, storage and terminal assets for the year ended December 31, 2024 increased $217 million when compared to the year ended December 31, 2023.
Current wording
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.
Previous wording
A number of our pipelines, including the Mid-America Pipeline System, Seminole NGL Pipeline, Chaparral Pipeline, and Shin Oak NGL Pipeline, serve Permian Basin and/or Rocky Mountain producers. On a combined basis, gross operating margin from these pipelines increased a net$64 million year-to-year primarily due to a 186 MBPD (net to our interest) increase in transportation volumes, which accounted for a $95 million increase, and higher average transportation fees, which accounted for an additional $25 million increase, partially offset by higher operating costs, which accounted for a $50 million decrease.
Current wording
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.
Previous wording
Gross operating margin for our Eastern ethane pipelines, which include our ATEX and Aegis pipelines, increased a combined $30 million year-to-year primarily due to higher average transportation fees. Transportation volumes on these pipelines increased a combined 2 MBPD year-to-year.
Current wording
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.
Previous wording
Gross operating margin from LPG-related activities at EHT increased $63 million year-to-year primarily due to a 79 MBPD increase in LPG export volumes, which accounted for a $46 million increase, and higher average loading fees, which accounted for an additional $21 million increase. Gross operating margin from our related Houston Ship Channel Pipeline System increased $28 million year-to-year primarily due to a 99 MBPD increase in transportation volumes, which accounted for a $19 million increase, and higher average transportation fees, which accounted for an additional $11 million increase.
Current wording
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.
Previous wording
Gross operating margin from our Acadian Gas System increased a net $23 million year-to-year primarily due to higher average fees, which accounted for a $32 million increase, partially offset by higher operating costs, which accounted for a $9 million decrease. Transportation volumes on our Acadian Gas System increased 47 BBtus/d year-to-year.
Current wording
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.
Previous wording
Gross operating margin from NGL fractionation during the year ended December 31, 2024 increased $135 million when compared to the year ended December 31, 2023.
Current wording
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.
Previous wording
Gross operating margin from our Mont Belvieu area NGL fractionation complex increased a net $123 million year-to-year primarily due to higher fractionation volumes, which accounted for a $79 million increase, and higher ancillary service revenues, which accounted for an additional $51 million increase, partially offset by higher operating costs, which accounted for an $11 million decrease. NGL fractionation volumes at our Mont Belvieu area NGL fractionation complex increased 54 MBPD (net to our interest) primarily due to contributions from Frac 12, which entered service during the third quarter of 2023, and the acquisition of the remaining equity interest in EF78 in February 2024.
Current wording
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 from Frac 14, which was placed into service during the fourth quarter of 2025.
Previous wording
Gross operating margin from our Crude Oil Pipelines & Services segment for the year ended December 31, 2024 decreased $61 million when compared to the year ended December 31, 2023.
Current wording
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.
Previous wording
Gross operating margin from crude oil activities at EHT increased $11 million year-to-year primarily due to higher storage revenues, which accounted for a $5 million increase, and lower operating costs, which accounted for an additional $5 million increase. Crude oil terminal volumes at EHT increased 52 MBPD year-to-year.
Current wording
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.
Previous wording
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 $30 million year-to-year primarily due to a 458 BBtus/d increase in natural gas gathering volumes, which accounted for a $31 million increase, and a $23 million increase in treating and other revenues, partially offset by higher operating costs, which accounted for a $25 million decrease.
Current wording
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.
Previous wording
Gross operating margin from our Texas Intrastate System increased a net $109 million year-to-year primarily due to higher average transportation fees, which accounted for a $67 million increase, higher capacity reservation fees and other revenues, which accounted for a $39 million increase, and a 293 BBtus/d increase in transportation volumes, which accounted for an additional $16 million increase, partially offset by higher operating costs, which accounted for a $13 million decrease.
Current wording
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.
Previous wording
Gross operating margin from our natural gas marketing activities increased $105 million year-to-year primarily due to higher average sales margins.
Current wording
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.
Previous wording
Gross operating margin from our Midland Basin Gathering System increased a net $16 million year-to-year primarily due to a 434 BBtus/d increase in natural gas gathering volumes, which accounted for a $60 million increase, partially offset by higher operating costs, which accounted for a $44 million decrease.
Current wording
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.
Showing the first 40 of 70 pairs. Open the source sections for the rest.
Rearranged current paragraphs (4)
Current report — wording carried from elsewhere
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.
Current report — wording carried from elsewhere
Gross operating margin from our refined products marketing activities decreased $15 million year-to-year primarily due to lower average sales margins.
Current report — wording carried from elsewhere
(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.
Current report — wording carried from elsewhere
•our second natural gas processing train at our Mentone West location in the Delaware Basin (first quarter of 2026);
Rearranged previous paragraphs (2)
Previous report — wording carried elsewhere
Issuance of $2.5 Billion of Senior Notes in August 2024
Previous report — wording carried elsewhere
Gross operating margin from our Mont Belvieu area storage complex increased $49 million year-to-year primarily due to higher storage revenues.