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.: 001-35230

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 presentation will be posted on the Partnership’s website, www.enterpriseproducts.com.

ENTERPRISE PRODUCTS PARTNERS L.P.

RBC CAPITAL MARKETS

MLP CONFERENCE

November 19, 2014

Mike Creel

CEO

enterpriseproducts.com

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.

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

the

SEC

http://www.sec.gov.

Copies

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

deemed

“participants”

the

solicitation

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.

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 >36% of EPD units

EPD TODAY: NATURAL GAS, NGL

CRUDE OIL,

REFINED PRODUCTS AND PETROCHEMICALS

Pipelines:

52,000 miles of natural gas, NGL, crude oil, refined

products and petrochemical pipelines

Storage:

220 MMBbls of NGL, refined products, petrochemical and

crude oil, and 14 Bcf of natural gas storage capacity

Processing:

24 natural gas processing plants; 22 fractionators

Exports:

added refined products export terminal; expanding World

Scale LPG export facilities and adding ethane exports 2016

Connected to U.S. major shale basins

Connected to every U.S. ethylene cracker

Connected to

90% of refineries East of Rockies

Pipeline connected to 22 Gulf Coast PGP customers

Connected to the “First and Last Mile”

for supplies and

markets through extensive marine and trucking fleets

Asset Overview

Connectivity

Note: includes Oiltanking assets

GEOGRAPHIC AND BUSINESS

DIVERSIFICATION PROVIDE MULTIPLE

EARNINGS STREAMS

$5.2 Billion Gross Operating Margin

For 12 months ended September 30, 2014

Year

Growth

Capital

Allocation

2013–2016E

(1)

$12.5 Billion

NGL Pipelines & Services

Onshore Natural Gas Pipelines & Services

Petrochemical & Refined Products Services

Onshore Crude Oil Pipelines & Services

Offshore Pipelines & Services

15%

21%

63%

15%

13%

56%

Growth capital projects either result in additional revenue from existing assets or from expansion of our asset base through construction of new facilities.

(1)

VISIBILITY

GROWTH:

$20B

PROJECTS

Recently Completed / Under Construction

Projects completed since 2011: $12.7 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 /

Jones Creek to ECHO

Projects under construction: $6.3 Billion

•

Export terminals: LPG / ethane / refined products

•

Aegis Ethane Header Pipeline (partially complete)

•

Propane dehydrogenization facility (PDH)

•

South Eddy (Permian) gas processing facility

•

NGL

fractionator

Mont

Belvieu

•

ECHO Crude Oil Storage

$12.7B Completed

$6.3B Under

Construction

$2.4

$3.2

$0.3

$2.5

$3.5

Organic Growth Capital Projects

$3.9

Note: excludes Oiltanking projects

$0.0

$0.5

$1.0

$1.5

$2.0

$2.5

$3.0

$3.5

$4.0

$4.5

2011

2012

2013

2014

2015

2016

Actual

Estimated

Year of Completion

VISIBILITY TO GROWTH: MAJOR CAPITAL PROJECTS

$6.2B In-Service in 2013 / 3Q14;

$6.3B 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

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

–

mile

pipeline

(1Q

2014)

Done

Mont Belvieu natural gasoline system (4Q 2014)

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

85MBPD

(1Q

2016)

Permian

South

Eddy

gas

plant

200MMcf/d

(1Q

2016)

Onshore Crude Oil Pipelines & Services

North

Loop

extension

West

Texas

Crude

system

(21

miles

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

1.6

MMBbls)

Done

ECHO

addt'l

MMBbl

(total

capacity

6.5

MMBbls)

and

miles

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

Value of capital placed in service ($ Billions)

2.3

2.5

0.9

0.5

Value of remaining capital projects to be put in service

0.3

2.5

3.5

VISIBILITY TO GROWTH

Additional Opportunities Under Development

•

Purity and mixed NGL pipelines from

growing supply areas

•

Expansion of natural gas processing

facilities in growing basins

•

NGL storage in market area

•

Pipelines to serve growing onshore

and Gulf of Mexico supply areas

•

ECHO supply aggregation and blending

•

Gathering and storage projects

•

Marine and truck logistics

Crude Oil

NGLs

Supply-side Opportunities

NGLs

Crude Oil and Condensate

Natural Gas

Refined Products and Petrochemicals

Demand-side Opportunities

•

Pipeline and storage projects to serve expanding petrochemical industry

•

Water access for exports

•

Marine and truck logistics

•

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

Coast refiners

•

Provide water access for North America destinations and exports

•

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

•

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

100

U.S. Natural Gas

POTENTIAL ENERGY PRODUCTION GROWTH

0.7

2.5

1.2

7.5

16.7

10.7

1.2

2.8

1.8

Source: EPD Fundamentals

* Includes refinery production and imports

North American Crude Oil & Condensate

U.S.

Canada

0.0

0.5

1.0

1.5

2.0

2.5

3.0

U.S. Ethane

U.S. Demand

Production

0.0

0.5

1.0

1.5

2.0

2.5

3.0

U.S. LPG

U.S. Demand

Production

PROJECTS OVERVIEW

enterpriseproducts.com

MAJOR NGL CAPITAL GROWTH PROJECTS

ATEX and Aegis Ethane Pipelines

ATEX Pipeline

Initial Origins

Aegis Pipeline

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

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

EXPORT CAPACITY: LINKING U.S. SUPPLIES

TO GROWING GLOBAL DEMAND

Corpus Christi

Texas City

Morgan’s Point

OTI

Freeport / Jones Creek

ECHO

Mont

Belvieu

Source: EPD Fundamentals

OTI

EPD

Product

Docks

Berths

U/C

OILT - Beaumont

Multi

EPD - Beaumont

Refined

OILT - Houston

Multi

Morgan's Point

Ethane

Texas City

Condensate,

Crude

Freeport /

Jones Creek

Crude

Corpus Christi

Crude

Refined Products

Crude Oil

NGLs

Crude Oil –

Under Construction (U/C)

Dock / Berth Terminal

Pipeline Corridors

U.S. BECOMES LARGEST EXPORTER OF PROPANE

Propane Exports by Destination as of October 2014

South America

43 MMBbls

42% EPD

Mexico, Caribbean

& Central America

Total Waterborne Imports:

50 MMBbls

45% EPD

Source: Waterborne

Europe /

North Africa

122 MMBbls

7% EPD

Far East

224 MMBbls

8% EPD

Top Propane Exporters in 2013 and 2014 YTD

% of Cargoes Loaded

% of Destination Market

North America

33%

45%

South America

26%

42%

Europe / North Africa

13%

Far East

26%

Other

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

USA

EPD BOOKING CARGOES / BUILDING CAPACITY

2,000 LPG Cargoes Scheduled Through 2024

2010

2011

2012

2013

2014E

2015E

2016E

2017E

2018E

2019E

2020E

2021E

2022E

2023E

2024E

Historical & Contracted Future LPG Loadings vs. Capacity

Average monthly loadings per year

Operational Capacity

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

NEW MARKETS DEVELOP FOR U.S. ETHANE

EPD Ethane Export Facility at Morgan’s Point, TX

Supported by long-term contracts

Combined operating rate 200 MBPD across two

Source: EPD Fundamentals

Shipbuilders Response to Increased Ethane Demand

Market Potential

Estimated

Ethane

Ethylene

Vessel

Capacity

(1)

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

2014

2015

2016

2017

docks

Evaluating possible expansion

Expected to begin operations 3Q 2016

Europe vs. Caribbean / South America vs. Asia

Ultimate waterborne capacity needed will be

dependent on roundtrip transit times to end-

use market

Power generation

Fuel Market

300 MBPD ethane demand generated by

converting 25% of NW Europe operating

capacity to ethane feedstock

$330 million per year advantage for a 1.5 billion

lb. per year cracker (gross, before costs of logistics

and transport)

(MTBV)

(NEW)

Price per Gallon

$0.24

$1.56

Ethylene Costs

($ per pound)

$0.11

$0.33

Ethane

Naphtha

NW Europe example (as of 11/11/14):

Ethylene

cracker

feedstock

–

displacing

current

crude oil derivative feedstocks or new demand

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 early 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

EPD & SEAWAY’S GULF COAST CRUDE SYSTEM

Access to 8 MMBPD Refining and Water

OILTANKING

enterpriseproducts.com

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

ACQUISITION OF OILT

PRINCIPLE 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”

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 40% of OILT’s 2013 earnings before interest, taxes, interest

depreciation and amortization (per EPD estimates)

•

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

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

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

FINANCIAL

enterpriseproducts.com

SOLID OPERATING PERFORMANCE…

Equity NGL Production & Fee-based Processing

Natural Gas Pipeline Volumes

Offshore

Onshore

12.7

Liquids Pipeline Volumes

4.2

4.0

4.3

5.0

5.2

3.3

3.8

4.3

4.8

5.3

2010

2011

2012

2013

9M 2014

126

125

2.9

2.5

3.5

4.5

100

120

140

2010

2011

2012

2013

9M 2014

NGL / Propylene Fractionation &

Butane Isomerization / DIB Volumes

665

777

872

961

1,066

500

600

700

800

900

1,000

1,100

2010

2011

2012

2013

9M 2014

2010

2011

2012

2013

9M 2014

14.3

14.5

13.6

13.2

4.9

4.6

3.8

101

4.4

116

121

…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.

Annualized

Non-recurring items

Retained DCF / Coverage

(1,2)

$0.0

$1.0

$2.0

$3.0

$4.0

$5.0

$3.3

$3.9

$4.4

$4.8

$3.9

2010

2011

2012

2013

9M 2014

Gross Operating Margin

$0.5

$1.5

$2.5

$3.5

$4.5

$2.3

$3.8

$4.1

$3.8

$3.0

2010

2011

2012

2013

9M 2014

Distributable Cash Flow (“DCF”)

$0.0

$0.4

$0.8

$1.2

$1.6

$2.0

$1.9

2010

2011

2012

2013

9M 2014

$0.8

1.4x

1.9x

$0.4

1.2x

1.9x

$0.7

1.4x

1.3x

$1.2

1.5x

$0.9

1.4x

1.5x

$0.5

$1.7

$1.3

$1.0

Distributions Declared

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

$1.16

$1.22

$1.29

$1.37

$1.46

$1.00

$1.10

$1.20

$1.30

$1.40

$1.50

2010

2011

2012

2013

3Q 2014

$2.2

$2.8

$3.0

$3.7

$2.9

(1)

HISTORY OF FINANCIAL DISCIPLINE

WHILE EXECUTING GROWTH STRATEGY

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.

Total Growth Capex

(1)

& Debt Leverage

(2)

Actual

Debt Leverage Ratio

(4)

(3)

$3.1

$3.6

$3.9

$4.2

$3.1

3.9x

3.5x

3.6x

3.5x

3.7x

3.3x

3.5x

3.7x

3.9x

4.1x

4.3x

4.5x

4.7x

$0.0

$0.5

$1.0

$1.5

$2.0

$2.5

$3.0

$3.5

$4.0

$4.5

2010

2011

2012

2013

2014E

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

(1)

STRENGTHENING DEBT PORTFOLIO

Extending Maturities Without Increasing Costs

98.9% Fixed Rate Debt

$15.9 Billion Notes Issued

2009 –

10/2/2014

7.3%

12.3%

34.0%

46.4%

3 Year

5 Year

10 Year

30+ Year

9.2

11.0

12.4

13.3

14.7

5.7%

5.8%

5.5%

5.3%

5.0%

4.5%

5.5%

6.5%

7.5%

Average Maturity to First Call Date

Average Cost of Debt

EPD TOTAL RETURN

Compared to 9 Other Asset Classes

(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

Past results may not be indicative of future performance.

Source: Bloomberg L.P.

REIT

Commodities

IG Bonds

MLP Index

EPD

REIT

Small Cap Equity

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

Hedge Funds

EPD

MLP Index

Non-US Equity

EPD

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

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

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

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

Small Cap Equity

High Yield

S&P 500

IG Bonds

High Yield

Hedge Funds

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

Commodities

S&P 500

Hedge Funds

REIT

Non-US Equity

IG Bonds

Hedge Funds

8.5%

1.9%

-42.8%

26.5%

10.9%

-2.5%

7.7%

2.7%

-1.0%

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

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

Commodities

Non-US Equity

IG Bonds

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%

2006

2007

2008

2009

2010

2011

2012

2013

9M 2014

15-Year

CAGR ¹

10-Year

CAGR ¹

5-Year

CAGR ¹

3-Year

CAGR ¹

NON–GAAP RECONCILIATIONS

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):

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.

For the Nine

For the Twelve

Months Ended

2010

2011

2012

2013

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

For the Year Ended December 31,

For the Nine

For the Twelve

Months Ended

2010

2011

2012

2013

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

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 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):

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.

For the Nine

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

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 our

success

providing

cash

return

investment.

Specifically,

this

financial

measure

indicates

investors

whether

not

are

generating cash flows at a level that can sustain or support an increase in our quarterly cash distributions. Distributable cash flow

also

quantitative

standard

used

the

investment

community

with

respect

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):

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.

CONTACT INFORMATION

Randy Burkhalter –

Vice President, Investor Relations

•

(713) 381-6812

•

rburkhalter@eprod.com