Raymond James Institutional Investors Conference

Transcription

1 Raymond James Institutional Investors Conference March 9, 2009 W. Randall Fowler Executive Vice President & CFO

2 Forward Looking Statements This presentation contains forward-looking statements and information based on Enterprise s beliefs and those of its general partner, as well as assumptions made by and information currently available to them. When used in this presentation, words such as anticipate, project, expect, plan, goal, forecast, intend, could, believe, may, and similar expressions and statements regarding the plans and objectives of Enterprise for future operations, are intended to identify forward-looking statements. Although Enterprise and its general partner believe that such expectations reflected in such forward-looking statements are reasonable, neither it nor its general partner can give assurances that such expectations will prove to be correct. Such statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual results may vary materially from those Enterprise anticipated, estimated, projected or expected. Among the key risk factors that may have a direct bearing on Enterprise s results of operations and financial condition are: Fluctuations in oil, natural gas and NGL prices and production due to weather and other natural and economic forces; A reduction in demand for its products by the petrochemical, refining or heating industries; The effects of its debt level on its future financial and operating flexibility; A decline in the volumes of NGLs delivered by its facilities; The failure of its credit risk management efforts to adequately protect it against customer non-payment; Actual construction and development costs could exceed forecasted amounts; Operating cash flows from our capital projects may not be immediate; National, international, regional and local economic, competitive and regulatory conditions; Terrorist attacks aimed at its facilities; and The failure to successfully integrate its operations with assets or companies, if any, that it may acquire in the future. Enterprise has no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. 2

3 Overview EPD is one of the largest publicly traded partnerships with an equity market capitalization of approximately $10 billion, assets of $18 billion and an enterprise value of approximately $19 billion Ranks 90 th on the Fortune 500 Delivered record performance in 2006, 2007 and 2008 EPD owns and operates one of North America s largest fully integrated midstream value chains with significant geographic and business diversity 3

4 Strong Fundamentals Set Us Apart High quality, integrated system Access some of the most prolific natural gas and crude oil supply basins in the U.S. Serves 97% of the largest petrochemical market of NGLs and 95% of refining capacity east of the Rockies Serves the largest natural gas markets in the United States Large footprint generates growth opportunities with long-term investment horizon Investment grade credit ratings; demonstrated access to capital in difficult markets Track record of financial discipline Pro forma liquidity was $1.6 billion at December 31, 2008 Lower cost of capital GP top tier IDRs capped at 25% vs. 50% for most MLPs Consistent increases of quarterly cash distribution rate Increased cash distribution rate 18 consecutive quarters; 27 times since IPO in 1998 Significant management ownership (34% of common units owned by management) Proven management team with an average of 27 years industry experience 4

5 Significant Sponsor Ownership Interests Aligned with Investors 30% L.P. Interest Dan Duncan, EPCO, Inc. and Affiliates 0.01% G.P. Interest* Enterprise GP Holdings L.P. (NYSE: EPE) 2% G.P. Interest* 78% L.P. Interest 3% L.P. Interest Enterprise Products Partners L.P. (NYSE: EPD) Unique ownership structure with one of the largest ownership positions by management in the MLP sector EPCO s actions have benefited EPD s debt and equity investors Purchased approximately $600 million of new equity since IPO in July 1998; includes $67 million purchased by EPCO in November 2008 and $65 million in February 2009 DRIP Capped GP s incentive split at 25% vs. 50% for no consideration in 2002 Contributed 50% of GulfTerra s GP to EPD in 2004 for no consideration to complete the $4 billion acquisition approximately $460 million in value Note: Percent ownership as of January 31, * The 2% G.P. interest in EPD, and the 0.01% GP interest in EPE represents a 100% ownership of the respective GP. 5

6 EPD s Premier Midstream Network Serves Largest Producing and Consuming Regions Approximately 36,000 miles of natural gas, NGL, crude oil and petrochemical pipelines 157 MMBbls of NGL and petrochemical storage capacity 27 Bcf of natural gas storage capacity 24 natural gas processing plants ROCKIES Asset Overview 13 fractionation facilities 6 offshore hub platforms NGL import / export terminals Butane isomerization complex Octane enhancement facility SAN JUAN MID-CONTINENT NGL Pipelines Natural Gas Pipelines Crude Oil Pipelines Fractionation Facilities Natural Gas Processing Plants Natural Gas / NGL Storage Facilities NGL Terminal / Storage Import / Export Terminals Platforms PERMIAN BARNETT SHALE MT. BELVIEU Assets in areas with 92% of production and 88% of proved reserves in the lower 48 states (1) (1) Source U.S. Department of Energy EIA, December

7 Leading Business Positions Integrated Across Midstream Energy Value Chain Production Platforms Natural Gas & Crude Oil Pipelines Gas Processing (Removes Mixed NGLs) NGL Pipelines NGL Fractionation (or separation) Storage Distribution NGL Products Ethane Isobutane Propane Normal Butane Natural Gasoline 7

8 Diversified Business Mix Diversification of businesses provides multiple earnings streams and reduces risk $2.1 Billion Gross Operating Margin Year Ended 12/31/08 8% 18% NGL Pipelines 9% 5% NGL Fracs 20% 40% Gas Processing & Marketing NGL Pipelines & Services (63%) Natural gas processing plants & related NGL marketing activities NGL fractionation plants NGL pipelines and storage Onshore Natural Gas Pipelines & Services (20%) Natural gas pipelines Natural gas storage facilities Natural gas marketing Offshore Pipelines & Services (9%) Natural gas pipelines Oil pipelines Platform services Petrochemical Services (8%) Propylene fractionation facilities Butane isomerization facilities Octane enhancement facilities 8

9 Consistent Results from Diversification and Integration $115 $95 $75 $55 $35 $15 $14 $12 $10 9 $ per Barrel $ per MMBtu Hurricanes Approx. $3 billion of new assets in service $525 $475 $425 $375 $325 $8 $6 $4 $2 $0 $ in Millions $275 $225 $175 $125 1Q05 2Q05 3Q05 4Q05 1Q06 2Q06 3Q06 4Q06 1Q07 2Q07 3Q07 4Q07 1Q08 2Q08 3Q08 4Q08 1Q05 2Q05 3Q05 4Q05 1Q06 2Q06 3Q06 4Q06 1Q07 2Q07 3Q07 4Q07 1Q08 2Q08 3Q08 4Q08 Adjusted EBITDA Crude (Bbl) Ethane (Bbl) Nat. Gas (MMBtu)

10 2008 was a Record Year in Operating Terms TBtu/d Offshore Onshore Onshore & Offshore Natural Gas Pipeline Volumes MBPD 2,200 2,000 1,800 1,600 NGL, Crude Oil & Petrochemical Pipeline Volumes 1,669 1,827 1,934 2, NGL / Propylene Fractionation & Butane Isomerization Volumes 573 1, Equity NGL Production MBPD MBPD

11 Also a Record Year in Financial Terms $2.5 Gross Operating Margin $2.25 Adjusted EBITDA $2.0 $2.1 $1.75 $2.0 $ Billions $1.5 $1.0 $1.1 $1.4 $1.5 $ Billions $1.25 $1.1 $1.3 $1.4 $ $ $1.5 $1.3 Distributable Cash Flow $1.4 $350 $300 $250 Retained DCF / Coverage $ x $ Billions $1.1 $0.9 $0.7 $0.5 $1.0 $1.0 $ $ Millions $200 $150 $100 $50 $0 $ x $98 1.1x $26 1.0x

12 Strong Fundamentals in Major Growth Basins Jonah / Pinedale Fields Low F&D costs should continue to encourage drilling, although at lower levels; expect modest production growth based on current producer estimates Piceance Basin Pioneer plant in service February 2008; Meeker II began service in February 2009 Producers in Piceance basin have approximately 300 new gas wells drilled and ready for pipeline connection San Juan Natural gas gathering volumes expected to remain relatively flat to 2008 despite decrease in new well connects; supported by a modest decline curve Barnett Shale Producers have over 350 wells completed and waiting on pipeline connections SAN JUAN Mid-America Pipeline Jonah Gathering ROCKIES Pioneer Plant Meeker Plant PICEANCE PERMIAN Hobbs Fractionator MID-CONTINENT BARNETT SHALE MT. BELVIEU 12

13 LLO G LLO G LLO G LLO G jalexander LLO G LLO G LLO G LLO G Independence Project Generates Substantial Cash Flow with Visibility to Future Production Independence Trail MISSISSIPPI CANYON DESO 1, First Production Independence Hub Platform Volumes Down 66 days for Flex Joint repairs INDEPENDENCE TRAIL ENTERPRISE PIPELINES PRODUCING ANCHOR FIELDS 2007 LEASE SALES 2008 LEASE SALES ATWATER VALLEY LLOYD MMBtu/d MILE RADIUS Miles 2008 gross operating margin was $163 million on an average of 664 MMBtu/d of natural gas handled; 1Bcf/d of capacity Expect producers to keep facility full with production from existing fields in 2009 Producers acquired rights to explore 123 blocks within a 50-mile radius of the Hub since September Q07 4Q07 1Q08 2Q08 3Q08 4Q08 3/5/09 13

14 NGLs Expected to Have Economic Advantage for Ethylene Production in 2009 Average 2009 Feedstock Basis Steam Cracker Combined Ethylene and Propylene Cost Curve Market rebalancing occurs across this slice Source CMAI 14

15 NGLs Have the Advantage Estimated US Ethylene Margin by Feedstock $0.12 $0.08 Cents per Pound of Ethylene $0.04 $0.00 -$0.04 -$0.08 -$0.12 -$0.16 -$0.20 -$0.24 Mar- 09 Apr May Jun Jul Aug Sep Oct Nov Dec Jan- 10 Feb Mar Apr May Jun Ethane Propane Butane Naptha Gas Oil Source: CMAI, quoted forward prices for feedstocks, EPD estimates as of March 2,

16 Natural Gas Processing Contract Mix % of Inlet Gas 100% 80% 60% 40% 5.3 Bcf/d (1) 5.1 Bcf/d (1) 11% Minimum Fee / 12% Margin Band 25% Fee-only 26% (Rockies) 28% Keepwhole 25% (79% Hedged in 2009) Fee-based Equity Barrels (MBPD) MBPD 113 MBPD 26 Minimum Fee / Margin Band 26 (Rockies) 69 Keepwhole (79% Hedged in 2009) 69 20% % of Proceeds 36% (52% Hedged in 2009) 37% 20 % of Proceeds 19 (52% Hedged in 2009) 18 0% High Gross Spread $0 C 2 Gross Spread on USGC 0 High Gross Spread $0 C 2 Gross Spread on USGC % of Proceeds / NGLs Keepwhole Fee Fee + Margin (1) $0 gross spread for ethane; Henry Hub vs. Mont Belvieu Updated: February

17 Major Growth Projects Project Description Q09 2Q09 3Q09 4Q09 Pioneer Processing Plant #1 DONE DEP South Texas NGL Pipeline System Phase 2 DONE CenterPoint Energy Wilson Pipeline Connection Phase 1 DONE Petal Natural Gas Storage Expansion 1.6 Bcf of subscribed capacity DONE Jonah Phase V Expansion Part 2 (EPD approximately 20%) DONE Wilson Storage Expansion Wilson Pipeline Connection DONE Petal Gas Storage Expansion 5 Bcf cavern DONE RGP Pipeline from Port Arthur to Mont Belvieu DONE Exxon Conditioning & Treating Facility Piceance Basin DONE White River Natural Gas Hub Piceance Basin DONE Mont Belvieu Well Utilization Program DONE Meeker Processing Plant #2 DONE Sherman Extension Natural Gas Pipeline DONE Norco-Garyville Pipeline Expansion DONE Shenzi Oil Pipeline Pinedale Gathering Pipeline expansion (EPD approximately 20%) Motiva to Mont Belvieu Propane & Butane Pipelines Hutchinson NGL Storage Expansion Marathon Gathering System Piceance Basin Phase 1 Trinity River Basin Lateral 17

18 Barnett Shale Growth Projects Sherman Extension: New 1.1 Bcf/d 178-mile pipeline extends EPD s Texas Intrastate System through growing Barnett Shale region to interconnect with Boardwalk s Gulf Crossing Project near Sherman, Texas Signed long-term agreements with producers for 1 Bcf/d of capacity Commenced operations February 2009 Currently flowing 340 MMcf/d; expect to be at 950 MMcf/d by April 1, 2009 Trinity River Basin Lateral: EPD is constructing a new 40-mile 36 /30 pipeline in the Trinity River basin area and Newark East Field into its Sherman Extension Capable of flowing up to 1Bcf/d of natural gas and providing producers new pipeline takeaway capacity Anchored by long-term agreements with major producers In-service: year-end

19 Financial Overview

20 Financial Objectives Maintain a strong balance sheet, liquidity and credit ratios that support investment grade credit ratings Prudently invest capital in the partnership through organic growth projects, joint ventures with strategic partners and acquisitions Focus on infrastructure assets serving producing and consuming regions with long-term durability Manage EPD s capital and distributable cash flow to support balance sheet, financial flexibility and cash distribution goals 20

21 Record Growth from Base Business and New Assets ($millions; except per unit amounts) Twelve Months Ended Dec. 31, Description % Change Gross Operating Margin by Segment: NGL Pipelines & Services $ 1,290 $ % Onshore Natural Gas Pipelines & Services % Offshore Pipelines & Services % Petrochemical Services % Total segment gross operating margin $ 2,057 $ 1,492 38% Net Income Earnings Per Unit (fully diluted) Adjusted EBITDA Debt / Adjusted EBITDA (1) Distributable Cash Flow ("DCF") $ 954 $ % $ 1.85 $ % $ 1,987 $ 1,429 39% 4.2x 4.3x $ 1,378 $ 1,001 38% Declared Distributions Per Unit $ 2.08 $ % Distribution Coverage 1.34x 1.03x Retained DCF $ 314 $ % (1) Debt is adjusted for 50% equity treatment of hybrids. Record 2008 results (despite hurricanes) Surpassed record 2006 and 2007 results Supported by increased volumes and margins from base businesses, and Strong contributions from new assets put into service in 2H 2007 and 2008 Independence platform & pipeline Meeker & Pioneer facilities Mid-America 50 MBPD expansion Hobbs fractionator Approximately $2.3 billion of growth capital projects expected to be put in service and generating cash flow in

22 History of Financial Discipline Conservative Leverage Through Investment Cycle Ratio of Debt/Adjusted EBITDA 6.0x 5.0x 4.0x 3.0x 2.0x 1.0x 0.0x Invested $13 Billion of Capital during period 4.2x 4.1x 4.3x 4.2x 3.7x $2,000 $1,500 $1,000 $500 $0 Construction Work in Progress ($mm) Excludes pro forma EBITDA adjustments associated with assets under construction 22

23 Substantial Financial Flexibility Added by Eliminating GP s 50% IDR $ in Millions $350 $325 $300 $275 $250 $225 $200 $175 $150 $125 $100 Cumulative Savings: $368MM 3Q04 4Q04 1Q05 2Q05 3Q05 4Q05 1Q06 2Q06 3Q06 4Q06 1Q07 2Q07 3Q07 4Q07 1Q08 2Q08 3Q08 4Q08 Landmark action taken by EPD s GP in December 2002 to cap GP s IDRs at 25% for no consideration 4Q 2008 annualized savings of $166 million Enhances EPD s financial flexibility by retaining cash flow for debt retirement or capital investment Significantly lowers long-term cost of capital LP Distributions GP Distributions Avoided 50% Splits 23

24 Providing Distribution Growth While Reinvesting in the Partnership 15% DCF Reinvested in Partnership ( ) Distributions Declared $2.25 $2.00 $1.75 $1.50 $1.25 $1.00 $0.75 $0.93 $1.05 $1.19 $1.36 9% CAGR $1.54 $1.47 $1.70 $1.83 $1.95 $2.08 $2.12 $579 $899 ($ in millions) $4,596 $0.50 $0.25 $ Current 1.2x LP Distribution Coverage LP Distributions GP Distributions Retained DCF 24

25 Demonstrated Access to Capital Markets In April 2008, issued $400MM of 5.65% 5-year senior notes and $700MM of 6.5% 10-year senior notes In November 2008, only BBB-/Baa3 rated company of which we are aware able to raise approximately $600MM of interim liquidity to provide additional margin of safety $375MM 364-day revolver; and $217MM Yen-based term loan In December 2008, EPD was the first BBB-/Baa3 issuer to access debt capital markets since July 2008; issued $500MM of 9.75% 5-year senior notes; high cost but successfully limited tenure to 5 years In December 2008, completed the $730MM DEP II drop-down transaction Received cash proceeds of $280MM and $450MM of DEP common units at $12.04/unit; 35% appreciated value at end of February 2009 DEP term loan priced at LIBOR+105 bps EPD now owns 74% of DEP LP units In January 2009, EPD completed first US equity offering of the year with the issuance of 10.6MM common units raising net proceeds of $226MM From November 2008 thru January 2009, EPD has raised approximately $1.6 billion of debt and equity to enhance liquidity and financial flexibility Pro forma liquidity at December 31, 2008 was $1.6 billion 25

26 Liquidity We re a Believer Always Have Been $1,750 $1,500 $ in millions $1,250 $1,000 $750 $500 $250 $0 3Q Q Q Q Q Q Q Q Q Q Q Q Q Q

27 EPD is Among Largest Partnerships Providing Investors Liquidity EPD s business and geographic diversification along with its size and liquidity provides investors with stability and an excellent platform for future growth. Enterprise Value (1) 1,500 1,472 Daily Liquidity (2) $20 $20 $19 1,200 1,172 $16 $Billions $12 $8 $4 $11 $9 $7 $6 $6 $5 000 s of units $0 KMP EPD ETP PAA OKS BWP EEP TPP (1) As of March 3, 2009 for market capitalization (2) Based on trailing 6-month average 0 EPD KMP ETP PAA TPP BWP EEP EPB Source: Bloomberg 27

28 Strong Fundamentals Set Us Apart High quality, integrated system Access some of the most prolific natural gas and crude oil supply basins in the U.S. Serves 97% of the largest petrochemical market of NGLs and 95% of refining capacity east of the Rockies Serves the largest natural gas markets in the United States Large footprint generates growth opportunities with long-term investment horizon Investment grade credit ratings; demonstrated access to capital in difficult markets Track record of financial discipline Pro forma liquidity was $1.6 billion at December 31, 2008 Lower cost of capital GP top tier IDRs capped at 25% vs. 50% for most MLPs Consistent increases of quarterly cash distribution rate Increased cash distribution rate 18 consecutive quarters; 27 times since IPO in 1998 Significant management ownership (34% of common units owned by management) Proven management team with an average of 27 years industry experience 28

29 Non-GAAP Reconciliations

30 Non-GAAP Financial Measures This presentation utilizes the Non-GAAP financial measures of Gross Operating Margin, Adjusted EBITDA and Distributable Cash Flow. In general, we define Gross Operating Margin as operating income before (i) depreciation, amortization and accretion expense; (ii) operating lease expense for which we do not have the payment obligation; (iii) gains and losses from asset sales and related transactions and (iv) general and administrative costs. The GAAP measure most directly comparable to Gross Operating Margin is operating income. We define Adjusted EBITDA as net income or loss plus interest expense, provision for income taxes and depreciation, amortization and accretion expense; less equity in earnings of unconsolidated affiliates; plus distributions received from unconsolidated affiliates. Adjusted EBITDA is commonly used as a supplemental financial measure by senior management and by external users of our financial statements, such as investors, commercial banks, research analysts and rating 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 cost 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 presented in this press release may not be comparable to similarly titled measures of other companies. The GAAP measure most directly comparable to Adjusted EBITDA is net cash flows provided by operating activities. In general, we define distributable cash flow as net income or loss plus: (1) depreciation, amortization and accretion expense; (2) operating lease expenses for which we do not have the payment obligation; (3) cash distributions received from unconsolidated affiliates less equity in the earnings of such unconsolidated affiliates; (4) the subtraction of sustaining capital expenditures and cash payments to settle asset retirement obligations; (5) the addition of losses or subtraction of gains from asset sales and related transactions; (6) cash proceeds from asset sales, the return of investment from unconsolidated affiliates or related transactions; (7) gains or losses on monetization of financial instruments less related amortization of such amount to earnings, if any; (8) transition support payments received from El Paso Corporation related to the GulfTerra merger; (9) minority interest expense associated with the public unitholders of DEP less related distributions to be paid to such holders with respect to the period of calculation; and (10) the addition of losses or subtraction of gains relating to other miscellaneous non-cash amounts affecting net income for the period. The GAAP measure most directly comparable to Distributable Cash Flow is net cash flows provided by operating activities. 30

31 Non-GAAP Reconciliations Enterprise Products Partners L.P. Gross Operating Margin by Segment (Dollars in 000s, Unaudited) For the Year Ended December 31, Gross Operating Margin by Segment: NGL Pipelines & Services $ 579,706 $ 752,548 $ 812,521 $ 1,290,458 Onshore Natural Gas Pipelines & Services 353, , , ,344 Offshore Pipelines & Services 77, , , ,083 Petrochemical Services 126, , , ,584 Total non-gaap gross operating margin 1,136,347 1,362,449 1,492,068 2,057,469 Adjustments to reconcile non-gaap Gross operating margin to GAAP Operating income: Depreciation, amortization and accretion in operating costs and expenses (413,441) (440,256) (513,840) (555,370) Operating lease expense paid by EPCO, Inc. in operating costs and expenses (2,112) (2,109) (2,105) (2,038) Gain (loss) on asset sales and related transactions operating costs and expenses 4,488 3,359 (5,391) 3,735 General and administrative costs (62,266) (63,391) (87,695) (90,550) Operating income per GAAP $ 663,016 $ 860,052 $ 883,037 $ 1,413,246 31

32 Non-GAAP Reconciliations Enterprise Products Partners L.P. Adjusted EBITDA (Dollars in 000s, Unaudited) Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q Reconciliation of non-gaap "Adjusted EBITDA" to GAAP "net income" and GAAP "net cash flows provided by operating activities" Net income $ 109,256 $ 70,659 $ 131,169 $ 108,424 $ 133,777 $ 126,295 $ 208,302 $ 132,781 Additions to net income to derive EBITDA: Equity in earnings of unconsolidated affiliates (8,279) (2,581) (3,703) 15 (4,029) (8,012) (2,265) (7,259) Distributions received from unconsolidated affiliates 21,838 17,070 8,480 8,670 8,253 12,095 6,737 15,947 Interest Expense (including related amortization) 53,413 56,746 60,538 59,852 58,077 56,333 62,793 60,820 Provision for income taxes 1,769 (1,034) 3,223 4,404 2,892 6,272 3,285 8,874 Depreciation, amortization and accretion in costs and expenses 101, , , , , , , ,780 Adjusted EBITDA 279, , , , , , , ,943 Adjustments to Adjusted EBITDA to derive net cash flows provided by operating activities (add or subtract as indicated by sign of number): Interest expense (53,413) (56,746) (60,538) (59,852) (58,077) (56,333) (62,793) (60,820) Amortization in interest expense (477) Provision for income taxes (1,769) 1,034 (3,223) (4,404) (2,892) (6,272) (3,285) (8,874) Loss (gain) on asset sales and related transactions (5,436) (61) (136) (3,204) 42 Operating lease expense paid by EPCO, Inc Minority interest 1, ,574 2, ,940 4,403 Deferred income tax expense (benefit) 1,802 2,073 1,952 2,767 1,487 7,693 3,198 2,049 Changes in fair market value of financial instruments (53) - 12 (10) Cumulative effect of changes in accounting principles ,208 (1,475) Provision for non-cash asset impairment charge Net effect of changes in operating accounts (58,920) (237,353) (17,929) 47, ,084 (172,392) 85,157 (76,431) Net cash flows provided by operating activities $ 164,246 $ (46,409) $ 226,796 $ 287,075 $ 494,276 $ 77,049 $ 414,699 $ 189,045 32

33 Non-GAAP Reconciliations Enterprise Products Partners L.P. Adjusted EBITDA (Dollars in 000s, Unaudited) Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q Reconciliation of non-gaap "Adjusted EBITDA" to GAAP "net income" and GAAP "net cash flows provided by operating activities" Net income $ 112,045 $ 142,154 $ 117,606 $ 161,869 $ 259,609 $ 263,270 $ 203,081 $ 228,061 Additions to net income to derive EBITDA: Equity in earnings of unconsolidated affiliates (6,179) 6,211 (13,960) (15,730) (14,592) (18,569) (14,876) (11,067) Distributions received from unconsolidated affiliates 16,947 18,079 17,317 21,250 28,576 27,434 13,842 28,701 Interest Expense (including related amortization) 63,358 71,275 85,075 92,056 91,946 95, , ,274 Provision for income taxes 8,788 (1,860) 2,073 6,256 3,657 6,926 6,610 9,208 Depreciation, amortization and accretion in costs and expenses 121, , , , , , , ,291 Adjusted EBITDA 316, , , , , , , ,468 Adjustments to Adjusted EBITDA to derive net cash flows provided by operating activities (add or subtract as indicated by sign of number): Interest expense (63,358) (71,275) (85,075) (92,056) (91,946) (95,809) (102,657) (110,274) Amortization in interest expense (768) 130 (1,242) (2,049) (697) Provision for income taxes (8,788) 1,860 (2,073) (6,256) (3,657) (6,926) (6,610) (9,208) Loss (gain) on asset sales and related transactions (73) 5,737 (219) (54) (165) (687) (858) (2,036) Operating lease expense paid by EPCO, Inc Minority interest 5,661 5,740 7,782 11,460 12,411 8,936 7,946 12,083 Deferred income tax expense (benefit) 1,596 2,492 1,454 2,764 (913) 3,442 3, Changes in fair market value of financial instruments 104 (406) 3,813 (2,530) 662 8,918 (4,119) (5,263) Effect of pension settlement recognition (114) Loss (gain) on early extinguishment of debt (7,093) Net effect of changes in operating accounts 168,903 (173,128) 114, ,034 (156,912) 69 (71,554) (129,033) Net cash flows provided by operating activities $ 420,751 $ 131,298 $ 385,786 $ 653,106 $ 265,065 $ 431,643 $ 276,336 $ 264,025 33

34 Non-GAAP Reconciliations Enterprise Products Partners L.P. Distributable Cash Flow (Dollars in 000s, Unaudited) Year Ended December 31, Reconciliation of Non-GAAP "Distributable cash flow" to GAAP "Net income" and GAAP "Net cash flows provided by operating activities" Net income $ 419,508 $ 601,155 $ 533,674 $ 954,021 Adjustments to Net income to derive Distributable cash flow: (add or subtract as indicated by sign of number): Amortization in interest expense (336) (3,858) Depreciation, amortization and accretion in costs and expenses 420, , , ,029 Operating lease expense paid by EPCO, Inc. 2,112 2,109 2,105 2,038 Deferred income tax expense 8,594 14,427 8,306 6,199 Monetization of interest rate hedging financial instruments ,895 (14,444) Amortization of net gains related to monetization of financial instrumen (3,602) (3,760) (4,044) (4,409) Cumulative effect of changes in accounting principles 4,208 (1,472) - - Equity in earnings of unconsolidated affiliates (14,548) (21,565) (29,658) (59,104) Distributions received from unconsolidated affiliates 56,058 43,032 73,593 98,553 Loss (gain) on asset sales and related transactions (4,488) (3,359) 5,391 (3,746) Proceeds from asset sales and related transactions 44,746 3,927 12,027 15,999 Sustaining capital expenditures (92,158) (119,409) (162,471) (188,699) Changes in fair market value of financial instruments 122 (51) Provision for impairment of long-lived asset Return of investment in Cameron Highway 47, El Paso transition support payments 17,250 14,250 9,000 - Loss (gain) on early extinguishment of debt (7,093) Minority interest expense DEP public unitholders ,879 17,300 Distribution to be paid to DEP public unitholders with respect to period - - (21,888) (25,079) Non-cash income related to write-off of reserve balance - - (7,605) (5,039) Cash expenditures for asset abandonment activities - - (5,036) (7,227) Accrued property damage repair costs related to Hurricanes Ike and G ,547 Distributable cash flow 906, ,580 1,001,161 1,378,186 Adjustments to Distributable cash flow to derive Net cash flows provided by operating activities (add or subtract as indicated by sign of number): Monetization of interest rate hedging financial instruments - - (48,895) 14,444 Amortization of net gains related to monetization of financial instrumen 3,602 3,760 4,044 4,409 Proceeds from asset sales and related transactions (44,746) (3,927) (12,027) (15,999) Sustaining capital expenditures 92, , , ,699 El Paso transition support payments (17,250) (14,250) (9,000) - Minority interest 5,760 9,079 30,643 41,376 Return of investment in Cameron Highway (47,500) Non-cash income related to write-off of reserve balance - - 7,605 5,039 Minority interest expense DEP public unitholders - - (13,879) (17,300) Distribution to be paid to DEP public unitholders with respect to period ,888 25,079 Cash expenditures for asset abandonment activities - - 5,036 7,227 Accrued property damage repair costs related to Hurricanes Ike and G (36,547) Effect of pension settlement recognition (114) Net effect of changes in operating accounts (266,395) 83, ,306 (357,431) Net cash flows provided by operating activities $ 631,708 $ 1,175,069 $ 1,590,941 $ 1,237,068 34