Enterprise Products Partners LP
11/04/2026 | Press release | Distributed by Public on 11/04/2026 09:55
Quarterly Report for Quarter Ending September 30, 2026 (Form 10-Q)
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
For the Three and Nine Months Ended September 30, 2026 and 2025
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, 2025 (the "2025 Form 10-K"), as filed on February 27, 2026 with 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, 2026 (our "quarterly report") contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us. When used in this document, words such as "anticipate," "project," "expect," "plan," "seek," "goal," "estimate," "forecast," "intend," "could," "should," "would," "will," "believe," "may," "scheduled," "pending," "potential" and similar expressions and statements regarding our plans and objectives for future operations are intended to identify forward-looking statements. Although we and our general partner believe that our expectations reflected in such forward-looking statements (including any forward-looking statements/expectations of third parties referenced in this quarterly report) are reasonable, neither we nor our general partner can give any assurances that such expectations will prove to be correct.
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 2025 Form 10-K. 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 32.6% of the Partnership's common units outstanding at September 30, 2026.
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 third quarter of 2026 compared to the third quarter of 2025. Likewise, the phrase "period-to-period" means the nine months ended September 30, 2026 compared to the nine months ended September 30, 2025.
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 2025 Form 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 2025 Form 10-K.
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 to Expand Permian Basin Processing and Mont Belvieu Area NGL Fractionation Capacity
To support ongoing production growth in the Permian Basin, we announced in April 2026 plans to construct a tenth natural gas processing train ("Athena 2") in the Midland Basin and a twelfth natural gas processing train ("Delaware Basin Plant 12") in the Delaware Basin and in July 2026 announced plans to construct an eleventh natural gas processing train ("Midland Basin Plant 11") in the Midland Basin and a thirteenth natural gas processing train ("Delaware Basin Plant 13") in the Delaware Basin.
In the Midland Basin, each of these processing trains will have a nameplate natural gas processing capacity of 300 MMcf/d and will be able to extract more than 40 MBPD of NGLs. Athena 2 and Midland Basin Plant 11, which are supported by long-term acreage dedication agreements, are expected to be placed into service in the third quarter of 2027 and first quarter of 2029, respectively.
In the Delaware Basin, each of these processing trains will have a nameplate natural gas processing capacity of 300 MMcf/d and will be able to extract more than 40 MBPD of NGLs. Delaware Basin Plant 12 and Delaware Basin Plant 13, which are supported by long-term acreage dedication agreements and minimum volume commitments, are expected to be placed into service in the fourth quarter of 2027 and third quarter of 2028, respectively.
To accommodate incremental NGL production from the Permian Basin, we plan to construct an additional NGL fractionator ("Frac 15") at our Mont Belvieu area NGL fractionation complex. Frac 15 will have a nameplate capacity of 150 MBPD and is expected to be completed in the first quarter of 2028.
Enterprise Enters Into July 2026 $1.0 Billion Incremental Credit Agreement
In July 2026, EPO entered into an additional revolving credit agreement (the "July 2026 $1.0 Billion Incremental Credit Agreement"). Under the new agreement, EPO may borrow up to $1.0 billion at a variable interest rate, subject to its terms and conditions. The July 2026 $1.0 Billion Incremental Credit Agreement increases EPO's aggregate borrowing capacity under its credit agreements to $5.2 billion and enhances our liquidity and financial flexibility to support our working capital requirements amid increased commodity price volatility. Proceeds from borrowings under the agreement may be used for working capital, capital expenditures, acquisitions and general company purposes. Amounts borrowed under the agreement mature on March 26, 2027, coinciding with the maturity date of EPO's existing March 2026 $1.5 Billion 364-Day Revolving Credit Agreement.
Selected Energy Commodity Price Data
The following table presents selected average index prices for natural gas and selected NGL products for the periods indicated:
|
Natural Gas, $/MMBtu |
Ethane, $/gallon |
Propane, $/gallon |
Normal Butane, $/gallon |
Isobutane, $/gallon |
Natural Gasoline, $/gallon |
|||||||||||||||
| (1) | (2) | (2) | (2) | (2) | (2) | |||||||||||||||
| 2025 by quarter: | ||||||||||||||||||||
| 1st Quarter | $3.65 | $0.27 | $0.90 | $1.06 | $1.07 | $1.53 | ||||||||||||||
| 2nd Quarter | $3.44 | $0.24 | $0.78 | $0.88 | $0.93 | $1.32 | ||||||||||||||
| 3rd Quarter | $3.07 | $0.23 | $0.69 | $0.86 | $0.92 | $1.30 | ||||||||||||||
| 4th Quarter | $3.55 | $0.27 | $0.62 | $0.84 | $0.88 | $1.24 | ||||||||||||||
| 2025 Averages | $3.43 | $0.25 | $0.75 | $0.91 | $0.95 | $1.35 | ||||||||||||||
| 2026 by quarter: | ||||||||||||||||||||
| 1st Quarter | $5.05 | $0.23 | $0.66 | $0.88 | $0.89 | $1.50 | ||||||||||||||
| 2nd Quarter | $2.90 | $0.21 | $0.78 | $1.08 | $1.12 | $1.94 | ||||||||||||||
|
3rd Quarter
|
$2.96 | $0.24 | $0.74 | $1.11 | $1.31 | $1.88 | ||||||||||||||
| 2026 Averages | $3.64 | $0.23 | $0.73 | $1.02 | $1.11 | $1.77 | ||||||||||||||
(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.
The weighted-average indicative market price for NGLs was $0.69 per gallon in the third quarter of 2026 versus $0.56 per gallon in the third quarter of 2025. Likewise, the weighted-average indicative market price for NGLs was $0.65 per gallon during the nine months ended September 30, 2026 compared to $0.60 during the nine months ended September 30, 2025.
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) | |||||||||
| 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 | ||||||||
| 4th Quarter | $59.14 | $59.77 | $60.05 | ||||||||
| 2025 Averages | $64.84 | $65.62 | $65.90 | ||||||||
| 2026 by quarter: | |||||||||||
| 1st Quarter | $71.93 | $73.97 | $74.67 | ||||||||
| 2nd Quarter | $92.71 | $94.61 | $95.28 | ||||||||
| 3rd Quarter | $85.79 | $86.76 | $87.20 | ||||||||
| 2026 Averages | $83.48 | $85.11 | $85.72 | ||||||||
(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 13 of 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., which are generally influenced by a variety of macroeconomic and policy-related factors, have moderated from prior levels, but remain a relevant consideration for the overall cost environment. In addition, there is uncertainty of what effect, if any, trade tariffs 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, |
||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| Revenues | $ | 17,948 | $ | 12,023 | $ | 50,603 | $ | 38,803 | |||||||||||||||
| Costs and expenses: | |||||||||||||||||||||||
| Operating costs and expenses: | |||||||||||||||||||||||
| Cost of sales | 13,993 | 8,590 | 38,831 | 28,494 | |||||||||||||||||||
| Other operating costs and expenses | 1,269 | 1,119 | 3,596 | 3,241 | |||||||||||||||||||
| Depreciation, amortization and accretion expenses | 713 | 644 | 2,100 | 1,888 | |||||||||||||||||||
| Asset impairment charges | 7 | 17 | 24 | 38 | |||||||||||||||||||
| Net losses (gains) attributable to asset sales and related matters | 3 | (4) | 2 | (13) | |||||||||||||||||||
| Total operating costs and expenses | 15,985 | 10,366 | 44,553 | 33,648 | |||||||||||||||||||
| General and administrative costs | 60 | 61 | 188 | 189 | |||||||||||||||||||
| Total costs and expenses | 16,045 | 10,427 | 44,741 | 33,837 | |||||||||||||||||||
| Equity in income of unconsolidated affiliates | 87 | 90 | 272 | 276 | |||||||||||||||||||
| Operating income | 1,990 | 1,686 | 6,134 | 5,242 | |||||||||||||||||||
| Other income (expense): | |||||||||||||||||||||||
| Interest expense | (385) | (354) | (1,154) | (1,026) | |||||||||||||||||||
| Other, net | 50 | 11 | 61 | 27 | |||||||||||||||||||
| Total other expense, net | (335) | (343) | (1,093) | (999) | |||||||||||||||||||
| Income before income taxes | 1,655 | 1,343 | 5,041 | 4,243 | |||||||||||||||||||
| Benefit from (provision for) income taxes | (17) | 13 | (51) | (27) | |||||||||||||||||||
| Net income | 1,638 | 1,356 | 4,990 | 4,216 | |||||||||||||||||||
| Net income attributable to noncontrolling interests | (13) | (17) | (41) | (47) | |||||||||||||||||||
| Net income attributable to preferred units | (1) | (1) | (3) | (3) | |||||||||||||||||||
| Net income attributable to common unitholders | $ | 1,624 | $ | 1,338 | $ | 4,946 | $ | 4,166 | |||||||||||||||
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, |
||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| NGL Pipelines & Services: | |||||||||||||||||||||||
| Sales of NGLs and related products | $ | 5,154 | $ | 2,736 | $ | 12,898 | $ | 10,110 | |||||||||||||||
| Midstream services | 791 | 729 | 2,313 | 2,161 | |||||||||||||||||||
| Total | 5,945 | 3,465 | 15,211 | 12,271 | |||||||||||||||||||
| Crude Oil Pipelines & Services: | |||||||||||||||||||||||
| Sales of crude oil | 6,317 | 5,087 | 20,374 | 14,391 | |||||||||||||||||||
| Midstream services | 314 | 309 | 895 | 909 | |||||||||||||||||||
| Total | 6,631 | 5,396 | 21,269 | 15,300 | |||||||||||||||||||
| Natural Gas Pipelines & Services: | |||||||||||||||||||||||
| Sales of natural gas | 665 | 476 | 1,462 | 1,893 | |||||||||||||||||||
| Midstream services | 523 | 456 | 1,492 | 1,331 | |||||||||||||||||||
| Total | 1,188 | 932 | 2,954 | 3,224 | |||||||||||||||||||
| Petrochemical & Refined Products Services: | |||||||||||||||||||||||
| Sales of petrochemicals and refined products | 3,856 | 1,919 | 10,149 | 7,020 | |||||||||||||||||||
| Midstream services | 328 | 311 | 1,020 | 988 | |||||||||||||||||||
| Total | 4,184 | 2,230 | 11,169 | 8,008 | |||||||||||||||||||
| Total consolidated revenues | $ | 17,948 | $ | 12,023 | $ | 50,603 | $ | 38,803 | |||||||||||||||
Third Quarter of 2026 Compared to Third Quarter of 2025. Total revenues for the third quarter of 2026 increased $5.9 billion when compared to the third quarter of 2025 primarily due to higher marketing revenues.
Revenues from the marketing of NGLs, natural gas, and petrochemicals and refined products increased a combined $4.6 billion quarter-to-quarter primarily due to higher average sales prices, which accounted for a $2.8 billion increase, and higher sales volumes, which accounted for an additional $1.8 billion increase. Revenues from the marketing of crude oil increased $1.2 billion quarter-to-quarter primarily due to higher average sales prices.
Revenues from midstream services for the third quarter of 2026 increased $151 million when compared to the third quarter of 2025. Revenues from our natural gas processing facilities increased $65 million quarter-to-quarter primarily due to higher market values for the equity NGL-equivalent production volumes we received as non-cash consideration for processing services. Revenues from our natural gas transportation assets increased $68 million quarter-to-quarter primarily due to higher demand for transportation services.
Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025. Total revenues for the nine months ended September 30, 2026 increased $11.8 billion when compared to the nine months ended September 30, 2025 primarily due to higher marketing revenues.
Revenues from the marketing of crude oil, NGLs and petrochemicals and refined products increased a combined $11.9 billion period-to-period primarily due to higher average sales prices, which accounted for a $7.1 billion increase, and higher sales volumes, which accounted for an additional $4.8 billion increase. Revenues from the marketing of natural gas decreased $431 million period-to-period primarily due to lower average sales prices.
Revenues from midstream services for the nine months ended September 30, 2026 increased $331 million when compared to the nine months ended September 30, 2025. Revenues from our natural gas processing facilities increased $167 million period-to-period primarily due to higher market values for the equity NGL-equivalent production volumes we receive as non-cash consideration for processing services. Revenues from our natural gas transportation assets increased $158 million period-to-period primarily due to higher demand for transportation services.
Operating costs and expenses
Total operating costs and expenses for the three and nine months ended September 30, 2026 increased $5.6 billion and $10.9 billion, respectively, when compared to the same periods in 2025.
Cost of sales
Third Quarter of 2026 Compared to Third Quarter of 2025. Cost of sales for the third quarter of 2026 increased $5.4 billion when compared to the third quarter of 2025. The cost of sales associated with the marketing of NGLs, natural gas, and petrochemicals and refined products increased a combined $4.2 billion quarter-to-quarter primarily due to higher average purchase prices, which accounted for a $2.3 billion increase, and higher volumes, which accounted for an additional $1.9 billion increase. The cost of sales associated with the marketing of crude oil increased $1.2 billion quarter-to-quarter primarily due to higher average purchase prices.
Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025. Cost of sales for the nine months ended September 30, 2026 increased $10.3 billion when compared to the nine months ended September 30, 2025. The cost of sales associated with the marketing of crude oil, NGLs and petrochemicals and refined products increased a combined $10.4 billion period-to-period primarily due to higher average purchase prices, which accounted for a $5.5 billion increase, and higher volumes, which accounted for an additional $4.9 billion increase. The cost of sales associated with the marketing of natural gas decreased $51 million period-to-period primarily due to lower average purchase prices.
Other operating costs and expenses
Other operating costs and expenses for the three and nine months ended September 30, 2026 increased $150 million and $355 million, respectively, when compared to the same periods in 2025 primarily due to higher compensation, chemical costs, ad valorem taxes, maintenance and other operating costs.
Depreciation, amortization and accretion expenses
Depreciation, amortization and accretion expense for the three and nine months ended September 30, 2026 increased $69 million and $212 million, respectively, when compared to the same periods in 2025 primarily due to higher depreciation expense on assets placed into full or limited service since the end of the respective periods in 2025.
Operating income
Operating income for the three and nine months ended September 30, 2026 increased $304 million and $892 million, respectively, when compared to the same periods in 2025 due 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, |
||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| Interest charged on debt principal outstanding (1) | $ | 397 | $ | 396 | $ | 1,200 | $ | 1,154 | |||||||||||||||
| Impact of interest rate hedging program, including related amortization | (1) | (2) | (5) | (5) | |||||||||||||||||||
| Interest costs capitalized in connection with construction projects (2) | (21) | (49) | (68) | (147) | |||||||||||||||||||
| Other | 10 | 9 | 27 | 24 | |||||||||||||||||||
| Total | $ | 385 | $ | 354 | $ | 1,154 | $ | 1,026 | |||||||||||||||
(1)The weighted-average interest rate on debt principal outstanding during each of the three months ended September 30, 2026 and 2025 was 4.62%. The weighted-average interest rate on debt principal outstanding during each of the nine months ended September 30, 2026 and 2025 was 4.66%.
(2)We capitalize interest costs incurred on funds used to construct property, plant and equipment while the asset is in its construction phase. Capitalized interest amounts become part of the historical cost of an asset and are charged to earnings (as a component of depreciation expense) on a straight-line basis over the estimated useful life of the asset once the asset enters its intended service. When capitalized interest is recorded, it reduces interest expense from what it would be otherwise. Capitalized interest amounts fluctuate based on the timing of when projects are placed into service, our capital investment levels and the interest rates charged on borrowings.
Interest charged on debt principal outstanding, which is a key driver of interest expense, increased a net $1 million quarter-to-quarter and a net $46 million period-to-period. These increases were primarily due to the issuance of $2.0 billion and $1.65 billion of fixed-rate senior notes in June 2025 and November 2025, respectively, which accounted for a combined increase of $20 million quarter-to-quarter and $104 million period-to-period. These increases were partially offset by the retirement of $750 million and $875 million of fixed-rate senior notes in January 2026 and February 2026, respectively, which accounted for a combined decrease of $18 million quarter-to-quarter and $48 million period-to-period.
For additional information regarding our debt obligations, see Note 7 of 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, |
||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| Gross operating margin by segment: | |||||||||||||||||||||||
| NGL Pipelines & Services | $ | 1,535 | $ | 1,303 | $ | 4,583 | $ | 4,018 | |||||||||||||||
| Crude Oil Pipelines & Services | 367 | 371 | 1,181 | 1,148 | |||||||||||||||||||
| Natural Gas Pipelines & Services | 411 | 339 | 1,463 | 1,113 | |||||||||||||||||||
| Petrochemical & Refined Products Services | 430 | 370 | 1,162 | 1,039 | |||||||||||||||||||
| Total segment gross operating margin (1) | 2,743 | 2,383 | 8,389 | 7,318 | |||||||||||||||||||
| Net adjustment for shipper make-up rights | (8) | 2 | (39) | (25) | |||||||||||||||||||
| Total gross operating margin (non-GAAP) | $ | 2,735 | $ | 2,385 | $ | 8,350 | $ | 7,293 | |||||||||||||||
(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, |
||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| Operating income | $ | 1,990 | $ | 1,686 | $ | 6,134 | $ | 5,242 | |||||||||||||||
|
Adjustments to reconcile operating income to total gross operating margin (addition or subtraction indicated by sign):
|
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|
Depreciation, amortization and accretion expense in operating costs and expenses (1)
|
675 | 625 | 2,002 | 1,837 | |||||||||||||||||||
| Asset impairment charges in operating costs and expenses | 7 | 17 | 24 | 38 | |||||||||||||||||||
| Net losses (gains) attributable to asset sales and related matters in operating costs and expenses | 3 | (4) | 2 | (13) | |||||||||||||||||||
| General and administrative costs | 60 | 61 | 188 | 189 | |||||||||||||||||||
| Total gross operating margin (non-GAAP) | $ | 2,735 | $ | 2,385 | $ | 8,350 | $ | 7,293 | |||||||||||||||
(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, |
||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| Segment gross operating margin: | |||||||||||||||||||||||
| Natural gas processing and related NGL marketing activities | $ | 488 | $ | 354 | $ | 1,415 | $ | 1,068 | |||||||||||||||
| NGL pipelines, storage and terminals | 785 | 746 | 2,374 | 2,309 | |||||||||||||||||||
| NGL fractionation | 262 | 203 | 794 | 641 | |||||||||||||||||||
| Total | $ | 1,535 | $ | 1,303 | $ | 4,583 | $ | 4,018 | |||||||||||||||
| Selected volumetric data: | |||||||||||||||||||||||
| NGL pipeline transportation volumes (MBPD) | 4,978 | 4,694 | 4,926 | 4,570 | |||||||||||||||||||
| NGL marine terminal volumes (MBPD) | 1,196 | 908 | 1,173 | 947 | |||||||||||||||||||
| NGL fractionation volumes (MBPD) | 1,890 | 1,636 | 1,885 | 1,650 | |||||||||||||||||||
| Equity NGL-equivalent production volumes (MBPD) (1) | 242 | 225 | 237 | 221 | |||||||||||||||||||
| Fee-based natural gas processing volumes (MMcf/d) (2,3) | 8,196 | 7,454 | 7,710 | 7,303 | |||||||||||||||||||
(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
Third Quarter of 2026 Compared to Third Quarter of 2025. Gross operating margin from natural gas processing and related NGL marketing activities for the third quarter of 2026 increased $134 million when compared to the third quarter of 2025.
Gross operating margin from our NGL marketing activities increased $75 million quarter-to-quarter primarily due to higher average sales margins.
Gross operating margin from our Delaware Basin natural gas processing facilities increased $31 million quarter-to-quarter primarily due to a 359 MMcf/d increase in fee-based natural gas processing volumes, which accounted for a $17 million increase, and a 6 MBPD increase in equity NGL-equivalent production volumes, which accounted for an additional $14 million increase.
Gross operating margin from our Midland Basin natural gas processing facilities increased a net $12 million quarter-to-quarter primarily due to a 280 MMcf/d increase in fee-based natural gas processing volumes, which accounted for an $8 million increase, a 13 MBPD increase in equity NGL-equivalent production volumes, which accounted for an $8 million increase, and lower operating costs, which accounted for an additional $5 million increase, partially offset by lower average processing margins (including the impact of hedging), which accounted for a $9 million decrease.
Gross operating margin from our Louisiana and Mississippi natural gas processing facilities increased $6 million quarter-to-quarter primarily due to higher average processing margins (including the impact of hedging activities). Fee-based natural gas processing volumes and equity NGL-equivalent production volumes increased 18 MMcf/d and decreased 3 MBPD, respectively, quarter-to-quarter.
Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025. Gross operating margin from natural gas processing and related NGL marketing activities for the nine months ended September 30, 2026 increased $347 million when compared to the nine months ended September 30, 2025.
Gross operating margin from our NGL marketing activities increased $167 million period-to-period primarily due to higher average sales margins, which accounted for a $123 million increase, higher sales volumes, which accounted for a $31 million increase, and higher mark-to-market earnings, which accounted for an additional $15 million increase.
Gross operating margin from our Delaware Basin natural gas processing facilities increased a net $90 million period-to-period primarily due to higher average processing margins (including the impact of hedging activities), which accounted for a $59 million increase, a 296 MMcf/d increase in fee-based natural gas processing volumes, which accounted for a $42 million increase, and a 2 MBPD increase in equity NGL-equivalent production volumes, which accounted for an additional $12 million increase, partially offset by higher operating costs, which accounted for a $23 million decrease.
Gross operating margin from our Midland Basin natural gas processing facilities increased $85 million period-to-period primarily due to higher average processing margins (including the impact of hedging activities), which accounted for a $37 million increase, a 12 MBPD increase in equity NGL-equivalent production volumes, which accounted for a $23 million increase, a 177 MMcf/d increase in fee-based natural gas processing volumes, which accounted for an $18 million increase, and lower operating costs, which accounted for an additional $7 million increase.
Gross operating margin from our Louisiana and Mississippi natural gas processing facilities increased $13 million period-to-period primarily due to higher average processing margins (including the impact of hedging activities), which accounted for a $6 million increase, and higher average processing fees, which accounted for an additional $5 million increase. Fee-based natural gas processing volumes and equity NGL-equivalent production volumes increased 15 MMcf/d and 1 MBPD, respectively, period-to-period.
NGL pipelines, storage and terminals
Third Quarter of 2026 Compared to Third Quarter of 2025. Gross operating margin from our NGL pipelines, storage and terminal assets during the third quarter of 2026 increased $39 million when compared to the third quarter of 2025.
Gross operating margin for our Eastern ethane pipelines, which include our ATEX and Aegis pipelines, increased a combined $15 million quarter-to-quarter primarily due to a 243 MBPD increase in transportation volumes, which accounted for an $8 million increase, and higher other transportation-related revenues, which accounted for an additional $8 million increase.
Gross operating margin at our Morgan's Point, Neches River and Enterprise Hydrocarbons Terminals increased a combined net $14 million quarter-to-quarter primarily due to an increase in ethane export volumes, which accounted for a $31 million increase, and an increase in propane export volumes at our Neches River Terminal, which accounted for an additional $14 million increase, partially offset by higher operating costs, which accounted for a $20 million decrease. Ethane export volumes at these terminals increased a combined 139 MBPD quarter-to-quarter primarily due to contributions from the first phase of our Neches River export facility, which was placed into service in July 2025. Propane export volumes at our Neches River Terminal increased 162 MBPD quarter-to-quarter due to contributions from the second phase of this facility, which was placed into service in May 2026. LPG export volumes at Enterprise Hydrocarbons Terminal ("EHT") decreased 13 MBPD quarter-to-quarter.
Gross operating margin from our Mont Belvieu area storage complex increased $12 million quarter-to-quarter primarily due to higher storage revenues.
A number of our pipelines, including the Mid-America Pipeline System, Seminole NGL Pipeline, Chaparral Pipeline, Shin Oak NGL Pipeline and Bahia NGL Pipeline, serve Permian Basin and/or Rocky Mountain producers. On a combined basis, gross operating margin from these pipelines increased a net $10 million quarter-to-quarter primarily due to higher average transportation fees, which accounted for a $20 million increase, partially offset by higher operating costs, which accounted for a $10 million decrease.
Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025. Gross operating margin from our NGL pipelines, storage and terminal assets during the nine months ended September 30, 2026 increased $65 million when compared to the nine months ended September 30, 2025.
A number of our pipelines, including the Mid-America Pipeline System, Seminole NGL Pipeline, Chaparral Pipeline, Shin Oak NGL Pipeline and Bahia NGL Pipeline, serve Permian Basin and/or Rocky Mountain producers. On a combined basis, gross operating margin from these pipelines increased a net $44 million period-to-period primarily due to higher average transportation fees, which accounted for a $31 million increase, and an increase in transportation volumes, which accounted for an additional $25 million increase, partially offset by lower other revenues, which accounted for an $8 million decrease, and higher operating costs, which accounted for an additional $4 million decrease.
Gross operating margin from our Mont Belvieu area storage complex increased $34 million period-to-period primarily due to higher storage revenues.
Gross operating margin for our Eastern ethane pipelines, which include our ATEX and Aegis pipelines, increased a combined $22 million period-to-period primarily due to a 192 MBPD increase in transportation volumes.
Gross operating margin at our Morgan's Point, Neches River and Enterprise Hydrocarbons Terminals increased a combined net $6 million period-to-period primarily due to an increase in ethane export volumes, which accounted for an $86 million increase, an increase in propane export volumes at our Neches River Terminal, which accounted for a $25 million increase, and higher other fee revenues, which accounted for an additional $5 million increase, partially offset by lower average LPG loading fees at EHT, which accounted for a $44 million decrease, higher operating costs, which accounted for a $41 million decrease, and lower average ethane loading fees, which accounted for an additional $25 million decrease. Ethane export volumes at these terminals increased a combined 129 MBPD period-to-period primarily due to contributions from the first phase of our Neches River export facility, which was placed into service in July 2025. Propane export volumes at our Neches River Terminal increased 101 MBPD period-to-period due to contributions from the second phase of this facility, which was placed into service in May 2026. LPG export volumes at EHT decreased 4 MBPD period-to-period.
NGL fractionation
Third Quarter of 2026 Compared to Third Quarter of 2025. Gross operating margin from NGL fractionation during the third quarter of 2026 increased $59 million when compared to the third quarter of 2025.
Gross operating margin from our Mont Belvieu area NGL fractionation complex increased a net $51 million quarter-to-quarter primarily due to higher fractionation volumes, which accounted for a $46 million increase, and higher ancillary service revenues, which accounted for an additional $23 million increase, partially offset by higher operating costs, which accounted for a $20 million decrease. NGL fractionation volumes at our Mont Belvieu area NGL fractionation complex increased 223 MBPD quarter-to-quarter primarily due to contributions from Frac 14, which was placed into service during the fourth quarter of 2025.
On a combined basis, gross operating margin from NGL fractionators other than our Mont Belvieu area complex increased $7 million quarter-to-quarter primarily due to a combined 31 MBPD (net to our interest) increase in fractionation volumes, which accounted for a $4 million increase, and higher ancillary service revenues, which accounted for an additional $4 million increase.
Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025. Gross operating margin from NGL fractionation during the nine months ended September 30, 2026 increased $153 million when compared to the nine months ended September 30, 2025.
Gross operating margin from our Mont Belvieu area NGL fractionation complex increased a net $139 million period-to-period primarily due to higher fractionation volumes, which accounted for a $133 million increase, higher average fractionation fees (including the impact of hedging activities), which accounted for a $29 million increase, and higher ancillary service revenues, which accounted for an additional $37 million increase, partially offset by higher operating costs, which accounted for a $62 million decrease. NGL fractionation volumes at our Mont Belvieu area NGL fractionation complex increased 217 MBPD period-to-period primarily due to contributions from Frac 14, which was placed into service during the fourth quarter of 2025.
On a combined basis, gross operating margin from NGL fractionators other than our Mont Belvieu area complex increased $14 million period-to-period primarily due to a combined 18 MBPD (net to our interest) increase in fractionation volumes, which accounted for a $7 million increase, and higher ancillary service revenues, which accounted for an additional $6 million increase.
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, |
||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| Segment gross operating margin | $ | 367 | $ | 371 | $ | 1,181 | $ | 1,148 | |||||||||||||||
| Selected volumetric data: | |||||||||||||||||||||||
| Crude oil pipeline transportation volumes (MBPD) | 2,679 | 2,631 | 2,785 | 2,581 | |||||||||||||||||||
| Crude oil marine terminal volumes (MBPD) | 926 | 720 | 974 | 757 | |||||||||||||||||||
Third Quarter of 2026 Compared to Third Quarter of 2025. Gross operating margin from our Crude Oil Pipelines & Services segment for the third quarter of 2026 decreased $4 million when compared to the third quarter of 2025.
Gross operating margin from our Texas crude oil pipelines, related terminals and marketing activities (excluding the Seaway Pipeline) decreased a combined net $14 million quarter-to-quarter primarily due to higher operating costs, which accounted for a $28 million decrease, and lower transportation and related revenues, which accounted for an additional $15 million decrease and largely attributable to lower average transportation fees from our equity investment in the Eagle Ford Crude Oil Pipeline, partially offset by higher average sales margins from marketing activities, which accounted for a $28 million increase. Crude oil transportation volumes on these pipelines increased a combined 6 MBPD (net to our interest) quarter-to-quarter.
Gross operating margin from crude oil activities at EHT increased $6 million quarter-to-quarter primarily due to higher loading and other revenues. Crude oil marine terminal volumes at EHT increased 163 MBPD quarter-to-quarter.
Gross operating margin from our equity investment in the Seaway Pipeline increased $4 million quarter-to-quarter primarily due to higher average transportation and related fees. Transportation volumes on our Seaway Pipeline increased 42 MBPD (net to our interest) and marine terminal volumes at the Freeport System and Texas City System increased a combined 20 MBPD (net to our interest) quarter-to-quarter.
Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025. Gross operating margin from our Crude Oil Pipelines & Services segment for the nine months ended September 30, 2026 increased $33 million when compared to the nine months ended September 30, 2025.
Gross operating margin from our equity investment in the Seaway Pipeline increased a net $28 million period-to-period primarily due to higher loading and other fee revenues, which accounted for a $15 million increase, an 88 MBPD (net to our interest) increase in transportation volumes, which accounted for a $10 million increase, and higher average transportation and related fees, which accounted for an additional $9 million increase, partially offset by higher operating costs, which accounted for a $6 million decrease. On a combined basis, marine terminal volumes at the Freeport System and Texas City System increased 45 MBPD (net to our interest) period-to-period.
Gross operating margin from our Texas crude oil pipelines, related terminals and marketing activities (excluding the Seaway Pipeline) increased a combined net $9 million period-to-period primarily due to higher sales volumes from marketing activities, which accounted for a $55 million increase, and higher average sales margins from marketing activities, which accounted for an additional $46 million increase, partially offset by lower transportation and related revenues, which accounted for a $57 million decrease and largely attributable to lower average transportation fees from our equity investment in the Eagle Ford Crude Oil Pipeline, and higher operating costs, which accounted for an additional $40 million decrease. Crude oil transportation volumes on these pipelines increased a combined 116 MBPD (net to our interest) 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, |
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| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| Segment gross operating margin | $ | 411 | $ | 339 | $ | 1,463 | $ | 1,113 | |||||||||||||||
| Selected volumetric data: | |||||||||||||||||||||||
| Natural gas pipeline transportation volumes (BBtus/d) | 22,695 | 21,027 | 21,644 | 20,583 | |||||||||||||||||||
Third Quarter of 2026 Compared to Third Quarter of 2025. Gross operating margin from our Natural Gas Pipelines & Services segment for the third quarter of 2026 increased $72 million when compared to the third quarter of 2025.
Gross operating margin from our natural gas marketing activities increased $31 million quarter-to-quarter primarily due to higher mark-to-market earnings, which accounted for a $14 million increase, higher average sales margins, which accounted for an $11 million increase, and higher sales volumes, which accounted for an additional $6 million increase.
Gross operating margin from our Delaware Basin Gathering System increased a net $17 million quarter-to-quarter primarily due to higher treating and other revenues, which accounted for a $13 million increase, higher average gathering fees, which accounted for a $9 million increase, and a 423 BBtus/d increase in natural gas gathering volumes, which accounted for an additional $7 million increase, partially offset by higher operating costs, which accounted for a $12 million decrease.
Gross operating margin from our Acadian Gas System and Haynesville Gathering System increased a combined $10 million quarter-to-quarter primarily due to a 131 BBtus/d increase in transportation volumes.
On a combined basis, gross operating margin from our Jonah Gathering System, Piceance Basin Gathering System, and San Juan Gathering System in the Rocky Mountains increased $9 million quarter-to-quarter primarily due to lower operating costs, which accounted for a $4 million increase, and higher average gathering fees, which accounted for an additional $3 million increase. Gathering volumes on our Rocky Mountain gathering systems decreased a combined 5 BBtus/d quarter-to-quarter.
Gross operating margin from our Midland Basin Gathering System increased a net $5 million quarter-to-quarter primarily due to a 469 BBtus/d increase in natural gas gathering volumes, which accounted for a $16 million increase, partially offset by higher operating costs, which accounted for a $13 million decrease.
Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025. Gross operating margin from our Natural Gas Pipelines & Services segment for the nine months ended September 30, 2026 increased $350 million when compared to the nine months ended September 30, 2025.
Gross operating margin from our natural gas marketing activities increased $232 million period-to-period primarily due to higher average sales margins, which accounted for a $210 million increase, and higher mark-to-market earnings, which accounted for an additional $22 million increase.
Gross operating margin from our Texas Intrastate System increased $44 million period-to-period primarily due to higher capacity reservation fees and other revenues, which accounted for a $27 million increase, and a 340 BBtus/d increase in transportation volumes, which accounted for an additional $13 million increase.
Gross operating margin from our Delaware Basin Gathering System, increased a net $26 million period-to-period primarily due to higher treating and other revenues, which accounted for a $20 million increase, a 390 BBtus/d increase in natural gas gathering volumes, which accounted for a $19 million increase, and higher average gathering fees, which accounted for an additional $11 million increase, partially offset by higher operating costs, which accounted for a $24 million decrease.
Gross operating margin from our Acadian Gas System and Haynesville Gathering System increased a combined $19 million period-to-period primarily due to a 220 BBtus/d increase in transportation volumes.
Gross operating margin from our Midland Basin Gathering System increased a net $17 million period-to-period primarily due to a 310 BBtus/d increase in natural gas gathering volumes, which accounted for a $31 million increase, and higher other revenues, which accounted for an additional $13 million increase, partially offset by higher operating costs, which accounted for a $27 million decrease.
On a combined basis, gross operating margin from our Jonah Gathering System, Piceance Basin Gathering System, and San Juan Gathering System in the Rocky Mountains increased $14 million period-to-period primarily due to lower operating costs, which accounted for an $8 million increase, and higher average gathering fees, which accounted for an additional $6 million increase. Gathering volumes on our Rocky Mountain gathering systems decreased a combined 84 BBtus/d period-to-period.
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, |
||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| Segment gross operating margin: | |||||||||||||||||||||||
| Propylene production and related activities | $ | 115 | $ | 112 | $ | 421 | $ | 332 | |||||||||||||||
| Butane isomerization and related operations | 34 | 30 | 96 | 88 | |||||||||||||||||||
| Octane enhancement and related plant operations | 100 | 81 | 178 | 197 | |||||||||||||||||||
| Refined products pipelines and related activities | 115 | 93 | 273 | 274 | |||||||||||||||||||
| Ethylene exports and related activities | 43 | 36 | 136 | 90 | |||||||||||||||||||
| Marine transportation and other services | 23 | 18 | 58 | 58 | |||||||||||||||||||
| Total | $ | 430 | $ | 370 | $ | 1,162 | $ | 1,039 | |||||||||||||||
| Selected volumetric data: | |||||||||||||||||||||||
| Propylene production volumes (MBPD) | 124 | 119 | 128 | 117 | |||||||||||||||||||
| Butane isomerization volumes (MBPD) | 125 | 123 | 120 | 120 | |||||||||||||||||||
| Standalone deisobutanizer ("DIB") processing volumes (MBPD) | 221 | 196 | 223 | 190 | |||||||||||||||||||
| Octane enhancement and related plant sales volumes (MBPD) (1) | 48 | 41 | 38 | 42 | |||||||||||||||||||
| Pipeline transportation volumes, primarily refined products and petrochemicals (MBPD) | 1,208 | 1,056 | 1,171 | 1,003 | |||||||||||||||||||
| Marine terminal volumes, primarily refined products and petrochemicals (MBPD) | 413 | 347 | 405 | 329 | |||||||||||||||||||
(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
Third Quarter of 2026 Compared to Third Quarter of 2025. Gross operating margin from propylene production and related activities for the third quarter of 2026 increased $3 million when compared to the third quarter of 2025.
On a combined basis, gross operating margin from our Mont Belvieu area propylene production facilities increased a net $8 million quarter-to-quarter primarily due to higher average propylene sales margins, which accounted for a $27 million increase, and higher propylene sales volumes, which accounted for an additional $7 million increase, partially offset by higher operating costs, which accounted for a $30 million decrease. Propylene and associated by-product production volumes at these facilities increased a combined 6 MBPD quarter-to-quarter.
Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025. Gross operating margin from propylene production and related activities for the nine months ended September 30, 2026 increased $89 million when compared to the nine months ended September 30, 2025.
On a combined basis, gross operating margin from our Mont Belvieu area propylene production facilities increased a net $91 million period-to-period primarily due to higher average propylene sales margins, which accounted for a $94 million increase, and higher propylene sales volumes, which accounted for an additional $58 million increase, partially offset by higher operating costs, which accounted for a $53 million decrease. Propylene and associated by-product production volumes at these facilities increased a combined 10 MBPD period-to-period.
Butane isomerization and related operations
Third Quarter of 2026 Compared to Third Quarter of 2025. Gross operating margin from butane isomerization and related operations for the third quarter of 2026 increased a net $4 million when compared to the third quarter of 2025 primarily due to higher average sales margins, which accounted for an $8 million increase, partially offset by lower sales volumes, which accounted for a $2 million decrease, and higher operating costs, which accounted for an additional $3 million decrease.
Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025. Gross operating margin from butane isomerization and related operations for the nine months ended September 30, 2026 increased a net $8 million when compared to the nine months ended September 30, 2025 primarily due to higher average sales margins, which accounted for an $18 million increase, partially offset by higher operating costs, which accounted for a $9 million decrease.
Octane enhancement and related plant operations
Third Quarter of 2026 Compared to Third Quarter of 2025. Gross operating margin from our octane enhancement and related plant operations for the third quarter of 2026 increased $19 million when compared to the third quarter of 2025 primarily due to higher sales volumes.
Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025. Gross operating margin from our octane enhancement and related plant operations for the nine months ended September 30, 2026 decreased a net $19 million when compared to the nine months ended September 30, 2025 primarily due to higher operating costs, which accounted for a $13 million decrease, and lower sales volumes, which accounted for an additional $12 million decrease, partially offset by higher average sales margins, which accounted for a $6 million increase. The period-to-period decrease in sales volumes at these facilities was primarily due to planned major maintenance activities at our octane enhancement plant during the first quarter of 2026, which were completed in April 2026.
Refined products pipelines and related activities
Third Quarter of 2026 Compared to Third Quarter of 2025. Gross operating margin from refined products pipelines and related activities for the third quarter of 2026 increased $22 million when compared to the third quarter of 2025.
Gross operating margin from our refined products marketing activities, including the TW Products System, increased a net $19 million quarter-to-quarter primarily due to higher average sales margins, which accounted for a $30 million increase, lower operating costs, which accounted for a $4 million increase, and higher mark-to-market earnings, which accounted for an additional $3 million increase, partially offset by lower sales volumes, which accounted for an $18 million decrease.
Gross operating margin from our refined products terminal in Beaumont, Texas increased $6 million quarter-to-quarter primarily due to lower operating costs. Refined products marine terminal volumes at Beaumont increased 62 MBPD quarter-to-quarter.
Gross operating margin from our TE Products Pipeline System decreased a net $5 million quarter-to-quarter primarily due to higher operating costs, which accounted for a $7 million decrease, partially offset by a 138 MBPD increase in transportation volumes, which accounted for a $3 million increase.
Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025. Gross operating margin from refined products pipelines and related activities for the nine months ended September 30, 2026 decreased $1 million when compared to the nine months ended September 30, 2025.
Gross operating margin from our TE Products Pipeline System decreased a net $24 million period-to-period primarily due to higher operating costs, which accounted for a $32 million decrease, and lower other revenues, which accounted for an additional $9 million decrease, partially offset by a 140 MBPD increase in transportation volumes, which accounted for a $20 million increase.
Gross operating margin from our refined products terminal in Beaumont, Texas increased $16 million period-to-period primarily due to lower operating costs, which accounted for an $11 million increase, and higher storage and other fee revenues, which accounted for an additional $6 million increase. Refined products marine terminal volumes at Beaumont increased 48 MBPD period-to-period.
Ethylene exports and related activities
Third Quarter of 2026 Compared to Third Quarter of 2025. Gross operating margin from ethylene exports and related activities for the third quarter of 2026 increased $7 million when compared to the third quarter of 2025 primarily due to lower operating costs, which accounted for a $4 million increase, and a 20 MBPD increase in transportation volumes, which accounted for an additional $2 million increase.
Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025. Gross operating margin from ethylene exports and related activities for the nine months ended September 30, 2026 increased $46 million when compared to the nine months ended September 30, 2025 primarily due to a 20 MBPD increase in ethylene export volumes, which accounted for a $29 million increase, and a 36 MBPD increase in transportation volumes, which accounted for an additional $11 million increase.
Marine transportation and other services
Third Quarter of 2026 Compared to Third Quarter of 2025. Gross operating margin from marine transportation and other services for the third quarter of 2026 increased $5 million when compared to the third quarter of 2025 primarily due to higher average fleet utilization rates, which accounted for a $3 million increase, and higher average fees, which accounted for an additional $2 million increase.
Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025. Gross operating margin from marine transportation and other services for the nine months ended September 30, 2026 was flat when compared to the nine months ended September 30, 2025 primarily due to higher fleet utilization rates, which accounted for a $6 million increase, partially offset by higher operating costs, which accounted for a $6 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, 2026, we had $4.8 billion of consolidated liquidity. This amount was comprised of $232 million of unrestricted cash on hand and $4.5 billion of available borrowing capacity under EPO's revolving credit facilities, which is the net of $5.2 billion of total borrowing capacity under EPO's revolving credit facilities and $660 million outstanding under EPO's commercial paper program.
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, the Partnership has 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). The current registration statement for the ATM program was declared effective on September 1, 2026 and replaced the prior registration statement with respect to such program.
Enterprise Declares Cash Distribution for Third Quarter of 2026
On October 8, 2026, we announced that the Board declared a quarterly cash distribution of $0.56 per common unit, or $2.24 per common unit on an annualized basis, to be paid to the Partnership's common unitholders with respect to the third quarter of 2026. The quarterly distribution is payable on November 13, 2026 to unitholders of record as of the close of business on October 30, 2026. The total amount to be paid is $1.2 billion, which includes $12 million for distribution equivalent rights on phantom unit awards.
The payment of quarterly cash distributions is subject to management's evaluation of our financial condition, results of operations and cash flows in connection with such payments and Board approval. Management will evaluate any future increases in cash distributions on a quarterly basis.
Consolidated Debt
At September 30, 2026, the average maturity of EPO's consolidated debt obligations was approximately 16.6 years. The following table presents the scheduled maturities of principal amounts of EPO's consolidated debt obligations at September 30, 2026 for the years indicated (dollars in millions):
| Scheduled Maturities of Debt | |||||||||||||||||||||||||||||||||||||||||
| Total |
Remainder of 2026 |
2027 | 2028 | 2029 | 2030 | Thereafter | |||||||||||||||||||||||||||||||||||
| Commercial Paper Notes | $ | 660 | $ | 660 | $ | - | $ | - | $ | - | $ | - | $ | - | |||||||||||||||||||||||||||
| Senior Notes | 30,800 | - | 1,575 | 1,800 | 1,250 | 1,250 | 24,925 | ||||||||||||||||||||||||||||||||||
| Junior Subordinated Notes | 2,282 | - | - | - | - | - | 2,282 | ||||||||||||||||||||||||||||||||||
| Total | $ | 33,742 | $ | 660 | $ | 1,575 | $ | 1,800 | $ | 1,250 | $ | 1,250 | $ | 27,207 | |||||||||||||||||||||||||||
In March 2026, EPO entered into a 364-Day Revolving Credit Agreement (the "March 2026 $1.5 Billion 364-Day Revolving Credit Agreement") that replaced its prior 364-day revolving credit agreement. The March 2026 $1.5 Billion 364-Day Revolving Credit Agreement matures in March 2027. EPO's borrowing capacity was unchanged from the prior 364-day revolving credit agreement. As of September 30, 2026, there were no principal amounts outstanding under this revolving credit agreement.
As discussed under "Recent Developments" within this Item 2, EPO entered into its July 2026 $1.0 Billion Incremental Credit Agreement, which provides EPO with an incremental $1.0 billion of borrowing capacity. As of September 30, 2026, there were no principal amounts outstanding under this revolving credit agreement.
For additional information regarding our consolidated debt obligations, see Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.
Credit Ratings
As of November 4, 2026, the investment-grade credit ratings of EPO's long-term senior unsecured debt securities were A- from Standard and Poor's, A3 from Moody's and A- from Fitch Ratings. In addition, the credit ratings of EPO's short-term senior unsecured debt securities were A-2 from Standard and Poor's, P-2 from Moody's and F-2 from Fitch Ratings. EPO's credit ratings reflect only the view of a rating agency and should not be interpreted as a recommendation to buy, sell or hold any of our securities. A credit rating can be revised upward or downward or withdrawn at any time by a rating agency, if it determines that circumstances warrant such a change. A credit rating from one rating agency should be evaluated independently of credit ratings from other rating agencies.
Common Unit Repurchases Under 2019 Buyback Program
In January 2019, we announced that the Board had approved a $2.0 billion multi-year unit buyback program (the "2019 Buyback Program"), which provides the Partnership with an additional method to return capital to investors. In October 2025, we announced that the Board approved an increase to the authorized maximum aggregate purchase price (excluding fees, commissions and other ancillary expenses) of the Partnership's common units that may be repurchased under the 2019 Buyback Program from $2.0 billion to $5.0 billion. The Partnership repurchased 2,922,742 and 10,213,672 common units during the three and nine months ended September 30, 2026, respectively. The total cost of these repurchases, including commissions and fees, was $112 million and $387 million, respectively. As of September 30, 2026, the remaining available capacity under the 2019 Buyback Program was $3.2 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, |
|||||||||||
| 2026 | 2025 | ||||||||||
| Net cash flow provided by operating activities | $ | 6,835 | $ | 6,113 | |||||||
| Net cash flow used in investing activities | 2,571 | 4,256 | |||||||||
| Net cash flow used in financing activities | 5,170 | 2,263 | |||||||||
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 2025 Form 10-K.
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, 2026 increased a net $722 million when compared to the nine months ended September 30, 2025 primarily due to:
•a $998 million period-to-period increase resulting from higher partnership earnings (determined by adjusting our $774 million period-to-period increase in net income for changes in the non-cash items identified on our Unaudited Condensed Consolidated Statements of Consolidated Cash Flows); partially offset by
•a $264 million period-to-period decrease from 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-period changes 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, 2026 decreased $1.7 billion when compared to the nine months ended September 30, 2025 primarily due to:
•a $1.1 billion period-to-period decrease in investments for property, plant and equipment (see "Capital Investments" within this Part I, Item 2 for additional information); and
•a $579 million period-to-period increase in proceeds from asset sales and other matters primarily attributable to the $595 million second installment payment received in January 2026 related to the sale of a 40% undivided joint interest in the Bahia NGL Pipeline.
Financing activities
Net cash flow used in financing activities during the nine months ended September 30, 2026 increased $2.9 billion when compared to the nine months ended September 30, 2025 primarily due to:
•a net cash outflow of $971 million related to debt transactions that occurred during the nine months ended September 30, 2026 compared to a net cash inflow of $1.7 billion related to debt transactions that occurred during the nine months ended September 30, 2025. During the nine months ended September 30, 2026, we repaid $1.63 billion aggregate principal amount of senior notes, partially offset by net issuances of $660 million under EPO's commercial paper program. 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;
•a $137 million period-to-period increase in the repurchase of common units under the 2019 Buyback Program; and
•an $89 million period-to-period increase in cash distributions paid to common unitholders primarily attributable to increases in the quarterly cash distribution rate per unit.
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, |
||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| Net income attributable to common unitholders (GAAP) (1) | $ | 1,624 | $ | 1,338 | $ | 4,946 | $ | 4,166 | |||||||||||||||
| 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 | 729 | 660 | 2,152 | 1,939 | |||||||||||||||||||
| Cash distributions received from unconsolidated affiliates (2) | 112 | 112 | 318 | 336 | |||||||||||||||||||
| Equity in income of unconsolidated affiliates | (87) | (90) | (272) | (276) | |||||||||||||||||||
| Asset impairment charges | 7 | 17 | 24 | 38 | |||||||||||||||||||
| Change in fair market value of derivative instruments | 13 | 34 | (18) | 24 | |||||||||||||||||||
| Deferred income tax expense (benefit) | 11 | (17) | 30 | (1) | |||||||||||||||||||
| Sustaining capital expenditures (3) | (185) | (198) | (530) | (417) | |||||||||||||||||||
|
Other, net (4)
|
87 | (37) | 84 | (67) | |||||||||||||||||||
| Operational DCF (non-GAAP) | $ | 2,311 | $ | 1,819 | $ | 6,734 | $ | 5,742 | |||||||||||||||
| Proceeds from asset sales and other matters | 1 | 6 | 600 | 21 | |||||||||||||||||||
| Monetization of interest rate derivative instruments accounted for as cash flow hedges | - | - | - | 14 | |||||||||||||||||||
| DCF (non-GAAP) | $ | 2,312 | $ | 1,825 | $ | 7,334 | $ | 5,777 | |||||||||||||||
| Cash distributions paid to common unitholders with respect to period, including distribution equivalent rights on phantom unit awards | $ | 1,220 | $ | 1,190 | $ | 3,643 | $ | 3,552 | |||||||||||||||
|
Cash distribution per common unit declared by Enterprise GP with respect to period (5)
|
$ | 0.5600 | $ | 0.5450 | $ | 1.6700 | $ | 1.6250 | |||||||||||||||
|
Total DCF retained by the Partnership with respect to period (6)
|
$ | 1,092 | $ | 635 | $ | 3,691 | $ | 2,225 | |||||||||||||||
|
Distribution coverage ratio (7)
|
1.9 | x | 1.5 | x | 2.0 | x | 1.6 | 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)The third quarter of 2026 includes $100 million for the collection of trade accounts receivable related to income recognized in a prior period.
(5)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.
(6)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.
(7)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, |
||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| Net cash flow provided by operating activities (GAAP) | $ | 2,185 | $ | 1,738 | $ | 6,835 | $ | 6,113 | |||||||||||||||
| 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 | 238 | 322 | 433 | 169 | |||||||||||||||||||
| Sustaining capital expenditures | (185) | (198) | (530) | (417) | |||||||||||||||||||
| Distributions received from unconsolidated affiliates attributable to the return of capital | 27 | 21 | 50 | 56 | |||||||||||||||||||
| Net income attributable to noncontrolling interests | (13) | (17) | (41) | (47) | |||||||||||||||||||
| Other, net | 59 | (47) | (13) | (132) | |||||||||||||||||||
| Operational DCF (non-GAAP) | $ | 2,311 | $ | 1,819 | $ | 6,734 | $ | 5,742 | |||||||||||||||
| Proceeds from asset sales and other matters | 1 | 6 | 600 | 21 | |||||||||||||||||||
| Monetization of interest rate derivative instruments accounted for as cash flow hedges | - | - | - | 14 | |||||||||||||||||||
| DCF (non-GAAP) | $ | 2,312 | $ | 1,825 | $ | 7,334 | $ | 5,777 | |||||||||||||||
Capital Investments
Since the beginning of 2026, we have placed into service our second natural gas processing train at our Mentone West location in the Delaware Basin and the second phase of our Neches River Ethane / Propane Export Facility located in Orange County, Texas. We have approximately $6.3 billion of major growth capital projects scheduled to be completed by the end of the first quarter of 2029, including the following projects (including their respective scheduled completion dates):
•natural gas gathering, compression and treating expansion projects in the Delaware and Midland Basins (fourth quarter of 2026 through 2028);
•the expansion of our LPG and PGP export capacity at EHT, including Ref 4 (fourth quarter of 2026);
•a ninth natural gas processing train ("Athena") in the Midland Basin (fourth quarter of 2026);
•a tenth natural gas processing train ("Athena 2") in the Midland Basin (third quarter of 2027);
•a twelfth natural gas processing train in the Delaware Basin (fourth quarter of 2027);
•the expansion and extension of the Bahia NGL Pipeline (fourth quarter of 2027);
•an NGL fractionator ("Frac 15") at our Mont Belvieu area NGL fractionation complex (first quarter of 2028);
•a thirteenth natural gas processing train in the Delaware Basin (third quarter of 2028); and
•an eleventh natural gas processing train in the Midland Basin (first quarter of 2029).
Based on information currently available, we expect our total organic capital investments for 2026, net of contributions from noncontrolling interests, to approximate $4.1 to $4.6 billion, which reflects organic growth capital investments of $3.5 to $4.0 billion and sustaining capital expenditures of $650 million. In addition, we have received $600 million in cash proceeds from asset sales and other matters during 2026, primarily from the second installment payment received in January 2026 related to the sale of a 40% undivided joint interest in our Bahia NGL Pipeline, which proceeds may be used to offset a portion of our forecasted organic growth capital investments.
Our forecast of capital investments is dependent upon our ability to generate the required funds from either operating cash flows or other means, including borrowings under debt agreements, the issuance of additional equity and debt securities, and potential divestitures. We may revise our forecast of capital investments due to factors beyond our control, such as adverse economic conditions, weather-related issues and changes in supplier prices resulting from raw material or labor shortages, supply chain disruptions or inflation. Furthermore, our forecast of capital investments may change over time based on future decisions by management, which may include changing the scope or timing of projects or cancelling projects altogether. Our success in raising capital, having the ability to increase revenues commensurate with cost increases and our ability to partner with other companies to share project costs and risks continue to be significant factors in determining how much capital we can invest. We believe our access to capital resources is sufficient to meet the demands of our current and future growth needs, and although we currently expect to make the forecast capital investments noted above, we may revise our plans in response to changes in economic and capital market conditions.
The following table summarizes our capital investments for the periods indicated (dollars in millions):
|
For the Nine Months Ended September 30, |
|||||||||||
| 2026 | 2025 | ||||||||||
| Capital investments: (1) | |||||||||||
| Growth capital projects (2) | $ | 2,647 | $ | 3,368 | |||||||
| Sustaining capital projects (3) | 522 | 368 | |||||||||
|
Asset acquisitions (4)
|
30 | 583 | |||||||||
| Total | $ | 3,199 | $ | 4,319 | |||||||
(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.
Comparison of Nine Months Ended September 30, 2026 with Nine Months Ended September 30, 2025
In total, investments in growth capital projects decreased a net $721 million period-to-period primarily due to the following:
•lower investments in our Bahia NGL Pipeline (placed into service in December 2025), which accounted for a $458 million decrease;
•lower investments in ethane, ethylene and LPG export expansion and enhancement projects that support our Gulf Coast terminals (primarily the first and second phases of our Neches River export facility placed into service in July 2025 and May 2026, respectively, and the second phase of enhancements at our Morgan's Point terminal placed into service in December 2025), which accounted for a $230 million decrease; and
•lower investments at our Mont Belvieu area NGL fractionation complex (Frac 14 placed into service during the fourth quarter of 2025), which accounted for an additional $90 million decrease; partially offset by
•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 $154 million increase.
Investments attributable to sustaining capital projects increased $154 million period-to-period primarily due to 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 2025 Form 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, 2026, the total amount of Guaranteed Debt was $34.0 billion, which was comprised of $30.8 billion of EPO's senior notes, $2.3 billion of EPO's junior subordinated notes, $660 million of commercial paper and $288 million of related accrued interest.
The Partnership's guarantees of EPO's senior note obligations, commercial paper notes and borrowings under bank credit facilities represent unsecured and unsubordinated obligations of the Partnership that rank equal in right of payment to all other existing or future unsecured and unsubordinated indebtedness of the Partnership. In addition, these guarantees effectively rank junior in right of payment to any existing or future indebtedness of the Partnership that is secured and unsubordinated, to the extent of the assets securing such indebtedness.
The Partnership's guarantees of EPO's junior subordinated notes represent unsecured and subordinated obligations of the Partnership that rank equal in right of payment to all other existing or future subordinated indebtedness of the Partnership and senior in right of payment to all existing or future equity securities of the Partnership. The Partnership's guarantees of EPO's junior subordinated notes effectively rank junior in right of payment to (i) any existing or future indebtedness of the Partnership that is secured, to the extent of the assets securing such indebtedness and (ii) all other existing or future unsecured and unsubordinated indebtedness of the Partnership.
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 $56.0 billion at September 30, 2026. The Obligor Group's equity in the earnings of the Non-Obligor Subsidiaries for the nine months ended September 30, 2026 was $5.6 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, 2026 | December 31, 2025 | |||||||||
| Current receivables from Non-Obligor Subsidiaries | $ | 607 | $ | 487 | |||||||
| Other current assets | 8,487 | 7,035 | |||||||||
| Long-term receivables from Non-Obligor Subsidiaries | 187 | 187 | |||||||||
|
Other noncurrent assets, excluding investments in Non-Obligor Subsidiaries of $56.0 billion at September 30, 2026 and $54.9 billion at December 31, 2025
|
9,242 | 9,519 | |||||||||
| Selected liability information: | |||||||||||
|
Current portion of Guaranteed Debt, including interest of $288 million at September 30, 2026 and $566 million at December 31, 2025
|
$ | 2,522 | $ | 2,190 | |||||||
| Current payables to Non-Obligor Subsidiaries | 1,903 | 1,344 | |||||||||
| Other current liabilities | 6,179 | 4,416 | |||||||||
| Noncurrent portion of Guaranteed Debt, principal only | 31,507 | 33,082 | |||||||||
| Noncurrent payables to Non-Obligor Subsidiaries | 55 | 54 | |||||||||
| Other noncurrent liabilities | 242 | 205 | |||||||||
| Mezzanine equity of Obligor Group: | |||||||||||
| Preferred units | $ | 44 | $ | 44 | |||||||
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, 2026 |
For the Twelve Months Ended December 31, 2025 | ||||||||||
| Revenues from Non-Obligor Subsidiaries | $ | 7,729 | $ | 16,128 | |||||||
| Revenues from other sources | 20,893 | 17,795 | |||||||||
| Operating income of Obligor Group | 557 | 359 | |||||||||
|
Net loss of Obligor Group excluding equity in earnings of Non-Obligor Subsidiaries of $5.6 billion for the nine months ended September 30, 2026 and $6.9 billion for the twelve months ended December 31, 2025
|
(618) | (1,082) | |||||||||
Related Party Transactions
For information regarding our related party transactions, see Note 14 of 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 04, 2026, and is solely responsible for the information contained herein. Distributed via EDGAR on November 04, 2026 at 15:55 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]