Enterprise Products Partners Lp

ENTERPRISE PRODUCTS PARTNERS L . P. ANALYST DAY

March 4, 2021 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,” “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.

I: Executive Overview Jim Teague Co-Chief Executive Officer Randy Fowler Co-Chief Executive Officer & Chief Financial Officer

II: Supply and Demand Fundamentals Tony Chovanec Senior VP, Fundamentals & Commodity Risk Assessment

III: Commercial Update Brent Secrest Executive VP & Chief Commercial Officer Chris D’Anna Senior VP, Petrochemical Natalie Gayden Senior VP, Natural Gas Assets Tug Hanley Senior VP, Pipelines and Terminals Brad Motal Senior VP, Liquid Hydrocarbons

IV: Financial Update Chris Nelly Executive VP, Finance, Sustainability & Treasurer

© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Page 3 EXECUTIVE OVERVIEW Jim Teague – Co-CEO Randy Fowler – Co-CEO and CFO Enterprise Products Partners L.P. (NYSE:EPD) NGLs, Crude Oil, Natural Gas, Petrochemicals and Refined Products • ≈50,000 miles of NGL, crude oil, • 21 natural gas processing facilities; Fully integrated natural gas, petrochemicals and 25 fractionators; 11 condensate refined products pipelines distillation facilities; PDH facility; midstream • ≈260 MMBbls of NGL, petrochemical, iBDH facility energy company refined products and crude oil, and • 19 deepwater docks handling NGLs, 14 Bcf of natural gas storage capacity PGP, crude oil and refined products

Diversified & built for Market Capitalization: Among highest credit >22 consecutive the long run ≈$47B ratings in midstream space: BBB+ / Baa1 years of Enterprise Value: distribution ≈$77B 2020 Leverage(1): increases Daily Trading Value: 3.5x reported (last 20 days)

Geographic, Product ≈$168MM and Market Diversification as of February 22, 2021

Disciplined Allocator of Average 2020 History of unitholder Capital – 2020: Return on Invested Capital(1): alignment through actions & $1.80/unit ownership CFFO Allocation: 12% 4Q 2020 distribution annualized Payout(1) 70% 1.6x distribution coverage Capital investment 51% over the last 10 years 32% of common units (2) $3.0B owned by Funding Capital Investments : 2020 Growth CAPEX CFFO (less distributions) 65% Debt 35% Management $2B buyback in place as of 4Q 2020 (≈$312MM repurchased(3))

(1) For a definition, see appendix (2) Our CFFO for 4Q 2020 was impacted by increased uses of working capital for marketing opportunities (including contango) (3) Through December 31, 2020

Balanced and Disciplined Approach Allocating cash flow with a long-term focus and maintaining 3.5x area leverage

Buyback Opportunities Cash • Opportunistic buybacks of Distributions common units • 2020 buybacks were executed • 22 years of consecutive at an average CFFO Yield of distribution growth ≈15% • Continue to increase distribution with solid cash flow coverage Growth Capital Investments • Self-fund growth CAPEX • Targeting ≈12%+ ROIC(1)

(1)(2) Nat. Gas Ethane Propane Butanes C5+ Crude Oil 3.5 MMBOED 2.3 MMBPD 2.1 MMBPD 1.2 MMBPD 420 MBPD 2.9 MMBPD transported handled handled handled handled handled product & & product volume

electric generation heating bottled fuels diluent refinery feedstock heating petchem feedstock cooking gasoline blending gasoline blending ses

irect irect propellant petchem feedstock u cooking crop drying d vehicle fuel vehicle fuel refrigerants industrial fuel petchem feedstock petchem feedstock iBDH, HPIB PDH & & Octane refining manufacture cracker Splitters Enhancement cracker

activity Isobutylene & Refined

ownstream Ethylene Propylene Octane Additives Products d 340 MBPD handled . 110 MBPD handled 50 MBPD handled 570 MBPD handled

fertilizer food packaging durable products fuel additives tires gasoline paints prosthetics consumer electronics lubricants synthetic rubber heating oil coatings water pipes strong packaging specialty additives paints kerosene glue medical tubing PPE & pharmaceuticals textiles jet fuel insulation material molded parts sporting goods asphalt textiles carpets specialty chemicals lubricants hygiene products & tools synthetic rubber end uses upholstery detergents films plastics antifreeze helmets rayon diapers nylon resins (1) Estimated handling volumes; all volumes are approximate based on FY 2020 averages with assumptions applied to multi product systems and fractionation volumes (2) Handled volumes are the sum of transportation, fractionation, isomerization, petchem processes, and marine loading volumes, as applicable © All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Page 5 SUPPLY AND DEMAND FUNDAMENTALS Tony Chovanec – SVP, Fundamentals & Commodity Risk Assessment Fundamental Outlook

EPD Supply Forecasts

NGL Production Stability and GORs

Producer Cash flows

Global Balances and Price Trends

U.S. Crude Supply Scenarios 15

11 MMBPD

7 Jan-15 Jan-16 Jan-17 Jan-18 Jan-19 Jan-20 Jan-21 Jan-22 Jan-23 Jan-24 Jan-25 *High case: Permian and Eagle Ford completions return to pre-Covid level by mid 2023, other plays return to about 67% *Low case: Permian and Eagle Ford completions return to 67% of pre-Covid levels, other plays return to about 50%

U.S. Available NGL Supply Forecast 8

5 MMBPD

2 Jan-15 Jan-16 Jan-17 Jan-18 Jan-19 Jan-20 Jan-21 Jan-22 Jan-23 Jan-24 Jan-25

Does not include refinery output. Includes all available ethane.

U.S. Dry Natural Gas Supply Scenarios 100

80 Bcf/d

60 Jan-15 Jan-16 Jan-17 Jan-18 Jan-19 Jan-20 Jan-21 Jan-22 Jan-23 Jan-24 Jan-25

U.S. Production 16 150 • Increasing Gas to Oil Ratio (GOR) . GOR rises over time in typical oil wells 14 140 . With fewer new wells to offset the rising GOR, overall basin GOR increased 12 130 Oil down 13% . From Nov-19 to Nov-20, oil production fell 13%, gas fell 4%; NGLs up 7% 10 120 • Reduced flaring

MMBPD Gas down 4% . Permian: 600 to 300 MMcf/d

8 110 /d . Bakken: 546 to 211 MMcf/d NGLs, NGLs,

MMcf . =Additional 500 MMcf/d gas processed 6 100 Gas, Gas, Oil and NGLs up 7% • Newer processing plants . Recovered GPM of C3+ in Texas rose from 4 90 C3+ up 2% 1.97 to 2.14 from Nov-19 to Nov-20 • Increased ethane recovery 2 80 . As demand increased due to the startup of new crackers, ethane production grew 0 70 276 MBPD from Nov-19 to Nov-20

Crude oil NGL C3+ Gas Gross Withdrawals

Sources: EPD Fundamentals, EIA and listed company sources © All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Page 7 U.S. Producers – Significant Cash Flow Upside Above $45/Barrel Producers’ Self-Funding Possible When Oil Prices Exceed $45

Breakeven WTI Price ($/Bbl) $45 $50 $55 $60 $65 U.S. Production (MMBPD) 10.0 10.0 10.0 10.0 10.0 Price Increase $5.0 $10.0 $15.0 $20.0 Net Cashflow Increase @ 66% $3.3 $6.6 $9.9 $13.2 Incremental Cash Flow Annually ($Billions) $12.0 $24.1 $36.1 $48.2

Assumptions: $45/Bbl as Corporate Breakeven oil price according to Dallas Federal Reserve Survey Operating Cash Flow Breakeven includes corporate costs, but not including interest, debt or taxes Assumes Producers get to keep 2/3 of every dollar above $45

• Dallas Federal Reserve survey: producers need $45/Bbl to breakeven • With higher prices, producers cash flow improves significantly allowing for balance sheet upgrades and self-funding of additional wells

Quarterly Oil & Products Stocks 4.0 ≈3.5 billion barrels – peak 3.5 2019: ≈3 billion barrels Nov 2020: ≈3.2 billion barrels

3.0

2.5

2.0 Products

Billion Barrels 1.5

1.0

0.5 Historically low Inventories if Crude OPEC sticks to plan

0.0 Mar-19 Jun-19 Sep-19 Dec-19 Mar-20 Jun-20 Sep-20 Dec-20 Mar-21 Jun-21 Sep-21 Dec-21 Historical Future

Sources: EPD Fundamentals, Energy Aspects, IEA and Bloomberg © All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Page 9 COMMERCIAL UPDATE BRENT SECREST EVP and Chief Commercial Officer Enterprise Products Partners L.P. (NYSE:EPD) NGLs, Crude Oil, Natural Gas, Petrochemicals and Refined Products • ≈50,000 miles of NGL, crude oil, • 21 natural gas processing facilities; Fully integrated natural gas, petrochemicals and 25 fractionators; 11 condensate refined products pipelines distillation facilities; PDH facility; midstream • ≈260 MMBbls of NGL, petrochemical, iBDH facility energy company refined products and crude oil, and • 19 deepwater docks handling NGLs, 14 Bcf of natural gas storage capacity PGP, crude oil and refined products

Enterprise witnessing WTI crude oil falling below $0 for the first time in history due to amplified concerns about supply and demand dynamics amidst the COVID-19 pandemic

Supply vs. Capacity Volume

2018 2019 2020 2021 2022 2023

Capacity Supply Source: EPD Fundamentals

NATURAL GAS ASSET OVERVIEW • 21 natural gas processing facilities • 19,500 miles of natural gas pipelines • 2.6 Bcf/d of natural gas treating • 14.2 Bcf of natural gas storage • Processing 5.8 Bcf/d • Producing 500 MBPD NGL

Enterprise Pipelines Processing Facility

• Filling our most efficient “Tier 1” gas plants and idling the unfilled / inefficient ones • Saving over $20MM per year in expenses for the 3 plants we are idling this year • 2020 vs. 2019 NGL production was up 3% and is expected to rise in 2021

ROCKIES TEXAS AND LOUISIANA

MEEKER (800) ARMSTRONG (250)

Enterprise Pipelines GILMORE Active Processing Facility (260) Currently Idled Processing Facility To-be-Idled Processing Facility

In order to rationalize processing capacity, 3 additional gas processing plants will be idled this year until supply (production) justifies the need for demand (service)

ENTERPRISE PLANT VOLUME VS. DELAWARE RIGS DELAWARE PROCESSING CAPACITY VS. PRODUCTION FORECAST

1.6 250 Effective Delaware Capacity 1.4 14.0 12.0 100% 1.2 200 1.0 10.0 150 85% 0.8 8.0

0.6 6.0 70% 100 2019

75% Delaware Capacity Delaware Rig Count Delaware Rig Enterprise (Bcf/d) Inlet 0.4 2/21 4.0 DUCs ≈1,600 Delaware Rig Count ≈100 50 55%

0.2 Permits ≈4,200 44% Pre-COVID-19 Levels Delaware Production (Bcf/d) 2.0

0.0 0 0.0 40% Feb-20 May-20 Aug-20 Nov-20 2018 2019 2020 2021 2022 2023 2024 2025 EPD Plant Inlet Delaware Rigs Low Price High Price Actuals

ENTERPRISE GAS PROCESSING PLANT TIMELINE

March 2018 May 2018 October 2018 June 2019 Dec 2019 Delaware Basin Orla I Orla II Orla III Mentone I

We use the downstream value chain and competitive transportation and fractionation to attract production to our gas plants even in an environment where basin capacity will go underutilized

Source: EPD Fundamentals © All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Page 9 De-risking the Delaware G&P Portfolio Increasing Take-or-Pays and Term, a Beneficiary of Contract Modifications

TAKE-OR-PAY VS. ACREAGE DEDICATION CONTRACT SUMMARY

100% • Our take-or-pay contracts go 90% beyond 2028 and equate to 80% ≈70% of our nameplate

70% capacity 60% Weighted Average Credit Rating: A ≈30% of contracts structured 50% • as acreage dedications are 40% operated by privately owned 30% ≈40% of Delaware Rigs companies 20% are Privately Operated 10% • We leveraged our diversified 0% and integrated value chain as 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 an opportunity to create a Take-or-Pay Acreage Dedication Delaware % Private Rig Count win-win

A portfolio highly weighted with investment grade take-or-pays yields sustainable cash flow through troughs while keeping exposure to acreage dedications with privately operated production

POST-COVID-19 RIG RECOVERY

106% Carthage Mainline 110% 12/20 100% 90% 80% 70% 60%

% Recovery 50% 50% 40% 30% Feb-20 Apr-20 Jun-20 Aug-20 Oct-20 Dec-20 U.S. Rig Recovery Haynesville Rig Recovery

Gillis GILLIS TAKE-OR-PAY VOLUME 4Q 21

1.0

0.5 Bcf/d

Enterprise Pipelines 0.0 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Processing Facility

Source: EPD Fundamentals © All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Page 11 TUG HANLEY SVP, Pipelines & Terminals NGL, Refined Products and Crude Pipeline Systems Overview

REGULATED NGL, REFINED PRODUCTS AND CRUDE PIPELINES

• Regulated NGL, refined products and crude pipeline system spans over 20,000 miles or ≈40% of our total pipeline mileage • Established footprint in over 27 states, transporting over 4 MMBPD • Connects major producing regions and demand centers MAPL NORTHERN

MAPL ROCKIES FRONT RANGE

MAPL CENTRAL CONWAY

CUSHING

HOBBS

RIO GRANDE

Selected Enterprise Pipelines TRI-STATES Other Enterprise Regulated System Pipelines AEGIS WILPRISE Storage MONT BELVIEU Liquids Terminal

TE PRODUCTS THROUGHPUT Supply to NE Area: 75 225%125% Supply to Chicago Area: Propane 60 100% Refinery Demand Demand Diluent Demand 45 75% Propane Demand MAPL NORTHERN MBPD 30 50%

15 25% MAPL ROCKIES 0 FRONT 0% Diluent Diesel Jet Propane RANGE Long Haul All Products Propane Jet Fuel Supply for 4Q 19 4Q 20 2020 vs 2019 Cargo Transport MAPL CENTRAL TE PRODUCTS PIPELINE CONWAY Supply to • 1,250-mile batched pipeline system from the Gulf Coast to New York Central Area: Refined Products • Long Haul Capacity: 192 MBPD CALVERT CITY • Capable of batching 9 different products Propane Demand • Connected to 30 RP and 24 LPG locations KEY TAKEAWAYS HOBBS Supply to • Beat post-pandemic expectations through product diversity Southern Area: Refined Products Demand • TE backfilled less economicRIO GRANDE PADD I refinery production via Gulf Coast • Throughput supported by top-tier cargo and logistics providers • TE now achieving record 4Q diesel, jet and diluent throughput Selected Enterprise Pipelines TE PRODUCTS BATCH “TRAIN” Other Enterprise Regulated System Pipelines TRI-STATES Storage AEGIS Butanes Propane Butanes Diluent CBOB ULSD MONT BELVIEU WILPRISE Liquids Terminal Refinery

ATEX PIPELINE MARCELLUS / UTICA ETHANE PRODUCTION

• Expansion of 45 MBPD scheduled in-service 2Q 22 1,000 • Northeast flow assurance to customers 800 600

MBPD 400 ATEX CONTRACTED VOLUME MAPL NORTHERN 200 200 0 171 171 171 171 171 171 Jan-20 Mar-20 May-20 Jul-20 Sep-20 Nov-20 MAPL161 ROCKIES 160 FRONT 131 RANGE 120

MBPD MAPL CENTRAL 80 CONWAY

40 CALVERT CITY

0 2021 2022 2023 2024 2025 2026 2027 2028 HOBBS KEY TAKEAWAYS RIO GRANDE • Pandemic proof production • Gulf Coast connectivity provides access to diverse Selected Enterprise Pipelines markets Other Enterprise Regulated System Pipelines TRI-STATES Storage • Long term take-or-pay contracts AEGIS WILPRISE Liquids Terminal Cracker MONT BELVIEU Source: EPD Fundamentals © All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Page 15 AEGIS Pipeline – Supplying the Petrochemical Industry Critical Feedstock to Downstream Durable Demand

AEGIS PIPELINE AEGIS PIPELINE

• Serves as an ethane header to major petrochemical facilities along the Texas and Louisiana Gulf Coast • Expansion of 80 MBPD scheduled online in 1Q 21

MAPL NORTHERN AEGIS CONTRACTED VOLUME

450 427 427 427 427 MAPL384 ROCKIES 400 FRONT 350 RANGE 300 250 200 MAPL CENTRAL MBPD CONWAY 150 100 50 CALVERT CITY 0 2021 2022 2023 2024 2025

HOBBS KEY TAKEAWAYS

• Supplies customersRIO GRANDE that contribute to higher standard of living • Long term take-or-pay contracts • Potential for future growth Selected Enterprise Pipelines Other Enterprise Regulated System Pipelines TRI-STATES Storage AEGIS WILPRISE Liquids Terminal MONT BELVIEU Cracker

SYSTEM ADVANTAGES

• Confidence in Supply: • Front Range and Texas Express commitments • MAPL Rockies and Panola commitments • Suite of counterparties in Delaware and Midland Basins MAPL NORTHERN• Strategic Integration: pipeline systems providing flow assurance, reliability and redundancy • Robust Connectivity: access to multiple markets – Conway, Hutchinson, Hobbs and Mont Belvieu MAPL ROCKIES • Well Positioned Assets: connectivity to Permian, San Juan, Piceance FRONT RANGE and DJ

2020 VS. 2019 VOLUME MAPL CENTRAL CONWAY 101% 108% 100% 93%

CUSHING 75% CALVERT CITY 50%

25% HOBBS 0% Year Over Year Variance U.S. Oil Production U.S. NGL Production EPD NGL Throughput RIO GRANDE KEY TAKEAWAYS

Selected Enterprise Pipelines • Supply diversity with access to multiple basins Other Enterprise Regulated System Pipelines • Despite lower U.S.TRI- STATESoil production, U.S. NGL production was up and EPD AEGIS Storage NGL pipelineWILPRISE throughput exceeded U.S. NGL trend Liquids Terminal • Additional connections scheduled online in 2Q 21 MONT BELVIEU Source: EPD Fundamentals; Total U.S. Production © All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Page 17 Seaway – Shifting From Light to Heavy Advantaged Canadian Supply to Advantaged Refinery Complex

SEAWAY PIPELINE CANADIAN HEAVY VOLUME

• 950 MBPD existing capacity with over Expansion Opportunity 90% utilization 1,200 4,600 1,000 4,400 • Canadian export volume continues to 800 MAPL NORTHERN grow 600 4,200 400 • Expansion opportunities with minimal 4,000 capital investment 200

MAPL ROCKIES CER Volume (MBPD) 0 3,800 Strategic alignment with our JVFRONT partner Seaway Volume (MBPD) • RANGE 2020 2021 2022 2023 2024 2025 2026 2027 from Canada to the Gulf Coast Heavy Expansion Western Canadian Heavy Crude Production

MAPL CENTRAL CONWAY

CUSHING CALVERT CITY

HOBBS

RIO GRANDE

Selected Enterprise Pipelines TRI-STATES Other Enterprise Regulated System Pipelines AEGIS Storage ECHO WILPRISE Liquids Terminal

SEMINOLE PIPELINE CONVERTIBILITY STORAGE OPTIONS LOUTEX CONVERSION NGL ↔ CRUDE PRODUCT FLEXIBILITY FROM SUPPLY PUSH TO DEMAND PULL

CRUDE MARKET OPTIONALITY ATEX CONVERSION AND REVERSAL TE PRODUCTS VERSATILITY NORTH ↔ SOUTH FLEXIBILITY NORTHBOUND TO SOUTHBOUND INNOVATIVE ASSET UTILIZATION

PROJECT JUSTIFICATION

Executed a mutually beneficial restructuring with an anchor customer across multiple Midland-to-ECHO 4 business units enabling us to cancel this project while adding additional term / revenues and optimizing our existing infrastructure

Modified our current asset footprint and contractual arrangements with new and existing MTBV Isom customers to meet obligations with existing capacity

Postponed further expansions of our hydrocarbon export facilities to reflect shifting Export Dock Expansions market fundamentals

Utilized the flexibility within our contract obligations based on market fundamentals Fractionation Capacity allowing for the delay of this project

Restructured G&P commitments in 2020 to avoid adding capacity and eliminating Permian Processing additional capital expenditures

Enterprise eliminated nearly $2 billion of capital while meeting the needs of our customers and adding long term stability to our contract portfolio

MIDLAND-TO-ECHO PIPELINE SYSTEM (“M2E”) TOTAL M2E VOLUME VS. RIG COUNT

• The M2E system offers unparalleled market choice, 1,000 500 flow assurance and reliability 800 400

• 1 MMBPD “optimal” capacity with maximum 600 300 capacity of 1.3 MMBPD MBPD 400 200 ≈15 MMBbls of crude oil storage at Midland, Sealy Count Rig • 200 100 and ECHO terminals 0 0 • ≈95% of customers also elected to contract with us Jan-20 Feb-20 Mar-20 Apr-20 May-20 Jun-20 Jul-20 Aug-20 Sep-20 Oct-20 Nov-20 Dec-20 for additional services Total M2E Volume Rig Count

MIDLAND

BEAUMONT EHSC SEALY ECHO M2E Pipeline System Other Enterprise Crude Pipelines TEXAS CITY Storage JONES CREEK Export Dock FREEPORT

M2E OPTIMAL CAPACITY VS. COMMITMENTS

1,400

1,200 Potential Upside

1,000

800 MBPD 600 Weighted Average Rating: A–

400

200

0 2020 2021 2022 2023 2024 2025 2026 2027 2028

Take-or-Pay Volume Committed Volume Total Max Capacity Total Optimal Capacity

We have contracted our “optimal” crude operating capacity to over 90% beyond 2028

2020 CRUDE DOCK VOLUME VS. GROSS OPERATING MARGIN

1,000

900

800

700

600

500

400

Loaded / Unloaded (MBPD) 300

200

100

0 Jan-20 Feb-20 Mar-20 Apr-20 May-20 Jun-20 Jul-20 Aug-20 Sep-20 Oct-20 Nov-20 Dec-20

Exports Per Month Imports Per Month Gross Operating Margin

Despite decreased crude dock volume, revenues remained consistent due to our contracting strategy

HOUSTON FUTURES CONTRACT OVERVIEW Magellan Enterprise • Futures contract for physical delivery at MEH and ECHO Permian Supply Permian Supply • Outright pricing decoupling from NYMEX WTI at Cushing • Receive from and deliver into the Magellan / Enterprise systems – MEH, FOB (Seabrook), Speed Junction, ECHO, FOB (EHSC), Genoa Junction, Moore Road and FOB (SPOT) New Houston Futures Contract • Gain access to the most robust crude infrastructure in Houston with connections to all major refiners, extensive storage capacity and export terminals MEH ECHO . ≈5 MMBPD inbound capacity . ≈9 MMBPD outbound capacity . ≈5 MMBPD Houston area refining capacity . ≈300 MMBbls of Houston area storage capacity • Specifications to reflect Midland WTI crude quality

Water Access Local Terminals PAD III Refining

UNREGULATED NGL OVERVIEW • 17 fractionators fed by the major producing basins • ≈1.2 MMBPD of optimal operating capacity with a maximum capability of ≈1.5 MMBPD • ≈200 MMBbls of NGL and petrochemical storage • Export facilities include Morgan’s Point and Houston Ship Channel • Connected to 7 Enterprise and 6 third party y-grade pipelines

HOBBS

TEBONE MONT BATON ROUGE BELVIEU

ARMSTRONG PROMIX NORCO

NGL Active NGL Fractionator SHOUP Idled NGL Fractionator Storage NGL Export Dock

LPG EXPORT CONTRACT SUMMARY

700 EXPANSION

600

EXPANSION 500

400 (MBPD)

300 Volume

200

100

0 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Contract Outlook as of 12/15 Contract Outlook as of 1/21 Effective Capacity

We continue to re-contract the majority of our LPG export capacity while holding additional “upside” capacity open to capture market opportunities

ATTRACTIVE GROWTH DIFFICULT TO REPLICATE

• Quality of Life: quality of life improvements drive demand • World-scale, fee-based processing facilities growth for primary petrochemicals in emerging markets • Established integrated pipeline system • Commoditization: accelerate market development through hubs and export terminals • Storage and hub ownership

• Value Chain: integration downstream allows higher value • Export terminals capture across our entire chain

GLOBAL CAGR (2010–2019 AVERAGE) OUR PETROCHEMICAL VALUE CHAIN GROSS OPERATING MARGIN

4% Petchem & RP 3% 13% NatGas 11%

2% 3.8% NGLs 2.8% 3.0% 51% 1% Crude 1.4% 25%

0% GDP Oil Ethylene PGP

For Gross Operating Margin (GOM) see the non-GAAP reconciliation section of this presentation for the closest GAAP measure. © All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Page 29 Open Access Ethylene and Propylene Hubs Transforming How Global Petrochemicals Markets Transact

OPEN ACCESS PETROCHEMICAL HUBS

• Open access hubs located at the center of the most cost advantaged location for petrochemicals

• Most connected and accessible petrochemicals market in the world

• Linking North American petrochemicals to global markets

• Creating a true commodities marketplace for petrochemicals with transparent pricing and a liquid index

• Hub ownership benefits include optimization and growth opportunities

U.S. ETHYLENE PRODUCTION CAPACITY

100

20 BillionPounds Per Year 0

OUR ETHYLENE BUSINESS

• All ethylene assets supported by contracts with investment grade customers, take-or-pays and terms up to 20 years

• Storage: ethylene cavern has a capacity of over 600 million pounds with connectivity to over 80% of USGC pipelines

• Pipelines: includes the Ship Channel area header, the South Texas System under construction and future expansions under development

• Export Terminal: our terminal is the largest ethylene terminal in the world capable of loading ≈3 million pounds per hour, capable of co-loading ethane and ethylene, and has multiple docks for loading and space for expansion

REFINERY GRADE PROPYLENE (“RGP”) POLYMER GRADE PROPYLENE (“PGP”)

Largest and most reliable refinery grade propylene off-take Largest polymer grade propylene system in the world service for U.S. refineries and crackers • 11 billion pounds per year of operating production capacity • Over 350 miles of dedicated gathering pipelines post PDH 2 • 550 miles of delivery pipelines by the end of 2021 • Pipeline system stretches from Louisiana to South Texas • Connected to ≈90% of U.S. PGP consumers • Over 100 railcars per day of unload capacity • PGP caverns serve as industry hub with over 1 billion pounds • 5 dedicated RGP storage caverns with over 9 million barrels of storage of storage capacity • U.S. Gulf Coast PGP export terminal with over 3.5 billion • 2 world scale propane dehydrogenation plants by 2023 pounds per year capacity

FULFILLING PROPYLENE DEMAND

• Growing demand for propylene derivatives requires additional on-purpose production

• Our significant dehydro experience and extensive propylene system make PDH 2 a natural extension

• PDH capacity is sold to investment grade customers as long-term, 10–15 year contracts with fixed fees on a take-or-pay basis

PDH 1

iBDH 2

PDH 2 (RENDERING)

ASSET PRODUCTION CAPACITY U.S. RANK Propylene Splitters(1) 7.6 billion pounds per year 1 PDHs(2) 3.3 billion pounds per year 1 iBDHs 2.2 billion pounds per year 1 MTBE 750 thousand tons per year 2 (1) Includes operational capacity (2) Includes PDH 2 (2023) © All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Page 33 FINANCIAL UPDATE Successfully Managing Economic Cycles Chris Nelly – EVP, Finance, Sustainability & Treasurer Consistent Financial Objectives

Continuity is Key Through the Years 1999 2008 Invest in high quality assets with stable sources of cash flows Attractive returns in excess of cost of capital

Tax deferred income and yield

Maintain an attractive 2013 2018 payout ratio

Long-term financial durability with strong balance sheet and investment grade ratings

© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Page 2 Successful History of Execution Preserve, Protect and Provide Partners Reliable Distributions • Dependable distribution growth and coverage in excess of distributions • Solid balance sheet; BBB+ rated (highest in the midstream space) and 2020 leverage of 3.5x

$ in MMs 22 Years of Distribution Growth $7,000 Moderated Distribution Growth; Self-Fund Equity $6,000 $38.8 Billion returned to unitholders via LP distributions & unit buybacks 1.7x $5,000 1.6x Collapsed GP/LP Structure 1.5x

$4,000 1.2x 1.2x 1.3x Moderated Distribution 1.4x $3,000 Growth; Retained 1.5x Incremental Cash Flow 1.4x 1.3x $2,000 1.3x

1.3x Eliminated 50% IDRs 1.4x 1.1x $1,000 1.2x 1.3x 1.1x 0.9x 2.0x 1.8x 1.0x 0.6x 1.5x $0 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 LP Distributions GP Distributions Operational DCF & Coverage See Appendix for definitions of Operational DCF and the reconciliation of DCF to its nearest GAAP measure © All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Page 3 Successful History of Cash Flow per Unit Growth DCF Coverage Ratio or CFFO Payout Ratio – the Trend is the Same

COVID-19 Financial Crisis Pandemic $3.50 Oil Price Collapse

$3.00 $2.96 $3.00 $2.92 $2.80 $2.65 $2.68

$2.50

$2.20 $2.16 $2.09 $2.06 $2.05 $1.97 $1.99 $2.00 $1.92 $1.99 $1.93 $1.94

$1.72 $1.61 $1.59 $1.56 $1.58 $1.47 $1.50 $1.37 $1.40 $1.30 $1.22 $1.21

Operational CFFO perUnit DCF / $1.01 $1.00 $0.94

$0.50

$0.00 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

(1) (1) Operational DCF per Unit CFFO per Unit

$ in MMs $7,000 $6,521 $6,126 $5,892 $6,000

Oiltanking $5,000 acquisition $4,666 $4,162 $4,002 $4,067 $4,000 $3,866 $3,331 $2,891 $3,000 $2,670 $2,472 $2,001 $2,000 $1,331

$1,000 $583 $441 $34 $0 2011 2012 $(169) 2013 2014 2015 2016 2017 2018 2019 2020 $(224) -$1,000

-$2,000 $(1,746)

-$3,000 CFFO FCF

Free Cash Flow (“FCF”): CFFO less cash used in investing activities net of contributions paid and distributions received from noncontrolling interest. See Appendix for reconciliation of FCF to nearest GAAP counterpart. © All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Page 5 Improved Financial Metrics the “EPD Way” What Stayed the Same and What Changed?

2015 2020 2021E Organic Growth Same (1) $3.7B $3.0B $1.6B Capital Continuing to invest in high quality assets

(2) Maintaining investment Leverage 4.2x 3.5x 3.5x area grade balance sheet Continuing CFFO/unit and distribution growth Payout as a % of CFFO(3) 76% 70% TBD Changed Transitioned to self- Net Equity funding majority of Issuance $1.2B ------capital investments Moderated capital Investments Buybacks - - - $200MM TBD Added buybacks to cash flow payout

(1) Organic Growth Capital includes: Capital Expenditures, Investments in Unconsolidated Affiliates, Other investing activities, net of adjustments for noncontrolling interests and sustaining capital (2) Leverage: Net Debt / Adjusted EBITDA (3) Payout includes distributions, distribution equivalent rights, and buybacks © All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Page 6 Consistent History of Returning Capital to Partners Cash Flow from Operations Allocation

% of CFFO 100%

90%

80%

70% 3% 1% 1% 60%

50%

86% 83% 40% 78% 75% 77% 76% 77% 67% 66% 64% 65% 30% 61% 61% 61% 59%

20%

10%

0% 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Distributions Buybacks Reinvested Capital

• Distributions include: GP & LP distributions paid and distribution equivalent rights • Excess cash flow from operations historically went towards funding growth capital projects

as % of 2020 Cash flow from Operations Payout/CFFO Ranked Payout

Real Estate 85% 69% 2% 71% 1

Enterprise 51% 67% 3% 70% 2

MidstreamMidstream C-Corps (1)(1) 64% 57% 57% 3

Information Technology 11% 19% 31% 50% 4

Energy 87% 38% 2% 40% 5

Consumer Staples 21% 32% 6% 38% 6

Industrials 16% 23% 13% 36% 7

Utilities 146% 33% 0% 33% 8

S&P 500 Median 19% 21% 12% 33% 9

Materials 30% 22% 4% 26% 10

Health Care Median 18% 6% 14% 20% 11

Consumer Discretionary 20% 8% 10% 18% 12

Communication Services Median 27% 7% 3% 10% 13 0% 20% 40% 60% 80% 100% 120% 140% 160% 180% 200% Capex Dividends / Distributions Equity Repurchase

Sources: Bloomberg. 12 months ended as of February 1, 2020. Consensus estimates; Median value of S&P 500 firms; Payout consists of indicated dividends defined as most recent dividend and common stock repurchases of with respect to the trailing 12 months; (1) Median figures for Kinder Morgan (KMI), ONEOK (OKE), and Williams Companies (WMB)

Continuity Invest in high quality assets with stable is Key sources of cash flows

Attractive returns in excess of cost of capital

Tax deferred income and yield

Maintain an attractive payout ratio

Long-term financial durability with strong balance sheet and investment grade ratings

© All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Page 9 APPENDIX Capital Updates ≈$3.6B of Major Capital Projects Under Construction* Forecast Highlighted Major Capital Projects 2020–Forward In-service Major Capital Projects Under Construction Mont Belvieu Area Fractionators 10 & 11 In-service Texas Express & Front Range Expansions In-service NGLs 11% Mont Belvieu to Beaumont Ethane Expansion 1Q 2021 Liquids Natural

NaturalGas Gas C5 Hydrotreater 2H 2021 14% Petchem & $3.6B Ref. Prod. 2021–Fwd Crude Natural Gas Pipeline to Carthage (Panola-related) In-service 68% 7% Gillis Lateral & Acadian Haynesville Expansion 4Q 2021

NaturalGas Permian Gathering & Residue Lines 4Q 2021

Permian Gathering & Condensate Projects In-service Midland-to-ECHO 3 Pipeline In-service Project In-service Estimates EHT Dock 1A Layberth In-service $3.0

Crude Oil EFS Projects & Other Tank Projects In-service $2.5 $2.4 $2.0 Midland & ECHO Tank Expansions (support M2E3) 1Q 2021 $2.0 $1.6 $1.5 Mont Belvieu Area DIB 2 In-service $ in B $1.0 In-service & Ethylene Export Terminal, Storage and Ethylene Pipelines $0.5 2Q–3Q 2021 $0.0 Refined

Products PDH 2 Facility 2Q 2023

Petchem & 2020 2021 2022–2023 Other Petchem Projects 2Q–3Q 2021 & 2022 Estimated In-Service Date

* Excludes SPOT export terminal, which is pending permit approval Note: The table above includes a selection of highlighted projects, and may not represent the entirety of projects included in the monetary sums © All Rights Reserved. Enterprise Products Partners L.P. enterpriseproducts.com Page 2 Strengthening Debt Portfolio Extending Maturities Without Increasing Costs

$32.1 Billion Notes Issued 99.2% Fixed Rate Debt 2010–2020 (as of December 31, 2020) 21.0 6.5%

20.0 20.4 6.0% 9.0% 19.0 19.2 7.9% 5.8% 5.8% 19.1 Years

18.8 DebtCost of – 5.5% 18.0 5.5% 5.3% 17.7 17.6 83.1% in 17.0 17.3 17.3 52.5% >10 years 5.0%

Average Maturity Maturity Average 16.0 30.6% 16.2 4.8% 16.1 4.7% 4.7% 4.6% 4.6% 4.5% 15.0 4.5% 4.4% 14.9 14.0 4.0%

3 Year 5 Year 10 Year 30+ Year Weighted Avg Term to Maturity Average Cost of Debt

• Operational Distributable Cash Flow (“DCF”) represents DCF excluding proceeds from asset sales and property damage insurance claims and net receipts / payments from the monetization of interest rate derivative instruments. • Distributable Cash Flow (“DCF”) per Unit is determined by dividing DCF for a period by the average number of fully diluted common units outstanding for that period. • Net Cash Flows Provided by Operating Activities (“CFFO”) represents the GAAP financial measure “Net cash flows provided by operating activities”. • CFFO Payout Ratio is calculated as trailing 12 months distributions + distribution equivalent rights + buybacks per share divided by the trailing 12 months cash flow from operations. • Leverage is defined as net debt divided by adjusted EBITDA. • Adjusted EBITDA is adjusted earnings before interest, taxes, depreciation and amortization. • 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.

We measure cash available for distribution by reference to distributable cash flow (“DCF”). DCF is a quantitative standard used by the investment community for evaluating 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 to compute our distribution coverage ratio. Our calculation of DCF may or may not be comparable to similarly titled measures used by other companies. The GAAP financial measure most directly comparable to DCF is cash flow from operations (“CFFO”), otherwise referred to as net cash flows provided by operating activities. See “Investors – Non-GAAP Financial Measures” 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 2017–2020 (each ended December 31) (dollars in millions): Total 2017 Total 2018 Total 2019 Total 2020

Net income attributable to common unitholders (GAAP) $ 2,799.3 $ 4,172.4 $ 4,591.3 $ 3,774.7 Adjustments to GAAP net income attributable to common unitholders to derive DCF (addition or subtraction indicated by sign): Depreciation, amortization and accretion expenses 1,644.0 1,791.6 1,949.3 2,071.9 Cash distributions received from unconsolidated affiliates 483.0 529.4 631.3 614.1 Equity in income of unconsolidated affiliates (426.0) (480.0) (563.0) (426.1) Asset impairment and related charges 49.8 50.5 132.8 890.6 Change in fair market value of derivative instruments 22.8 16.4 27.2 (79.3) Change in fair value of Liquidity Option Agreement 64.3 56.1 119.6 2.3 Gain on step acquisition of unconsolidated affiliate - (39.4) - - Subtract sustaining capital expenditures (243.9) (320.9) (325.2) (293.6) Other, net 38.3 30.0 40.0 (127.4) Subtotal DCF, before proceeds from assets sales and monetization of interest rate derivative instruments accounted for as cash flow hedges 4,431.6 5,806.1 6,603.3 6,427.2 Proceeds from asset sales and insurance recoveries 40.1 161.2 20.6 12.8 Monetization of interest rate derivative instruments accounted for as cash flow hedges 30.6 22.1 - (33.3) Distributable cash flow (non-GAAP) 4,502.3 5,989.4 6,623.9 6,406.7 Adjustments to non-GAAP DCF to derive GAAP net cash flows 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) (767.5) Sustaining capital expenditures 243.9 320.9 325.2 293.6 Other, net (112.1) (200.2) 28.8 (41.3) Net cash flows provided by operating activities (GAAP) $ 4,666.3 $ 6,126.3 $ 6,520.5 $ 5,891.5

We evaluate segment performance based on our financial measure of gross operating margin (“GOM”). GOM 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. GOM is presented on a 100 percent basis before any allocation of earnings to noncontrolling interests. Our calculation of GOM may or may not be comparable to similarly titled measures used by other companies. The GAAP financial measure most directly comparable to total segment GOM is operating income. See “Investors – Non-GAAP Financial Measures” 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 2017–2020 (each ended December 31) (dollars in millions):

Total 2017 Total 2018 Total 2019 Total 2020 Gross operating margin by segment: NGL Pipelines & Services $ 3,258.3 $ 3,830.7 $ 4,069.8 $ 4,182.4 Crude Oil Pipelines & Services 987.2 1,511.3 2,087.8 1,997.3 Natural Gas Pipelines & Services 714.5 891.2 1,062.6 926.6 Petrochemical & Refined Products Services 714.6 1,057.8 1,069.6 1,081.8 Total segment gross operating margin (a) 5,674.6 7,291.0 8,289.8 8,188.1 Net adjustment for shipper make-up rights (b) 5.8 34.7 (24.1) (85.7) Total gross operating margin (non-GAAP) 5,680.4 7,325.7 8,265.7 8,102.4 Adjustments to reconcile non-GAAP gross operating margin to GAAP operating income (addition or subtraction indicated by sign): Depreciation, amortization and accretion expense in operating costs and expenses (1,531.3) (1,687.0) (1,848.3) (1,961.5) Asset impairment and related charges in operating costs and expenses (49.8) (50.5) (132.7) (890.6) Net gains or losses attributable to asset sales in operating costs and expenses 10.7 28.7 5.7 4.4 General and administrative costs (181.1) (208.3) (211.7) (219.6) Operating income (GAAP) $ 3,928.9 $ 5,408.6 $ 6,078.7 $ 5,035.1

(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.

Free cash flow (“FCF”) is a traditional cash flow metric that is widely used by investors and other participants in the financial community. In general, FCF is a measure of how much cash flow a business generates during a specified time period after accounting for all capital investments, including expenditures for growth and sustaining capital projects. We believe that FCF is important to investors since it reflects the amount of cash available for reducing debt, investing in additional capital projects, paying distributions, common unit repurchases and similar matters. Our calculation of FCF may or may not be comparable to similarly titled measures used by other companies. The GAAP financial measure most directly comparable to FCF is CFFO.

See “Investors – Non-GAAP Financial Measures” on our website (www.enterpriseproducts.com) for more information regarding FCF, including additional reconciliation detail. The following table presents our calculation of FCF for the years 2017–2020 (each ended December 31) (dollars in millions):

Total 2017 Total 2018 Total 2019 Total 2020

Net cash flow provided by operating activities (GAAP) $ 4,666.3 $ 6,126.3 $ 6,520.5 $ 5,891.5 Adjustments to reconcile GAAP net cash flow provided by operating activities to non-GAAP free cash flow (addition or subtraction by sign): Cash used in investing activities (a) (3,286.1) (4,281.6) (4,575.5) (3,120.7) Cash contributions from noncontrolling interests 0.4 238.1 632.8 30.9 Cash distributions paid to noncontrolling interests (49.2) (81.6) (106.2) (131.3) Free Cash Flow (non-GAAP) $ 1,331.4 $ 2,001.2 $ 2,471.6 $ 2,670.4

(a) Effective December 31, 2017, we applied the provisions of ASU 2016-18 which requires that restricted cash be presented as part of the reconciliation of the beginning of period and end of period total amounts shown on the statements of consolidated cash flows. The guidance was applied on a retrospective basis; therefore, we adjusted our historical statements of consolidated cash flows to remove the change in restricted cash from cash flows used in investing activities.

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. Our calculation of Adjusted EBITDA may or may not be comparable to similarly titled measures used by other companies. The GAAP financial measure most directly comparable to Adjusted EBITDA is CFFO. See “Investors – Non-GAAP Financial Measures” 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 2017–2020 (each ended December 31) (dollars in millions): Total 2017 Total 2018 Total 2019 Total 2020

Net income (GAAP) $ 2,855.6 $ 4,238.5 $ 4,687.1 $ 3,885.7 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 1,565.9 1,723.3 1,894.3 2,009.7 Interest expense, including related amortization 984.6 1,096.7 1,243.0 1,287.4 Cash distributions received from unconsolidated affiliates 483.0 529.4 631.3 614.1 Equity in income of unconsolidated affiliates (426.0) (480.0) (563.0) (426.1) Asset impairment and related charges 49.8 50.5 132.8 890.6 Provision for or benefit from income taxes 25.7 60.3 45.6 (124.3) Change in fair market value of commodity derivative instruments 23.1 16.2 (67.7) (79.3) Change in fair value of Liquidity Option Agreement 64.3 56.1 119.6 2.3 Gain on step acquisition of unconsolidated affiliate - (39.4) - - Other, net (10.7) (28.7) (5.7) (4.4) Adjusted EBITDA (non-GAAP) 5,615.3 7,222.9 8,117.3 8,055.7 Adjustments to non-GAAP Adjusted EBITDA to derive GAAP net cash flows provided by operating activities (addition or subtraction by sign): Interest expense, including related amortization (984.6) (1,096.7) (1,243.0) (1,287.4) Net effect of changes in operating accounts, as applicable 32.2 16.2 (457.4) (767.5) Other, net 3.4 (16.1) 103.6 (109.3) Net cash flows provided by operating activities (GAAP) $ 4,666.3 $ 6,126.3 $ 6,520.5 $ 5,891.5

• Randy Burkhalter – Vice President, Investor Relations . (713) 381-6812 . [email protected]

• Joe Theriac – Director, Finance & Investor Relations . (713) 381-6394 . [email protected]

• Libby Strait – Senior Manager, Investor Relations . (713) 381-4754 . [email protected]