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. UBS MLP ONE?ON?ONE CONFERENCE January 13–14, 2015 Randy Fowler
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 has filed a registration statement with the SEC that includes a proxy statement of Oiltanking that also constitutes a prospectus of Enterprise. The registration statement was declared effective by the SEC on January 9, 2015. On or about January 15, 2015, Oiltanking and Enterprise will begin mailing the definitive proxy statement / prospectus to Oiltanking unitholders of record as of the close of business on the January 2, 2015 record date. This communication is not a substitute for any proxy statement, registration statement, prospectus or other document Enterprise and/or Oiltanking has filed or may file with the SEC in connection with the proposed merger. INVESTORSAND SECURITY HOLDERSOF 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. 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?Kfor 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, is contained in the registration statement, proxy statement/prospectus and other relevant materials that have been filed with the SEC.
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
set 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 ipeline 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 Scalemarkets through extensive marine and trucking fleets LPG export facilities, adding ethane exports 2016 and processed condensate EPD TODAY: NATURAL GAS, NGLS, CRUDE OIL, REFINED PRODUCTS AND PETROCHEMICALS
GEOGRAPHIC AND BUSINESS DIVERSIFICATION PROVIDE MULTIPLE EARNINGS STREAMS 4 Year Growth Capital Allocation 2013–2016E(1) $5.2 Billion Gross Operating Margin For 12 months ended September 30, 2014 ?$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
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 • Aegis Ethane Header Pipeline • Propane dehydrogenization facility (PDH) • South Eddy (Permian) gas processing facility • 9th NGL fractionator at Mont Belvieu
FUNDAMENTALS
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 Americansupply 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
INDICATIVE BREAKEVEN FOR KEY OIL AND CONDENSATE PLAYS Average and High?Grade Wells with NGL Upgrade
INDICATIVE CRUDE PRODUCTION FORECASTS Assumes $65 WTI Crude Production Sensitivity CAGR
INDICATIVE NGL PRODUCTION FORECASTS Assumes $65 WTI NGL Production Sensitivity 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
PROJECTS OVERVIEW
MAJOR NGL CAPITAL GROWTH PROJECTS ATEX and Aegis Ethane Pipelines ATEX Pipeline 1,265?mile, 16” and 20” pipeline Initial capacity 125 MBPD, expandable to265 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
EXPORT CAPACITY: LINKING U.S. SUPPLIES TO GLOBAL DEMAND
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%
EPD BOOKING CARGOES / BUILDING CAPACITY 2,000 LPG Cargoes Scheduled Through 2024 Historical & Contracted Future LPG Loadings vs. Capacity
NEW MARKETS DEVELOP FOR U.S. ETHANE Market Potential EPD Ethane Export Facility at Morgan’s Point, TX Ethylene cracker feedstock – displacing Supported by long?term contracts current crude oil derivative feedstocks or Combined operating rate ?200 MBPD across new demand two docks Portfolio approach Expected to begin operations 3Q 2016 • Consuming nations retain a strong desire Evaluating possible expansion to diversify portfolios from a feedstock and regional perspective Shipbuilders Response to Increased Ethane Demand • ?300 MBPD ethane demand generated by Estimated Ethane / Ethylene Vessel Capacity (1) converting 25% of NW Europe operating capacity to ethane feedstock Fuel Market • Power generation Ultimate waterborne capacity needed will be dependent on roundtrip transittimes to end?use market • Europe vs. Caribbean / South America vs. Asia
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
EPD & SEAWAY’S GULF COAST CRUDE SYSTEM Access to ?8 MMBPD Refining and Water
EAGLE FORD JV PROJECT EXPANSION TO HANDLE PROCESSED CONDENSATE EPD and Plains JV will construct a new condensate gathering system • 55 miles connecting surrounding counties to Three Rivers Terminal Expand mainline between Three Rivers and Corpus Christi • 70 mile 20” pipeline and expand storage capacity • Increasing the ultimate mainline system capacity >600 MPBD Supported by long term production commitment • Expected in service: 3Q 2015 Also constructing a new deep water terminal at Corpus Christi • Dock capacity will handle variety of ocean going vessels • Expected in service by 2017
OILTANKING PARTNERS L.P.
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) 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 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 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 ?30% of 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
OILT HOUSTON ASSET OVERVIEW Two sites with 19.8 MMBbls ?100 miles of pipeline in Houston area of storage capacity 7 ship docks (post expansion) and 2 barge docks • Predominantly crude oil Hosts EPD’s expanding LPG refrigeration facility storage Provides critical services for EPD’s LPG, • Additional 3.5 MMBbls under construction methanol and octane enhancement business
OILT BEAUMONT ASSET OVERVIEW Two sites with 5.5 MMBbls of 4 ship docks (poststorage capacity expansion), 2 barge docks • Predominantly refined products Significant land for expansion storage Near EPD’s refined products marine • Additional 4.1 MMBbls of storage terminal at Port of Beaumont
FINANCIAL
SOLID OPERATING PERFORMANCE…
…DRIVES STRONG FINANCIAL RESULTS
HISTORY OF FINANCIAL DISCIPLINE WHILE EXECUTING GROWTH STRATEGY
STRENGTHENING DEBT PORTFOLIO Extending Maturities Without Increasing Costs
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 Source: Bloomberg L.P. Past results may not be indicative of future performance.
APPENDIX
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
NON–GAAP RECONCILIATIONS
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) 14.82.4? ? ?Total gross operating margin (non?GAAP) 3,253.0 3,871.7 4,387.0 4,818.13,928.15,218.9 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 83.499.0 114.0 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
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) 57.522.533.8 Add depreciation, amortization and accretion in costs and expenses 974.5 990.5 1,094.9 1,185.4 966.21,272.5 Adjusted EBITDA (non GAAP) 3,256.1 3,960.1 4,329.9 4,736.83,902.35,146.5 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 applicable7.9 12.1(66.2) 37.9 2.6 8.4 Add impairment charges8.4 27.8 63.4 92.618.257.5 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) 39.118.236.2 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.
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 instruments1.3 (23.2)(147.8)(168.8) ? Add deferred income tax expenses or subtract benefit, as applicable7.912.1 (66.2)37.9 2.6 Add impairment charges8.427.863.492.618.2 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 3,750.43,015.6 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 112.641.324.932.8 (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.
CONTACT INFORMATION Randy Burkhalter – Vice President, Investor Relations • (713) 381 6812 • rburkhalter@eprod.com Jackie Richert – Manager, Investor Relations • (713) 381 3920 • jmrichert@eprod.com