Morgan Keegan Equity Conference

Morgan Keegan Equity Conference September 5, 2008 Randy Fowler Executive Vice President & CFO

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

Overview Enterprise Products Partners L.P. (NYSE: EPD) is one of the largest publicly traded partnerships with an equity market capitalization of approximately $13 billion and an enterprise value of approximately $21 billion Continues to deliver record performance in 2006, 2007 and first half of 2008 EPD owns and operates one of North America s largest fully integrated midstream energy value chains with significant geographic and business diversity Serves producers and consumers of natural gas, NGLs and crude oil 3

Strong Fundamentals Sets Us Apart Quality of assets Access to the most prolific supply basins in the United States Serve 97% of the largest petrochemical market of NGLs and 95% of refining capacity east of the Rockies The largest natural gas markets in the United States Management s interest aligned with investors Substantial ownership: 34% of common units owned by management Proven management team with an average of 27 years industry experience Numerous organic growth opportunities vs. acquisitions Higher return and lower risk profile vs. high acquisition multiples Long-term investment horizon Lower cost of capital GP top tier IDRs capped at 25% vs. 50% Investment grade credit ratings; demonstrated access to capital in difficult markets Consistent increases of quarterly cash distribution rate 4

EPD s Premier Midstream Network Serves Largest Producing and Consuming Regions Approximately 35,000 miles of natural gas, NGL, crude oil and petrochemical pipelines 155 MMBbls of NGL and petrochemical storage capacity 33 Bcf of natural gas storage capacity 26 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 2007 5

Diversified Business Mix Diversification of businesses provides multiple earnings streams and reduces risk $1.9 Billion Gross Operating Margin LTM June 30, 2008 10% 13% 55% 22% NGL Pipelines & Services (55%) Natural gas processing plants & related NGL marketing activities NGL fractionation plants NGL pipelines and storage Onshore Natural Gas Pipelines & Services (22%) Natural gas pipelines Natural gas storage facilities Natural gas marketing Offshore Pipelines & Services (13%) Natural gas pipelines Oil pipelines Platform services Petrochemical Services (10%) Propylene fractionation facilities Butane isomerization facilities Octane enhancement facilities 6

Significant Sponsor Ownership Interests Aligned with Investors 30% L.P. Interest 1% 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* 3% L.P. Interest Enterprise Products Partners L.P. (NYSE: EPD) 2% G.P. Interest* 78% L.P. Interest 26% L.P. Interest Duncan Energy Partners L.P. (NYSE: DEP) Unique ownership structure with one of the largest ownership positions by management in the MLP sector $7.6 billion EPD: 34% or $4.4 billion EPE: 78% or $3.2 billion EPCO s actions have benefited EPD s debt and equity investors Purchased approximately $460 million of new equity since the IPO in July 1998 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 Formed Duncan Energy Partners in 2007 as a vehicle to support funding EPD s capital program by providing an alternative source of equity capital at a lower expected long-term cost with EPD retaining indirect control of the assets * Note that the 2% G.P. interest in EPD and DEP, and the 0.01% GP interest in EPE represents a 100% ownership of the respective GP 7

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. $24 $20 $23 Enterprise Value (1) Daily Liquidity (2) 600 560 $21 500 488 456 429 $16 400 380 $Billions $12 $8 $13 $10 $8 $8 000 s of units 300 200 225 219 $6 $4 100 $0 KMP EPD ETP PAA OKS EEP TPP (1) As of August 27, 2008 for market capitalization (2) Based on trailing 6-month average 0 EPD KMP ETP BWP PAA EEP TPP Source: Bloomberg 8

Major Organic Growth Projects

Major Organic Growth Projects Expected Start Dates Project Description 1Q08 2Q08 3Q08 4Q08 2009 & Beyond Pioneer Processing Plant #1 DEP South Texas NGL Pipeline System - Phase 2 (EPD 34%) CenterPoint Energy - Wilson Pipeline Connection - Phase 1 Petal Natural Gas Storage Expansion - 1.6 Bcf of subscribed capacity NGL Pipeline from Hobbs frac to Flint Hill's facility - Odessa Jonah Phase V Expansion - Part 2 (EPD approximately 20%) Wilson Storage Expansion - Wilson Pipeline Connection Petal Gas Storage Expansion - 5 Bcf cavern RGP Pipeline from Port Arthur to Mont Belvieu Sherman Extension Natural Gas Pipeline Pinedale Gathering Pipeline expansion (EPD approximately 20%) Meeker Processing Plant #2 Mont Belvieu Well Utilization Program Norco-Garyville NGL Pipeline Expansion Exxon Conditioning & Treating Facility - Piceance Basin White River Natural Gas Hub - Piceance Basin Wilson Storage Expansion - 5 Bcf cavern Marathon Gathering System - Piceance Basin - Phase 1 Petal Gas Storage Expansion - 2 additional caverns - 10 Bcf Chaparral Gas Processing Facility - Southeast Texas Hutchinson NGL Storage Expansion Shenzi Oil Pipeline Texas Offshore Port System (TOPS) Barnett Shale Pipeline Expansions Motiva to Mont Belvieu Propane & Butane Pipelines DONE DONE DONE DONE DONE DONE DONE DONE 10

Western Franchise Growth Projects 75% Complete Bcf/d 14 12 10 8 6 4 2 Rockies Production Forecast 2006 Rocky Mountain Production Constrained by Take-Away Capacity Jonah Gathering Pioneer Plant Meeker Plant PICEANCE 0 2000 2002 2004 2006 2008 2010 2012 2014 Source: PIRA MMcf/d 1,400 1,200 1,000 800 600 400 Piceance Basin Production 19% CAGR 692 534 443 876 1,109 1,276 Mid-America Pipeline Hobbs Fractionator 200 0 2002 2003 2004 2005 2006 2007 CAGR = Compound Annual Growth Rate Source: HPDI, Inc. 11

Barnett Shale Continues to Exceed Expectations Jan 05 1.1 75 Gas Production (Bcf/d) Rigs Producing Wells Aug. 08 Est. 4.3 200 9,300 6+ Bcf/d by 2011 Premiere shale play in the United States Producers exceeding original expectations Technology continues to improve deliverability and recoveries Basin footprint is expanding 3,781 12

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 new long-term agreements with producers for 900 MMcf/d of capacity Interim service on Southern segment began August 2008 Fully in-service: 4Q 2008 New pipeline lateral: EPD will construct 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: 3Q 2009 13

Independence Hub and Trail Largest single organic capital project to date 1 Bcf/d natural gas Hub platform and 134-mile Trail pipeline Received first production in July 2007 Flowing approx. 900 MMBtu/d Annual net gross operating margin would be approx. $190 million on an annual average flow rate of 850 MMBtu/d 2Q 2008 impacted by: downtime ($29 million) and repairs ($14 million) 14

LLOG LLOG LLOG LLOG ja lexa nder2 0 0808 2 1 LLOG LLO G LLOG LLOG LLOG LLOG LLOG LLOG LLOG Independence Hub and Trail Project Visibility to Future Production Independence Trail MISSISSIPPI CANYON INDEPENDENCE TRAIL ENTERPRISE PIPELINES PRODUCING ANCHOR FIELDS 2007 LEASE SALES 2008 LEASE SALES 50 MILE RADIUS ATWATER VALLEY LLOYD DESOTO Diamond Producers acquired rights to explore 123 blocks within a 50-mile radius of the Hub since September 2007 Reinforcing the future value of the platform Evaluating options to increase take-away capacity Franchise further enhanced by proximity to 113 blocks recently leased outside the 50-mile radius but within the same prolific gas area MMS estimates 5.8 Tcf potential for the areas east and south of the Hub Murphy announced gas discovery at Diamond 65 miles southeast of Hub 0 10 20 40 Miles 15

Texas Offshore Port System ( TOPS ) Enterprise Products Partners L.P. (NYSE: EPD), TEPPCO Partners, L.P. (NYSE: TPP) and Oiltanking Holding Americas, Inc. (Oiltanking) have formed a joint venture to design, construct, own and operate the Offshore Port to Texas City System and Texas City to Port Arthur system Systems facilitate deliveries of waterborne crude oil cargoes to refining facilities along the upper Texas Gulf Coast Comprised of two complementary projects that combined will include: Offshore port; 2 onshore storage facilities with approximately 5.1 MMBbls of total crude oil storage capacity; 2 crude oil pipelines totaling 160 miles; Capacity to deliver up to 1.8 MMBPD along the Texas Gulf Coast; and Capacity is expandable with the construction of additional offshore facilities, and the onshore pipeline could be extended to deliver barrels to refining facilities in Lake Charles, LA. Supported by long-term contracts with Motiva Enterprises LLC and ExxonMobil Corporation totaling approximately 725 MBPD of crude oil throughput 16

Offshore Port Illustration 17

Financial Overview

Strong Financial Performance EBITDA & Debt to EBITDA Ratio Distributable Cash Flow & Coverage $525 $491 $506 $400 $383 $450 $350 $347 $Millions $375 $300 $225 $335 $341 $403 $Millions $300 $250 $200 $294 $223 $262 $150 $150 4.0x 4.5x 4.3x 4.2x 4.0x $100 1.25x 0.89x 1.05x 1.57x 1.38x $75 $50 $0 2Q 2007 3Q 2007 4Q 2007 1Q 2008 2Q 2008 $0 2Q 2007 3Q 2007 4Q 2007 1Q 2008 2Q 2008 19

Record Growth from Base Business and New Assets ($millions; except per unit amounts) Six Months Ended June 30, Description 2008 2007 % Change Gross Operating Margin by Segment: NGL Pipelines & Services $ 608 $ 399 52% Onshore Natural Gas Pipelines & Services 233 160 46% Offshore Pipelines & Services 117 51 129% Petrochemical Services 99 88 13% Total segment gross operating margin $ 1,057 $ 698 51% Net Income Earnings Per Unit (fully diluted) EBITDA Distributable Cash Flow $ 523 $ 254 106% $ 1.03 $ 0.46 124% $ 997 $ 641 56% $ 730 $ 516 41% Declared Distributions Per Unit $ 1.02 $ 0.96 7% Distribution Coverage (1) 1.47x 1.09x Retained Distributable Cash Flow $ 212 $ 38 458% (1) Distribution coverage is with respect to distributions declared for the first six months. Record operating & financial results 6 Mos. 2008 vs 6 Mos. 2007 Supported by increased volumes and margins from our base businesses, and Strong contributions from new assets put into service in second half 2007 and first half of 2008 Independence Hub platform & Trail pipeline Meeker & Pioneer cryogenic gas processing facilities Mid-America 50 MBPD expansion $1.5 billion of growth capital projects expected to be completed & begin generating cash flow in second half 2008 & first half 2009 20

History of Financial Discipline Managing Distributable Cash Flow $ in millions 15% DCF Reinvested in Partnership (1999 2Q 2008) $501 $798 How many Partnerships do you know that have retained >1.5 times more DCF than was paid to the GP? Hint: It s a short list! 1.2x LP Distribution Coverage $4,128 LP Distributions GP Distributions Retained DCF 21

Lower Cost of Capital & Added Financial Flexibility by Eliminating GP s 50% IDR $ in Millions $325 $300 $275 $250 $225 $200 $175 $150 $125 $100 Cumulative Savings: $288MM 3Q04 4Q04 1Q05 2Q05 3Q05 4Q05 1Q06 2Q06 3Q06 4Q06 1Q07 2Q07 3Q07 4Q07 1Q08 2Q08 LP Distributions GP Distributions Avoided 50% Splits Landmark action taken by EPD s GP in December 2002 to cap GP s IDRs at 25% for no consideration 2Q 2008 annualized savings of $143 million Significantly lowers long-term cost of capital Enhances EPD s financial flexibility by retaining cash flow for debt retirement, capital investment and increases in LP distribution rate Benefits to investors are tangible, significant & growing! 22

Proven Track Record (1) Total Assets - $Billion Total Return w/reinvested Distributions $20 $18 $16 $14 $12 $10 $8 $6 $4 $2 $0 800% 700% 600% 500% 400% 300% 200% 100% 0% -100% $0.7 Jul- 98 $1.5 $2.0 $2.4 39% CAGR $4.2 $4.8 $14.0 $12.6 $11.3 $16.6 673% 353% 24% 1999 2000 2001 2002 2003 2004 2005 2006 2007 Jun- 08 EPD Alerian MLP Index S&P 500 (1) Past results may not be representative of future performance. $18.2 1999 2000 2001 2002 2003 2004 2005 2006 2007 2Q08 Distributions Declared Average Annual Compound Return $2.50 $2.00 $1.50 $1.00 $0.50 $0.00 20% 15% 10% 5% 0% -5% -10% -15% 9% CAGR $1.54 $1.47 $1.36 $1.19 $1.05 $0.93 $1.95 $2.05 $1.83 $1.70 1999 2000 2001 2002 2003 2004 2005 2006 2007 2Q 2008 Periods Ending June 30, 2008 16.0% 12.5% 10.2% 9.3% 4.4% 2.4% -1.1% -4.3% -4.3% -11.9% -10.7% -13.1% YTD Year 1 Year 2 Year 3 EPD Alerian MLP Index S&P 500 Source: Bloomberg 23

Non-GAAP Reconciliations

Non-GAAP Financial Measures This presentation utilizes the Non-GAAP financial measures of Gross Operating Margin, 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 on the sale of assets and (iv) general and administrative costs. The GAAP measure most directly comparable to Gross Operating Margin is operating income. We define EBITDA as net income plus (i) interest expense, (ii) provision for income taxes and (iii) depreciation and amortization and accretion expense. EBITDA is commonly used as a supplemental financial measure by management and external users of our financial statements. Because EBITDA excludes some, but not all, items that affect net income or loss and because these measures may vary among other companies, the EBITDA data presented in this presentation may not be comparable to similarly titled measures of other companies. The GAAP measure most directly comparable to 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; (5) the addition of losses or subtraction of gains relating to the sale of assets; (6) cash proceeds from the sale of assets or return of investment from unconsolidated affiliates; (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; (10) the addition of losses or subtraction of gains relating to other miscellaneous non-cash amounts affecting net income for the period; and (11) the subtraction of cash expenditures for asset retirement obligations. The GAAP measure most directly comparable to Distributable Cash Flow is net cash flows provided by operating activities. 25

Non-GAAP Reconciliations Enterprise Products Partners L.P. Gross Operating Margin by Segment (Dollars in 000s, Unaudited) 2007 2008 1Q 2Q 3Q 4Q 1Q 2Q Gross operating margin by segment: NGL Pipelines & Services $ 190,694 $ 208,805 $ 190,209 $ 222,813 $ 289,742 $ 317,649 Onshore Natural Gas Pipelines & Services 76,515 83,163 75,424 100,581 109,905 123,172 Offshore Pipelines & Services 19,707 31,046 46,676 74,122 81,571 35,317 Petrochemical Services 37,583 50,334 51,412 32,984 41,003 58,219 Total segment gross operating margin 324,499 373,348 363,721 430,500 522,221 534,357 Adjustments to reconcile Non-GAAP "Gross Operating Margin" to GAAP "Operating Income" Depreciation, amortization and accretion in operating costs and expenses (119,492) (121,161) (133,869) (139,318) (133,922) (136,262) Operating lease expense paid by EPCO, Inc. in operating costs and expenses (526) (527) (526) (526) (527) (526) Gain (loss) on sale of assets in operating costs and expenses 73 (5,737) 219 54 165 677 General and administrative costs (16,630) (31,361) (18,715) (20,989) (21,205) (23,976) Operating income per GAAP $ 187,924 $ 214,562 $ 210,830 $ 269,721 $ 366,732 $ 374,270 26

Non-GAAP Reconciliations Enterprise Products Partners L.P. EBITDA (Dollars in 000s, Unaudited) 2007 2008 1Q 2Q 3Q 4Q 1Q 2Q Reconciliation of non-gaap "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 Additions to net income to derive EBITDA: Interest Expense (including related amortization) 63,358 71,275 85,075 92,056 91,946 95,809 Provision for income taxes 8,788 (1,860) 2,073 6,256 3,657 6,926 Depreciation, amortization and accretion in costs and expenses 121,089 123,823 136,739 142,447 135,846 139,546 EBITDA 305,280 335,392 341,493 402,628 491,058 505,551 Adjustments to 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) Amortization in interest expense 132 69 231 (768) 130 (1,242) Provision for income taxes (8,788) 1,860 (2,073) (6,256) (3,657) (6,926) Equity in (income) loss of unconsolidated affiliates (6,179) 6,211 (13,960) (15,730) (14,592) (18,569) Distributions received from unconsolidated affiliates 16,947 18,079 17,317 21,250 28,576 27,434 (Gain) loss on sale of assets (73) 5,737 (219) (54) (165) (687) Operating lease expense paid by EPCO, Inc. 526 527 526 526 527 526 Minority interest 5,661 5,740 7,782 11,460 12,411 8,936 Deferred income tax expense (benefit) 1,596 2,492 1,454 2,764 (913) 3,442 Changes in fair market value of financial instruments 104 (406) 3,813 (2,530) 662 8,918 Effect of pension settlement recognition - - - 588 (114) - Loss on early extinguishment of debt - - - 250 - - Net effect of changes in operating accounts 168,903 (173,128) 114,497 331,034 (156,912) 69 Net cash flows provided by operating activities $ 420,751 $ 131,298 $ 385,786 $ 653,106 $ 265,065 $ 431,643 27

Non-GAAP Reconciliations Enterprise Products Partners L.P. Distributable Cash Flow (Dollars in 000s, Unaudited) Reconciliation of non-gaap "Distributable cash flow " to GAAP "Net 2007 2008 1Q 2Q 3Q 4Q 1Q 2Q income" and GAAP "Net cash flow s provided by operating activities" Net income $ 112,045 $ 142,154 $ 117,606 $ 161,869 $ 259,609 $ 263,270 Adjustments to derive Distributable cash flow (add or subtract as indicated by sign of number): Amortization in interest expense 132 69 231 (768) 130 (1,242) Depreciation, amortization and accretion in costs and expenses 121,089 123,823 136,739 142,447 135,846 139,546 Operating lease expense paid by EPCO 526 527 526 526 527 526 Deferred income tax expense 1,596 2,492 1,454 2,764 (913) 3,442 Monetization of interest rate hedging financial instruments - 42,269 6,626-6,251 (28,395) Amortization of net gains related to monetization of financial instruments (965) (1,056) (1,172) (851) (1,590) (1,593) Equity in earnings of unconsolidated affiliates (6,179) 6,211 (13,960) (15,730) (14,592) (18,569) Distributions received from unconsolidated affiliates 16,947 18,079 17,317 21,250 28,576 27,434 Loss (gain) on sale of assets (73) 5,737 (219) (54) (165) (687) Proceeds from sale of assets 91 924 918 10,094 119 395 Sustaining capital expenditures (25,511) (47,600) (46,681) (42,679) (25,012) (43,631) Changes in fair market value of financial instruments 104 (406) 3,813 (2,530) 662 8,918 Minority interest expense DEP public unitholders 2,831 3,283 3,242 4,523 4,353 4,766 Distribution to be paid to DEP public unitholders w ith respect to period (3,648) (5,980) (6,130) (6,130) (6,130) (6,279) Cash expenditures for asset abandonment activities - - - (5,036) (4,906) (572) Non-cash income related to w rite-off of reserve balance - - - (7,605) - - El Paso transition support payments 3,000 3,000 3,000 - - - Distributable cash flow 221,985 293,526 223,310 262,090 382,765 347,329 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 - (42,269) (6,626) - (6,251) 28,395 Amortization of net gains related to monetization of financial instruments 965 1,056 1,172 851 1,590 1,593 Proceeds from sale of assets (91) (924) (918) (10,094) (119) (395) Sustaining capital expenditures 25,511 47,600 46,681 42,679 25,012 43,631 El Paso transition support payments (3,000) (3,000) (3,000) - - - Minority interest 5,661 5,740 7,782 11,460 12,411 8,936 Minority interest expense DEP public unitholders (2,831) (3,283) (3,242) (4,523) (4,353) (4,766) Cash expenditures for asset abandonment activities - - - 5,036 4,906 572 Effect of pension settlement recognition - - - 588 (114) - Distribution to be paid to DEP public unitholders w ith respect to period 3,648 5,980 6,130 6,130 6,130 6,279 Non-cash income related to w rite-off of reserve balance - - - 7,605 - - Loss on early extinguishment of debt - - - 250 - - Net effect of changes in operating accounts 168,903 (173,128) 114,497 331,034 (156,912) 69 Net cash flows provided by operating activities $ 420,751 $ 131,298 $ 385,786 $ 653,106 $ 265,065 $ 431,643 28