Slides
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NYSE: EPD First Quarter 2025 Earnings Support Slides April 29, 2025
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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 first quarter of 2025 and our SEC Form 10-Q (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 • $58 Billion (“B”) of capital returned to equity investors via LP distributions and common unit buybacks, since IPO • Distributions: $0.535/unit for 1Q 2025, a 3.9% increase over 1Q 2024 • Buybacks: $60 million (“MM”), 1.8MM common units, of repurchases in 1Q 2025 • $239 MM, 8MM common units, for the trailing 12 months ended 1Q 2025 (“TTM 1Q 2025”) • Unitholder Reinvestment & Employee Support: our DRIP (1) and EUPP (2) programs purchased a combined 1.1MM and 6MM common units in 1Q 2025 and TTM 1Q 2025 respectively, on the open market • Adjusted CFFO Payout Ratio (3) : 56% TTM 1Q 2025 (1) Distribution Reinvestment Plan (“DRIP”) (2) Employee Unit Purchase Plan (“EUPP”) (3) See definitions Maintain and Protect Balance Sheet • Leverage Ratio (3) : 3.1x TTM 1Q 2025; target ratio of 3.0x (+/– 0.25x) • Liquidity: $3.6B comprised of available credit capacity and unrestricted cash as of March 31, 2025 Capital Expenditures • Growth Capital Expenditures Range: $4.0B to $4.5B in 2025; $2.0B to $2.5B in 2026 • Sustaining Capital Expenditures: ≈$525MM in 2025
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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 an 18-year average maturity (1) , 96% of portfolio is fixed rate (1) , weighted- average interest rate of 4.7% (1) Stable Cash Flow Yields and Consistent Distribution Income Growth • 26 consecutive years of distribution growth throughout business cycles (1) As of March 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) $3.62 $3.92 $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 TTM 1Q 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 $4.8 $2.9 $3.9 $4.2 $3.0 $1.8 $1.6 $2.9 $3.9 $4.0 2017 2018 2019 2020 2021 2022 2023 2024 TTM 1Q 2025 Capital Returned to Unitholders Growth Capital Expenditures Responsible, Strategic Growth Returning Capital & Reinvesting in the Business $4.8 Billion of Capital Returned to Unitholders in the Form of Distributions & Buybacks for TTM 1Q 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 7.7 Bcf/d 4.0 4.5 5.0 5.5 6.0 6.5 7.0 7.5 8.0 2021 2022 2023 2024 1Q 2025 Equivalent Pipeline Transportation Volume (1) Total Marine Terminal VolumesNGL Fractionation Volume Natural Gas Processing Plant Inlet Volume 9% CAGR 8% CAGR 8% CAGR 7% CAGR Note:These selected volume statistics reflect volumes 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 13.2 MMBPD 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000 2021 2022 2023 2024 1Q 2025 1.6 MMBPD 900 1,000 1,100 1,200 1,300 1,400 1,500 1,600 1,700 2021 2022 2023 2024 1Q 2025 2.0 MMBPD 1,000 1,200 1,400 1,600 1,800 2,000 2,200 2021 2022 2023 2024 1Q 2025
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9© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Growth Capital Expenditures $7.6B of Major Capital Projects Under Construction (1) Highlighted Major Capital Projects (1) (1) Major Capital Projects Under Construction: $7.6 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. Forecasted Annual Growth Capex Range $1.0 $1.5 $2.0 $2.5 $3.0 $3.5 $4.0 $4.5 $5.0 2025 2026 $ Billions $4.5B $4.0B $2.5B $2.0B • $7.6B of major capital projects under construction with growth concentrated in our core NGL value chain; $6B of these projects are slated to come online in 2025 • Incremental $700MM+ of backlog projects under development included in 2025-2026 forecasted spend range below • Additional projects under construction and identified backlog are largely related to successful commercialization of our Permian Basin gathering, processing & treating footprint Fcst. In-Service Permian Basin Gathering & Treating Delaware Basin & Midland Basin Natural Gas Gathering, Compression & Treating 2025 & 2026 Orion 300 MMcf/d Gas Processing Plant in Permian (Midland) 3Q 25 Mentone West 300 MMcf/d Gas Processing Plant in Permian (Delaware) 3Q 25 Mentone West 2 300 MMcf/d Gas Processing Plant in Permian (Delaware) 1H 26 Bahia Pipeline 600 MBPD Mixed NGL (“Y-Grade”) Pipeline 4Q 25 Fractionator 14 150 MBPD Nameplate Capacity Fractionator in Mont Belvieu 3Q 25 Neches River Terminal (“NRT”) New Build Ethane & Propane Export Terminal in Orange County, TX 3Q 25 & 1H 26 EHT LPG Expansion +300 MBPD Expansion of LPG (Propane & Butane) Loading Capacity at Enterprise Hydrocarbons Terminal (“EHT”) YE 2026 Morgan’s Point Enhancements 900 MBbl Refrigerated Ethane Tank Enabling Higher Loading Rates at Morgan’s Point Ethane Terminal 4Q 25
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10© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Indicative Attribution of Total GOM 82% 74% 77% 78% 80% 5% 10% 6% 6% 6% 13% 16% 17% 16% 14% $0.0 $2.0 $4.0 $6.0 $8.0 $10.0 $12.0 2021 2022 2023 2024 1Q 2025 Total GOM in $Billions Fee-Based Commodity Price-Based Differential-Based $9.4B $10.0B $8.6B $9.3B $2.4B Note: Total GOM 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.
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11© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com $44 $111 $100 $116 $18 $107 $394 $442 $415 $59 $63 $283 $342 $299 $41 $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 1Q 2025 Price Spread GOM in $Millions Fee Non-Fee Spread RBOB vs Butane ($/Gal) Octane Enhancement, HPIB, iBDH GOM & Related Spreads(3) Indicative Attribution of Segment GOM Select Businesses as of Year-To-Date 2025 26% 21% 14% 23% 27%$493 $405 $449 $432 $85 $204 $54 $83 $16 $798 $564 $583 $506 $101 $105 $51 $58 $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 1Q 2025 Price Spread GOM in $Millions Fee Upside to Fee Non-Fee Spread PGP vs RGP ($/Lb) Propylene Activities GOM & Related Spreads(2) 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 primarly 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. $194 $365 $448 $530 $140 $43 $535 $202 $214 $59 $95 $166 $87 $215 $48 $332 $1,066 $737 $959 $247 $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 1Q 2025 Price Spread GOM in $Millions Natural Gas Processing GOM Fee POP & POL Keepwhole Indicative Processing Spreads ($/Gal) (1)
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Segment Gross Operating Margin Variance 1Q 2025 vs. 1Q 2024
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13© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Total GOM Bridge by Segment 1Q 2025 vs. 1Q 2024 $2,490 $78 ($37) $45 ($129) ($16) $2,431 1Q 2024 GOM NGL Segment Crude Oil Segment Natural Gas Segment Petrochemicals & Ref. Products Segment Net Adj. for Shipper Make-up Rights 1Q 2025 GOM $0 $500 $1,000 $1,500 $2,000 $2,500 The following slides summarize the primary drivers for changes in gross operating margin for each segment between 1Q 2025 and 1Q 2024. Total gross operating margin is a Non-GAAP measure. For a reconciliation of these amounts to their nearest GAAP counterparts, see “Non-GAAP Financial Measures” on our website GOM Bridge$ in MMs
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14© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com NGL Segment 1Q 2025 vs. 1Q 2024 $ in MMs $1,340 $2 $46 $22 $19 $16 $12 $9 ($25) ($15) ($7) ($1) $1,418 1Q 2024 GOM MTM Change Permian Basin Processing Facilities Permian Basin & Rocky Mountain NGL Pipelines Morgan's Point Ethane Export Terminal Dixie Pipeline and Related Terminals Eastern Ethane Pipelines South Texas NGL Pipeline System NGL Marketing (excl. MTM) Mont Belvieu Area NGL Fractionation Complex Rockies Processing Facilities Other 1Q 2025 GOM $0 $200 $400 $600 $800 $1,000 $1,200 $1,400 $1,600 Details: • MTM activity resulted in a loss of $5MM in 1Q 2025 compared to a loss of $7MM in 1Q 2024 • Permian Basin Processing Facilities (Delaware Basin and Midland Basin) GOM increased primarily due to higher processing volumes and higher equity NGL- equivalent production volumes. In March 2024, we began service at the Leonidas plant in the Midland Basin and the Mentone 3 plant in the Delaware Basin. • Permian Basin and Rocky Mountain NGL pipelines (MAPL, Seminole, Chaparral and Shin Oak) GOM increased primarily due to a 74 MBPD increase in transportation volumes • Morgan’s Point Ethane Export Terminal GOM increased primarily due to a 68 MBPD increase in export volumes • Dixie Pipeline and related terminals GOM increased primarily due to higher loading, transportation, and other revenues • Eastern Ethane Pipelines GOM increased primarily due to higher transportation revenues • South Texas NGL Pipeline System GOM increased primarily due to higher transportation-related revenues and lower operating costs • NGL marketing activities (excluding MTM) GOM decreased primarily due to lower average sales margins, 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 • Rockies Processing Facilities (Pioneer, Meeker and Chaco) GOM decreased primarily due to lower average processing margins, including the impact of hedging GOM Bridge
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15© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Crude Oil Segment 1Q 2025 vs. 1Q 2024 $411 ($6) ($31) $374 1Q 2024 GOM MTM Change Crude Oil Assets & Marketing (excl. MTM) 1Q 2025 GOM $0 $50 $100 $150 $200 $250 $300 $350 $400 $450 Details: • MTM activity resulted in a loss of $2MM in 1Q 2025 compared to a gain of $4MM in 1Q 2024 • Crude oil assets and marketing (excluding MTM) GOM decreased primarily due to lower sales volumes and lower average sales margins, partially offset by an increase in storage and other revenues at EHT GOM Bridge$ in MMs
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16© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Natural Gas Segment 1Q 2025 vs. 1Q 2024 Details: • MTM activity resulted in a loss of $33MM in 1Q 2025 compared to a loss of $2MM in 1Q 2024 • Permian Basin Gathering Systems (Delaware Basin and Midland Basin) GOM increased primarily due to higher treating and other revenues and a combined 1.3 TBtus/d increase in gathering volumes, partially offset by higher operating costs. In October 2024, we expanded our Delaware Basin Gathering System by acquiring the Pinon Midstream sour gas gathering and treating system. • Texas Intrastate System GOM increased primarily due to higher transportation-related revenues • Natural gas marketing activities (excluding MTM) GOM increased primarily due to higher average sales margins $312 ($31) $37 $27 $16 ($4) $357 1Q 2024 GOM MTM Change Permian Basin Gathering Systems Texas Intrastate System Natural Gas Marketing (excl. MTM) Other 1Q 2025 GOM $0 $50 $100 $150 $200 $250 $300 $350 $400 GOM Bridge$ in MMs
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17© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Petrochemical & Refined Products Segment 1Q 2025 vs. 1Q 2024 Details: • MTM activity resulted in a loss of $2MM in 1Q 2025 compared to a gain of $1MM in 1Q 2024 • Octane enhancement and related plant operations GOM decreased primarily due to lower average sales margins and lower deficiency revenues • Propylene production and related activities (excluding MTM) GOM decreased primarily due to lower average propylene sales margins as a result of lower Refinery Grade Propylene to Polymer Grade Propylene spreads. The majority of our legacy margin-based processing contracts at our propylene splitters, which contained exposure to this spread, were converted to fee-based processing agreements by the end of 1Q 2025. • Ethylene exports and related activities GOM decreased primarily due to lower deficiency revenues on our ethylene pipelines and a 25 MBPD decrease in ethylene export volumes • Refined products pipelines and related activities (excluding MTM) GOM increased primarily due to higher transportation volumes and revenues, including a $13 million contribution from the TW Products System that was commissioned in phases beginning in March 2024 through October 2024 $444 ($3) ($83) ($51) ($28) $35 $1 $315 1Q 2024 GOM MTM Change Octane Enhancement & Related Plant Operations Propylene Production & Related Activities (excl. MTM) Ethylene Exports & Related Activities Refined Products Pipelines & Related Activites (excl. MTM) Other 1Q 2025 GOM $0 $50 $100 $150 $200 $250 $300 $350 $400 $450 $500 GOM Bridge$ in MMs
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Segment Gross Operating Margin Variance 1Q 2025 vs. 4Q 2024
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19© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Total GOM Bridge by Segment 1Q 2025 vs. 4Q 2024 $2,628 ($130) ($43) $34 ($33) ($25) $2,431 4Q 2024 GOM NGL Segment Crude Oil Segment Natural Gas Segment Petrochemicals & Ref. Products Segment Net Adj. for Shipper Make-up Rights 1Q 2025 GOM $0 $500 $1,000 $1,500 $2,000 $2,500 The following slides summarize the primary drivers for changes in gross operating margin for each segment between 1Q 2025 and 4Q 2024. Total gross operating margin is a Non-GAAP measure. For a reconciliation of these amounts to their nearest GAAP counterparts, see “Non-GAAP Financial Measures” on our website GOM Bridge$ in MMs
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20© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com NGL Segment 1Q 2025 vs. 4Q 2024 $ in MMs $1,548 ($7) ($102) ($18) ($17) ($13) $19 $12 ($4) $1,418 4Q 2024 GOM MTM Change NGL Marketing (excl. MTM) Permian Basin Processing Facilities Mont Belvieu Area NGL Fractionation Complex Permian Basin & Rocky Mountain NGL Pipelines Rockies Processing Facilities Dixie Pipeline & Related Terminals Other 1Q 2025 GOM $0 $200 $400 $600 $800 $1,000 $1,200 $1,400 $1,600 GOM Bridge Details: • MTM activity resulted in a loss of $5MM in 1Q 2025 compared to a gain of $2MM in 4Q 2024 • NGL marketing activities (excluding MTM) GOM decreased primarily due to lower average sales margins • Permian Basin Processing Facilities (Delaware Basin and Midland Basin) GOM decreased primarily due to lower average processin g margins, including the impact of hedging • Mont Belvieu area NGL Fractionation Complex GOM decreased primarily due to higher operating costs, and a 13 MBPD decrease in fractionation volumes • Permian Basin and Rocky Mountain NGL pipelines (MAPL, Seminole, Chaparral and Shin Oak) GOM decreased primarily due to lower transportation volumes • Rockies Processing Facilities (Pioneer, Meeker and Chaco) GOM increased primarily due to lower operating costs and higher ave rage processing margins, including the impact of hedging activities • Dixie Pipeline and related terminals GOM increased primarily due to a 30 MBPD increase in transportation volumes and higher loading revenues
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21© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Crude Oil Segment 1Q 2025 vs. 4Q 2024 Details: • MTM activity resulted in a loss of $2MM in 1Q 2025 compared to a gain of $4MM in 4Q 2024 • Crude oil assets and marketing (excluding MTM) GOM decreased primarily due to lower deficiency fee and other revenues, lower average sales margins, and lower sales volumes, partially offset by an increase in crude oil transportation volumes $417 ($6) ($37) $374 4Q 2024 GOM MTM Change Crude Oil Assets & Marketing (excl. MTM) 1Q 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 1Q 2025 vs. 4Q 2024 $323 ($36) $41 $10 $9 $8 $2 $357 4Q 2024 GOM MTM Change Natural Gas Marketing (excl. MTM) Rockies Gathering Systems Permian Basin Gathering Systems Texas Intrastate System Other 1Q 2025 GOM $0 $50 $100 $150 $200 $250 $300 $350 $400 Details: • MTM activity resulted in a loss of $33MM in 1Q 2025 compared to a gain of $3MM in 4Q 2024 • Natural gas marketing activities (excluding MTM) GOM increased primarily due to higher average sales margins • Rockies Gathering Systems (Jonah, Piceance and San Juan) GOM increased primarily due to higher average gathering fees and lower operating costs • Permian Basin Gathering Systems (Delaware Basin and Midland Basin) GOM increased primarily due to higher average gathering fees • Texas Intrastate System GOM increased primarily due to lower operating costs GOM Bridge$ in MMs
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23© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Petrochemical & Ref. Products Segment 1Q 2025 vs. 4Q 2024 Details: • MTM activity resulted in a loss of $2MM in 1Q 2025 compared to an immaterial loss in 4Q 2024 • Mont Belvieu area propylene production facilities (excluding MTM) GOM decreased primarily due to lower average propylene sales margins, partially offset by higher processing revenues • Ethylene exports and related activities GOM decreased primarily due to a 13 MBPD decrease in ethylene export volumes, lower deficiency fee revenues and a 36 MBPD decrease in ethylene pipeline transportation volumes • Octane enhancement and related plant operations GOM decreased primarily due to lower deficiency fee revenues and lower average sales margins, partially offset by lower operating costs and higher sales volumes • TE Products Pipeline System GOM increased primarily due to higher transportation volumes • Refined products marketing activities (excluding MTM) GOM increased primarily due to higher average sales margins $348 ($2) ($34) ($15) ($10) $26 $8 ($6) $315 4Q 2024 GOM MTM Change Mont Belvieu Area Propylene Production Facilities (excl. MTM) Ethylene Exports & Related Activities Octane Enhancement & Related Plant Operations TE Products Pipeline System Refined Products Marketing (excl. MTM) Other 1Q 2025 GOM $0 $50 $100 $150 $200 $250 $300 $350 $400 GOM Bridge$ 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.