
			Exhibit 99.1

Enterprise Reports Fourth Quarter 2025 Earnings

Houston, Texas (Tuesday, February 3, 2026) – Enterprise Products Partners L.P. (“Enterprise”) (NYSE: EPD) today announced its financial results for the three months and year ended December 31, 2025.

Year End 2025 Results

Enterprise reported net income attributable to common unitholders of $5.8 billion, or $2.66 per common unit on a fully diluted basis, for 2025, compared to $5.9 billion, or $2.69 per common unit on a fully diluted basis, for 2024.

Operational distributable cash flow (“Operational DCF”) was $7.9 billion for 2025 and 2024. Distributions declared with respect to 2025 increased 3.6 percent to $2.175 per common unit, compared to distributions declared for 2024. 2025 marked Enterprise’s 27th consecutive year of distribution growth. Operational DCF provided 1.7 times coverage of the distributions declared for the year, and Enterprise retained $3.2 billion of distributable cash flow (“DCF”) to reinvest in the partnership.

Enterprise repurchased approximately $300 million of its common units in 2025, bringing total common unit repurchases under the partnership’s authorized $5.0 billion common unit buyback program to approximately $1.4 billion.

Adjusted cash flow from operations (“Adjusted CFFO”) was a record $8.7 billion for 2025 compared to $8.6 billion for 2024. For 2025, Enterprise’s payout ratio, comprised of declared distributions to common unitholders and partnership common unit buybacks, was 58 percent of Adjusted CFFO.

Total capital investments, net of proceeds from asset sales, were $5.6 billion in 2025, which included $4.4 billion for growth capital projects, $632 million for the acquisition of Permian Basin gathering assets and gulf coast liquid storage assets, and $620 million of sustaining capital expenditures, less $82 million of proceeds from asset sales. Organic growth capital investments, net of proceeds from asset sales, are expected to be in the range of $1.9 billion to $2.3 billion in 2026, which includes estimated growth capital expenditures of approximately $2.5 to $2.9 billion less approximately $600 million of proceeds from asset sales. Sustaining capital expenditures are expected to be approximately $580 million in 2026.

Total debt principal outstanding at December 31, 2025 was $34.7 billion. At December 31, 2025, Enterprise had consolidated liquidity of approximately $5.2 billion, comprised of available borrowing capacity under its revolving credit facilities and unrestricted cash on hand.

Fourth Quarter 2025 Results

Enterprise reported net income attributable to common unitholders of $1.6 billion for both the fourth quarters of 2025 and 2024. On a fully diluted basis, net income attributable to common unitholders was $0.75 per common unit for the fourth quarter of 2025, compared to $0.74 per common unit for the fourth quarter of 2024.

Operational DCF was $2.2 billion for both the fourth quarters of 2025 and 2024. Distributions declared with respect to the fourth quarter of 2025 increased 2.8 percent to $0.550 per common unit, or $2.20 per common unit annualized, compared to distributions declared for the fourth quarter of 2024. Operational DCF provided 1.8 times coverage of the distribution declared for the fourth quarter of this year. Enterprise retained $1.0 billion of DCF.

Enterprise repurchased approximately $50 million of its common units during the fourth quarter of 2025.

Adjusted CFFO was $2.4 billion for the fourth quarter of 2025 compared to $2.3 billion for the fourth quarter of 2024.

Total capital investments, net of proceeds from asset sales, were $1.3 billion in the fourth quarter of 2025, which included $1.1 billion for growth capital projects, $203 million of sustaining capital expenditures, and $49 million of cash used for asset acquisitions, less $61 million of proceeds from asset sales.


Fourth Quarter and Year End 2025 Financial Highlights	For the Three Months Ended December 31,				For the Year Ended December 31,
	2025		2024		2025		2024
($ in millions, except per unit amounts)
Operating income (1)	$	2,024	$	1,971	$	7,266	$	7,338
Net income (1)	$	1,660	$	1,633	$	5,876	$	5,970
Fully diluted earnings per common unit	$	0.75	$	0.74	$	2.66	$	2.69
Total gross operating margin (1) (2)	$	2,737	$	2,628	$	10,030	$	9,984
Adjusted EBITDA (2)	$	2,707	$	2,599	$	9,964	$	9,899
Adjusted CFFO (2)	$	2,427	$	2,301	$	8,709	$	8,621
Adjusted FCF (2)	$	1,167	$	336	$	3,130	$	3,172
DCF (2)	$	2,223	$	2,155	$	8,000	$	7,839
Operational DCF (2)	$	2,162	$	2,152	$	7,904	$	7,858

(1)Operating income, net income, and gross operating margin include mark-to-market (“MTM”) gains on financial instruments used in our commodity hedging activities of $8 million and losses of $16 million for the fourth quarter and year ended 2025, respectively, compared to gains of $9 million and $20 million for the fourth quarter and year ended 2024, respectively.

(2)Total gross operating margin, adjusted earnings before interest, taxes, depreciation and amortization (“Adjusted EBITDA”), Adjusted CFFO, adjusted free cash flow (“Adjusted FCF”), DCF and Operational DCF are non-generally accepted accounting principle (“non-GAAP”) financial measures that are defined and reconciled later in this press release.


Fourth Quarter and Year End 2025 Volume Highlights	For the Three Months Ended December 31,		For the Year Ended December 31,
	2025	2024	2025	2024
Equivalent pipeline transportation volumes (million BPD)(1)	14.1	13.6	13.7	13.0
NGL, crude oil, refined products & petrochemical pipeline volumes (million BPD)	8.6	8.4	8.3	7.9
Marine terminal volumes (million BPD)	2.2	2.2	2.1	2.2
Natural gas pipeline volumes (TBtus/d)	21.1	19.9	20.7	19.3
NGL fractionation volumes (million BPD)	1.9	1.7	1.7	1.7
Propylene plant production volumes (MBPD)	118	113	116	112
Natural gas processing plant inlet volumes (Bcf/d)	8.1	7.7	7.9	7.5
Fee-based natural gas processing volumes (Bcf/d)	7.3	7.1	7.3	6.7
Equity NGL-equivalent production volumes (MBPD)	225	203	223	203

(1)Represents total NGL, crude oil, refined products and petrochemical transportation volumes plus equivalent energy volumes where 3.8 million British thermal units (“MMBtus”) of natural gas transportation volumes are equivalent to one barrel of NGLs transported.

As used in this press release, “NGL” means natural gas liquids, “LPG” means liquefied petroleum gas, “BPD” means barrels per day, “MBPD” means thousand barrels per day, “MMcf/d” means million cubic feet per day, “Bcf/d” means billion cubic feet per day, “BBtus/d” means billion British thermal units per day, “TBtus/d” means trillion British thermal units per day, and “PDH” means propane dehydrogenation.

2025 K-1 Tax Packages

Enterprise’s K-1 tax packages, including all information to fiduciaries for common units owned in tax exempt accounts, are expected to be made available online through our website at www.enterpriseproducts.com on or before February 27, 2026. The mailing of the tax packages is expected to be completed by March 6, 2026.

Conference Call to Discuss Fourth Quarter 2025 Earnings

Enterprise will host a conference call today to discuss fourth quarter 2025 earnings. The call will be webcast live beginning at 9:00 a.m. CT and may be accessed by visiting the partnership’s website at www.enterpriseproducts.com.

“Enterprise completed 2025 with a record fourth quarter,” said A.J. “Jim” Teague, co-chief executive officer of Enterprise’s general partner. “Record natural gas processing inlet volume of 8.1 Bcf/d, record NGL fractionation volume of 1.9 million BPD, record ethane marine terminal volume of 334 MBPD and record total pipeline volume of 14.1 million BPD-equivalent were some of the ten operational records for the quarter. This volume growth led to increases in gross operating margin in our NGL, refined products and natural gas pipeline businesses that resulted in record gross operating margin, record net income attributable to common unitholders and record cash flow performance for the quarter, which were slightly better than our record performance in the fourth quarter of 2024. Operational DCF for the fourth quarter of 2025 provided 1.8 times coverage of our increased cash distribution to partners of $0.55 per unit, and we retained $1.0 billion to reinvest in the growth of the partnership.”

“We continue to forecast strong natural gas and NGL production growth in the Permian Basin as gas-to-oil ratios continue to increase and as producers use new completion technology, develop new geologic horizons, and step out further on their inventory of locations. This natural gas and NGL production growth is expected despite moderating crude oil production growth in the Permian Basin. Commitments from our producer customers, coupled with our visibility and conviction around basin fundamentals, gave us the confidence to be the industry leader to add significant NGL takeaway capacity from the Permian Basin with the development of the Bahia NGL Pipeline. We are pleased to announce Bahia began operations in December of 2025,” stated Teague.

“Bahia NGL Pipeline has the capacity to transport 600 MBPD of NGLs from the Permian Basin to Enterprise’s 1.5 million BPD Mont Belvieu area fractionation complex. In December of 2025, we completed the previously announced sale of a 40 percent undivided joint interest in the Bahia NGL Pipeline to ExxonMobil. This sale comes in connection with an announcement to expand Bahia’s capacity to 1 million BPD and to extend the pipeline to Exxon’s Cowboy natural gas processing complex in Eddy County, New Mexico. These expansion and extension projects are scheduled to be completed in the fourth quarter of 2027. Additionally, the recent commissioning of the Bahia NGL Pipeline brings the added benefit of our Seminole pipeline’s conversion back to crude oil transportation service, lowering the operating costs on our Permian crude oil pipeline system through the return of cost-effective transportation capacity,” continued Teague.

“At our Dark Horse facility in the Eastern Delaware Basin in New Mexico, we are expanding our sour natural gas treating capacity and have started construction on the previously announced treater 4, which is scheduled to be completed in the second quarter of 2026. We recently executed agreements with producers that underwrite further expansions of this sour natural gas treating system. These projects include the extension of trunk lines in our gathering system in Lea County, the construction of Dark Horse treater 5, and the addition of a third acid gas injection well at our Dark Horse facility. Elsewhere in the Permian Basin, the construction on our Mentone West 2 and Athena natural gas processing plants continues to progress well. Mentone West 2 in the Delaware Basin is scheduled to begin operations later in the first quarter of this year and Athena, our ninth plant in the Midland Basin, should begin operations by the end of 2026,” stated Teague.

“Our acquisition of midstream assets from Occidental, which closed in August of 2025, is also providing additional ‘bolt on’ growth projects. We expect this trend to continue and will result in incremental investment opportunities in natural gas gathering, treating and processing in the Midland Basin. The timing for these potential future investments, as well as other natural gas and liquids opportunities, will be dictated by the pace of our customers’ growth. While these additional investments have increased our expected organic growth capital expenditures for 2026, the proceeds from asset sales has essentially offset this increase and supports our ability to generate free cash flow after capital expenditures and cash distributions for 2026 to fund debt reduction and buybacks,” said Teague.

“We have been at the forefront in developing NGL wellhead-to-water infrastructure since 2008. For the past eighteen years, this role has enabled Enterprise and our customers to be leaders in developing and serving global markets for U.S. NGLs. This is a critical midstream service as U.S. NGL supply continues to be well in excess of domestic demand. The industry must continue to reach international market demand for associated NGLs to continue to facilitate growth of U.S. shale natural gas and crude oil production” stated Teague.

“Surplus U.S. energy continues to be in strong demand in international markets that seek cost competitive, reliable supply. The U.S. energy surplus also serves as an avenue to reduce trade deficits with our country’s international trading partners. In July of 2025, Enterprise commissioned the first phase of our Neches River NGL marine terminal and began ethane exports. In the second quarter of 2026, we will add capacity for both ethane and LPG exports. The expansion of our LPG export capacity on the Houston Ship Channel is on schedule to be completed by the end of this year. We are also seeing opportunities to use operational leverage and modest investments in our natural gas pipeline systems in Texas and Louisiana to serve growing demand to support the development of AI/data centers, industrial reshoring and a general increase in electrification. Much of this growth comes from our traditional customer base,” stated Teague.

“We believe the partnership remains well positioned to capitalize on growth opportunities across our asset footprint, while consistently returning capital to our limited partners,” stated Teague.

Review of Fourth Quarter 2025 Results

Total gross operating margin was $2.7 billion for the fourth quarter of 2025 compared to $2.6 billion for the fourth quarter of 2024.

NGL Pipelines & Services – Gross operating margin from the NGL Pipelines & Services segment was $1.5 billion for both the fourth quarters of 2025 and 2024.

Gross operating margin from the natural gas processing business and related NGL marketing activities was $439 million for the fourth quarter of 2025 compared to $483 million for the fourth quarter of 2024. Natural gas processing plant inlet volumes were a record 8.1 Bcf/d in the fourth quarter of 2025, a 399 MMcf/d, or 5 percent, increase compared to the fourth quarter of 2024. Total fee-based natural gas processing volumes increased 4 percent, or 261 MMcf/d, to 7.3 Bcf/d in the fourth quarter of 2025, compared to the fourth quarter of 2024. Total equity NGL-equivalent production volumes were 225 MBPD and 203 MBPD in the fourth quarters of 2025 and 2024, respectively. The following highlight summarizes selected variances within this business, with results for the fourth quarter of 2025 as compared to the fourth quarter of 2024:

•Gross operating margin from NGL marketing and related activities decreased $36 million due to lower average sales margins primarily related to elevated spot loading rates on export cargos in the prior period, partially offset by higher sales volumes.

Gross operating margin from the NGL pipelines and storage business was a record $860 million for the fourth quarter of 2025, an increase of $38 million compared to the fourth quarter of 2024. Total NGL pipeline volumes were a record 4.9 million BPD in the fourth quarter of 2025, a 57 MBPD, or 1 percent, increase over the fourth quarter of 2024. Total NGL marine terminal volumes were a record 1.0 million BPD in the fourth quarter of 2025, a 31 MBPD increase compared to the fourth quarter of 2024. The following highlights summarize selected variances within this business, with results for the fourth quarter of 2025 as compared to the fourth quarter of 2024:

•Eastern ethane pipelines, which include the ATEX and Aegis pipelines, reported a $29 million increase in gross operating margin primarily due to a 79 MBPD increase in transportation volumes and higher other revenues.

•On a combined basis, gross operating margin from Permian Basin and Rocky Mountain NGL pipelines increased $23 million primarily due to lower operating costs and higher other revenues. This includes the Mid-America Pipeline System, Seminole NGL Pipeline, Shin Oak NGL Pipeline and Chaparral NGL Pipeline. Transportation volumes decreased a combined 46 MBPD.

•Gross operating margin from the Morgan’s Point and Neches River Terminals increased $18 million primarily due to a combined 94 MBPD increase in ethane export volumes. The first phase of the Neches River Terminal was placed in service in July 2025.

•Gross operating margin from LPG-related activities at the Enterprise Hydrocarbons Terminal (“EHT”) decreased $51 million primarily due to lower average loading fees largely due to the recontracting of a legacy agreement in the first half of 2025. LPG export volumes at EHT decreased 63 MBPD.

Gross operating margin from the NGL fractionation business was $242 million for the fourth quarter of 2025 compared to $243 million for the fourth quarter of 2024. Total NGL fractionation volumes were a record 1.9 million BPD for the fourth quarter of 2025 compared to 1.7 million BPD for the fourth quarter of 2024. The following highlight summarizes selected variances within this business, with results for the fourth quarter of 2025 as compared to the fourth quarter of 2024:

•Gross operating margin from the Mont Belvieu area NGL fractionation complex decreased $1 million. NGL fractionation volumes increased 158 MBPD. The favorable impact of higher fractionation volumes and fees was offset by higher operating costs related to planned turnarounds for two fractionators and lower ancillary service revenues.

Crude Oil Pipelines & Services – Gross operating margin from the Crude Oil Pipelines & Services segment was $353 million for the fourth quarter of 2025 compared to $417 million for the fourth quarter of 2024. Total crude oil pipeline volumes were 2.6 million BPD in both the fourth quarters of 2025 and 2024. Total crude oil marine terminal volumes were 785 MBPD in the fourth quarter of 2025 compared to 841 MBPD in the fourth quarter of 2024. The following highlight summarizes selected variances within this segment, with results for the fourth quarter of 2025 as compared to the fourth quarter of 2024:

•Gross operating margin from Texas crude oil pipelines, related terminals and marketing activities (excluding Seaway) decreased $70 million primarily due to lower average sales margins and lower transportation-related revenues, partially offset by a combined 20 MBPD, net to our interest, increase in crude oil transportation volumes.

Natural Gas Pipelines & Services – Gross operating margin for the Natural Gas Pipelines & Services segment was $445 million for the fourth quarter of 2025 compared to $323 million for the fourth quarter of 2024. Total natural gas pipeline volumes were a record 21.1 TBtus/d in the fourth quarter of 2025, a 6 percent increase compared to 19.9 TBtus/d for the same quarter in 2024. The following highlights summarize selected variances within this segment, with results for the fourth quarter of 2025 as compared to the fourth quarter of 2024:

•Natural gas marketing gross operating margin increased $52 million primarily due to higher average sales margins.

•Permian natural gas gathering, including the Delaware and Midland Basin gathering systems, reported a $26 million increase in gross operating margin primarily due to a 641 BBtus/d increase in gathering volumes, higher gathering fees, and higher treating and other revenues.

•Texas Intrastate System gross operating margin increased $23 million primarily due to higher capacity reservation fees and other revenues and higher transportation fees. Transportation volumes increased 89 BBtus/d.

•Acadian Gas System gross operating margin increased $7 million primarily due to a 358 BBtus/d increase in transportation volumes and lower operating costs.

Petrochemical & Refined Products Services – Gross operating margin for the Petrochemical & Refined Products Services segment was $397 million for the fourth quarter of 2025 compared to $348 million for the fourth quarter of 2024. Total segment pipeline volumes were a record 1.1 million BPD in the fourth quarter of 2025 compared to 961 MBPD in the fourth quarter of 2024. Total marine terminal volumes were 331 MBPD in the fourth quarter of 2025 compared to 310 MBPD for the fourth quarter of 2024. The following highlights summarize selected variances within this segment, with results for the fourth quarter of 2025 as compared to the fourth quarter of 2024:

•Refined products pipelines and related activities gross operating margin increased $36 million primarily due to a 184 MBPD increase in transportation volumes, higher sales volumes and margins, and higher other revenues on our refined products pipeline systems.

•Propylene production and related activities reported a $15 million increase in gross operating margin primarily due to higher propylene sales volumes and higher average sales margins.

Use of Non-GAAP Financial Measures

This press release and accompanying schedules include the non-GAAP financial measures of total gross operating margin, Adjusted CFFO, FCF, Adjusted FCF, DCF, Operational DCF and Adjusted EBITDA. The accompanying schedules provide definitions of these non-GAAP financial measures and reconciliations to their most directly comparable financial measure calculated and presented in accordance with GAAP. Our non-GAAP financial measures should not be considered as alternatives to GAAP measures such as net income, operating income, net cash flow provided by operating activities or any other measure of financial performance calculated and presented in accordance with GAAP. Our non-GAAP financial measures may not be comparable to similarly titled measures of other companies because they may not calculate such measures in the same manner as we do.

Company Information and Use of Forward-Looking Statements

Enterprise Products Partners L.P. is one of the largest publicly traded partnerships and a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, refined products and petrochemicals. Services include: natural gas gathering, treating, processing, transportation and storage; NGL transportation, fractionation, storage and marine terminals; crude oil gathering, transportation, storage and marine terminals; petrochemical and refined products transportation, storage and marine terminals; and a marine transportation business that operates on key U.S. inland and intracoastal waterway systems. The partnership’s assets currently include more than 50,000 miles of pipelines; over 300 million barrels of storage capacity for NGLs, crude oil, petrochemicals and refined products; and 14 billion cubic feet of natural gas storage capacity.

This press release includes forward-looking statements. Except for the historical information contained herein, the matters discussed in this press release are forward-looking statements that involve certain risks and uncertainties, such as the partnership’s expectations regarding future results, capital expenditures, project completions, liquidity and financial market conditions. These risks and uncertainties include, among other things, insufficient cash from operations, adverse market conditions, governmental regulations and other factors discussed in Enterprise’s filings with the U.S. Securities and Exchange Commission. If any of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results or outcomes may vary materially from those expected. The partnership disclaims any intention or obligation to update publicly or reverse such statements, whether as a result of new information, future events or otherwise.

Contacts: Libby Strait, Vice President, Investor Relations, (713) 381-4754

Rick Rainey, Vice President, Media Relations, (713) 381-3635


Enterprise Products Partners L.P.					Exhibit A
Condensed Statements of Consolidated Operations – UNAUDITED
($ in millions, except per unit amounts)
	For the Three Months Ended December 31,				For the Year Ended December 31,
	2025		2024		2025		2024
Revenues	$	13,793	$	14,201	$	52,596	$	56,219
Costs and expenses:
Operating costs and expenses	11,792		12,276		45,440		49,045
General and administrative costs	62		60		251		244
Total costs and expenses	11,854		12,336		45,691		49,289
Equity in income of unconsolidated affiliates	85		106		361		408
Operating income	2,024		1,971		7,266		7,338
Other income (expense):
Interest expense	(375)		(346)		(1,401)		(1,352)
Other, net	7		18		34		49
Total other expense, net	(368)		(328)		(1,367)		(1,303)
Income before income taxes	1,656		1,643		5,899		6,035
Benefit from (provision for) income taxes	4		(10)		(23)		(65)
Net income	1,660		1,633		5,876		5,970
Net income attributable to noncontrolling interests	(15)		(13)		(62)		(69)
Net income attributable to preferred units	(1)		(1)		(4)		(4)
Net income attributable to common unitholders	$	1,644	$	1,619	$	5,810	$	5,897
Per common unit data (fully diluted):
Earnings per common unit	$	0.75	$	0.74	$	2.66	$	2.69
Average common units outstanding (in millions)	2,185		2,190		2,188		2,192

Supplemental financial data:
Net cash flow provided by operating activities	$	2,472	$	2,358	$	8,585	$	8,115
Net cash flow used in investing activities	$	1,235	$	2,000	$	5,491	$	5,433
Net cash flow used in financing activities	$	424	$	1,193	$	2,687	$	2,164
Total debt principal outstanding at end of period	$	34,707	$	32,207	$	34,707	$	32,207

Non-GAAP Distributable Cash Flow (1)	$	2,223	$	2,155	$	8,000	$	7,839
Non-GAAP Operational Distributable Cash Flow (1)	$	2,162	$	2,152	$	7,904	$	7,858
Non-GAAP Adjusted EBITDA (2)	$	2,707	$	2,599	$	9,964	$	9,899
Non-GAAP Adjusted Cash flow from operations (3)	$	2,427	$	2,301	$	8,709	$	8,621
Non-GAAP Free Cash Flow (4)	$	1,212	$	393	$	3,006	$	2,666
Non-GAAP Adjusted Free Cash Flow (4)	$	1,167	$	336	$	3,130	$	3,172
Gross operating margin by segment:
NGL Pipelines & Services	$	1,541	$	1,548	$	5,559	$	5,548
Crude Oil Pipelines & Services	353		417		1,501		1,646
Natural Gas Pipelines & Services	445		323		1,558		1,277
Petrochemical & Refined Products Services	397		348		1,436		1,547
Total segment gross operating margin (5)	2,736		2,636		10,054		10,018
Net adjustment for shipper make-up rights (6)	1		(8)		(24)		(34)
Non-GAAP total gross operating margin (7)	$	2,737	$	2,628	$	10,030	$	9,984

(1)See Exhibit F for reconciliation to GAAP net cash flow provided by operating activities.

(2)See Exhibit G for reconciliation to GAAP net cash flow provided by operating activities.

(3)See Exhibit E for reconciliation to GAAP net cash flow provided by operating activities.

(4)See Exhibit D for reconciliation to GAAP net cash flow provided by operating activities.

(5)Within the context of this table, total segment gross operating margin represents a subtotal and corresponds to measures similarly titled within the financial statement footnotes provided in our quarterly and annual filings with the U.S. Securities and Exchange Commission (“SEC”).

(6)Gross operating margin by segment for NGL Pipelines & Services and Crude Oil Pipelines & Services reflects adjustments for non-refundable deferred transportation revenues relating to the make-up rights of committed shippers on certain major pipeline projects. These adjustments are included in managements’ evaluation of segment results. However, these adjustments are excluded from non-GAAP total gross operating margin in compliance with guidance from the SEC.

(7)See Exhibit H for reconciliation to GAAP total operating income.


Enterprise Products Partners L.P.			Exhibit B
Selected Operating Data – UNAUDITED

	For the Three Months Ended December 31,		For the Year Ended December 31,
	2025	2024	2025	2024
Selected operating data:(1)
NGL Pipelines & Services, net:
NGL pipeline transportation volumes (MBPD)	4,871	4,814	4,646	4,426
NGL marine terminal volumes (MBPD)	1,036	1,005	970	915
NGL fractionation volumes (MBPD)	1,871	1,688	1,706	1,667
Equity NGL-equivalent production volumes (MBPD) (2)	225	203	223	203
Fee-based natural gas processing volumes (MMcf/d) (3,4)	7,339	7,078	7,311	6,733
Natural gas processing inlet volumes (MMcf/d) (5)	8,074	7,675	7,906	7,490
Crude Oil Pipelines & Services, net:
Crude oil pipeline transportation volumes (MBPD)	2,576	2,595	2,578	2,528
Crude oil marine terminal volumes (MBPD)	785	841	763	955
Natural Gas Pipelines & Services, net:
Natural gas pipeline transportation volumes (BBtus/d) (6)	21,062	19,929	20,704	19,276
Petrochemical & Refined Products Services, net:
Propylene production volumes (MBPD)	118	113	116	112
Butane isomerization volumes (MBPD)	124	120	121	118
Standalone DIB processing volumes (MBPD)	208	194	194	198
Octane enhancement and related plant sales volumes (MBPD) (7)	37	33	40	37
Pipeline transportation volumes, primarily refined products and petrochemicals (MBPD)	1,136	961	1,040	947
Refined products and petrochemicals marine terminal volumes (MBPD) (8)	331	310	330	326
Total, net:
NGL, crude oil, petrochemical and refined products pipeline transportation volumes (MBPD)	8,583	8,370	8,264	7,901
Natural gas pipeline transportation volumes (BBtus/d)	21,062	19,929	20,704	19,276
Equivalent pipeline transportation volumes (MBPD) (9)	14,126	13,614	13,712	12,974
NGL, crude oil, refined products and petrochemical marine terminal volumes (MBPD)	2,152	2,156	2,063	2,196

(1)Operating rates are calculated based on total volumes divided by the number of calendar days during the applicable period. Total volumes, which include volumes for newly constructed assets from the related in-service date and for recently purchased assets from the related acquisition date, reflect volumes for assets owned by consolidated entities on a 100% basis and volumes for assets owned by our unconsolidated affiliates net to our ownership interest.

(2)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.

(3)Volumes reported correspond to the revenue streams earned by our gas plants. “MMcf/d” means million cubic feet per day.

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

(5)Natural gas processing inlet volumes is an operational measure representing the physical, unprocessed rich natural gas passing through meters located at or near the inlet of our natural gas processing plants or at the wellhead for all natural gas processing facilities that we operate. Substantially all natural gas processing inlet volumes are processed under service contracts that are either fee-based, commodity-based or a combination of both. Natural gas processing inlet volumes are reflected in “Fee-based natural gas processing volumes” for volumes processed under fee-based service contracts, “Equity NGL-equivalent production volumes” for volumes processed under commodity-based service contracts or both of the aforementioned categories for volumes processed under service contracts that have both fee and commodity-based terms.

(6)“BBtus/d” means billion British thermal units per day.

(7)Reflects aggregate sales volumes for our octane enhancement and isobutane dehydrogenation (“iBDH”) facilities located at our Mont Belvieu area complex and our high-purity isobutylene production facility located adjacent to the Houston Ship Channel.

(8)In addition to exports of refined products, these amounts include loading volumes at our ethylene export terminal.

(9)Represents total NGL, crude oil, refined products and petrochemical transportation volumes plus equivalent energy volumes where 3.8 million British thermal units (“MMBtus”) of natural gas transportation volumes are equivalent to one barrel of NGLs transported.


Enterprise Products Partners L.P.						Exhibit C
Selected Commodity Price Information – UNAUDITED


	Natural Gas, $/MMBtu	Ethane, $/gallon	Propane, $/gallon	Normal Butane, $/gallon	Isobutane, $/gallon	Natural Gasoline, $/gallon	Polymer Grade Propylene, $/pound	Refinery Grade Propylene, $/pound
	(1)	(2)	(2)	(2)	(2)	(2)	(3)	(3)
2024 by quarter:
1st Quarter	$2.25	$0.19	$0.84	$1.03	$1.14	$1.54	$0.55	$0.18
2nd Quarter	$1.89	$0.19	$0.75	$0.90	$1.26	$1.55	$0.47	$0.21
3rd Quarter	$2.15	$0.16	$0.73	$0.97	$1.08	$1.48	$0.53	$0.28
4th Quarter	$2.79	$0.22	$0.78	$1.13	$1.12	$1.50	$0.42	$0.24
2024 Averages	$2.27	$0.19	$0.78	$1.01	$1.15	$1.52	$0.49	$0.23

2025 by quarter:
1st Quarter	$3.65	$0.27	$0.90	$1.06	$1.07	$1.53	$0.45	$0.33
2nd Quarter	$3.44	$0.24	$0.78	$0.88	$0.93	$1.32	$0.38	$0.30
3rd Quarter	$3.07	$0.23	$0.69	$0.86	$0.92	$1.30	$0.36	$0.28
4th Quarter	$3.55	$0.27	$0.62	$0.84	$0.88	$1.24	$0.31	$0.22
2025 Averages	$3.43	$0.25	$0.75	$0.91	$0.95	$1.35	$0.38	$0.28

(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 Non-TET commercial index prices as reported by Oil Price Information Service, which is a division of Dow Jones.

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


	WTI Crude Oil, $/barrel	Midland Crude Oil, $/barrel	Houston Crude Oil, $/barrel
	(1)	(2)	(2)
2024 by quarter:
1st Quarter	$76.96	$78.55	$78.85
2nd Quarter	$80.57	$81.73	$82.33
3rd Quarter	$75.10	$75.96	$76.51
4th Quarter	$70.27	$71.19	$71.72
2024 Averages	$75.73	$76.86	$77.35

2025 by quarter:
1st Quarter	$71.42	$72.52	$72.81
2nd Quarter	$63.87	$64.42	$64.65
3rd Quarter	$64.93	$65.76	$66.09
4th Quarter	$59.14	$59.77	$60.05
2025 Averages	$64.84	$65.62	$65.90

(1)West Texas Intermediate (“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.

The weighted-average indicative market price for NGLs (based on prices for such products at Mont Belvieu, Texas, which is the primary industry hub for domestic NGL production) was $0.54 per gallon during the fourth quarter of 2025 versus $0.62 per gallon during the fourth quarter of 2024. 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.

Enterprise Products Partners L.P.

Exhibit D

Free Cash Flow and Adjusted Free Cash Flow – UNAUDITED

($ in millions)


	For the Three Months Ended December 31,				For the Year Ended December 31,
	2025		2024		2025		2024
Free Cash Flow (“FCF”) and Adjusted FCF
Net cash flow provided by operating activities (GAAP)	$	2,472	$	2,358	$	8,585	$	8,115
Adjustments to reconcile net cash flow provided by operating activities to FCF and Adjusted FCF (addition or subtraction indicated by sign):
Net cash flow used in investing activities	(1,235)		(2,000)		(5,491)		(5,433)
Cash contributions from noncontrolling interests	–		57		5		90
Cash distributions paid to noncontrolling interests	(25)		(22)		(93)		(106)
FCF (non-GAAP)	$	1,212	$	393	$	3,006	$	2,666
Net effect of changes in operating accounts, as applicable	(45)		(57)		124		506
Adjusted FCF (non-GAAP)	$	1,167	$	336	$	3,130	$	3,172

FCF is a non-GAAP measure of how much cash a business generates after accounting for capital expenditures such as plants or pipelines. Additionally, Adjusted FCF is a non-GAAP measure of how much cash a business generates, excluding the net effect of changes in operating accounts, after accounting for capital expenditures. We believe that FCF is important to traditional investors since it reflects the amount of cash available for reducing debt, investing in additional capital projects and/or paying distributions. We believe that Adjusted FCF is also important to traditional investors for the same reasons as FCF, without regard for fluctuations caused by timing of when amounts earned or incurred were collected, received or paid from period to period. Since we partner with other companies to fund certain capital projects of our consolidated subsidiaries, our determination of FCF and Adjusted FCF appropriately reflect the amount of cash contributed from and distributed to noncontrolling interests.

Enterprise Products Partners L.P.

Exhibit E

Adjusted cash flow from operations – UNAUDITED

($ in millions)


	For the Three Months Ended December 31,				For the Year Ended December 31,
	2025		2024		2025		2024
Adjusted cash flow from operations (“Adjusted CFFO”)
Net cash flow provided by operating activities (GAAP)	$	2,472	$	2,358	$	8,585	$	8,115
Adjustments to reconcile net cash flow provided by operating activities to Adjusted cash flow from operations (addition or subtraction indicated by sign):
Net effect of changes in operating accounts, as applicable	(45)		(57)		124		506
Adjusted CFFO (non-GAAP)	$	2,427	$	2,301	$	8,709	$	8,621

Adjusted CFFO is a non-GAAP measure that represents net cash flow provided by operating activities before the net effect of changes in operating accounts. We believe that it is important to consider this non-GAAP measure as it can often be a better way to measure the amount of cash generated from our operations that can be used to fund our capital investments or return value to our investors through cash distributions and buybacks, without regard for fluctuations caused by timing of when amounts earned or incurred were collected, received or paid from period to period.

Enterprise Products Partners L.P.

Exhibit F

Distributable Cash Flow and Operational Distributable Cash Flow – UNAUDITED

($ in millions)


	For the Three Months Ended December 31,				For the Year Ended December 31,
	2025		2024		2025		2024
Distributable Cash Flow (“DCF”) and Operational DCF
Net income attributable to common unitholders (GAAP)	$	1,644	$	1,619	$	5,810	$	5,897
Adjustments to net income attributable to common unitholders to derive DCF (addition or subtraction indicated by sign):
Depreciation, amortization and accretion expenses (1)	684		628		2,623		2,473
Cash distributions received from unconsolidated affiliates	102		116		438		483
Equity in income of unconsolidated affiliates	(85)		(106)		(361)		(408)
Asset impairment charges	12		6		50		57
Change in fair market value of derivative instruments	(8)		(9)		16		(20)
Deferred income tax expense	47		22		46		45
Sustaining capital expenditures (2)	(203)		(113)		(620)		(667)
Other, net	(31)		(11)		(98)		(2)
Operational DCF (non-GAAP)	2,162		2,152		7,904		7,858
Proceeds from asset sales and other matters	61		3		82		14
Monetization of interest rate derivative instruments accounted for as cash flow hedges	–		–		14		(33)
DCF (non-GAAP)	$	2,223	$	2,155	$	8,000	$	7,839
Adjustments to reconcile DCF with net cash flow provided by operating activities (addition or subtraction indicated by sign):
Net effect of changes in operating accounts, as applicable	45		57		(124)		(506)
Sustaining capital expenditures	203		113		620		667
Other, net	1		33		89		115
Net cash flow provided by operating activities (GAAP)	$	2,472	$	2,358	$	8,585	$	8,115

(1)Excludes amortization of finance lease right-of-use assets, which are a component of DCF.

(2)Sustaining capital expenditures are capital expenditures (as defined by GAAP) resulting from improvements to and major renewals of existing assets. Such expenditures serve to maintain existing operations but do not generate additional revenues.

DCF is an important non-GAAP liquidity measure for our common unitholders since it serves as an indicator of our success in providing a cash return on investment. Specifically, this liquidity measure indicates to investors whether or not we are generating cash flows at a level that can sustain or support an increase in our quarterly cash distributions. DCF is also a quantitative standard used by the investment community with respect to publicly traded partnerships because 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 common unitholder.

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.

The GAAP measure most directly comparable to DCF and Operational DCF is net cash flow provided by operating activities.

Enterprise Products Partners L.P.

Exhibit G

Adjusted EBITDA - UNAUDITED

($ in millions)


	For the Three Months Ended December 31,				For the Year Ended December 31,
	2025		2024		2025		2024
Net income (GAAP)	$	1,660	$	1,633	$	5,876	$	5,970
Adjustments to net income to derive Adjusted EBITDA (addition or subtraction indicated by sign):
Depreciation, amortization and accretion in costs and expenses (1)	656		606		2,535		2,398
Interest expense, including related amortization	375		346		1,401		1,352
Cash distributions received from unconsolidated affiliates	102		116		438		483
Equity in income of unconsolidated affiliates	(85)		(106)		(361)		(408)
Asset impairment charges	12		6		50		57
Provision for (benefit from) income taxes	(4)		10		23		65
Change in fair market value of commodity derivative instruments	(8)		(9)		16		(20)
Other, net	(1)		(3)		(14)		2
Adjusted EBITDA (non-GAAP)	2,707		2,599		9,964		9,899
Adjustments to reconcile Adjusted EBITDA to net cash flow provided by operating activities (addition or subtraction indicated by sign):
Interest expense, including related amortization	(375)		(346)		(1,401)		(1,352)
Deferred income tax expense	47		22		46		45
Benefit from (provision for) income taxes	4		(10)		(23)		(65)
Net effect of changes in operating accounts, as applicable	45		57		(124)		(506)
Other, net	44		36		123		94
Net cash flow provided by operating activities (GAAP)	$	2,472	$	2,358	$	8,585	$	8,115

(1)Excludes amortization of major maintenance costs for reaction-based plants, which are a component of Adjusted EBITDA.

Adjusted EBITDA is commonly used as a supplemental financial measure by our management and external users of our financial statements, such as investors, commercial banks, research analysts and rating agencies, to assess the financial performance of our assets without regard to financing methods, capital structures or historical cost basis; the ability of our assets to generate cash sufficient to pay interest and support our indebtedness; and the viability of projects and the overall rates of return on alternative investment opportunities.

Since Adjusted EBITDA excludes some, but not all, items that affect net income or loss and because these measures may vary among other companies, the Adjusted EBITDA data presented in this press release may not be comparable to similarly titled measures of other companies. The GAAP measure most directly comparable to Adjusted EBITDA is net cash flow provided by operating activities.

Enterprise Products Partners L.P.

Exhibit H

Gross Operating Margin – UNAUDITED

($ in millions)


	For the Three Months Ended December 31,				For the Year Ended December 31,
	2025		2024		2025		2024
Total gross operating margin (non-GAAP)	$	2,737	$	2,628	$	10,030	$	9,984
Adjustments to reconcile total gross operating margin to total operating income (addition or subtraction indicated by sign):
Depreciation, amortization and accretion expense in operating costs and expenses (1)	(640)		(594)		(2,477)		(2,343)
Asset impairment charges in operating costs and expenses	(12)		(6)		(50)		(57)
Net gains (losses) attributable to asset sales and related matters in operating costs and expenses	1		3		14		(2)
General and administrative costs	(62)		(60)		(251)		(244)
Total operating income (GAAP)	$	2,024	$	1,971	$	7,266	$	7,338

(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.

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 term “total gross operating margin” represents GAAP operating income exclusive of (i) depreciation, amortization and accretion expenses (excluding amortization of major maintenance costs for reaction-based plants and amortization of finance lease right-of-use assets), (ii) impairment charges, (iii) gains and losses attributable to asset sales and related matters, and (iv) general and administrative costs. Total 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. Total gross operating margin is presented on a 100 percent basis before any allocation of earnings to noncontrolling interests. The GAAP financial measure most directly comparable to total gross operating margin is operating income.

Total gross operating margin excludes amounts attributable to shipper make-up rights as described in footnote (6) to Exhibit A of this press release.

Enterprise Products Partners L.P.

Exhibit I

Other Information – UNAUDITED

($ in millions)


	For the Three Months Ended December 31,				For the Year Ended December 31,
	2025		2024		2025		2024
Capital investments:
Capital expenditures	$	1,252	$	1,059	$	4,988	$	4,544
Cash used for asset acquisitions	49		–		632		–
Cash used for business combinations, net of cash received	–		949		–		949
Investments in unconsolidated affiliates	1		–		2		–
Other investing activities	12		8		25		31
Total capital investments	$	1,314	$	2,016	$	5,647	$	5,524

The following table summarizes the mark-to-market gains (losses) for the periods indicated:


	For the Three Months Ended December 31,				For the Year Ended December 31,
	2025		2024		2025		2024
Mark-to-market gains (losses) in gross operating margin:
NGL Pipelines & Services	$	2	$	2	$	(3)	$	(8)
Crude Oil Pipelines & Services	(1)		4		(4)		21
Natural Gas Pipelines & Services	5		3		(10)		5
Petrochemical & Refined Products Services	2		–		1		2
Total mark-to-market impact on gross operating margin	$	8	$	9	$	(16)	$	20

ENTERPRISE PRODUCTS PARTNERS L.P. 8-K