Edgar Filing: Oiltanking Partners, L.P.

425

Filed by Enterprise Products Partners L.P.

Pursuant to Rule 425 under the Securities Act of 1933

Subject Company: Oiltanking Partners, L.P.

Commission File No.: 333-200608

Enterprise Products Partners L.P. (the “Partnership”) is filing an investor presentation that discloses a variety of financial, operating and general information regarding the Partnership. In addition, this material contains references to the proposed merger of Oiltanking Partners, L.P. with a subsidiary of the Partnership. The communication will be posted on the Partnership’s website, www.enterpriseproducts.com.

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ENTERPRISE PRODUCTS PARTNERS L.P.

BMO CAPITAL MARKETS UTILITIES & PIPELINES DAY

December 2, 2014

Bryan Bulawa

SVP and Treasurer

EPD LISTED NYSE

enterpriseproducts.com

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FORWARD–LOOKING STATEMENTS

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

Although management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. You should not put undue reliance on any forward-looking statements, which speak only as of their dates. Forward-looking statements are subject to risks and uncertainties that may cause actual results to differ materially from those expected, including insufficient cash from operations, adverse market conditions, governmental regulations, the possibility that tax or other costs or difficulties related thereto will be greater than expected, the impact of competition and other risk factors discussed in our latest filings with the Securities and Exchange Commission.

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

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ADDITIONAL INFORMATION

This communication does not constitute an offer to buy or solicitation of an offer to sell any securities. In furtherance of the proposed merger of Oiltanking Partners, L.P. (“Oiltanking”) with a wholly-owned subsidiary of Enterprise, Enterprise and Oiltanking will file one or more registration statements, proxy statements or other documents with the SEC. This communication is not a substitute for any proxy statement, registration statement, prospectus or other document Enterprise and/or Oiltanking may file with the SEC in connection with the proposed merger. INVESTORS AND SECURITY HOLDERS OF ENTERPRISE AND OILTANKING ARE URGED TO READ THE PROXY STATEMENT/PROSPECTUS, REGISTRATION STATEMENT AND OTHER DOCUMENTS FILED WITH THE SEC CAREFULLY IN THEIR ENTIRETY WHEN THEY BECOME AVAILABLE AS THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE PROPOSED MERGER. Any definitive proxy statement/prospectus (when available) will be mailed to unitholders of Oiltanking. Investors and security holders will be able to obtain free copies of these documents (when available) and other documents filed with the SEC by Enterprise and/or Oiltanking through the web site maintained by the SEC at http://www.sec.gov. Copies of the registration statement and the definitive proxy statement/prospectus and the SEC filings that will be incorporated by reference in the proxy statement/prospectus may also be obtained for free by directing a request to: (i) Investor Relations: Enterprise Products Partners L.P., (713) 381≈6500, or (ii) Investor Relations, Oiltanking Partners, L.P., (281) 457≈7900.

Enterprise, Oiltanking and their respective general partners, and the directors and certain of the management of the respective general partners, may be deemed to be “participants” in the solicitation of proxies from the unitholders of Oiltanking in connection with the proposed merger. Information about the directors and executive officers of the respective general partners of Enterprise and Oiltanking is set forth in each company’s Annual Report on Form 10-K for the year ended December 31, 2013, filed with the SEC on March 3, 2014 and February 25, 2014, respectively, and in subsequent statements of changes in beneficial ownership on file with the SEC. These documents can be obtained free of charge from the sources listed above. Other information regarding the persons who may be participants in the proxy solicitation and a description of their direct and indirect interests, by security holdings or otherwise, will be contained in the proxy statement/prospectus and other relevant materials to be filed with the SEC when they become available.

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ENTERPRISE PRODUCTS PARTNERS L.P.

EPD is one of the largest publicly traded midstream energy partnerships with a firm value of ≈$90 billion

One of the largest integrated midstream energy systems

Diversified sources of cash flow

History of successful execution / clear visibility to growth

Consistent distribution growth: 6.2% compound annual growth rate (CAGR) over 41 consecutive quarters

Financial flexibility

Highest credit rating among MLPs: Baa1 / BBB+

Margin of safety with average distribution coverage of 1.4+x and $6.4 billion of retained DCF since 2010

Simple investor-friendly structure

No GP IDRs results in a lower cost of capital

Significant insider ownership: owns >35% of EPD units

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EPD TODAY: NATURAL GAS, NGLs, CRUDE OIL, REFINED PRODUCTS AND PETROCHEMICALS

Asset Overview Connectivity

Pipelines: 52,000 miles of natural gas, NGL, crude oil, refined Connected to U.S. major shale basins

products and petrochemical pipelines Connected to every U.S. ethylene cracker

Storage: 220 MMBbls of NGL, refined products, petrochemical and Connected to ≈90% of refineries East of Rockies

crude oil, and 14 Bcf of natural gas storage capacity

Processing: 24 natural gas processing plants; 22 fractionators Pipeline connected to 22 Gulf Coast PGP customers

Connected to the “First and Last Mile” for supplies and

Exports: added refined products export terminal; expanding World markets through extensive marine and trucking fleets

Scale LPG export facilities and adding ethane exports 2016

Natural Gas Pipeline

Liquids Pipeline

Crude Pipeline

Gas Processing Plant

Underground Nat Gas Storage

Underground Liquids Storage

Fractionator

Crude Oil Terminal & Storage

Liquids Terminal

Offshore Oil Platform

Offshore Gas Platform

Note: includes Oiltanking Partners L.P. assets

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GEOGRAPHIC AND BUSINESS

DIVERSIFICATION PROVIDE MULTIPLE EARNINGS STREAMS

$5.2 Billion Gross Operating Margin For 12 months ended September 30, 2014

15%

13%

56%

13%

4 Year Growth Capital Allocation 2013–2016E(1)

≈$12.5 Billion

15%

21%

63%

NGL Pipelines & Services

Onshore Natural Gas Pipelines & Services

Petrochemical & Refined Products Services

Onshore Crude Oil Pipelines & Services

Offshore Pipelines & Services

(1) Growth capital projects either result in additional revenue from existing assets or from expansion of our asset base through construction of new facilities. Note: Excludes Oiltanking Partners L.P.

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VISIBILITY TO GROWTH: ≈$20B PROJECTS

Recently Completed / Under Construction

Projects completed since 2011: $13.0 Billion

approximately 3% under budget

Pipelines: 4,200 miles of natural gas, NGL and crude oil pipelines

Gas Processing: Yoakum – 3 processing trains

NGL Fractionators: Mont Belvieu 5–8

LPG export expansions: 4 MMBbls/Mo

ECHO Crude Oil Storage

Gulf of Mexico crude oil pipeline

Seaway Looping / ECHO to Port Arthur pipeline

Projects under construction: $6.0 Billion

Export terminals: LPG / ethane / refined products

Aegis Ethane Header Pipeline

Propane dehydrogenization facility (PDH)

South Eddy (Permian) gas processing facility

9th NGL fractionator at Mont Belvieu

Organic Growth Capital Projects

$ 4.5 $13.0B Completed $6.0B Under

Construction

$4.2

$4.0

$3.5

$3.2 $3.2 $3.5

$3.0

$2.5 $2.4

$2.5

$ in Billions $2.0

$1.5

$1.0

$0.5

$0.0

2011 2012 2013 2014 2015 2016

Year of Completion

Actual

Estimated

Note: excludes Oiltanking Partners L.P. projects

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VISIBILITY TO GROWTH: MAJOR CAPITAL PROJECTS

≈$6.6B In-Service 2013–2014; ≈$6.0B Under Construction

In Service Date 2013 1Q 2014 2Q 2014 3Q 2014

4Q 2014

2015

2016

NGL Pipeline & Services

Eagle Ford Yoakum gas processing facility (phase III – additional 300 MMcf/d)

Done

NGL export facility expansion at Houston Ship Channel

Done

Mont Belvieu DIB expansion

Done

Eagle Ford 20” P/L from Yoakum to Needville and 24” P/L from Needville to Alvin

Done

Eagle Ford Phase II mixed NGL pipeline and lateral

Done

Mont Belvieu (JV) NGL fractionators 7 & 8

Done

Texas Express (JV) NGL pipeline and gathering system – Skellytown to Mont Belvieu

Done

Mont Belvieu Mixed NGL pipeline expansions & pump upgrades

Done

Mid-America NGL pipeline expansion – Rocky Mountain segment

Done

ATEX Express ethane pipeline – Marcellus / Utica (2016)

Done

Front Range (JV) NGL pipeline

Done

South Carlsbad expansion – 60 mile pipeline (1Q 2014)

Done

Mont Belvieu natural gasoline system (4Q 2014)

Done

Aegis ethane pipeline – 270 miles (1Q-4Q 2015)

NGL export facility on Gulf Coast (6.0–6.5 MMBbl/mo) (4Q 2015)

Ethane export facility on Gulf Coast (2016)

Mont Belvieu Frac 9 - 85MBPD (1Q 2016)

Permian South Eddy gas plant - 200MMcf/d (1Q 2016)

Onshore Crude Oil Pipelines & Services

North Loop extension of West Texas Crude system (21 miles of 10” P/L)

Done

Avalon–Bone Spring gathering pipeline (Permian Basin Phase II)

Done

Eagle Ford (JV) – crude oil pipeline (3Q 2013), expansion to 470 MBPD (2Q 2015)

Done

Seaway (JV) crude oil laterals

Done

Seaway (JV) crude oil looping (up to 850 MBPD)

Done

ECHO storage expansion 900MBbls (capacity increase to ≈1.6 MMBbls)

Done

ECHO addt’l 4 MMBbl (total capacity ≈6.5 MMBbls) and 55 miles of 36” pipelines (1Q-2Q 2015)

Rancho II crude oil 30” pipeline (3Q 2015)

Midland Tank Farm storage expansion - 400 MBbls (2Q 2015)

Petrochemical & Refined Products Services

MTBV Propylene Splitter IV expansion

Done

Diluent service to Chicago area (Southern Lights & Cochin P/L connections)

Done

Refined products export dock

Done

Propane Dehydrogenation Unit (“PDH”) (2016)

Other

Offshore Pipelines & Services

Lucius (JV) crude oil pipeline SEKCO (3Q 2014)

Done

Note: Excludes Oiltanking Partners L.P.

Value of capital placed in service ($ Billions)

$2.3

$2.5

$0.9

$0.5

$0.3

Value of remaining capital projects to be put in service

$2.5

$3.5

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VISIBILITY TO GROWTH

Additional Opportunities Under Development

Supply-side Opportunities

NGLs

Purity and mixed NGL pipelines from growing supply areas

Expansion of natural gas processing facilities in growing basins

NGL storage in market area

Crude Oil

Pipelines to serve growing onshore and Gulf of Mexico supply areas

ECHO supply aggregation and blending

Gathering and storage projects

Marine and truck logistics

Demand-side Opportunities

NGLs

Pipeline and storage projects to serve expanding petrochemical industry

Water access for exports

Marine and truck logistics

Crude Oil and Condensate

ECHO storage, blending and distribution projects to serve U.S. Gulf

Coast refiners

Provide water access for North America destinations and exports

Natural Gas

Pipeline projects to serve industrial expansion in Texas and Louisiana

Pipeline projects to serve growing usage in power generation

Pipeline projects to serve LNG and Mexico export markets

Refined Products and Petrochemicals

Distribution pipelines to serve expanding petrochemical industry

Water access for refined products, gasoline additives and polymer grade propylene exports

Motor gasoline additive blending

Marine logistics

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POTENTIAL ENERGY PRODUCTION GROWTH

U.S. Natural Gas

100

90 CAGR ≈4% CAGR ≈3%

Bcf/d 70

60 59

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

U.S. Ethane

3.0

U.S. Demand Production

2.5 2.5

BPD 2.0

Million CAGR ≈10% CAGR ≈10%

1.5

1.2

1.0

0.7

0.5

0.0

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

20 North American Crude Oil & Condensate

U.S. Canada 16.7

BPD

Million CAGR ≈7% CAGR ≈7%

10 10.7

7.5

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

3.0 U.S. LPG

2.8

U.S. Demand Production *

2.5 CAGR ≈5% CAGR ≈5%

BPD 2.0 1.8

Million

1.5

1.2

1.0

0.5

0.0

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Source: EPD Fundamentals

* Includes refinery production and imports

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PROJECTS OVERVIEW

enterpriseproducts.com

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MAJOR NGL CAPITAL GROWTH PROJECTS

ATEX and Aegis Ethane Pipelines

ATEX Pipeline

1,265-mile, 16” and 20” pipeline

Initial capacity 125 MBPD, expandable to 265 MBPD

Connected to 4 NGL fractionators 15 year ship-or-pay commitments In-service January 2014

Aegis Ethane Pipeline

270-mile, 20” pipeline with capacity up to 425 MBPD

Creates header pipeline from Corpus Christi to Louisiana, when combined with existing South Texas ethane pipeline Will deliver ethane to at least 6 petrochemical customers Received commitments in excess of 200 MBPD First segment to Beaumont completed September 2014; remaining 2 segments expected in-service in phases throughout 2015

Initial Origins

Blue Racer

Natrium (WV)

Utica East Ohio Scio (OH)

Mark West

Mark West Houston (PA)

Cadiz (OH)

ATEX Pipeline

Aegis Pipeline

ATEX C2 Contracted Volumes

150

120

MBPD 90 60 131 104 116 30 68 81 0

2014

2015

2016

2017 2018-2028

Initial Northeast Origins

Gas Processing Plant

Liquids Terminal

Fractionator

Import/Export Terminal

Underground Liquids Storage

Liquids Pipeline

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EPD PDH FACILITY UPDATE

Propylene production from ethylene crackers decreased by 5.4 billion lbs. or 37% since 2010 due to the decline in cracking naphtha Capacity to produce up to 1.65 billion pounds per year of polymer grade propylene (25 MBPD)

Will consume 35 MBPD of propane

100% of capacity is contracted under fee-based contracts that average 15 years with investment grade companies Integrated with EPD’s existing facilities to provide reliability and flexibility Completion expected in mid-2016

60% of costs locked in

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EXPORT CAPACITY: LINKING U.S. SUPPLIES TO GROWING GLOBAL DEMAND

Sealy

Beaumont

OTI EPD

Mont OTI Belvieu

Houston

Morgan’s Point

ECHO

Texas City

Freeport / Jones Creek

Corpus Christi

/10/2014

:\ArcGIS-Projects\Analyst Presentation\2014\ArcMaps\EP-Export-Facilities-revised.mxd

Product Docks Berths U/C

OILT - Beaumont Multi 242

EPD - Beaumont Refined 1 01

OILT - Houston Multi 821

Morgan’s Point Ethane 0 02

Condensate, Texas City

2 0 0

Crude Freeport /

Crude

1 0 0

Jones Creek

Corpus Christi Crude 1 0 0

Dock / Berth Terminal

Pipeline Corridors

NGLs

Refined Products Crude Oil

Crude Oil – Under Construction (U/C)

Source: EPD Fundamentals

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U.S. BECOMES LARGEST EXPORTER OF PROPANE

Propane Exports by Destination as of October 2014

2014 YTD Propane Exports (from EPD Facility) by Destination Region: 68 MMBbls

% of Cargoes Loaded % of Destination Market

North America 33% 45%

South America 26% 42%

Europe / North Africa 13% 7%

Far East 26% 8%

Other 2% 4%

Europe / North Africa

122 MMBbls

7% EPD

Mexico, Caribbean & Central America

Total Waterborne Imports:

50 MMBbls

45% EPD

South America

43 MMBbls

42% EPD

Far East

224 MMBbls

8% EPD

Top Propane Exporters in 2013 and 2014 YTD

140

120

2013 2014 YTD EPD

100

MMbls 60

USA Qatar UAE Norway Saudi Algeria Kuwait Venezuela

Source: Waterborne

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EPD BOOKING CARGOES / BUILDING CAPACITY

2,000 LPG Cargoes Scheduled Through 2024

Historical & Contracted Future LPG Loadings vs. Capacity

MMBbls/month

Existing Capacity: 7.5 MMBbls/mo

Expansion 1Q 2015: +1.5 MMBbls/mo

Expansion 4Q 2015: +7.0 MMBbls/mo

Ultimate Capacity: 16.0 MMBbls/mo

2010

2011

2012

2013

2014E 2015E 2016E 2017E 2018E 2019E 2020E

2021E

2022E

2023E

2024E

Average monthly loadings per year

Operational Capacity

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NEW MARKETS DEVELOP FOR U.S. ETHANE

Market Potential

Ethylene cracker feedstock – displacing current crude oil derivative feedstocks or new demand NW Europe example (as of 11/11/14):

Ethane Naphtha

(MTBV) (NEW)

Price per Gallon $0.24 $1.56

Ethylene Costs ($ per pound) $0.11 $0.33

≈$330 million per year advantage for a 1.5 billion lb. per year cracker (gross, before costs of logistics and transport)

≈300 MBPD ethane demand generated by converting 25% of NW Europe operating capacity to ethane feedstock

Fuel Market

Power generation

Ultimate waterborne capacity needed will be dependent on roundtrip transit times to end-use market

Europe vs. Caribbean / South America vs. Asia

EPD Ethane Export Facility at Morgan’s Point, TX

Supported by long-term contracts

Combined operating rate ≈200 MBPD across two docks

Expected to begin operations 3Q 2016

Evaluating possible expansion

Shipbuilders Response to Increased Ethane Demand

Estimated Ethane / Ethylene Vessel Capacity (1)

Capacity 10

(MMBbls) 8

6 29

2 5

2014 2015 2016 2017

(1) # of vessels (125+ MBbls capacity per vessel); confirmed shipbuilding orders only

Source: EPD Fundamentals

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SEAWAY CRUDE OIL PIPELINE EXPANSION COMPLETED

Cushing

Oklahoma

Arkan

Texas

Lou

Beaumont/ Port Arthur

Sealy ECHO

Katy TX City

Jones Creek Freeport

Terminal

Seaway Pipeline (JV)

Rancho Pipeline

Seaway Loop: 512 mile, 30” parallel pipeline along existing pipeline; completed June 2014

Linefill is underway

Expect volumes to reach Jones Creek in December

Jones Creek to ECHO Lateral:

65 mile, 36” pipeline; completed January 2014

ECHO to Port Arthur Lateral:

100 mile, 30” pipeline from ECHO to Beaumont / Port Arthur; completed July 2014

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EPD & SEAWAY’S GULF COAST CRUDE SYSTEM

Access to ≈8 MMBPD Refining and Water

From Cushing

From Permian

From Eagle Ford

Sealy

Seaway Longhaul 2 x 30”

Katy

Rancho 24”

Rancho II 36”

Jones Creek Lateral 36”

Galena Park

VLO H.R. PRSI Shell

24”

Genoa ECHO Speed Junction Bertron

18”

Morgan’s Point

Seaway TX City 36”

Baytown

XOM

Beaumont

Motiva VLO TOT XOM

Port Arthur Lateral 30”

P66

Jones Creek

Freeport

45’ draft

Texas City

GBR VLO MPC

45’ draft

Refinery

Enterprise Pipeline

Enterprise Pipeline Under Development

Seaway Pipeline

Third Party Pipeline

Storage Terminal

Dock

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OILTANKING PARTNERS L.P.

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ACQUISITION OF OILTANKING (OILT) OVERVIEW AND RATIONALE

On October 1, 2014, EPD acquired OILT’s GP and related IDRs, 15.9 million OILT common units and 38.9 million OILT subordinated units (which converted one-to-one to common units on November 17, 2014) for $4.41 billion of consideration consisting of $2.21 billion of cash and 54.8 million newly issued EPD common units

On November 11, 2014, EPD and OILT executed merger agreement in which EPD would issue 1.3 EPD common units for each OILT common unit (≈$1.4 billion)

Merger requires approval of holders of simple majority of OILT common units; EPD has agreed to vote its then 54.8 million common units (66% of total OILT common units) in favor of the merger

Total consideration of $6.0 billion plus $228 million of OILT debt

Merger expected to be completed in first quarter of 2015

Combines EPD’s integrated system of midstream energy infrastructure and access to supplies of NGL, crude oil and refined products with OILT’s access to waterborne markets and storage

Expected to be accretive to EPD’s distributable cash flow per unit in 2016

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ACQUISITION OF OILTANKING (OILT) PRINCIPAL DRIVERS OF VALUE CREATION

At least $30 million of synergies and cost savings from the complete integration of OILT’s business into Enterprise’s system as well as public company cost savings

Opportunities for new business and repurposing existing assets for “best use” to meet the growing demand for export and logistical services for petroleum products related to increase in North American crude oil and NGL production from the shale and non-conventional plays

Secures ownership and control of OILT’s assets that are essential to EPD’s midstream

EPD is OILT’s largest customer, representing ≈31% of total 2013 revenues;

EPD accounted for ≈29% of OILT’s 2013 revenues

OILT provides essential dock and storage services to EPD LPG export and octane enhancement businesses, which accounted for ≈10% of EPD’s 2013 gross operating margin

Upon completion of EPD’s LPG export facility in 2016, EPD assets with a value of ≈$1.5 billion would be located on land owned by OILT

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OILT HOUSTON ASSET OVERVIEW

13.2 MMBbls of storage at main site

6.7 MMBbls at Appelt site

≈100 miles of pipeline in Houston area

7 ship docks (post expansion) and 3 barge docks Hosts EPD’s expanding LPG refrigeration facility

Provides critical services for EPD’s LPG, methanol and octane enhancement business

Seaway Galena Park Terminal

Oiltanking Appelt Terminal

Oiltanking Jacintoport Terminal

Enterprise ECHO Terminal

Seaway ECHO Terminal

Enterprise Assets

Enterprise Terminal

Enterprise Crude

Proposed Enterprise

Seaway Assets

Seaway Terminal

Seaway Crude

Oiltanking Assets

Oiltanking Terminal

Oiltanking Crude

Proposed Oiltanking

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OILT BEAUMONT ASSET OVERVIEW

Two sites with 5.5 MMBbls of storage

4 ship docks (post expansion), 2 barge docks

Significant land for expansion

Adjacent to EPD’s storage facility

Near EPD’s refined products marine terminal at Port of Beaumont

Oiltanking Beaumont South Terminal

EPD Storage Facility

Oiltanking Beaumont North Terminal

Seaway Assets

Seaway Crude

Oiltanking Assets

Oiltanking Terminal

Oiltanking Crude

Proposed Oiltanking

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FINANCIAL

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SOLID OPERATING PERFORMANCE…

Million BPD

5.3 4.8 4.3 3.8 3.3

Liquids Pipeline Volumes

4.2 4.0 4.3 5.0 5.2

2010 2011 2012 2013 9M 2014

MBPD

1,100 1,000 900 800 700 600 500

NGL / Propylene Fractionation &

Butane Isomerization / DIB Volumes

665 777 872 961 1,066

2010 2011 2012 2013 9M 2014

Equity NGL Production

MBPD

140 120 100 80 60 40 20 0

Equity NGL Production & Fee-based Processing

121 116 101 126 125

2.9 3.8 4.4 4.6 4.9

5 4.5 4 3.5 3 2.5 2

Bcf/d

Fee-based Processing

2010 2011 2012 2013 9M 2014

TBtu/d

16 14 12 10 8 6

Natural Gas Pipeline Volumes

12.7

Offshore

Onshore

14.3 14.5 13.6 13.2

2010 2011 2012 2013 9M 2014

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…DRIVES STRONG FINANCIAL RESULTS

$ Billions

$5.0 $4.0 $3.0 $2.0 $1.0 $0.0

Gross Operating Margin

$3.3 $3.9 $4.4 $4.8 $3.9

2010 2011 2012 2013 9M 2014

$ per Unit

$1.50 $1.40 $1.30 $1.20 $1.10 $1.00

Distributions Declared

(Adjusted for 2-for-1 Split in August 2014)

$1.16 $1.22 $1.29 $1.37 $1.46

2010 2011 2012 2013 3Q 2014 Annualized

$ Billions

$4.5 $3.5 $2.5 $1.5 $0.5

Distributable Cash Flow (“DCF”)(1)

$2.3 $3.8 $4.1 $3.8 $3.0

$2.2 $2.8 $3.0 $3.7 $2.9

2010 2011 2012 2013 9M 2014

$ Billions

$2.0 $1.6 $1.2 $0.8 $0.4 $0.0

Retained DCF / Coverage(1,2)

$0.5 1.3x $0.4 1.2x

$1.7 1.9x $0.7 1.4x

$1.9 1.9x $0.8 1.4x

$1.3 1.5x $1.2 1.5x

$1.0 1.5x $0.9 1.4x

2010 2011 2012 2013 9M 2014

Non-recurring items

(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.

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HISTORY OF FINANCIAL DISCIPLINE WHILE EXECUTING GROWTH STRATEGY

$ Billions

$4.5 $4.0 $3.5 $3.0 $2.5 $2.0 $1.5 $1.0 $0.5 $0.0

Total Growth Capex(1) & Debt Leverage(2)

4.6x $2.9

4.2x $1.5

$3.1 3.9x

$3.6 3.5x

$3.9 3.6x

$4.2 3.5x

$3.1 3.7x(3)

4.7x 4.5x 4.3x 4.1x 3.9x 3.7x 3.5x 3.3x

Debt / Adjusted EBITDA

2008 2009 2010 2011 2012 2013 2014E(4)

Actual Debt Leverage Ratio

(1) Represents cash used in investing activities as presented on our Statements of Consolidated Cash Flows before changes in restricted cash, proceeds from asset sales and related transactions, and sustaining capital expenditures.

(2) Coverage ratio reflects total debt adjusted for the average 50% equity credit that the rating agencies ascribe to the Junior Subordinated Notes

(3) Debt leverage ratio presented reflects historical data for the 12 months ended September 30, 2014 and should not be inferred as a projection of such ratio for the 12 months ended December 31, 2014. (4) Growth capital spending estimate for the 12 months ended December 31, 2014, includes actuals for the 9 months ended September 30, 2014.

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STRENGTHENING DEBT PORTFOLIO

Extending Maturities Without Increasing Costs

≈$15.9 Billion Notes Issued 2009 – 10/2/2014

46.4% 7.3% 12.3% 34.0%

3 Year 5 Year 10 Year 30+ Year

Average Maturity – Years

15 13 11 9 7

98.9% Fixed Rate Debt

5.7% 7.9

6.1% 9.2

5.7% 9.2

11.0 5.8%

12.4 5.5%

13.3 5.3%

14.7 5.0%

7.5% 6.5% 5.5% 4.5%

Cost of Debt

12/31/2008 12/31/2009 12/31/2010 12/31/2011 12/31/2012 12/31/2013 10/2/2014

Average Maturity to First Call Date

Average Cost of Debt

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EPD TOTAL RETURN

Compared to 9 Other Asset Classes

2006 2007 2008 2009 2010 2011 2012 2013 9M 2014 15-Year CAGR1 10-Year CAGR1 5-Year CAGR1 3-Year CAGR1

REIT 35.4% Commodities 40.7% IG Bonds -6.1% MLP Index 76.4% EPD 41.0% EPD 17.8% REIT 19.6% Small Cap Equity 38.8% EPD 25.3% EPD 22.7% EPD 20.3% EPD 29.8% EPD 32.0%

EPD 29.3% EPD 16.9% Hedge Funds -19.1% EPD 64.7% MLP Index 35.9% MLP Index 13.9% Non-US Equity 17.9% EPD 38.4% MLP Index 19.5% MLP Index 18.3% MLP Index 16.2% MLP Index 23.6% S&P 500 23.0%

Non-US Equity 26.9% MLP Index 12.7% High Yield -21.3% Commodities 50.3% REIT 27.7% IG Bonds 7.4% Small Cap Equity 16.3% S&P 500 32.4% REIT 13.4% REIT 11.8% REIT 8.5% REIT 15.9% MLP Index 22.9%

MLP Index 26.1% Hedge Funds 12.6% EPD -30.1% High Yield 39.2% Small Cap Equity 26.9% REIT 7.5% S&P 500 16.0% MLP Index 27.6% S&P 500 8.3% Small Cap Equity 7.9% Small Cap Equity 8.2% S&P 500 15.7% Small Cap Equity 21.3%

Small Cap Equity 18.4% Non-US Equity 11.6% Small Cap Equity -33.8% Non-US Equity 32.5% Commodities 20.4% High Yield 7.3% High Yield 14.3% Non-US Equity 23.3% IG Bonds 4.4% Commodities 7.6% S&P 500 8.1% Small Cap Equity 14.3% REIT 17.0%

S&P 500 15.8% IG Bonds 6.2% MLP Index -36.9% REIT 28.5% S&P 500 15.1% Commodities 2.1% EPD 13.4% Hedge Funds 9.7% High Yield 3.5% Hedge Funds 7.4% Non-US Equity 6.8% High Yield 9.4% Non-US Equity 14.2%

Hedge Funds 13.9% S&P 500 5.5% S&P 500 -37.0% Small Cap Equity 27.2% High Yield 12.5% S&P 500 2.1% IG Bonds 9.2% High Yield 4.7% Hedge Funds 3.4% High Yield 6.4% High Yield 6.7% Non-US Equity 7.0% High Yield 9.5%

High Yield 8.5% High Yield 1.9% Commodities -42.8% S&P 500 26.5% Hedge Funds 10.9% Hedge Funds -2.5% Hedge Funds 7.7% REIT 2.7% Non-US Equity -1.0% IG Bonds 6.3% Hedge Funds 6.3% Hedge Funds 6.4% Hedge Funds 7.2%

IG Bonds 4.3% Small Cap Equity -1.6% REIT -37.6% Hedge Funds 18.6% IG Bonds 10.6% Small Cap Equity -4.2% MLP Index 4.8% IG Bonds -1.4% Small Cap Equity -4.4% S&P 500 4.9% Commodities 5.5% IG Bonds 6.3% IG Bonds 4.6%

Commodities 0.4% REIT -15.6% Non-US Equity -43.1% IG Bonds 17.9% Non-US Equity 8.2% Non-US Equity -11.7% Commodities 0.3% Commodities -2.2% Commodities -9.2% Non-US Equity 4.3% IG Bonds 5.4% Commodities 4.4% Commodities -1.0%

(1) CAGR calculations based upon closing prices ending the last trading day of the third quarter for each period.

Commodities: S&P World Commodity Index; EPD: Enterprise Products Partners L.P.; Hedge Funds: CS Tremont Hedge Fund; High Yield: Vanguard High Yield US Corporate Fund; IG Bonds: Vanguard Intermediate Term US Investment Grade Fund; MLP Index: Alerian Index; Non-US Equity: MSCI Daily Total Return EAFE Index; REIT: DJ Equity REIT Index; S&P 500: S&P 500 Index; Small Cap Equity: Russell 2000 Index

Source: Bloomberg L.P. Past results may not be indicative of future performance.

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NON–GAAP RECONCILIATIONS

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GROSS OPERATING MARGIN

We evaluate segment performance based on the non-GAAP financial measure of gross operating margin. Gross operating margin (either in total or by individual segment) is an important performance measure of the core profitability of our operations. This measure forms the basis of our internal financial reporting and is used by our management in deciding how to allocate capital resources among business segments. The following table reconciles non-GAAP gross operating margin to operating income, which is the most directly comparable GAAP financial measure to gross operating margin (dollars in millions):

For the Year Ended December 31,

For the Nine Months Ended September 30, 2014

For the Twelve Months Ended September 30, 2014

2010 2011 2012 2013

Gross operating margin by segment:

NGL Pipelines & Services $1,732.6 $2,184.2 $2,468.5 $2,514.4 $2,172.4 $2,909.8

Onshore Natural Gas Pipelines & Services 527.2 675.3 775.5 789.0 618.8 805.9

Onshore Crude Oil Pipelines & Services 113.7 234.0 387.7 742.7 534.5 697.6

Offshore Pipelines & Services 297.8 228.2 173.0 146.1 120.0 148.0

Petrochemical & Refined Products Services 584.5 535.2 579.9 625.9 482.4 657.6

Other Investments (2.8) 14.8 2.4 - - -

Total gross operating margin (non-GAAP) 3,253.0 3,871.7 4,387.0 4,818.1 3,928.1 5,218.9

Adjustments to reconcile non-GAAP gross operating margin to GAAP operating income:

Subtract depreciation, amortization and accretion expense amounts not reflected in gross operating margin (936.3) (958.7) (1,061.7) (1,148.9) (936.5) (1,233.7)

Subtract impairment charges not reflected in gross operating margin (8.4) (27.8) (63.4) (92.6) (18.2) (57.5)

Subtract operating lease expenses paid by EPCO not reflected in gross operating margin (0.7) (0.3) - - - -

Add net gains attributable to asset sales and insurance recoveries not reflected in gross operating margin 44.4 156.0 17.6 83.4 99.0 114.0

Subtract non-refundable deferred revenues attributable to shipper make-up rights on new pipeline projects reflected in gross operating margin - - - (4.4) (66.8) (71.2)

Subtract general and administrative costs not reflected in gross operating margin (204.8) (181.8) (170.3) (188.3) (150.9) (200.3)

Operating income (GAAP) $2,147.2 $2,859.1 $3,109.2 $3,467.3 $2,854.7 $3,770.2

Note: Gross Operating Margin has been presented as if EPD were Enterprise GP Holdings for all periods prior to the Holdings Merger, which was completed in November 2010.

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ADJUSTED EBITDA

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

(dollars in millions):

For the Year Ended December 31,

For the Nine Months Ended September 30, 2014

For the Twelve Months Ended September 30, 2014

2010 2011 2012 2013

Net income (GAAP) $1,383.7 $2,088.3 $2,428.0 $2,607.1 $2,152.4 $2,858.1

Adjustments to GAAP net income to derive non-GAAP Adjusted EBITDA:

Subtract equity in income of unconsolidated affiliates (62.0) (46.4) (64.3) (167.3) (179.1) (220.3)

Add distributions received from unconsolidated affiliates 191.9 156.4 116.7 251.6 260.7 324.7

Add interest expense, including related amortization 741.9 744.1 771.8 802.5 679.6 877.7

Add provision for or subtract benefit from income taxes, as applicable 26.1 27.2 (17.2) 57.5 22.5 33.8

Add depreciation, amortization and accretion in costs and expenses 974.5 990.5 1,094.9 1,185.4 966.2 1,272.5

Adjusted EBITDA (non-GAAP) 3,256.1 3,960.1 4,329.9 4,736.8 3,902.3 5,146.5

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 (741.9) (744.1) (771.8) (802.5) (679.6) (877.7)

Add benefit from or subtract provision for income taxes reflected in Adjusted EBITDA (26.1) (27.2) 17.2 (57.5) (22.5) (33.8)

Subtract net gains attributable to asset sales and insurance recoveries (46.7) (155.7) (86.4) (83.3) (99.0) (113.9)

Add deferred income tax expense or subtract benefit, as applicable 7.9 12.1 (66.2) 37.9 2.6 8.4

Add impairment charges 8.4 27.8 63.4 92.6 18.2 57.5

Add or subtract the net effect of changes in operating accounts, as applicable (190.4) 266.9 (582.5) (97.6) (435.8) (19.5)

Add or subtract miscellaneous non-cash and other amounts to reconcile non-GAAP Adjusted EBITDA with GAAP net cash flows provided by operating activities 32.7 (9.4) (12.7) 39.1 18.2 36.2

Net cash flows provided by operating activities (GAAP) $2,300.0 $3,330.5 $2,890.9 $3,865.5 $2,704.4 $4,203.7

Note: Adjusted EBITDA has been presented as if EPD were Enterprise GP Holdings for all periods prior to the Holdings Merger, which was completed in November 2010.

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DISTRIBUTABLE CASH FLOW

Distributable cash flow is an important non-GAAP financial measure for our limited partners since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flows at a level that can sustain or support an increase in our quarterly cash distributions. Distributable cash flow is also a quantitative standard used by the investment community with respect to publicly traded partnerships because the value of a partnership unit is, in part, measured by its yield, which is based on the amount of cash distributions a partnership can pay to a unitholder. 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 (dollars in millions):

For the Year Ended December 31,

For the Nine Months Ended September 30, 2014

2010 2011 2012 2013

Net income attributable to limited partners (GAAP) $1,266.7 $2,046.9 $2,419.9 $2,596.9 $2,127.6

Adjustments to GAAP net income attributable to limited partners to derive non-GAAP distributable cash flow:

Add depreciation, amortization and accretion expenses 980.2 1,007.0 1,104.9 1,217.6 992.4

Add distributions received from unconsolidated affiliates 128.2 156.4 116.7 251.6 260.7

Subtract equity in income of unconsolidated affiliates (69.0) (46.4) (64.3) (167.3) (179.1)

Subtract sustaining capital expenditures (240.3) (296.4) (366.2) (291.7) (262.0)

Subtract net gains from asset sales and insurance recoveries (46.7) (155.7) (86.4) (83.3) (99.0)

Add cash proceeds from asset sales and insurance recoveries 105.9 1,053.8 1,198.8 280.6 121.5

Add gains or subtract losses from the monetization of interest rate derivative instruments 1.3 (23.2) (147.8) (168.8) -

Add deferred income tax expenses or subtract benefit, as applicable 7.9 12.1 (66.2) 37.9 2.6

Add impairment charges 8.4 27.8 63.4 92.6 18.2

Add or subtract other miscellaneous adjustments to derive non-GAAP distributable cash flow, as applicable 113.8 (25.8) (39.5) (15.7) 32.7

Distributable cash flow (non-GAAP) 2,256.4 3,756.5 4,133.3 3,750.4 3,015.6

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 240.3 296.4 366.2 291.7 262.0

Subtract cash proceeds from asset sales and insurance recoveries reflected in distributable cash flow (105.9) (1,053.8) (1,198.8) (280.6) (121.5)

Add losses or subtract gains from the monetization of interest rate derivative instruments (1.3) 23.2 147.8 168.8 -

Add or subtract the net effect of changes in operating accounts, as applicable (202.1) 266.9 (582.5) (97.6) (435.8)

Add miscellaneous non-cash and other amounts to reconcile non-GAAP distributable cash flow with GAAP net cash flows provided by operating activities 112.6 41.3 24.9 32.8 (15.9)

Net cash flows provided by operating activities (GAAP) $2,300.0 $3,330.5 $2,890.9 $3,865.5 $2,704.4

Note: Distributable Cash Flow for the period prior to the fourth quarter of 2010 is presented based on the historical results of EPD prior to the Holdings merger.

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CONTACT INFORMATION

Randy Burkhalter – Vice President, Investor Relations

(713) 381-6812

rburkhalter@eprod.com