Enterprise Products Partners LP
11/06/2025 | Press release | Distributed by Public on 11/06/2025 10:57
Quarterly Report for Quarter Ending September 30, 2025 (Form 10-Q)
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
For the Three and Nine Months Ended September 30, 2025and 2024
The following information should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and accompanying Notes included in this quarterly report on Form 10-Q and the Audited Consolidated Financial Statements and related Notes, together with our discussion and analysis of financial position and results of operations, included in our annual report on Form 10-K for the year ended December 31, 2024(the "2024Form 10-K"), as filed on February 28, 2025with the U.S. Securities and Exchange Commission ("SEC"). Our financial statements have been prepared in accordance with generally accepted accounting principles ("GAAP") in the United States ("U.S.").
Cautionary Statement Regarding Forward-Looking Information
This quarterly report on Form 10-Q for the three and nine months ended September 30, 2025(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.
Forward-looking statements are subject to a variety of risks, uncertainties and assumptions as described in more detail under Part I, Item 1A of our 2024Form 10-K and within Part II, Item 1A of this quarterly report. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. You should not put undue reliance on any forward-looking statements. The forward-looking statements in this quarterly report speak only as of the date hereof. Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason.
Key References Used in this Management's Discussion and Analysis
Unless the context requires otherwise, references to "we," "us" or "our" within this quarterly report are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries.
References to the "Partnership" or "Enterprise" mean Enterprise Products Partners L.P. on a standalone basis.
References to "EPO" mean Enterprise Products Operating LLC, which is an indirect wholly owned subsidiary of the Partnership, and its consolidated subsidiaries, through which the Partnership conducts its business. We are managed by our general partner, Enterprise Products Holdings LLC ("Enterprise GP"), which is a wholly owned subsidiary of Dan Duncan LLC, a privately held Texas limited liability company.
The membership interests of Dan Duncan LLC are owned by a voting trust, the current trustees ("DD LLC Trustees") of which are: (i) Randa Duncan Williams, who is also a director and Chairman of the Board of Directors of Enterprise GP (the "Board"); (ii) Richard H. Bachmann, who is also a director and Vice Chairman of the Board; and (iii) W. Randall Fowler, who is also a director and a Co-Chief Executive Officer of Enterprise GP. Ms. Duncan Williams and Messrs. Bachmann and Fowler also currently serve as managers of Dan Duncan LLC.
References to "EPCO" mean Enterprise Products Company, a privately held Texas corporation, and its privately held affiliates. The outstanding voting capital stock of EPCO is owned by a voting trust, the current trustees ("EPCO Trustees") of which are: (i) Ms. Duncan Williams, who serves as Chairman of EPCO; (ii) Mr. Bachmann, who serves as the President and Chief Executive Officer of EPCO; and (iii) Mr. Fowler, who serves as an Executive Vice President and the Chief Financial Officer of EPCO. Ms. Duncan Williams and Messrs. Bachmann and Fowler also currently serve as directors of EPCO.
We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates under the collective common control of the DD LLC Trustees and the EPCO Trustees. EPCO, together with its privately held affiliates, owned approximately 32.5%of the Partnership's common units outstanding at September 30, 2025.
As generally used in the energy industry and in this quarterly report, the acronyms below have the following meanings:
| /d | = | per day | MMBPD | = | million barrels per day | ||||||||||||
| BBtus | = | billion British thermal units | MMBtus | = | million British thermal units | ||||||||||||
| Bcf | = | billion cubic feet | MMcf | = | million cubic feet | ||||||||||||
| BPD | = | barrels per day | MWac | = | megawatts, alternating current | ||||||||||||
| MBPD | = | thousand barrels per day | MWdc | = | megawatts, direct current | ||||||||||||
| MMBbls | = | million barrels | TBtus | = | trillion British thermal units | ||||||||||||
As used in this quarterly report, the phrase "quarter-to-quarter" means the thirdquarter of 2025compared to the thirdquarter of 2024. Likewise, the phrase "period-to-period" means the ninemonths ended September 30, 2025compared to the nine months ended September 30, 2024.
Overview of Business
We are a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange ("NYSE") under the ticker symbol "EPD." Our preferred units are not publicly traded. We were formed in April 1998 to own and operate certain natural gas liquids ("NGLs") related businesses of EPCO and are a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, petrochemicals and refined products. We are owned by our limited partners (preferred and common unitholders) from an economic perspective. Enterprise GP, which owns a non-economic general partner interest in us, manages our Partnership. We conduct substantially all of our business operations through EPO and its consolidated subsidiaries.
Our fully integrated, midstream energy asset network (or "value chain") links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the U.S., Canada and the Gulf of Mexico with domestic consumers and international markets. Our midstream energy operations include:
•natural gas gathering, treating, processing, transportation and storage;
•NGL transportation, fractionation, storage, and marine terminals (including those used to export liquefied petroleum gases ("LPG") and ethane);
•crude oil gathering, transportation, storage, and marine terminals;
•propylene production facilities (including propane dehydrogenation ("PDH") facilities), butane isomerization, octane enhancement, isobutane dehydrogenation ("iBDH") and high purity isobutylene ("HPIB") production facilities;
•petrochemical and refined products transportation, storage, and marine terminals (including those used to export ethylene and polymer grade propylene ("PGP")); and
•a marine transportation business that operates on key U.S. inland and intracoastal waterway systems.
The safe operation of our assets is a top priority. We are committed to protecting the environment and the health and safety of the public and those working on our behalf by conducting our business activities in a safe and environmentally responsible manner. For additional information, see "Environmental, Safety and Conservation" within the Regulatory Matters section of Part I, Items 1 and 2 of the 2024Form 10-K.
Like many publicly traded partnerships, we have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement (the "ASA") or by other service providers.
Our financial position, results of operations and cash flows are subject to certain risks. For information regarding such risks, see "Risk Factors" included under Part I, Item 1A of the 2024Form 10-K and Part II, Item 1A of this quarterly report.
We provide investors access to additional information regarding the Partnership and our consolidated businesses, including information relating to governance procedures and principles, through our website, www.enterpriseproducts.com.
Recent Developments
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.
Issuance of $2.0 Billion of Senior Notes in June 2025
In June 2025, EPO issued $2.0 billion aggregate principal amount of senior notes comprised of (i) $500 million principal amount of senior notes due June 2028 ("Senior Notes LLL"), (ii) $750 million principal amount of senior notes due January 2031 ("Senior Notes MMM") and (iii) $750 million principal amount of senior notes due January 2036 ("Senior Notes NNN"). Net proceeds from this offering were used by EPO for general company purposes, including for growth capital investments, and the repayment of debt (including amounts outstanding under our commercial paper program).
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. The Partnership guaranteed these senior notes through an unconditional guarantee on an unsecured and unsubordinated basis.
Selected Energy Commodity Price Data
The following table presents selected average index prices for natural gas and selected NGL and petrochemical products for the periods indicated:
|
Natural Gas, $/MMBtu |
Ethane, $/gallon |
Propane, $/gallon |
Normal Butane, $/gallon |
Isobutane, $/gallon |
Natural Gasoline, $/gallon |
Polymer Grade Propylene, $/pound |
Refinery Grade Propylene, $/pound |
Indicative Gas Processing Gross Spread $/gallon |
|||||||||||||||||||||
| (1) | (2) | (2) | (2) | (2) | (2) | (3) | (3) | (4) | |||||||||||||||||||||
| 2024 by quarter: | |||||||||||||||||||||||||||||
| 1st Quarter | $2.25 | $0.19 | $0.84 | $1.03 | $1.14 | $1.54 | $0.55 | $0.18 | $0.43 | ||||||||||||||||||||
| 2nd Quarter | $1.89 | $0.19 | $0.75 | $0.90 | $1.26 | $1.55 | $0.47 | $0.21 | $0.43 | ||||||||||||||||||||
| 3rd Quarter | $2.15 | $0.16 | $0.73 | $0.97 | $1.08 | $1.48 | $0.53 | $0.28 | $0.39 | ||||||||||||||||||||
| 4th Quarter | $2.79 | $0.22 | $0.78 | $1.13 | $1.12 | $1.50 | $0.42 | $0.24 | $0.39 | ||||||||||||||||||||
| 2024 Averages | $2.27 | $0.19 | $0.78 | $1.01 | $1.15 | $1.52 | $0.49 | $0.23 | $0.41 | ||||||||||||||||||||
| 2025 by quarter: | |||||||||||||||||||||||||||||
| 1st Quarter | $3.65 | $0.27 | $0.90 | $1.06 | $1.07 | $1.53 | $0.45 | $0.33 | $0.37 | ||||||||||||||||||||
| 2nd Quarter | $3.44 | $0.24 | $0.78 | $0.88 | $0.93 | $1.32 | $0.38 | $0.30 | $0.30 | ||||||||||||||||||||
|
3rd Quarter
|
$3.07 | $0.23 | $0.69 | $0.86 | $0.92 | $1.30 | $0.36 | $0.28 | $0.30 | ||||||||||||||||||||
|
2025 Averages
|
$3.39 | $0.25 | $0.79 | $0.93 | $0.97 | $1.38 | $0.40 | $0.30 | $0.32 | ||||||||||||||||||||
(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 $0.56per gallon in the thirdquarter of 2025versus $0.57per gallon in the thirdquarter of 2024. Likewise, the weighted-average indicative market price for NGLs was $0.60per gallon during the ninemonths ended September 30, 2025 compared to $0.59 per gallon during the nine months ended September 30, 2024.
The following table presents selected average index prices for crude oil for the periods indicated:
|
WTI Crude Oil, $/barrel |
Midland Crude Oil, $/barrel |
Houston Crude Oil, $/barrel |
|||||||||
| (1) | (2) | (2) | |||||||||
| 2024 by quarter: | |||||||||||
| 1st Quarter | $76.96 | $78.55 | $78.85 | ||||||||
| 2nd Quarter | $80.57 | $81.73 | $82.33 | ||||||||
| 3rd Quarter | $75.10 | $75.96 | $76.51 | ||||||||
| 4th Quarter | $70.27 | $71.19 | $71.72 | ||||||||
| 2024 Averages | $75.73 | $76.86 | $77.35 | ||||||||
| 2025 by quarter: | |||||||||||
| 1st Quarter | $71.42 | $72.52 | $72.81 | ||||||||
| 2nd Quarter | $63.87 | $64.42 | $64.65 | ||||||||
| 3rd Quarter | $64.93 | $65.76 | $66.09 | ||||||||
| 2025 Averages | $66.74 | $67.57 | $67.85 | ||||||||
(1)WTI prices are based on commercial index prices at Cushing, Oklahoma as measured by the NYMEX.
(2)Midland and Houston crude oil prices are based on commercial index prices as reported by Argus.
Fluctuations in our consolidated revenues and cost of sales amounts are explained in large part by changes in energy commodity prices. An increase in our consolidated marketing revenues due to higher energy commodity sales prices may not result in an increase in gross operating margin or cash available for distribution, since our consolidated cost of sales amounts would also be expected to increase due to comparable increases in the purchase prices of the underlying energy commodities. The same type of relationship would be true in the case of lower energy commodity sales prices and purchase costs.
We attempt to mitigate commodity price exposure through our hedging activities and the use of fee-based arrangements. See Note 14of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report and "Quantitative and Qualitative Disclosures About Market Risk" under Part I, Item 3 of this quarterly report for information regarding our commodity hedging activities.
Impact of Inflation
Inflation rates in the U.S. increased significantly in 2022 and have remained elevated 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 has generally remained intact in 2025. In addition, there is uncertainty of what effect, if any, trade tariffs will have on inflation in future periods. However, to the extent that a rising cost environment impacts our results, there are typically offsetting benefits either inherent in our business or that result from other steps we take proactively to reduce the impact of inflation on our net operating results. These benefits include: (1) provisions included in our long-term fee-based revenue contracts that offset cost increases in the form of rate escalations based on positive changes in the U.S. Consumer Price Index, Producer Price Index for Finished Goods or other factors; (2) provisions in other revenue contracts that enable us to pass through higher energy costs to customers in the form of gas, electricity and fuel rebills or surcharges; and (3) higher commodity prices, which generally enhance our results in the form of increased volumetric throughput and demand for our services. Additionally, we take measures to mitigate the impact of cost increases in certain commodities, including a portion of our electricity needs, using fixed-price, term purchase agreements, or financial derivatives. For these reasons, the increased cost environment, caused in part by inflation, has not had a material impact on our historical results of operations for the periods presented in this report. However, a significant or prolonged period of high inflation could adversely impact our results if costs were to increase at a rate greater than the increase in the revenues we receive.
See "Capital Investments" within this Part I, Item 2 for a discussion of the impact of inflation on our capital investment decisions.
Income Statement Highlights
The following table summarizes the key components of our consolidated results of operations for the periods indicated (dollars in millions):
|
For the Three Months Ended September 30, |
For the Nine Months Ended September 30, |
||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| Revenues | $ | 12,023 | $ | 13,775 | $ | 38,803 | $ | 42,018 | |||||||||||||||
| Costs and expenses: | |||||||||||||||||||||||
| Operating costs and expenses: | |||||||||||||||||||||||
| Cost of sales | 8,590 | 10,387 | 28,494 | 31,976 | |||||||||||||||||||
| Other operating costs and expenses | 1,120 | 1,018 | 3,243 | 2,946 | |||||||||||||||||||
| Depreciation, amortization and accretion expenses | 643 | 601 | 1,886 | 1,791 | |||||||||||||||||||
| Asset impairment charges | 17 | 27 | 38 | 51 | |||||||||||||||||||
| Net losses (gains) attributable to asset sales and related matters | (4) | - | (13) | 5 | |||||||||||||||||||
| Total operating costs and expenses | 10,366 | 12,033 | 33,648 | 36,769 | |||||||||||||||||||
| General and administrative costs | 61 | 61 | 189 | 184 | |||||||||||||||||||
| Total costs and expenses | 10,427 | 12,094 | 33,837 | 36,953 | |||||||||||||||||||
| Equity in income of unconsolidated affiliates | 90 | 99 | 276 | 302 | |||||||||||||||||||
| Operating income | 1,686 | 1,780 | 5,242 | 5,367 | |||||||||||||||||||
| Other income (expense): | |||||||||||||||||||||||
| Interest expense | (354) | (343) | (1,026) | (1,006) | |||||||||||||||||||
| Other, net | 11 | 14 | 27 | 31 | |||||||||||||||||||
| Total other expense, net | (343) | (329) | (999) | (975) | |||||||||||||||||||
| Income before income taxes | 1,343 | 1,451 | 4,243 | 4,392 | |||||||||||||||||||
| Benefit from (provision for) income taxes | 13 | (19) | (27) | (55) | |||||||||||||||||||
| Net income | 1,356 | 1,432 | 4,216 | 4,337 | |||||||||||||||||||
| Net income attributable to noncontrolling interests | (17) | (14) | (47) | (56) | |||||||||||||||||||
| Net income attributable to preferred units | (1) | (1) | (3) | (3) | |||||||||||||||||||
| Net income attributable to common unitholders | $ | 1,338 | $ | 1,417 | $ | 4,166 | $ | 4,278 | |||||||||||||||
Revenues
The following table presents each business segment's contribution to consolidated revenues for the periods indicated (dollars in millions):
|
For the Three Months Ended September 30, |
For the Nine Months Ended September 30, |
||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| NGL Pipelines & Services: | |||||||||||||||||||||||
| Sales of NGLs and related products | $ | 2,736 | $ | 4,134 | $ | 10,110 | $ | 12,115 | |||||||||||||||
| Midstream services | 729 | 697 | 2,161 | 2,121 | |||||||||||||||||||
| Total | 3,465 | 4,831 | 12,271 | 14,236 | |||||||||||||||||||
| Crude Oil Pipelines & Services: | |||||||||||||||||||||||
| Sales of crude oil | 5,087 | 4,952 | 14,391 | 15,672 | |||||||||||||||||||
| Midstream services | 309 | 299 | 909 | 882 | |||||||||||||||||||
| Total | 5,396 | 5,251 | 15,300 | 16,554 | |||||||||||||||||||
| Natural Gas Pipelines & Services: | |||||||||||||||||||||||
| Sales of natural gas | 476 | 243 | 1,893 | 987 | |||||||||||||||||||
| Midstream services | 456 | 406 | 1,331 | 1,128 | |||||||||||||||||||
| Total | 932 | 649 | 3,224 | 2,115 | |||||||||||||||||||
| Petrochemical & Refined Products Services: | |||||||||||||||||||||||
| Sales of petrochemicals and refined products | 1,919 | 2,751 | 7,020 | 8,105 | |||||||||||||||||||
| Midstream services | 311 | 293 | 988 | 1,008 | |||||||||||||||||||
| Total | 2,230 | 3,044 | 8,008 | 9,113 | |||||||||||||||||||
| Total consolidated revenues | $ | 12,023 | $ | 13,775 | $ | 38,803 | $ | 42,018 | |||||||||||||||
ThirdQuarter of 2025Compared to ThirdQuarter of 2024. Total revenues for the thirdquarter of 2025 decreased $1.8 billionwhen compared to the thirdquarter of 2024primarily due to lowermarketing revenues.
Revenues from the marketing of NGLs and petrochemicals and refined products decreased a combined $2.2 billionquarter-to-quarter primarily due to lower average sales prices, which accounted for a $1.6 billion decrease, and lower sales volumes, which accounted for an additional $583 million decrease. Revenues from the marketing of natural gas increased $233 million quarter-to-quarter primarily due to higher average sales prices. Revenues from the marketing of crude oil increased a net $134 million quarter-to-quarter primarily due to higher sales volumes, which accounted for a $738 million increase, partially offset by lower average sales prices, which accounted for a $604 million decrease.
Revenues from midstream services for the thirdquarter of 2025 increased $110 millionwhen compared to the thirdquarter of 2024. Revenues from our NGL and natural gas transportation assets increased a combined $69 million quarter-to-quarter primarily due to higher demand for transportation services. Revenues from our natural gas processing facilities increased $20 million quarter-to-quarter primarily due to an increase in total fee-based natural gas processing volumes as a result of the contributions from our Orion and Mentone West 1 natural gas processing trains, which were placed into service in the third quarter of 2025. Lastly, revenues from our Midland-to-ECHO System increased $22 million quarter-to-quarter primarily due to higher demand for transportation services.
Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Total revenues for the nine months ended September 30, 2025 decreased $3.2 billionwhen compared to the nine months ended September 30, 2024primarily due to lowermarketing revenues.
Revenues from the marketing of NGLs and crude oil decreased a combined net $3.3 billion period-to-period primarily due to lower average sales prices, which accounted for a $4.9 billion decrease, partially offset by higher sales volumes, which accounted for a $1.6 billion increase. Revenues from the marketing of petrochemicals and refined products decreased $1.1 billion period-to-period primarily due to lower average sales prices. Revenues from the marketing of natural gas increased $906 million period-to-period primarily due to higher average sales prices.
Revenues from midstream services for the nine months ended September 30, 2025 increaseda net $250 millionwhen compared to the nine months ended September 30, 2024. Revenues from our NGL and natural gas transportation assets increased a combined $298 million period-to-period primarily due to higher demand for transportation services. Revenues from our octane enhancement and related plant operations decreased $34 million period-to-period primarily due to lower deficiency fee revenues. Lastly,revenues from our natural gas processing facilities decreased $29 million period-to-period primarily due to lower market values for the equity NGL-equivalent production volumes we receive as non-cash consideration for processing services.
Operating costs and expenses
Total operating costs and expenses for the three and nine months ended September 30, 2025 decreased $1.7 billionand $3.1 billion, respectively when compared to the same periods in 2024.
Cost of sales
ThirdQuarter of 2025Compared to ThirdQuarter of 2024. Cost of sales for the thirdquarter of 2025 decreaseda net $1.8 billionwhen compared to the thirdquarter of 2024. The cost of sales associated with the marketing of NGLs decreased $1.3 billion quarter-to-quarter primarily due to lower average purchase prices. The cost of sales associated with the marketing of petrochemicals and refined products decreased $798 millionquarter-to-quarter primarily due to lower volumes. The cost of sales associated with the marketing of crude oil increased a net $246 million quarter-to-quarter primarily due to higher volumes which accounted for a $677 million increase, partially offset by lower average purchase prices, which accounted for a $431 million decrease.
Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Cost of sales for the nine months ended September 30, 2025 decreaseda net $3.5 billionwhen compared to the nine months ended September 30, 2024. The cost of sales associated with the marketing of NGLs and crude oil decreased a combined net $2.7 billion period-to-period primarily due to lower average purchase prices, which accounted for a $4.2 billion decrease, partially offset by higher volumes, which accounted for a $1.5 billion increase. The cost of sales associated with the marketing of petrochemicals and refined products decreased $1.1 billion period-to-period primarily due to lower volumes. The cost of sales associated with the marketing of natural gas increased $308 million period-to-period primarily due to higher average purchase prices.
Other operating costs and expenses
Other operating costs and expenses for the three and ninemonths ended September 30, 2025 increased $102 millionand $297 million, respectively, when compared to the same periods in 2024 primarily due to higher employee compensation, maintenance and utility costs.
Depreciation, amortization and accretion expenses
Depreciation, amortization and accretion expense for the three and ninemonths ended September 30, 2025 increased $42 millionand $95 million, respectively, when compared to the same periods in 2024primarily due to higher depreciation expense on assets placed into full or limited service since the end of the respective periods in 2024.
General and administrative costs
General and administrative costs for the three months ended September 30, 2025 was flat when compared to the same period in 2024. General and administrative costs for the nine months ended September 30, 2025 increased $5 millionwhen compared to the same period in 2024primarily due to higher employee compensation costs.
Equity in income of unconsolidated affiliates
Equity income from our unconsolidated affiliates for the three and ninemonths ended September 30, 2025 decreased $9 millionand $26 million, respectively, when compared to the same periods in 2024primarily due to lower earnings from investments in NGL pipelines and services.
Operating income
Operating income for the three and ninemonths ended September 30, 2025 decreased $94 millionand$125 million, respectively, when compared to the same periods in 2024due to the previously described quarter-to-quarter and period-to-period changes.
Interest expense
The following table presents the components of our consolidated interest expense for the periods indicated (dollars in millions):
|
For the Three Months Ended September 30, |
For the Nine Months Ended September 30, |
||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| Interest charged on debt principal outstanding (1) | $ | 396 | $ | 369 | $ | 1,154 | $ | 1,073 | |||||||||||||||
| Impact of interest rate hedging program, including related amortization | (2) | (2) | (5) | (5) | |||||||||||||||||||
| Interest costs capitalized in connection with construction projects (2) | (49) | (31) | (147) | (82) | |||||||||||||||||||
| Other | 9 | 7 | 24 | 20 | |||||||||||||||||||
| Total | $ | 354 | $ | 343 | $ | 1,026 | $ | 1,006 | |||||||||||||||
(1)The weighted-average interest rates on debt principal outstanding during the three and nine months ended September 30, 2025 were 4.62% and 4.66%, respectively. The weighted-average interest rates on debt principal outstanding during the three and nine months ended September 30, 2024 were 4.59% and 4.60%, respectively.
(2)We capitalize interest costs incurred on funds used to construct property, plant and equipment while the asset is in its construction phase. Capitalized interest amounts become part of the historical cost of an asset and are charged to earnings (as a component of depreciation expense) on a straight-line basis over the estimated useful life of the asset once the asset enters its intended service. When capitalized interest is recorded, it reduces interest expense from what it would be otherwise. Capitalized interest amounts fluctuate based on the timing of when projects are placed into service, our capital investment levels and the interest rates charged on borrowings.
Interest charged on debt principal outstanding, which is a key driver of interest expense, increaseda net $27 million quarter-to-quarter and a net $81 millionperiod-to-period. These increases were primarily due to the issuance of $2.5 billion and $2.0 billion of fixed-rate senior notes in August 2024 and June 2025, respectively, which accounted for a combined increase of $37 million quarter-to-quarter and $106 million period-to-period. These increases were partially offset by the retirement of $1.15 billion of fixed-rate senior notes in February 2025, which accounted for a decrease of $11 million quarter-to-quarter and $27 million period-to-period.
For additional information regarding our debt obligations, see Note 7of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report. For a discussion of our capital projects, see "Capital Investments" within this Part I, Item 2.
Business Segment Highlights
Our operations are reported under four business segments: (i) NGL Pipelines & Services, (ii) Crude Oil Pipelines & Services, (iii) Natural Gas Pipelines & Services and (iv) Petrochemical & Refined Products Services. Our business segments are generally organized and managed according to the types of services rendered (or technologies employed) and products produced and/or sold.
We evaluate segment performance based on our financial measure of gross operating margin. Gross operating margin is an important performance measure of the core profitability of our operations and forms the basis of our internal financial reporting. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results.
The following table presents gross operating margin by segment and total gross operating margin, a non-generally accepted accounting principle ("non-GAAP") financial measure, for the periods indicated (dollars in millions):
|
For the Three Months Ended September 30, |
For the Nine Months Ended September 30, |
||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| Gross operating margin by segment: | |||||||||||||||||||||||
| NGL Pipelines & Services | $ | 1,303 | $ | 1,335 | $ | 4,018 | $ | 4,000 | |||||||||||||||
| Crude Oil Pipelines & Services | 371 | 401 | 1,148 | 1,229 | |||||||||||||||||||
| Natural Gas Pipelines & Services | 339 | 349 | 1,113 | 954 | |||||||||||||||||||
| Petrochemical & Refined Products Services | 370 | 363 | 1,039 | 1,199 | |||||||||||||||||||
| Total segment gross operating margin (1) | 2,383 | 2,448 | 7,318 | 7,382 | |||||||||||||||||||
| Net adjustment for shipper make-up rights | 2 | 6 | (25) | (26) | |||||||||||||||||||
| Total gross operating margin (non-GAAP) | $ | 2,385 | $ | 2,454 | $ | 7,293 | $ | 7,356 | |||||||||||||||
(1)Within the context of this table, total segment gross operating margin represents a subtotal and corresponds to measures similarly titled within our business segment disclosures found under Note 10 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.
Gross operating margin includes equity in the earnings of unconsolidated affiliates, but is exclusive of other income and expense transactions, income taxes, the cumulative effect of changes in accounting principles and extraordinary charges. Gross operating margin is presented on a 100% basis before any allocation of earnings to noncontrolling interests. Our calculation of gross operating margin may or may not be comparable to similarly titled measures used by other companies. Segment gross operating margin for NGL Pipelines & Services and Crude Oil Pipelines & Services reflect adjustments for shipper make-up rights that are included in management's evaluation of segment results. However, these adjustments are excluded from non-GAAP total gross operating margin.
The GAAP financial measure most directly comparable to total gross operating margin is operating income. For a discussion of operating income and its components, see the previous section titled "Income Statement Highlights" within this Part I, Item 2. The following table presents a reconciliation of operating income to total gross operating margin for the periods indicated (dollars in millions):
|
For the Three Months Ended September 30, |
For the Nine Months Ended September 30, |
||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| Operating income | $ | 1,686 | $ | 1,780 | $ | 5,242 | $ | 5,367 | |||||||||||||||
|
Adjustments to reconcile operating income to total gross operating margin (addition or subtraction indicated by sign):
|
|||||||||||||||||||||||
|
Depreciation, amortization and accretion expense in operating costs and expenses (1)
|
625 | 586 | 1,837 | 1,749 | |||||||||||||||||||
| Asset impairment charges in operating costs and expenses | 17 | 27 | 38 | 51 | |||||||||||||||||||
| Net losses (gains) attributable to asset sales and related matters in operating costs and expenses | (4) | - | (13) | 5 | |||||||||||||||||||
| General and administrative costs | 61 | 61 | 189 | 184 | |||||||||||||||||||
| Total gross operating margin (non-GAAP) | $ | 2,385 | $ | 2,454 | $ | 7,293 | $ | 7,356 | |||||||||||||||
(1)Excludes amortization of major maintenance costs for reaction-based plants and amortization of finance lease right-of-use assets, which are components of gross operating margin.
Each of our business segments benefits from the supporting role of our marketing activities. The main purpose of our marketing activities is to support the utilization and expansion of assets across our midstream energy asset network by increasing the volumes handled by such assets, which results in additional fee-based earnings for each business segment. In performing these support roles, our marketing activities also seek to participate in supply and demand opportunities as a supplemental source of gross operating margin for us. The financial results of our marketing efforts fluctuate due to changes in volumes handled and overall market conditions, which are influenced by current and forward market prices for the products bought and sold.
NGL Pipelines & Services
The following table presents segment gross operating margin and selected volumetric data for the NGL Pipelines & Services segment for the periods indicated (dollars in millions, volumes as noted):
|
For the Three Months Ended September 30, |
For the Nine Months Ended September 30, |
||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| Segment gross operating margin: | |||||||||||||||||||||||
| Natural gas processing and related NGL marketing activities | $ | 354 | $ | 371 | $ | 1,068 | $ | 1,115 | |||||||||||||||
| NGL pipelines, storage and terminals | 746 | 716 | 2,309 | 2,166 | |||||||||||||||||||
| NGL fractionation | 203 | 248 | 641 | 719 | |||||||||||||||||||
| Total | $ | 1,303 | $ | 1,335 | $ | 4,018 | $ | 4,000 | |||||||||||||||
| Selected volumetric data: | |||||||||||||||||||||||
| NGL pipeline transportation volumes (MBPD) | 4,694 | 4,303 | 4,570 | 4,296 | |||||||||||||||||||
| NGL marine terminal volumes (MBPD) | 908 | 887 | 947 | 886 | |||||||||||||||||||
| NGL fractionation volumes (MBPD) | 1,636 | 1,662 | 1,650 | 1,661 | |||||||||||||||||||
| Equity NGL-equivalent production volumes (MBPD) (1) | 225 | 204 | 221 | 203 | |||||||||||||||||||
| Fee-based natural gas processing volumes (MMcf/d) (2,3) | 7,454 | 6,850 | 7,303 | 6,617 | |||||||||||||||||||
(1)Primarily represents the NGL and condensate volumes we earn and take title to in connection with our processing activities. The total equity NGL-equivalent production volumes also include residue natural gas volumes from our natural gas processing business.
(2)Volumes reported correspond to the revenue streams earned by our natural gas processing plants.
(3)Fee-based natural gas processing volumes are measured at either the wellhead or plant inlet in MMcf/d.
Natural gas processing and related NGL marketing activities
ThirdQuarter of 2025Compared to ThirdQuarter of 2024. Gross operating margin from natural gas processing and related NGL marketing activities for the thirdquarter of 2025 decreased $17 millionwhen compared to the thirdquarter of 2024.
Gross operating margin from our NGL marketing activities decreased a net $21 million quarter-to-quarter primarily due to lower average sales margins, which accounted for a $49 million decrease, partially offset by higher mark-to-market earnings, which accounted for a $16 million increase, and higher sales volumes, which accounted for an additional $12 million increase.
Gross operating margin from our Rockies natural gas processing facilities (Meeker, Pioneer and Chaco) decreased a combined $11 million quarter-to-quarter 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 69 MMcf/d and increased 3 MBPD, respectively, quarter-to-quarter.
Gross operating margin from our Midland Basin natural gas processing facilities decreased a net $11 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $12 million decrease, and higher operating costs, which accounted for an additional $9 million decrease, partially offset by higher fee-based natural gas processing volumes, which accounted for an $8 million increase. Fee-based natural gas processing volumes at our Midland Basin natural gas processing facilities increased 211 MMcf/d quarter-to-quarter primarily due to contributions from our Orion natural gas processing train, which was placed into service in the third quarter of 2025.
Gross operating margin from our Delaware Basin natural gas processing facilities increased a net $13 million quarter-to-quarter primarily due to higher fee-based natural gas processing volumes, which accounted for a $10 million increase, and higher average processing margins (including the impact of hedging activities), which accounted for an additional $9 million increase, partially offset by higher operating costs, which accounted for a $6 million decrease. Fee-based natural gas processing volumes at our Delaware Basin natural gas processing facilities increased 240 MMcf/d quarter-to-quarter primarily due to contributions from our Mentone West 1 natural gas processing train, which was placed into service in the third quarter of 2025.
Gross operating margin from our Louisiana and Mississippi natural gas processing facilities increased $8 million quarter-to-quarter primarily due to higher average processing margins (including the impact of hedging activities), which accounted for a $4 million increase, a 12 MBPD increase in equity NGL-equivalent production volumes, which accounted for a $3 million increase, and a 318 MMcf/d increase in fee-based natural gas processing volumes, which accounted for an additional $2 million increase.
Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Gross operating margin from natural gas processing and related NGL marketing activities for the nine months ended September 30, 2025 decreased $47 millionwhen compared to the nine months ended September 30, 2024.
Gross operating margin from our NGL marketing activities decreased a net $58 million period-to-period primarily due to lower average sales margins, which accounted for a $97 million decrease, partially offset by higher sales volumes, which accounted for a $36 million increase, and higher mark-to-market earnings, which accounted for an additional $4 million increase.
Gross operating margin from our Rockies natural gas processing facilities (Meeker, Pioneer and Chaco) decreased a combined $28 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities). On a combined basis, fee-based natural gas processing volumes decreased 56 MMcf/d and equity NGL-equivalent production were flat period-to-period.
Gross operating margin from our Midland Basin natural gas processing facilities increased a net $20 million period-to-period primarily due to higher fee-based natural gas processing volumes, which accounted for a $29 million increase, and a 6 MBPD increase in equity NGL-equivalent production volumes, which accounted for an additional $14 million increase, partially offset by higher operating costs, which accounted for a $23 million decrease. Fee-based natural gas processing volumes at our Midland Basin natural gas processing facilities increased 329 MMcf/d period-to-period primarily due to contributions from our Leonidas and Orion natural gas processing trains, which were placed into service in late first quarter of 2024 and the third quarter of 2025, respectively.
Gross operating margin from our Delaware Basin natural gas processing facilities increased a net $14 million period-to-period 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 $21 million increase, partially offset by lower average processing margins (including the impact of hedging activities), which accounted for a $30 million decrease, and higher operating costs, which accounted for an additional $9 million decrease. Fee-based natural gas processing volumes at our Delaware Basin natural gas processing facilities increased 296 MMcf/d period-to-period primarily due to contributions from our Mentone 3 and Mentone West 1 natural gas processing trains, which were placed into service in late first quarter of 2024 and the third quarter of 2025, respectively.
NGL pipelines, storage and terminals
ThirdQuarter of 2025Compared to ThirdQuarter of 2024. Gross operating margin from our NGL pipelines, storage and terminal assets during the thirdquarter of 2025 increased $30 millionwhen compared to the thirdquarter of 2024.
Gross operating margin for our Eastern ethane pipelines, which include our ATEX and Aegis pipelines, increased a combined $19 million quarter-to-quarter primarily due to higher average transportation fees, which accounted for an $11 million increase, and a 109 MBPD increase in transportation volumes, which accounted for an additional $6 million increase.
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 $16 million quarter-to-quarter primarily due to a 138 MBPD increase in transportation volumes.
Gross operating margin from our Tri-States NGL Pipeline increased $5 million quarter-to-quarter primarily due to an 11 MBPD increase in transportation volumes.
Gross operating margin from our Mont Belvieu area storage complex increased a net $5 million quarter-to-quarter primarily due to higher storage revenues, which accounted for a $9 million increase, partially offset by higher operating costs, which accounted for a $4 million decrease.
Gross operating margin from our Dixie Pipeline and related terminals increased $4 million quarter-to-quarter primarily due to higher average transportation and related fees. Transportation volumes on our Dixie Pipeline increased 6 MBPD quarter-to-quarter.
Gross operating margin from LPG-related activities at our Enterprise Hydrocarbons Terminal ("EHT") decreased $44 million quarter-to-quarter primarily due to lower average loading fees. LPG export volumes at EHT decreased 42 MBPD quarter-to-quarter. Gross operating margin at our Morgan's Point and Neches River Export Terminals increased a combined $22 million quarter-to-quarter primarily due to higher ethane export volumes, which accounted for a $16 million increase, and higher other fee revenues, which accounted for an additional $4 million increase. Ethane export volumes at these terminals increased a combined 63 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. Gross operating margin from our related Houston Ship Channel Pipeline System increased a net $1 million quarter-to-quarter primarily due to a 70 MBPD increase in transportation volumes, which accounted for a $5 million increase, partially offset by higher operating costs, which accounted for a $4 million decrease.
Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Gross operating margin from our NGL pipelines, storage and terminal assets during the nine months ended September 30, 2025 increased $143 millionwhen compared to the nine months ended September 30, 2024.
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 $63 million period-to-period primarily due to an 84 MBPD increase in transportation volumes, which accounted for a $49 million increase, higher other revenues, which accounted for a $19 million increase, and higher average transportation fees, which accounted for an additional $10 million increase, partially offset by higher operating costs, which accounted for a $15 million decrease.
Gross operating margin for our Eastern ethane pipelines, which include our ATEX and Aegis pipelines, increased a combined $47 million period-to-period primarily due to higher average transportation fees, which accounted for a $29 million increase, and a 61 MBPD increase in transportation volumes, which accounted for an additional $15 million increase.
Gross operating margin from our Dixie Pipeline and related terminals increased $22 million period-to-period primarily due to higher average transportation fees, which accounted for an $11 million increase, and higher loading and other fee revenues, which accounted for an additional $10 million increase. Transportation volumes on our Dixie Pipeline increased 6 MBPD period-to-period.
Gross operating margin from our Tri-States NGL Pipeline increased $18 million period-to-period primarily due to a 9 MBPD increase in transportation volumes, which accounted for a $9 million increase, and higher average transportation fees, which accounted for an additional $5 million increase.
Gross operating margin from our South Texas NGL Pipeline System increased $15 million period-to-period primarily due to higher capacity reservation revenues, which accounted for an $8 million increase, and lower operating costs, which accounted for an additional $4 million increase. Transportation volumes on this system increased 15 MBPD period-to-period.
Gross operating margin from our Mont Belvieu area storage complex increased a net $12 million period-to-period primarily due to higher storage revenues, which accounted for a $22 million increase, partially offset by higher operating costs, which accounted for a $10 million decrease.
Gross operating margin from LPG-related activities at EHT decreased $84 million period-to-periodprimarily due to lower average loading fees, which accounted for a $76 million decrease, and higher operating costs, which accounted for an additional $11 million decrease. LPG export volumes at EHT increased 14 MBPD period-to-period. Gross operating margin at our Morgan's Point and Neches River Export Terminals increased a combined $42 million period-to-period primarily due to higher ethane export volumes, which accounted for a $36 million increase, and higher other fee revenues, which accounted for an additional $6 million increase. The combined 47 MBPD period-to-periodincrease 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 period-to-periodprimarily due to an 84 MBPD increase in transportation volumes.
NGL fractionation
ThirdQuarter of 2025Compared to ThirdQuarter of 2024. Gross operating margin from NGL fractionation during the thirdquarter of 2025 decreased $45 millionwhen compared to the thirdquarter of 2024.
Gross operating margin from our Mont Belvieu area NGL fractionation complex decreased $33 million quarter-to-quarter primarily due to higher operating costs, which accounted for a $20 million decrease, and lower ancillary service revenues, which accounted for an additional $13 million decrease. NGL fractionation volumes at our Mont Belvieu area NGL fractionation complex decreased 21 MBPD quarter-to-quarter.
On a combined basis, gross operating margin from NGL fractionators other than our Mont Belvieu area complex decreased $9 million quarter-to-quarter primarily due to lower ancillary service revenues. NGL fractionation volumes from these NGL fractionators decreased a combined 5 MBPD (net to our interest) quarter-to-quarter.
Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Gross operating margin from NGL fractionation during the nine months ended September 30, 2025 decreased $78 millionwhen compared to the nine months ended September 30, 2024.
Gross operating margin from our Mont Belvieu area NGL fractionation complex decreased $51 million period-to-period primarily due to higher operating costs, which accounted for a $28 million decrease, and lower ancillary service revenues, which accounted for an additional $23 million decrease. NGL fractionation volumes at our Mont Belvieu area NGL fractionation complex decreased 2 MBPD period-to-period.
On a combined basis, gross operating margin from NGL fractionators other than our Mont Belvieu area complex decreased $23 million period-to-period primarily due to lower ancillary service revenues. NGL fractionation volumes from these NGL fractionators decreased a combined 9 MBPD (net to our interest) period-to-period.
Crude Oil Pipelines & Services
The following table presents segment gross operating margin and selected volumetric data for the Crude Oil Pipelines & Services segment for the periods indicated (dollars in millions, volumes as noted):
|
For the Three Months Ended September 30, |
For the Nine Months Ended September 30, |
||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| Segment gross operating margin | $ | 371 | $ | 401 | $ | 1,148 | $ | 1,229 | |||||||||||||||
| Selected volumetric data: | |||||||||||||||||||||||
| Crude oil pipeline transportation volumes (MBPD) | 2,631 | 2,537 | 2,581 | 2,507 | |||||||||||||||||||
| Crude oil marine terminal volumes (MBPD) | 720 | 910 | 757 | 992 | |||||||||||||||||||
ThirdQuarter of 2025Compared to ThirdQuarter of 2024. Gross operating margin from our Crude Oil Pipelines & Services segment for the thirdquarter of 2025 decreased $30 millionwhen compared to the thirdquarter of 2024.
Gross operating margin from our Texas crude oil pipelines, related terminals and marketing activities (excluding the Seaway Pipeline) decreased a combined net $26 million quarter-to-quarter primarily due to lower average sales margins from marketing activities, which accounted for a $30 million decrease, lower mark-to-market earnings, which accounted for an $11 million decrease, and higher operating expenses, which accounted for an additional $8 million decrease, partially offset by a combined 99 MBPD (net to our interest) increase in crude oil transportation volumes, which accounted for a $12 million increase, and higher other revenues, which accounted for an additional $10 million increase.
Gross operating margin from crude oil activities at EHT decreased a net $1million quarter-to-quarter primarily due to lower storage and other revenues, which accounted for a $6 million decrease, partially offset by higher loading revenues, which accounted for a $5 million increase. Crude oil marine terminal volumes at EHT decreased 179 MBPD quarter-to-quarter.
Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Gross operating margin from our Crude Oil Pipelines & Services segment for the nine months ended September 30, 2025 decreased $81 millionwhen compared to the nine months ended September 30, 2024.
Gross operating margin from our Texas crude oil pipelines, related terminals and marketing activities (excluding the Seaway Pipeline) decreased a combined net $100 million period-to-period primarily due to lower sales volumes from marketing activities, which accounted for a $43 million decrease, lower average sales margins from marketing activities, which accounted for a $41 million decrease, lower mark-to-market earnings, which accounted for a $20 million decrease, and higher operating costs, which accounted for an additional $19 million decrease, partially offset by higher average crude oil transportation fees, which accounted for a $14 million increase, and a combined 74 MBPD (net to our interest) increase in crude oil transportation volumes, which accounted for an additional $10 million increase.
Gross operating margin from crude oil activities at EHT increased $26million period-to-period primarily due to lower operating costs, which accounted for a $12 million increase, higher loading revenues, which accounted for a $9 million increase, and higher storage and other revenues, which accounted for an additional $5 million increase. Crude oil marine terminal volumes at EHT decreased 217 MBPD period-to-period.
Natural Gas Pipelines & Services
The following table presents segment gross operating margin and selected volumetric data for the Natural Gas Pipelines & Services segment for the periods indicated (dollars in millions, volumes as noted):
|
For the Three Months Ended September 30, |
For the Nine Months Ended September 30, |
||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| Segment gross operating margin | $ | 339 | $ | 349 | $ | 1,113 | $ | 954 | |||||||||||||||
| Selected volumetric data: | |||||||||||||||||||||||
| Natural gas pipeline transportation volumes (BBtus/d) | 21,027 | 19,517 | 20,583 | 19,057 | |||||||||||||||||||
ThirdQuarter of 2025Compared to ThirdQuarter of 2024. Gross operating margin from our Natural Gas Pipelines & Services segment for the thirdquarter of 2025 decreased $10 millionwhen compared to the thirdquarter of 2024.
Gross operating margin from our natural gas marketing activities decreased $47 million quarter-to-quarter primarily due to lower mark-to-market earnings, which accounted for a $41 million decrease, and lower average sales margins, which accounted for an additional $6 million decrease.
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 $24 million quarter-to-quarter primarily due to higher treating and other revenues, which accounted for a $22 million increase, a 660 BBtus/d increase in natural gas gathering volumes, which accounted for an additional $13 million increase, partially offset by higher operating costs, which accounted for an $14 million decrease.
Gross operating margin from our Midland Basin Gathering System increased a net $7 million quarter-to-quarter primarily due to a 277 BBtus/d increase in natural gas gathering volumes, which accounted for a $12 million increase, partially offset by higher operating costs, which accounted for a $5 million decrease.
Gross operating margin from our Texas Intrastate System increased a net $5 million quarter-to-quarter primarily due to higher capacity reservation fees and other revenues, which accounted for a $23 million increase, and a 374 BBtus/d increase in transportation volumes, which accounted for an additional $4 million increase, partially offset by lower average transportation fees, which accounted for a $21 million decrease.
Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Gross operating margin from our Natural Gas Pipelines & Services segment for the nine months ended September 30, 2025 increased $159 millionwhen compared to the nine months ended September 30, 2024.
Gross operating margin from our Delaware Basin Gathering System, increased a net $69 million period-to-period primarily due to higher treating and other revenues, which accounted for a $59 million increase, a 649 BBtus/d increase in natural gas gathering volumes, which accounted for a $39 million increase, and higher average gathering fees, which accounted for an additional $12 million increase, partially offset by higher operating costs, which accounted for a $41 million decrease.
Gross operating margin from our Texas Intrastate System increased a net $53 million period-to-period primarily due to higher capacity reservation fees and other revenues, which accounted for a $58 million increase, and a 311 BBtus/d increase in transportation volumes, which accounted for an additional $11 million increase, partially offset by lower average transportation fees, which accounted for a $15 million decrease.
Gross operating margin from our Midland Basin Gathering System increased a net $23 million period-to-period primarily due to a 428 BBtus/d increase in natural gas gathering volumes, which accounted for a $45 million increase, partially offset by higher operating costs, which accounted for a $22 million decrease.
Gross operating margin from our natural gas marketing activities increased a net $13 million period-to-period primarily due to higher average sales margins, which accounted for a $21 million increase, and higher sales volumes, which accounted for an additional $9 million increase, partially offset by lower mark-to-market earnings, which accounted for a $17 million decrease.
Petrochemical & Refined Products Services
The following table presents segment gross operating margin and selected volumetric data for the Petrochemical & Refined Products Services segment for the periods indicated (dollars in millions, volumes as noted):
|
For the Three Months Ended September 30, |
For the Nine Months Ended September 30, |
||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| Segment gross operating margin: | |||||||||||||||||||||||
| Propylene production and related activities | $ | 112 | $ | 128 | $ | 332 | $ | 396 | |||||||||||||||
| Butane isomerization and related operations | 30 | 28 | 88 | 90 | |||||||||||||||||||
| Octane enhancement and related plant operations | 81 | 96 | 197 | 344 | |||||||||||||||||||
| Refined products pipelines and related activities | 93 | 67 | 274 | 212 | |||||||||||||||||||
| Ethylene exports and related activities | 36 | 25 | 90 | 106 | |||||||||||||||||||
| Marine transportation and other services | 18 | 19 | 58 | 51 | |||||||||||||||||||
| Total | $ | 370 | $ | 363 | $ | 1,039 | $ | 1,199 | |||||||||||||||
| Selected volumetric data: | |||||||||||||||||||||||
| Propylene production volumes (MBPD) | 119 | 124 | 117 | 112 | |||||||||||||||||||
| Butane isomerization volumes (MBPD) | 123 | 116 | 120 | 117 | |||||||||||||||||||
| Standalone deisobutanizer ("DIB") processing volumes (MBPD) | 196 | 191 | 190 | 199 | |||||||||||||||||||
| Octane enhancement and related plant sales volumes (MBPD) (1) | 41 | 37 | 42 | 37 | |||||||||||||||||||
| Pipeline transportation volumes, primarily refined products and petrochemicals (MBPD) | 1,056 | 995 | 1,003 | 942 | |||||||||||||||||||
| Marine terminal volumes, primarily refined products and petrochemicals (MBPD) | 347 | 286 | 329 | 333 | |||||||||||||||||||
(1)Reflects aggregate sales volumes for our octane enhancement and iBDH facilities located at our Mont Belvieu area complex and our HPIB facility located adjacent to the Houston Ship Channel.
Propylene production and related activities
ThirdQuarter of 2025Compared to ThirdQuarter of 2024. Gross operating margin from propylene production and related activities for the thirdquarter of 2025 decreased $16 million when compared to the thirdquarter of 2024.
On a combined basis, gross operating margin from our Mont Belvieu area propylene production facilities decreased a net $8 million quarter-to-quarter primarily due to higher operating costs, which accounted for a $16 million decrease, partially offset by higher propylene sales volumes, which accounted for a $5 million increase, and higher propylene processing and other revenues, which accounted for an additional $4 million increase. Propylene and associated by-product production volumes at these facilities decreased a combined 7 MBPD quarter-to-quarter.
Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Gross operating margin from propylene production and related activities for the nine months ended September 30, 2025 decreased $64 millionwhen compared to the nine months ended September 30, 2024.
On a combined basis, gross operating margin from our Mont Belvieu area propylene production facilities decreased a net $48 million period-to-period primarily due to higher operating costs, which accounted for an $82 million decrease, and lower average propylene sales margins, which accounted for an additional $42 million decrease, partially offset by higher propylene sales volumes, which accounted for a $52 million increase, and higher propylene processing and other revenues, which accounted for an additional $25 million increase . Propylene and associated by-product production volumes at these facilities increased a combined 4 MBPD.
Butane isomerization and related operations
ThirdQuarter of 2025Compared to ThirdQuarter of 2024. Gross operating margin from butane isomerization and related operations for the thirdquarter of 2025 increased $2 millionwhen compared to the thirdquarter of 2024primarily due to higher average sales margins and a 7 MBPD increase in isomerization volumes.
Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Gross operating margin from butane isomerization and related operations for the nine months ended September 30, 2025 decreased a net $2 millionwhen compared to the nine months ended September 30, 2024primarily due to higher operating costs, which accounted for a $9 million decrease, partially offset by higher ancillary service revenues, which accounted for a $7 million increase.
Octane enhancement and related plant operations
ThirdQuarter of 2025Compared to ThirdQuarter of 2024. Gross operating margin from our octane enhancement and related plant operations for the thirdquarter of 2025 decreased a net $15 millionwhen compared to the thirdquarter of 2024primarily due to lower average sales margins, which accounted for a $27 million decrease, and higher operating costs, which accounted for an additional $5 million decrease, partially offset by higher sales volumes, which accounted for a $17 million increase.
Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Gross operating margin from our octane enhancement and related plant operations for the nine months ended September 30, 2025 decreaseda net $147 millionwhen compared to the nine months ended September 30, 2024primarily due to lower average sales margins, which accounted for a $125 million decrease, lower deficiency revenues, which accounted for a $32 million decrease, and higher operating costs, which accounted for an additional $8 million decrease, partially offset by higher sales volumes, which accounted for a $19 million increase.
Refined products pipelines and related activities
ThirdQuarter of 2025Compared to ThirdQuarter of 2024. Gross operating margin from refined products pipelines and related activities for the thirdquarter of 2025 increased $26 millionwhen compared to the thirdquarter of 2024.
Gross operating margin from our TW Products System increased $10 million quarter-to-quarter primarily due to the full start-up of the system, which was placed into service in stages during 2024 and was fully operational in October 2024.
Gross operating margin from our TE Products Pipeline System increased a net $9 million quarter-to-quarter primarily due to a 61 MBPD increase in transportation volumes, which accounted for a $16 million increase, partially offset by higher operating costs, which accounted for a $10 million decrease.
Gross operating margin from our refined products marketing activities increased a net $5 million quarter-to-quarter primarily due to higher average sales margins, which accounted for a $13 million increase, partially offset by lower sales volumes, which accounted for a $6 million decrease.
Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Gross operating margin from refined products pipelines and related activities for the nine months ended September 30, 2025 increased $62 millionwhen compared to the nine months ended September 30, 2024.
Gross operating margin from our TE Products Pipeline System increased a net $38 million period-to-period primarily due to a 33 MBPD increase in transportation volumes, which accounted for a $39 million increase, higher average transportation fees, which accounted for a $12 million increase, and higher other revenues, which accounted for an additional $10 million increase, partially offset by higher operating costs, which accounted for a $23 million decrease.
Gross operating margin from our TW Products System increased $36 million period-to-period primarily due to the full start-up of the system, which was placed into service in stages during 2024 and was fully operational in October 2024.
Gross operating margin from our refined products marketing activities decreased $14 million period-to-period primarily due to lower average sales margins.
Ethylene exports and related activities
ThirdQuarter of 2025Compared to ThirdQuarter of 2024. Gross operating margin from ethylene exports and related activities for the thirdquarter of 2025 increaseda net $11 millionwhen compared to the thirdquarter of 2024primarily due to a 28 MBPD increase in ethylene export volumes, which accounted for a $14 million increase, and higher storage and other revenues, which accounted for a $3 million increase, partially offset by higher operating costs, which accounted for a $7 million decrease. Ethylene transportation volumes increased 22 MBPD quarter-to-quarter.
Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Gross operating margin from ethylene exports and related activities for the nine months ended September 30, 2025 decreased a net $16 millionwhen compared to the nine months ended September 30, 2024primarily due to lower deficiency fee revenues from our ethylene pipelines, which accounted for a $16 million decrease, and higher operating costs, which accounted for an additional $10 million decrease, partially offset by a 3 MBPD increase in ethylene export volumes, which accounted for a $5 million increase, and higher storage and other revenues, which accounted for an additional $5 million increase. Ethylene transportation volumes increased 3 MBPD period-to-period.
Marine transportation and other services
ThirdQuarter of 2025Compared to ThirdQuarter of 2024. Gross operating margin from marine transportation and other services for the thirdquarter of 2025 decreased $1 millionwhen compared to the thirdquarter of 2024primarily due to higher operating costs.
Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Gross operating margin from marine transportation and other services for the nine months ended September 30, 2025 increaseda net $7 millionwhen compared to the nine months ended September 30, 2024primarily due to higher average fees, which accounted for a $10 million increase, partially offset by higher operating costs, which accounted for a $3 million decrease.
Liquidity and Capital Resources
Based on current market conditions (as of the filing date of this quarterly report), we believe that the Partnership and its consolidated businesses will have sufficient liquidity, cash flow from operations and access to capital markets to fund their capital investments and working capital needs for the reasonably foreseeable future. At September 30, 2025, we had $3.6 billionof consolidated liquidity. This amount was comprised of $3.4 billionof available borrowing capacity under EPO's revolving credit facilities, which is the net of $4.2 billionof total borrowing capacity under EPO's revolving credit facilities and $840 millionoutstanding under EPO's commercial paper program, and $206 millionof unrestricted cash on hand.
We may issue debt and equity securities to assist us in meeting our future funding and liquidity requirements, including those related to capital investments. We have a universal shelf registration statement on file with the SEC that allows the Partnership and EPO to issue an unlimited amount of equity and debt securities, respectively. In addition, we have a registration statement on file with the SEC covering the issuance of up to $2.5 billion of the Partnership's common units in amounts, at prices and on terms based on market conditions and other factors at the time of such offerings (referred to as the Partnership's at-the-market ("ATM") program).
Enterprise Declares Cash Distribution for ThirdQuarter of 2025
On October 7, 2025, we announced that the Board declared a quarterly cash distribution of $0.545per common unit, or $2.18per common unit on an annualized basis, to be paid to the Partnership's common unitholders with respect to the third quarter of 2025. The quarterly distribution is payable on November 14, 2025 to unitholders of record as of the close of business on October 31, 2025. The total amount to be paid is $1.19 billion, which includes $11 millionfor distribution equivalent rights on phantom unit awards.
The payment of quarterly cash distributions is subject to management's evaluation of our financial condition, results of operations and cash flows in connection with such payments and Board approval. Management will evaluate any future increases in cash distributions on a quarterly basis.
Consolidated Debt
At September 30, 2025, the average maturity of EPO's consolidated debt obligations was approximately 17.2 years. The following table presents the scheduled maturities of principal amounts of EPO's consolidated debt obligations at September 30, 2025for the years indicated (dollars in millions):
| Scheduled Maturities of Debt | |||||||||||||||||||||||||||||||||||||||||
| Total |
Remainder of 2025 |
2026 | 2027 | 2028 | 2029 | Thereafter | |||||||||||||||||||||||||||||||||||
| Commercial Paper Notes | $ | 840 | $ | 840 | $ | - | $ | - | $ | - | $ | - | $ | - | |||||||||||||||||||||||||||
| Senior Notes | 30,775 | - | 1,625 | 1,575 | 1,500 | 1,250 | 24,825 | ||||||||||||||||||||||||||||||||||
| Junior Subordinated Notes | 2,282 | - | - | - | - | - | 2,282 | ||||||||||||||||||||||||||||||||||
| Total | $ | 33,897 | $ | 840 | $ | 1,625 | $ | 1,575 | $ | 1,500 | $ | 1,250 | $ | 27,107 | |||||||||||||||||||||||||||
In March 2025, EPO entered into a new 364-Day Revolving Credit Agreement (the "March 2025$1.5Billion 364-Day Revolving Credit Agreement") that replaced its prior 364-day revolving credit agreement. The March 2025$1.5Billion 364-Day Revolving Credit Agreement matures in March 2026. EPO's borrowing capacity was unchanged from the prior 364-day revolving credit agreement. As of September 30, 2025, there are no principal amounts outstanding under this new revolving credit agreement.
Also in March 2025, EPO amended its Multi-Year Revolving Credit Agreement (the "March 2023$2.7Billion Multi-Year Revolving Credit Agreement") to extend its maturity date from March 2028 to March 2030. The remaining material terms of the March 2023$2.7Billion Multi-Year Revolving Credit Agreement, as amended, are consistent with those reported in our 2024 Form 10-K. As of September 30, 2025, there are no principal amounts outstanding under this revolving credit agreement.
In June 2025, EPO issued $2.0 billion aggregate principal amount of senior notes comprised of (i) $500 million principal amount of senior notes due June 2028 ("Senior Notes LLL"), (ii) $750 million principal amount of senior notes due January 2031 ("Senior Notes MMM") and (iii) $750 million principal amount of senior notes due January 2036 ("Senior Notes NNN"). Senior Notes LLL were issued at 99.869% of their principal amount and have a fixed interest rate of 4.30% per year. Senior Notes MMM were issued at 99.816% of their principal amount and have a fixed interest rate of 4.60% per year. Senior Notes NNN were issued at 99.665% of their principal amount and have a fixed interest rate of 5.20% per year. Net proceeds from this offering were used by EPO for general company purposes, including for growth capital investments, and the repayment of debt (including amounts outstanding under our commercial paper program).
For additional information regarding our consolidated debt obligations, see Note 7of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.
Credit Ratings
As of November 6, 2025, the investment-grade credit ratings of EPO's long-term senior unsecured debt securities were A- from Standard and Poor's, A3 from Moody's and A- from Fitch Ratings. In addition, the credit ratings of EPO's short-term senior unsecured debt securities were A-2 from Standard and Poor's, P-2 from Moody's and F-2 from Fitch Ratings. EPO's credit ratings reflect only the view of a rating agency and should not be interpreted as a recommendation to buy, sell or hold any of our securities. A credit rating can be revised upward or downward or withdrawn at any time by a rating agency, if it determines that circumstances warrant such a change. A credit rating from one rating agency should be evaluated independently of credit ratings from other rating agencies.
Common Unit Repurchases Under 2019 Buyback Program
In January 2019, we announced that the Board had approved a $2.0 billion multi-year unit buyback program (the "2019 Buyback Program"), which provides the Partnership with an additional method to return capital to investors. The Partnership repurchased 2,543,004 and 7,913,198common units during the three and ninemonths ended September 30, 2025, respectively. The total cost of these repurchases, including commissions and fees was $80 million and $250 million, respectively. As of September 30, 2025, the remaining available capacity under the 2019 Buyback Program was $613 million.
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.
Cash Flow Statement Highlights
The following table summarizes our consolidated cash flows from operating, investing and financing activities for the periods indicated (dollars in millions).
|
For the Nine Months Ended September 30, |
|||||||||||
| 2025 | 2024 | ||||||||||
| Net cash flow provided by operating activities | $ | 6,113 | $ | 5,757 | |||||||
| Net cash flow used in investing activities | 4,256 | 3,433 | |||||||||
| Net cash flow used in financing activities | 2,263 | 971 | |||||||||
Net cash flow provided by operating activities are largely dependent on earnings from our consolidated business activities. Changes in energy commodity prices may impact the demand for natural gas, NGLs, crude oil, petrochemicals and refined products, which could impact sales of our products and the demand for our midstream services. Changes in demand for our products and services may be caused by other factors, including prevailing economic conditions, reduced demand by consumers for the end products made with hydrocarbon products, increased competition, public health emergencies, adverse weather conditions and government regulations affecting prices and production levels. We may also incur credit and price risk to the extent customers do not fulfill their contractual obligations to us in connection with our marketing activities and long-term take-or-pay and dedication agreements. For a more complete discussion of these and other risk factors pertinent to our business, see "Risk Factors" included under Part I, Item 1A of the 2024Form 10-K and Part II, Item 1A of this quarterly report.
For additional information regarding our cash flow amounts, please refer to the Unaudited Condensed Statements of Consolidated Cash Flows included under Part I, Item 1 of this quarterly report.
The following information highlights significant quarter-to-quarter fluctuations in our consolidated cash flow amounts:
Operating activities
Net cash flow provided by operating activities for the nine months ended September 30, 2025 increased $356 millionwhen compared to the nine months ended September 30, 2024primarily due to changes in operating accounts primarily due to the use of working capital employed in our marketing activities, which includes the impact of (i) fluctuations in commodity prices, (ii) timing of our inventory purchase and sale strategies, and (iii) changes in margin deposit requirements associated with our commodity derivative instruments.
For information regarding significant period-to-periodchanges in our consolidated net income and underlying segment results, see "Income Statement Highlights" and "Business Segment Highlights" within this Part I, Item 2.
Investing activities
Net cash flow used in investing activities during the nine months ended September 30, 2025 increased $823 millionwhen compared to the nine months ended September 30, 2024primarily due to an increasein investments for property, plant and equipment (see "Capital Investments" within this Part I, Item 2 for additional information).
Financing activities
Net cash flow used in financing activities during the nine months ended September 30, 2025 increaseda net $1.3 billionwhen compared to the nine months ended September 30, 2024primarily due to:
•a net cash inflowof $1.7 billionrelated to debt transactions that occurred during the nine months ended September 30, 2025compared to a net cash inflowof $3.1 billionrelated to debt transactions that occurred during the nine months ended September 30, 2024. During the nine months ended September 30, 2025, we issued $2.0 billion aggregate principal amount of senior notes and issued a net $840 million under EPO's commercial paper program, partially offset by the repayment of $1.15 billion principal amount of senior notes. During the nine months ended September 30, 2024, we issued $4.5 billion aggregate principal amount of senior notes, partially offset by the repayment of $850 million principal amount of senior notes and net repayments of $450 million under EPO's commercial paper program;
•a $125 million period-to-period increasein cash distributions paid to common unitholders primarily attributable to increases in the quarterly cash distribution rate per unit; and
•a $94 million period-to-period increase in the repurchase of common units under the 2019 Buyback Program; partially offset by
•a $400 million cash outflow during the first quarter of 2024 in connection with the acquisition of noncontrolling interests from affiliates of Western Midstream Partners, LP.
Non-GAAP Cash Flow Measures
Distributable Cash Flow and Operational Distributable Cash Flow
Our partnership agreement requires us to make quarterly distributions to our common unitholders of all available cash, after any cash reserves established by Enterprise GP in its sole discretion. Cash reserves include those for the proper conduct of our business, including those for capital investments, debt service, working capital, operating expenses, common unit repurchases, commitments and contingencies and other amounts. The retention of cash allows us to reinvest in our growth and reduce our future reliance on the equity and debt capital markets.
We measure available cash by reference to distributable cash flow ("DCF"), which is a non-GAAP cash flow measure. DCF is an important financial measure for our common unitholders since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flows at a level that can sustain our declared quarterly cash distributions. DCF is also a quantitative standard used by the investment community with respect to publicly traded partnerships since the value of a partnership unit is, in part, measured by its yield, which is based on the amount of cash distributions a partnership can pay to a unitholder. Our management compares the DCF we generate to the cash distributions we expect to pay our common unitholders. Using this metric, management computes our distribution coverage ratio. Our calculation of DCF may or may not be comparable to similarly titled measures used by other companies.
Based on the level of available cash each quarter, management proposes a quarterly cash distribution rate to the Board, which has sole authority in approving such matters. Enterprise GP has a non-economic ownership interest in the Partnership and is not entitled to receive any cash distributions from it based on incentive distribution rights or other equity interests.
Operational distributable cash flow ("Operational DCF"), which is defined as DCF excluding the impact of proceeds from asset sales and other matters and monetization of interest rate derivative instruments, is a supplemental non-GAAP liquidity measure that quantifies the portion of cash available for distribution to common unitholders that was generated from our normal operations. We believe that it is important to consider this non-GAAP measure as it provides an enhanced perspective of our assets' ability to generate cash flows without regard for certain items that do not reflect our core operations.
Our use of DCF and Operational DCF for the limited purposes described above and in this quarterly report is not a substitute for net cash flow provided by operating activities, which is the most comparable GAAP measure to DCF and Operational DCF. For a discussion of net cash flow provided by operating activities, see "Cash Flow Statement Highlights" within this Part I, Item 2.
The following table summarizes our calculation of DCF and Operational DCF for the periods indicated (dollars in millions):
|
For the Three Months Ended September 30, |
For the Nine Months Ended September 30, |
||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| Net income attributable to common unitholders (GAAP) (1) | $ | 1,338 | $ | 1,417 | $ | 4,166 | $ | 4,278 | |||||||||||||||
| Adjustments to net income attributable to common unitholders to derive DCF and Operational DCF (addition or subtraction indicated by sign): | |||||||||||||||||||||||
| Depreciation, amortization and accretion expenses | 660 | 618 | 1,939 | 1,845 | |||||||||||||||||||
| Cash distributions received from unconsolidated affiliates (2) | 112 | 124 | 336 | 367 | |||||||||||||||||||
| Equity in income of unconsolidated affiliates | (90) | (99) | (276) | (302) | |||||||||||||||||||
| Asset impairment charges | 17 | 27 | 38 | 51 | |||||||||||||||||||
| Change in fair market value of derivative instruments | 34 | (3) | 24 | (11) | |||||||||||||||||||
| Deferred income tax expense (benefit) | (17) | 9 | (1) | 23 | |||||||||||||||||||
| Sustaining capital expenditures (3) | (198) | (129) | (417) | (554) | |||||||||||||||||||
| Other, net | (37) | (8) | (67) | 9 | |||||||||||||||||||
| Operational DCF (non-GAAP) | $ | 1,819 | $ | 1,956 | $ | 5,742 | $ | 5,706 | |||||||||||||||
| Proceeds from asset sales and other matters | 6 | 5 | 21 | 11 | |||||||||||||||||||
| Monetization of interest rate derivative instruments accounted for as cash flow hedges | - | (4) | 14 | (33) | |||||||||||||||||||
| DCF (non-GAAP) | $ | 1,825 | $ | 1,957 | $ | 5,777 | $ | 5,684 | |||||||||||||||
| Cash distributions paid to common unitholders with respect to period, including distribution equivalent rights on phantom unit awards | $ | 1,190 | $ | 1,149 | $ | 3,552 | $ | 3,428 | |||||||||||||||
| Cash distribution per common unit declared by Enterprise GP with respect to period (4) | $ | 0.5450 | $ | 0.5250 | $ | 1.6250 | $ | 1.5650 | |||||||||||||||
| Total DCF retained by the Partnership with respect to period (5) | $ | 635 | $ | 808 | $ | 2,225 | $ | 2,256 | |||||||||||||||
| Distribution coverage ratio (6) | 1.5 | x | 1.7 | x | 1.6 | x | 1.7 | x | |||||||||||||||
(1)For a discussion of the primary drivers of changes in our comparative income statement amounts, see "Income Statement Highlights" within this Part I, Item 2.
(2)Reflects aggregate distributions received from unconsolidated affiliates attributable to both earnings and the return of capital.
(3)Sustaining capital expenditures include cash payments and accruals applicable to the period.
(4)See Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report for information regarding our quarterly cash distributions declared with respect to the periods indicated.
(5)Cash retained by the Partnership may be used for capital investments, debt service, working capital, operating expenses, common unit repurchases, commitments and contingencies and other amounts. The retention of cash reduces our reliance on the capital markets.
(6)Distribution coverage ratio is determined by dividing DCF by total cash distributions paid to common unitholders and in connection with distribution equivalent rights with respect to the period.
The following table presents a reconciliation of net cash flow provided by operating activities to DCF and Operational DCF for the periods indicated (dollars in millions):
|
For the Three Months Ended September 30, |
For the Nine Months Ended September 30, |
||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| Net cash flow provided by operating activities (GAAP) | $ | 1,738 | $ | 2,072 | $ | 6,113 | $ | 5,757 | |||||||||||||||
| Adjustments to reconcile net cash flow provided by operating activities to DCF and Operational DCF (addition or subtraction indicated by sign): | |||||||||||||||||||||||
| Net effect of changes in operating accounts | 322 | 36 | 169 | 563 | |||||||||||||||||||
| Sustaining capital expenditures | (198) | (129) | (417) | (554) | |||||||||||||||||||
| Distributions received from unconsolidated affiliates attributable to the return of capital | 21 | 25 | 56 | 64 | |||||||||||||||||||
| Net income attributable to noncontrolling interests | (17) | (14) | (47) | (56) | |||||||||||||||||||
| Other, net | (47) | (34) | (132) | (68) | |||||||||||||||||||
| Operational DCF (non-GAAP) | $ | 1,819 | $ | 1,956 | $ | 5,742 | $ | 5,706 | |||||||||||||||
| Proceeds from asset sales and other matters | 6 | 5 | 21 | 11 | |||||||||||||||||||
| Monetization of interest rate derivative instruments accounted for as cash flow hedges | - | (4) | 14 | (33) | |||||||||||||||||||
| DCF (non-GAAP) | $ | 1,825 | $ | 1,957 | $ | 5,777 | $ | 5,684 | |||||||||||||||
Capital Investments
Since the beginning of 2025, we have placed into service two natural gas processing trains in the Permian Basin, the first phase of our Neches River Ethane / Propane Export Facility and an NGL fractionator ("Frac 14") and associated DIB unit at our Mont Belvieu area NGL fractionation complex. We have approximately $5.1 billion of growth capital projects scheduled to be completed by the end of 2026, including the following projects (including their respective scheduled completion dates):
•natural gas gathering, compression and treating expansion projects in the Delaware and Midland Basins (2025 and 2026);
•the Bahia NGL Pipeline (fourth quarter of 2025);
•the second phase of enhancements at our Morgan's Point terminal (fourth quarter of 2025);
•the second phase of our Neches River Ethane / Propane Export Facility located in Orange County, Texas (first half of 2026);
•our second natural gas processing train at our Mentone West location in the Delaware Basin (first half of 2026);
•the expansion of our LPG and PGP export capacity at EHT, including Ref 4 (fourth quarter of 2026); and
•a ninth natural gas processing train ("Athena") in the Midland Basin (fourth quarter of 2026).
Based on information currently available, we expect our total organic capital investments for 2025, net of contributions from noncontrolling interests, to approximate $5.0 billion, which reflects organic growth capital investments of $4.5 billion and sustaining capital expenditures of $525 million.
Our forecast of capital investments is dependent upon our ability to generate the required funds from either operating cash flows or other means, including borrowings under debt agreements, the issuance of additional equity and debt securities, and potential divestitures. We may revise our forecast of capital investments due to factors beyond our control, such as adverse economic conditions, weather-related issues and changes in supplier prices resulting from raw material or labor shortages, supply chain disruptions or inflation. Furthermore, our forecast of capital investments may change over time based on future decisions by management, which may include changing the scope or timing of projects or cancelling projects altogether. Our success in raising capital, having the ability to increase revenues commensurate with cost increases and our ability to partner with other companies to share project costs and risks continue to be significant factors in determining how much capital we can invest. We believe our access to capital resources is sufficient to meet the demands of our current and future growth needs, and although we currently expect to make the forecast capital investments noted above, we may revise our plans in response to changes in economic and capital market conditions.
The following table summarizes our capital investments for the periods indicated (dollars in millions):
|
For the Nine Months Ended September 30, |
|||||||||||
| 2025 | 2024 | ||||||||||
|
Capital investments: (1)
|
|||||||||||
| Growth capital projects (2) | $ | 3,368 | $ | 2,950 | |||||||
| Sustaining capital projects (3) | 368 | 535 | |||||||||
|
Asset acquisitions (4)
|
583 | - | |||||||||
| Total | $ | 4,319 | $ | 3,485 | |||||||
(1)Growth capital, sustaining capital and asset acquisition amounts presented in the table above are presented on a cash basis. In total, these amounts represent "Capital expenditures" as presented on our Unaudited Condensed Statements of Consolidated Cash Flows.
(2)Growth capital projects either (a) result in new sources of cash flow due to enhancements of or additions to existing assets (e.g., additional revenue streams, cost savings resulting from debottlenecking of a facility, etc.) or (b) expand our asset base through construction of new facilities that will generate additional revenue streams and cash flows.
(3)Sustaining capital projects are capital expenditures (as defined by GAAP) resulting from improvements to existing assets. Such expenditures serve to maintain existing operations but do not generate additional revenues or result in significant cost savings. Sustaining capital expenditures include the costs of major maintenance activities at our reaction-based plants, which are accounted for using the deferral method.
(4)Amount for the nine months ended September 30, 2025 represents the total cost of the acquisition of the Oxy natural gas gathering affiliate, which closed in August 2025. The total acquisition cost presented is comprised of $581 million in cash consideration paid to Oxy and $2 million in transaction-related costs. For additional information, see Note 12 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.
Comparison of Nine Months Ended September 30, 2025with Nine Months Ended September 30, 2024
In total, investments in growth capital projects increaseda net $418 million period-to-periodprimarily due to the following:
•higher investments in the construction of natural gas processing trains and related gathering system expansions in the Delaware and Midland Basins, which accounted for a $291 million increase;
•higher investments in our Bahia NGL Pipeline, which accounted for an additional $254 million increase; partially offset by
•lower investments in our TW Products System (placed into service during 2024), which accounted for a $145 million decrease.
Investments attributable to sustaining capital projects decreased $167 million period-to-periodprimarily due to lower major maintenance activities performed at certain of our reaction-based plants (e.g., our PDH 1 and iBDH facilities) and fluctuations in timing and costs of pipeline integrity and similar projects.
Critical Accounting Policies and Estimates
A discussion of our critical accounting policies and estimates is included in our 2024Form 10-K. The following types of estimates, in our opinion, are subjective in nature, require the exercise of professional judgment and involve complex analysis:
•depreciation methods and estimated useful lives of property, plant and equipment;
•measuring recoverability of long-lived assets and fair value of equity method investments;
•amortization methods of customer relationships and contract-based intangible assets;
•methods we employ to measure the fair value of goodwill and related assets; and
•the use of estimates for revenue and expenses.
When used to prepare our Unaudited Condensed Consolidated Financial Statements, the foregoing types of estimates are based on our current knowledge and understanding of the underlying facts and circumstances. Such estimates may be revised as a result of changes in the underlying facts and circumstances. Subsequent changes in these estimates may have a significant impact on our consolidated financial position, results of operations and cash flows.
Other Matters
Parent-Subsidiary Guarantor Relationship
The Partnership (the "Parent Guarantor") has guaranteed the payment of principal and interest on the consolidated debt obligations of EPO (the "Subsidiary Issuer") (collectively, the "Guaranteed Debt"). If EPO were to default on any of its Guaranteed Debt, the Partnership would be responsible for full and unconditional repayment of such obligations. At September 30, 2025, the total amount of Guaranteed Debt was $34.2 billion, which was comprised of $30.8 billionof EPO's senior notes, $2.3 billionof EPO's junior subordinated notes, $840 million of commercial paper and $288 millionof related accrued interest.
The Partnership's guarantees of EPO's senior note obligations, commercial paper notes and borrowings under bank credit facilities represent unsecured and unsubordinated obligations of the Partnership that rank equal in right of payment to all other existing or future unsecured and unsubordinated indebtedness of the Partnership. In addition, these guarantees effectively rank junior in right of payment to any existing or future indebtedness of the Partnership that is secured and unsubordinated, to the extent of the assets securing such indebtedness.
The Partnership's guarantees of EPO's junior subordinated notes represent unsecured and subordinated obligations of the Partnership that rank equal in right of payment to all other existing or future subordinated indebtedness of the Partnership and senior in right of payment to all existing or future equity securities of the Partnership. The Partnership's guarantees of EPO's junior subordinated notes effectively rank junior in right of payment to (i) any existing or future indebtedness of the Partnership that is secured, to the extent of the assets securing such indebtedness and (ii) all other existing or future unsecured and unsubordinated indebtedness of the Partnership.
The Partnership may be released from its guarantee obligations only in connection with EPO's exercise of its legal or covenant defeasance options as described in the underlying agreements.
Selected Financial Information of Obligor Group
The following tables present summarized financial information of the Partnership (as Parent Guarantor) and EPO (as Subsidiary Issuer) on a combined basis (collectively, the "Obligor Group"), after the elimination of intercompany balances and transactions among the Obligor Group.
In accordance with Rule 13.01 of Regulation S-X, the summarized financial information of the Obligor Group excludes the Obligor Group's equity in income and investments in the consolidated subsidiaries of EPO that are not party to the guarantee obligations (the "Non-Obligor Subsidiaries"). The total carrying value of the Obligor Group's investments in the Non-Obligor Subsidiaries was $54.5 billionat September 30, 2025. The Obligor Group's equity in the earnings of the Non-Obligor Subsidiaries for the nine months ended September 30, 2025was $5.0 billion. Although the net assets and earnings of the Non-Obligor Subsidiaries are not directly available to the holders of the Guaranteed Debt to satisfy the repayment of such obligations, there are no significant restrictions on the ability of the Non-Obligor Subsidiaries to pay distributions or make loans to EPO or the Partnership. EPO exercises control over the Non-Obligor Subsidiaries. We continue to believe that the unaudited condensed consolidated financial statements of the Partnership presented under Part I, Item 1 of this quarterly report provide a more appropriate view of our credit standing. Our investment grade credit ratings are based on the Partnership's consolidated financial statements and not the Obligor Group's financial information presented below.
The following table presents summarized balance sheet information for the combined Obligor Group at the dates indicated (dollars in millions):
| Selected asset information: |
September 30, 2025 |
December 31, 2024 |
|||||||||
| Current receivables from Non-Obligor Subsidiaries | $ | 520 | $ | 1,569 | |||||||
| Other current assets | 6,044 | 6,487 | |||||||||
| Long-term receivables from Non-Obligor Subsidiaries | 187 | 187 | |||||||||
|
Other noncurrent assets, excluding investments in Non-Obligor Subsidiaries of $54.5 billion at September 30, 2025 and $50.8 billion at December 31, 2024
|
9,293 | 9,350 | |||||||||
| Selected liability information: | |||||||||||
|
Current portion of Guaranteed Debt, including interest of $288 million at September 30, 2025 and $536 million at December 31, 2024
|
$ | 2,752 | $ | 1,686 | |||||||
| Current payables to Non-Obligor Subsidiaries | 1,551 | 1,438 | |||||||||
| Other current liabilities | 4,219 | 4,074 | |||||||||
| Noncurrent portion of Guaranteed Debt, principal only | 31,432 | 31,057 | |||||||||
| Noncurrent payables to Non-Obligor Subsidiaries | 55 | 55 | |||||||||
| Other noncurrent liabilities | 188 | 215 | |||||||||
| Mezzanine equity of Obligor Group: | |||||||||||
| Preferred units | $ | 50 | $ | 50 | |||||||
The following table presents summarized income statement information for the combined Obligor Group for the periods indicated (dollars in millions):
|
For the Nine Months Ended September 30, 2025 |
For the Twelve Months Ended December 31, 2024 | ||||||||||
| Revenues from Non-Obligor Subsidiaries | $ | 14,187 | $ | 22,286 | |||||||
| Revenues from other sources | 12,053 | 19,781 | |||||||||
| Operating income of Obligor Group | 186 | 443 | |||||||||
|
Net loss of Obligor Group excluding equity in earnings of Non-Obligor Subsidiaries of $5.0 billion for the nine months ended September 30, 2025 and $6.8 billion for the twelve months ended December 31, 2024
|
(882) | (933) | |||||||||
Related Party Transactions
For information regarding our related party transactions, see Note 15of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.
Enterprise Products Partners LP published this content on November 06, 2025, and is solely responsible for the information contained herein. Distributed via Edgar on November 06, 2025 at 16:57 UTC. If you believe the information included in the content is inaccurate or outdated and requires editing or removal, please contact us at [email protected]