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 Partnerships website, www.enterpriseproducts.com.
ENTERPRISE PRODUCTS PARTNERS L.P.
GOLDMAN SACHS
GLOBAL
ENERGY CONFERENCE
January 78, 2015
Randy Fowler
EVP and CFO
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FORWARDLOOKING 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 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 companys 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 »$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
* excludes Oiltanking Partners L.P. assets
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4
EPD TODAY: NATURAL GAS, NGLS, CRUDE OIL, REFINED PRODUCTS AND PETROCHEMICALS
sset Overview
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: refined products export terminal; expanding World Scale
LPG export facilities, adding ethane exports 2016 and processed
condensate
nnectivity
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
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
4 Year Growth Capital Allocation 20132016E(1)
$12.5 Billion (predominantly fee based)
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 58
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 $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
Note: excludes Oiltanking Partners L.P. projects
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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 cutting back on drilling; more expected in 2015; however, leasehold and drilling commitments will delay impact. Additionally, the severity of these cutbacks will be offset by continued technology enhancements and location high-grading.
U.S. crude and NGL production expected to 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
$20 Well 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
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
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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 EPDs existing facilities to provide reliability and
flexibility Completion expected in mid-2016
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EXPORT CAPACITY: LINKING U.S. SUPPLIES TO GLOBAL DEMAND
OTI
EPD Mont OTI Belvieu
Ship Barge Under Product Docks Docks Construction
Morgans Point
OILT - Beaumont Multi 2 2 2
EPD - Beaumont Refined 1 0 1 ECHO OILT - Houston Multi 6 2 1 Ethane, Morgans 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 1 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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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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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 Morgans 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 Capacity
6 29 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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SEAWAY CRUDE OIL PIPELINE EXPANSION PROJECTS COMPLETED
Seaway Loop: 512 mile, 30 parallel pipeline along existing legacy pipeline
Initial volumes delivered to Jones Creek December 2014
Loop more than doubles capacity up to 850 MBPD from Cushing to Gulf Coast
Currently moving 100% heavy; legacy line flowing combination light / heavy
Began collecting demand fees on December 1, 2014 for Loop Pipeline ECHO to Beaumont Lateral: 100 mile, 30 pipeline; line fill currently underway Seaway system provides producers
enhanced access to additional markets for various grades of crude
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EPD & SEAWAYS 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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OILTANKING PARTNERS L.P.
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ACQUISITION OF OILTANKING (OILT) OVERVIEW AND RATIONALE
On October 1, 2014, EPD acquired OILTs 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) On November 26, 2014, filed preliminary Form S 4 Registration Statement with the Securities and Exchange Commission 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
EPDs integrated system of midstream energy infrastructure and access to supplies of NGL, crude oil and refined products with OILTs access to waterborne markets and storage Expected to be accretive to EPDs 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 OILTs business into Enterprises 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 OILTs assets that are essential to EPDs midstream
EPD is OILTs largest customer, representing »30% of revenues
OILT provides essential dock and storage services to EPD LPG export and octane enhancement businesses, which accounted for »10% of EPDs
2013 gross operating margin
Upon completion of EPDs 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
Two sites with 19.8
MMBbls of storage capacity
Predominantly crude oil storage
Additional 3.5 MMBbls under construction
»100 miles of pipeline in Houston area
7 ship docks (post expansion) and 2 barge docks Hosts EPDs expanding LPG refrigeration facility Provides critical services for EPDs LPG, methanol and octane enhancement
business
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OILT BEAUMONT ASSET OVERVIEW
Two sites with 5.5
MMBbls of storage capacity
Predominantly refined products storage
Additional 4.1 MMBbls of storage capacity under construction
4 ship docks (post expansion), 2 barge docks Significant land for expansion Near EPDs refined products marine
terminal at Port of Beaumont
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26
FINANCIAL
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SOLID OPERATING PERFORMANCE
5.3 Liquids
Pipeline Volumes 5.2 Equity NGL Production & Fee-based Processing
5.0 140 5 121 126 125
4.8 116 120 4.6 4.9 4.5
101 100
BPD 4.4 4 Million 4.3 4.2 4.3 80
Processing Production NGL 3.8 3.5 Bcf/d
4.0 MBPD 60
Equity 3 based
40 2.9 Fee-
3.8 20 2.5 0 2
3.3 2010 2011 2012 2013 9M 2014
2010 2011 2012 2013 9M 2014 16
NGL / Propylene
Fractionation & Natural Gas Pipeline Volumes
1,100 1,066
14.3 14.5
Butane Isomerization / DIB Volumes 14 13.6
1,000
961 13.2 12.7
900 872 12 Offshore
MBPD 800 777 TBtu/d
10 Onshore 700 665
600 8 500 6
2010 2011 2012 2013 9M 2014 2010 2011 2012 2013 9M 2014
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DRIVES STRONG FINANCIAL RESULTS
Gross Operating
Margin Distributable Cash Flow (DCF)(1)
$4.8 $4.5 $5.0 $4.1 $4.4 $3.8 $3.8 $3.9 $3.9 $4.0 $3.5
$3.3 $3.7 $3.0 $3.0 $3.0 $2.9 $2.5 $2.3
Billions $2.8
Billions $ $2.0 $ $2.2 $1.5 $1.0
$0.5 $0.0
2010 2011 2012 2013 9M 2014
2010 2011 2012 2013 9M 2014
Distributions Declared Retained DCF / Coverage(1,2)
$1.50 $1.46 $2.0 $1.9 (Adjusted for 2-for-1 Split in August 2014) $1.7 $1.40 $1.37 $1.6 1.9x
1.9x $1.3
$1.29
Unit $1.30 $1.2 1.5x $1.0 $1.22 1.5x
per $1.2
$1.20 Billions $0.8 $ $1.16 $ 1.5x
$0.5 $0.8 $0.9
$0.4 1.3x $0.7 1.4x 1.4x
$1.10 1.4x
$0.4 1.2x $0.0 $1.00 2010201120122013 9M 2014
2010 2011 2012 2013 3Q 2014
Annualized 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
(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 $2.5 4.2x 4.1x
Billions$ $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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STRENGTHENING DEBT PORTFOLIO
Extending Maturities
Without Increasing Costs
»$15.9 Billion Notes Issued 98.9% Fixed
Rate Debt 2009 10/2/2014 15
14.7
7.5%
13 13.3
7.3% Years
12.3% 12.4
Maturity 6.5% 11
46.4% 11.0
Average 6.1% Cost of Debt
5.8%
5.7% 5.7% 5.5%
34.0% 9
9.2 9.2 5.5%
5.3%
5.0%
7.9
7 4.5%
3 Year 5 Year 10 Year 30+ Year
Average Maturity
to First Call Date Average Cost of Debt
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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.
© ALL RIGHTS RESERVED. ENTERPRISE PRODUCTS PARTNERS L.P.
32
APPENDIX
© ALL RIGHTS RESERVED. ENTERPRISE
PRODUCTS PARTNERS L.P. enterpriseproducts.com
VISIBILITY TO GROWTH: MAJOR CAPITAL PROJECTS
»$6.6B In-Service 20132014; »$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
Ö 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)
Ö NGL export facility on Gulf Coast (6.06.5 MMBbl/mo) (4Q 2015) Ö Ethane export facility on Gulf Coast
(2016) Ö Mont Belvieu Frac 985MBPD (1Q 2016) Ö Permian South Eddy gas plant200MMcf/d (1Q 2016) Ö
Onshore Crude Oil Pipelines & Services
North Loop extension of West Texas Crude system (21 miles of 10 P/L) Done AvalonBone Spring gathering pipeline
(Permian Basin Phase II) Done
Eagle Ford (JV) crude oil pipeline (3Q 2013), expansion to 470 MBPD (2Q
2015) Done Ö 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 addtl 4 MMBbl (total capacity »6.5 MMBbls) and 55 miles of 36 pipelines (1Q-2Q 2015)
Ö Rancho II crude oil 30 pipeline (3Q 2015) Ö Midland Tank Farm storage expansion400 MBbls (2Q 2015) Ö
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) Ö Other ÖÖ
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
© ALL RIGHTS RESERVED. ENTERPRISE PRODUCTS PARTNERS L.P.
34
NONGAAP RECONCILIATIONS
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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.
© ALL RIGHTS RESERVED. ENTERPRISE PRODUCTS
PARTNERS L.P. 36
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.
© ALL RIGHTS RESERVED. ENTERPRISE PRODUCTS PARTNERS L.P. 37
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 unit holder. 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.
© ALL RIGHTS
RESERVED. ENTERPRISE PRODUCTS PARTNERS L.P. 38
CONTACT INFORMATION
Randy Burkhalter Vice
President, Investor Relations
(713) 381-6812
rburkhalter@eprod.com
© ALL RIGHTS RESERVED. ENTERPRISE PRODUCTS PARTNERS L.P. 39m
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