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ENTERPRISE PRODUCTS PARTNERS L.P.

enterpriseproducts.com© ALL RIGHTS RESERVED. ENTERPRISE PRODUCTS PARTNERS L.P.

MLPA INVESTOR CONFERENCEMay 31–June 2, 2017

© ALL RIGHTS RESERVED. ENTERPRISE PRODUCTS PARTNERS L.P. 2

FORWARD–LOOKING STATEMENTS

This presentation contains forward‐looking statements based on the beliefs of the company, as wellas assumptions made by, and information currently available to our management team. When usedin this presentation, words such as “anticipate,” “project,” “expect,” “plan,” “seek,” “goal,”“estimate,” “forecast,” “intend,” “could,” “should,” “will,” “believe,” “may,” “scheduled,”“potential” and similar expressions and statements regarding our plans and objectives for futureoperations, are intended to identify forward‐looking statements.

Although management believes that the expectations reflected in such forward‐looking statementsare reasonable, it can give no assurance that such expectations will prove to be correct. You shouldnot 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 todiffer materially from those expected, including insufficient cash from operations, adverse marketconditions, governmental regulations, the possibility that tax or other costs or difficulties relatedthereto will be greater than expected, the impact of competition and other risk factors discussed inour latest filings with the Securities and Exchange Commission.

All forward‐looking statements attributable to Enterprise or any person acting on our behalf areexpressly qualified in their entirety by the cautionary statements contained herein, in such filingsand in our future periodic reports filed with the Securities and Exchange Commission. Except asrequired by law, we do not intend to update or revise our forward‐looking statements, whether as aresult of new information, future events or otherwise.


KEY INVESTMENT CONSIDERATIONS

One of the largest integrated midstream energy companies • Integrated system enables EPD to reduce impact of cyclical commodity swings

• Large supply aggregator and access to domestic and international markets provides market optionality to producers and consumers

History of successful execution of growth projects and M&A• ≈$38 billion of organic growth projects and $26 billion of major acquisitions since IPO in 1998 through 2017E

• ≈$8.4 billion of capital growth projects under construction• New projects under development

Low cost of capital; financial flexibility• One of the highest credit ratings among MLPs: Baa1 / BBB+

• Simplified structure with no GP IDRs for long‐term durability and flexibility

• Margin of safety with average distribution coverage of ≈1.2x and ≈$675 million of retained DCF in last 12 months (excludes non‐recurring items)

• Consistent distribution growth: 51 consecutive quarters

Financially strong, supportive GP committed for the long‐term


EPD’S UNIQUE ADVANTAGESignificant & Supportive Insider Ownership

Note: as of April 30, 2017

Supportive and unlevered GP with significant ownership • EPCO and affiliates own 32% of LP units (no structural subordination –all unitholders are aligned)

• Facilitated elimination of IDRs in a non‐taxable transaction through waiver of ≈$322 million in distributions from 2011 through 2015 – no backdoor distribution cuts

• Purchased ≈$1.6 billion in EPD units since IPO

68.0% L.P.Interest

EPCO & Affiliates

32.0% L.P.Interest

Public General Partner

Non‐economicG.P. Interest

100%

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


0%

50%

100%

150%

200%

250%

300%

350%

400%

EPD Unit Price AMZ Index XLE ETF WTI Crude

SUCCESSFUL EXECUTION THROUGHOUT CYCLESIncreased Cash Distributions for 51 Consecutive Quarters

(1) Total gross operating margin and distributable cash flow represent reported amounts. For a reconciliation of these amounts to their nearest GAAP counterparts, see “Non‐GAAP Financial Measures” on our website.(2) Excludes non‐recurring cash transactions (e.g., proceeds from asset sales and property damage insurance claims and payments to settle interest rate hedges).

MLP Equities: Higher Correlation to Crude for Last 30 Months EPD Has Delivered Consistent Results Throughout Cycles…

…Which Has Supported Distribution Growth… …While Building a Margin of Safety for Future Growth

Sources: EPD and Bloomberg

Correlation to WTI Total Since 2Q'14EPD Unit Price 0.21 0.84AMZ Index 0.49 0.85XLE ETF 0.63 0.94 $0

$20

$40

$60

$80

$100

$120

$140

$160

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

$/Bb

l

$ millions

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

Total Gross Operating Margin(1)

Distributable Cash Flow(1,2)

$0

$20

$40

$60

$80

$100

$120

$140

$160

$0.0

$0.2

$0.4

$0.6

$0.8

$1.0

$1.2

$1.4

$1.6

$1.8

$2.0

$/Bb

l

$/un

it

Annualized Distribution per Unit WTI Crude

CAGR: EPD Distribution per Unit2Q 2004–1Q 2017 6.5%Last 3 Years 5.3%1 Year 5.1% $0

$200

$400

$600

$800

$1,000

$1,200

$ millions

Retained EPD DCF w/o Non Recurring Cash Distributions

Cumulative Retained DCF2Q 2004–1Q 2017 $6,914Last 3 Years $2,710 39%Last 12 Months $675 10%


EPD: NATURAL GAS, NGLS, CRUDE OIL, PETROCHEMICALS AND REFINED PRODUCTS

Pipelines: ≈50,000 miles of natural gas, NGL, crude oil, petrochemicals and refined products pipelinesStorage: ≈260 MMBbls of NGL, petrochemical, refined products, and crude oil, and 14 Bcf of natural gas storage capacityProcessing: 26 natural gas processing plants; 22 fractionators; 11 condensate distillation facilitiesExport Facilities: 18 deepwater docks handling ethane, LPG, PGP, crude oil and refined products

Fully integrated midstream energy company aggregating domestic supply directly connected to domestic and international demandConnected to U.S. major shale basins Connected to every U.S. ethylene crackerConnected to ≈90% of refineries East of RockiesPipeline connected to 21 Gulf Coast PGP customers

Asset Overview Connectivity

Assets Under ConstructionPipelines: ≈1,000 miles of pipelinesProcessing: 1 gas processing plantPetchem: 1 PDH and 1 iBDH facilityFrac IX: Mont Belvieu


DIVERSIFIED SOURCES OF CASH FLOW BACKED BY FEE–BASED BUSINESS MODEL

$5.4 Billion Total Gross Operating Margin for 12 months ended March 31, 2017

17%

13%

13%

57%

NGL Pipelines & ServicesCrude Oil Pipelines & ServicesNatural Gas Pipelines & ServicesPetrochemical & Refined Products Services

(1) Total gross operating margin amounts presented for NG Gathering and NG Processing are components of the total gross operating margin amounts historically reported for our Natural Gas Pipelines & Services and NGL Pipelines & Services segments, respectively.

$301 $259 $253 $247

$510$535 $292 $169

17%15%

10%

8%

7%

0%

5%

10%

15%

20%

$0

$150

$300

$450

$600

$750

$900

2013 2014 2015 2016 1Q17

$ in M

illions

NG Gathering NG Processing % of Total GOM

$5,248$5,339$5,205$4,814Total GOM:

% of Total G

OM

(1) (1)

% contribution from G&P businesses has decreased with investments in fee‐based pipelines, fractionators and export facilities and lower commodity prices / volumes

Natural Gas Gathering & Processing DiminishingContribution to Total Gross Operating Margin

$51

$1,469

$58


SUPPLY / DEMAND FUNDAMENTALS


CURRENT MACRO ENERGY OUTLOOKSupply–Side

Entering 3rd year of lower commodity prices• Is recent OPEC agreement an inflection point to support $50+ crude?• How fast will global GDPs grow? • Will U.S. production grow faster than global demand?E&P still generally living within cash flow; selective in capital allocation• Capital markets for E&P spotty, but very supportive of Permian investmentsTechnology continues to drive improvements in U.S. drilling economicsProducers rationalize properties in some established basins:• Piceance, Jonah, Barnett, Haynesville, Eagle Ford

Total Eagle Ford acquisition activity >$4B so far in 2017, only second to Permian• New owners increase drilling activity in established basins with “The Need for Speed”: hedge, drill, complete, and produce to drive IRR

Volume declines in most regions (excluding Permian) have resulted in underutilized midstream assets, which leads to operational leverage when volumes return• Seen inflection point for DJ, Eagle Ford and Haynesville Sources: EIA, Hodson and Waterborne


‐1,500

‐1,000

‐500

0

500

1,000

1,500

2,000

2,500

0

200

400

600

800

1,000

1,200

1,400

1,600

Gross Crude Exports Gross NGLs Net Refined Products

0200400600800

1,0001,2001,4001,6001,8002,000

Ethane Propane Butane Naphtha

CURRENT MACRO ENERGY OUTLOOKDemand–Side Dominates This Part of the Cycle

Domestic demand‐side pull• U.S. petrochemicals consumed a record 1.6 MMBPD of NGLs in 2016; industry added its first world scale ethylene plant (+40 MBPD of ethane consumption in 1Q 2017)

• Growing global appetite for U.S. petrochemical products with plentiful natural gas / NGL feedstocks, labor and sound rule of law

International demand‐side pull• U.S. NGL exports of 1.4 MMBPD YTD February 2017 U.S. began exporting ethane by water in 2016

• Record U.S. crude exports of 1.1 MMBPD YTD February 2017

• Record U.S. refinery runs, and record net refined products exports of 1.8 MMBPD YTD February 2017

• U.S. began LNG exports and increased exports of natural gas to Mexico via pipeline U.S. exports more natural gas than it imports for first time in history

Sources: EIA, Hodson and Waterborne

MBP

D

U.S. Ethylene Cracker Feedstocks>70% Growth

YE 2016–YE 2020E

U.S. Exports MBP

D

Refined ProductsMBPD


GLOBAL BALANCES: MOST ANALYSTS EXPECT MARKET TO BALANCE BY 2H 2017

2016 2017 2018IEA OMR, January 2017 +1.6 MMBPD +1.4 MMBPD

PIRA, February 2017 +1.9 MMBPD +1.7 MMBPD +1.7 MMBPD

Oil demand growth remains robust, especially in emerging markets

Sources: IEA and PIRA

OECD Total Products StocksDemand / Supply Balance until 2Q17

Supp

ly / Dem

and (M

MBP

D)

Stock Ch

ange

(MMBP

D)


ALL MAJOR U.S. CRUDE OIL BASINS HAVE SOLID RETURNS IN CORE ACREAGE

Source: EPD FundamentalsAssumes $3/MMBtuHalf–cycle economics for “core” wells

0%

20%

40%

60%

80%

100%

DJ Niobrara HZ Midland Basin HZ Eagle Ford Oil Delaware Basin HZ Eagle Ford Cond Bakken

Rate of R

eturn

ROR Highgrade $55 ROR Highgrade $45

≈1,050

≈300≈875

≈600

≈1,400

≈350 Basin size in current production (MBPD)


ALL MAJOR U.S. NATURAL GAS BASINS HAVE SOLID RETURNS IN CORE ACREAGE

0%

20%

40%

60%

80%

100%

Rich ScoopStack

Rich Marcellus Pinedale Rich Utica LeanMarcellus

Haynesville Lean Utica Fayetteville

Rate of R

eturn

LeanRich

Assumes $55/Bbl and $3/MMBtuHalf–cycle economics for “core” wells Source: EPD Fundamentals


RECOVERY IN RIG COUNTS

0

100

200

300

400

500

600Permian

361

548

142

233

05101520253035404550

Haynesville

4043

15

26

0

50

100

150

200

250Eagle Ford

85

214

29

103

0

10

20

30

40

50

60

70DJ

23

53

13

30


Total Supply

108138 157

050100150200

Current 2020 2022

Source: EPD Fundamentals

ROCKIES

U.S. OIL & CONDENSATE SUPPLY POTENTIALASSUMING SUFFICIENT MARKETS (MBPD)

8,80310,678

12,182

0

5,000

10,000

15,000

current 2020 2022

1,7141,957 2,053

1,4001,6001,8002,0002,200

Current 2020 2022

1,012 926 901

0250500750

1,000

Current 2020 2022

AK & CA

APPALACHIAN

634 765 792

0300600900

Current 2020 2022

3,1323,651 4,085

01,0002,0003,0004,0005,000

Current 2020 2022

2,2033,241

4,196

01,0002,0003,0004,0005,000

Current 2020 2022

PERMIAN

MID–CONTINENT

Current

GULF COAST



U.S. NGL SUPPLY POTENTIAL ASSUMING SUFFICIENT MARKETS (MBPD)

NGL Components Current 2020 2022Ethane 1,884 2,388 2,756Propane 1,184 1,462 1,680N. Butane 400 491 563Iso Butane 240 293 338Natural Gasoline 440 534 611

Total 4,148 5,168 5,948

976 1,1121,278

0

500

1,000

current 2020 2022

4,148

5,168

5,948

0

1,000

2,000

3,000

4,000

5,000

6,000

current 2020 2022 9421,370

1,759

0500

1,0001,500

current 2020 2022

Total Supply

481 526 542

0200400600

current 2020 2022

824941

983

600

800

1,000

current 2020 2022

130 124 122

050

100150

current 2020 2022

7941,095

1,263

0

500

1,000

current 2020 2022

AK & CA

APPALACHIAN

GULF COAST

PERMIAN

MID–CONTINENT

Current

Current

Current

Current

ROCKIES



U.S. NATURAL GAS SUPPLY POTENTIALASSUMING SUFFICIENT MARKETS (BCF/D)

22

29 31

0

10

20

30

Current 2020 2022

APPALACHIAN

7284

94

0

20

40

60

80

100

Current 2020 2022

13 13 13

0481216 ROCKIES

Current 2020 2022

9 10 10

048

12MID–CONTINENT

Current 2020 2022

TX GULF COAST

12 12 14

048

1216

Current 2020 2022

1 1 1

0

2

4 AK & CA

Current 2020 2022

GULF COAST

9 1114

048

1216

Current 2020 2022

6 911

048

12 PERMIAN

Current 2020 2022


PERMIAN BASIN CRUDE OIL TAKEAWAY EXPECTED TO TIGHTEN


‐

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

Jan‐13

Jul‐1

3

Jan‐14

Jul‐1

4

Jan‐15

Jul‐1

5

Jan‐16

Jul‐1

6

Jan‐17

Jul‐1

7

Jan‐18

Jul‐1

8

Jan‐19

Jul‐1

9

Jan‐20

Jul‐2

0

Jan‐21

Jul‐2

1

Jan‐22

MBP

D

Other Expansions

PE2

PE3

Midland to Sealy

Midland to Sealy

Cactus Expansion

BridgeTex Expansion

Lone Star W TX conversion

Existing

Refining

Production

Expansion

Permian Crude Oil Balances(using Capacities at 100% Load Factor)

Conversion


TO MATCH REFINERS PREFERRED FEED SLATE:LIGHT OIL EXPORTED & HEAVY / MEDIUM IMPORTED

We expect EPD assets to handle exports, imports, batching and blending of various crude oil grades and qualities

Sources: EPD Fundamentals and Company Announcements

0

2

4

6

8

10

12

14

16

18

20

22

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

MMBPD

US Prod ‐ Light

US Prod ‐ Cond

US Prod ‐ Medium

US Prod ‐ Heavy

Imports ‐ Canada

Imports: KSA, MEX & VEZ

Other Imp PADD 5

Other Imp PADD 1

Potential Exports:Mostly Light Oil and Condensates

U.S. Demand for Crude: ≈16.2

Canadian Net Imports

Light Oil

'Base' Imports


NATURAL GAS: U.S. GULF COAST–CENTRIC DEMAND & FORECASTED FLOW PATTERNS

2016 to 2022 Change in NG Flow

RockiesProduction

0

+3–5 Permian+1 California E.G.+1 from MidCon+5–7 Bcf/d

+1 Mid Con+1 From Midwest+1 Rockies/Canada

+3 Bcf/d

Mexico+4‐5 Bcf/d

LNG+0.8

RC & E.G.+1.0

Canada+1.5

DemandOther Western

Markets+1 E.G.

1 Bcf/d

MidwestMarkets+2 E.G.

Canada+3 Bcf/d

California E.G.(Renewables)

–1

Bakken +0.5

E.G.Southeast

+1–2New capacity is needed to reach future demand

in South Texas

1–2 Bcf/d

Gulf &S. Texas

+7

Demand:+7–10 LNG+1–2 E.G.+3 Mexico+3–4 Indust14–19 Bcf/d

Marcellus & UticaProduction+9–11 Bcf/d

Recently, a new pipe was announced to evacuate oil from SCOOP / Stack towards Gulf region (Midship project sponsored by Cheniere / Kinder / Boardwalk)In addition to EPD, other Permian projects are being proposed (e.g., KMI / DCP and ETC)



HOW DOES THE HOUSTON SHIP CHANNEL STACK UP?Best Overall Attributes of Texas Gulf Coast

Houston Freeport Beaumont Corpus Christi Texas City

Traffic Limitations None

–Pilot staffing–Tug availability

–Escorts required forLPG & LNG ships

One way traffic

convoys

–Military priority–Offshore platforms shutdown traffic

–Frequent shoaling

None

Vessel Traffic Service Yes No Yes No YesDesignated Barge Lanes Yes No No No No

Two way Traffic Yes No No Yes NoMax Draft 45’ 42’ 40’ 45’ 45’Max Beam 166’ 180’ 157’ 160’ 220’Air Draft 175’ None 136’ 138’ No limit# of Pilots 100 3 30 16 16

Available # of Tugs Excellent Below average / shared with Houston Average Average Excellent



HOUSTON SHIP CHANNEL HAS PLENTY OF CAPACITYAverage Utilization is ≈57% of Peak Movements

2016 arrivals per year 8,300

2016 average movements per day 52

Peak historical single‐day movements 92

Houston Deepdraft Vessel Movements

Month

Vessels

Houston Vessel Arrivals2014–2017

Sources: HarborLights and Greater Houston Port Bureau


North America19.9 MMBbls Market

11.1 MMBbls (56%); EPD % of Market

Source: Waterborne

Europe & Africa

64.8 MMBbls5.7 MMBbls (9%) EPD

South America18.9 MMBbls

2.2 MMBbls (12%) EPD

EPD LPG Exports by Destination Region through March 2017: 46.34 MMBbls% of Cargos Loaded EPD% of Destination Market

North America 24% 56%South America 5% 12%Europe / Africa 12% 9%Far East 54% 16%

Other (Australia, Mid East, unknown) 5% 16%

U.S. THE LARGEST EXPORTER OF LPGLPG Exports by Destination through March 2017

Other14.1 MMBbls


Far East159.1 MMBbls


‐

50

100

150

200

250

300

350

USA Qatar Algeria UAE Saudi Norway Iran Kuwait

MMbls

EPD 2013 2014 2015 2016 1Q 2017

USA Qatar Algeria UAE Saudi Norway Iran Kuwait

Top LPG Exporters in 2013, 2014, 2015, 2016 and 1Q 2017


ASIA LPG IMPORT TRENDS

Asian countries, in aggregate, import 45% of their LPG needs. A large portion of this demand is consumer‐oriented and relatively price inelasticIndia converted 32 million households to LPG in 2016 and is projected to add another 70 million by 2019

Source: Bloomberg

‐

100

200

300

400

500

600

2010 2011 2012 2013 2014 2015 2016 2017 1Q

LPG Imports

China

S Korea

India

Japan

MBPD


CONTRACTED LPG EXPORT LOADINGS

1,150 Cargos Contracted from 2017–2020

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

2010 2011 2012 2013 2014 2015 2016 2017E 2018E 2019E 2020E

Mbb

ls/Mon

th

Average Term Commitments Operational Capacity

LPG Export Capacity: 14.0 MMbbls/Month

Note: Dock capacity calculated at 85% of nameplate capacity


LPG DOCK SPACE EXPECTED TO TIGHTEN

0

500

1,000

1,500

2,000

2,500

3,000

3,500

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

MBPD

LPG Domestic Demand Current LPG Exports Export Capacity Addit'l Export

LPG SupplyExport Capacity at 85% Operating Rate

Note: Includes butane, refinery production and importsDock capacity calculated at 85% of nameplate Industrywide Sources: EPD Fundamentals and Company Announcements


205410 460

259

234278

0

200

400

600

800

Current 2020 2022

MBPD

Extraction Rejection

U.S. GULF COAST ETHANE BALANCES


95

New Cracker2020?

+30?

Mariner EastExport

+50?

Utopia Export

(1) EPD believes there is ≈120 MBPD of additional ethane at high prices

Current Demand : ≈1,100 MBPDIncremental Demand 2020–2022:

+750 to +900 MBPD

AppalachiaSupply Potential

1,0901,624 1,898

233

120120

120

0

600

1,200

1,800

2,400

Current 2020 2022

MBPD

Extraction Rejection High Cost

(1)

(1)

(1)

All Regions ‘West’ of AppalachiaSupply Potential


ETHANE EXPORT FACILITYLargest of Its Kind

MORGAN’SPOINT

HOUSTON SHIP CHANNEL

0

50

100

150

200

2016 2017 2018 Forward

MBP

D

Base w/Option Volumes

Average Annual Contracted Volumes

Note: Volume commitments for 2016 & 2017 could vary depending on customer elections.


Shipbuilders Response to Increased Ethane DemandEstimated Ethane / Ethylene Vessel Capacity

Note: Includes all vessel sizes

180

195 201 202

165

175

185

195

205

‐

5

10

15

20

25

30

In Service 2017 2018 2019

Capacity (M

MBb

ls)

Current In Orderbook # of vessels

Num

ber of Vessels


Company CapacityBillion lb/year

Ethane Consumption (MBPD)

Ethane ConsumptionCumulative (MBPD)

Estimated Completion Date

Location

Occidental Chemical / Mexichem 1.2 40 Operational Ingleside, TX

Dow Chemical 3.3 90 Commissioning Freeport, TX

Chevron Phillips Chemical 3.3 90 2017 Cedar Bayou, TX

ExxonMobil Chemical 3.3 90 2017 Baytown, TX

Indorama 1.1 30 340 2017 Lake Charles, LA

Shintech 1.1 30 2018 Plaquemine, LA

Sasol 3.3 90 460 2018 Lake Charles, LA

Formosa Plastics 3.5 95 2019 Point Comfort, TX

Axiall / Lotte 2.2 60 2019 Lake Charles, LA

Total Petrochemicals & Refining 2.2 60 675 2019 Port Arthur, TX

Shell 3.5 95 770 Early 2020s Monaca, PA

TOTAL 28.0 770

THE CHEMICALS INDUSTRY IS MAKING LARGE INVESTMENTS BASED ON U.S. ETHANE

American Chemistry Council (ACC) analysis shows ≈$164 billion in capital spending could lead to ≈$105 billion per year in new chemical outputGlobal petrochemical demand growth generally exceeds global GDP growth

Sources: American Chemistry Council and EPD Fundamentals

U.S. World Scale Ethylene Plants Under Construction


NEW U.S. CRACKERS BUILT TO CRACK ETHANE; OTHER FEEDSTOCKS LITTLE CHANGED

Sources: Hodson Report and EPD FundamentalsAssumes 90% operating rate

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

Ethane Propane Butane Naphtha

MBPD

2010 2015 2020

U.S. Ethylene Feedstocks: 2010–2020


CRACKING ETHANE HAS A HIDDEN COST (OPPORTUNITY): FEW HEAVIER OLEFINS

CRACKING ETHANE FOR ETHYLENE YIELDS FEW COPRODUCTS, SUCH AS PROPYLENE AND BUTYLENE…THUS THE ADVANTAGE OF ON PURPOSE PROPYLENE AND BUTYLENE


ProductionEthylene Propylene Butylene Butadiene Other

Ethane 78% 0% 1% 2% 19%

Propane 42% 17% 1% 3% 37%

Butane 40% 17% 7% 3% 33%

Naphtha 31% 16% 4% 5% 44%

Gas Oil 21% 15% 5% 4% 55%

End Uses Consumer Plastics,Packaging, Vinyls, PVC, Antifreeze, etc.

Durable Plastics, Paint, Fabrics, Containers, etc.

Rubber, Lubricants,Motor Fuels & Additives, etc.

Rubber,Carpet, Paper Coatings, Resins, etc.

Feed

stock


PROJECT UPDATES


NGL29%

Crude 23%

Petchem48%

EPD VISIBILITY TO GROWTH$8.4B of Major Capital Projects with More to Come…

$0.1

$2.8

$0.0 $0.1

$3.3

$2.2

$0.0

$0.5

$1.0

$1.5

$2.0

$2.5

$3.0

$3.5

$4.0

$4.5

$5.0

1Q17 2Q17 3Q17 4Q17 2018 2019

$ in Billions

Estimated

Refined products infrastructure

iBDHShin Oak pipeline

Midland–to–ECHO pipelineCrude oil infrastructureMont Belvieu Frac IXPermian processing plantEthylene infrastructure

PDH facilityButane recovery facilityPropylene pipeline expansion


ETHANE TAKEAWAY SOLUTIONSSteady Volume Commitment Growth

ATEXCurrent capacity of 130 MBPD

• Expansion to 145 MBPD scheduled by year end to meet contractual commitments

Connected to 4 NGL fractionators and currently transporting ≈115 MBPD to Mont Belvieu15 year ship‐or‐pay commitments

Aegis280‐mile, 20” pipeline combined with existing South Texas ethane pipeline creates header system from Corpus Christi to Mississippi River in LouisianaReceived commitments of ≈360 MBPD and are in discussions for more on Aegis

• Expandable beyond 400 MBPD with additional pipeline looping

Aegis currently transporting ≈165 MBPD

ATEX Pipeline

Aegis Pipeline

50160 160

297362

0

50

100

150

200

250

300

350

400

2015 2016 2017 2018 2019

MBP

D

Aegis C2 Contracted Volumes

81104 116 131

0

30

60

90

120

150

2015 2016 2017 2018‐2028

MBP

D

ATEX C2 Contracted Volumes


EXPANDING FOOTPRINT IN DELAWARE BASINBringing Gas Processing Capacity to 800 MMcf/d

South Eddy Gas PlantCapacity of 200 MMcf/d inlet gas and ≈25 MBPD of NGL production feeding EPD’s 16” MAPL extension

Delaware Basin Gas Plant (DBGP)Capacity of 150 MMcf/d inlet gas and ≈22 MBPD of NGL production feeding EPD’s 12” Chaparral extensionFully integrated with EPD’s Texas intrastate gas system at Waha Hub50/50 joint venture with Occidental

Orla Gas Plant:Capacity of 300 MMcf/d inlet gas and ≈40 MBPD of NGL production feeding EPD’s 16” MAPL extension via South EddyFully integrated with EPD’s Texas intrastate gas system via new 36” pipeline to WahaStart‐up expected by 2Q 2018


PERMIAN NGL TAKE AWAY SOLUTIONShin Oak Pipeline

571‐mile, 24” mixed NGL pipelineInitial capacity 250 MBPD, expandable to 600 MBPD

• Would consider JV with a strategic partner to support an expansionSupported by long‐term customer commitmentsExpected in‐service: 2Q 2019

Shin Oak


0

700

1,400

2,100

1Q 2016 1Q 2017

ENTERPRISE WESTERN G&P ASSETSFocus on Increasing Supply

Franchise assets in the Rockies feeding EPD's downstream NGL system of pipelines, fractionation, storage and export terminalsRecent transactions bring in “regionally‐focused” producersFocusing on offering incentives for drilling and completions on dedicated acreageNegotiated incentive deals in all three basins to incentivize drilling in 2016–2019Expecting an incremental ≈200 MMcf/d of inlet gas to EPD processing plants producing ≈11 MBPD in 2017 from incentive deals

Utah

Wyoming

Colorado

NewMexico

PioneerPlant

UintaBasin

PiceanceBasin

Green River Basin

San JuanBasin

MeekerPlant

ChacoPlant

Gas GatheringMAPL (NGLs)

Inlet Volumes (MMcf/d)


DEMONSTRATED GROSS NGL FRACTIONATION CAPACITYFrac IX on the Horizon

Forecasted

Sup

ply

0

200

400

600

800

1,000

1,200

1,400

2010 2011 2012 2013 2014 2015 2016 2017 2018

Frac Capacity

(MBP

D)

LA S. TX Hobbs MTBV

IX


MIDLAND TO SEALY CRUDE OIL P/L SEGMENTFrom Permian Supply Hub to Multiple Markets

416‐mile, 24” pipeline from Midland to Sealy segment connects to Sealy storage facility Sealy connected to ECHO by existing 1.0 MMBPD Rancho II pipelineCapacity of 450 MBPD supported by long term contractsExpected in‐service in 4Q 2017 ramping up through early 2018Competitive advantages

• Origin not dependent on 3rd party pipelines

• Direct route from Midland to Gulf Coast

• Four segregations: WTS, WTI, Light WTI and condensate

• Destination can efficiently distribute barrels to markets on Texas Gulf Coast

ECHO

T E X A S

O K L A H O M A

Texas City

Freeport

Beaumont

Cushing

MarshallMilton

LyssyGardendale

Three Rivers

Corpus Christi

Katy

Midland

SealyEHSC

N E W M E X I C O

Jones Creek

TerminalEagle Ford Terminal (JV)Seaway (JV)Red River GatheringWest Texas GatheringBasin (JV)Midland to SealyEagle Ford Pipeline (JV) Eagle Ford Gathering (JV)South Texas LegacyEagle Ford EFS Liquids Gathering Rancho II EHSC SystemEDS Header

T E X A S


MIDLAND CRUDE OIL TERMINALGrowing to ≈4 MM Barrels with Connectivity

Mesa Plains / Basin Centurion Sunoco

MIDLAND AREA

McCamey

Crane

Colorado CityWichita Falls

Cushing

Gardendale Lyssy

Corpus

ENTERPRISE EAGLE FORD

EPD

EAGLE FORD JV

MESA

LONGHORN

CACT

US

SunVit

Garden City

PE II

Centurion

Houston

Texas CityFreeport /Jones Creek

BRIDGETEX

Beaumont / Nederland


CRUDE OIL DISTRIBUTION SYSTEMConnectivity to ≈4 MMBbls Refining CapacityCapability to Load >4 MMBPD of Crude Oil Products

Katy

Rancho II36”

Galena Park

Beaumont

Texas CityJones Creek

Jones Creek Lateral36”

ECHO

45’ draft

VLO H.R. PRSI

VLO MPCGBR

Refinery

ECPL PipelineECPL Pipeline Under ConstructionSeaway Pipeline

EHSC PipelineEHSC PipelineUnder ConstructionThird Party Pipeline

Storage Terminal

Dock

42’ draftFreeport

Cushing

Motiva VLO TOT XOM

P66

BaytownSealy

Seaway Longhaul and Loop / Twin

2 x 30” Seaway TX City36”

Beaumont / Port Arthur Lateral

30”

XOM

BMW / BME

45’ draft

40’ draft

Pasadena Junction

Shell

24"

Moore Road

36”/24”/24"

24"

24"

24"

EHSC

30"

30”/30”/24”

24"

36"

30”SDP Junction


TYPICAL MIDSTREAM VALUE CHAIN

Gas Liquids

NGL Fractionation

Typical Midstream Value Chain

Feed to PetchemsFuel (Nat Gas)Export

ButaneFeed to PetchemsFuel (Motor) Export

Ethane

Feed to PetchemsFuel (Heating & Crop Drying)Export

Propane


PDH & iBDHExtending the Value Chain w/PetChem

Moving Down the Value Chain

Feed to PetchemsFuel (Nat Gas)Export

Butane

H2

Feed to PetchemsFuel (Motor) Export

Propylene(fabrics, plastics, paints, etc)

Butylene(lubricants, fuels, rubbers, additives, etc.)

PDH

iBDH

Removing (and Selling)Hydrogen Adds Value

Gas Liquids

NGL Fractionation

Ethane

Feed to PetchemsFuel (Heating & Crop Drying)Export

Propane


PDH FACILITY

Produce up to 1.65 billion lbs/year (25 MBPD) of PGP• Consume 35 MBPD of propane

100% of capacity subscribed under fee‐based contracts with investment grade companies averaging 15 years• No contractual volume ramp after completion

Transitioned to new primary construction contractor December 2015; productivity significantly increasedIn‐service 3Q 2017; currently commissioning


ISOBUTYLENE VALUE CHAIN

Continuing Strategy: Convert low cost NGLs into value added olefins

Crude Isobutylene

MTBE

High Purity IsoButylene

(HPIB)

Gas Plants IsomerizationFractionationisoButane DeHydro(iBDH)

Y‐Grade

Storage Caverns

EPD Assets

N‐butane IsobutaneCrude

Isobutylene

Existing DeHydro Unit (within MTBE Unit) has been operating for 23 yearsThere continues to be very high growth in isobutylene derivative markets• As the isobutylene market demand has grown (particularly for octane enhancers, fuel and lubricants additive packages) the opportunity cost of the idle capacity in our existing derivative units, MTBE and High Purity Isobutylene (HPIB), has become more acute


iBDHConverting Low Cost NGLs into Value Added Olefins

Capacity• 425 kta = 937 million pounds of isobutylene annually

• Doubles Enterprise capacity• Will consume 30 MBPD butaneSchedule• Engineering is in full swing• Permit is expected this coming Fall• Key long leads have been ordered• Completion expected 4Q 2019Contracts• 50% will fill Crude Isobutylene sales with 15 year (average) fee‐based contracts with investment grade companies, all on a feedstock cost‐plus basis

• 25% will fill EPD’s idle HPIB capacity for lubricants, additives, and rubber, all on a feedstock cost‐plus basis

• 25% will fill EPD’s idle MTBE capacity into the export motor gasoline market

Announced January 30


POTENTIAL NEW NATURAL GAS PIPELINEAddressing a Potential Permian Constraint

Agua Dulce Hub

Waha Hub


FINANCIAL UPDATE


SOLID OPERATING PERFORMANCE…

12.912.5 12.3

11.911.4

8

9

10

11

12

13

14

2013 2014 2015 2016 1Q17

Tbtu/d

Onshore Natural Gas Pipeline Volumes(1)

4.4

4.7

5.05.2

5.4

3.5

4.0

4.5

5.0

5.5

6.0

2013 2014 2015 2016 1Q17

Million BP

D

Onshore Liquids Pipeline Volumes(1)

NGL / Propylene Fractionation & Butane Isomerization

894

992 993 1,009971

600

700

800

900

1,000

1,100

2013 2014 2015 2016 1Q17

MBP

D

4.64.8

4.94.7

4.5

3.5

4.0

4.5

5.0

5.5

60

80

100

120

140

160

2013 2014 2015 2016 1Q17

Bcf/d

MBP

D

Equity NGL Production& Fee‐based Processing

Fee‐based Processin

g

Equity NGL Prod

uctio

n

126 116 133 141 150

(1) Excludes offshore volumes prior to 2015.


MARINE TERMINAL / DOCK ACTIVITY

(1) Excludes Oiltanking volumes prior to October 1, 2014.(2) Reflects net interest volumes for joint owned assets. Unloadings Loadings

38210 191 167 143

172

481

366328 332

0

150

300

450

600

750

2013 2014 2015 2016 1Q17

MBP

D

Crude Oil & Condensate(1,2)

210

691

557495 475

5

173

258286 26797

97103 132

0

100

200

300

400

2013 2014 2015 2016 1Q17

MBP

D

Petrochemical & Refined Products(1) 389

355

270

399

238 253299

435

568

8 53

1

1

0

100

200

300

400

500

600

2013 2014 2015 2016 1Q17

MBP

D

Natural Gas Liquids

246 258302

569

281

636748

888978

180

583 466432

465

0

250

500

750

1,000

1,250

1,500

2013 2014 2015 2016 1Q17

MBP

D

Total Volumes

461

1,219 1,2141,320

1,443

436


STRONG FINANCIAL RESULTS

(1) Each period noted includes non‐recurring transactions (e.g., proceeds from asset sales and property damage insurance claims and payments to settle interest rate hedges).(2) Retained DCF represents the amount of distributable cash flow for each period that was retained by the general partner for reinvestment in capital projects and other reasons.

Non‐recurring items

$4.8$5.2 $5.3 $5.2

$1.5

$0.0

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

2013 2014 2015 2016 1Q17

$ Billion

s

Total Gross Operating Margin (“Total GOM”)

$3.7 $3.9 $4.0 $4.1

$1.1

$0.0

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

2013 2014 2015 2016 1Q17

$ Billion

s

Distributable Cash Flow (“DCF”)(1)

$3.8 $4.1

$5.6

$4.1

$0.0

$0.5

$1.0

$1.5

$2.0

$2.5

$3.0

2013 2014 2015 2016 1Q17

$ Billion

s

1.2x

$1.21.5x

1.5x

$0.7

$1.3

$1.21.4x

1.5x

$2.6

$1.01.3x

1.9x

$1.4

Retained DCF / Coverage(1,2)

$1.37

$1.45

$1.53

$1.61$1.66

$1.25

$1.35

$1.45

$1.55

$1.65

$1.75

2013 2014 2015 2016 1Q17

$ pe

r Unit

Distributions Declared(Adjusted for 2‐for‐1 Split in August 2014)

Annualized

1.3x$0.2


DEMONSTRATED FINANCIAL DISCIPLINE WHILE EXECUTING GROWTH STRATEGY

4.2x

3.9x

3.5x

3.6x

3.5x

3.8x

4.2x

4.4x 4.3x(3)

3.3x

3.5x

3.7x

3.9x

4.1x

4.3x

4.5x

4.7x

$0.0

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

$7.0

$8.0

2009 2010 2011 2012 2013 2014 2015 2016 2017E

Debt / Ad

justed

EBITD

A

$ in Billions

Total Growth Capex & Debt Leverage

$3.2

$1.5

$3.1$3.6

$3.9$4.2

$7.8

$4.6

$6.2

$2.5

$3.7

(1) Proforma includes full year EBITDA for Oiltanking(2) Adjusted for an incremental 0.2x of leverage (2016 & TTM March 2017) was associated with proportional contracted cash flows from projects under construction and an additional 0.2x/0.1x ( 2016/TTM

March 2017) for elevated working capital associated with short‐term contango across commodities(3) Trailing 12‐months March 2017

(1)$2.9

Actual Oiltanking, EFS Midstream & Azure Debt Leverage Ratio(2014/2015) (2015/2016)

$1.0

$3.9

$2.5–$2.75

4.0x(2) 4.0x(2,3)

(2017)

$0.2


STRENGTHENING DEBT PORTFOLIOExtending Maturities Without Increasing Costs

9.7%

12.9%

34.9%

42.5%

3 Year 5 Year 10 Year 30+ Year

Average Maturity

–Years

Cost of Debt

88.3% Fixed Rate Debt

14.9

16.2

17.3 17.7

17.6 17.3

16.1 16.0

5.8% 5.8%

5.5%5.3%

4.8%4.7%

4.5%4.6%

4.0%

5.0%

6.0%

7.0%

8.0%

13.5

14

14.5

15

15.5

16

16.5

17

17.5

18

Average Maturity to First Call Date Average Cost of Debt

≈$19.6 Billion Notes Issued2009–1Q 2017


6.97%

4.49%4.23%

3.49%

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%

6.0%

7.0%

8.0%

Midstream MLP Midstream C-Corp REIT (RMZ) Utility (UTY)

MLPs PROVIDE COMPELLING VALUE COMPARED TO OTHER INCOME SECURITIES

EPD 5.7%

Source: Bloomberg. Market data as of 4/27/2017.1. REIT = RMZ Index constituents, Utility = UTY Index Constituents. Midstream C‐Corp include ENB, ENLC, KMI, OKE, PAGP, TEGP, TRGP, TRP, WMB.

Median Current Yield

EPD 6.08%


EPD VISIBILITY TO GROWTH$8.4B of Major Capital Projects with More to Come…

In Service Date 2016 1Q 2017 2Q 2017 3Q 2017 4Q 2017 2018 2019+

NGL Pipeline & ServicesSouth Eddy (Permian) gas plant – 200 MMcf/d & related pipelines DoneEthane export facility on Gulf Coast DoneDelaware Basin gas plant (Oxy JV) – 150 MMcf/d & related pipelines DoneSouth Texas 16" ethane pipeline expansion DoneAegis ethane pipeline – Phase 2 (2018) √Mont Belvieu brine handling expansion (2018) √ATEX Express ethane pipeline 25 MBPD expansion – Marcellus / Utica (2018) √Orla (Permian) gas plant – 300 MMcf/d & related pipelines (2018) √Mont Belvieu Frac 9 – 85 MBPD (2018) √Shin Oak (Permian to Mont Belvieu) 571–mile 24" NGL pipeline (2019) √

Crude Oil Pipelines & ServicesAppelt & Beaumont storage terminal expansions, including 58 acre expansion (2015–2018) Done √ECHO addt'l 4 MMBbl (total capacity ≈6.5 MMBbls) & 55 miles of 36" pipelines (2015–2018) √Rancho II 36" crude oil pipelinePermian 25–mile, 10" crude gathering pipeline Eagle Ford (JV) – crude oil pipeline expansion & gathering (2015) & dock (2018) √Midland to Sealy 24" crude oil pipeline (2018) √EFS gathering & condensate pipeline projects (2016–2018) √ √

Petrochemical & Refined Products Services Refined products export dock – Beaumont expansion (2Q 2016 & 1Q,3Q 2017) Done Done √Expansion of propylene pipeline system (2016–2017) Done √Propane Dehydrogenation Unit ("PDH") (2017) √Ethylene storage and 24–mile 12" pipeline from Mont Belvieu to Bayport, TX (2018) √Isobutane Dehydrogenation (“iBDH”) Unit (4Q 2019) √Other Done √ √

Value of capital placed in service ($ Billions) 2.2$ 0.1$ -$ -$ -$ -$ -$

Value of remaining capital projects to be placed in service ($ Billions) -$ -$ 2.8$ 0.0$ 0.1$ 3.3$ 2.2$


NON–GAAP RECONCILIATIONS


For the ThreeMonths Ended

2012 2013 2014 2015 2016 March 31, 2017Gross operating margin by segment:

NGL Pipelines & Services 2,468.5$ 2,514.4$ 2,877.7$ 2,771.6$ 2,990.6$ 856.0$ Crude Oil Pipelines & Services 387.7 742.7 762.5 961.9 854.6 264.6 Natural Gas Pipelines & Services 775.5 789.0 803.3 782.6 734.9 170.9 Petrochemical & Refined Products Services 579.9 625.9 681.0 718.5 650.6 181.8 Offshore Pipelines & Services 173.0 146.1 162.0 97.5 ‐ ‐ Other Investments 2.4 ‐ ‐ ‐ ‐ ‐

Total segment gross operating margin (a) 4,387.0 4,818.1 5,286.5 5,332.1 5,230.7 1,473.3 Net adjustment for shipper make‐up rights (b) ‐ (4.4) (81.7) 7.1 17.1 (4.2) Total gross operating margin (non‐GAAP) 4,387.0 4,813.7 5,204.8 5,339.2 5,247.8 1,469.1 Adjustments to reconcile non‐GAAP gross operating margin to GAAP operating income:

Subtract depreciation, amortization and accretion expense amounts not reflected ingross operating margin (1,061.7) (1,148.9) (1,282.7) (1,428.2) (1,456.7) (376.2)

Subtract asset impairment and related charges not reflected in gross operating margin (63.4) (92.6) (34.0) (162.6) (52.8) (11.2) Add net gains or subtract net losses attributable to asset sales and insurance recoveries

not reflected in gross operating margin 17.6 83.4 102.1 (15.6) 2.5 0.3 Subtract general and administrative costs not reflected in gross operating margin (170.3) (188.3) (214.5) (192.6) (160.1) (50.4)

Operating income (GAAP) 3,109.2$ 3,467.3$ 3,775.7$ 3,540.2$ 3,580.7$ 1,031.6$

(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 financial 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 recently issued guidance from the SEC.

For the Year Ended December 31,

TOTAL GROSS OPERATING MARGIN

We evaluate segment performance based on our financial measure of gross operating margin. Gross operating margin is animportant 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 evaluatingsegment results.

The term "total gross operating margin" represents GAAP operating income exclusive of (i) depreciation, amortization andaccretion expenses, (ii) impairment charges, (iii) gains and losses attributable to asset sales, insurance recoveries and relatedproperty damage and (iv) general and administrative costs. Total gross operating margin includes equity in the earnings ofunconsolidated affiliates, but is exclusive of other income and expense transactions, income taxes, the cumulative effect ofchanges in accounting principles and extraordinary charges. Total gross operating margin is presented on a 100% basis before anyallocation of earnings to noncontrolling interests. The GAAP financial measure most directly comparable to total gross operatingmargin is operating income (dollars in millions).



2012 2013 2014 2015 2016 March 31, 2017

Net income (GAAP) 2,428.0$ 2,607.1$ 2,833.5$ 2,558.4$ 2,553.0$ 771.0$ Adjustments to GAAP net income to derive non‐GAAP Adjusted EBITDA:

Subtract equity in income of unconsolidated affi l iates (64.3) (167.3) (259.5) (373.6) (362.0) (94.8) Add distributions received from unconsolidated affi l iates 116.7 251.6 375.1 462.1 451.5 102.5 Add interest expense, including related amortization 771.8 802.5 921.0 961.8 982.6 249.3 Add provision for or subtract benefit from income taxes (17.2) 57.5 23.1 (2.5) 23.4 6.0 Add depreciation, amortization and accretion in costs and expenses 1,094.9 1,185.4 1,325.1 1,472.6 1,486.9 384.3 Add asset impairment and related charges 63.4 92.6 34.0 162.6 53.5 11.2 Add non‐cash net losses or subtract net gains attributable to asset sales and

insurance recoveries 20.0 15.7 7.7 18.9 (2.5) (0.3) Add non‐cash expense attributable to changes in fair value of the Liquidity

Option Agreement ‐ ‐ ‐ 25.4 24.5 5.5 Add losses and subtract gains attributable to unrealized changes in the fair market value

of derivative instruments (29.5) 1.4 30.6 (18.4) 45.0 (20.3) Adjusted EBITDA (non‐GAAP) 4,383.8 4,846.5 5,290.6 5,267.3 5,255.9 1,414.4 Adjustments to non‐GAAP Adjusted EBITDA to derive GAAP net cash flows

provided by operating activities:Subtract interest expense, including related amortization, reflected in Adjusted EBITDA (771.8) (802.5) (921.0) (961.8) (982.6) (249.3) Subtract provision for or add benefit from income taxes reflected in Adjusted EBITDA 17.2 (57.5) (23.1) 2.5 (23.4) (6.0) Subtract net gains attributable to asset sales and insurance recoveries (106.4) (99.0) (109.8) (3.3) ‐ ‐ Subtract distributions received for return of capital from unconsolidated affil iates ‐ ‐ ‐ ‐ (71.0) (12.0) Add deferred income tax expense or subtract benefit (66.2) 37.9 6.1 (20.6) 6.6 0.1 Add or subtract the net effect of changes in operating accounts, as applicable (582.5) (97.6) (108.2) (323.3) (180.9) (288.8) Add or subtract miscellaneous non‐cash and other amounts to reconcile non‐GAAP

Adjusted EBITDA with GAAP net cash flows provided by operating activities 16.8 37.7 27.6 41.6 62.2 17.2 Net cash flows provided by operating activities (GAAP) 2,890.9$ 3,865.5$ 4,162.2$ 4,002.4$ 4,066.8$ 875.6$


ADJUSTED EBITDA

Adjusted EBITDA is commonly used as a supplemental financial measure by our management and external users of our financialstatements, such as investors, commercial banks, research analysts and ratings agencies to assess: (1) the financial performanceof our assets without regard to financing methods, capital structures or historical cost basis; (2) the ability of our assets togenerate cash sufficient to pay interest and support our indebtedness; and (3) the viability of projects and the overall rates ofreturn on alternative investment opportunities. Since Adjusted EBITDA excludes some, but not all, items that affect net income orloss and because these measures may vary among other companies, the Adjusted EBITDA data included in this presentation maynot be comparable to similarly titled measures of other companies. The following table reconciles non‐GAAP Adjusted EBITDA tonet cash flows provided by operating activities, which is the most directly comparable GAAP financial measure to Adjusted EBITDA(dollars in millions):



2012 2013 2014 2015 2016 March 31, 2017

Net income attributable to l imited partners (GAAP) 2,419.9$ 2,596.9$ 2,787.4$ 2,521.2$ 2,513.1$ 760.7$ Adjustments to GAAP net income attributable to limited partners to derive non‐GAAP distributable cash flow:

Add depreciation, amortization and accretion expenses 1,104.9 1,217.6 1,360.5 1,516.0 1,552.0 402.3 Add distributions received from unconsolidated affi l iates 116.7 251.6 375.1 462.1 451.5 102.5 Subtract equity in income of unconsolidated affi l iates (64.3) (167.3) (259.5) (373.6) (362.0) (94.8) Subtract sustaining capital expenditures (366.2) (291.7) (369.0) (272.6) (252.0) (48.0) Add net losses or subtract net gains from asset sales and insurance recoveries (86.4) (83.3) (102.1) 15.6 (2.5) (0.3) Add cash proceeds from asset sales and insurance recoveries 1,198.8 280.6 145.3 1,608.6 46.5 2.0 Add non‐cash expense attributable to changes in fair value of the Liquidity Option Agreement ‐ ‐ ‐ 25.4 24.5 5.5 Add net gains or subtract net losses from the monetization of interest rate derivative instruments (147.8) (168.8) 27.6 ‐ 6.1 ‐ Add deferred income tax expenses or subtract benefit (66.2) 37.9 6.1 (20.6) 6.6 0.1 Add asset impairment and related charges 63.4 92.6 34.0 162.6 53.5 11.2 Add or subtract other miscellaneous adjustments to derive non‐GAAP distributable cahs flow,

as applicable (39.5) (15.7) 73.2 (37.4) 65.5 (12.6) Distributable cash flow (non‐GAAP) 4,133.3 3,750.4 4,078.6 5,607.3 4,102.8 1,128.6 Adjustments to non‐GAAP distributable cash flow to derive GAAP net cash flows

provided by operating activities:Add sustaining capital expenditures reflected in distributable cash flow 366.2 291.7 369.0 272.6 252.0 48.0 Subtract cash proceeds from asset sales and insurance recoveries reflected in distributable cash flow (1,198.8) (280.6) (145.3) (1,608.6) (46.5) (2.0) Add net losses or subtract net gains from the monetization of interest rate derivative instruments 147.8 168.8 (27.6) ‐ (6.1) ‐ Add or subtract the net effect of changes in operating accounts, as applicable (582.5) (97.6) (108.2) (323.3) (180.9) (288.8) Add or subtract miscellaneous non‐cash and other amounts to reconcile non‐GAAP distributable

cash flow with GAAP net cash flows provided by operating activities, as applicable 24.9 32.8 (4.3) 54.4 (54.5) (10.2) Net cash flows provided by operating activities (GAAP) 2,890.9$ 3,865.5$ 4,162.2$ 4,002.4$ 4,066.8$ 875.6$


DISTRIBUTABLE CASH FLOW

Distributable cash flow is an important non‐GAAP financial measure for our limited partners since it serves as an indicator of oursuccess in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we aregenerating cash flows at a level that can sustain or support an increase in our quarterly cash distributions. Distributable cash flowis also a quantitative standard used by the investment community with respect to publicly traded partnerships because the valueof a partnership unit is, in part, measured by its yield, which is based on the amount of cash distributions a partnership can pay toa unitholder. The following table reconciles non‐GAAP Distributable Cash Flow to net cash flows provided by operating activities,which is the most directly comparable GAAP financial measure to distributable cash flow for the periods presented (dollars inmillions):


CONTACT INFORMATION

Randy Burkhalter – Vice President, Investor Relations• (713) 381‐6812• [email protected] Jackie Richert – Director, Investor Relations• (713) 381‐3920• [email protected]

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