ENTERPRISE PRODUCTS PARTNERS L.P.
enterpriseproducts.com© ALL RIGHTS RESERVED. ENTERPRISE PRODUCTS PARTNERS L.P.
MLPA INVESTOR CONFERENCEMay 31–June 2, 2017
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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.
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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
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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)
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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%
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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
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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
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SUPPLY / DEMAND FUNDAMENTALS
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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
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‐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
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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)
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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)
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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
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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
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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
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Source: EPD Fundamentals
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
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Source: EPD Fundamentals
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
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PERMIAN BASIN CRUDE OIL TAKEAWAY EXPECTED TO TIGHTEN
Source: EPD Fundamentals
‐
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
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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
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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)
Source: EPD Fundamentals
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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
Source: EPD Fundamentals
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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
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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
2.2 MMBbls (16%) EPD
Far East159.1 MMBbls
25.1 MMBbls (16%) EPD
‐
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
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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
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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
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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
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205410 460
259
234278
0
200
400
600
800
Current 2020 2022
MBPD
Extraction Rejection
U.S. GULF COAST ETHANE BALANCES
Source: EPD Fundamentals
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
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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.
Source: EPD Fundamentals
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
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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
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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
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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
Source: EPD Fundamentals
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
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PROJECT UPDATES
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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
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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
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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
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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
© ALL RIGHTS RESERVED. ENTERPRISE PRODUCTS PARTNERS L.P. 37
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)
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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
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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
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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
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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
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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
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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
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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
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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
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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
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POTENTIAL NEW NATURAL GAS PIPELINEAddressing a Potential Permian Constraint
Agua Dulce Hub
Waha Hub
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FINANCIAL UPDATE
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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.
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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
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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
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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
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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
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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%
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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$
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NON–GAAP RECONCILIATIONS
© ALL RIGHTS RESERVED. ENTERPRISE PRODUCTS PARTNERS L.P. 57
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).
© ALL RIGHTS RESERVED. ENTERPRISE PRODUCTS PARTNERS L.P. 58
For the ThreeMonths Ended
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$
For the Year Ended December 31,
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):
© ALL RIGHTS RESERVED. ENTERPRISE PRODUCTS PARTNERS L.P. 59
For the ThreeMonths Ended
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$
For the Year Ended December 31,
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):
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CONTACT INFORMATION
Randy Burkhalter – Vice President, Investor Relations• (713) 381‐6812• [email protected] Jackie Richert – Director, Investor Relations• (713) 381‐3920• [email protected]