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.

ENTERPRISE PRODUCTS PARTNERS L.P.

WELLS FARGO SECURITIES ENERGY SYMPOSIUM

December 9, 2014

Mike Creel

Chief Executive Officer

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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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2

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 has filed a registration statement with the SEC that includes a proxy statement of Oiltanking that also constitutes a prospectus of Enterprise. 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 BECAUSE THEY 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 can obtain free copies of these documents 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. Thesedocuments canbeobtainedfreeofchargefromthe 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, is contained in the registration statement, proxy statement/prospectus and other relevant materials that have been filed with the SEC.

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3

ENTERPRISE PRODUCTS PARTNERS L.P.

EPD is one of the largest publicly traded midstream energy partnerships with a firm value of ?$93 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

* excludes Oiltanking Partners L.P. assets

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4

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 Pipeline connected to 22 Gulf Coast PGP customers Processing: 24 natural gas processing plants; 22 fractionators Connected to the “First and Last Mile” for supplies and Exports: refined products export terminal; expanding World Scale markets through extensive marine and trucking fleets LPG export facilities, adding ethane exports 2016 and processed condensate

Note: includes Oiltanking Partners L.P. assets

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5

GEOGRAPHIC AND BUSINESS

DIVERSIFICATION PROVIDE MULTIPLE EARNINGS STREAMS

$5.2 Billion Gross Operating Margin 4 Year Growth Capital Allocation 2013–2016E(1)

For 12 months ended September 30, 2014 ?$12.5 Billion (predominantly fee?based)

15% 15%

13%

21% 56% 63% 13% 1% 3%

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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6

VISIBILITY TO GROWTH: ?$20B PROJECTS

Recently Completed / Under Construction

Projects completed since 2011: $13.0 Billion

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

Note: excludes Oiltanking Partners L.P. projects

Organic Growth Capital Projects

$4.5 $6.0B Under

$13.0B Completed

Construction

$4.2

$4.0

$3.5

$3.2 $3.2

$3.5

$3.0

$2.5 $2.4

Billions $2.5 in $2.0 $

$1.5

$1.0

$0.5

$0.0

2011 2012 2013 2014 2015 2016

Year of Completion

Actual Estimated

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7

FUNDAMENTALS

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EPD OBSERVATIONS ON OIL PRICES

Cut Existing Production: OPEC could not agree on production cuts at November 2014 meeting, with strongest members signaling no appetite to cut Slow Supply Growth: lower prices impact both OPEC, Russian and North American supply growth

Poorly capitalized OPEC nations and Russia rely on multinational oil company investments; lower prices and geopolitical instability in Middle East North Africa (“MENA”) will impact these investments

U.S. shale producers are indicating drilling cut backs in 2015; however, leasehold and drilling commitments will delay impact. In addition, the severity of these cutbacks will be offset by continued technology enhancements and location high?grading.

U.S. crude and NGL production will grow in 2015 regardless of current oil prices

Incremental Demand: low prices create incremental demand including Asian strategic petroleum reserve (“SPR”)

Economists estimate ?300 MBPD global demand response for each 10% decline in oil price; however, it comes with a time lag that is impacted by many factors

China and India have increased SPR over last year at higher prices and have capacity to further increase stockpiling

Low prices likely to cause some demand destruction from renewable initiatives

Geopolitical Risks: low prices will have far reaching consequences on poorly capitalized nations with economies dependent on much higher oil prices

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9

INDICATIVE BREAKEVEN FOR KEY OIL AND CONDENSATE PLAYS

Average and High?Grade Wells with NGL Upgrade

$90

$80

Drilling Impacted

$70

$60 $ /Bbl $50 NYMEX $40 $30

Well

$20 Well Grade

$10 Average High ?

$?

Note: assumes 20% before income tax Source: EPD Fundamentals’ estimates

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10

INDICATIVE CRUDE PRODUCTION FORECASTS

Assumes $65 WTI

Crude Production Sensitivity

CAGR

12,500

6.4%

12,000

5.4%

11,500

11,000

10,500 3.4%

MBPD Increase: 2014 to 2015

10,000 12.8% 11.6% 9.4%

9,500

9,000

8,500

Prior to Price Collapse Adjusted High Case Adjusted Low Case 8,000 2014 2015 2016 2017 2018 2019 2020

High Production Case: assumes 20%–25% reduction in Oil Completions, offset by high?grade benefits

Low Production Case: assumes a larger 25%–35% reduction in Oil Completions, offset by high?grade benefits Source: EPD Fundamentals’ estimates

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11

INDICATIVE NGL PRODUCTION FORECASTS

Assumes $65 WTI

NGL Production Sensitivity

6,000

CAGR

5,500 8.4%

7.1%

5,000

5.6%

Increase: 2014 to 2015

4,500

MBPD 14.0% 12.5% 10.5%

4,000

3,500

Prior to Price Collapse Adjusted High Case Adjusted Low Case

3,000

2014 2015 2016 2017 2018 2019 2020

High Production Case: assumes 20%–25% reduction in Oil Completions, offset by high?grade benefits

Low Production Case: assumes a larger 25%–35% reduction in Oil Completions, offset by high?grade benefits Source: EPD Fundamentals’ estimates

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12

PROJECTS OVERVIEW

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MAJOR NGL CAPITAL GROWTH PROJECTS

ATEX and Aegis Ethane Pipelines

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14

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

ATEX C2 Contracted Volumes

150

ATEX Pipeline 120

MBPD 90

60 131 116 104 81

30 68

0

2014 2015 2016 2017 2018?2028

Aegis Pipeline

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

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15

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

OTI

EPD Mont OTI Belvieu

Ship Barge Under Product Docks Docks Construction

Morgan’s Point

OILT ? Beaumont Multi 2 2 2 EPD ? Beaumont Refined 1 0 1 ECHO OILT ? Houston Multi 6 2 1 Ethane, Morgan’s Point 0 1 2 Crude

Texas City Processed

Texas City Condensate, 2 0 0 Crude Freeport /

Crude 2 0 0 Jones Creek Corpus Christi Crude 0 0 1

Freeport / Jones Creek Docks

Pipeline Corridors

Corpus Christi NGLs

Refined Products Crude Oil

Source: EPD Fundamentals

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16

U.S. BECOMES LARGEST EXPORTER OF PROPANE

Propane Exports by Destination as of November 2014

2014 YTD Propane Exports (from EPD Facility) by Destination Region: 75 MMBbls

% of Cargoes Loaded

% of Destination Market

North America

24%

45%

South America

35%

39%

Europe / North Africa

13%

8%

Far East

27%

9%

Other

1%

6%

Europe /

Far East North Africa

229 MMBbls

North America & 124 MMBbls 9% EPD Caribbean 8% EPD

Total Waterborne Imports:

40 MMBbls

45% EPD Top Propane Exporters in 2013 and 2014 YTD

140

120 2013 2014 YTD 100

South America & 80 Central America MMbls

60

66 MMBbls

39% EPD 40

20

0

Source: Waterborne USA Qatar Algeria UAE Saudi Norway Iran Kuwait

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17

EPD BOOKING CARGOES / BUILDING CAPACITY

2,000 LPG Cargoes Scheduled Through 2024

Historical & Contracted Future LPG Loadings vs. Capacity

16 14 12 10

8 MMBbls/month 6

Existing Capacity: 7.5 MMBbls/mo

4 Expansion 1Q 2015: +1.5 MMBbls/mo Expansion 4Q 2015: +7.0 MMBbls/mo

2 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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18

NEW MARKETS DEVELOP FOR U.S. ETHANE

Market Potential

Ethylene cracker feedstock – displacing current crude oil derivative feedstocks or new demand Portfolio approach

Consuming nations retain a strong desire to diversify portfolios from a feedstock and regional perspective ?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)

14

48 12

10 (MMBbls) 8

6 29 Capacity 4 14 2 5 0

2014 2015 2016 2017

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

Source: EPD Fundamentals

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19

SEAWAY CRUDE OIL PIPELINE EXPANSION COMPLETED

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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20

Cushing

O k l a h o m a

A r k a n

L o u

T e x a s Beaumont/ Port Arthur

ECHO

City

Jones Creek

Terminal

Seaway Pipeline (JV)

EPD & SEAWAY’S GULF COAST CRUDE SYSTEM

Access to ?8 MMBPD Refining and Water

From Cushing Galena Park

Baytown Sealy XOM

Rancho

24” XOM Speed Junction

Port Arthur Lateral 30” Seaway Longhaul 2 x 30”

Refinery TX City 36”

Enterprise Pipeline

Enterprise Pipeline Under Development

Seaway Pipeline

Jones Creek

Third Party Pipeline P66

GBR VLO MPC Storage Terminal Freeport

Dock 45’ draft

45’ draft

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21

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 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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23

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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24

OILT HOUSTON ASSET OVERVIEW

13.3 MMBbls of storage ?100 miles of pipeline in Houston area capacity at main site 7 ship docks (post expansion) and 2 barge docks

6.5 MMBbls of storage Hosts EPD’s expanding LPG refrigeration facility capacity at Appelt site Provides critical services for EPD’s LPG,

Additional 3.5 MMBbls under

methanol and octane enhancement business

construction

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25

OILT BEAUMONT ASSET OVERVIEW

Two sites with 5.6 MMBbls of Significant land for expansion storage capacity Adjacent to EPD’s storage facility

Additional 4.1 MMBbls of storage

Near EPD’s refined products marine

capacity under construction

terminal at Port of Beaumont 4 ship docks (post expansion), 2 barge docks

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26

FINANCIAL

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enterpriseproducts.com

SOLID OPERATING PERFORMANCE…

5.3 Liquids Pipeline Volumes 5.2

5.0

140

4.8

120

BPD 100

4.3

4.3 4.2 Production 80

Million 4.0 NGL MBPD 60

40

3.8

Equity 20 0

3.3

2010 2011 2012 2013 9M 2014 16

1,100 NGL / Propylene Fractionation & 1,066

Butane Isomerization / DIB Volumes 14

1,000 961

900 872 12 MBPD 800 777 TBtu/d

10

700 665

600 8 500 6 2010 2011 2012 2013 9M 2014

Equity NGL Production & Fee?based Processing

5

121 126 125

116 4.9 4.5

4.6

101

4.4 4 Processing

3.8 3.5 Bcf/d

3 ? based

2.9 Fee

2.5

2 2010 2011 2012 2013 9M 2014

Natural Gas Pipeline Volumes

14.3 14.5

13.6 13.2

12.7

Offshore

Onshore

2010 2011 2012 2013 9M 2014

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…DRIVES 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.

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29

Gross Operating Margin

$5.0 $4.8

$4.4

$3.9 $3.9

$4.0

$3.3 Billions $3.0

$ $2.0

$1.0

$0.0

2010 2011 2012 2013 9M 2014

Distributions Declared

$1.50 $1.46

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

$1.40 $1.37

$1.29 Unit $1.30 per $1.22 $ $1.20 $1.16

$1.10

$1.00

2010 2011 2012 2013 3Q 2014

Annualized

Distributable Cash Flow (“DCF”)(1)

$4.5 $4.1 $3.8 $3.8 $3.5

$3.7 $3.0

$3.0 $2.9 $2.5 $2.3

Billions $2.8 $

$2.2 $1.5

$0.5

2010 2011 2012 2013 9M 2014

Retained DCF / Coverage(1,2)

$2.0 $1.9

$1.7

$1.6 1.9x

1.9x $1.3

$1.2 1.5x $1.0

1.5x

Billions $1.2

$0.8

$ 1.5x

$0.5 $0.8 $0.9

$0.4 1.3x $0.7 1.4x 1.4x

$0.4 1.4x

1.2x

$0.0

2010201120122013 9M 2014

Non?recurring items

HISTORY OF FINANCIAL DISCIPLINE WHILE EXECUTING GROWTH STRATEGY

(1) (2)

Total Growth Capex & Debt Leverage

$4.5

$4.2

4.6x 4.7x

$3.9

$4.0 $3.6

4.5x

$3.5

$3.1 $3.1

$2.9

$3.0 4.3x EBITDA

$2.5 4.2x

Billions 4.1x

$ $2.0 Adjusted

3.9x

$1.5 3.9x (3) /

$1.5 3.7x

$1.0 3.7x Debt

3.6x

3.5x 3.5x 3.5x

$0.5

$0.0 3.3x

(4)

2008 2009 2010 2011 2012 2013 2014E 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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30

STRENGTHENING DEBT PORTFOLIO

Extending Maturities Without Increasing Costs

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31

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

7.3%

12.3%

46.4%

34.0%

3 Year 5 Year 10 Year 30+ Year

98.9% Fixed Rate Debt

15

14.7

7.5%

13 13.3 Years

12.4 –

Maturity 6.5% 11

11.0

Average 6.1% Cost of Debt

5.8%

5.7% 5.7% 5.5%

9

9.2 9.2 5.5%

5.3%

5.0%

7.9

7 4.5%

Average Maturity to First Call Date Average Cost of Debt

EPD TOTAL RETURN

Compared to 9 Other Asset Classes

15-Year 10-Year 5-Year 3-Year 2006 2007 2008 2009 2010 2011 2012 2013 9M 2014 1 1 1 1 CAGR CAGR CAGR CAGR

REIT Commodities IG Bonds MLP Index EPD EPD REIT Small Cap Equity EPD EPD EPD EPD EPD

35.4% 40.7% -6.1% 76.4% 41.0% 17.8% 19.6% 38.8% 25.3% 22.7% 20.3% 29.8% 32.0%

EPD EPD Hedge Funds EPD MLP Index MLP Index Non-US Equity EPD MLP Index MLP Index MLP Index MLP Index S&P 500

29.3% 16.9% -19.1% 64.7% 35.9% 13.9% 17.9% 38.4% 19.5% 18.3% 16.2% 23.6% 23.0% Non-US Equity MLP Index High Yield Commodities REIT IG Bonds Small Cap Equity S&P 500 REIT REIT REIT REIT MLP Index

26.9% 12.7% -21.3% 50.3% 27.7% 7.4% 16.3% 32.4% 13.4% 11.8% 8.5% 15.9% 22.9% MLP Index Hedge Funds EPD High Yield Small Cap Equity REIT S&P 500 MLP Index S&P 500 Small Cap Equity Small Cap Equity S&P 500 Small Cap Equity

26.1% 12.6% ?30.1% 39.2% 26.9% 7.5% 16.0% 27.6% 8.3% 7.9% 8.2% 15.7% 21.3% Small Cap Equity Non-US Equity Small Cap Equity Non-US Equity Commodities High Yield High Yield Non-US Equity IG Bonds Commodities S&P 500 Small Cap Equity REIT

18.4% 11.6% -33.8% 32.5% 20.4% 7.3% 14.3% 23.3% 4.4% 7.6% 8.1% 14.3% 17.0% S&P 500 IG Bonds MLP Index REIT S&P 500 Commodities EPD Hedge Funds High Yield Hedge Funds Non-US Equity High Yield Non-US Equity

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

13.9% 5.5% -37.0% 27.2% 12.5% 2.1% 9.2% 4.7% 3.4% 6.4% 6.7% 7.0% 9.5%

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

IG Bonds Small Cap Equity REIT Hedge Funds IG Bonds Small Cap Equity MLP Index IG Bonds Small Cap Equity S&P 500 Commodities IG Bonds IG Bonds

4.3% -1.6% -37.6% 18.6% 10.6% -4.2% 4.8% -1.4% -4.4% 4.9% 5.5% 6.3% 4.6%

Commodities REIT Non-US Equity IG Bonds Non-US Equity Non-US Equity Commodities Commodities Commodities Non-US Equity IG Bonds Commodities Commodities

0.4% -15.6% -43.1% 17.9% 8.2% -11.7% 0.3% -2.2% -9.2% 4.3% 5.4% 4.4% -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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APPENDIX

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enterpriseproducts.com

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 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 Done

Refined products export dock Done Done

Propane Dehydrogenation Unit (“PDH”) (2016) ?

Other ? ?

Offshore Pipelines & Services

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

Value of capital placed in service ($ Billions) $ 2.3 $ 2.5 $ 0.9 $ 0.5 $ 0.3 $— $ -

Note: Excludes Oiltanking Partners L.P. Value of remaining capital projects to be put in service $— $ — $ — $ — $ — $ 2.5 $ 3.5

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NON–GAAP RECONCILIATIONS

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

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 Nine For the Twelve

For the Year Ended December 31, Months Ended Months Ended

2010 2011 2012 2013 September 30, 2014 September 30, 2014

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 Nine For the Twelve

For the Year Ended December 31, Months Ended Months Ended

2010 2011 2012 2013 September 30, 2014 September 30, 2014

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

Adjusted EBITDA

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

Distributablecashflowisanimportant 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 Nine

For the Year Ended December 31, Months Ended

2010 2011 2012 2013 September 30, 2014

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

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