INVESTOR DECK

August 2020

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.

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Page 2

Enterprise Products Partners L.P. (NYSE:EPD)

NGLs, Crude Oil, Natural Gas, Petrochemicals and Refined Products

Fully integrated

midstream

energy company

  • ≈50,000 miles of NGL, crude oil, natural gas, petrochemicals and refined products pipelines
  • ≈260 MMBbls of NGL, petrochemical, refined products and crude oil, and 14 Bcf of natural gas storage capacity
  • 22 natural gas processing facilities;
    24 fractionators; 11 condensate distillation facilities; PDH facility; iBDH facility
  • 19 deepwater docks handling NGLs, PGP, crude oil and refined products

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Page 3

Why EPD?

Diversification:

Geographic, Products

and Markets

Disciplined Allocator of

Capital - TTM June 2020:

CFFO Allocation:

Payout(1)

62%

Capital investment

38%

Funding Growth Capital(2):

CFFO (less distributions)

65%

Debt

35%

as of 2Q 2020

Market Capitalization:

≈$39B

Enterprise Value:

≈$70B

Daily Trading Value:

(last 20 days)

≈$134MM

as of August 7, 2020

Average

Return on Invested Capital(1):

12%

over the last 10 years

Among highest credit ratings in midstream space:

BBB+ / Baa1

TTM June 2020 Leverage(1):

3.4x reported

2020

$1.78/unit

2Q 2020 distribution annualized

1.6x distribution coverage

$2.5B-$3.0B

2020 Growth CAPEX

$2B buyback in place

(>$220MM repurchased to-date)

>21 consecutive years of distribution increases

Interests Aligned with Investors:

32% of common units owned by

Management

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

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Page 4

SUSTAINABILITY PERSPECTIVES

Global Population Growth

Development Drives Energy Demand

Global Population

12

Global Population

Year

Years to Grow

+1B People

10

1,000,000,000

1803

2,000,000,000

1927

124

3,000,000,000

1960

33

8

4,000,000,000

1975

15

5,000,000,000

1987

12

Billions

6,000,000,000

1999

12

8,000,000,000

2023E

12

6

7,000,000,000

2011

12

9,000,000,000

2037E

14

4

10,000,000,000

2057E

20

2

0

B.C.

0

Global Population

Population Markers

2000

Actual

Projected

Sources: OurWorldInData.org; History Database of Global Environment (HYDE);

United Nations, Department of Economic and Social Affairs, Population Division

(2019). World Population Prospects 2019, Online Edition. Rev. 1.

10.9 B 2100E

7.8 B 2020

6.1 B

2000

2.5 B

1950

1.7 B

1900

Industrial Revolution

1700

1800

1900

2000

2100

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Page 6

Population and Consumption Outlook Through 2050

Driven by Growth in Non-OECD Asia

Non-OECD vs. OECD(1) Population Forecast (EIA)

Non-OECD Energy Consumption by Region (EIA)

9

700

8

Non-OECD

600

7

Units

6

500

BritishThermal

Billions

5

400

4

300

Quadrillion

3

200

2

OECD

100

1

0

0

2010

2030

2050

2010

2020

2030

2040

2050

Reference case

Europe and Eurasia

Americas

Africa

Middle East

Asia

Source: EIA International Energy Outlook 2019

  1. OECD = Organization for Economic Cooperation and Development

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Page 7

U.N. Human Development Index (HDI)

HDI is a measure of human progress

Humanity has experienced significant

in terms of health, education and income

gains in HDI around the world since 1990

Long and

Knowledge

Decent

Global Population 1990

Standard

Healthy Life

of Living

Life Expectancy

Years of

Gross National

62%

at Birth

Education

Income per capita

5.3 Billion

Low HDI

Human Development Index (HDI)

HDI Classifications(1)

Global Population 2018

Low

Least Developed

Medium

High

7.6 Billion

12%

Very High

Most Developed

Low HDI

Source: United Nations Development Programme; Human Development Index

  1. http://hdr.undp.org/sites/default/files/hdr2019_technical_notes.pdf

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Page 8

Energy is Essential for HDI Improvement

Very

High

High

Medium

Low

Human Development Index (HDI)

A strong positive correlation exists between

HDI & energy use per capita

0.98

Size of Circles Depicts Relative Size Population

U.S.

0.88

0.78China

0.68

India

As energy use per

0.58capita increases, HDI increases

0.48

0.38

0.28

0

2,000

4,000

6,000

8,000

Energy Use per Capita (kg of oil equivalent)

India and China have made significant gains in HDI since 1990, as energy use per capita increased

0.95

Size of Circles Depicts Relative Size Population

U . S .

0.85

(HDI)

China 2018

0.75

0.76

Index

High HDI

0.65

India 2018

Development

0.65

0.45

India 1990

Low HDI

Medium HDI

0.55

China 1990

Human

0.50

0.43

Low HDI

0.35

0.25

-

500

1,000

1,500

2,000

2,500

3,000

Energy Use per Capita

(kg of oil equivalent)

India 1990 to 2018

China 1990 to 2018

Mean education increased 2.2x;

Mean education increased 1.6x;

Life expectancy increased 11.5 yrs

Life expectancy increased: 7.4 yrs

Source: World Bank and United Nations Development Programme 2018

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Page 9

Global Energy Expectations; Transition?

All of the Above Energy Approach Needed

Global End-use Energy Consumption by Fuel

2019

2050 Expected

453 quadrillion Btus(1)

623 quadrillion Btus(1)

energy consumption

Electricity Natural Gas

Renewables

18%

20%

Electricity

Natural Gas

energy consumption

5%

23%

22%

Coal

Petroleum

Renewables

15%

5%

42%

Coal

Petroleum

13%

37%

EIA International Energy Outlook Expectations

Most economic growth will

occur in non-OECD

Most energy-intensive

countries where GDP per

manufacturing is expected

person is projected to

to shift to non-OECD Asia,

nearly triple from

and, increasingly to India

2018 to 2050

  1. Btu = British thermal unit

The industrial sector is expected to remain the largest consumer of energy, with energy-intensive manufacturing being the largest component

in the sector

Source: EIA International Energy Outlook 2019

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Page 10

Non-OECD Asia Has Little Wind and Solar Potential

  • While growing applications for wind and solar energy sources exist, there are limitations to their scalability
  • As depicted in the graphic below, the most suitable locations for broad-scale wind and solar power generation have minimal overlap with global population concentrations

Global Wind & Solar Potential

within 1,000 miles of a major city

Over half of the

global population lives in this circle, with limited wind & solar potential

Source: Zeihan on Geopolitics

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Page 11

EPD Environmental, Social, Governance (ESG)

"The way we do business is as important as the business we do." - Dan Duncan, Founder

We are Committed to...

Sustainable

Our People

The Durability

& Our

of

Operations

Communities

Our Business

2020 ESG Focus:

  • Commitment to the environment and to landowners
  • Maintaining our assets and the reliability of our systems
  • Supporting our people through unprecedented times
  • Board and executive alignment on sustainability, including compensation metrics

More information on EPD's ESG efforts can be found in our recently published

2019-2020 Sustainability Report, available on our website at www.enterpriseproducts.com

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Page 12

FUNDAMENTALS

U.S. Crude Oil Supply Forecast

U.S. Oil and Condensate Forecast

14

3,600

13

3,200

12

2,800

Production

11

2,400

Completions per Month

Production MMBPD

10

2,000

9

1,600

8

1,200

Oil

High Price Scenario $60-$70/Bbl

7

800

Oil Completions

Low Price Scenario $40-$50/Bbl

6

400

Normalized

5

Historical

Forecast

0

Jan-16

Jan-17

Jan-18

Jan-19

Jan-20

Jan-21

Jan-22

Jan-23

Jan-24

Jan-25

Model Update: August 7, 2020

Source: EPD Fundamentals

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Page 14

Global Oil Balances Expected to Drain

OECD Crude Stocks are ≈200 MMBbls Above 5 year Average per IEA Estimates

Forecasted Crude Oil Supply & Demand

Compared to 2019

Annual Average in MMBPD

2019

2020

2021

Crude Oil Supply

change vs. 2019

U.S. Production*

12.04

(0.75)

(1.25)

OPEC+ Production

42.12

(4.24)

(4.00)

Others:

non-OPEC+**

19.50

(0.63)

(1.50)

Venezuela, Libya, Iran

4.25

(1.33)

(0.28)

Brazil, Norway, Guyana

4.19

0.65

0.90

Total Supply

82.10

(6.29)

(6.13)

Total Crude Oil Demand

81.8

(6.75)

(2.20)

Crude Balance

0.30

0.46

(3.93)

Over/(Under)

  • In addition to oil, global NGL balances are expected to trend tighter as the

U.S. is the world's incremental supplier of NGLs

*Includes ≈300 MBPD of permanent shutins **non-OPEC+ and excludes U.S., Brazil, Norway and Guyana

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Page 15

U.S. Waterborne Crude Exports

U.S. Crude Exports

MMBPD

4.0

3.5

3.0

2.5

2.0

1.5

1.0

0.5

0.0

Jan-20

Feb-20

Mar-20

Apr-20

May-20

Jun-20

Jul-20

Houston

Corpus Christi

All Other Terminals

2019 Average

Source: RBN Vessel Tracking

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Page 16

U.S. Waterborne NGL Exports

MMBPD

U.S. NGL Exports

YTD + 14% increase year-over-year

2.0

1.63 MMBPD

1.43 MMBPD

1.8

1.6

1.4

1.2

1.0

0.8

0.6

0.4

0.2

0.0

Sep-19Nov-19

Ethane

Butane

Propane

  • Exports remained strong due to global residential demand as well as petrochemical demand driven by personal protective equipment needs related to COVID-19

Source: IHS Waterborne

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Page 17

YTD 2020: 54% of U.S. NGL Exports went to Asia

EPD Export Facilities Handled >40% of Total Exported Volumes

Europe: 13%

Far East Asia: 48%

of U.S. NGL Exports

of U.S. NGL Exports

YTD 2020 Total U.S.

Exported NGLs: 346 MMBbls

C2: 38 MMBbls

C3: 241 MMBbls

Indian Ocean: 6%

C4: 66 MMBbls

of U.S. NGL Exports

Other Countries: 19%

of U.S. NGL Exports

LatAm: 13%

of U.S. NGL Exports

Note: YTD includes January-July 2020

Source: IHS Waterborne

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Page 18

Petrochemical Market Update

Olefin Prices in Asia

60.0

50.0

40.0

Pound

30.0

Cents per

20.0

10.0

0.0

Jul-19

Oct-19

Jan-20

Apr-20

Jul-20

Asia Ethylene

Asia Propylene

Asia Butadiene

  • The COVID-19 pandemic created new demand for single-use plastics (ethylene) and strong demand for health-care PPE and household cleaners (propylene), while demand for auto-related applications (butadiene) continues to lag
  • U.S. is a price competitive supplier of feedstocks and olefins
    • EPD facilities export ethane, ethylene, propane and propylene

Cracker Insight

Tons Yielded per Ton Feedstock

Feedstock

Ethane

Naphtha

Derivative

Ethylene

0.78

0.31

Butadiene +

0.02

0.09

Propylene

0.03

0.16

Butylene

Sources: Bloomberg and EPD Fundamentals

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Page 19

EPD Facility Exports Remain Resilient

MMBPD

2.5

2.0

1.5

1.0

0.5

0.0

Exports at EPD Facilities

Jan-19

Apr-19

Jul-19

Oct-19

Jan-20

Apr-20

Jul-20

NGL

Crude

Petchem & Refined Products

Source: EPD

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Page 20

FINANCIAL UPDATE

EPD Durable Cash Flows

Through Business Cycles

CFFO per Unit & Distribution per Unit

Gross Operating Margin and DCF

$100

$160

$2,500

$90

$2.96

$2.96

$140

$80

$2.80

$2,000

$120

$70

$2.20

$2.10

$2.17

$60

$1.92

$2.00$1.95

$100

$1,500

$/Bbl

$/Bbl

$40

$1.22

$1.21

$1.61

$80

$50

$1.59

$1.56$1.47

$60

$1,000

$30

$0.56$0.73

$40

$500

$20

$0.77

$0.85

$0.91

$0.97

$1.04

$1.10

$1.16

$1.22

$1.29

$1.37

$1.45

$1.53

$1.61

$1.68

$1.73

$1.77

$1.78

$20

$10

$0

$-

$0

$3.50

$3.00

$2.50

$2.00

$1.50

$1.00

$0.50

$-

$/unit

WTI Crude EPD Gross Operating Margin EPD DCF w/o Non Recurring

Returns on Invested Capital(1)

$100

12.9%

13.3%

13.1%

13.3%

$80

10.5%

11.8%

10.8%

11.4%

11.2%

11.6%

12.5%

11.0%

10.2%

10.7%

12.6%

12.5%

$/Bbl

$60

$40

$20

$0

ROIC

WTI Crude

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Distribution per unit

CFFO Per Unit

WTI Crude

14.0%

12.0%

• Delivered consistent results

10.0%

throughout cycles which supported

8.0%

distribution growth and built a margin

6.0%

of safety through excess coverage

4.0%

• Generated Returns on Invested

2.0%

Capital(1) of 12% on average since 2005

0.0%

* For GOM and DCF, please see the non-GAAP reconciliation

section of this presentation for the closest GAAP measure

(1)

See definitions

Source for WTI Crude Price: Bloomberg

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Page 22

* Excludes SPOT export terminal, which is pending permit approval

EPD 2020 Financial Outlook

Capital Expenditure Updates

  • 2020 Growth Capital Forecast: ≈$2.5-$3 billion
  • Currently forecasting 2021 and 2022 growth capital of ≈$2.3 billion and $1 billion, respectively*
      • Based on sanctioned projects to date
    • Continuing to negotiate JV opportunities which could further reduce growth capital expenditures
  • Continue to invest in quality projects
    • Supported by high quality customers, long-termfee-based contracts
  • 2020 sustaining capital expenditures: $300 million

Maintain and Protect Balance Sheet

  • Leverage(1) 3.5x target area; 12 months ended June 30, 2020 was 3.4x
  • Liquidity(2): $7.3 billion comprised of available credit capacity and unrestricted cash

Returning Capital to Investors

  • Distribution declared with respect to 2Q 2020 was held flat to 1Q 2020 at $0.445/unit payment
    • Plan to evaluate distribution growth quarterly
  • CFFO Payout Ratio(1): 83%(3) for 2Q 2020 and 62% for TTM 2Q 2020

(1) See definitions

  1. As of June 30th, 2020
  2. Our payout ratio for 2Q 2020 was higher than normal as a result of increased use of cash for working capital for marketing opportunities (including contango)

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Page 23

2Q 2020 Financial Results

$2.0B $8.1B $2.0B $8.0B 3.4x $1.2B $6.5B $2.7B

  • Total Gross Operating Margin (GOM)* 2Q 20
  • Total GOM* Trailing 12 Months 2Q 20
  • Adjusted EBITDA* 2Q 20
  • Adjusted EBITDA* Trailing 12 Months 2Q 20
  • Leverage
    (Net Debt / 12 Month Adjusted EBITDA*)
  • Net Cash Flow Provided by Operating Activities ("CFFO") 2Q 20
  • CFFO Trailing 12 months 2Q 20
  • Free Cash Flow ("FCF")* Trailing 12 Months 2Q 20

Gross Operating Margin

TTM June 2020

NatGas

12%

Petchem

& RP

12%

$8.1B

51%

NGLs

Crude

25%

* For GOM, adjusted EBITDA and FCF, please see the non-GAAP reconciliation section of this presentation for the closest GAAP measure

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Page 24

Capital Projects Under Construction

Highlighted Major Capital Projects

Forecast

In-Service

NaturalGas Liquids

Mont Belvieu Area Fractionators 10 & 11

In-service & 3Q 2020

Texas Express & Front Range Expansions

In Service

EHT LPG & PGP Export Expansion (refrigeration)

On Hold

C5 Hydrotreater

2021+

Gas

Natural Gas Pipeline to Carthage (Panola-related)

4Q 2020

Permian Gathering & Residue Lines

2021+

Natural

Gillis Lateral & Acadian Haynesville Expansion

4Q 2021

Permian Gathering & Condensate Projects

In Service

Midland-to-ECHO 3 Pipeline

3Q 2020

Oil

EHT Dock 1A Layberth & Expansion

In-Service & On Hold

Crude

EFS Projects & Other Tank Projects

3Q 2020 & In-Service

Midland & ECHO Tank Expansions (support M2E3)

1Q 2021

in B

Midland-to-ECHO 4 Pipeline

2H 2021

$

Mont Belvieu Area DIB 2

3Q 2020

Petchem& Refined Products

Ethylene Export Expansion (tank) & Ethylene Pipelines

4Q 2020

PDH 2 Facility

2Q 2023

Major Capital Projects Under Construction

NGLs

16%

Petchem

$6.6B

Natural

Ref. Prod.

12%

&

Gas

40%

total

Crude

32%

Current Projects Under Construction

$5

$4.7

$4

$3

$2

$1.4

$1

$0.5

$0.2

$0.5

$0

1Q 20

2Q 20

3Q 20

4Q 20

21+

Estimated In-Service Date

Note: The table above includes a selection of highlighted projects, and may not represent all of the projects included in the monetary sums.

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Page 25

APPENDIX

Estimated Breakeven Prices

Oil 20% ROR Breakeven

Average Well

Highgrade Well

$70.00

$60.00

$50.00

$40.00

$/Bbl

$30.00

$20.00

$10.00

$0.00

DJ Powder River HZ SCOOP STACK Oil Eagle Ford Bakken Eagle Ford Oil Delaware HZL Midland HZL Condensate

Assumes $2.50/MMBtu gas price, approximately $17.50/bbl NGL price, includes gas basis differentials

Source: EPD Fundamentals

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Page 27

Natural Gas Liquids Assets

Existing Assets

Project Highlights (Expected)

•

19,900 miles of pipelines

• Mont Belvieu area fractionator

•

22 natural gas processing facilities

3Q 2020 forecast in-service

11.4 Bcf/d gross capacity

Adds 150 MBPD

  • 17 fractionators
    • 1.4 MMBPD gross capacity
  • 179 MMBbls of storage
  • Export terminals
    • 7 LPG docks
    • 2 ethane docks

Export Terminal

Fractionation

Gas Processing

Storage

Pipelines

Note: mileage figures and capacities are approximate

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Page 28

Crude Oil Assets

Existing Assets

  • 5,300 miles of pipelines
    • 3 MMBPD of gross capacity
  • 71 MMBbls of storage
  • 14 export docks

Project Highlights (Expected)

  • Midland-to-ECHO3 pipeline
    • 3Q 2020 forecast in-service
    • Adds 450 MBPD when fully complete
  • Midland and ECHO tank expansions
    • 1Q 2021 forecast in-service
    • Adds 2.4 MBbls of storage
  • Midland-to-ECHO4 pipeline
    • 2H 2021 forecast in-service
    • Adds 450 MBPD
  • Sea Port Oil Terminal (SPOT)
    • Proposed offshore oil terminal capable of fully loading VLCCs
    • Subject to governmental approvals, permit process pending

Terminal

Storage

Export Terminal

Pipelines

Note: mileage figures and capacities are approximate

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Page 29

Natural Gas Assets

Existing Assets

  • 19,400 miles of pipelines
  • 22.2 Bcf/d gross capacity
    • 11.8 Bcf/d gathering and
      10.4 Bcf/d intrastate
  • 2.0 Bcf/d natural gas treating
  • 14.2 Bcf/d storage

Project Highlights (Expected)

• Pipeline to Carthage (Panola-related)

4Q 2020 forecast in-service

• Gillis lateral and Acadian expansion

4Q 2021 forecast in-service

• Permian gathering and residue lines

2021+ forecast in-service

Gas Treater

Storage

Pipelines

Note: mileage figures and capacities are approximate

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Page 30

Petrochemical Midstream and Refined Products Assets

Petrochemical Midstream Existing Assets

  • 800 miles of petrochemical pipelines
  • 7 Propylene fractionators
    • 116 MBPD gross capacity
  • 1 PDH; 25 MBPD gross PGP capacity
  • 3 Butane isomerization and 9 deisobutanizer ("DIB") units
    • 116 MBPD and 139 MBPD capacity, respectively
  • Isobutane Dehydrogenation ("iBDH") unit
    • 25 MBPD capacity
  • Octane Enhancement and High Purity Isobutylene ("HPIB") facilities
  • Petrochemical storage
  • Ethylene export facility at Morgan's Point
  • PGP & MTBE export docks at Houston Ship Channel

Refined Products Existing Assets

  • 3,300 miles of refined products pipelines
  • 33 MMBbls storage
  • Export terminals at Houston Ship Channel and Beaumont
  • Barge / Marine fleet

Project Highlights (Expected)

  • Mont Belvieu Area DIB 2
    • 3Q 2020 forecast in-service
  • Ethylene Export storage and pipelines
    • 4Q 2020 forecast in-service
  • PDH 2 Facility
    • 2Q 2023 forecast in-service

Storage

Export Terminal

Mont Belvieu

RP & Petchem pipelines

Note: mileage figures and capacities are approximate

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Page 31

Strengthening Debt Portfolio

Extending Maturities Without Increasing Costs

$32.1 Billion Notes Issued

99.2% Fixed Rate Debt

2010-August 2020

21.0

(as of August 7, 2020)

6.5%

20.0

20.1

6.0%

9.0%

Years

19.0

7.9%

5.8%

5.8%

19.2

18.8

AverageMaturity -

5.5%

Debt of Cost

18.0

5.5%

4.8%

16.0

16.2

83.1% in

5.3%

17.7

17.6

52.5%

>10 years

17.0

17.3

17.3

5.0%

30.6%

4.7%

16.1

4.7%

4.5%

4.6%

15.0

4.5%

4.4%

14.9

14.0

4.0%

3 Year

5 Year

10 Year

30+ Year

Average Maturity to First Call Date

Average Cost of Debt

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Page 32

Funding Growth with Financial Discipline

$8.0

$7.8

$4.6

4.4x

4.5x

$7.0

$6.2

4.1x

$6.0

(1)

4.2x

4.x

/ Adjusted EBITDA

$2.5

3.8x

$ in Billions

$5.0

3.5x

3.5x

3.4x

$4.0

$3.7

$4.1

3.3x

3.5x

$4.2

$0.2

$3.9

$3.7

$1.0

$3.1

$3.7

$3.0

$3.2

$0.2

3.x

Debt

$2.7

$2.9

Net

$2.0

$1.8

2.5x

$1.0

$0.0

2.x

2013

2014

2015

2016

2017

2018

2019

1H 2020

Organic Growth Capital(2)

Acquisitions

Debt Leverage Ratio(3)

  1. Proforma includes full year EBITDA for Oiltanking
  2. Growth capital investment net of contributions from JV partners
  3. Reflects leverage for the trailing 12 months ended at the conclusion of each period

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Indicative Attribution of Gross Operating Margin

Gross Operating Margin in $Billions

$9.0

$8.0

$7.0

$6.0

$5.0

$4.0

$3.0

$2.0

$1.0

$0.0

$8.3B

$7.3B

10%

4%

8%

6%

$5.2B

$5.7B

6%

5%

5%

4%

$4.0B

86%

9%

86%

3%

89%

fee-based

91%

fee-based

fee-based

fee-based

88%

fee-based

2016

2017

2018

2019

1H 2020

Fee-Based

Commodity Price-Based

Differential-Based

Total gross operating margin is a Non-GAAP measure. For a reconciliation of these amounts to their nearest GAAP counterparts, see "Non-GAAP Financial Measures" on our website. Excludes non-cash MTM results for respective periods

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Indicative Attribution of Segment GOM: 1H 2020

(4) % Breakout of GOM

100%

9%

10%

15%

10%

4%

2%

80%

9%

60%

40%

91%

86%

76%

88%

fee-based

fee-based

fee-based

fee-based

20%

0%

NGL Segment (1)

Crude Segment

Natural Gas Segment(2)

Petchem & Refined(3)

Products Segment

Fee-Based

Commodity Price-Based

Differential-Based

Based on Gross Operating Margin

  1. Differential-basedmay include: marketing transactions such as spot exports, location differentials, or commodity differentials, and keepwhole gas processing agreements. Commodity-based may include: percent of liquids and percentage of proceeds gas processing agreements
  2. San Juan gathering generates commodity sensitive earnings, while natural gas marketing includes Waha to Carthage and Waha to Houston transportation differentials
  3. Largest differential contribution was from propylene fractionation and refined products marketing
  4. The above figures exclude non-cash MTM results for the segments

Total gross operating margin is a Non-GAAP measure. For a reconciliation of these amounts to their nearest GAAP counterparts, see "Non-GAAP Financial Measures" on our website.

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Indicative Attribution of GOM for Select Businesses

$600

Natural Gas Processing GOM

$0.50

$500

$500

$0.40

$Millions

$400

$356

Spread

$0.30

$300

GOM in

$244

$0.20

Price

$200

$169

57%

70%

$0.10

$100

81%

68%

$50

$0

100%

$0.00

1H 2020(1)

2016

2017

2018

2019

Fee

POP & POL

Keepwhole

Indicative Processing Spreads ($/Gal)

$500

Propylene Activities GOM & Related Spreads

$0.80

Octane Enhancement, HPIB, iBDH GOM & Related Spreads

$463

$445

$180

$166

$1.20

$450

$0.70

$160

$154

$1.00

$400

$140

$0.60

$350

$123

GOM in $Millions

GOM in $Millions

$120

$0.80

$300

$0.50

Price Spread

$106

Price Spread

$100

$250

$0.40

$0.60

$212

$222

$80

$200

$0.30

74%

79%

$169

$60

$0.40

$150

$42

62%

$0.20

61%

$100

$40

55%

57%

$0.20

70%

69%

87%

$0.10

$50

$20

60%

$0

$0.00

$0

$0.00

2016

2017

2018

2019

1H 2020

2016

2017

2018

2019

1H 2020

Fee

Non-Fee

Spread PGP vs RGP ($/Gal)

Fee

Non-Fee

Spread RBOB vs Butane ($/Gal)

The above figures exclude non-cash MTM results for the segments

  1. Commodity exposed earnings were offset by negative hedging impacts

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Indicative Attribution of Gross Operating Margin

Slides 34-36 attribute gross operating margin (GOM) among fee-based,commodity-based and differential-based business activities. Most activities fit easily into one category; however, the classification of certain activities involves an element of subjectivity. The classifications reflected in the preceding slides represent what we currently believe is the most logical fit of our business activities into the categories described below, based on the underlying fee or pricing characteristics applicable thereto.

These classifications may be subject to change in the event that management's estimates or assumptions underlying such classifications are revised or updated. In addition, our attribution of GOM into the categories described below may not be comparable to similar classifications by other companies because such companies may use different estimates and assumptions than we do in defining such categories or otherwise calculating such attributions.

Three categories of GOM:

  • Fee-based: Pipeline transportation fees and tariffs, NGL and propylene fractionation fees, storage capacity reservation and throughput fees, export terminal fees, marine and trucking fees, fee-based natural gas processing arrangements, isomerization and dehydrogenation fees, demand and deficiency fees, and similar activities that are predominantly fee-oriented.
  • Commodity-based:Percentage-of-liquids and percentage-of-proceeds natural gas processing arrangements, certain condensate sales, gathering revenues on our San Juan natural gas pipeline system, and similar activities that have commodity price exposure.
  • Differential-based: Certain business activities where earnings are generated based on price differentials or spreads between locations, time periods and products in excess of any related fees, tariffs and other expenses.

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Definitions

  • 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.
  • 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 Yield is calculated as trailing 12 month CFFO per share divided by stock price.
  • Free Cash Flow ("FCF") per Unit is calculated as the free cash flow divided by the number of fully diluted common units outstanding for that period.
  • Total Return is defined as distribution yield plus price appreciation.
  • Price / Earnings is defined as current share price relative to trailing 12 months earnings per share.
  • Price / Cash Flow is defined as current share price relative to trailing 12 months cash flow from operations divided by the basic weighted average number of shares.
  • CFFO Payout Ratio is calculated as trailing 12 months distribution 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.
  • EV / EBITDA is calculated as Enterprise Value divided by estimated EBITDA.

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NON-GAAP RECONCILIATIONS

Distributable Cash Flow

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 each of the three years ended December 31, 2019 or periods presented below (dollars in millions):

Total 2017

Total 2018

Total 2019

1Q 2020

2Q 2020

Total 2020

Net income attributable to limited partners (GAAP)

$

2,799.3

$

4,172.4

$

4,591.3

$

1,350.1

$

1,034.7

$

2,384.8

Adjustments to GAAP net income attributable to limited partners to derive DCF

(addition or subtraction indicated by sign):

Depreciation, amortization and accretion expenses

1,644.0

1,791.6

1,949.3

509.0

522.7

1,031.7

Cash distributions received from unconsolidated affiliates

483.0

529.4

631.3

137.2

178.4

315.6

Equity in income of unconsolidated affiliates

(426.0)

(480.0)

(563.0)

(140.8)

(113.3)

(254.1)

Change in fair market value of derivative instruments

22.8

16.4

27.2

(29.5)

(61.9)

(91.4)

Change in fair value of Liquidity Option Agreement

64.3

56.1

119.6

2.3

-

2.3

Gain on step acquisition of unconsolidated affiliate

-

(39.4)

-

-

-

-

Subtract sustaining capital expenditures

(243.9)

(320.9)

(325.2)

(68.9)

(74.0)

(142.9)

Other, net

88.1

80.5

172.8

(173.1)

87.2

(85.9)

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

1,586.3

1,573.8

3,160.1

Proceeds from asset sales and insurance recoveries

40.1

161.2

20.6

0.6

3.5

4.1

Monetization of interest rate derivative instruments accounted for as cash flow hedges

30.6

22.1

-

(33.3)

-

(33.3)

Distributable cash flow (non-GAAP)

4,502.3

5,989.4

6,623.9

1,553.6

1,577.3

3,130.9

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)

341.7

(430.7)

(89.0)

Sustaining capital expenditures

243.9

320.9

325.2

68.9

74.0

142.9

Other, net

(112.1)

(200.2)

28.8

48.0

(39.0)

9.0

Net cash flows provided by operating activities (GAAP)

$

4,666.3

$

6,126.3

$

6,520.5

$

2,012.2

$

1,181.6

$

3,193.8

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Gross Operating Margin

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 each of the three years ended December 31, 2019 or periods presented below (dollars in millions):

Total 2017

Total 2018

Total 2019

1Q 2020

2Q 2020

Total 2020

Gross operating margin by segment:

NGL Pipelines & Services

$

3,258.3

$

3,830.7

$

4,069.8

$

1,042.0

$

968.1

$

2,010.1

Crude Oil Pipelines & Services

987.2

1,511.3

2,087.8

452.9

634.4

1,087.3

Natural Gas Pipelines & Services

714.5

891.2

1,062.6

283.8

208.9

492.7

Petrochemical & Refined Products Services

714.6

1,057.8

1,069.6

278.5

191.5

470.0

Total segment gross operating margin (a)

5,674.6

7,291.0

8,289.8

2,057.2

2,002.9

4,060.1

Net adjustment for shipper make-up rights (b)

5.8

34.7

(24.1)

(9.7)

(4.5)

(14.2)

Total gross operating margin (non-GAAP)

5,680.4

7,325.7

8,265.7

2,047.5

1,998.4

4,045.9

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)

(482.8)

(494.3)

(977.1)

Asset impairment and related charges in operating costs and expenses

(49.8)

(50.5)

(132.7)

(1.6)

(11.8)

(13.4)

Net gains or losses attributable to asset sales in operating costs and expenses

10.7

28.7

5.7

(0.1)

1.6

1.5

General and administrative costs

(181.1)

(208.3)

(211.7)

(55.5)

(57.0)

(112.5)

Operating income (GAAP) (c)

$

3,928.9

$

5,408.6

$

6,078.7

$

1,507.5

$

1,436.9

$

2,944.4

  1. 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.
  2. 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.

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Free Cash Flow

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 each of the three years ended December 31, 2019 or periods presented below (dollars in millions):

Total 2017

Total 2018

Total 2019

1Q 2020

2Q 2020

Total 2020

Net cash flow provided by operating activities (GAAP)

$

4,666.3

$

6,126.3

$

6,520.5

$

2,012.2

$

1,181.6

$

3,193.8

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)

(1,071.7)

(858.8)

(1,930.5)

Cash contributions from noncontrolling interests

0.4

238.1

632.8

5.2

14.5

19.7

Cash distributions paid to noncontrolling interests

(49.2)

(81.6)

(106.2)

(29.9)

(31.9)

(61.8)

Free Cash Flow (non-GAAP)

$

1,331.4

$

2,001.2

$

2,471.6

$

915.8

$

305.4

$

1,221.2

  1. 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.

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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. 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 each of the three years ended December 31, 2019 or periods presented below (dollars in millions):

Total 2017

Total 2018

Total 2019

1Q 2020

2Q 2020

Total 2020

Net income (GAAP)

$

2,855.6

$

4,238.5

$

4,687.1

$

1,375.0

$

1,060.8

$

2,435.8

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

494.5

507.1

1,001.6

Interest expense, including related amortization

984.6

1,096.7

1,243.0

317.5

320.2

637.7

Cash distributions received from unconsolidated affiliates

483.0

529.4

631.3

137.2

178.4

315.6

Equity in income of unconsolidated affiliates

(426.0)

(480.0)

(563.0)

(140.8)

(113.3)

(254.1)

Provision for or benefit from income taxes

25.7

60.3

45.6

(179.2)

59.7

(119.5)

Change in fair market value of commodity derivative instruments

23.1

16.2

(67.7)

(29.5)

(61.9)

(91.4)

Change in fair value of Liquidity Option Agreement

64.3

56.1

119.6

2.3

-

2.3

Gain on step acquisition of unconsolidated affiliate

-

(39.4)

-

-

-

-

Other, net

39.1

21.8

127.1

1.7

10.2

11.9

Adjusted EBITDA (non-GAAP)

5,615.3

7,222.9

8,117.3

1,978.7

1,961.2

3,939.9

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)

(317.5)

(320.2)

(637.7)

Net effect of changes in operating accounts, as applicable

32.2

16.2

(457.4)

341.7

(430.7)

(89.0)

Other, net

3.4

(16.1)

103.6

9.3

(28.7)

(19.4)

Net cash flows provided by operating activities (GAAP)

$

4,666.3

$

6,126.3

$

6,520.5

$

2,012.2

$

1,181.6

$

3,193.8

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Investor Relations Contact Information

  • Randy Burkhalter - Vice President, Investor Relations
    • (713) 381-6812
    • rburkhalter@eprod.com
  • Jackie Richert - Senior Director, Investor Relations
    • (713) 381-3920
    • jmrichert@eprod.com
  • Libby Strait - Manager, Investor Relations
    • (713) 381-4754
    • ecstrait@eprod.com

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Enterprise Products Partners LP published this content on 11 August 2020 and is solely responsible for the information contained therein. Distributed by Public, unedited and unaltered, on 11 August 2020 12:18:07 UTC