Earnings release
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Exhibit 99.1 Enterprise Reports Second Quarter 2026 Earnings Houston, Texas (Thursday, July 30, 2026) – Enterprise Products Partners L.P. (“Enterprise”) (NYSE: EPD) today announced its financial results for the three and six months ended June 30, 2026. Financial Highlights (2Q 2026 compared to 2Q 2025, as applicable) • Net income attributable to common unitholders: a record $1.8 billion, $0.84 per diluted common unit, up 28% • Adjusted EBITDA: a record $2.8 billion, up 17% • Operational DCF: a record $2.3 billion, which provided 1.9x coverage of distributions declared for 2Q 2026, up 21%; retained $1.1 billion of DCF • Adjusted CFFO: a record $2.5 billion, up 19% • Common unit repurchases: $159 million for the quarter and $405 million for the 12 months ended June 30, 2026; 34% cumulative utilization of $5.0 billion buyback program • For the 12 months ended June 30, 2026, the payout ratio, comprised of distributions to common unitholders and common unit buybacks, was 56% of Adjusted CFFO • Distributions declared: $0.56 per common unit, or $2.24 per common unit annualized, up 2.8% Capital Investment and Operational Highlights (2Q 2026 compared to 2Q 2025, as applicable) • Record equivalent pipeline volumes: 14.7 MMBPD, up 8% • Record marine terminal volumes: 2.8 MMBPD, up 33% • Assets placed into service: Second phase of our Neches River Terminal in Texas • Capital investments for 2Q 2026: $1.2 billion, comprised of $1.0 billion for growth capital projects and $140 million for sustaining capital expenditures • Announced plans to construct a new 150 MBPD NGL fractionator (Frac 15) at our Mont Belvieu area complex • Announced plans to construct a new 300 MMcf/d Gas Processing Plant (Plant 13) in the Delaware Basin and a new 300 MMcf/d Gas Processing Plant (Plant 11) in the Midland Basin; expected to begin service in the third quarter of 2028 and the first quarter of 2029, respectively • Growth capital spending for 2026, net of $599 million of proceeds from asset sales, is expected to be in the range of $2.9 to $3.4 billion; and $600 million for sustaining capital expenditures Conference Call to Discuss Second Quarter 2026 Earnings Enterprise will host a conference call today to discuss second quarter 2026 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. Adjusted earnings before interest, taxes, depreciation and amortization (“Adjusted EBITDA”), distributable cash flow (“DCF”), Operational distributable cash flow (“Operational DCF”), Adjusted cash flow from operations (“Adjusted CFFO”), total gross operating margin, and adjusted free cash flow (“Adjusted FCF”) are non- generally accepted accounting principle (“non-GAAP”) financial measures that are defined and reconciled later in this press release. 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, “MMBPD” means million 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.
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“Enterprise reported strong volumes, earnings and cash flow for the second quarter of 2026,” said A. J. “Jim” Teague, co-chief executive officer of Enterprise’s general partner. “The partnership handled record pipeline and marine terminal volumes during the quarter due in part to strong international demand for U.S. energy in April and May. We also benefited from new assets and expansion projects that began operating and commissioning activities within the last twelve months including Frac 14 at our Mont Belvieu area complex and the expansions of our Neches River and Morgan’s Point Terminals. Total pipeline equivalent volumes for the quarter increased 8 percent to 14.7 MMBPD compared to the second quarter of 2025 while total marine terminal equivalent volumes increased 33 percent to 2.8 MMBPD compared to the second quarter of last year. We also reported a 14 percent increase in propylene production volumes to a record 134 MBPD during the second quarter of 2026 as we achieved higher utilization rates at our propylene production facilities. While not a record, inlet volumes to our natural gas processing plants increased to 8.1 Bcf/d in the second quarter of 2026 primarily due to a 14 percent increase in volume to our natural gas processing plants in the Permian Basin. “This volume growth, an increase in the value of our equity NGL production and higher marketing volumes and margins led to record earnings and cash flow in the second quarter of 2026. Operational distributable cash flow for the quarter increased 21 percent to a record $2.3 billion compared to the second quarter of last year. This provided 1.9 times coverage of the partnership’s cash distribution. In addition to $1.2 billion of cash distributions to unitholders, we retained $1.1 billion to apply to internally funded growth capital expenditures and buybacks,” stated Teague. “I would like to congratulate our engineering and operations team for enabling Enterprise to respond to the acute global demand for U.S. energy by accelerating the completion of construction and beginning of commissioning activities for the expansion of our Neches River Terminal. Volumes at our marine terminals have returned to normal levels in June and July after the initial rush to backfill volumes affected by hostilities in the Middle East in April and May. Global shipping of energy, however, continues to be disrupted due to damage to production facilities and navigation restrictions in the Middle East, longer transits due to reroutes and the continuing uncertainty in the region,” continued Teague. “During the quarter, we approved the construction of two new 300 MMcf/d gas processing plants located in the Permian Basin and a 150 MBPD NGL fractionator at our Mont Belvieu area complex. These assets support ongoing production growth in the Permian Basin and international demand for U.S NGLs. This brings the partnership’s total organic growth projects under construction to $6.5 billion. The next major capital project scheduled for completion is our expansion of the LPG export marine terminal on the Houston Ship Channel that is expected to begin operations by year end 2026,” concluded Teague. Review of Second Quarter 2026 Results Total gross operating margin for the second quarter of 2026 increased $514 million to a record $3.0 billion compared to the second quarter of 2025. This includes a $77 million increase in unrealized mark-to-market (“MTM”) gains on financial instruments used in our hedging activities. NGL Pipelines & Services – Gross operating margin from the NGL Pipelines & Services segment was $1.5 billion for the second quarter of 2026 compared to $1.3 billion for the second quarter of 2025. Gross operating margin from the natural gas processing business and related NGL marketing activities was $512 million for the second quarter of 2026 compared to $341 million for the second quarter of 2025. Natural gas processing plant inlet volumes were 8.1 Bcf/d in the second quarter of 2026, a 4 percent increase compared to the second quarter of 2025. Notably, inlet volumes to the partnership’s natural gas processing plants in the Permian Basin increased 14 percent to 4.3 Bcf/d for the second quarter of 2026. Total fee- based natural gas processing volumes increased 182 MMcf/d to 7.4 Bcf/d in the second quarter of 2026 compared to the second quarter of last year. Total equity NGL-equivalent production volumes increased 7 percent to 230 MBPD in the second quarter of 2026 compared to the second quarter of 2025. The following highlights summarize selected variances within this business, with results for the second quarter of 2026 as compared to the second quarter of 2025: • NGL marketing reported an $83 million increase in gross operating margin driven by higher average sales margin of $51 million, higher MTM earnings of $19 million and higher sales volumes of $13 million. • Midland Basin natural gas processing facilities reported a $47 million increase in gross operating margin primarily due to higher average processing margins, which includes a $38 million increase attributable to hedging activities, and increased volumes. Fee-based natural gas processing volumes increased 218 MMcf/d and equity NGL-equivalent production volumes increased 10 MBPD. 2
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• Delaware Basin natural gas processing facilities reported a net $36 million increase in gross operating margin primarily due to higher average processing margins and increased volumes, partially offset by higher operating costs. Fee-based natural gas processing volumes increased 288 MMcf/d and equity NGL-equivalent production volumes increased 8 MBPD. Gross operating margin from the NGL pipelines and storage business was $757 million for the second quarter of 2026 compared to $732 million for the second quarter of 2025. Total NGL pipeline volumes were a record 4.9 MMBPD in the second quarter of 2026, a 351 MBPD, or 8 percent, increase over the second quarter of 2025. Total NGL marine terminal volumes were a record 1.2 MMBPD in the second quarter of 2026, a 284 MBPD increase compared to the second quarter of 2025. The following summarizes the variance for this business, with results for the second quarter of 2026 as compared to the second quarter of 2025: • Gross operating margin from the Morgan's Point, Neches River and Enterprise Hydrocarbons terminals and the associated Channel pipeline increased $35 million primarily driven by higher volumes, including the completion of the second phase of the Neches River Terminal in May 2026. On a combined basis, ethane export volumes increased by 143 MBPD and propane export volumes increased 141 MBPD. Gross operating margin from the NGL fractionation business was a record $276 million for the second quarter of 2026 compared to $224 million for the second quarter of 2025. Total NGL fractionation volumes were 1.9 MMBPD for the second quarter of 2026 compared to 1.7 MMBPD for the second quarter of 2025. The following summarizes the variance for this business, with results for the second quarter of 2026 as compared to the second quarter of 2025: • Gross operating margin from our Mont Belvieu area NGL fractionation complex increased $54 million primarily due to a 207 MBPD increase in fractionation volumes and higher ancillary service revenues, partially offset by higher operating costs. The higher fractionation volumes were primarily due to Frac 14, which was placed into service in the fourth quarter of 2025. Crude Oil Pipelines & Services – Gross operating margin from the Crude Oil Pipelines & Services segment was $485 million for the second quarter of 2026 compared to $403 million for the second quarter of 2025. Total crude oil pipeline volumes were a record 3.0 MMBPD in the second quarter of 2026, a 403 MBPD increase compared to the second quarter of 2025. Total crude oil marine terminal volumes were a record 1.1 MMBPD in the second quarter of 2026 compared to 811 MBPD in the second quarter of 2025. The following highlights summarize selected variances within this segment, with results for the second quarter of 2026 as compared to the second quarter of 2025: • On a combined basis, gross operating margin from our Texas crude oil pipelines, related terminals and marketing activities (excluding the Seaway Pipeline) increased $69 million primarily due to higher average sales margins and sales volumes, partially offset by higher operating costs. Crude oil pipeline volumes and EHT crude oil marine terminal volumes increased 265 MBPD and 227 MBPD, respectively. • Gross operating margin from the Seaway Pipeline system increased $23 million primarily due to higher pipeline volumes and crude oil marine terminal volumes (net to our interest), which benefited from exports of crude oil originating from the U.S. Strategic Petroleum Reserve. Net to our interest, pipeline volumes increased 138 MBPD and crude oil marine terminal volumes increased 86 MBPD. Natural Gas Pipelines & Services – Gross operating margin for the Natural Gas Pipelines & Services segment was a record $556 million for the second quarter of 2026 compared to $417 million for the second quarter of 2025. Total natural gas pipeline volumes were 21.0 TBtus/d in the second quarter of 2026, a 3 percent increase compared to 20.4 TBtus/d for the same quarter in 2025. The following highlights summarize selected variances within this segment, with results for the second quarter of 2026 as compared to the second quarter of 2025: • Natural gas marketing reported a $91 million increase in gross operating margin primarily due to $60 million of higher average sales margins and $31 million of higher MTM earnings. • Texas Intrastate System gross operating margin increased $32 million primarily due to higher average transportation and related fees and increased pipeline volumes. • On a combined basis, gross operating margin from our Delaware Basin Gathering System and Midland Basin Gathering System increased a net $13 million primarily due to higher gathering volumes partially offset by higher operating costs. 3
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Petrochemical & Refined Products Services – Gross operating margin for the Petrochemical & Refined Products Services segment was $418 million for the second quarter of 2026 compared to $354 million for the second quarter of 2025. Total segment pipeline volumes were a record 1.2 MMBPD in the second quarter of 2026 compared to 1.0 MMBPD in the second quarter of 2025. Total marine terminal volumes were 422 MBPD in the second quarter of 2026 compared to 328 MBPD for the second quarter of 2025. The following highlights summarize selected variances within this segment, with results for the second quarter of 2026 as compared to the second quarter of 2025: • The partnership’s ethylene business reported a $23 million increase in gross operating margin primarily due to a 20 MBPD increase in export volumes, and higher sales and pipeline volumes. • Propylene production and related activities reported a net $19 million increase in gross operating margin primarily due to record propylene production volumes, which resulted in higher propylene sales volumes, and higher average propylene sales margins, partially offset by higher operating costs. • Gross operating margin from our octane enhancement and related plant operations increased $8 million due to higher average sales margins and higher MTM earnings. 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, 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: Joe Theriac, Vice President, Finance & Investor Relations, (713) 381-6394 Rick Rainey, Vice President, Media Relations, (713) 381-3635 4
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Enterprise Products Partners L.P. Exhibit A Condensed Statements of Consolidated Operations – UNAUDITED ($ in millions, except per unit amounts) For the Three Months Ended June 30, For the Six Months Ended June 30, For the Twelve Months Ended June 30, 2026 2025 2026 2025 2026 Revenues $ 18,269 $ 11,363 $ 32,655 $ 26,780 $ 58,471 Costs and expenses: Operating costs and expenses 16,065 9,592 28,568 23,282 50,726 General and administrative costs 64 68 128 128 251 Total costs and expenses 16,129 9,660 28,696 23,410 50,977 Equity in income of unconsolidated affiliates 109 92 185 186 360 Operating income 2,249 1,795 4,144 3,556 7,854 Other income (expense): Interest expense (384) (332) (769) (672) (1,498) Other, net 3 7 11 16 29 Total other expense, net (381) (325) (758) (656) (1,469) Income before income taxes 1,868 1,470 3,386 2,900 6,385 Provision for income taxes (12) (16) (34) (40) (17) Net income 1,856 1,454 3,352 2,860 6,368 Net income attributable to noncontrolling interests (15) (18) (28) (30) (60) Net income attributable to preferred units (1) (1) (2) (2) (4) Net income attributable to common unitholders $ 1,840 $ 1,435 $ 3,322 $ 2,828 $ 6,304 Per common unit data (fully diluted): Earnings per common unit $ 0.84 $ 0.66 $ 1.52 $ 1.29 $ 2.89 Average common units outstanding (in millions) 2,185 2,190 2,185 2,190 2,185 Supplemental financial data: Net cash flow provided by operating activities $ 3,181 $ 2,061 $ 4,650 $ 4,375 $ 8,860 Net cash flow used in investing activities $ 1,154 $ 1,274 $ 1,535 $ 2,321 $ 4,705 Net cash flow used in financing activities $ 2,076 $ 145 $ 4,015 $ 1,796 $ 4,906 Total debt principal outstanding at end of period $ 33,532 $ 33,057 $ 33,532 $ 33,057 $ 33,532 Non-GAAP Distributable Cash Flow $ 2,315 $ 1,939 $ 5,022 $ 3,952 $ 9,070 Non-GAAP Operational Distributable Cash Flow $ 2,312 $ 1,914 $ 4,423 $ 3,923 $ 8,404 Non-GAAP Adjusted EBITDA $ 2,829 $ 2,408 $ 5,521 $ 4,852 $ 10,633 Non-GAAP Adjusted Cash flow from operations $ 2,515 $ 2,111 $ 4,845 $ 4,222 $ 9,332 Non-GAAP Adjusted Free Cash Flow $ 1,341 $ 812 $ 3,267 $ 1,867 $ 4,530 Gross operating margin by segment: NGL Pipelines & Services $ 1,545 $ 1,297 $ 3,048 $ 2,715 $ 5,892 Crude Oil Pipelines & Services 485 403 814 777 1,538 Natural Gas Pipelines & Services 556 417 1,052 774 1,836 Petrochemical & Refined Products Services 418 354 732 669 1,499 Total segment gross operating margin 3,004 2,471 5,646 4,935 10,765 Net adjustment for shipper make-up rights (13) 6 (31) (27) (28) Non-GAAP total gross operating margin $ 2,991 $ 2,477 $ 5,615 $ 4,908 $ 10,737 (1) See Exhibit E for reconciliation to GAAP net cash flow provided by operating activities. (2) See Exhibit F for reconciliation to GAAP net cash flow provided by operating activities. (3) See Exhibit D for reconciliation to GAAP net cash flow provided by operating activities. (4) 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”). (5) 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. (1) (1) (2) (3) (3) (4) (5) (6)
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(6) See Exhibit G for reconciliation to GAAP total operating income. 5
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Enterprise Products Partners L.P. Exhibit B Selected Operating Data – UNAUDITED For the Three Months Ended June 30, For the Six Months Ended June 30, For the Twelve Months Ended June 30, 2026 2025 2026 2025 2026 Selected operating data: NGL Pipelines & Services, net: NGL pipeline transportation volumes (MBPD) 4,913 4,562 4,894 4,504 4,838 NGL marine terminal volumes (MBPD) 1,226 942 1,162 968 1,066 NGL fractionation volumes (MBPD) 1,858 1,667 1,885 1,657 1,819 Equity NGL-equivalent production volumes (MBPD) 230 214 232 220 229 Fee-based natural gas processing volumes (MMcf/d) 7,448 7,266 7,463 7,223 7,429 Natural gas processing inlet volumes (MMcf/d) 8,116 7,768 8,184 7,744 8,124 Crude Oil Pipelines & Services, net: Crude oil pipeline transportation volumes (MBPD) 3,025 2,622 2,837 2,554 2,718 Crude oil marine terminal volumes (MBPD) 1,123 811 995 774 873 Natural Gas Pipelines & Services, net: Natural gas pipeline transportation volumes (BBtus/d) 21,048 20,405 21,109 20,358 21,077 Petrochemical & Refined Products Services, net: Propylene production volumes (MBPD) 134 118 129 115 124 Butane isomerization volumes (MBPD) 115 122 118 118 121 Standalone DIB processing volumes (MBPD) 228 186 223 187 213 Octane enhancement and related plant sales volumes (MBPD) 37 39 32 42 37 Pipeline transportation volumes, primarily refined products and petrochemicals (MBPD) 1,208 1,008 1,151 977 1,124 Refined products and petrochemicals marine terminal volumes (MBPD) 422 328 400 320 371 Total, net: NGL, crude oil, petrochemical and refined products pipeline transportation volumes (MBPD) 9,146 8,192 8,882 8,035 8,680 Natural gas pipeline transportation volumes (BBtus/d) 21,048 20,405 21,109 20,358 21,077 Equivalent pipeline transportation volumes (MBPD) 14,685 13,562 14,437 13,392 14,227 NGL, crude oil, refined products and petrochemical marine terminal volumes (MBPD) 2,771 2,081 2,557 2,062 2,310 (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. (1) (2) (3,4) (5) (6) (7) (8) (9) 6
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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 (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 2026 Averages $3.98 $0.22 $0.72 $0.98 $1.01 $1.72 (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. 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 2026 Averages $82.32 $84.29 $84.98 (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 $0.68 per gallon during the second quarter of 2026 versus $0.58 per gallon during the second quarter of 2025. Fluctuations in our consolidated revenues and cost of sales amounts are explained in large part by changes in energy commodity prices. An increase in our consolidated marketing revenues due to higher energy commodity sales prices may not result in an increase in gross operating margin or cash available for distribution, since our consolidated cost of sales amounts would also be expected to increase due to comparable increases in the purchase prices of the underlying energy commodities. The same type of relationship would be true in the case of lower energy commodity sales prices and purchase costs. 7
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Enterprise Products Partners L.P. Exhibit D Adjusted cash flow from operations and Adjusted Free Cash Flow – UNAUDITED ($ in millions) For the Three Months Ended June 30, For the Six Months Ended June 30, 2026 2025 2026 2025 Adjusted cash flow from operations (“Adjusted CFFO”) and Adjusted Free Cash Flow (“Adjusted FCF”) Net cash flow provided by operating activities (GAAP) $ 3,181 $ 2,061 $ 4,650 $ 4,375 Adjustments to reconcile net cash flow provided by operating activities to Adjusted CFFO and Adjusted FCF (addition or subtraction indicated by sign): Net effect of changes in operating accounts, as applicable (666) 50 195 (153) Adjusted CFFO (non-GAAP) $ 2,515 $ 2,111 $ 4,845 $ 4,222 Net cash flow used in investing activities (1,154) (1,274) (1,535) (2,321) Cash contributions from noncontrolling interests 1 1 1 5 Cash distributions paid to noncontrolling interests (21) (26) (44) (39) Adjusted FCF (non-GAAP) $ 1,341 $ 812 $ 3,267 $ 1,867 For the Twelve Months Ended June 30, 2026 2025 Net cash flow provided by operating activities (GAAP) $ 8,860 $ 8,805 Adjustments to reconcile net cash flow provided by operating activities to Adjusted CFFO and Adjusted FCF (addition or subtraction indicated by sign): Net effect of changes in operating accounts, as applicable 472 (174) Adjusted CFFO (non-GAAP) $ 9,332 $ 8,631 Net cash flow used in investing activities (4,705) (5,473) Cash contributions from noncontrolling interests 1 70 Cash distributions paid to noncontrolling interests (98) (82) Adjusted FCF (non-GAAP) $ 4,530 $ 3,146 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. Adjusted FCF is a non-GAAP measure that reflects cash generated from our operations, excluding the net effect of changes in operating accounts, after accounting for capital expenditures. We believe that Adjusted 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, 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 Adjusted FCF appropriately reflects the amount of cash contributed from and distributed to noncontrolling interests. 8
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Enterprise Products Partners L.P. Exhibit E Distributable Cash Flow and Operational Distributable Cash Flow – UNAUDITED ($ in millions) For the Three Months Ended June 30, For the Six Months Ended June 30, For the Twelve Months Ended June 30, 2026 2025 2026 2025 2026 Distributable Cash Flow (“DCF”) and Operational DCF Net income attributable to common unitholders (GAAP) $ 1,840 $ 1,435 $ 3,322 $ 2,828 $ 6,304 Adjustments to net income attributable to common unitholders to derive DCF (addition or subtraction indicated by sign): Depreciation, amortization and accretion expenses 722 643 1,423 1,279 2,767 Cash distributions received from unconsolidated affiliates 120 121 206 224 420 Equity in income of unconsolidated affiliates (109) (92) (185) (186) (360) Asset impairment charges 9 11 17 21 46 Change in fair market value of derivative instruments (129) (52) (31) (10) (5) Deferred income tax expense 5 5 19 16 49 Sustaining capital expenditures (140) (117) (345) (219) (746) Other, net (6) (40) (3) (30) (71) Operational DCF (non-GAAP) 2,312 1,914 4,423 3,923 8,404 Proceeds from asset sales and other matters 3 11 599 15 666 Monetization of interest rate derivative instruments accounted for as cash flow hedges – 14 – 14 – DCF (non-GAAP) $ 2,315 $ 1,939 $ 5,022 $ 3,952 $ 9,070 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 666 (50) (195) 153 (472) Sustaining capital expenditures 140 117 345 219 746 Proceeds from asset sales and other matters (3) (11) (599) (15) (666) Other, net 63 66 77 66 182 Net cash flow provided by operating activities (GAAP) $ 3,181 $ 2,061 $ 4,650 $ 4,375 $ 8,860 (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. (1) (2) 9
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Enterprise Products Partners L.P. Exhibit F Adjusted EBITDA - UNAUDITED ($ in millions) For the Three Months Ended June 30, For the Six Months Ended June 30, For the Twelve Months Ended June 30, 2026 2025 2026 2025 2026 Net income (GAAP) $ 1,856 $ 1,454 $ 3,352 $ 2,860 $ 6,368 Adjustments to net income to derive Adjusted EBITDA (addition or subtraction indicated by sign): Depreciation, amortization and accretion in costs and expenses 688 625 1,360 1,240 2,655 Interest expense, including related amortization 384 332 769 672 1,498 Cash distributions received from unconsolidated affiliates 120 121 206 224 420 Equity in income of unconsolidated affiliates (109) (92) (185) (186) (360) Asset impairment charges 9 11 17 21 46 Provision for income taxes 12 16 34 40 17 Change in fair market value of commodity derivative instruments (129) (52) (31) (10) (5) Other, net (2) (7) (1) (9) (6) Adjusted EBITDA (non-GAAP) 2,829 2,408 5,521 4,852 10,633 Adjustments to reconcile Adjusted EBITDA to net cash flow provided by operating activities (addition or subtraction indicated by sign): Interest expense, including related amortization (384) (332) (769) (672) (1,498) Deferred income tax expense 5 5 19 16 49 Provision for income taxes (12) (16) (34) (40) (17) Net effect of changes in operating accounts, as applicable 666 (50) (195) 153 (472) Other, net 77 46 108 66 165 Net cash flow provided by operating activities (GAAP) $ 3,181 $ 2,061 $ 4,650 $ 4,375 $ 8,860 (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. (1) 10
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Enterprise Products Partners L.P. Exhibit G Gross Operating Margin – UNAUDITED ($ in millions) For the Three Months Ended June 30, For the Six Months Ended June 30, For the Twelve Months Ended June 30, 2026 2025 2026 2025 2026 Total gross operating margin (non-GAAP) $ 2,991 $ 2,477 $ 5,615 $ 4,908 $ 10,737 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 (671) (610) (1,327) (1,212) (2,592) Asset impairment charges in operating costs and expenses (9) (11) (17) (21) (46) Net gains attributable to asset sales and related matters in operating costs and expenses 2 7 1 9 6 General and administrative costs (64) (68) (128) (128) (251) Total operating income (GAAP) $ 2,249 $ 1,795 $ 4,144 $ 3,556 $ 7,854 (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 (5) to Exhibit A of this press release. (1) 11
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Enterprise Products Partners L.P. Exhibit H Other Information – UNAUDITED ($ in millions) For the Three Months Ended June 30, For the Six Months Ended June 30, For the Twelve Months Ended June 30, 2026 2025 2026 2025 2026 Capital investments: Capital expenditures $ 1,138 $ 1,299 $ 2,121 $ 2,361 $ 4,748 Cash used for asset acquisitions 20 – 20 – 652 Investments in unconsolidated affiliates – 1 – 1 1 Other investing activities 11 5 16 9 32 Total capital investments $ 1,169 $ 1,305 $ 2,157 $ 2,371 $ 5,433 The following table summarizes the mark-to-market gains (losses) for the periods indicated: For the Three Months Ended June 30, For the Six Months Ended June 30, For the Twelve Months Ended June 30, 2026 2025 2026 2025 2026 Mark-to-market gains (losses) in gross operating margin: NGL Pipelines & Services $ 3 $ (16) $ – $ (21) $ 18 Crude Oil Pipelines & Services 16 5 3 3 (4) Natural Gas Pipelines & Services 89 58 33 25 (2) Petrochemical & Refined Products Services 21 5 (5) 3 (7) Total mark-to-market impact on gross operating margin $ 129 $ 52 $ 31 $ 10 $ 5 12