Slides
Page 1
Enterprise Products Partners L.P. Investor Deck August 2026 NYSE : EPD
Page 2
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.
Page 3
3© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Why EPD? A-Rated Balance Sheet, 28 years of Distribution Growth, 6% Yield A Compelling Value Proposition Critical Energy Infrastructure Integrated Footprint with Geographic, Product and Market Diversification Provides Critical Energy Infrastructure Services Bringing Products to Market Attractive Returns Support Future Cash Flows Average Return on Invested Capital (1) 12% Over the Last 10 Years $6.5B Major Growth Capital Projects Under Construction Focused on Responsibly Returning Capital $65B Returned to Unitholders in Distributions & Buybacks Since IPO 28 Years of Consecutive Distribution Growth $1.7B Common Unit Repurchases (2) + History of Unitholder Alignment Through Actions & Ownership ≈33% of Common Units Owned by GP Management & Affiliates (2) Long-Term Focus Managing for Longevity & Durability Across Decades Setting the Standard for Balance Sheet Strength A- / A- / A3 Credit Rating 3.0x Leverage (1) for TTM 2Q 2026 4.7% Weighted-Average Cost of Debt (2) 97% Fixed Rate Debt (2) Note: ROIC for 2021, 2022, 2023, 2024 was 13%. (1) For a definition, see Appendix (2) As of June 30, 2026
Page 4
4© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Focusing on Value Creation for the Long-Term Commercial Strategy Build a reliable and resilient integrated U.S. midstream energy company to provide essential services to producers and consumers of natural gas, NGLs, crude oil, refined products and petrochemicals Invest in midstream energy infrastructure at attractive returns on capital Manage for long-term financial flexibility and balance sheet strength Responsibly return capital to investors Financial Objectives Grow cash flow per unit
Page 5
5© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com 1 Integrated Value Chain NGL Focused with Benefit of Diversification *Represents % of Total Segment Gross Operating Margin $10.8B TTM 2Q 2026 Total Segment Gross Operating Margin Crude Oil 14% Petchem & Refined Products 14% Simplified NGL Value Chain Separates NGLs from the natural gas stream Transports mixed NGLs to complexes for further processing Separates individual purity products like ethane, propane, butane and natural gasoline from the mixed NGL stream Large quantities of NGLs are stored in underground storage caverns Transports purity products to consuming markets and/or export infrastructure Marine Terminals / Exports Petchem & Wholesale Consumption Markets Natural Gas Processing Pipeline Transportation Fractionation Storage Pipeline Transportation Enterprise Function External Function Natural Gas 17% Natural Gas Liquids (“NGLs”) 55%
Page 6
6© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com 0.60 0.70 0.80 0.90 1.00 1.10 1.20 1.30 1.40 2019 2020 2021 2022 2023 2024 2025 TTM 2Q 2026 Unit Count Adj. CFFO/Unit Debt & Preferreds $0 $1 $2 $3 $4 $5 $6 2019 Authorization Oct 2025 Expansion Common Unit Buyback Program Utilization Remaining Capacity Responsible Long-Term Value Creation Note: “Unit Count” represents the total number of weighted-average fully diluted units or shares outstanding for the applicable period; "Adj. CFFO/Unit" is cash flow from operations, as adjusted for net changes in operating accounts, divided by the applicable "Unit Count”; "Debt & Preferreds" represents the sum of total debt principal (including amounts outstanding under credit facilities, commercial paper programs and other borrowing arrangements) and total lease liabilities as of the applicable period. Adj. CFFO/Unit +34.8% Debt & Preferreds +22.9% Unit Count -0.8% Balancing Cash Flow per Unit Growth with Capital Efficiency Expanding Buyback Program to Enhance Shareholder Return Potential $3 Billion Program Expansion $Billions $5 Billion $2 Billion
Page 7
7© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com + 2 Gas Processing Plants July 2025 + P1 Neches River Terminal July 2025 + Frac 14 October 2025 + Bahia NGL Pipeline December 2025 + 1 Gas Processing Plant February 2026 + P2 Neches River Terminal 2Q 2026 + 1 Gas Processing Plant 4Q 2026 + EHT LPG Export Expansion 4Q 2026 + Bahia Expansion & Extension 4Q 2027 + 2 Gas Processing Plants 2H 2027 + Frac 15 1Q 2028 + 2 Gas Processing Plants 3Q 2028, 1Q 2029 2026 Outlook Executing on NGL-focused infrastructure opportunities $2.9–$3.4B expected organic growth spending, net of $0.6B in proceeds from asset sales Continuing to prioritize return of capital and financial flexibility Expecting inflection point in excess cash flow available to allocate to unit buybacks & debt paydown Outlook Project Execution
Page 8
8© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com 2 2.5 3 3.5 4 4.5 2026 2027 $ Billions Growth Capital Expenditures $6.5B of Major Capital Projects Under Construction (1) Highlighted Major Capital Projects (1) (1) Major Capital Projects Under Construction: $6.5 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 & Power Generation 2026–2027 Athena 300 MMcf/d Gas Processing Plant in Permian (Midland) 4Q 26 Athena 2 300 MMcf/d Gas Processing Plant in Permian (Midland) 3Q 27 Midland Plant 11 300 MMcf/d Gas Processing Plant in Permian 1Q 29 Delaware Plant 12 300 MMcf/d Gas Processing Plant in Permian 4Q 27 Delaware Plant 13 300 MMcf/d Gas Processing Plant in Permian 3Q 28 Bahia Expansion & Extension +400 MBPD Expansion and 92-mile extension of Bahia Pipeline to Eddy County, NM 4Q 27 Fractionator 15 150 MBPD Nameplate Capacity Fractionator in Mont Belvieu 1Q 28 EHT LPG Expansion +300 MBPD Expansion of LPG (Propane & Butane) Loading Capacity at Enterprise Hydrocarbons Terminal (“EHT”) 4Q 26 Forecasted Annual Growth Capex Range $4.0B $3.5B $3.0B area (2) Organic growth capital investments, net of proceeds from asset sales, are expected to be in the range of $2.9–$3.4B in 2026, which includes estimated growth capital expenditures of ≈$3.5–$4.0B less ≈ $0.6B 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
Page 9
9© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com 0 200 400 600 800 1000 1200 1400 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 NGL Pipeline Vol, MBPD EPD Permian NGL Pipeline Volume(1) Navitas Acquisition Orion & Mentone West 1 Mentone West 2 & Athena (4Q 26) Athena 2 (3Q 27) Delaware Plant 12 (4Q 27) Delaware Plant 13 (3Q 28) Midland Plant 11 (1Q 29) 1 1 3 3 5 6 7 7 12 14 16 18 20 22 23 24 0 1 2 4 5 6 7 0 5 0 5 0 5 0 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 Processing Capacity, Bcf/d EPD Permian Gas Process Plant Capacity # of plants total capacity EPD Permian NGLs Plant Additions Benefit Downstream NGL Infrastructure Continued growth in EPD processing plant capacity driving NGL transportation volumes with ≈70% of EPD NGL pipeline volume coming from EPD G&P facilities (1) Forward projections include estimated NGL volume associated with announced additional gas plants and does not include growth in third-party volume. Navitas Acquisition Permian Inlet Volumes CAGR 2020–2029: 16% CAGR 2022–2029: 14% CAGR 2025 – 2029: 9%
Page 10
10© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Midland Basin Gathering & Processing Gas Gathering Assets Acquired from Occidental (1) Strategic acquisition to expand our Midland Basin footprint • $583MM purchase price; meaningful cash flow contributions beginning in 2027, expecting mid- teens return • ≈200 miles of gathering pipeline that support Occidental’s production activities • Long-term dedication of ≈73,000 acres across 4 counties • Additional G&P expansion opportunities with access to 1,000+ remaining drillable locations Midland Basin Supporting Midland Basin Production • New 300 MMcf/d Gas Processing Plant (“Athena”) is expected to be in-service by 4Q 2026 • With Athena, Enterprise will have the capability to process 2.2 Bcf/day of natural gas and extract 310 MBPD of NGLs in the Midland Basin in 4Q 2026 Newly Acquired Gas Pipelines Existing EPD Gas Pipelines Existing EPD Gas Plants (1) Acquisition closed in August 2025
Page 11
11© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Delaware Basin Sour Gas Infrastructure Treating & Acid Gas Injection Assets Acquired from Pinon Midstream (1) 3rd Party Upstream Hydrocarbon Extraction Dark Horse Treating Facility Removes CO2 and H2S Gathering Lines Class II Sequestration Wells Casing Designed for Safe & Reliable Operations CO2 and H2S Permanently Sequestered Treating & AGI Operations Sour Gas Gathering & Treating Gas Processing Transportation Fractionation Mixed NGLsGas Additional NGL Services Extending the Value Chain with Essential Services for Sour Gas Production • Eastern ⅓ of the Delaware Basin in Lea County, NM contains liquids-rich hydrocarbons that require H2S and CO2 treating (2) • Expanding capacity to from 270 MMcf/d to 450 MMcf/d by mid 2026 • Facility includes 2 active high-quality AGI wells, 18,000 feet deep • Project backlog includes further expansion of treating capacity and AGI wells, and related opportunities • Business is supported by fee-based contracts with long-term acreage dedications, including minimum volume commitments • Assets offer speed-to-market and flow assurance to producers in the region (1) Acquisition of Pinon Midstream closed in October 2024 (2) Sour natural gas production contains hydrogen sulfide (H2S) and carbon dioxide (CO2) commingled in the produced natural gas stream. Sour natural gas treating facilities use an amine process to isolate the H2S and CO2 (“acid gas”), then inject the treated acid gas (“TAG”) into wells where it is sequestered DELAWARE BASIN
Page 12
12© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Bahia Expansion & Extension Leveraging Economies of Scale BAHIA EXTENSION • Extend Bahia West 92 miles via the Cowboy Connector • Connections to Exxon Cowboy Processing Complex & multiple Enterprise-owned processing facilities in the Delaware Basin • Undivided Joint Interest in extension; Ownership Structure: Enterprise 30% / Exxon 70% EPD Assets Exxon Cowboy Processing Complex Cowboy Connector BAHIA EXPANSION • Increase capacity to 1,000 MBPD by adding pump stations • Brings Exxon production and 3rd party volumes on to Bahia • Undivided Joint Interest in Bahia; Ownership Structure: Enterprise 60% / Exxon 40% HOBBS AREA EPD NGL MARKET HUB MONT BELVIEU
Page 13
13© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com 0 300 600 900 1,200 1,500 LPG Today LPG Post- Expansions LPG Pre-Expansions LPG Post-Expansions 0 100 200 300 400 500 600 Ethylene Today Ethylene Post- Expansions Ethane Today Ethane Post- Expansions Ethylene Pre-Expansion Ethylene Post-Expansion Ethane Pre-Expansions Ethane Post-Expansions EPD Gulf Coast Export Expansions (1) 240 MBPD 540 MBPD 240 MBPD Dedicated Ethane Capacity 60 MBPD 180 MBPD Morgan’s Point Neches River Neches River Flex Morgan’s Point 300 MBPD Ethane- Capable Flex Capacity Morgan’s Point Morgan’s Point Flex Morgan’s Point Flex Morgan’s Point Morgan’s Point EHT EHT EHT Expansion Neches River Flex 1,135 MBPD Dedicated LPG Capacity 360 MBPD Propane- Capable Flex Capacity 1,495 MBPD 835 MBPD LPGEthylene & Ethane MBPD MBPD (1) Expansion projects portrayed in this slide have in-service dates ranging from 4Q 2024 through year-end 2026 Neches River Phase 2 Complete; EHT LPG Expansion 4Q26 In-service
Page 14
14© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com 80 85 90 95 100 105 110 115 120Bcf/d Dry Natural Gas 90 95 100 105 110 115 120 125 130 135Bcf/d Total Natural Gas 6.0 6.5 7.0 7.5 8.0 8.5 9.0 9.5MMBPD NGLs 10 11 12 13 14 15MMBPD Oil EPD U.S. Production Forecast April 2026 Update 2025: 13.5 MMBPD 2027: 13.9 (+0.4) MMBPD 2030: 14.4 (+0.9) MMBPD 14.5 MMBPD (2025 Forecast) 2025: 118.1 Bcf/d 2027: 123.8 (+5.7) Bcf/d 2030: 132.5 (+14.4) Bcf/d 130.8 Bcf/d (2025 Forecast) 2025: 8.0 MMBPD 2027: 8.5 (+0.5) MMBPD 2030: 9.0 (+1.0) MMBPD 9.1 MMBPD (2025 Forecast) 2025: 103.8 Bcf/d 2027: 108.7 (+4.9) Bcf/d 2030: 116.5 (+12.7) Bcf/d 114.9 Bcf/d (2025 Forecast) Growth to 2030 by Region Appalachia: +3.2 Bcf/d Haynesville: +6.8 Bcf/d Eagle Ford: +1.1 Bcf/d Permian: +5.2 Bcf/d Other*: -3.6 Bcf/d *Other decline of -3.6 Bcf/d primarily in legacy gas basins with vertical wells Source: EPD Fundamentals, April 2026
Page 15
15© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com 10 15 20 25 30Bcf/d Dry Natural Gas 15 20 25 30 35 40Bcf/d Total Natural Gas 2.0 2.5 3.0 3.5 4.0 4.5 5.0MMBPD NGLs 4.0 4.5 5.0 5.5 6.0 6.5 7.0 7.5 8.0MMBPD Oil EPD Permian Production Forecast April 2026: Permian Rich Gas & NGLS Growing 1.6x Faster than Crude +15% Growth 2025 to 2030 +24% Growth 2025 to 2030 (≈1.6x rate of Crude Growth) 23% Growth 2025 to 2030 (≈1.6x rate of Crude Growth) 23% Growth 2025 to 2030 2025: 6.5 MMBPD 2027: 7.1 (+0.6) MMBPD 2030: 7.5 (+1.0) MMBPD 7.6 MMBPD (2025 Forecast) 2025: 3.8 MMBPD 2027: 4.3 (+0.5) MMBPD 2030: 4.7 (+0.9) MMBPD 4.5 MMBPD (2025 Forecast) 2025: 28.7 Bcf/d 2027: 32.2 (+3.5) Bcf/d 2030: 35.4 (+6.7) Bcf/d 33.9 Bcf/d (2025 Forecast) 2025: 22.4 Bcf/d 2027: 25.0 (+2.6) Bcf/d 2030: 27.5 (+5.1) Bcf/d 24.6 Bcf/d (2025 Forecast) Source: EPD Fundamentals, April 2026
Page 16
16© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Permian Basin Trends Productivity & Longevity 28.7 Bcf/d 3.8 MMBPD CRUDE OIL 6.5 MMBPD 2025 Actuals 2030 Outlook TOTAL NATURAL GAS NGLs 35.4 Bcf/d (+6.7 Bcf/d Growth) 2025: 33.9 Bcf/d 4.7 MMBPD (+0.9 MMBPD Growth) 2025: 4.5 MMBPD 7.5 MMBPD (+1.0 MMBPD Growth) 2025: 7.6 MMBPD • Stacked Pay: Over 18,000 Hz wells completed in ≈25 different named geologic zones last 3 years; primarily in various Bone Spring, Spraberry and Wolfcamp benches • Producers continue to step-out, pursuing Barnett / Woodford and non-traditional benches along with sour gas targets on the eastern flank of the Delaware Basin • Advances in next generation technology (such as spacing, cube completions, and lighter proppants) enhance hydrocarbon recoveries • Consolidation drives efficiency and the rapid transfer of technology Note: Annual production figures represent annual average Source: EPD Fundamentals Annual Production Averages
Page 17
17© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com 1.03 0.98 0.97 0.97 0.98 0.97 1.01 1.07 1.14 0 250 500 750 1,000 0.00 0.50 1.00 1.50 2.00 2017 2018 2019 2020 2021 2022 2023 2024 2025 Gas Rate (Mcf/d) GOR (Mcf/Bbl) Midland GOR Peak Gas Rate 2.99 3.35 2.97 2.97 3.14 3.14 3.25 3.39 3.75 0 1,000 2,000 3,000 4,000 0.00 1.00 2.00 3.00 4.00 2017 2018 2019 2020 2021 2022 2023 2024 2025 Gas Rate (Mcf/d) GOR (Mcf/Bbl) Delaware TX GOR Peak Gas Rate 2.16 2.17 2.18 2.44 2.42 2.55 2.42 2.64 2.54 1,000 1,500 2,000 2,500 3,000 1.00 1.50 2.00 2.50 3.00 2017 2018 2019 2020 2021 2022 2023 2024 2025 Gas Rate (Mcf/d) GOR (Mcf/Bbl) Delaware NM GOR Peak Gas Rate GOR (Gas:Oil Ratio) Trends in the Permian Average Gas Peak Rates per Well Continue to Trend Upward 1.91 2.02 1.95 1.95 1.98 2.06 2.02 2.12 2.24 0 500 1,000 1,500 2,000 1.50 1.75 2.00 2.25 2.50 2017 2018 2019 2020 2021 2022 2023 2024 2025 Gas Rate (Mcf/d) GOR (Mcf/Bbl) Total Permian GOR Peak Gas Rate Source: EPD Fundamentals
Page 18
18© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com 0000 What Comes with a new Barrel of Permian Oil? Rich Gas & NGLs Ratios Continue to Grow in the Permian Basin 2022 2025 0.5 Barrel* Natural Gas (3 Mcf) 0.5 Barrel NGLs 1 Barrel Crude 0.64 Barrel* Natural Gas (3.78 Mcf) 0.66 Barrel NGLs 1 Barrel Crude Previous (2022) Today (2025) 1.0 Barrel Crude +1.3 Barrels NGLs and Natural Gas 50% CRUDE 25% NGLs 25% NATURAL GAS 43% CRUDE 29% NGLs 28% NATURAL GAS 1.0 Barrel Crude +1.0 Barrel NGLs and Natural Gas *Natural Gas is shown in Barrels of Oil Equivalent. Source: EPD Fundamentals
Page 19
19© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Permian Natural Gas Takeaway New Takeaway Capacity Crucial to Avoid Price Impact • Waha pricing is drastically improving as additional pipeline capacity comes online • $ value of a Permian barrel supported by the significant improvement in Waha pricing - Forward gas prices improves producer’s profitability relative to recent gas prices Source: EPD Fundamentals 0 5 10 15 20 25 30 35 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 MMcf/d Existing Gas Pipeline Capacity Additional Pipeline Capacity (FID) Announced Pipeline Capacity (no FID) Forecast Permian Gas Production
Page 20
20© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Natural Gas Demand Outlook Growth in U.S. Gas Demand by Type 2025–2030 in Bcf/d Low High End Use – Res / Com/ Industrial 1 2 Power Generation – Non-AI 0 1 AI & Data Centers 3 6 Domestic Growth Subtotal 4 9 Pipeline Exports – Mexico 0 2 Waterborne Exports – LNG 7 15 Export Growth Subtotal 7 17 Total Growth Bcf/d 11 26 • Global gas & power demand growth driven by economic growth, AI/data center infrastructure, and incremental industrial demand • Asia & Europe demand for LNG expected to grow ≈30% by 2030 • AI/data center infrastructure requires certainty of power supply to maintain high rates of reliability; natural gas and coal well suited to serve this demand • In addition to associated gas production from the Permian Basin, U.S. dry gas producers (Haynesville, Eagle Ford & Appalachia) have ample resources to meet this incremental demand, with supportive market signals & permitting reform 0 10 20 30 40 50 60 70 80 90 2024 2025 2026 2027 2028 2029 2030 Asia Europe Others Global LNG Demand by Region Sources: EPD Fundamentals, Bloomberg , April 2026 Bcf/d
Page 21
21© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com 0.0 0.8 1.5 2.3 3.0 3.8 4.5 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 MMBPD Ethane Domestic Demand ≈2 MMBPD Export Potential Exporting the U.S. Surplus Simplified Crude, Natural Gas, Ethane and LPG Balances 0 5 10 15 20 25 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 MMBPD Crude Oil Domestic Demand ≈5.5 MMBPD Export Potential 40 60 80 100 120 140 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Bcf/d Dry Natural Gas Domestic Demand ≈35 Bcf/d Export Potential 0.0 1.0 2.0 3.0 4.0 5.0 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 MMBPD LPG Domestic Demand ≈3 MMBPD Export Potential (1) Supply figures represent combined production and imports (2) Ethane supply shown is total potential supply volume that includes currently rejected ethane Sources: EIA, EPD Fundamentals
Page 22
22© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com World Appetite For LPG Keeps Growing Demand for LPG Continues to Exceed All Expectations Sources: IEA and EPD Fundamentals, April 2026 • EPD expects LPG demand to remain strong with ≈300 MBPD of growth annually • Heating and human needs in Non-OECD nations drive continued growth • Global demand growth will absorb growing LPG supply from USA while the reliability of Middle East supply is being reassessed following the closure of Hormuz Strait Global LPG Demand Growth 2025–2030 (MBPD) Pre Shale 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 MBPD Pre-Shale 2005–2012 Growth: 65 MBPD/year 1% CAGR Post-Shale 2012–2025 Growth: 295 MBPD/year 3.4% CAGR 2025–2030 Annually Global LPG Demand Petchem Demand (PDHs) 400 – 700 80 – 140 Heating Demand 800 – 1,200 175 - 250 Total 1,200 – 1,900 255 – 390 LPG Supply U.S. Supply (EPD View) 350 – 450 70 – 90 Estimated Shortfall – How to Balance? 850 – 1,150 180 – 260 Global LPG Demand 2005–2025
Page 23
23© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com The U.S. Advantage U.S. is a Low-Cost Supplier of NGLs to the World Source: EPD Fundamentals, Aug 2026 Propane - Asia Natural Gas - EU LNG - Asia Propane - Europe EU Gas Oil Asia Gas Oil Ethane - U.S.Propane U.S. U.S. Nat Gas $0 $5 $10 $15 $20 $25 $30 SEP 26 DEC 26 MAR 27 JUN 27 SEP 27 DEC 27 MAR 28 JUN 28 SEP 28 $/MMBtu International Demand Market Value U.S. Supply Price
Page 24
24© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com 0 200 400 600 800 1,000 1,200 1,400 1,600 2017 2017 2018 2018 2019 2019 2020 2020 2021 2021 2022 2022 2023 2023 2024 2024 2025 2025 2026 MBPD US Ethane, Ethylene & Derivative Exports in Ethane Equivalent MBPD U.S. Ethane Exports Net Ethylene Exports Ethylene Derivative Exports U.S. Ethane Feeds Global Petchem Demand Ethane Exported in Many Forms Sources: USITC, AFPM, Advisian, EPD Fundamentals, Aug 2026 (1) Ethylene derivatives reflects the approximate ethylene used in items like HDPE, LLDPE, PVC, Styrene, Ethylene Glycol, etc. (2) Shown as ethane (2)(2) Ethane Ethylene Ethylene Derivatives (1) Over 40% of U.S. Ethane produced is exported as Ethane, Ethylene or Pellets
Page 25
Appendix Financials & Non-GAAP Reconciliations
Page 26
26© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Enterprise Products Partners L.P . A Fully Integrated Midstream Energy Company Our Platform >300 MMBbls of Liquids Storage >50,000 Miles of Pipeline NGLs, Crude Oil, Natural Gas, Petrochemicals and Refined Products 21 Deepwater Docks 46 Natural Gas Processing Trains 2 PDH (1) 27 Fractionators 2 iBDH (1) A full interactive map of our assets is available on our website, enterpriseproducts.com (1) PDH means propane dehydrogenation. iBDH means isobutane dehydrogenation
Page 27
27© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com EPD Permian NGL Value Chain Rooted in Organic Growth, Enhanced by Strategic Acquisitions Sour Gas Treating Expanding to 450 MMcf/d capacity with 2 acid gas injection (“AGI”) wells Gas Processing 19 Permian plants with >4 Bcf/d inlet processing capacity Fractionation 20 NGL fractionators with up to ≈1.8 MMBPD total capacity NGL Storage Market Hub Long-Haul Transportation >1.3 MMBPD integrated NGL pipeline takeaway capacity NGL Export Facilities 3 USGC export terminals with >1.2 MMBPD total capacity Primary pricing benchmark for U.S. NGLs with 170 MMBbls total capacity MIDLAND BASIN DELAWARE BASIN EPD NGL MARKET HUB MONT BELVIEU H2S CO2
Page 28
28© 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) $3.85 $4.27 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 $4.50 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 TTM 2Q 2026 Operational DCF per Unit Adjusted CFFO per Unit
Page 29
29© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com 1.5x 2.0x 1.8x 1.0x 1.1x 1.3x 1.2x 1.1x 1.4x 1.3x 1.3x 1.3x 1.4x 1.5x 1.4x 1.3x 1.2x 1.2x 1.5x 1.7x 1.6x 1.7x 1.9x 1.7x 1.7x 1.7x $0 $1 $2 $3 $4 $5 $6 $7 $8 $9 '98 '99 '00 '01 '02 '03 '04 '05 '06 '07 '08 '09 '10 '11 '12 '13 '14 '15 '16 '17 '18 '19 '20 '21 '22 '23 '24 '25 LP Distributions GP Distributions DCF & Coverage Consistently Returning Capital to Unitholders Distribution Stability and Growth Remains a Core Focus $Billions 28 consecutive years of distribution growth and $65 Billion returned to unitholders via LP distributions & common unit buybacks since IPO (1) Distributable Cash Flow (“DCF”) is a non-GAAP measure. For a reconciliation of DCF amounts to the nearest GAAP counterpart, see “Non-GAAP Financial Measures and Reconciliations” under Investors – Financials on our website (1) Completely Eliminated IDRs and Collapsed GP Holdco to reduce cost of capital Eliminated 50% IDRs to reduce cost of capital Moderated Distribution Growth to reduce equity issuance Moderated distribution growth to self-fund equity 0.9x
Page 30
30© 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 $5.2 $2.9 $3.9 $4.2 $3.0 $1.8 $1.6 $2.9 $3.9 $4.4 $4.0 2017 2018 2019 2020 2021 2022 2023 2024 2025 TTM 2Q 2026 Capital Returned to Unitholders Growth Capital Expenditures Responsible, Strategic Growth Returning Capital & Reinvesting in the Business $5.2 Billion of Capital Returned to Unitholders in the Form of Distributions & Buybacks for TTM 2Q 2026 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
Page 31
31© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Enterprise’s History of Returning Capital 11% 12% 11% 11% 11% 12% 13% 13% 13% 12% 11% 10% 11% 13% 13% 12% 13% 13% 13% 13% 12% 0% 2% 4% 6% 8% 10% 12% 14% 16% 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 EPD’s Historical Return on Invested Capital ("ROIC")(1) (2) (3) (1) For a definition, see appendix (2) Pre-2008 is based on EPD reported results (not recast for Mergers) (3) 2008 and 2009 reflect recast financial statements of Enterprise giving effect to the TEPPCO and Enterprise GP Holdings mergers Attractive, Long-Term Returns
Page 32
32© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Setting the Standard for Balance Sheet Strength Ample liquidity, allowing for flexibility and opportunity Low leverage range reflects our robust balance sheet as we pass 28 years of consecutive distribution growth Manageable maturity schedule ≈$4B of liquidity A- / A- / A3 (1) Leverage of 3.0x, with a 2.75–3.25x target range Highest credit rating in the midstream space For a definition of Leverage Ratio, see Appendix. All figures are as of June 30, 2026 (1) S&P, Fitch, and Moody’s upgraded Enterprise to “A-” in March 2023, “A-” in September 2023, and “A3” in November 2023, respectively 4.7% weighted-average cost of debt 4.0% 4.4% 4.7% 5.1% 5.4% 5.8% 6.1% 6.5% 14 15 16 17 18 19 20 21 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Weighted-Avg Term to Maturity Average Cost of Debt Avg. Maturity – Years Cost of Debt (1) BBB+ BBB+ BBB+ BBB+ BBB+ BBB+ A- A- A- 1.0x 1.2x 1.4x 1.5x 1.7x 1.9x 2.1x 2.75x 3.00x 3.25x 3.50x 3.75x 4.00x 4.25x 2017 2018 2019 2020 2021 2022 2023 2024 2025 Distribution Coverage Net Leverage Ratio Rating Leverage Ratio Distribution Coverage
Page 33
33© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Fundamentals Outlook April 2026 Update Sources: EPD Fundamentals; OPEC+ U.S. PRODUCTION TRENDS GLOBAL DEMAND GROWTH • Petrochemical demand remains the primary driver of global liquid hydrocarbons growth • Petrochemical destocking due to Iran conflict creates tailwinds for cost advantaged crackers • Elevated Energy prices create headwinds for Global liquid hydrocarbon demand growth; Sticky demand for NGLs and naphtha will continue to account for more than 50% of growth • Low-cost feedstock advantage gives U.S. petrochemicals the edge over Asia and Europe • Despite transport costs, U.S. ethane remains preferred ethylene feedstock globally OPEC+ • UAE leaves OPEC – Reduces OPEC’s ability to control supply demand balance, Most of spare capacity in UAE and KSA • Continued closure of Hormuz – Risk of damage to mature wells of Gulf producers with medium sour crude • Geopolitical instability, sanctions on Russia and war with Iran remain a wildcard in global oil markets; Russian barrels on the water became spare capacity • Venezuela – next year could prove crucial to the future of its oil industry and oil trade flows, but meaningful growth will take time (2027+) NATURAL GAS DEMAND • LNG and AI driving major U.S. natural gas demand increase over the next five years • Global demand for reliable U.S. LNG driven by Middle East conflict and Russian sanctions • U.S dry gas production has been impacted by very low prices, but we see significant upside to Haynesville production over the next 3+ years with appropriate market signals • Both Texas and Louisiana favorable for AI infrastructure, crypto mining and industrial reshoring • U.S. shale producers showed capital discipline in 2025 and we expect no change in 2026; increased growth in production will be measured in high price environment • Permian responsible for ≈85% of U.S. liquid hydrocarbons growth with gas/NGL production continuing to outperform • Offshore oil production growth continues into 2028 • Haynesville awaits natural gas price signals to unleash upside potential over the next 3 years • Appalachia still faces regulatory and infrastructure challenges despite its large natural gas reserves, both rich and lean
Page 34
34© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Waterborne LPG Supply/Demand The World Will Continue to Need U.S. LPGs SUPPLY DEMAND Sources: EPD Fundamentals and Kpler; data year to date through October 2025 Total Waterborne LPG: 4.9 MMBPD with Asia importing ≈65% • U.S. provides ≈2.3 MMBPD (47%) of waterborne LPG supply - U.S. exports satisfy 35% of China’s demand USA CHINA MIDDLE EAST OTHER ASIA OTHER ASIA EUROPE EUROPE INDIA OTHER OTHER AFRICA 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000 MBPD
Page 35
35© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com EPD ≈18% U.S. Responsible for Global LPG Export Growth Growth Driven by Residential Market; >70% of Global LPG Demand (1) Sources: EPD Fundamentals and Kpler,1H26 global waterborne LPG exports The U.S. is the leading exporter of LPGs globally, which displaces coal and biomass. The U.S. holds ≈57% of the global waterborne LPG exports (1) 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 1H26 US Exports Rest of Globe Qatar Algeria UAE Saudi Arabia Iran Kuwait Norway LPG Waterborne Export Growth by Country MBPD
Page 36
36© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Fee, 61% Fee + Margin, 28% %-of-Proceeds / NGLs, 7% Keepwhole, 4% Column1 Natural Gas Processing Contract Mix As of 2Q 2026 Region EPD Elects to Extract Ethane Producer Elects to Extract Ethane Rockies 54 37 Texas 201 132 Louisiana 50 50 Chaco 8 4 Total 313 223 Equity NGL Production (MBPD) (2) 89% of Natural Gas Processing contracts have a fee component Source: EPD Fundamentals (1) Bullets represent highest concentrations of contract type by region (2) Equity NGL Production is estimated and may differ from actual results • Delaware Basin • South Texas • Midland Basin • Louisiana • Rockies • South Texas • Louisiana • Rockies Inlet Gas of 8.1 Bcf/d
Page 37
37© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Enterprise Marine Terminals Volumes Remain Resilient Note: Quarterly volumes 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. EPD NGL marine terminal volumes averaged 1,066 MBPD in TTM 2Q 2026 EPD crude marine terminal volumes averaged 873 MBPD in TTM 2Q 2026 EPD petrochemical & refined products marine terminal volumes averaged 371 MBPD in TTM 2Q 2026 - 500 1,000 1,500 2,000 2,500 3,000 1Q 21 2Q 21 3Q 21 4Q 21 1Q 22 2Q 22 3Q 22 4Q 22 1Q 23 2Q 23 3Q 23 4Q 23 1Q 24 2Q 24 3Q 24 4Q 24 1Q 25 2Q 25 3Q 25 4Q 25 1Q 26 2Q 26 MBPD NGLs Petrochemicals &'Refined Products Crude Oil
Page 38
38© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Definitions 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. Net Cash Flow Provided by Operating Activities (“CFFO”) represents the GAAP financial measure “Net cash flow provided by operating activities”. 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 Free Cash Flow is CFFO before the net effect of changes in operating accounts less investing activities less net cash flow to non-controlling interests. Adjusted CFFO Payout Ratio is calculated as trailing 12 months distributions + distribution equivalent rights + buybacks divided by the trailing 12 months Adjusted CFFO. Leverage Ratio is defined as net debt adjusted for equity credit in junior subordinated notes (hybrids) divided by Adjusted EBITDA. 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. Return on Invested Capital (“ROIC”) is calculated by dividing non-GAAP gross operating margin for the assets (the numerator) by the average historical cost of the underlying assets (the denominator). The average historical cost includes fixed assets, investments in unconsolidated affiliates, intangible assets and goodwill. Like gross operating margin, the historical cost amounts used in determining ROIC are before depreciation and amortization and reflect the original purchase or construction cost.
Page 39
39© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Distributable Cash Flow and Operational DCF (a) Excludes amortization of finance lease right-of-use assets, which are a component of distributable cash flow and operational distributable cash flow. We measure available cash by reference to DCF, which is a non-GAAP cash flow measure. DCF is an important financial measure for our limited partners since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flows at a level that can sustain our declared quarterly cash distributions. DCF is also a quantitative standard used by the investment community with respect to publicly traded partnerships since the value of a partnership unit is, in part, measured by its yield, which is based on the amount of cash distributions a partnership can pay to a unitholder. Our management compares the DCF we generate to the cash distributions we expect to pay our partners. Using this metric, management computes our distribution coverage ratio. Operational DCF, which is defined as DCF excluding the impact of proceeds from asset sales and other matters and monetization of interest rate derivative instruments, is a supplemental non-GAAP liquidity measure that quantifies the portion of cash available for distribution to common unitholders that was generated from our normal operations. We believe that it is important to consider this non-GAAP measure as it provides an enhanced perspective of our assets’ ability to generate cash flows without regard for certain items that do not reflect our core operations. Our calculation of DCF and Operational DCF may or may not be comparable to similarly titled measures used by other companies. The GAAP financial measure most directly comparable to DCF and Operational DCF is net cash flows provided by operating activities. For additional information regarding DCF and Operational DCF, see "Non-GAAP Cash Flow Measures" included under Item 7 of our annual report on Form 10-K for the most recent year. See “Investors – Financials” on our website (www.enterpriseproducts.com) for more information regarding DCF, including additional reconciliation detail. The following table presents our calculation of DCF for the years 2017–2025 (each ended December 31) or periods presented below (dollars in millions): Total 2017 Total 2018 Total 2019 Total 2020 Total 2021 Total 2022 Total 2023 Total 2024 Total 2025 1Q 2026 2Q 2026 Total 2026 TTM 2Q 2026 Net income attributable to common unitholders (GAAP) 2,799.3$ 4,172.4$ 4,591.3$ 3,775$ 4,634$ 5,487$ 5,529$ 5,897$ 5,810$ 1,482$ 1,840$ 3,322$ 6,304$ Adjustments to GAAP net income attributable to common unitholders to derive DCF (addition or subtraction indicated by sign): Depreciation, amortization and accretion expenses (a) 1,644.0 1,791.6 1,949.3 2,072 2,140 2,245 2,343 2,473 2,623 701 722 1,423 2,767 Cash distributions received from unconsolidated affiliates 483.0 529.4 631.3 615 590 544 488 483 438 86 120 206 420 Equity in income of unconsolidated affiliates (426.0) (480.0) (563.0) (426) (583) (464) (462) (408) (361) (76) (109) (185) (360) Asset impairment charges 49.8 50.5 132.8 890 233 53 32 57 50 8 9 17 46 Change in fair market value of derivative instruments 22.8 16.4 27.2 (79) (27) 78 33 (20) 16 98 (129) (31) (5) Change in fair value of Liquidity Option Agreement 64.3 56.1 119.6 2 - - - - - - - - - Gain on step acquisition of unconsolidated affiliate - (39.4) - - - - - - - - - - - Sustaining capital expenditures (243.9) (320.9) (325.2) (294) (430) (372) (413) (667) (620) (205) (140) (345) (746) Other, net 38.3 30.0 40.0 (128) (88) 58 (12) 43 (52) 17 (1) 16 (22) Operational distributable cash flow (non-GAAP) 4,431.6 5,806.1 6,603.3 6,427 6,469 7,629 7,538 7,858 7,904 2,111 2,312 4,423 8,404 Proceeds from asset sales and other matters 40.1 161.2 20.6 13 64 122 42 14 82 596 3 599 666 Monetization of interest rate derivative instruments accounted for as cash flow hedges 30.6 22.1 - (33) 75 - 21 (33) 14 - - - - Distributable cash flow (non-GAAP) 4,502.3 5,989.4 6,623.9 6,407 6,608 7,751 7,601 7,839 8,000 2,707 2,315 5,022 9,070 Adjustments to non-GAAP DCF to derive GAAP net cash flow provided by operating activities (addition or subtraction indicated by sign): Net effect of changes in operating accounts, as applicable 32.2 16.2 (457.4) (768) 1,366 (54) (555) (506) (124) (861) 666 (195) (472) Sustaining capital expenditures 243.9 320.9 325.2 294 430 372 413 667 620 205 140 345 746 Other, net (112.1) (200.2) 28.8 (42) 109 (30) 110 115 89 (582) 60 (522) (484) Net cash flow provided by operating activities (GAAP) 4,666.3$ 6,126.3$ 6,520.5$ 5,891$ 8,513$ 8,039$ 7,569$ 8,115$ 8,585$ 1,469$ 3,181$ 4,650$ 8,860$
Page 40
40© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com 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. 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. 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. Our calculation of total gross operating margin may or may not be comparable to similarly titled measures used by other companies. The GAAP financial measure most directly comparable to total gross operating margin is operating income. For additional information regarding total gross operating margin, see Note 10 of the Notes to Consolidated Financial Statements included under Item 8 of our annual report on Form 10-K for the most recent year. See “Investors – Financials” on our website (www.enterpriseproducts.com) for more information regarding GOM, including additional reconciliation detail. The following table presents our calculation of GOM for the years 2017–2025 (each ended December 31) or periods presented below (dollars in millions): (a) Within the context of this table, total segment gross operating margin represents a subtotal and corresponds to measures similarly titled and presented with the business segment footnote found in our consolidated financials statements. (b) Gross operating margin by segment for NGL Pipelines & Services and Crude Oil Pipelines & Services reflect adjustments for shipper make-up rights that are included in management's evaluation of segment results. However, these adjustments are excluded from non-GAAP total gross operating margin in compliance with guidance from the SEC.(c) 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. Total 2017 Total 2018 Total 2019 Total 2020 Total 2021 Total 2022 Total 2023 Total 2024 Total 2025 1Q 2026 2Q 2026 Total 2026 TTM 2Q 2026 Gross operating margin by segment: NGL Pipelines & Services 3,258.3$ 3,830.7$ 4,069.8$ 4,182$ 4,316$ 5,142$ 4,898$ 5,548$ 5,559$ 1,503$ 1,545$ 3,048$ 5,892$ Crude Oil Pipelines & Services 987.2 1,511.3 2,087.8 1,997 1,680 1,655 1,707 1,646 1,501 329 485 814 1,538 Natural Gas Pipelines & Services 714.5 891.2 1,062.6 927 1,155 1,042 1,077 1,277 1,558 496 556 1,052 1,836 Petrochemical & Refined Products Services 714.6 1,057.8 1,069.6 1,082 1,357 1,517 1,694 1,547 1,436 314 418 732 1,499 Total segment gross operating margin (a) 5,674.6 7,291.0 8,289.8 8,188 8,508 9,356 9,376 10,018 10,054 2,642 3,004 5,646 10,765 Net adjustment for shipper make-up rights (b) 5.8 34.7 (24.1) (85) 53 (47) 19 (34) (24) (18) (13) (31) (28) Total gross operating margin (non-GAAP) 5,680.4 7,325.7 8,265.7 8,103 8,561 9,309 9,395 9,984 10,030 2,624 2,991 5,615 10,737 Adjustments to reconcile non-GAAP gross operating margin to GAAP operating income (addition or subtraction indicated by sign): Depreciation, amortization and accretion expense in in operating costs and expenses (c) (1,531.3) (1,687.0) (1,848.3) (1,962) (2,011) (2,107) (2,215) (2,343) (2,477) (656) (671) (1,327) (2,592) Asset impairment charges in operating costs and expenses (49.8) (50.5) (132.7) (890) (233) (53) (30) (57) (50) (8) (9) (17) (46) Operating lease expenses paid by EPCO - - - - - - - - - - - - - Net gains or losses attributable to asset sales and related matters in operating costs and expenses 10.7 28.7 5.7 4 (5) (1) 10 (2) 14 (1) 2 1 6 General and administrative costs (181.1) (208.3) (211.7) (220) (209) (241) (231) (244) (251) (64) (64) (128) (251) Operating income (GAAP) 3,928.9$ 5,408.6$ 6,078.7$ 5,035$ 6,103$ 6,907$ 6,929$ 7,338$ 7,266$ 1,895$ 2,249$ 4,144$ 7,854$
Page 41
41© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Adjusted CFFO and Adjusted FCF Adjusted CFFO is a non-GAAP measure that represents net cash flow provided by operating activities ("CFFO") 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. Our calculation of Adjusted CFFO may or may not be comparable to similarly titled measures used by other companies. The GAAP financial measure most directly comparable to Adjusted CFFO is net cash flow provided by operating activities. 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 Free Cash Flow ("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. Our calculation of Adjusted FCF may or may not be comparable to similarly titled measures used by other companies. The GAAP financial measure most directly comparable to Adjusted FCF is net cash flows provided by operating activities. See “Investors – Financials” on our website (www.enterpriseproducts.com) for more information regarding Adjusted CFFO and Adjusted FCF, including additional reconciliation detail. The following table presents our calculation of FCF and Adjusted FCF for the years 2017– 2025 (each ended December 31) or periods presented below (dollars in millions): Total 2017 Total 2018 Total 2019 Total 2020 Total 2021 Total 2022 Total 2023 Total 2024 Total 2025 1Q 2026 2Q 2026 Total 2026 TTM 2Q 2026 Net cash flow provided by operating activities (GAAP) 4,666.3$ 6,126.3$ 6,520.5$ 5,891$ 8,513$ 8,039$ 7,569$ 8,115$ 8,585$ 1,469$ 3,181$ 4,650$ 8,860$ Adjustments to reconcile net cash flow provided by operating activities to Adjusted Cash Flow from operations Net effect of changes in operating accounts, as applicable (32.2) (16.2) 457.4 768 (1,366) 54 555 506 124 861 (666) 195 472 Adjusted CFFO (non-GAAP) 4,634.1$ 6,110.1$ 6,977.9$ 6,659$ 7,147$ 8,093$ 8,124$ 8,621$ 8,709$ 2,330$ 2,515$ 4,845$ 9,332$ Adjustments to reconcile non-GAAP Adjusted CFFO to non-GAAP Adjusted Free Cash Flow (addition or subtraction by sign): Net cash flow used in investing activities (3,286.1) (4,281.6) (4,575.5) (3,121) (2,135) (4,954) (3,197) (5,433) (5,491) (381) (1,154) (1,535) (4,705) Cash contributions from noncontrolling interests 0.4 238.1 632.8 31 72 7 44 90 5 - 1 1 1 Cash distributions paid to noncontrolling interests (49.2) (81.6) (106.2) (131) (154) (163) (160) (106) (93) (23) (21) (44) (98) Adjusted Free Cash Flow (non-GAAP) 1,299.2$ 1,985.0$ 2,929.0$ 3,438$ 4,930$ 2,983$ 4,811$ 3,172$ 3,130$ 1,926$ 1,341$ 3,267$ 4,530$
Page 42
42© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Adjusted EBITDA (a) Excludes amortization of major maintenance costs for reaction-based plants, which are a component of Adjusted EBITDA. 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. 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, our calculation of Adjusted EBITDA may not be comparable to similarly titled measures of other companies. The GAAP financial measure most directly comparable to Adjusted EBITDA is net cash flow provided by operating activities. See “Investors – Financials” on our website (www.enterpriseproducts.com) for more information regarding Adjusted EBITDA, including additional reconciliation detail. The following table presents our calculation of Adjusted EBITDA for the years 2017–2025 (each ended December 31) or periods presented below (dollars in millions): Total 2017 Total 2018 Total 2019 Total 2020 Total 2021 Total 2022 Total 2023 Total 2024 Total 2025 1Q 2026 2Q 2026 Total 2026 TTM 2Q 2026 Net income (GAAP) 2,855.6$ 4,238.5$ 4,687.1$ 3,886$ 4,755$ 5,615$ 5,657$ 5,970$ 5,876$ 1,496$ 1,856$ 3,352$ 6,368$ Adjustments to GAAP net income to derive non-GAAP Adjusted EBITDA (addition or subtraction indicated by sign): Depreciation, amortization and accretion in costs and expenses (a) 1,565.9 1,723.3 1,894.3 2,010 2,055 2,156 2,267 2,398 2,535 672 688 1,360 2,655 Interest expense, including related amortization 984.6 1,096.7 1,243.0 1,287 1,283 1,244 1,269 1,352 1,401 385 384 769 1,498 Cash distributions received from unconsolidated affiliates 483.0 529.4 631.3 615 590 544 488 483 438 86 120 206 420 Equity in income of unconsolidated affiliates (426.0) (480.0) (563.0) (426) (583) (464) (462) (408) (361) (76) (109) (185) (360) Asset impairment charges 49.8 50.5 132.8 890 233 53 32 57 50 8 9 17 46 Provision for or benefit from income taxes 25.7 60.3 45.6 (124) 70 82 44 65 23 22 12 34 17 Change in fair market value of commodity derivative instruments 23.1 16.2 (67.7) (79) (27) 78 33 (20) 16 98 (129) (31) (5) Change in fair value of Liquidity Option Agreement 64.3 56.1 119.6 2 - - - - - - - - - Gain on step acquisition of unconsolidated affiliate - (39.4) - - - - - - - - - - - Other, net (10.7) (28.7) (5.7) (4) 5 1 (10) 2 (14) 1 (2) (1) (6) Adjusted EBITDA (non-GAAP) 5,615.3 7,222.9 8,117.3 8,057 8,381 9,309 9,318 9,899 9,964 2,692 2,829 5,521 10,633 Adjustments to non-GAAP Adjusted EBITDA to derive GAAP net net cash flow provided by operating activities (addition or subtraction by sign): Interest expense, including related amortization (984.6) (1,096.7) (1,243.0) (1,287) (1,283) (1,244) (1,269) (1,352) (1,401) (385) (384) (769) (1,498) Net effect of changes in operating accounts, as applicable 32.2 16.2 (457.4) (768) 1,366 (54) (555) (506) (124) (861) 666 (195) (472) Other, net 3.4 (16.1) 103.6 (111) 49 28 75 74 146 23 70 93 197 Net cash flow provided by operating activities (GAAP) 4,666.3$ 6,126.3$ 6,520.5$ 5,891$ 8,513$ 8,039$ 7,569$ 8,115$ 8,585$ 1,469$ 3,181$ 4,650$ 8,860$
Page 43
43© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Investor Relations Contact Information Joe Theriac Vice President, Finance & Investor Relations Gayl Fogata Manager, Investor Relations Phone : (866) 230-0745 Email: investor .relations@eprod.com