Slides
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NYSE: EPD Fourth Quarter 2025 Earnings Support Slides February 3, 2026
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2© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Forward-Looking Statements This presentation contains forward-looking statements based on the beliefs of the company, as well as assumptions made by, and information currently available to our management team (including information published by third parties). When used in this presentation, 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 management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. You should not put undue reliance on any forward-looking statements, which speak only as of their dates. Forward-looking statements are subject to risks and uncertainties that may cause actual results to differ materially from those expected, including insufficient cash from operations, adverse market conditions, governmental regulations, the possibility that tax or other costs or difficulties related thereto will be greater than expected, the impact of competition and other risk factors discussed in our latest filings with the Securities and Exchange Commission. All forward-looking statements attributable to Enterprise or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained herein, in such filings and in our future periodic reports filed with the Securities and Exchange Commission. Except as required by law, we do not intend to update or revise our forward- looking statements, whether as a result of new information, future events or otherwise.
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3© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Qualifying Statements This supplemental package contains earnings support slides highlighting major variances for the quarter. This data should be read in conjunction with the information contained in the earnings release for the fourth quarter of 2025 and our SEC Form 10-K (when filed), which provide a more comprehensive description of the variances between certain periods.
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4© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Enterprise Allocation of Capital “All of the Above” Approach Responsibly Returning Capital to Investors • $62 Billion (“B”) of capital returned to equity investors via LP distributions and common unit buybacks, since IPO • Distributions: $0.55/unit for 4Q 2025, a 2.8% increase over 4Q 2024 • Buybacks: $50 million (“MM”), 1.6MM common units, of repurchases in 4Q 2025 • $300MM, 9.5MM common units, of repurchases in FY 2025 • Unitholder Reinvestment & Employee Support: our DRIP (1) and EUPP (2) programs purchased a combined 1.2MM and 4.7MM common units in 4Q 2025 and 2025 respectively, on the open market • Adjusted CFFO Payout Ratio (3) : 58% for FY 2025 (1) Distribution Reinvestment Plan (“DRIP”) (2) Employee Unit Purchase Plan (“EUPP”) (3) See definitions (4) Organic growth capital investments, net of proceeds from asset sales, are expected to be in the range of $1.9 - $2.3B in 2026, which includes estimated growth capital expenditures of ≈$2.5-$2.9B less ≈$600MM of proceeds from asset sales Maintain and Protect Balance Sheet • Leverage Ratio (3) : 3.3x as of December 31, 2025; target ratio of 3.0x (+/– 0.25x) • Liquidity: $5.2B comprised of available credit capacity and unrestricted cash as of December 31, 2025 Capital Expenditures • Growth Capital Expenditures Range: $2.5B to $2.9B in 2026 (4) ; $2.0B to $2.5B in 2027 • Sustaining Capital Expenditures: ≈$580MM in 2026
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5© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com EPD’s Role in Building a Resilient Portfolio Recession Resistant • Businesses have a high degree of inelastic demand from providing integral infrastructure services to producers and consumers of energy and energy products Inflation Protection • Approximately 90% of long-term contracts have escalation provisions to mitigate impacts of inflation to cash flow and distributions Assets Underwritten by Conservative, Long-Term Financing • Only A- rated midstream energy infrastructure company • Debt portfolio has a 17-year average maturity (1) , 98% of portfolio is fixed rate (1) , weighted- average interest rate of 4.7% (1) Stable Cash Flow Yields and Consistent Distribution Income Growth • 27 consecutive years of distribution growth throughout business cycles (1) As of December 31, 2025
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6© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Operational DCF and Adjusted CFFO per Unit (1) Financial Crisis Oil Price Collapse COVID-19 Pandemic History of Cash Flow per Unit Durability A Track Record of Resilience Source: EPD (1) For a definition, please see Appendix. (1) (1) $3.61 $3.98 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Operational DCF per Unit Adjusted CFFO per Unit
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7© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com $3.6 $3.8 $3.9 $4.1 $4.2 $4.4 $4.5 $4.8 $5.0 $2.9 $3.9 $4.2 $3.0 $1.8 $1.6 $2.9 $3.9 $4.4 2017 2018 2019 2020 2021 2022 2023 2024 2025 Capital Returned to Unitholders Growth Capital Expenditures Responsible, Strategic Growth Returning Capital & Reinvesting in the Business $5.0 Billion of Capital Returned to Unitholders in the Form of Distributions & Buybacks for 2025 Capital Returned to Unitholders (1) Capital Returned to Unitholders represents cash distributions to common unitholders and distribution equivalent rights and common unit repurchases for the applicable period. (2) Represents organic capital spending, excludes acquisitions (1) (2) Growth Capex
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8© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com 7.9 Bcf/d 4.0 4.5 5.0 5.5 6.0 6.5 7.0 7.5 8.0 2021 2022 2023 2024 2025 Natural Gas Processing Plant Inlet Volume Equivalent Pipeline Transportation Volume (1) Total Marine Terminal VolumesNGL Fractionation Volume 10% CAGR 8% CAGR 8% CAGR 8% CAGR Note: These selected volume statistics reflect volumes for assets owned by consolidated entities on a 100% basis and volumes for assets owned by unconsolidated affiliates net to Enterprise's interest. (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. Strategic Investment Drives Value Chain Growth Bcf/d MBPD MBPDMBPD RecordRecord Record 1.7 MMBPD 1,000 1,100 1,200 1,300 1,400 1,500 1,600 1,700 1,800 2021 2022 2023 2024 2025 13.7 MMBPD 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000 2021 2022 2023 2024 2025 2.1 MMBPD 1,000 1,200 1,400 1,600 1,800 2,000 2,200 2,400 2021 2022 2023 2024 2025 RECORD RECORD RECORD
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9© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Growth Capital Expenditures $4.8B of Major Capital Projects Under Construction (1) Highlighted Major Capital Projects (1) (1) Major Capital Projects Under Construction: $4.8 billion represents the total project value of major projects under construction (those that are not yet in-service) and includes growth projects of significance in terms of relative capital cost or commercial strategy. The table above includes a selection of highlighted projects. Forecast In-service Permian Basin Gathering & Treating Delaware Basin & Midland Basin Natural Gas Gathering, Compression & Treating 2026 - 2027 Mentone West 2 300 MMcf/d Gas Processing Plant in Permian (Delaware) 1Q 26 Athena 300 MMcf/d Gas Processing Plant in Permian (Midland) 4Q 26 Bahia Expansion & Extension +400 MBPD Expansion and 92-mile extension of Bahia Pipeline to Eddy County, NM 4Q 27 Neches River Terminal (“NRT”) Phase 2 “Flex” Ethane & Propane Export Terminal in Orange County, TX 1H 26 EHT LPG Expansion +300 MBPD Expansion of LPG (Propane & Butane) Loading Capacity at Enterprise Hydrocarbons Terminal (“EHT”) YE 2026 $1.0 $1.5 $2.0 $2.5 $3.0 $3.5 $4.0 2026 2027 $ Billions Forecasted Annual Growth Capex Range $2.9B $2.5B $2.0B $2.5B (2) Organic growth capital investments, net of proceeds from asset sales, are expected to be in the range of $1.9 - $2.3B in 2026, which includes estimated growth capital expenditures of ≈ $2.5 - $2.9B less ≈ $600MM of proceeds from asset sales (2) • Additional projects under construction include sour gas treater #5, acid gas injection well #3, additional Midland Basin gathering & treating, natural gas pipeline system expansions in Texas and Louisiana, and petchem pipeline extensions
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10© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Indicative Attribution of Total GOM 82% 74% 77% 78% 82% 5% 10% 6% 6% 5% 13% 16% 17% 16% 13% $0 $2 $4 $6 $8 $10 $12 2021 2022 2023 2024 2025 Gross Operating Margin in $Billions Fee-Based Commodity Price-Based Differential-Based $9.4B $10.0B Total gross operating margin is a Non-GAAP measure. For a reconciliation of these amounts to their nearest GAAP counterparts, see “Non-GAAP Financial Measures” on our website. The amounts above are adjusted to exclude non-cash MTM results for the respective periods. $8.6B $9.3B $10.0B
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11© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Indicative Attribution of Segment GOM Select Businesses as of Year-End 2025 $44 $111 $100 $116 $94 $107 $394 $442 $415 $273 $63 $283 $342 $299 $179 $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $1.20 $1.40 $1.60 $1.80 $0 $75 $150 $225 $300 $375 $450 $525 2021 2022 2023 2024 2025 Price Spread GOM in $Millions Fee Non-Fee Spread RBOB vs Butane ($/Gal) Octane Enhancement, HPIB, iBDH GOM & Related Spreads (3) 26% 21% 14% 23% 27% $493 $405 $449 $432 $442 $204 $54 $83 $16 $12 $798 $564 $584 $506 $458 $101 $105 $51 $58 $4 $0.00 $0.05 $0.10 $0.15 $0.20 $0.25 $0.30 $0.35 $0.40 $0.45 $0 $100 $200 $300 $400 $500 $600 $700 $800 $900 2021 2022 2023 2024 2025 Price Spread GOM in $Millions Fee Upside to Fee Non-Fee Spread PGP vs RGP ($/Lb) Propylene Activities GOM & Related Spreads (2) $194 $365 $448 $530 $564 $43 $535 $202 $214 $202 $95 $166 $87 $215 $197 $332 $1,066 $737 $959 $965 $0.00 $0.10 $0.20 $0.30 $0.40 $0.50 $0.60 $0 $200 $400 $600 $800 $1,000 $1,200 2021 2022 2023 2024 2025 Price Spread GOM in $Millions Natural Gas Processing GOM Fee POP & POL Keepwhole Indicative Processing Spreads ($/Gal) (1) The above figures exclude MTM results for the segments. (1) Contracts and commercial arrangements in Natural Gas Processing are structured as either fee-based, commodity-based or a combination of the two. Our commodity-based contracts include keepwhole, margin-band, percent-of-liquids (POL), percent-of-proceeds (POP) and contracts featuring a combination of commodity and fee-based terms. In February 2022, we completed the acquisition of Navitas Midstream (thereafter referred to as our “Midland Basin” assets). (2) Contracts and commercial arrangements in Propylene Activities are primarily structured as fee-based tolling contracts. The majority of our legacy margin-based contracts at our propylene splitters, which contained exposure to the Refinery Grade Propylene – Polymer Grade Propylene spread were converted to fee-based processing agreements by the end of the first quarter of 2025. Reactor-based assets are subject to scheduled turnarounds and plant maintenance. (3) Contracts and commercial arrangements in octane enhancement, HPIB, and iBDH are structured as fee-based tolling contracts and product sales with price spread based margins. Octane enhancement capacity is approx. 20 MBPD with relevant price spreads being Normal Butane to RBOB and RBOB to MTBE. Reactor-based assets are subject to scheduled turnarounds and plant maintenance.
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Segment Gross Operating Margin Variance 4Q 2025 vs. 4Q 2024
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13© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Total GOM Bridge by Segment 4Q 2025 vs. 4Q 2024 $2,628 ($7) $49 $9 $2,737 ($64) $122 4Q 2024 GOM NGL Segment Crude Oil Segment Natural Gas Segment Petrochemicals & Ref. Products Segment Net Adj. for Shipper Make-up Rights 4Q 2025 GOM $0 $500 $1,000 $1,500 $2,000 $2,500 The following slides summarize the primary drivers for changes in gross operating margin for each segment between 4Q 2025 and 4Q 2024. Total gross operating margin is a Non-GAAP measure. For a reconciliation of these amounts to their nearest GAAP counterparts, see “Non-GAAP Financial Measures” on our website. GOM Bridge$ in MMs
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14© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com NGL Segment 4Q 2025 vs. 4Q 2024 $1,548 ($51) ($42) ($1) $29 $23 $18 $17 $1,541 4Q 2024 GOM EHT NGL Marketing (excl. MTM) Mont Belvieu Area NGL Fractionation Complex Eastern Ethane Pipelines Permian Basin & Rocky Mountain NGL Pipelines Morgan's Point and Neches River Export Terminals Other 4Q 2025 GOM $0 $200 $400 $600 $800 $1,000 $1,200 $1,400 $1,600 Details: • MTM activity resulted in a gain of $2MM in both 4Q 2025 and 4Q 2024 • EHT GOM decreased primarily due to lower average loading fees largely due to the re-contracting of a legacy agreement in the first half of 2025 • NGL marketing activities (excluding MTM) GOM decreased due to lower average sales margins primarily related to elevated spot loading rates on export cargos in the prior period, partially offset by higher sales volumes • Mont Belvieu area NGL Fractionation Complex GOM decreased primarily due to higher operating costs and lower ancillary service revenues, partially offset by a 158 MBPD increase in fractionation volumes and higher fees • Eastern Ethane Pipelines GOM increased primarily due to a 79 MBPD increase in transportation volumes and higher other revenues • Permian Basin and Rocky Mountain NGL pipelines (MAPL, Seminole, Chaparral and Shin Oak) GOM increased primarily due to lower operating costs and higher other revenues • Morgan’s Point and Neches River Terminals GOM increased primarily due to a combined 94 MBPD increase in ethane export volumes; the first phase of the Neches River Terminal was placed in service in July 2025 GOM Bridge$ in MMs
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15© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Crude Oil Segment 4Q 2025 vs. 4Q 2024 $417 ($5) ($65) $6 $353 4Q 2024 GOM MTM Change Texas Crude Oil Pipelines, Related Terminals & Marketing (excl. Seaway and MTM) Other 4Q 2025 GOM $0 $50 $100 $150 $200 $250 $300 $350 $400 $450 Details: • MTM activity resulted in a loss of $1MM in 4Q 2025 compared to a gain of $4MM in 4Q 2024 • Texas crude oil pipelines, related terminals and marketing activities (excluding Seaway and MTM) GOM decreased primarily due to lower average sales margins and lower transportation-related revenues, partially offset by a combined 20 MBPD, net to our interest, increase in crude oil transportation volumes GOM Bridge$ in MMs
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16© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Natural Gas Segment 4Q 2025 vs. 4Q 2024 Details: • MTM activity resulted in a gain of $5MM in 4Q 2025 compared to a gain of $3MM in 4Q 2024 • Natural gas marketing activities (excluding MTM) GOM increased primarily due to higher average sales margins • Permian Basin Gathering Systems (Delaware Basin and Midland Basin) GOM increased primarily due to a 641 BBtus/d increase in gathering volumes, higher gathering fees, and higher treating and other revenues • Texas Intrastate System GOM increased primarily due to higher capacity reservation fees, other revenues, and higher transportation fees • Acadian Gas System GOM increased primarily due to a 358 BBtus/d increase in transportation volumes and lower operating costs $323 $2 $50 $26 $23 $7 $14 $445 4Q 2024 GOM MTM Change Natural Gas Marketing (excl. MTM) Permian Basin Gathering Systems Texas Intrastate System Acadian Gas System Other 4Q 2025 GOM $0 $50 $100 $150 $200 $250 $300 $350 $400 $450 $500 GOM Bridge$ in MMs
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17© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Petrochemical & Refined Products Segment 4Q 2025 vs. 4Q 2024 Details: • MTM activity resulted in a gain of $2MM in 4Q 2025 compared to an immaterial loss in 4Q 2024 • Refined products pipelines and related activities (excluding MTM) GOM increased 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 (excluding MTM) GOM increased primarily due to higher propylene sales volumes and higher average sales margins $348 $2 $33 $15 ($1) $397 4Q 2024 GOM MTM Change Refined Products Pipelines & Related Activities (excl. MTM) Propylene Production & Related Activities (excl. MTM) Other 4Q 2025 GOM $0 $50 $100 $150 $200 $250 $300 $350 $400 $450 GOM Bridge$ in MMs
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Segment Gross Operating Margin Variance 4Q 2025 vs. 3Q 2025
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19© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Total GOM Bridge by Segment 4Q 2025 vs. 3Q 2025 $2,385 $238 ($18) $106 $27 ($1) $2,737 3Q 2025 GOM NGL Segment Crude Oil Segment Natural Gas Segment Petrochemicals & Ref. Products Segment Net Adj. for Shipper Make-up Rights 4Q 2025 GOM $0 $500 $1,000 $1,500 $2,000 $2,500 The following slides summarize the primary drivers for changes in gross operating margin for each segment between 4Q 2025 and 3Q 2025. Total gross operating margin is a Non-GAAP measure. For a reconciliation of these amounts to their nearest GAAP counterparts, see “Non-GAAP Financial Measures” on our website. GOM Bridge$ in MMs
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20© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com NGL Segment 4Q 2025 vs. 3Q 2025 $1,303 ($14) $95 $36 $34 $17 $16 $14 $11 $8 $21 $1,541 3Q 2025 GOM MTM Change NGL Marketing (excl. MTM) Mont Belvieu Area NGL Fractionation Complex Permian Basin & Rocky Mountain NGL Pipelines Eastern Ethane Pipelines Dixie Pipeline and Related Terminals Permian Basin Processing Facilities Morgan's Point and Neches River Export Terminals Mont Belvieu Area Storage Complex Other 4Q 2025 GOM $0 $200 $400 $600 $800 $1,000 $1,200 $1,400 $1,600 GOM Bridge Details: • MTM activity resulted in a gain of $2 MM in 4Q 2025 compared to a gain of $16MM in 3Q 2025 • NGL marketing activities (excluding MTM) GOM increased primarily due to higher average sales margins and higher sales volumes • Mont Belvieu area NGL fractionation complex GOM increased primarily due to a 210 MBPD increase in fractionation volumes, part ially offset by lower ancillary services revenues; Frac 14 was placed into service during 4Q 2025 • Permian Basin and Rocky Mountain NGL pipelines (MAPL, Seminole, Chaparral and Shin Oak) GOM increased primarily due to lower operating costs, a 39 MBPD increase in transportation volumes, and higher average transportation fees • Eastern Ethane Pipelines GOM increased primarily due to higher other revenues, partially offset by lower transportation reven ues • Dixie Pipeline and related terminals GOM increased primarily due to a 40 MBPD increase in transportation volumes and higher loading and other fee revenues • Permian Basin processing facilities (Delaware Basin and Midland Basin) GOM increased primarily due to a combined 8 MBPD incre ase in equity NGL-equivalent production volumes and lower operating costs • Morgan’s Point and Neches River Terminals GOM increased primarily due to a combined 66 MBPD increase in ethane export volumes, partially offset by higher operating costs; we began initial service at the Neches River export facility in July 2025 • Mont Belvieu area storage complex GOM increased primarily due to higher storage revenues and lower operating costs $ in MMs
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21© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Crude Oil Segment 4Q 2025 vs. 3Q 2025 Details: • MTM activity resulted in a loss of $1MM in 4Q 2025 compared to a loss of $6MM in 3Q 2025 • EHT GOM increased primarily due to lower operating costs • Texas crude oil pipelines, related terminals and marketing activities (excluding Seaway and MTM) GOM decreased primarily due to lower average sales margins and lower transportation-related revenues, partially offset by lower operating costs and higher sales volumes $371 $5 $2 ($29) $4 $353 3Q 2025 GOM MTM Change EHT - Crude Texas Crude Oil Pipelines, Related Terminals & Marketing (excl. Seaway and MTM) Other 4Q 2025 GOM $0 $50 $100 $150 $200 $250 $300 $350 $400 $450 GOM Bridge$ in MMs
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22© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Natural Gas Segment 4Q 2025 vs. 3Q 2025 $339 $45 $27 $10 $9 $7 $6 $2 $445 3Q 2025 GOM MTM Change Natural Gas Marketing (excl. MTM) Rockies Gathering Systems Texas Intrastate System Acadian Gas System Permian Basin Gathering Systems Other 4Q 2025 GOM $0 $50 $100 $150 $200 $250 $300 $350 $400 $450 $500 Details: • MTM activity resulted in a gain of $5MM in 4Q 2025 compared to a loss of $40MM in 3Q 2025 • Natural gas marketing activities (excluding MTM) GOM increased primarily due to higher average sales margins • Rockies Gathering Systems (Jonah, Piceance and San Juan) GOM increased primarily due to lower operating costs and a combined 45 BBtus/d increase in gathering volumes • Texas Intrastate System GOM increased primarily due to higher average transportation fees, partially offset by a 304 BBtus/d decrease in transportation volumes • Acadian Gas System GOM increased primarily due to lower operating costs and a 149 BBtus/d increase in transportation volumes • Permian Basin Gathering Systems (Delaware Basin and Midland Basin) GOM increased primarily due to higher average gathering fees and higher other fee revenues, partially offset by higher operating costs GOM Bridge$ in MMs
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23© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Petrochemical & Ref. Products Segment 4Q 2025 vs. 3Q 2025 Details: • MTM activity resulted in a gain of $2MM in 4Q 2025 compared to a loss of $4MM in 3Q 2025 • TE Products Pipeline System GOM increased primarily due to a 29 MBPD increase in NGL transportation volumes, higher other revenues, and lower operating costs • Mont Belvieu area propylene production facilities GOM increased primarily due to higher average propylene sales margins and higher other revenues • Refined products marketing activities (excluding MTM) GOM decreased primarily due to lower average sales margins • Octane enhancement and related plant operations (excluding MTM) GOM decreased primarily due to lower average sales margins and lower sales volumes, partially offset by higher deficiency revenues • TW Products System GOM decreased primarily due to lower sales volumes and lower average sales margins, partially offset by lower operating costs $370 $6 $33 $12 ($15) ($6) ($3) $397 3Q 2025 GOM MTM Change TE Products Pipeline System Mont Belvieu Area Propylene Production Facilities Refined Products Marketing (excl. MTM) Octane Enhancement & Related Plant Operations (excl. MTM) TW Products System 4Q 2025 GOM $0 $50 $100 $150 $200 $250 $300 $350 $400 $450 GOM Bridge$ in MMs
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24© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Indicative Attribution of GOM • Slides 10 and 11 attribute gross operating margin (GOM) among various applicable business activities. Most activities fit easily into one category; however, the classification of certain activities involves an element of subjectivity. GOM classifications represent what we currently believe is the most logical fit of our business activities into each category, based on the underlying fee or pricing characteristics applicable thereto. • These classifications may be subject to change in the event that management’s estimates or assumptions underlying such classifications are revised or updated. In addition, our attribution of GOM into the categories may not be comparable to similar classifications by other companies because such companies may use different estimates and assumptions than we do in assigning such categories or otherwise calculating such attributions. • Categories of GOM: • Fee-based: Pipeline transportation fees and tariffs, NGL and propylene fractionation fees, storage capacity reservation and throughput fees, export terminal fees, marine and trucking fees, fee-based natural gas processing arrangements, isomerization and dehydrogenation fees, demand and deficiency fees, and similar activities that are predominantly fee-oriented. • Commodity-based: percentage-of-liquids and percentage-of-proceeds natural gas processing arrangements, certain condensate sales, gathering revenues on our San Juan natural gas pipeline system, and similar activities that have commodity price exposure • Differential-based: certain business activities where earnings are generated based on price differentials or spreads between locations, time periods and products in excess of any related fees, tariffs and other expenses.
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25© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Definitions Net Cash Flow Provided by Operating Activities (“CFFO”) represents the GAAP financial measure “Net cash flow provided by operating activities”. Operational DCF is Distributable Cash Flow (“DCF”) excluding the impact of proceeds from asset sales and other matters and monetization of interest rate derivative instruments. Operational DCF per Unit represents DCF excluding proceeds from asset sales and other matters and monetization of interest rate derivative instruments for a period divided by the average number of fully diluted common units outstanding for that period. Adjusted CFFO is CFFO before the net effect of changes in operating accounts (working capital). Adjusted CFFO per Unit is Adjusted CFFO divided by the average number of fully diluted common units outstanding for that period. Adjusted CFFO Payout Ratio is calculated as trailing 12 months distributions + distribution equivalent rights + buybacks divided by the trailing 12 months Adjusted CFFO. Adjusted EBITDA is earnings before interest, taxes, depreciation and amortization (“EBITDA”) adjusted for cash distributions received from unconsolidated affiliates, equity in income of unconsolidated affiliates, non-cash impairment charges, changes in the fair market value of commodity derivative instruments and net gains/losses attributable to asset sales and related matters. Additionally, amortization of major maintenance costs for reaction-based plants is excluded as this is a component of Adjusted EBITDA. Leverage Ratio is defined as net debt adjusted for equity credit in junior subordinated notes (hybrids) divided by Adjusted EBITDA.