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EXHIBIT 99.1

Table of Contents

Introduction

Michael A. Creel

Business Introduction

Robert G. Phillips

Natural Gas Pipelines / Storage / Offshore

James H. Lytal

Natural Gas Processing / Natural Gas Liquids (NGLs)

A.J. “Jim” Teague

Regulated NGL Pipelines

James M. Collingsworth

Petrochemical Services

Gil H. Radtke

Corporate Governance

Michael A. Creel

Financial Overview

Michael A. Creel

Closing Remarks

Robert G. Phillips

Michael A. Creel – Introduction

If we can get everybody to take a seat, we’ll get started. Be sure everybody has a big cup of coffee first. I’d like to welcome everybody to our Annual Analyst Conference. We’ve unfortunately had to miss a few times because of other projects. We do have a lot that we’re working on today, so don’t get the sense that we’ve slowed down a bit.

Page 2 – Forward Looking Statements

Before we get started, I want to direct you to the first slide in the presentation, forward-looking statements. We will be making forward-looking statements during the course of this presentation. Feel free to read through that at your leisure.

Page 3 – Use of Non-GAAP Financial Measures

We are also going to use some non-GAAP financial measures and we’ve got in the back of the presentation a description of what those are and a reconciliation to the GAAP financial measures.

Page 4 – Meeting Agenda

A number of people will be presenting today on different areas. I think you’re going to get a really good, in-depth view of what the company is doing, each of our business segments, our growth strategies and get a sense of what that means for the coming years.

Page 6 – Business Overview

First of all we’ll talk a little bit about Enterprise in the broadest sense. We are one of the largest publicly traded energy partnerships. We serve producers and consumers of natural gas, natural gas liquids and crude oil. We have an enterprise value in excess of $16 billion; we’re ranked 183 on the Fortune 500 list. We’ve grown quite a bit in the last seven or eight years and we’ll talk about that growth in depth.

We are currently the only integrated North American midstream network that includes natural gas and NGL transportation, fractionation processing, storage and import/export services. We’ll talk a lot about natural gas liquids or NGLs. Those are products that are found in natural gas. They’re ethane, propane, butane, both normal butane and isobutane, and natural gasolines. All of these are raw materials that are used by the petrochemical industry or the motor gasoline industry, as well as for home heating in the case of propane.

Our assets link producers and consumers of natural gas and NGLs from some of the biggest supply basins in the United States and we’ll show you the focus that we have in some of those basins. And we link that with the largest consumers of NGLs in the US and in the international markets. Very important to us is that we have leading positions in each of the business segments where we operate.

Page 7 – EPD’s Partnership Structure

We’ll talk more later in the presentation about the structure of Enterprise and the ownership, but it is very important to us that we have a very focused sponsor in EPCO and its affiliates. EPCO and its affiliates own 31% of our common units directly. They own additional units through their ownership interests in Enterprise GP Holdings, which owns not only our general partner, but owns about 13.5 million common units.

EPCO has been a consistent supporter of Enterprise, a big reason for its success and growth. They purchased $450MM worth of new Enterprise units since our IPO. The general partner back in December of 2002 elected to cap the incentive distribution rate at 25%, giving up the 50% split. That was unheard of in the MLP industry. It is one of the reasons that we’ve been able to successfully grow and we think we’re going to have a competitive advantage going forward. In addition, when we did the GulfTerra merger back in September of 2004, our general partner acquired 50% of the GulfTerra general partner and gave that to the partnership for no cost, about $460MM of value that the general partner contributed to the partnership.

The total value of EPCO’s holdings in Enterprise Products Partners and in Enterprise GP Holdings is about $6.7 billion, and they get about $360MM a year in cash distribution. So you can see that the focus of EPCO is on growing the partnership, on creating value. The interests of EPCO are directly aligned with those of our public unit holders and debt holders.

Page 8 – Key Investment Considerations

We’ll talk a lot about the assets, but suffice it to say, we have very strategically located assets, again, in the most prolific basins in the United States. You’ll see our focus in the Gulf of Mexico area, in Texas and the Rocky Mountain area. Strategically located – it’s really the best positioned midstream company.

Over 90% of our gross operating margin today comes from our fee-based businesses. It’s very different than it was maybe five years ago, but you’ll see, as we go through the presentation, how stable our cash flows and our operating margins have been.

One of the things that’s very important to us as we continue grow the company is to maintain strategic relationships, both on the supply side and the demand side. We do business with all of the major chemical companies, petrochemical companies, refiners, the big E&P companies and they look to us as a consistent provider of quality service.

Another thing that’s very important to us is to maintain an investment grade credit rating. That’s important to us for a number of reasons. As we continue to grow, we want to make sure that we have access to capital at reasonable costs and on reasonable terms. And for that reason, the investment grade credit rating is very important to us, but it’s also important to our customers and to our joint venture partners. We’ve done a lot of work to get the balance sheet in shape. We’re proud of the progress that we’ve made, but we’re not satisfied with it yet. We’re going to continue to work on it and make sure that going forward we’re able to grow the company in a way that’s financially responsible and that we meet the objectives, not only of our equity holders but also of our debt holders.

Again, the 25% split that we have now, the maximum rate that we pay out to the general partner, gives us a decided advantage in terms of cost to capital. And a little bit later in the presentation we’re going to talk a lot about cost of capital, a little bit about MLP math and hopefully be able to show you how we’re different from the typical MLP, how we look at things differently and how we think that’s going to translate into better growth prospects.

And we also have a very experienced management team. The management team has grown over the years with each transaction that we’ve done, and with the GulfTerra merger. We’ve brought in more and more high-quality people. We’ve got probably the best team with the most experience in the industry. We’re very proud of that group. We think it’s the right group to continue to grow and outperform the industry.

Page 9 – Diversified Business Mix

Our business mix has become quite a bit more balanced over the years. A lot of that has to do with investing in new assets. Some of it has to do with the merger that we did with GulfTerra, or the acquisition of the Mid-America Seminole Pipelines back in 2002. But today about half of our gross operating margin comes from our NGL pipelines and services segment. That includes our NGL pipelines, our processing plants, the related marking activities, fractionation facilities, as well as our NGL storage facilities.

About 30% of our gross operating margin comes from our onshore natural gas pipelines and services. That’s our pipelines in the Permian and San Juan Basins in Texas, the Texas Intrastate System, the Acadian system in Louisiana, as well as our natural gas storage.

About 14% of our gross operating margin comes from our petrochemical segment. That includes our propylene fractionation business, our butane isomerization business, as well as our isooctane and octane enhancement business. Gil Radtke is going to talk about those businesses, which are pretty exciting in today’s market, really doing very, very well.

And last is our offshore pipelines and services. It today represents about 6% of our gross operating margin, but that’s poised to grow as we have more projects coming on stream, particularly the Independence Hub and Trail that we expect to come in the early part of 2007, a very exciting project that James Lytal is going to get into quite a bit more.

Page 10 – Consistent Results from Diversified Businesses

This shows you our gross operating margin and our consolidated EBITDA for the six quarters, seven quarters since the GulfTerra merger. You can see that in the second quarter of 2005, we did have an $11MM charge for refinancing Cameron Highway debt. We also had some charges related to the startup of our isooctane facility, but you can see that the cash flows have been consistent, and this is in spite of the fact that we’ve had three hurricanes over this time. We had two hurricanes in the third quarter of 2005 and you can see how solid the gross operating margin and the EBITDA were over that period.

One of the things that investors perhaps overlooked was the fact that, while the hurricane did disrupt some of our businesses, it was in a specific geographic region. We are very spread out over the country, across different areas of the country, as well different product lines, and a disruption in one part of our system actually creates opportunities in the others. So in spite of disruptions in the Louisiana-Gulf Coast area, the rest of our business has profited and more than made up for it.

Page 11 – EPD’s Organic Growth and Lower Cost of Capital Drives Cash Flow Accretion

Again, we look at cash in the MLP business. That’s what our investors look for. Cash is generated by new investment and that new investment is going to be funded by a mix of debt and equity. We need to look at the effect of the funding mechanism for our capital investments to make sure that we have a sustainable, viable business model. And a lot of investors, a lot of analysts, focus only on the current cash cost of equity. So they’ll look at a transaction that’s being funded with say 50% debt, 50% equity. They assume that the debt cost is 6%, the equity has got a 7% yield and, voila, a 10% project is accretive. We’re going to talk about that a little later, but the fact of the matter is, you really have to look forward at the cost of that equity over time as you increase distributions and you come to some rather different conclusions when you do that.

Certainly in today’s market when the acquisition market is very hot, you’re seeing acquisitions of assets at 10x, 12x, even 14x multiples. We don’t think that works for an MLP, particularly when you’re buying a mature asset with little growth prospects. We have a very different approach and certainly with our backlog of organic growth projects, and higher return projects, coupled with the fact that we have the lower cost of capital by virtue of our maximum of 25% split, we think, again, that we have a very competitive advantage against many, if not most, of our competitors.

And with that I’ll turn it over to Bob for a brief introduction.

Robert G. Phillips – Business Introduction

Thanks, Mike, and good morning to all of you. Thanks for joining us. I was reflecting back on all of my years of making analysts meetings and I realized that this is the first opportunity that the new Enterprise has had to present its complete business model in amazing detail to the analysts. You guys have done an outstanding job of tracking our company over the two years since the merger, and I think for the most part, all of you have a real good sense as to what makes Enterprise special in the midstream business. Hopefully we can build on that today.

We have spent a lot of time going into great detail regarding our business model and the competitive strengths of our assets. In fact, this presentation is designed to give you a keen understanding of the strength of those assets, the focus of our growth strategy, and what I hope you’ll take away, the experience, competitiveness and aggressiveness of this management team. It is truly unique in this business and I’m pleased to be a part of it and proud to work with Dan and the rest of the managers at Enterprise to execute this strategy. We think all of these factors really combine to make us the most attractive and most sustainable midstream business in the MLP sector.

Slide 13 – Premier Network of Midstream Energy Assets

Given the strength of these assets and the competitive position that we enjoy in the markets that we serve, no one has a better geographic footprint for the midstream industry than Enterprise does. We touch all the right spots. We keep talking about our value chain and this is a great illustration of where it starts and where it goes.

It starts in the Rocky Mountains, it starts in the San Juan, the Permian, South Texas, the Barnett Shale, the Deepwater trend of the Gulf of Mexico, all the areas where the industry is seeing growth and production, that’s where we are. We have strong competitive positions in each of these basins where we’re going to benefit over the next 5 to 10 years from growth in production levels. That’s natural gas, natural gas liquids and crude oil. So we are a multi-commodity, multi-service player in the growth that we’re going to see over the next 5 to 10 years. That gives us an enormous advantage when we use the value chain model. And as I said, it starts in those supply regions and extends all the way through our gathering systems, our processing plants, our fractionation plants, and our storage and distribution network, into the markets that we serve. And we’re more well connected to the market area than any other midstream player.

So from the supply side where we access 90% of the natural gas production and 85% of the reserves, to the market area where we have almost 100% coverage to the petrochemical refiners, nobody is as well connected as Enterprise. It is a very competitive world that we live in out there. And don’t kid yourself. You guys know because you cover our competitors, you write about their strategies, you talk about their projects. I don’t think anybody is better positioned competitively in the industry than Enterprise.

Slide 14 – Competitive Advantages

Of course it starts with a great set of assets. As Mike said, we’ve got the most strategically located assets in the business. But all these other factors are important to be successful in this business. It’s a highly competitive business.

The integrated value chain is a unique strategy. It’s our business model. We have the only nationwide, fully integrated energy value chain, where we earn fees at each link in the chain. Earning fees at each link talks about cash flow stability, and from a competitive standpoint, winning business, not losing customers. It’s very unique among midstream companies. We don’t like to lose a contract. We don’t like to lose a customer. We use the value chain to retain customers and attract new business, and it works very well for us. And that is one of the ingredients to our success, using the value chain to attract customers and retain customers. That is a huge advantage.

Our diversified portfolio clearly, over the last eight quarters, has offset the inherent cyclicality in some of these midstream businesses and that allows us to provide a long-term cash flow generation to our shareholders. The size and scale of Enterprise – as I said, we have the biggest geographic footprint. From scale comes business opportunities. We have an incomparable set of growth opportunities. Sure, everybody has growth projects today. Trust me, nobody has the portfolio of growth projects that we have across multiple business lines, in a number of different geographic regions. We’ll put ours up against anybody.

Enterprise’s legendary cost to capital is a true competitive advantage for us. It’s an attribute and it should not be overlooked in our ability, again, to attract new business. It retains business and continues to generate cash flow from our assets. Mr. Duncan has been in the business over 40 years. He’s very carefully put this company together. These assets are all interlinked to provide a fully integrated value chain. I think it’s a brilliant strategy, one that’s clearly paying off in the market that we operate in today, and so the strength of our GP is a real competitive advantage. Our experienced management team is making a huge difference in our ability to attract new business.

Slide 15 – Leading Business Positions Across Midstream Energy Value Chain

This is the value chain. Many of you have seen this slide before. Clearly, we enjoy a strong competitive position across the value chain. Let’s look at each individual business – gas gathering, gas processing, NGL pipelines, fractionation, storage, the import/export business, and distribution to our market customers. These are our competitors. This is our yardstick, if you will. And we are a leader, or near the top, in each of the businesses that we operate in. In many cases we’re substantially larger than our nearest competitor, again, a huge competitive advantage in terms of building the business, retaining the business and moving forward by growing our business.

I think the integrated business model allow us to leverage our business relationships. Mike talked about how important the relationships are with our large major oil and gas companies, who are both suppliers into our value chain, as well as petrochemical and refinery off takers of feed stock and blend stock. That once again gives us a huge advantage in dealing with those customers. And those business relationships span the entire midstream spectrum, from the well head to the burner tip. By investing in this model over the years, we have established a substantial competitive position in each of these businesses. We are an aggressive management team, so we will maintain our competitive position in each of these businesses.

Page 16 – Integrated Midstream Energy Services: Fees are earned at each link of value chain

The essence of our business model is clearly what we call the value chain and I think this is a good illustration of it. It allows us to extend our reach and invest in new projects, to bring new supplies into the value chain, to expand our facilities as volume growth occurs and as requirements dictate, to enhance our margins as demand for services increases from time to time. Importantly, to capture higher all-in returns on investment by using the entire value chain, by attributing downstream economics to upstream investments. That’s a theme that you’re going to hear over and over and over again. It’s a discipline that Dan preaches day in, day out – make the investment to capture the supply and benefit from the full downstream economics. This is the essence of our business model. It’s what allows us to continue to outperform expectations quarter after quarter. We’ve got this great set of assets, a very aggressive management team and a classic business model that gives us an advantage over the competition.

Page 17 – Integrated Midstream Energy Services: Competitive Position and Outlook: Production Platforms

Let’s talk about each one of the segments. I’m going to talk first about the Deepwater trend. James will give you a lot more detail, but I’m going to highlight each of the areas where we are, shall we say, the 400 lb. gorilla in each of those businesses. We are the largest independent gatherer, oil and gas, and platform operator in the Deepwater trend. We’ve had three hurricanes in the last 18 months. That’s certainly slowed things down. It doesn’t change the facts about the Deepwater trend and the importance of Deepwater oil and gas production growth over the next 5 to 10 years. The Gulf of Mexico still produces 10 billion cubic feet per day (Bcf/d) – that’s 20% of US production. It is an important basin and we have a great position in infrastructure out there. It still produces 1 million barrels of oil per day (BOPD) and that’s expected to grow substantially and really the only source of lower 48 oil production growth in the next 10 years or so. So it’s an important place from an oil standpoint as well.

We staked out a position over 10 years ago – this has been a fundamental part of our growth strategy for the last five years. We’ve invested a lot of money and 2007 is the year where we’re going to start paying some big dividends. We’ve got seven offshore platforms out there. Marco Polo is well positioned in the South Green Canyon area. The Independence Hub platform, once installed in the fourth quarter of this year, will be the world’s deepest offshore floating platform. So we’re very pleased with our position.

And we think the outlook continues to be good for the Deepwater trend. Despite the hurricanes, producers continue to drill, technology continues to improve, and big discoveries continue to be made out there. And these are world-class discoveries. These are half billion barrel fields that producers are finding. They’re investing a lot of capital in the E&P side of it, they need the infrastructure to bring the production to market, we play a vital role in that whole scheme out there in the Deepwater trend.

Seventeen new Deepwater discoveries since the beginning of 2005, despite three hurricanes during the same time period. We’re well positioned in the South Green Canyon area. We think it is a world-class oil basin. We’ve got a lot of pipelines out there waiting for ramped up production. Producers like our model. We continue to use that to our advantage to attract new supplies to our offshore assets.

Page 18 – Integrated Midstream Energy Services: Competitive Position and Outlook: Natural Gas and Crude Oil Pipelines

We are the largest gas gatherer in the business. I think only Duke Energy Field Services, not an MLP, is close to us at about 6 Bcf/d. We expect to substantially increase those volumes over the next year, year and a half. As you can see, just the Independence Trail Pipeline System alone will add 1 Bcf/d. We just bought into a percentage interest in the Jonah Gas Gathering System and we’ve got pretty substantial growth factored into our assets in the San Juan, in the Permian, across the state of Texas, and in some of the other areas of the Gulf of Mexico. So we’re going to continue to extend our lead in gas gathering.

We do own and operate one of the largest pipelines in Texas, that’s been an area that’s been exciting for us and we have announced a number of projects and have others under consideration and development now. We’re the largest conventional gas gatherer in the San Juan. That is a gathering system that continues to deliver year after year after year -- stable volumes, strong margins, extremely stable cash flows.

The Jonah Gas Gathering area is an area that’s exciting to us and I know that you’re going to hear more about that from Jim, and James is going to give you a lot of detail on the offshore, both on the gas side as well as the oil side.

The outlook in that part of the world continues to be very favorable; the fundamentals are strong, driven by record prices. We’ve got strong drilling activity in almost all the areas that we operate in. We are renegotiating some of the contracts in the San Juan, at the same time our system optimization project was very successful out there because we’re seeing a record well connects year-to-date 2006. Texas is an exciting area, both in North Texas around the Barnett Shale where we’ve had some projects and we’re working on some others, in South Texas where we just made a new acquisition.

Gas storage is an area that we’re focused a lot on right now. The spreads in gas storage are significantly greater than NGL storage, so we’re looking at our entire portfolio of NGL storage caverns to see if those might be convertible to natural gas to capture some of those big summer-winter spreads in the market. And we’re very excited about early 2007 – that’s when Atlantis and Genghis Khan, two big oil fields, come on in Mexico.

Page 19 – Integrated Midstream Energy Services: Competitive Position and Outlook: Gas Processing

Gas processing has been a real force for us over the last couple of quarters. The outlook is very positive. It is generating significant processing margins right now. We’re the third largest processor in the business. We have about 6.5 Bcf/d of gas running through our plants right now. It produces 250 to 300 thousand barrels per day (MBPD) of feed into our downstream assets. 180 MBPD of NGLs are extracted from our plants alone, so those are the barrels, at a minimum, that we control. We’ve got strong competitive positions in South Louisiana, South Texas, and up in the New Mexico area with the Chaco plant, which is the third largest individual plant in the entire industry.

We like processing. We continue to build on that position. You know we’ve announced two large projects in the Rocky Mountains. Meeker and Pioneer will add another 1.4 Bcf/d of inlet processing capacity and about 75 MBPD of NGL producing capacity. We think they’ll be roughly full at the time we bring those plants on in the second and third quarter of next year.

We continue to predict strong processing margins throughout 2006 and beyond due to about a 65% gas to crude ratio. Right now we think that’s sustainable for a number of quarters. We continue to look at our plants on a daily basis to make processing decisions, but frankly, with $0.30 per gallon ethane extraction economics right now, there aren’t many daily decisions to make.

Page 20 – Integrated Midstream Energy Services: Competitive Position and Outlook: NGL Pipelines

On the NGL pipeline side of the business, we have the largest fully integrated NGL pipeline network across the country, over 13,000 miles of NGL pipeline. It’s largely attributed to the Mid-America Pipeline System Seminole and Dixie as well. That does not include the TEPPCO assets, which are separate. On a daily average we move about 1.2 MMBPD of Y-grade and finished products. We’re clearly the largest in the business from a volume standpoint.

We have a very important position to play in delivering propane to the winter heating markets – about 55 to 60 million barrels a year (MMBbl/yr). And importantly, we are the most well connected pipeline system to the growing markets. The petchems and the refiners who need feed stock and blend stock. We currently connect to 97% of ethylene steam cracking capacity in the US and 90% of the refiners for motor gasoline east of the Rockies. We’re very proud of that position. We leveraged that distribution network on a daily basis to deliver products to our customers.

Again, we’re not complacent, we’re building on our position here. We’re expanding the Mid-America Pipeline System by 50 MBPD because of the growth in production from the Rocky Mountain area. We’ve also got a Conway to Hobbs expansion which matches up with our new fractionator, and we’re fully integrating our South Texas NGL network. In fact, we’ve done that over the course of the past two years since the merger. We’ve also recently announced an acquisition of a pipeline from Exxon, which will give us further competitive position in South Texas and give us what we call Lou-Tex style optionality. Jim Teague will explain that to you.

Page 21 – Integrated Midstream Energy Services: Competitive Position and Outlook: NGL Fractionation

Fractionation, another area where we’re the leader in this business – over 450 to 500 MBPD of gross throughput. We’re running at capacity in all of the regions that we operate in – Mont Belvieu, Louisiana and South Texas. As a result, we continue to look for new build opportunities.

We announced at the middle of last year, a new fractionator in Hobbs to support the increased volumes from the Rockies, the two processing plants we’re building up there. You can see the value chain at work in the way that we develop these projects and announce these projects. It’s a disciplined approach to building piece by piece by piece along the value chain and benefiting from the full downstream economics each time we make an investment decision. We’re optimizing our capacity and we’ve really benefited from lower operating cost and improved fuel efficiency in our fractionators. So fractionation is an area where we’re very pleased with the performance.

Page 22 – Integrated Midstream Energy Services: Competitive Position and Outlook: NGL Storage, Marketing and Distribution

Finally to the end of the value chain, the NGL storage marketing and distribution network – once again, a clear leader in the field. We have an incredible set of NGL storage assets located in Louisiana, across the Mont Belvieu-Houston area, as far out to the Conway-Hutchinson Market in the Mid-Continent. We’re a major player in this business both for our own account, as well as third parties. All of the major NGL players have storage accounts with us. It’s a very important part of our business. It’s a business that we think has margin expansion capacity, so we’re going to be looking hard at all of our NGL storage caverns, both in terms of growing those, improving the optionality and the flexibility for our customers so that we can increase margins in that area, or converting those caverns to natural gas service, where clearly there’s a higher margin opportunity.

In the marketing side of the business, we move about 650 MBPD, so we are a key ingredient to all of the liquids that move between the petrochemical and the refinery markets. And our import-export business is also a very important part of our business. Again, we’ve got a leading market share there, 61% of the imports and 88% of the export business.

We think this is going to continue to be a very strong business for us and so we’ve announced some expansion projects, both in storage and brine capacity at Mont Belvieu. We’ve announced some long-term contracts with major international LPG importers and exporters. As a result, we’re expanding our import-export terminal there on the Houston Ship Channel and we’re looking for significantly increased product sales to our refiners and our petchems along the Gulf Coast.

So I think we’ve covered most of the value chain, given you a sense for our competitive position, some of the strategies that we’re employing. Now it’s our business managers opportunity to dig into the detail. I’m excited about this presentation. It really is a great opportunity for us to unveil not only the strength of our assets, but the focus of our strategies. But I hope you take away how strong the managers are in these businesses. We’re very proud of them. We’ve got a lot of momentum at Enterprise, and these guys are the guys that are driving the boat for us.

James H. Lytal – Natural Gas Pipelines / Storage / Offshore

Thank you, Bob. I don’t know why they do this – they give the slowest talking guy the most slides, so I apologize up front. But I’m James Lytal. I’m responsible for natural gas pipelines, natural gas storage and our offshore business.

Slide 25 – Texas Pipeline System

I want to start in Texas, where we think we have the best positioned intrastate pipeline in Texas. We serve 25% of the market in the state of Texas. It’s over 8,000 miles of transmission and gathering pipeline. We have a 6.4 Bcf salt cavern, or caverns, south of Houston – excellent position from a storage standpoint.

If you look at the map, and everybody hears about the Barnett Shale, we’re very well positioned for the Barnett Shale. We move about a third of the gas that’s currently coming out of the Barnett Shale area. We’re well positioned for the Bossier play over in East Texas. South Texas has always been a prolific basin with the Vicksburg and Wilcox production. What we do in South Texas with our gas plants, we gather almost 1.5 Bcf/d on our transportation system, up to the gas processing plants. So all the rich gas in South Texas, we benefit from the processing there also. And then the Permian Basin is really picking up. I mean it was a basin that had really slowed down. With the higher prices, there’s new Morrow development and people are pursuing the shale over in that area. So we think that’s going to benefit this asset over the long term.

And we’re tremendously positioned for the markets in Texas. Our major markets are in Central Texas. We serve the city of San Antonio and the city of Austin. Our peak day deliveries to them are over 800 MMcf/d off of our assets. We’re tied into all the Houston Ship Channel markets in the Houston area, Beaumont and Corpus Christi area. We’re tied to all the major pipeline hubs – Waha, Carthage and down in South Texas, Agua Dulce. These are important because we’ve seen tremendous basis differentials across our assets, and I’ll talk more about that in a little bit. And then there’s been a tremendous growth in the state of Texas with power plants and we’re tied into 19 power plants, so a lot of market on this asset.

We see the Barnett Shale volumes growing. We’re well positioned, and we think we’re going to have an opportunity to expand out of this area with the growth in those volumes. And there are a lot of stars you see along the Gulf Coast there. Those are LNG facilities that have been proposed. I don’t believe all these will be built, but some of them will be, and these will be great supply portals for us connected to our assets.

Slide 26 – Texas Drilling Statistics: Monthly Average Rig Count

This shows you the rig count in the State of Texas. Since January 2000 we’ve seen the rig count almost triple. What’s driving this is the growth in North Texas of the Barnett Shale and the growth of the Bossier play in East Texas. We’re seeing more drilling in the Permian, people pursuing the Morrow production, people pursing the shale plays. So a lot of activity and our assets are well positioned for all this activity that’s going on.

Slide 27 – Barnett Shale Production Growth

Here’s the Barnett Shale production. You see the growth over the past six years, projected to be 1.6 Bcf/d in 2006. We see this growing to 3 Bcf/d. That’s why we believe we’re going to have the opportunity to expand our assets out of this area. And the shale is not just happening in North Texas. I’ll talk a little bit more in a minute. Around our Waha gathering system there’s a million acres that people believe is new shale play. There’s a lot of drilling going on in that area so it’s in the early stages, but all the producers with the success of the Barnett Shale in North Texas are looking for any place they can to develop shale in other areas.

This slide says we currently transfer 450 MMcf/d. We actually today are doing over 500 MMcf/d out of the Barnett Shale area. With the major shipper being Devon, whose the major producer out of that, they’re shipping over 400,000 MMbtu/d on our assets. So even though we haven’t done the expansions out of this area, for no capital, we’ve been moving an awful lot of gas.

Slide 28 – 2005-2006 GDA Monthly Average Spreads (Waha to HSC)

I talked about basis awhile ago. This shows the basis differential between Waha and the Houston Ship Channel over the past year and a half. This is averaged around $0.45.

Slide 29 – 2005 Highlights

This benefits us in a couple of ways. One, we’ve sold most of our capacity on a firm basis, but they’re the customers that don’t always utilize it on 100% load factor. So when we have interruptible capacity to sell, we’re able to go out and generate a lot of interruptible revenue by taking advantage of this basis across our system. The other thing that’s happening is when we renegotiate long-term agreements, with the wider basis, cheaper supply in areas like Waha, we’re able to negotiate higher fees and you’ll see in 2005, we negotiate over 600 MMcf/d of contracts and we’re able to increase the fees on all of these.

Our transportation revenues for 2005 increased by $16MM due to these renegotiations. And in addition to being able to increase the fees, we’re also able to increase our fuel retention and our operations people have done a great job of keeping our fuel, as well as the lost and unaccounted for across our system, down, so there’s been several months when we actually collect more fuel than we utilized, which is a benefit and value to the asset. When we negotiate these contracts, typically, we’re doing deals for three to ten years.

Slide 30 – 2006 Highlights

In 2006, we’ve had several expansions we’ve got done. We’ve expanded our 30” from Waha down to the city of San Antonio. We’ve expanded in the Carthage area to move more Bossier production into the Carthage hub area. All these investments are supported by long-term contracts and I’ll talk a little bit more about them in a second.

We recently announced a new deal with CenterPoint to serve a portion of their load in the Houston area. We’ve done a deal with Shell, got a long-term commitment from Shell, which supported capital to expand to our delivery capabilities into Mexico by 150 MMcf/d. And in July we completed our acquisition of the Cerrito Gas Gathering System from Lewis Energy.

Slide 31 – West Texas Expansion

Our West Texas expansion, you see the map on the left there, involved installing 24,000 horsepower of compression. We added 120 MMcf/d of capacity from Waha down to the South Texas area. This investment was supported by two agreements – a 60 MMcf/d agreement with the city of San Antonio to handle the additional growth they’ve seen around the city of San Antonio and a 60 MMcf/d agreement with Devon. What we do with Devon is take their Barnett Shale, we backhaul it to Waha – their Barnett Shale production – backhaul it to Waha and then take it down to South Texas and deliver it into the interstate for them.

Slide 32 – CenterPoint Transaction

I mentioned the CenterPoint transaction – it’s a new long-term agreement we just entered into. Service will begin April 1, 2007. We expect 14 Bcf of load in the Houston area on an annual basis. This is in addition to, we currently do around 5 Bcf per year with CenterPoint in some of the city gates in South Texas. So in total we’ll be around 20 Bcf per year with CenterPoint as far as the provider of transportation and storage services to them.

We’re spending around $100MM – it involves buying some pipes in the Houston area, making interconnects to 11 of CenterPoint’s high growth LDC area. We’re also going to expand our Wilson storage facility and build a new pipeline from Wilson to provide, now we’re going to connect Wilson into our channel pipeline, which will provide more pipeline capacity coming out of the storage area.

We see two additional benefits from this transaction. One, we believe we’ll build the Wilson caverns bigger than required for the CenterPoint transaction, so we’ll be able to expand our third-party business out of Wilson. Then with new pipes in the Houston area and the expansions we’re doing, we think we’ll be able to pick up additional market in the Houston area.

Slide 33 – Cerrito Acquisition

Our Cerrito acquisition, you see a map here. The pipelines you see in blue are the pipelines we acquired from Lewis Energy. A little bit about Lewis Energy. Lewis is an integrated E&P company. They own seven drilling rigs – they are a very active driller all along these gathering assets. This footprint fits nicely with the developments that are going on down in the area. In red dash you see our Texas intrastate pipeline and in yellow you see our gas plants. So we have the full value chain here.

This is actually gas that every three to five years we bid on. We have the gas flowing into our system today coming off the gathering system. What we did in this transaction is we went back to the well head, entered into a new agreements for gathering and processing and the incremental revenue we get from these new agreements is what we use to amortize the investment we’re making to acquire this. We provide the total value chain service here, as Bob talked about earlier. We get the gathering, the gas moves on our Texas intrastate up to the gas plant, we get processing, the liquids are extracted at the plant and then we get a transportation and fractionation fee and our NGL marketing company actually buys the liquids. And then the residue gas is transported on our Texas pipeline to the markets. So it’s a nice asset. It’s the richest gas we see in South Texas.

Slide 34 – Cerrito Acquisition

We paid $325MM for the asset – $146MM was in cash and approximately $7.1MM in EPD common units. For those of you that have books, they say 484 million miles of pipe, which would have been a heck of an acquisition for $325MM. It actually is only 484 miles of pipe that we acquired from Lewis. There’s 31,000 horsepower of compression. We provide a very low pressure service, below a hundred pounds at the well head, which is required for the play that they produce from out there. There’s a blanket sand out there, it’s called the Olmos Sand, that’s the main field play. That’s where most of the gas comes from today.

What we got from Lewis as part of the transaction was a life of reserves dedication of their Olmos production. It’s currently 45 MMcf/d. Lewis has 335,000 acres in the area that they’ve dedicated to us for the life of reserves from a standpoint of the Olmos production. They plan on drilling 130 wells this year and they have over a thousand locations to drill over the next several years. So we’ve got a great dedication of production as part of this deal.

In addition to the dedication of the Olmos, we’ve got a 10-year dedication from Lewis of anything they drill deeper than the Olmos production, and we believe there’s going to be new shale production. There is some shale that produces down in this area, and we’ve got a dedication of that. We expect it to be rich gas also. This is – I mentioned the richness of this gas – this is the richest gas we’ve seen in South Texas. It runs 4 to 6 gallons per 1,000 cubic feet (gpm), on average around 4.3 gpm. So this gas is not only important to our pipeline system, it’s important to our plant.

Also Lewis has done a deal with PEMEX where they’re drilling wells across the border in Mexico. They’ve dedicated that gas to us. They will be building a line over to our gathering system from Mexico and that gas is dedicated to us for 10 years. Another play down here is the Edwards Lime – it is sour gas. Lewis is drilling that. They’re building a new treating facility to take the H2S out of the gas. We will get the gas at the tailgate of the plant and make a gathering fee on this.

So we’ve got a lot of dedications in this area as far as the transaction of acquiring the gathering assets from Lewis. We also got assignment of the third-party contracts, the gathering of processing contracts, which right now are around 55 MMcf/d of gas, but the third parties are very active drillers down in this area. We expect volumes to grow from their current level of 100 MMcf/d to over 200 MMcf/d by 2012 and very little of that volume – we think that most of this is going to come from the Olmos.

So there’s a tremendous amount of upside in the shale drilling that’s going to happen down here as well as the Austin Chalk. Anadarko and Chesapeake have taken huge acreage positions down here with plans to drill the shale, as well as Wilcox, Austin Chalk, other formations. So there’s a lot of upside to this area.

Slide 35 – Cerrito Gas Supply

There are 1,450 wells connected to this asset, as I said, producing 100 MMcf/d currently of sweet gas. Olmos is the main reservoir, there is some Wilcox production in the area. We think there’s 1,500 more locations to drill in the Olmos alone. A lot of upside through the Austin Chalk and the Eagleford Shale. I think there’s 1.5 Tcf of recoverable reserves over the next 20 years.

Slide 36 – Historical and Projected Cerrito Volumes

And this graph will show you the ramp up we expect from this production. You can see from 2001 production, already has almost doubled from the level that we were at in 2001. With the planned activity, the growth in the Olmos production and the upside in the shale production, we think these volumes are very attainable.

The other line you see there, I guess it comes across somewhat in orange, is the liquids that we extract at our processing plant. Currently we get about 8 MBPD. With the growth in gas volumes, we expect this to grow to 16 MBPD, which really benefits our value chain from the standpoint of the fees we get for transporting and fractionating the liquids, as well as buying and selling the liquids.

Slide 38 – San Juan Gathering and Processing

I’m going to move over to the San Juan and Permian. The map you see there shows our San Juan gathering assets in red, our Chaco processing plant and our Rattlesnake treating plant. At Rattlesnake we treat for high CO₂ gas out there.

The San Juan gathering system, it has to be one of the best in the industry, over 5,000 miles of pipe, almost 280,000 horsepower of compression. We provide a very low pressure service for the producers, over 10,000 wells connected to this asset. And we move over a Bcf per day through the gathering system. Our fees on this gathering system, we receive as our gathering fee a percentage of the gas price, the San Juan gas price, which gives the company link to gas out in this area, which is a nice natural hedge to our fuel usage at Mont Belvieu and MAPL and systems like that. So our risk to gas price changes is mitigated due to our position to gas. So gas prices don’t have that big effect on our earnings.

Chaco, our processing facility, is a 650 MMcf/d gas plant. Year-to-date we’ve averaged around 500 MMcf/d, although we’re moving more than that today. We have seen some increase in volumes. We recover almost 40,000 Bbls/d at this plant and the fee we receive, we receive a percentage of the liquids, so, net to the company, we’ve averaged about 8,000 Bbls/d for 2006.

Our major producers are ConocoPhillips, BP and XTO. With BP we’ve recently entered into a new 20-year gathering agreement. We gather their gas. BP owns a plant that’s connected to our gathering system. We gather their gas for that plant. With XTO we’re in negotiations to extend the agreement with them, and ConocoPhillips, with their acquisition of Burlington, now has over 500 MMcf/d of production on our gathering system. We are currently in negotiations. The ConocoPhillips legacy gas is about 180 MMcf/d. With the Burlington acquisition, they added over 300 MMcf/d. We’re in negotiations on the 180 MMcf/d and are looking, and the additional gas that they’ve acquired from Burlington has two more years on that contract. So a lot of ongoing negotiations for ConocoPhillips right now related to this asset.

Slide 39 – San Juan Basin Optimization

We completed a project in December of 2005 – we call it our optimization project. It involved an expansion of the gas gathering system. We expanded it by 150,000 MMbtu/d. It involved setting up high pressure and low pressure pathways. We improved our pigging capabilities on the system. We added a new downstream interconnect with TransWestern for the gas to go, a new market for the gas to go downstream to the plants.

What you see there on the graph is the volume response since we completed that project. We’ve seen volumes increase by 7% since we’ve completed the project and even today we’re seeing higher volumes than you see on the graph there. So while we’ve got the ability on a decatherm basis to add from the volumes you see on the graph, another 130 to 150 Mdth/d, we’re seeing the drilling response.

Slide 40 – San Juan Basin Well Ties

You can see, based on price and the fact these producers knew we were going to expand our capacity, you see the huge ramp up in our number of well connects over the years. Last year we did over 330 well connects. This year, for the first half of the year, we did over 200 and we’re on track to do over 400. So we should see volumes continue ramp up in this area.

Slide 41 – San Juan Area Reserves

It’s very long life reserves. You see 46 years on the conventional – conventional being the traditional sandstone reservoir. This is the richer gas, this is 3.5 gpm gas that we see in this area. Very long life reserves. About 10% to 15% of our volumes are coal seam, which is the leaner gas and it’s also long life reserves.

Slide 42 – San Juan Basin Production Outlook

This graph shows the projections for the basin. This is the total basin, these volumes. We see the coal seam declining, but we see the conventional ramping up, which is very positive for us because it will richen up our stream. The less lean gas and the more rich gas, obviously, benefits us from a standpoint of being a major processor in the basin.

Slide 43 – Carlsbad Gathering

Move over to Southeast New Mexico. This is a map of our Carlsbad gas gathering system. We’ve seen a lot of drilling activity in this area, volumes growing. Our major customers are Devon, EOG and Mewbourne out in this area. We’ve got two projects.

One we just completed, is a new interconnect with natural gas or NGPL, Natural Gas Pipeline, on the northern portion of the system – it’s up where you see the blue star there. This investment was supported by a new long-term agreement with EOG. They’ve got a lot of new drilling going on up in that area. It benefits the system. All our gas has traditionally been delivered off the south end of the system into El Paso Natural Gas. With the delivery point off the north end we get a system expansion by being able to move gas up to the north.

The other project we have going on is down in the southern part of the system. We are building a 150 MMcf/d dew point plant where we are going to extract the heavy liquids out of the gas to where it meets the quality specifications of El Paso Natural Gas. We are negotiating with the producers. This will be a good, stable fee business for us. It assures reliability of flow for the producers by conforming the quality of the gas to fit El Paso’s quality specification. So that will be starting up toward the end of this year.

Slide 44 – Waha Gathering and Treating

Waha is no different than Carlsbad. A tremendous amount of drilling activity. We’ve seen volumes grow 24% year-over-year. We do have a treating facility at Waha where we treat for H₂S and CO₂. We are currently moving 130 MMcf/d through that. Our major customers are Anadarko, Exxon, Forest and ChevronTexaco, but we’re seeing two big plays out in this area.

On the top of the map, you see the Morrow play. If you follow Anadarko, you’ve heard them talk about their Haley Ranch field. This is an area where four years ago there was no gas. Today we’re moving over 120 MMdth/d for Anadarko out of this field, and they just announced a new deal they did – a large farm in from ChevronTexaco on some acreage to the west of where their current acreage is and we expect them to pick up drilling in that area, also.

The other thing we’re seeing out here is people have found the shale out here and they believe it’s going to be the next big Barnett Shale type play. The major players out here are Petro Hunt, Chesapeake, EnCana and EOG. They believe there’s over a million acres that are covered with the shale production. We’ve got 45,000 acres dedicated to us so far and we’re working on a lot of other deals to get this dedicated. It’s in the very early stages. There have been a few wells drilled. It does produce gas. They’re working on the best way to stimulate this, but it has a significant amount of upside, not only for this asset, but by gathering it through this asset, it also can benefit our Texas pipelines because this asset can take gas, ultimately, into our Texas pipeline.

Slide 45 – Permian System Throughput

This shows the throughput on our Permian assets. You see it has grown from 2001, around 450 MMcf/d to over 500 MMcf/d today. The red line you see is the number of well connects. Last year we did over 80 well connects. Year-to-date we’ve already done 60, so there’s a tremendous drilling activity this area, and we expect volumes to continue to grow.

Slide 47 – Petal and Hattiesburg Gas Storage

Moving over to natural gas storage, and this is one of the hottest things going on in our industry. We’re seeing differentials between summer and winter over $3 right now. There’s a lot of demand for salt dome storage. Our Petal and Hattiesburg gas storage is located over in Mississippi. We completed an expansion in 2005, added 2.4 Bcf of working gas by converting a brine cavern that was part of our NGL storage over there. That investment was supported by a new long-term deal with BP. They leased 1.8 Bcf for that capacity. In total, at Petal and Hattiesburg we have 13.9 Bcf sold under long-term contracts.

We have just completed drilling a new well. We are going to add 5 Bcf of working gas in the area. We are fixing to start leaching that facility and it should be in service in April of 2008. We are in negotiations with a lot of parties, close to finalizing some deals that at the fees that we’re going to get for this business, it’s a five-year payout on the capital that we’re investing to expand this facility.

Slide 48 – Petal Gas Storage

The other thing we are doing at Petal is, we will be filing with the FERC to convert another brine cavern that we have over in the area, as well as three NGL caverns to natural gas service. It will add 3.1 Bcf of working gas to our Petal gas storage. We expect to complete this in the third quarter of 2007, and based on the capital we need to spend, this in the current market rates we’re receiving for storage, we believe this will pay out in four years, of the capital we spend to do this.

Slide 49 – Comparison of Economics and Returns of Natural Gas Storage vs. NGL Storage

With the value of natural gas storage in our position, in storage in general, not just gas, but NGLs, we have 94 million barrels of storage at Mont Belvieu. You see some analysis here of the value of gas storage in comparison to what we’ve received for NGL storage.

Slide 50 – Comparison of Economics and Returns of Natural Gas Storage vs. NGL Storage

And what you’re going to see us doing is we believe one, we’re either going to be able to increase the value of our NGL storage, or you’re going to see us converting other NGL caverns in the areas like Belvieu and Conway to natural gas to get more value out of this. So it’s easy growth, it’s low cost, but it should have a positive increase in our cash flows, but in this. We also at Wilson and Petal have the ability – we have a lot of acreage – we have the ability to build a lot of new caverns and I can tell you it’s a lot cheaper to build them than buy them today. So I think at Petal you’ll probably see us developing another 10 Bcf or so over the next few years, and at Wilson we’ll be adding space related to our CenterPoint deal, but we have the land and the ability to build a lot more at our Wilson storage facility.

Slide 52 – Deepwater Gulf of Mexico Overview

Let’s move to the Deepwater Gulf of Mexico. We’ve been an investor out there since the early ‘90s. When we complete our Independence Hub and Trail project, that will be, on a gross basis, around $3 billion of projects that we’ve developed over the past 12 to 13 years. Nobody has the footprint we have with oil and gas pipelines, platforms. We cover the gamut in the offshore. We are well positioned for all the activity that’s happening in the Deepwater. We have got a lot of projects that have come on recently, things like our Marco Polo platform and our Cameron Highway Oil Pipeline, that has significant dedications, life of reserves dedications, acreage dedications that support these investments.

We’ve been disappointed – I mean, weather-related, getting equipment due to the hurricanes. These are very deep wells, producers taking longer than expected to drill and complete wells. We have not ramped up the volumes at Cameron Highway and Marco Polo like we expected, and it’s mainly just due to the wells not coming on the timing basis that we expected due to weather, due to equipment, due to taking longer to drilling wells. But we do see volumes increasing in 2007. We absolutely believe we’re in the right area, even though the revenues have been delayed from these projects, we still think we’re going to earn great returns on things like Cameron Highway and Marco Polo.

Slide 53 – Enterprise Gulf of Mexico Assets

This shows our footprint. You see the gas pipelines in red, the oil pipelines in green, and our platforms in yellow. You also see some of our onshore infrastructure. This is very rich gas in the Deepwater. We’ve seen 4 to 8 gpm type gas, so it’s another thing Bob talked about, the value chain. We have it in the offshore too, as our assets can deliver gas into our processing and transportation facilities. You look at this footprint and then you look at the next slide where the activity is, we’re well positioned.

Slide 54 – Gulf of Mexico Drilling Activity

You look at South Green Canyon, Walker Ridge, kind of in the middle of the map there, over in the Eastern Gulf where we’re building Independence Hub. We’re well positioned for the activity that’s going on there. Close to 40 rigs currently working in the Deepwater. If you compare that to two and a half years ago, there was around 21, 22 rigs working, so people are very active out in this area.

Slide 55 – Deepwater Trend 2005/2006 Update

This shows the new discoveries in the Deepwater over the past year and a half – 17 discoveries. You see a quote from the MMS about the positive things going on in the Deepwater, and I know they have a strong belief in the growth of the Deepwater over the next few years. And all these are located, some are dedicated to us. On all these prospects though, we’re going to have the chance to compete and try to get the oil or gas into our pipeline systems.

Slide 56 – Marco Polo Platform

This is our Marco Polo platform. At the time we built it a couple years ago, it was the deepest water tension laid platform in the world. We are a partner with Helix – they are formerly known as CalDive – 50/50 partners. We’re the operator of the partnership. The actual operator of the platform is Anadarko, as they were the anchor tenant and they supported this investment with the dedication of their acreage in the area. It is located 4,300 feet of water. It is designed for 120 MBPD and 300 MMcf/d. We get fees. We get $2.1MM per month guaranteed, regardless of what flows across the platform. That’s an 8/8ths number, we get half of that. We also get a per barrel and per MMcf for everything that is processed at the platform.

Recently we have seen volumes as high as 43 MBPD and 33 MMcf/d. We expect that to ramp up over the next six months as two new wells are added this year at K2 and K2 North. These are wells that are subsea tiebacks to the platform. And then in early 2007, two more wells at Genghis Khan. Out of that 43 MBPD, most of it comes from four wells, around 40 MBPD of it, so these wells are high producers, averaging around 10 MBPD, these wells that are tied back to the platform.

In addition to the platform revenues, we own the downstream oil gathering pipeline. We gather the oil and get a fee for that business, up to Ship Shoal 332 where we own a platform. The oil can either go into the Poseidon asset, of which we own 36% or the Cameron Highway pipeline, of which we own 50%. On the gas side, we own the gas gathering pipelines. We gather the gas up to ANR and there is a new connect being made with Tennessee. Downstream of both those pipelines, we own plant assets as well as transportation and fractionation assets, so, quite a value chain with this asset.

Slide 57 – Constitution Oil and Gas Pipelines

We got our Constitution oil and gas pipelines flowing in February of this year, ahead of schedule. We worked a life of reserves commitment with Kerr-McGee, they dedicated their Constitution production, as well as their Ticonderoga production. Ticonderoga is a field that is subsea tied back to the Constitution platform. We are currently moving over 30 MBPD through the oil and 132 Mdth/d from the platform. That’s producing from six wells. There are two more wells that are going to come on here over the next few months at Constitution.

Also, Kerr-McGee owns a lot of acreage in the area that there’s a lot of potential for subsea tiebacks to this platform as they develop those new prospects. The gas goes into our Anaconda Gas Gathering System which is part of the pipeline we built for Marco Polo, so it meets up with the Marco Polo gas where we built the new pipeline to tie into that. The oil goes up to Ship Shoal 332 where we got a life of reserves dedication to Cameron Highway of Kerr-McGee’s barrels. Kerr-McGee does have some ability to divert some of the barrels. Some of the barrels are going into the Poseidon pipeline right now and I’ll show you a slide in a minute. The growth we’re seeing in Poseidon volumes, so a lot of upside in the area. The investment is really starting out well here.

Slide 58 – Cameron Highway Oil Pipeline System (CHOPS)

Our Cameron Highway oil pipeline, we are 50/50 owners with Valero. We are the operator of the pipeline system. This pipeline was supported with major dedications from BP, BHP and at the time Unocal, now ChevronTexaco, of their production from Holstein, Mad Dog and Atlantis fields. Since we developed the project, we got additional dedications from Constitution, K2 and Ticonderoga.

We have been disappointed in the ramp up of volumes here, but the future really looks bright for this asset. There are only 15 wells flowing today; there are 35 more wells to come on. The major field is Atlantis, a 200 MBPD field. The platform BP is out installing the platform as we speak. We expect that to come on in 2007. Mad Dog is flowing now. Mad Dog is a 120 MBPD platform. BP expects to fill that up over the next two years.

So you can see, we believe by 2008 you will be seeing over 300 MPBD flowing on the Cameron Highway Oil Pipeline, whereas compared today we are only, we have averaged around 80 MBPD since the beginning of the year. A lot of additional developments in the area that has the potential to go into Cameron Highway.

Slide 59 – Poseidon Oil Pipeline System

I wanted to talk a minute about our Poseidon system because part of our plan in the South Green Canyon area was to get volumes directed to Ship Shoal 332. With the growth in volumes in that area, a new pipeline was required. That’s how Cameron Highway was developed. The producers also look for optionality and by getting all the Ship Shoal 332, it not only can get to Cameron Highway, we can get it into Poseidon. We own 36% of Poseidon; Shell and Marathon are our partners. We are the operator.

In 2005 we averaged 120 MBPD, today we’re doing around 180 MBPD. So you are seeing the growth in volumes in this area, in what’s happening with Poseidon. Poseidon, some of the increases we’ve seen, 50% of Holstein, which is one of the Deepwater fields that was dedicated to Cameron Highway was owned by Shell. Cameron Highway did not get a dedication of those barrels. They are currently flowing into Poseidon. So a lot of growth. We expect that volume to continue to grow on Poseidon over the years and I’ll show you why here in a minute.

Slide 60 – Increased Crude Oil Deliveries

We have increased, even though the volumes have ramped up slower than expected, we’ve increased our crude oil deliveries into our ownership, or our pipelines. We have been impacted – one of the things with Cameron Highway that has negatively impacted us, but we believe will change – is the BP refinery has been down as far as their takes on sour crude, which has negatively impacted the Cameron Highway price, which as far as competing for undedicated barrels, has put Cameron Highway in a position where it hasn’t been able to compete. We expect that to change as BP gets their refinery up and running again.

The other thing that the markets, until your volumes reach a certain level and the markets are comfortable, you know the barrels will be there on a daily basis. They ding you a little bit on the price. We saw that 10 or 11 years ago when we started up our Poseidon pipeline. So we expect the price for the Cameron Highway barrel to increase significantly over the next year. A lot of growth in the Texas City area where Cameron Highway delivers crude oil, Texas City and the Beaumont-Port Arthur area. Several of the refineries in that area are going to be expanding.

Slide 61 – Southern Green Canyon: Continued Exploration Success

This shows you the South Green Canyon area. What you see out here, either existing or planned, are platforms that have over a million a day of capacity to process crude oil.

Slide 62 – South Green Canyon Summary

You see our pipeline position out here, you see how all the barrels are directed up to Ship Shoal 332, where we have our ownership in the Poseidon and Cameron Highway pipelines. So it’s a world-class oil basin that we’re dealing with here.

We are finalizing an arrangement to build a new gathering system out into this area. It will be a 200 MBPD pipeline. We are close to getting that deal done. If you add that capacity to what’s out there today between the gathering pipelines we own, as well as the big gathering systems owned by the producers, that’s over a million barrels a day of gathering capacity that can go up to Ship Shoal 332 where we have our Poseidon and Cameron Highway pipelines. Poseidon can expand to be able to move 400 MBPD, Cameron Highway with the addition of pumps can move around 600 MBPD. So we expect to see these volumes ramp up over the next several years, with the opportunity to fill both of our pipelines that we have an equity ownership in.

Also, there’s a new play going on south of the South Green Canyon area. It’s called the Walker Ridge area and there have been a lot of wells drilled. The producers are evaluating it. There is a lot of oil in place. They are working on the best way of developing it and we are well positioned for this crude oil to come into our assets also, so a lot of upside in this area.

Slide 63 – Independence Hub Platform and Trail Pipeline

Finally, our Independence Hub platform and our Independence Trail pipeline – we own 80% of the platform; Helix is our 20% partner in that. 100% of the pipeline. We originally designed this platform to process 850 MMcf/d. With the additional drilling and discoveries our anchor tenants or producers out here have found, we worked a deal with them to expand the platform to 1 Bcf/d. Our anchor tenants are Anadarko, Kerr-McGee, Dominion, Spinnaker (which is now Hydro) and Devon. They dedicated all their blocks in the area and all their production in the area for the life of reserves. This project involved building a new 134-mile, 24” gas gathering pipeline to connect the gas in Tennessee gas pipeline up in the shallow water.

Slide 64 – Independence Construction Update

You see the picture of the hull being transported, the bottom picture there, and it was built over in Singapore at Jurong’s yard and is now over at Kewit’s yard in Corpus Christi. It arrived in June 2006. We are almost finished building the deck and completing the final work on the hull. You will see in early September, the deck will be picked up and placed on top of the hull. At this time, we are out finalizing the building of the gas pipeline. We started in the Deepwater in 8,000 feet of water. We should be done, if we’re not done now, completely the installation of that.

We are building a new shallow water platform at West Delta 68. That is where the gas will land and we will deliver the gas into Tennessee gas pipeline. We have installed the jacket there, we’ll be putting the deck on later this year. And we expect to be out in the fourth quarter, installing the hull and deck at the location. It will take 4 to 8 weeks to get that done. We expect to start receiving demand charges once we hand the platform over. Anadarko is going to operate the platform. In the first quarter we will receive approximately $4.6MM per month in demand charges for five years, regardless of what flows across this platform. And then we expect first production in the second quarter of 2007.

Slide 65 – Independence Hub Subsea

This shows the area around the Independence Hub. It shows the fields that are going to be connected to the platform. There are over a hundred blocks that the producers have dedicated to us. Anadarko recently announced they flow tested one of the wells out here at 60 MMcf/d. There are 17 wells initially that are going to be connected. A lot of additional drilling to be done in the area, also.

We had an independent study done on the reserves. The P90 or proved reserves were almost 1 Tcf. The most likely reserves were in the range of 1.3 to 1.4 Tcf, and that’s just what they found to date. There is a lot of other acreage dedicated to us. We believe this area has well over 2 Tcf of reserves. And if you look, you see the flow lines that the producers are building, they’re responsible for building the pipelines up to our platform, there’s going to be almost 200 miles of gathering pipeline coming up to our platform. So when the producers drill a well, they don’t have to build a new pipeline up to our platform, they’ll just tie it in to the existing subsea floor line. So the economics on future wells is great, but a lot less capital to get the wells on. So they’re going to be incentivized to keep their pipelines full, as well as our platform full.

Slide 66 – Eastern Gulf of Mexico New Acreage Potential

And finally, one of the things going out in this area is the Senate recently passed a bill that would open up more area in the offshore. The House has also. It must go to Committee and they have to work out the final drafting of the bill, but it opens up about 8 million acres just to the east of our Independence Hub and Trail assets. And these are the only assets out in this area. This platform and this pipeline are the only things that go out in this area. And the opening up of this new area will stimulate a lot of new drilling and we will be the obvious choice for the development of these new reserves, so a lot of upside to the reserves that I’ve quoted you earlier, through the development of this area.

Questions and Answers

Q:	Hi, Paul Sankey, Deutsch Bank. You made an interesting point about natural gas storage being full. Could you talk a little bit more around the gas market, and that gas market as you see it in terms of what would lead you to make that statement?

James: Well, what we’re seeing, and you can look at the futures, you can look at today, is a huge differential between prices today in the summer and prices in the winter. And you can go out and lock in $2.50 or so spread over the next several years. And that’s basically just filling it in the summer and selling it in the winter. These salt dome storages, we can turn them 12 times. So you are going to get more value than just that one turn, so we don’t, and because of that spread, you’re going to see more storage facilities being built. People are willing to pay up. I think the benefit we have, as I said earlier, is that we own the land, we have the dome, we do not have to go buy something. We can build something. And it’s much cheaper to build it than it is to buy it today.

Dan: Hi, I’m Dan Duncan. I’d like to give a little bit of color to the natural gas storage deal. What we’re looking at now, and James hasn’t had time to put it all together, we’re going back to like 3 or 4 years and look at the amount of gas production. First is the actual demand, to see what the ratio is to gas demand in the wintertime, versus gas demand in the summertime, including the new heating season that we’re going through right now – the cooling season, not the heating season – to see what happens 3, 5 and 10 years out on natural gas storage.

We’ve also got LNG coming in now. Most of the LNG is probably going to come in 60% to 70% in the summer months because in the winter months the LNG in the Persian Gulf area will go to the either European market or the Asian market or the Japanese market, because their storage is a lot cheaper than the United States on salt dome storage. But in natural gas, there’s going to be an inverse ratio of summer and LNG coming in the United States, versus winter LNG coming into the United States. So that means you have to have more storage.

So we’re looking at the ratio as between summer and winter relative to historic patterns and also relative to new demand patterns as you go through, especially where we’re coming into the play of moving into more natural gas storage. It also will affect us in the NGL market side. We are probably the biggest company in the NGL storage. So if we can convert some of our NGL storage domes like Mont Belvieu or Petal, Mississippi to gas storage, then we also gain on the NGL side. If we tighten up the NGL storage and if you look at, you remember the slide which is in your book, I think the Belvieu storage revenue today is $0.60 to $0.70 a barrel. You’ve got the same type of storage on those salt beds.

A few years ago, Conway, Kansas was in the $0.40 to $0.50 a barrel. Today, Conway, Kansas is $1.60, $1.80, $2 a barrel. And you see the difference between Conway, Kansas and Mont Belvieu, Texas which is the largest hub in the United States on NGLs – then you see what on conversion of NGLs to the natural gas you gain under that arbitrage. And the main thing we’re tightening up NGL storage, so we can raise our overall rates in NGL storage at the same time, create new business for Enterprise, and that’s the value chain that we’re talking about.

And we will have questions at the end of each one of the business people’s deals, and at the end of the deal, both Bob and Mike and all of us will be able to take questions at the end of the session also. So we thank you all for all coming today. We really appreciate being in New York too – it’s typical Texas weather we’re having up here now, so I mean we can also come to Houston, same group of you. And we do invite you to Houston at any time. Any other questions? We’ve got more questions for James and also for any of us to the management team that y’all would like to ask questions. At each breakout, from business section deals, there will be questions and answers.

Q:	What are the issues in changing over NGL, I’m sorry, your storage in NGLs over to gas storage?

James: Well, you say issues. I mean it depends on the cavern, is one thing. I mean it has to be at certain depths and be able to handle certain pressures, but we’ve done a lot of analysis and just like I said at Petal, we already have identified three caverns we can convert and then you have a brine well that’s easy to convert. It’s very low capital conversion. I mean the most of the capital is just the base gas you have to go out and buy to provide the pressure that you need to operate the cavern. And then we see, we have caverns at Belvieu that we know we can convert. So it’s just looking at where we get the most value as a company.

Q:	So it’s relatively low cost. And finally, what is the capacity of Marco Polo processing line?

James: It’s 120 MBPD and 300 MMcf/d. Like I said, we have seen volumes as high as 43 MBPD. There are four more wells to come on. Most of that volume is made up of four wells that probably average around 10 MBPD, and we expect the new wells to be in that general area also. We do have some other third-party activity in the area that we think we can use to top off the platform if Anadarko doesn’t ultimately fill it up. But there are more wells to bring on out there.

Dan: I think we have time for probably one more question, and then of course there’ll be another opportunity for questions at the end also. So do we have one more question?

Q:	Good morning. Do you think that you’ll be able to – on the natural gas storage – do you think you’ll be able to lock in that $3 winter-summer spread or conversely, what do you think happens if two years down the road we see more of a historical spread between winter and summer?

James: Well, today we’re obviously out in the market because we are building a new cavern and we are negotiating and we are seeing what people are willing to pay today. Traditionally though, because it is a, these caverns, you can turn them so many times. It takes 20 days to fill and 10 days to empty. You traditionally get a lot more than just, I mean if the spread went back down to lower, we still get good value. We are just seeing greater value than we have in the past because of that spread being larger today. But these caverns still get a great value, just because of the service they can provide and the number of times you can turn it. It’s not like a typical cavern where you go to an old producing field and you can fill it over the shoulder months and then empty it in the winter and you only get one turn. You can go in and out of these real quickly. So with the volatility in prices, you get a lot of benefit of having that kind of flexibility and we use these caverns. We have our firm customers, but we have the ability to do interruptible deals, too. So if prices are high today, we can loan the gas out to somebody and they can sell it and then they can hedge it out a month or two and then pay us back in and so we have a pretty good interruptible business at these caverns also.

A.J. “Jim” Teague – Natural Gas Processing / Natural Gas Liquids (NGLs)

First of all, I want to start off by offering an apology. And my apology is, I feel terribly inadequate presenting this story to you because I’m not sure that there’s anyone that can truly stand before a group of people and capture the true dynamics inherent in Enterprise’s NGL system. But given that, we’re going to give it a shot.

Slide 68 – Strong NGL Industry Fundamentals

I’m going to start out by talking about the state of the industry today. If you were here, oh, back the last time we had an analyst conference, we had a fellow come in and talk about how NGLs interact with petrochemical demand. And if you remember back at that time, one of the key components in the study that we had this guy do is any time ethylene production goes above 53 billion pounds annualized per year, then their ability to switch off of primarily ethane to heavier liquids diminishes. And it continues diminishing as their production goes up. Today, they’re producing at an annualized rate of 59 billion pounds per year. Consequently, their demand for, their ability to switch off of NGLs has been diminished pretty dramatically. And if you remember that study, another thing it talked about is what’s important in terms of the feedstock they select as the gas to crude ratio. To the extent that you have low gas prices relative to crude, that suggests then that ethane and propane is a lot more preferable in those furnaces than is naphtha or Algerian condensate or gas oil. Today, the gas to crude ratio is what, 50%? Now, the viability of the US ethylene industry is really a function of what’s your view on gas to crude. And you can find consultants that are all over the map on that.

One of the consultants we use is an outfit called PIRA here in New York. I visited with them yesterday, and they’re forecasting a long-term 65% gas to crude ratio. At 65%, these crackers will run and they’ll run hard as long as the economy is supporting that. I asked the guy, I said, “How comfortable are you with your forecast on gas to crude?” He said, “You know, I’m really not that comfortable.” I thought he was going to say, “You know, I’m really thinking 80 to 85%.” What he said is it’s too high. We’re pretty bearish on that. If they’re right, that bodes well for Enterprise from our processing and the throughput in all of our systems. Today every gas processing plant is in full extraction. We’re seeing margins that in my 35 years I’ve never seen. Have you seen them like this in your 50 years, Dan? They’re running north of $0.50, indicative Belvieu to Henry Hub and we had a day last week I think, Bill Ordemann, that we saw $0.60 per gallon indicative spread between gas and liquids. We expect that those kind of, we expect that these processing spreads will remain healthy for the foreseeable future.

Slide 69 – NGL Assets

I’m going to try to tell you a story about this system, and the story I want to tell you is first of all, you start with the margins we’re realizing as a result of these industry fundamentals. We didn’t create a system to capture those margins last month. What we are today and the margins we are capturing is really a function of what we did 3 years ago, 5 years ago and even 10 years ago. And what we’re going to be 3 to 5 years from now is a function of what we’re doing today. You heard Bob talk a little bit about some of the things we’re trying to do to position ourselves for the long haul. I want to touch on that during the course of this and then I also want to touch on how we’re capturing the margin out of existing assets in today’s fundamentals.

It’s really a simple theme, though it’s a dynamic system. And the theme that we have is we want to position ourselves in major producing basins. And you heard both Bob and James talk about that. I don’t care if it’s – we like the Gulf of Mexico, we like South Texas, we like the Permian, we like the Four Corners, we like Piceance, we like Jonah, we like Pinedale. We are well-positioned as it relates to every one of those key producing regions in the US. The other thing we want to do is we want to build a corridor from an NGL perspective from each of those producing basins to our massive Mont Belvieu complex. And we want volume control.

What does that gain us? It gains us an enhanced value for the liquids we produce because we can get it to the major market and we’re not held hostage by local demand. But it also gives us the opportunity then to leverage relative to Mont Belvieu to increase the value of our sales in those local markets. So that’s really the basic theme of what this whole system is about. The dilemma is there’s so dad-gummed many dynamics associated with that basic theme and you’ve got to be on your toes every day to capture those margins.

Slide 70 – Natural Gas Processing

We’ll start with what our processing portfolio looks like, and Lord knows we’ve worked hard over the last few years to refine this portfolio. What you see on the left-hand side is the environment we’re in today. 44& of our liquids that we own, we get as a fee. James talked about the Chaco plant: 9 MBPD, 8 MBPD we get from the Chaco plant as a fee. Our Norco fractionator, on two key plants that feed that Norco fractionator, our freight fee is what, Bill, anywhere from 10% to 14% of the liquids. And then we have liquid split deals in South Texas in our processing plants, as well as South Louisiana. The 7% that says discretionary keepwhole or keepwhole discretionary is, we have the ability on a look-back basis to say, “You know what? We like the margins. That gas, we’re going to keep them whole on that gas.” And we keep the benefit of the margin. 20% is just fees and then 29% says fee plus. That’s our Shell deal where we have a floor and a ceiling where at the floor we’re still making money and they’re eating anything below it. Above the cap, they get the benefit of it. In a low frac environment, you can see that virtually no keepwhole. I think with the numbers on the next page you’ll see, I think it’s about 300 BPD, a legacy deal that we’re not out of yet.

Slide 71 – Natural Gas Processing

So if you look at where we are today, that 20 MBPD that you see under percent of liquids / proceeds, when prices are north of $1 a barrel on everything except ethane, but if you just said that the aggregate barrel was worth $1 a gallon, that’s $300MM per year in and of itself at $1 a gallon on 20 MBPD. That 11.3 MBPD keepwhole discretionary at today’s margins is around $90MM per year. You move to a low frac spread environment, we’re back to fee plus the Shell deal, no downside risk. We’re down to 17.5 MBPD of liquid splits and very little keepwhole.

Slide 72 – Rocky Mountain Assets / Activity

Now we’re going to go by region and talk about what we’re doing, and we are going to start out by what we’re doing up in the Rocky Mountain area. Ever since we bought Mid-America Pipeline in 2002, we’ve had a goal to be upstream of that pipeline. In fact, Bill Ordemann and I spent countless hours trying to negotiate joint ventures with existing players up there that had no interest in a joint venture with us on their asset. What we’ve done since then is we’ve created two major processing locations that we’ll dig deeper into, a gathering system and frankly the potential of a second gathering system, and then a whole value chain with a Hobbs fractionator that will be supported by the production from these two processing plants.

Slide 73 – Jonah and Pinedale Fields Growth

We’ll start out with the Jonah Pinedale area. If you look at the buildup in production from Jonah and Pinedale, this is about 1.4 Bcf/d. You can see where the, how fast the growth has been. All except the Questar volume flows through the Jonah gas gathering system. I think last month, Bill, that was 1.25 Bcf/d. There are four producers that make up 93% of the throughput and that’s EnCana, BP, Shell and Ultra. The finding cost in that area is less than $1 per Bcf/d equivalent.

And another discussion I had with PIRA yesterday, the potential is pretty dramatic. Their studies suggest that they think that this can grow to be 3.5 Bcf/d by 2010, primarily because of five acre spacings in Jonah. Bill, are they at 10 acre spacings in Pinedale and they could prove that? So, a lot of activity driven by four key players.

Slide 74 – Jonah Gas Gathering System

The gathering system today is about 600 miles of pipe, 92,000 horsepower compression. It’s got about 900 wells. Really, it’s going to be, it’s connected to 4 plants, our Pioneer plant, Williams’ Opal plant, Western’s Granger plant and Questar’s Blacks Fork plant. The exciting thing is what we’re doing up there beyond where we are today. We’re expanding that system. This year we’re going to add about 90 miles of pipe, 24” and 36”. We’re adding 67,000+ horsepower of compression. We’ll have that pipeline completed in 2006, the compression in March of 2007. That’s the first phase of the full expansion. What we’ll get out of that, we’ll get more capacity, about 2 Bcf/d and we’ll reduce the pressure somewhat.

In addition, the following year we’re going to add another 50 miles of pipe, 30”. We’re going to add 90,000 horsepower more of compression. We’re going to bring the volume up to about 2.5 Bcf/d and we’re going to lower the pressures in Jonah to below 300 lbs. and in Pinedale to about 450 lbs., depending on how much gas is going to flow. We’ve positioned ourselves nicely with the growth at Pinedale that we can make incremental investments and get a pretty good pop on a conditional capacity.

The key thing we’re doing is we’re segregating these systems. In the past when you had some problems on the gathering system, there’s always a fight between the Pinedale producer and the Jonah producer over who should get the space. That won’t be an issue anymore. Pinedale will have their own system, Jonah will have their own system, and we have life of lease dedications with the four key producers in that area – Shell, Ultra, BP and EnCana.

Slide 75 – Pioneer Processing Plants

We’re going to anchor that system with a processing plant at Pioneer. As you know, we acquired the silica gel plant from TEPPCO. We’re building a 650 MMcf/d cryo plant. We have agreements, long-term agreements, with EnCana and with Ultra that will anchor this plant. We’re in negotiations with BP and Yates, and fully expect to close those deals. Once the cryo plant comes on, we’re going to shut down this. We’re going to use the silica gel plants as a standby for flow assurance. The story we tell the producers, and it gets a lot of traction, is your gathering fee and your processing fee is really minimal in terms of what you’ve got at risk. What you’ve got at risk at a $5, $6, $7 gas price dwarfs your concerns about those fees. So what we’re offering them is flow assurance. Natural gas liquid processing and NGL takeaway will not be an issue in terms of the flow assurance. That plant will be able to turn down from full extraction where it’ll produce 30 MBPD to a dew point mode where it’ll produce about 2.5 MBPD and still meet downstream pipeline specifications. In addition, Jim’s going to talk about his expansion all the way to Belvieu. We have dual pipe to transport the NGLs. So the story we tell the producer is if you want flow assurance, then you want to be in our system.

Slide 76 – Piceance Basin Growth

And the Piceance in Colorado is another area, and I’ll explain to you what we’re seeing there. We started negotiating with EnCana two and a half years ago about doing a deal to build a processing plant anchored by their production. We have a long-term agreement with them. This just reflects the growth of the Piceance since 2002. When we bought MAPL, it wasn’t even on our radar screen. What we’re hearing in the Piceance right now is that Williams expects their production to peak above 1 Bcf/d; EnCana expects their production to peak above 1 Bcf/d and they’ve made some commitments to us that suggests they’ve got a high level of confidence in that; Exxon advertises more than 1 Bcf/d. When they talk we listen. That’s pretty damn good reserve study in and of itself. Chevron’s talking about 500 MMcf/d and then you have people like Bill Barrett, like Berry, like Marathon, like XTO and Noble out there drilling.

Slide 77 – Meeker Processing Plants

We finally finalized our agreement with EnCana. We’re building a 750 MMcf/d cryogenic plant. It will treat, it will do gas separation, treat for CO₂, NGL recovery and residue compression. It has a turn down from 35 MBPD of full extractions when it’s full to 3.5 MBPD. We spent the money to get the flexibility to be able to meet these producer’s needs. Nothing’s going to keep that gas from flowing from an NGL processing and takeaway perspective. We have, in addition to the deal we have with EnCana, we’re in negotiations with virtually every producer in the Piceance basin. And we’re at the definitive document stage with a couple. This isn’t going to be a processing plant. This is going to be a processing complex because we’re already starting the process of building the second 750 MMcf/d train at Meeker.

Slide 78 – Hobbs Fractionator

At full extraction Meeker I, Meeker II and Pioneer produce right around 100 MBPD. That 100 MBPD will feed our downstream NGL system and the first step will be at the Hobbs fractionator that we’re building at Hobbs. You can read about the fractionator on the slide, 75 MBPD and what we’re doing. And Jim will talk about what we’re doing between Hobbs and Conway.

You see up there, it says Hutchinson Storage? That’s the storage that we bought from FerrellGas last year. It seems like we’ve had it forever. Last year. This is kind of what I was talking about in the beginning. Look at what we’re able to do. We can take those barrels all the way to Mont Belvieu. That’s how we price them. We fractionate them at Hobbs. Our ability to take them to Mont Belvieu gives us an awful lot of opportunity to increase the value in the local market or to take them to Conway. It’s what I was talking about earlier. By having a corridor, you enhance the value of your liquids and you maximize them further by being able to get Belvieu plus in the local market. Or when Conway natural gasoline goes to $0.10 over Mont Belvieu, you move it up there.

Slide 79 – Texas Gas Processing

Down to South Texas, this is a lot. This place is a lot like what we got when we bought Shell’s NGL business in South Louisiana. It had a pipe up too close to Mont Belvieu but it was, it didn’t have a lot of capacity in it. It had contracts down in the local market, pretty good contracts in reality for the most part. One of them was with a refinery down there that used to own the system and needed the product and it was ten years and about to expire. One was with a chemical company that used to have a cracker down there; they had since shut it down. So what we were faced with in South Texas until up before last year is our chemical customer that we’re getting a pretty decent price from that no longer had an appetite because he shut his plant down. So all of a sudden what he was offering us was some pretty deep discounts relative to Mont Belvieu. In addition what he was suggesting is that we had to produce. So regardless of extraction economics, we were going to have to produce the product; we were going to get a deep discount.

Slide 80 – South Texas NGL Facilities

We looked at Javalina whenever it came up. We saw what they were getting for C4+ and we saw things like Mont Belvieu less $0.04 and $0.05 per gallon. So what we’ve done with these plants is they’re all tied into our Shoup fractionator. And what we’ve now done is we converted that one pipeline that we had that we just used in batch service as kind of an overflow, pressure relief valve if you would. And last January first when our contract with that chemical company expired, we didn’t renew it. We have converted that 8” pipeline to ethane service and we moved all 35 MBPD to Mont Belvieu.

Now we’ve got another big contract terminating at the end of this year and we, I mean you know we looked at Javalina. We, I may be from Shreveport but I’m not totally dense, I figured out that the price is going to be a pretty good discount compared to where we were. So we bought a 16” pipeline that Bob mentioned that we closed on 2 weeks ago, and we’re extending that pipeline into Mont Belvieu. Now we’ve got options. Now we’ve got another corridor. We’re going to take those liquids to Mont Belvieu. If we have to, we’re going to shut that frac down and we’re going to take all 70 to 75 MBPD to Mont Belvieu and that 8” line that’s been transporting the ethane, we’re going to reverse it because there’s still a heck of a local market down there that needs serving. But we’re not going to be looking at Belvieu less 2, 3, 4 or 5. Our sales are going to be Belvieu plus $0.025 or $0.03 because we can serve it and that’s our alternative. Their alternatives are things like barges at $0.06 or railcars at $0.06, Dan? I don’t know what a rail rate is, but that’s what we’re doing in South Texas.

We have a corridor from the Rockies, strong production, a lot of volume and control with the local market at Hobbs and Conway. Now we’ve got a corridor from South Texas. We aggregate all of our volume. We move it up to the massive complex we have in Mont Belvieu and then we serve the local market. We’re using that complex to help us enhance the total and then enhance at the margin.

Slide 81 – Gulf Coast Gas Processing

And then finally our Gulf Coast processing assets. And, again, you can read, you can see that we’re recovering from the storms. We had a pretty interesting experience last year and waking up one morning and having not very much production. But we’ve got all of our plants back on and running. We’re seeing our volumes continuously increase. The one area where we still have some issues is down at VESCO. That gas, however, is being diverted to other plants that we own. So we’re still continuing to get the benefits of that. We’re in discussions with the VESCO partners. Again, though, we’re on every evacuation route out of the Gulf of Mexico. So James talked about all the pipelines and other people’s pipelines out in the Gulf of Mexico.

Slide 82 – Louisiana NGL Facilities

If it comes out of the Gulf of Mexico, chances are it goes through our processing plant. If it goes through our processing plant, guess what? It goes into our downstream NGL system. And our downstream NGL system we put in soon after we acquired Shell. We spent $200 to $250MM over there and I’ll tell you, we’ve created an unbelievable franchise because we serve all of – I’ll tell you how important we are. When Katrina went through and knocked out all the production, we were the people that kept most of those people online because we took LouTex and we moved all of the products they needed from Texas back over there. So as refineries and crackers came back up, they had supply that they needed, otherwise they couldn’t have run, by virtue of our system. When Dow’s cracker went down at St. Charles and it uses 100 MBPD of liquids, when that cracker when down at St. Charles, we didn’t have the supply to run Norco fractionator. Consequently, Dow left half of that cracker down until we got Norco back up. This system is absolutely critically important to the petrochemical industry on the Gulf Coast.

In addition to what we’re doing here, we’re also in negotiations. We serve every refinery over there. We’re in negotiations with two of the key ones, Motiva down in Port Arthur and Marathon over at Garyville. We want to be their 100% NGL guy. We want to take care of the butanes they need when they need it. We want to market the propane they have. Today we handle 100% of Motiva’s Norco and Convent business. We handle 100% of Valero St. Charles business. And we handle a lot of Murphy’s and the Exxon Chalmette’s and Exxon Baton Rouge. We are a 100% supplier to Shell Chemical over there. We have, I mentioned the supply arrangement with Dow Chemical and we supply 75% of the Williams crackers needs in Louisiana. And guess what? What’s common to this, tied to Mont Belvieu? It’s a corridor. We’re not in the days before we built this system when we were getting 3, 4, 5, even 8 cents discounts in the summer to Belvieu on butane. We don’t sell at discounts in the local market. We sell at premiums to Mont Belvieu.

Slide 83 – Mont Belvieu, Texas and It’s Pivotal Role in the Global LPG Industry

So we talk about Belvieu. I think one of the most exciting things that happened to me in my career, and I’m a Dow retiree so I have a little bit of knowledge of these petrochemical companies. But I always used Mont Belvieu but I never had anything there. One of the most exciting things about being a part of Enterprise is you’ve got a big position in a major location like Mont Belvieu. I don’t think people fully appreciate what this system or what this location means, not just to the NGL industry but to the whole hydrocarbon industry. It’s the storage gets it, it makes it a transparent trading, look, but let’s start. It’s the primary global pricing point against which all other regions are balanced. And these are the reasons, the storage, the connectivity, its fully integrated and developed production consumption base and its primary location utilized with industry, it holds significant seasonal excesses.

Here’s what it really means. There’s a cracker down in Argentina that Dow owns that cracks ethane. How do you think it’s priced? Mont Belvieu. The Saudis wake up every morning and they want to know as they put their CP together at the beginning of every month, what’s contract price, posted, what’s going on at Mont Belvieu? Because they’ve got this little company in Mont Belvieu that, if they’re not careful, has the ability to export the hell out of propane into their market. Algeria, one of our largest – what are they? Hell, vendors? Suppliers? – mark their performance on how they do relative to Mont Belvieu. It is a very special place. Every petrochemical company in the US price their NGL feedstocks off of Mont Belvieu as does every refinery, as does other parts of the country.

Slide 84 – Mont Belvieu Fractionation, Storage and Distribution System

Our system in Mont Belvieu is, we’ve got the largest position there. We’ve got a 225 MBPD fractionator that we recently expanded by 15 MBPD. We didn’t just get capacity at one of our trains, we lowered the hell out of our operating costs. Gil will talk about the storage capacity there. James says he’s going to take a bunch of it away. That’s fine. We just get higher prices on what’s left. We’ve got a distribution system that’s second to none out of there and we’ll talk about that real briefly.

Slide 85 – Houston Ship Channel Pipelines and Import / Export Terminals

Our ship channel pipeline has primarily been driven by serving petrochemicals and refining on the Houston Ship Channel, as well as our import / export business. We’ve really been focused and it’s a pretty dynamic system because you’ve got, what you’re going to have is our pipes from South Texas tying into this, as well as our import pipes. So we’re looking at ways that we can tie all this together to get more capability without adding a heck of a lot more pipe. And we think we can. We’re also looking at how do we expand the utility of that pipeline system by doing things like we’re in negotiations right now with a petrochemical out of Chocolate Bayou has a demand for about 120 MBPD and other than about 30 that he produces himself; we’re in negotiations with him to being his sole feedstock supplier. We’ll use that system to be a sole supplier and we’ll make some money. We’ll make $0.0075 to $0.0125 on every gallon we deliver to him.

Last week we finalized a deal with another Chocolate Bayou chemical company whereby they import a lot of naphtha and a lot of Algerian condensate. We are, we’ve done a deal with them where we’re going to transport 100% of their imported condensate and naphtha that they use at their cracker and that’s virtually everything they use. And it’ll be 50 to 55 MBPD; 10 year deal. Reality is it’ll go beyond my lifetime. The other thing we do there is we load barges at Morgan’s Point and then it serves all of our import / export activity.

Slide 86 – Enterprise LPG Imports and Exports

This shows you what we’ve imported over the last few years and what our mark, and what we’ve exported and what our market share is. If you come to the US, by and large we’re the gateway. This year we’re going to have over 60% market share of all imports in the US and that’s primarily a missed point on the other slide. The other thing we’re doing in combination with the import terminal and the Houston Ship Channel is we’re trying to expand the range of products we handle. So we’re doing things like signing contracts to import and transport and store stuff like low sulfur natural gasoline and light straight run naphtha because the new specs require that. And we’ve got a million and a half barrels in the hole right now and talking to several other companies about expanding that service.

Back to this, we’re going to be over 60% market share this year in imports. We’re going to be 88% market share in exports. When we talk about imports, we’re talking about purity propane, we’re talking about mixed butanes primarily. It’s kind of neat, though. We’ve been able to take that market share and hold that market share without cutting fees. In fact, we’ve been raising our fees. And we’ve gotten our spot fees up from $0.0125 and $0.035 on propane and butane to $0.02 on propane and $0.05 on butane, which also includes the splitting. We get $0.055 on the exports, I think. The other thing you get when you get this propane is this stuff’s 99% propane, HD5 can have 4% or 5% ethane in it. At a $0.30 spread, you start blending a little ethane in there, you’re still making, you’re still meeting HD5 specs and all of a sudden you’re turning ethane into propane and capturing $0.30 on every barrel you blend in.

Slide 87 – Enterprise NGL Marketing Import Term Contract Slate

We changed our approach on our imports. Used to it was strictly spot. You call, we’re here. We’ve seen some growth and I’ll show you a slide. We see growth coming in the international market. So we’ve got growing production in the Rockies. We’ve got growing production James talked about in the Gulf of Mexico. You’ve got growing international production. So we changed and we said, “You know what? We’re going to contract this thing and we want some take or pay contracts or minimum throughput contracts.”

So the left circle shows you what we’ve got under contract now. These are 5-year plus contracts with national oil companies, major oil companies and some international trading companies – a minimum of 20 MMBbls, maximum of 32 MMBbls. Our current import dock is virtually sold out today. And this is with people like Statoil, Petrobras and Dow and folks like that.

We are in negotiation to put together another 12 to 15 MMBbls with people like Sonitrach. What they get out of this is they retain their optionality. They know that they’ve got space at our terminal. If they get a better deal in the Far East, we still get our money and we sell that as the way we participated in their upside. So the story we tell them is, look, you put a ship in the water. If Japan goes $100 over CP, you don’t have to bring it to us. Just send us a check. We’re okay with that. Go collect the money from them. This is why these guys are pretty interested in this.

Slide 88 – Global LPG Supplies Are Expanding

This is the production growth Purvin & Gertz is forecasting internationally for additional supplies of propane and butane in millions of barrels, and you can see sourcing. Primarily it’s West Africa and the Middle East. Qatar is a big part of that with some of their projects.

Slide 89 – Enterprise Import / Export Expansion

Consequently, what we’re going to do is we’re expanding our terminal. The left side shows the current system. The right side shows next April what it will be. We’re going from three docks with two loading arms – we’re adding two more loading arms. Why? Because we’ll be able to unload two different products at the same time instead of just one product at a time. We’ll be able to unload two vessels at the same time instead of one vessel at the same time. We’ll have an instantaneous rate of 20,000 barrels per hour (bph) instead of 10,000 bph. There is nobody in the Gulf Coast of the US that can touch that, and very few people in the rest of the world. We’ll increase our export capacity by 2,000 barrels to 7,500 bph, up from 5,500 bph. But here’s the key to that. The key to this is we’re also expanding our butane splitting capability. Targa’s sitting over there or Dow’s sitting down there and they can compete with us for offloading ships. But whenever half of this stuff is mixed butane, you damn well better be able to split the butane. So God knows 300 MBPD is splitting capacity now, Dan?

Slide 90 – Enterprise NGL Marketing: Wholesale Marketing

I’m about through you all – I see Bob doing a sigh of relief. We’ve got producing basins that we’re tied to in corridors. We’ve got a hell of a supply system. We’re bringing it out of the Rockies, the Four Corners, the Permian, the Gulf Coast and internationally. Now you tie that all together with market reach, and I’ve touched on that some as we’ve gone through this. But we’ve got a marketing group and their job then is to take this and make the extra money. And we’ll show you how they do it.

First of all, we’ve got a pretty big wholesale group. These guys sell propane to the retail propane market. We move about 40 million barrels per year. We’re the second largest in this. We make $15MM, $12 to $15MM, but that’s after they pay full tariffs on all Enterprise assets that they use. And if you’ll see on the slide where they’re really concentrated in the Southeast where we have assets, like the Dixie Pipeline and the terminals on the Dixie Pipeline. We’ve got about 10 guys I think, 10 to 12 guys dedicated to this.

Slide 91 – Enterprise NGL Marketing: West Coast Refinery Services

The other thing we do is we serve the refining industry. Here a few years ago, we opened a small office in California because we got a couple of Shell’s refineries. And we said, “You know, let’s put a presence out there. Let’s see what happens to it.” Today we’re serving five refineries. We’ve got Tesoro 100%. We’ve got a couple of the Shell refineries. We’re negotiating for 3 other refineries. We’ve bought the storage at Adamana which is now full with rates increased supporting that activity. And believe it or not, it ties back to Mont Belvieu because in the summer when these guys are long, we rail this stuff back to Mont Belvieu or up to Conway. We also have bought some terminals that support that activity. Out there we’re doing about 50 MBPD. Key customers are Tesoro and Shell, and in negotiations with Valero.

Slide 92 – Enterprise NGL Marketing: Gulf Coast Refinery Services

On the Gulf Coast we’re pipeline-connected to every refinery down here, virtually. I’m not going to go through all of them, I’ll just give you a highlight of it. Down at Valero–Corpus Christi, we supply them with 17 to 20 MBPD out of the Shoup fractionator. We’re going to continue to serve them. If we shut down Shoup, we’ll just serve them from Mont Belvieu. It’s a pretty critical supply to them because they had their MTBE plant, now they’re converting to isooctane. They need low sulfur feedstock. We produce low sulfur feedstocks. We’re going to see that price improve $0.03 to $0.04 per gallon.

We do 100% of Citgo’s isobutane demand down there. Up on the Houston Ship Channel, people like Valero and BP down at Texas City, we serve. We’ve just signed a new deal with Motiva at Port Arthur to be able to supply them isobutane, Valero at Port Arthur, and we’re in negotiations with Motiva at Port Arthur to serve them 100% of all their NGL requirements. We have 100% of Motiva, Convent and Norco. Anything they need on LPGs, we’re the guy. We’ve got 100% of Valero at Norco. We’ve got about 75% of Marathon’s, and in negotiations to serve their expanded refinery.

I think what it boils down to is there’s not a refinery on the Gulf Coast that we’re not doing business with. Our drive is we want to be the guy that does all the business that they need from an NGL perspective.

Slide 93 – Enterprise NGL Marketing: Gulf Coast Petrochemical Services

And the other one, we started off talking about petrochemicals, is what we do with the petrochemical industry with our marketing group. We’re pipeline-connected to every petrochemical site in the US, except West Lake, a small cracker in Kentucky. We market to every chemical company and we deliver more to them than we market to them. Our system is absolutely critical to the petrochemical market in the US. They are hampered if we can’t serve them.

Example: 65% of Dow Chemical’s NGL feedstock are delivered through an Enterprise asset. We handle 100% of Shell Chemical’s feedstocks and we sell to them 100%. I told you how Dow reacted, what they, how they were crippled when our fractionator couldn’t run. Equistar, we provide them with 80% of their NGL feedstock; Exxon 50%; Huntsman 50%. We’re negotiating with them to be an exclusive supplier out in West Texas. My point is, we are well positioned to take the production that we have from the basins and to serve the wholesale propane, the refining and the petrochemical industry. We want the volume control from a supply point. We want the market penetration from a sales point.

Slide 94 – Enterprise NGL Marketing: Domestic Marketing

And then what we do, and we talked about earlier about how you can then leverage that Belvieu position to enhance your sales into local markets. We’ve got about four guys that every day are focused on strategies that put the marginal dollar in our pocket. And these are the kind of things they look at. Some of these guys, they don’t want to have any working capital. They keep low inventories. When they want it, they want it. They’ll pay us $0.01 or $0.02 per gallon to give it to them now, and they’ll give it back to us at the end of the month, or we’ll just buy it at the end of the month. $0.01 or $0.02 spread.

North; South; we’ll buy Conway when it’s cheap; we’ll sell Mont Belvieu and we back it up by our ability to pump barrels South. Think of what we’re going to have with this thing in Corpus Christi or in South Texas with our new corridor. We’re going to be able to do the same sort of thing. We even do those things within the Mont Belvieu area when you’ve got pump barrels with a premium to others. We also look forward to buy in current month and sell forward. Or we’ll sell current and buy forward. The point is these guys are taking a look at the total and they’re pulling it together and they’re capturing the marginal money plus paying Enterprise assets full tariff on every barrel they flow through. They happen to be our NGL assets’ biggest customer.

And with that I’ll open it up for questions.

Questions and Answers

Q:	What do your customers say about taking NGL storage and switching it to natural gas? And I know that you feel that’s going to be good for your margins, but what does it do for your relationship with your customers?

Jim: I think they understand. From a petrochemical perspective, and I’ll use the only paradigm I have, is my experience with Dow. They know storage is undervalued, number one. And it’s really not the hole in the ground they’re after, it’s the deliverability. When I was at Dow, I had storage contracts with Dan; I had them at TEPPCO; I had them at Diamond Shamrock, I had them at Warren. Why? It’s dirt cheap. Why did I have all those storage contracts? I didn’t need to put all that stuff in the ground. I wanted the deliverability. Our customers understand it’s a bargain and they, I don’t think there’s going to be any issue with our relationship. What they may do, as long as we can meet their deliverability requirements, that’s key to them. And in many cases my point to you is they may be storing at more than one location because it’s deliverability they’re after. You raise the fees, we’re going to be able to give them the deliverability with all the money that Gil will talk about that we’re spending on the brine system in Louisiana. I think we’re going to improve the relationship before it’s all said and done. But it’s not about taking storage away. It’s about giving them deliverability.

Dan: And I would like to add a little bit of color to that deal. Since we bought the storage, and Gil Radtke here at that time he was with a company called Diamond-Koch, and we bought the Diamond-Koch storage in Mont Belvieu. Since that time, I think it was in 2002, Enterprise has spent probably $125 to $150MM of expenditures at Mont Belvieu, like brine storage now. We just spent probably $45 to $50MM for brine storage that you have to have, that a few years ago you didn’t have to have because you could inject it in the salt water sand. All of our pipelines out there we’ve done, all the Houston Ship Channel pipelines we’ve done, we’ve probably spent $150MM over the last 3 years on infrastructure at Mont Belvieu. We had long-term contracts that we have not been able, when they come up we’re going to renegotiate those long-term contracts and we’ll have a storage contract and we’re going to have a deliverability type contract.

So we’re not talking about taking anything away from anybody. What we’re doing, we’re adding the services and getting the return on the additional capital that we’re having to spend to serve all the people out there. As you can see, we’ve got 94 MMBbls of storage out there. We can expand that storage by 5 MMBbl increments or probably $10 to $15MM for each storage well we would develop. For a natural gas storage well, you have to have compressibility so you’re talking $35MM for natural gas. So we have plenty of room to expand storage, so we won’t take away any service from anybody we’re doing business with.

But now, when product index used to be $30 crude oil, $4 natural gas, you were getting the same amount of fees. Now as prices go up, I think all of the majors are talking about $4.5 to $5 gas long-range based on today’s dollar. I think they’re talking $40 to $45 crude oil based on today’s dollar. So as they see the expenses are going up everywhere, there’s no question about that, fuel costs are going up everywhere, so what we’re going to do is try to catch up with the cost increases or what we call cost creep on the deal and start getting a return on all of the additional investments we’re talking about. And we go to our customers and explain that to them and show them what we’re doing and give them the service that we’re giving them. It’s very small prices they’re paying for storage relative to the value they get out of it.

Hi Jim, I have 2 questions on the Rockies. One is related to the processing plants that you’re building out there. And since the gas isn’t quite as rich out there in the Rockies as it is in some other areas of the country, just in terms of how you’re structuring those processing contracts to make your return on those assets stay relative to some of the other basins that you’re active in.

Jim: I didn’t want that question.

Sorry.

Jim: Okay. These contracts are keepwhole contracts. But what we’re doing is, we’re building in the capability in the plant to be able to manage any exposure. And that’s what we meant by we can go from 35 MBPD at Meeker to 3.5 or 3 MBPD. Bill, what is it? 3 MBPD butanes and gasoline primarily, a little propane, still meet the downstream specs. And we’ve not seen that underwater. We think we’ve protected ourselves and our ability to swing that. In terms of the richness, what we’re seeing in the Piceance is 2 to 2.5, Bill? And the same thing in Jonah. We see Pinedale is just a little leaner. We’re negotiating with another company that’s a little leaner. Those deals will be different. They’ll be more fee-based deals.

Q:	I guess a related question, which I’m not sure you want either, but in terms of all the gas pipeline proposals that are looking to move from the drawing board to actually getting done coming out of the Rockies, just in terms of your view longer-term in terms of that historical basis differential.

Jim: You know we did. When we did our economics on Meeker and Jonah, I think, I’m looking at Bill Ordemann who runs our processing, I think we used a $0.60 or $0.70 basis, Bill. So we were not outrageous in terms of looking at our economics as to what the basis would be. We were pretty conservative in looking at those plants and what we expected. And we used a narrow basis. When I was at PIRA the other day, they said we should be thinking just north of $1.00. We used $0.60 to $0.70.

Q:	Fair enough. Thanks, Jim.

Jim: Anybody else?

Q:	You came out with a very positive press release yesterday on the contracts on Mid-America. Can you just touch base with...?

Jim: That’s Collingsworth. He’s the next up.

Q:	Okay. All right. Very good.

Jim: I wouldn’t dare steal his thunder. He’s gone through hell to get those.

Randy: We’ll go ahead and get started with Jim’s, and then we can take some more questions later to try to get back on schedule.

James M. Collingsworth – Regulated NGL Pipelines

Slide 96 – Regulated NGL Pipeline Group Overview

Good morning. The regulated NGL pipeline group is made up or comprised of 5 different companies. You’ve got Seminole Pipeline Company, Mid-America Pipeline Company and Dixie Pipeline Company that are regulated. We have 2 unregulated entities which are Enterprise Terminalling & Storage Company and Dixie Terminalling & Storage Company.

Slide 97 – MAPL, Seminole and Dixie Pipelines

Spend a little time on this map, and Randy said there was a pointer up here. But what you don’t see when you see this map, and to me it’s quite an impressive map covering over 20 states in the US. What you don’t see is 20 to 25 businesspeople back home in Houston, and 250 to 300 people out in the field every day, and what I tell you they do every single day is spend every minute of every day trying to make this system better and looking for the next deal for us to do.

I’ll focus on the Northern system. We really break down Mid-America into three different systems. On the Northern system, going due north out of central Kansas, you have 2 lines that we refer to as the West Line. The red line is a batch line that moves propane and refinery-blend stocks to the Pine Bend, Minnesota area or the Twin Cities. The blue line is dedicated 365 to the movement of propane. Along that system you have several terminals that are owned by Enterprise.

If you move east of there out of Conway, you’ve got an additional 2 lines. The red line is dedicated to the movement of EP mix. We move approximately 70 to 75 MBPD of EP mix to petrochemical facilities in the Chicago area. The blue line following the red line there is like the line on the West system which is dedicated to propane 365 days a year. The 2 propane lines are unique in the fact that it’s one of the only on-demand propane systems in the US. What that means is if you deposit a barrel of propane in Conway, you can immediately withdraw it at any terminal along the system. The 4 systems up there move approximately 22 MMBbls/yr of propane, 5 to 7 MMBbls/yr of refinery feedstock and about 70 MMBbls/yr of EP mix.

From there I’m going to move down south to the Dixie Pipeline system which is a C-Corp. It’s also today a dedicated propane line and the only line that services the propane market or the propane industry in the Southeast. It moves approximately 100 MBPD. And I might back up a little bit and tell you that where we are not the only pipeline, in areas where we are not the only pipeline, we are the biggest. And in the Southeast on Dixie, we’re the only one in the area.

I’ll move from there, west to Seminole. You’ll see on Seminole Pipeline Company, we have 2 pipelines. The blue line starting at Hobbs, going down to Mont Belvieu is a batch system where we move EP and purity products from the Conway and Hobbs market down to the petrochemical complex in Belvieu with some y-grade in that. The red line is dedicated to the movement of y-grade. Since we bought this system, these 2 lines have a total capacity of about 250 to 260 MBPD. These lines have been running full. In fact, for the last couple of years we’ve been offloading 20 to 25 MBPD of product to other carriers so we could meet our customers’ demands.

I’ll go from the Seminole Pipeline Company to the Central system. Again, you see 2 lines. One of those lines, the blue line, moves from the Conway area south, taking excess finished products from Conway into the Skellytown area, which I’ll talk about a little bit more later, into the Hobbs area and then further down to Mont Belvieu on Seminole. The red line picks up y-grade from the north Texas, Oklahoma and Kansas producing regions and can deliver that y-grade either to the Conway fractionators back to the Hobbs fractionator or on down to our huge Belvieu complex.

Finally I’ll move back to the Rocky Mountain system, and this is kind of a general overview. I’ll go into more details on the Rockies in a minute. The Rockies pipeline today is the only pipeline that transports demethanized mix out of the Rocky Mountain region. It’s dedicated to the y-grade. It’s got a current capacity of about 225 MBPD.

Slide 98 – 2006 MAPL Growth Initiatives

Going to our 2006 growth initiatives. First, the expansion of the Rocky Mountain pipeline and the Conway to Skellytown system – I’ll go into more detail on that in a minute. The next line is to secure long-term volume dedications from the Rocky Mountains. Yesterday we announced that we signed all but one of our current shippers up for a minimum of 10-year up to a maximum 20-year terms that will ensure the current capacity to 25 and the expansion capacity of 50 MBPD will be full for the next 10+ years. And additionally, as I look at the volume forecast provided by our producers, I expect a further expansion of that pipeline system in let’s say the 9 to 10 year timeframe.

The next item we’ve been working on is the tariff filings we’ve made on the Northern system. When we bought these systems, prior owners had looked at it as a combined system. We broke it apart into 3 different systems. What we discovered on the Northern system was that our operating revenues were less than our actual cash operating expenses. Using the FERC process, we filed for a tariff increase in May 2005. We did a pancake filing in May 2006. Those 2 filings will add $16MM per year in revenue to the Northern system. We’re collecting those revenues today, subject to refund. The rates are before FERC. We are very confident we’ll prevail in our position, as we only raised the rates to get half of the headroom available under FERC guidelines. However, that will not be an easy win or a quick win. We’re looking at probably 1 to 2 years as we go through this FERC process. Our hearing on those rates today is scheduled for February 13, 2007.

And then the final item of our initiatives is to continue power optimization projects along our pipelines. Fuel is our biggest single expense on the pipeline system. I use the rule of thumb that for every dollar gas goes up, our fuel costs on the system go up $8 to $10MM per year. We’ve taken a very aggressive approach the last several years in looking at where we can convert from gas to electricity, putting in variable speed drives. We continue that process today, and we’re really focusing on the Seminole Pipeline.

Slide 99 – MAPL Rocky Mountain System

On the Rocky Mountain expansion, we’ll go through some of the things we’re doing here. As I said earlier, it’s 225 MBPD. That system ran at 85% of capacity over the last 4 years. Last year it ran at 90%. In June of this year, we did 6 MBPD more than we did June of last year. July of this year we did 16 MBPD more than we did July of last year. So you can see the volumes are already coming up, even though we haven’t added a new plant yet and that’s because of the strong ethane recovery margins that exist today. Where’s the volume growth coming for to fill the expansion?

Slide 100 – Expected NGL Volume Growth in Rockies

I’ve got a slide here that shows that volumes are going to go from about 200 MBPD in 2005 to about 375 MBPD in the 2013 timeframe. What’s important to note is most of the volume growth you see on this chart is associated with either plants Enterprise is expanding or building and/or shippers that have just dedicated their production to our system for at least the next 10 years.

Slide 101 – MAPL Western Expansion Project (WEP)

On the expansion to date of 50 MBPD, we’ve got 75 miles of the 165 miles of pipe laid. The remaining will be complete by October 2006. The pump station conversions started in April; they’ll be complete by mid-2007. There are 23 pump stations along that pipeline and we’re redoing every single pump station. The first new plant is expected to start up in December 2006, which is Opal #5, adding somewhere between 12 and 20 MBPD on a ramp-up basis. The next plants coming on will be in the third to fourth quarter of 2007. What we referred to is WEP I. WEP I is right-sized for WEP II, which we anticipate down the road.

Slide 102 – MAPL Rocky Mountain System

Unlike the offshore business, I don’t have those big floating things or like Jim’s business and Gil’s business those big round things or big tall things. I’ve got a piece of pipe buried in the ground. It makes great math but there’s really not much to look at. So what I thought I’d do is show you what a pipeline looks like when it’s being constructed. Here you see a picture of the crews out there and their dynamite, preparing to dynamite a ditch where there’s a lot of rock and the ditching equipment can’t go through it.

Slide 103 – MAPL Rocky Mountain System

On the next slide you’ll actually see the pipeline being laid on the left, and on the right is what the ground looks like after the pipeline is laid and full of product. It kind of shows how environmentally-friendly Enterprise is as we go through the construction process.

Slide 104 – Conway to Skellytown Loop

The Conway to Skellytown Loop, Jim talked about it a little bit. What we have today is 102 miles of 10” pipe between Conway and Skellytown. We’re adding 190 miles of 12” pipe. What that allows us to do is expand the capacity from Conway to Skellytown by 60 MBPD where we have refineries such as Valero, ConocoPhillips and petrochemical plant Celanese that we can serve better than we have been in the last few years because we’ve been full. In addition to that, it allows us to fully utilize a virtually idle piece of pipe between Skellytown and Hobbs of 50 MBPD. That will allow our customers to move product from the West Texas market to Conway and/or from Conway back to Hobbs and/or Belvieu.

Slide 105 – Dixie Pipeline

Now I’ll move to the Dixie Pipeline. Dixie Pipeline is the C-Corp. It’s 1,300 miles long, starting in Mont Belvieu, Texas, ending at Apex, North Carolina. For the golfers in the group, that’s about 22 minutes from the number one tee box at Pinehurst number two. There are 7 Dixie-owned terminals and 5 privately-owned terminals. We have storage capacity of 640,000 barrels and a pipeline capacity of 220 MBPD. We move on average 101 MBPD. Enterprise currently owns 66% of the pipeline, BP owns 23% and Exxon owns 11%.

Slide 106 – Dixie Pipeline 2006 Objectives

Our strategies or objectives for 2006. Last year, about a month prior to Enterprise taking over managing operations of the pipeline, we had a contamination event where we incurred approximately $9 to $10MM in extraordinary costs cleaning the system up. We’re actually pursuing the recoupment of that money from the offending party. On our growth optimization initiatives, we just made a tie-in to Jim’s – let’s see the company Jim retired from, I think – Dow Chemical over in Louisiana. We started pulling that connection in July of this year. By the end of this month, we’ll deliver more barrels into Dow than we envisioned delivering the entire year when we did the economics on the connections. We’re looking at potentials of removing the terminals from the regulated rate-base, which will increase business opportunities as we look forward. And also in July of this year, we indexed our tariff by the FERC-allowed 6%. We’re also expecting this year to increase our ownership in the Dixie Pipeline.

Slide 107 – Revenue Increase from PPI Adjustments

The last thing I’d like to touch on, and I’m trying to real hard to get us back on schedule since Teague took so long, is the indexing methodology that FERC has adopted. Several years ago they came out with a formula that allows all regulated pipelines to increase their rates on an annual basis on July 1 each year. And historically that’s been based on the producer price index. They review that formula every 5 years to see if the companies are getting what they deserve. They just came out with a new formula where we add 1.3% to what the increase is for the year on PPI. If you look at July 1, 2006, the increase on Dixie, Mid-America and Seminole was 6.15%, generating about $16MM per year in additional operating margin. As we look forward using the first six months of this year and estimating what the next six months will be, we estimate that we’ll get another 6% increase in July 2007.

And with that, I’ll take any questions. I think I may have answered his one on the contracts. Good. And I think, Mike, a break is next?

Mike: Yeah, if there are no other questions. And back over here through these doors we have drinks and some food back in there for your break, about 10 minutes.

BREAK

Gil H. Radtke – Petrochemical Services

I’m Gil Radtke, and I’m responsible for the Petrochemical Services group. This group of assets, for the most part, is at the tail end of the value chain that we’ve talked about today.

Slide 109 – Petrochemical Services Overview

When we look at the assets that make up this group, you have butane isomerization, which is towards the tail end of the value chain. Propylene fractionation is also at the end. Mont Belvieu hydrocarbon storage that we’ve talked about some today already is kind of in the middle of the chain. And then our pipelines for propylene and isobutane, high purity isobutene, are kind of in the middle. Then the octane enhancement is really the one that is at the end of the chain.

Slide 110 – Mont Belvieu Growth Initiatives

When we’ve talked about some of these growth initiatives that we’ve had around Mont Belvieu, we’ve talked about the pipelines to a certain degree. Jim talked about the rawmake pipeline out of South Texas, but we’ve also expanded our refinery-grade propylene gathering systems from Texas City and we’re also working on a new one from Port Arthur. When we look at our gathering system now, we’re expanding our reach into these major refining hubs that we didn’t historically have connections into. And that’s important to us to keep our feedstock to our propylene business.

We’ve talked about the storage services and some of the things that we’re doing there. We’ve drilled 2 new brine production wells out there. We’ve increased our above ground brine storage capacity, and we’re also working on the optimization, if you will, of the utilization of our wells. And I think one of the questions earlier was kind of addressing are you going to basically take services or business from your NGL guys at the benefit of the gas storage. And really what we’re doing through this optimization program and what this is is pipelines, it’s second entries into wells. It’s going to allow us to maintain our NGL business for storage but then also get into the natural gas side of the business which has a much higher return than what we’ve historically seen in Mont Belvieu. And part of that has to do with the fact that, as Dan alluded to earlier, the fees out of Mont Belvieu are much lower and that’s driven by the fact that it’s only 40% utilized. If you look at the total storage capacity at Mont Belvieu, it’s north of 170 MMBbls. And at the peak you’re at about 40% utilization of that. So simple supply / demand economics will tell you you’re not going to get higher fees out there for that. So, what we’re trying to do is find the better value pieces of the storage business so that we can get the return up on this business.

Jim alluded to, just continuing on here with our growth initiatives in Mont Belvieu, Jim already alluded to the NGL fractionation expansion we’ve done. We’re in the middle of completing a propylene fractionation expansion that will be on in the third quarter of 2007. And then our octane enhancement that we’ve reported on in the second quarter, we had a very good quarter in that business and we actually completed that conversion in May 2005. And that facility earlier in the, right after we converted it toward the end of last year, we were actually still producing MTBE in that plant for export. And that was a very good market at that particular time. Now, again, that’s going away as they’ve phased out MTBE in the United States. But this facility has a lot of flexibility that’s built into it now. So it’s been a very, very good business for us so far this year.

Slide 111 – Butane Isomerization Service

Just kind of hitting some of the highlights of each one of these businesses, when we talk about butane, butane isomerization, basically this is the process of converting normal butane into high purity isobutane. And this high purity isobutane, the primary markets that we sell to are propylene oxide businesses. We also can, we have excess capacity as refiners need more isobutane we can produce that from the normal butane. In general, the industry is typically long normal butane and short isobutane. So this facility helps balance out that inequity there.

Slide 112 – Isomerization Business Outlook

When we look at our business, and overall it’s a fee-based business, it has very stable demand from long-term customers but we have extra capacity that we can utilize with some of the imports. There’s different parts of this plant, so we can utilize parts of the plant when we have more imports of mixed butanes that Jim alluded to earlier that allows us to really get more out of these plants than just what their base business is. And there’s, our expectation is you’re going to see an increase in demand for this isobutane product going forward because you’re basically eliminating MTBE in the gasoline pool. The replacement for that is alkylate or isooctane. Those components need isobutane to make them work.

Slide 113 – Propylene Fractionation

Turning to propylene now, this is kind of a Propylene 101. When we talk about propylene, there’s really 3 grades of propylene. There’s refinery grade propylene (RGP), which is the lowest grade. It comes from refineries – it comes off of cat crackers at refineries and it comes off of cokers. It’s about 60% to 75% pure. Chemical grade propylene (CGP) is a little purer – about 95%. And then polymer grade propylene (PGP), which we produce off of our fractionators out there, is 99.5% to 99.8% pure. We look at refinery grade in BPD and the chemical industry looks at all the polymer grade and chemical grade in millions of pounds (MMlbs). So basically 183 lbs. equals one barrel.

Slide 114 – Propylene Assets

Looking at our assets, what we have is we own 3 polymer grade splitters out in Belvieu. It has a capacity today of about 72 MBPD of product. Our share of that is about 3.9 billion pounds. Basell is a partner in one of the splitters with us. TOTAL is another partner in another splitter. These guys are important partners to us because they have the offtake. They produce the polypropylene, that is, this feeds their polypropylene plants.

We also own a 30% interest in a 1.5 billion pound per year chemical grade plant in Baton Rouge, Louisiana. Our partner is ExxonMobil – they own the other 70%. They manage it and they supply the feedstock to it.

Slide 115 – Combined Propylene Systems

This is just kind of a graphic of the reach that we have in this business. The red line is what we call our LouTex chemical grade line that goes all the way across, basically getting chemical grade propylene from Shell and ExxonMobil and bringing it to Belvieu. We have an extensive refinery grade propylene gathering system that goes all the way over into Louisiana, as well as around the Texas City and Port Arthur areas that we’re developing now. Third party lines bring in feedstock from the Mid-Continent area and from North Texas. And then our distribution grid is a pretty tight grid because of all the demand is right there close to Mont Belvieu, for the most part it’s close to Mont Belvieu, other than the line that goes over to Basell in Lake Charles.

Slide 116 – Current Propylene Business

Currently, I mean, this business is pretty much a fee-based business. If you look at those first 2 bullet points, the total processing and implicit fee arrangements, both of those are basically fee-based business. So 79% of what we do is very stable income, very steady. The other 21% that’s variable margin is typically close to the same value that we have on our fee-based businesses, but it has some variability to it. So we actually have some upside in this business. Baton Rouge, the chemical grade splitter that we talked about, is equity income. It’s fee-based and it’s very, very stable. And same thing for the pipelines – all these pipelines are fee-based pipelines and very stable income.

Slide 117 – Propylene Outlook

Now in general the propylene outlook is, I would say, it’s very optimistic because what you have today is you’ve got about 154 billion pounds of demand in the world, 36 billion pounds in North America. It’s grown at about 5% per year. The crackers that are being built around the world, primarily in the Middle East in Saudi Arabia, Iran and other points are light crackers. They’re not going to produce a lot of propylene. So what that means to us is the propylene growth is going to have to be fed by the refiners. And we’ve seen some of these refinery expansions, Motiva has a big refinery expansion that they’re doing in Port Arthur. Others are doing smaller expansions that may not necessarily be announced but they will add feedstock to our business here.

Slide 118 – Propylene Outlook

So because of that, we’ve been working on an expansion. It is well underway. It will be completed in the third quarter of 2007. It is a billion pound expansion. We’ll ramp up our utilization from 80% in 2008 to 90% to 100% in 2010 forward. And this business historically has been around a 20% return-type business and that’s what we’re looking at here on this kind of business.

Slide 119 – Mont Belvieu Storage Services

Now focusing on Mont Belvieu storage a little bit more, as we mentioned before we have 94 MMBbls of what we call usable capacity – that’s what we can readily use based on pressures and size of caverns, the permitted volume, and whatnot. So we have multiple pipelines. The picture that you see here, a lot of the, it’s hard to describe, but the white dots you see out there are mainly the well heads. Everything else is underground. There’s a huge spaghetti bowl of pipelines that run in and out of these facilities. And as Jim mentioned, I mean this is the focal point for the Gulf Coast for NGLs and olefins. It is the pricing point for NGLs around the world. And this again, is a fee-based business. We have very stable operating margins. Historically this has been almost a no-growth business, very stable cash flows, cash cow kind of business, but it’s starting to evolve because the gas storage has become more important to us and to others, as well as specialty products that people want to store like the naphthas and the condensates that Jim mentioned. So this business, I think, is kind of evolving into something that has historically been a very low return on capital to something now that has the potential to really grow for us. And, again, this is in the middle of our value chain, so this is important to us.

Slide 120 – Mont Belvieu Storage Outlook

So we talked about some of the things that we’re working on. I think the last bullet point on this slide is the important one. We are working on filing the request to the Railroad Commission. This will take time to make this filing and to get it through the Railroad Commission because nobody stores gas out at Mont Belvieu today. But it’s stored in all, it’s stored all around Texas. This isn’t a quantum leap. It’s just going to be new for Mont Belvieu.

Slide 121 – Octane Enhancement

Finally turning to our octane enhancement business, as we mentioned in the conference call, we earned over $20MM in this business in the second quarter. We own this facility. It’s been in MTBE service for over 10 years, and now we’ve converted it to isooctane. We completed these conversions in May 2005, and since restarting the plant we do an annual turnaround in the first quarter on this plant. And since restarting the plant in March 2006, we’ve been producing isooctane solely out of this, as well as isobutylene which is really an intermediate product that goes into the lube oil business.

Slide 122 – Isooctane

When we first looked at the economics on this plant, we really felt like California was going to be our primary market, and that was because of the value difference between CARBOB (California Reformulated Gasoline Blendstock for Oxygenate Blending) and the Gulf Coast. But we’ve actually found this year that the majority of this volume has gone into the Gulf Coast because of the impact of taking MTBE out of gasoline. So what we can do today is we can produce just a little bit over 10 MBPD. We’ve got our turnaround scheduled for January 2007. As part of that turnaround, we are going to replace a piece of equipment called a cold box. Once we replace that, our capacity, we get another 20% increase in our capacity up to 12 MBPD. So we’re very, very happy with the results of this. I think we announced last year that we spent $40MM on this, and we made $20MM on it in the second quarter.

The other important takeaway on this is that this facility also takes 20 MBPD from our isomerization business. So it’s not only a standalone facility, it is also helping the rest of the value chain when you look back at the isom business. And another key takeaway here, I think, is that we have a plant that’s similar to this plant down in Morgan’s Point, and this was a part of another acquisition that we did on some pipelines. So in essence, we got the plant for free. We can restart this plant with basically the same technology that we know how to run today. You’ve got to remember, this is only the second plant in the world like this and it’s not like boiling oil. It’s a lot more difficult to run, so we’ve got some expertise. We know how to do this, and restarting another plant down at Morgan’s Point for us looks very attractive. So we’re working hard on that.

Slide 123 – Ethanol Drives Demand for Isooctane

Now the final point. I just want to bring up some understanding because we’ve had a few questions on this, is what impact does ethanol have on this whole business for us, the isooctane business. And in essence what the regulation did, what the energy bill did, was it banned MTBE and it forced ethanol into a gasoline pool by a Renewable Fuel Standard. So what happens when you do that is you’ve got MTBE that is a very good blending component, low vapor pressure, high octane. You’re putting back in ethanol, which has good octane but very high vapor pressure, so that forces you then to strip out some of the higher vapor pressure components. In order to keep those in the pool, what you need to do is put in something like an isooctane, which has in essence, 100 octane and only 2 lbs of vapor pressure. So it’s very low.

So for us, the more ethanol that goes in the gasoline pool, the better off we are because there’s going to be much more demand for isooctane. And again, there’s only 2 plants like this in the world. Now the refiners are converting, as Jim mentioned. Valero is converting their MTBE plant down in Corpus Christi to isooctene. But the difficulty with isooctene is you can’t ship it very easily. It polymerizes so it just ends up being a big slug in a rail car unless you put in some inhibitors. So refiners in general can do specialized things in their facilities because they don’t have to move it around. But those refiners that don’t have those options are going to have to come for isooctane or alkylate, and again, that just creates significant demand when you talk about the effects of ethanol.

Slide 124 – Ethanol Renewable Fuel Standard

And this final slide just shows in essence, the ramp up of this fuel standard because what you’ll have is today, you’ve got 4 billion gallons that goes into the gasoline pool and by mandate in the energy bill, it’s going up to about 7.5 billion gallons by the time you get out to 2011 / 2012. So I mean our outlook on this business is very positive and that’s why we’re looking at expanding or restarting the plant that we have down at Morgan’s Point.

And that’s all I had. Any questions?

Questions and Answers

Q:	Thanks, Paul Sankey at Deutsche Bank. The Morgan’s Point capacity is how much, do you think, and how much of the market do you have with your current, or do you estimate the total isooctane market to be in the US?

Gil: The Morgan’s Point plant is about 9 MBPD. That was your first question, I think.

Right.

Gil: The market on this is really hard to define because what it really is is an alkyd. So you could produce alkyd, which is a slightly different process. But if you look at the shortfall today, maybe the context to look at this at is MTBE, made up about 200 MBPD of the gasoline pool. You took that out, now you’re putting ethanol back in. But the calculation’s a little bit more complicated than that because it’s an octane barrel and some of these other components that you have to strip out. So basically you’ve lost, when you calculate it, 400 MBPD of gasoline production capability because of what you’ve stripped out. When you look at the excess demand in the future, the numbers we’re looking at is an order of magnitude of about 200 MBPD of either isooctane or alkyd that’s going to be required. And so what we’re trying to do is fill just a small piece of that void. So if you assume 200 MBPD is what’s missing, we’re only putting in, even with the restart of Morgan’s Point, 20 MBPD.

Q:	And it’s worth making the point they’re probably going to double the ethanol mandate as well, aren’t they?

Gil: Fifteen by the time you, if they agree to that difference, right. So I’ll turn it over to, who’s going to do Hank’s? Oh, okay.

Michael A. Creel – Corporate Governance

You may notice that I am not Hank Bachmann. Wanted to make sure everybody knew that upfront. Hank is our Chief Legal Officer and unable to be here tonight, this afternoon, so he asked me to take this spot on corporate governance. So I’m going to give it a shot.

Slide 126 – Current EPCO Structure

This is, believe it or not, the simplified view of EPCO, the privately owned company, and the three separate MLPs that it controls. We did it in a simplified manner just to try to explain the ownership interest. You can see at the top in the middle is EPCO, Inc. That is a privately-owned company controlled by Dan Duncan and his family. Off to the left side there’s an entity that owns the general partner of TEPPCO, and as you know, TEPPCO is a publicly-traded company that will be presenting this afternoon. Off to the right side you can see that EPCO and Dan Duncan LLC own the general partner of Enterprise GP Holdings, an entity that we took public last August. Enterprise GP Holdings, in turn, owns the general partner of Enterprise Products Partners.

Slide 127 – EPCO Family Governance

So, a lot of MLPs, a lot of general partners, a lot of potential areas of conflict that we’re very aware of and take a lot of pain and effort to try to make sure that we have separate corporate identities for each of these entities. We are very sensitive to the fact that because of the three separate entities but with common control ultimately at Dan Duncan, that there is an appearance from time to time of potential conflicts of interest. We want to make sure that the unitholders, the debt holders of each of these three companies are not disadvantaged because of a common ownership up at the top. We do have a lot of provisions in place to try to ensure that.

Each of these general partners has a Board of Directors, and within those Boards of Directors, there are at least three Independent Directors, and those Independent Directors meet the independent standards by the New York Stock Exchange, as well as the SEC. Each of the general partners also has within the board, a Governance Committee, again, comprised of the three Independent Directors, and an Audit and Conflicts Committee, also comprised of those same three Independent Directors.

The Audit and Conflicts Committee is very important for the general partner because it is the one that has final say over any related-party transactions, any transactions that might give rise to a significant conflict of interest. That is really the safeguard that we look to primarily to make sure that the board is being run in a very independent fashion. There is no overlap among the three boards with respect to the Independent Directors.

We have an Administrative Services Agreement that controls a lot of activities for the partnerships. It includes, first of all, the allocation of costs. All of the employees for all three of these partnerships are employees of EPCO, the private company. None of the MLPs have any employees, other than Dixie Pipeline which is majority-owned by Enterprise Products Partners and has some employees. But for the most part, all of these employees are EPCO employees.

So the challenge becomes how do we allocate those costs? Well, the easy one is that there are certain employees that work only for one of the partnerships. And the cost of those employees are directly billed to the respective partnership. There are others of us that do work not only for one or more of the public companies, but also for the private company. And so we allocate our costs based on the time that we spend. We are working on developing a more robust system within our payroll system to track those costs and they’re billed to the respective partnerships or to the private company, based again on the time that we spend working for that particular entity. There is no markup of costs to the partnerships. They’re paid actual costs, not any kind of a markup. And what we’ve been able to do by having a common set of employees and allocating costs is that we’ve been able to streamline a lot of functions. We have one human resource department, one IT department, one accounting department, one engineering department, one operations department. Everything is on a combined basis, a shared service basis, except for our commercial activities. Those are separate. And as a result, we’ve been able to capitalize on a lot of the efficiencies that would have only been possible through a merger. We’re able to do that through a shared service and lower the G&A costs for all of the partnerships in a very effective way.

We are working to refine the Administrative Services Agreement further to make sure that we capture all these costs, that we’re able to track them prudently, and that we’re also able to somehow measure the efficiencies that we’re getting. We have retained separate Delaware counsel to help us further refine this.

Slide 128 – Non-Consolidation Objectives

Certainly one of the issues that we’ve been talking with the rating agencies about is non-consolidation opinions. That is something that is important to the debt holders. It’s becoming less of an issue now because of some recent court decisions, but it is nonetheless something that we’re very focused on. We think that the issue of substantive consolidation is, again, very remote, particularly given some recent court decisions. But we have delivered a draft of a non-consolidation opinion to the rating agencies with respect to EPCO and Enterprise to the effect that if EPCO were for any reason to declare bankruptcy, that Enterprise Products Partners could not be substantively consolidated in a bankruptcy filing. We are planning to provide one or more similar opinions with respect to non-consolidation with respect to EPD and EPE (Enterprise GP Holdings) and with respect to TEPPCO.

Michael A. Creel – Financial Overview

And with that, we’ll launch into a little bit of a financial overview.

Slide 130 – Strong 2006 Performance

Great story. We’ve had good performance year-to-date. We’ve had gross operating margin of $623MM. That’s 20% above the first six months of last year. You’ve heard some of the business guys talk about their respective businesses. Certainly the Petrochemicals segment contributed $47MM to that increase. The NGL Pipelines and Services contributed $44MM.

Businesses are doing well across the line. Gil talked about Petrochemical Services having a $25MM increase from the octane enhancement due to the start up of the isooctane facility, $14MM from propylene fractionation, and $8MM from butane isomerization. So we’re not just counting on one business or one segment; we’re doing it across the board.

NGLs, you heard Jim Collingsworth and Jim Teague talking about their businesses. Certainly the Gas Processing and Marketing has contributed a $26MM increase over the first six months of 2005, and the NGL Pipelines and Storage is up $19MM for the first six months versus last year.

Slide 131 – Strong Financial Position at June 30, 2006

We finished the second quarter of this year in pretty good financial shape as well. We had liquidity of about $700MM under our revolver. We’ve got a debt to EBITDA ratio of about 4x. What we’ve done is pro forma that for our hybrid securities transaction that we recently did. It’s a $300MM transaction that gets some equity credit from the rating agencies. Adjusting our debt to EBITDA to give effect to the equity component of the hybrid securities gets us at a debt to EBITDA of about 3.9x. It also frees up additional liquidity under our revolver, almost $1 billion of liquidity there.

A couple things to note on this slide is that our average interest rate on all of our debt is just a touch over 6%. The average maturity of our debt is 13.4 years. And the average or the total fixed debt as opposed to floating rate debt is 74%. So we’ve done a lot over the last couple of years in terming out our debt, extending maturities, taking advantage of a low interest rate environment, taking the interest rate risk out of the equation, very little floating rate debt. We think we’re in great shape going forward.

Slide 132 – History of Financial Discipline

We have been very disciplined in our financial approach. Although, I’ll show you a couple of slides that show the timing of issuing equity compared to when we’ve done some major transactions, and in a couple of cases the equity issuances have lagged the acquisitions a bit. But over the time period since our IPO in July of 1998, we’ve made $11.8 billion in capital investments and we funded 53% of that with equity. When we did the Mid-America / Seminole Pipeline acquisition in July 2002, we laid out for the rating agencies and for the markets that we planned to refinance that on a more permanent basis within 12 months. We accomplished that in 7 months, so we are 5 months ahead of schedule.

We financed 64% of the $6 billion GulfTerra merger that we closed September 2004; 64% of that was financed with equity. Quickly after we completed the GulfTerra merger, we refinanced most of the GulfTerra high coupon debt. There’s still a little drib and drab left outstanding, but by refinancing that, we were able to lower our interest expense almost $50MM per year. We also had laid out at the time that we expected some fairly significant merger synergies. We have surpassed that. We’re very pleased with the way the organizations have come together. Certainly with the shared service model that we have that includes TEPPCO now, we’ve been able to realize some additional efficiencies.

In terms of the management support, I don’t think you’ll find a management team, a sponsor of an MLP, that’s more supportive of the growth of the partnership. EPCO and its affiliates and management have invested $450MM in new equity issuances of Enterprise since our IPO. We’ve had very strong distribution coverage, 1.2x coverage of our distribution, since our IPO. And since our IPO we’ve retained $476MM of cash flow in the company for reinvestment, to pay down debt, to maintain financial flexibility. Since the GulfTerra merger at the end of the second quarter of 2004, we’ve retained $216MM of cash flow. So we’ve done a lot to make sure that we can reinvest this money in a prudent fashion, maintain financial flexibility, make it an attractive investment, not only for equity investors, but also for fixed income.

Slide 133 – History of Financial Discipline: Funding Growth with Equity

Here you can see our track record of capital investment year-by-year, compared to the equity issuances. Again, $11.8 billion of capital, $6.3 billion of equity issued to fund that growth. A couple I’ll point out. In 1999 you can see that we had capital investment of $504MM, $213MM of equity. That was equity that was issued to Shell when we acquired their midstream assets. You can see in 2002 we had capital investment of $1.7 billion. A big chunk of that was the acquisition of the Mid-America and Seminole Pipelines from Williams. You can see that we were a little late in funding that with equity. Certainly you can’t fund it all in one year, but we did an equity offering in October of that year, and we did two subsequent follow-on offerings in early 2003 to fund the rest of that. In 2004 you can see another big capital investment program. This was the merger with GulfTerra, in addition to some other capital investment and about $3.8 billion of equity. A good chunk of that was related to the merger and the exchange of EPD units for GulfTerra units. And then you can see the Cerrito acquisition that we recently completed, the $325MM acquisition that James Lytal talked about. We closed that in July of this year and that has included the issuance to the Lewis family as partial consideration, about 7 million units, $179MM of equity.

Slide 134 – History of Financial Discipline: Debt to Total Capitalization

This bar chart shows you our debt to total cap since our IPO. You can see that we started off as an IPO in 1998 fairly unlevered. In 2002 we kind of topped out at 64% debt to equity. Again, that was with the Mid-America / Seminole transaction. You can see in 2004, the year that we completed the GulfTerra merger on September 30^th, we finished the year 44% debt to cap. We’re at 44% debt to cap at the end of the second quarter this year. So again, working to make sure that we’ve got the right financial metrics.

Slide 135 – History of Financial Discipline: Managing Distributable Cash Flow

In terms of our distributions, you can see in the green, that is the amount of cash flow that we’ve paid out to our LP unitholders, about $2.4 billion since our IPO. In blue you can see the GP distributions at $242MM. And then compare that to the retained cash flow, $476MM. I think you’d be hard pressed to find an MLP that’s been around as long as Enterprise that’s retained as much cash flow in the business. And again, looking on the right side you can see what’s happened since the GulfTerra merger at the end of the third quarter of 2004. We’ve retained $150MM – I mean we’ve paid out $150MM to the general partner. We’ve retained more than that, $216MM for reinvestment. This is not a general partner that’s looking to find out how much cash he can suck out of the company. The general partner is interested in the growth and the health of the partnership, and they’ve taken a number of steps to make sure that we have a sustainable business model.

Slide 136 – Realizing Benefits of Eliminating GP’s 50% Splits

We’ve talked a lot over the last several years about the importance of eliminating that 50% split. We’ve seen one partnership after us that eliminated the 50% split. We know that there are two other partnerships that are trying to figure out how to deal with that as well. This shows you just in dollars and cents what it means to the partnership. And you can see in gold the amount that we’ve paid out to the LP unitholders every year. The blue is the amount that goes to the general partner. The piece in red is the piece that would have been paid out under the 50% split that now we’re able to retain in the partnership for reinvestment. In the second quarter of 2006 that was $17MM. That number will continue to grow as we increase distributions. For the time period since we eliminated the 50% split, that’s $67MM. This is going to be a big factor for Enterprise going forward. It’s a tremendous advantage in terms of cost of capital and we’ve got some slides that will talk about cost of capital in more detail.

Slide 138 – 10 Largest Energy Partnerships: Indicative Cost of Capital Comparison

This chart shows the distributions of the yield, if you will, on a snapshot basis. You can see Enterprise at about a 7% yield. What we’ve done in gold is show the yield on the units given a 10% increase in the distribution and assuming that the price of the units doesn’t change. So you can see the partnerships over on the right side with a 10% distribution increase, their yield goes up 0.3% to 0.4%. On the left side are partnerships that are deeper in the 50% splits. And you can see that same percent distribution increase increases their yield by somewhere in the 80 to 90 basis point range. That just continues to grow over time.

This is a study that we’ve done on cost of capital. We think that it’ll give you a better idea of how we look at MLP math. Admittedly maybe everybody doesn’t look at it the same way, maybe some people are in denial, but we think it’s a valid case study.

Slide 139 – Updated Cost of Capital Study

What we’ve done here is looked at two MLPs. We’ve looked at obviously Enterprise, and we’ve looked at what we call a generic MLP – it’s really just an unnamed MLP. We’ve not picked one that makes us in the best light, but it is one that’s in the 50% splits, kind of middle of the road, and I think it gives you a good view of the differences between Enterprise with a 25% maximum IDR and somebody that’s in the 50% splits.

We’ve run three cases. We’ve assumed in each case that the MLP is going to invest $100MM per year and they’re going to do this every year for 10 years. Now in Case A, we’re assuming that you get a 15% return on investment (ROI) on that asset and that the cash flow is going to grow 2% per year. In Case B, we’re assuming a 12.5% ROI and, again, a 2% growth. And in Case C, we’re looking at an asset that returns 10%. It’s a mature asset; there is no growth after that. Whatever you earn in year one is the same thing you earn for the remainder of the 10 years.

Now, for Cases A and B we’re funding that capital with 50% debt / 50% equity, but in Case C we’re having to fund it with 40% debt / 60% equity in order to maintain a 4x debt to EBITDA ratio, trying to maintain that investment grade ratio. The importance is that as you, as an MLP stretches and pays up for an asset with either a lower growth or a lower return, they’re going to have to fund that with more equity. So MLPs need to be prudent in how they pay for these assets. In both of these, all of these cases, we’re assuming that both partnerships increase their distribution 7.5% per year. What this will show you is that we do have an advantage at Enterprise.

What it doesn’t show you is the effect that we’ve got through our downstream assets in earning additional revenues. So if we invest in a 15% project, we very likely are going to have additional revenues generated from our downstream assets. Another way to look at it is maybe you’ve got two partnerships investing in a 12.5% return project. The generic partnership may only get to 12.5% and 2% growth. Enterprise, again, will get 12.5% on the investment, but it has a very strong likelihood of earning more because of their downstream assets.

Slide 140 – Generic Partnership: Scenarios A & B Assumptions and Resulting WACC

Now, to flip to a busy chart, this gets into the numbers, and across the top you can see the annual investment, $100MM a year. You can see, and this is only for Cases A and B, we’re just showing one set of assumptions. This is the generic partnership. So down on the left where it says EPD distribution rate or implied EPD unit price, it’s not EPD, it’s the generic MLP. But again, we’re funding the investment 50% debt / 50% equity. The distributions are growing at 50% per year. You can see that in this case the distribution that’s being paid in year one is $2.31. They’ve got a unit price of $35.85, giving you a yield of 6.44%. Across the bottom you can see the cost of capital, and this is a blended cost of capital for these investments. In year one the blended cost of capital is 7.78% and that’s 50% debt. You’ve got debt at 6.3%, half of that’s 3.15%. You’ve got a yield on your units of 6.44%, half of that is 3.36%. And then you’ve got the GP take, which in this case equates to 1.27%. So a total cost of capital in year one for that asset for the equity you issued is 7.78%.

Now you can see as you go across to the right that the cost of capital goes up. That’s a function because of the equity that you issue in year one, if you’re going to increase the distributions in year two, three, four by 7.5% a year, the cost of that equity that you issued in year one has just gone up. And if you’re in the 50% splits, the amount that you’re paying to the general partner goes up even more. The numbers kind of work out if you look at the equity you issue in year one. Again, it’s 7.78% cost of capital in year one. The cost of capital for that one year, that first year investment, rises to 13.75% for the equity component of that. So that’s the function of having a yield on the units that you issued in year one, not at 6.44%, but by year five it’s 8.96% yield on those units and the GP take is 4.79%. The cost of the equity, LP and GP in year ten gets to 21.6%. So if you’re funding 50% debt / 50% equity your cost of equity on that transaction you did in year one, by year ten the equity piece of that is 20, almost 22% and then you’ve got the debt on top of that. If you’re investing in a 10% rate of return project, it’s going to be hard to make that work.

Now the blended cost of capital, because each year you’re issuing additional units, you’ve got a different cost of capital for those units. The blended effect kind of mutes the point that in year one that initial investment is returning less than you thought it would. And so it does kind of hide the fact.

Slide 141 – EPD: Scenarios A & B Assumptions and Resulting WACC

Now for Enterprise, again, a little different set of facts. We do have the capital and the incentive distribution rate, but one thing to point out is that here we’re looking at a yield on Enterprise units of 6.88%. You will remember in the generic partnership we used 6.44%. Those were actually yields at the time we did this, but it does put Enterprise at a disadvantage if you’re trying to compare apples to apples. It sets us back about 25 basis points in return. But even with that, you can see that our cost of capital in year one is 7.23%, and by year ten on a blended basis it’s 9.4%, compared with 11.1% for the generic partnership. A lot of numbers but it’s a different way to think about it.

Slide 142 – Portfolio Cost of Capital per Year: Financed 50% Debt / 50% Equity

This shows you, again, the blended portfolio cost of capital for all of your investments. You can see that for the generic MLP, again 7.8% in year one increasing to 11.1%. For Enterprise it’s 7.2% increasing to 9.4%.

Slide 143 – Portfolio Blending Masks the High Cost of Capital for the Year 1 Investment

If you look only at the investment you made in year one, it’s a little more dramatic. Again, 7.8% percent for the generic MLP in year one, increasing to almost 14% in year ten. Now you think about that partnership investing in a 12x multiple project, they’re not going to be able to make money throughout that ten year period. At some point it’s not going to pay for itself. Enterprise on the other hand, is going from 7.2% to 11.6%. A project that we invest in with downstream economics with a little bit of growth is a whole different ballgame for us than it is for a partnership high in the 50% splits.

Slide 144 – Investment Scenario A: 15% ROI + 2% Growth: Cash Accretion to Existing Limited Partners

This will tell you the difference in a project – a 15% rate of return project, 2% growth – what the accretion is year-by-year. And you can see that it’s significantly more accretive for Enterprise because of our cost of capital. Over the entire time period we get $403MM of accretion to EPD limited partners as opposed to $331MM to the generic MLP. That’s a 22% increase in value over the generic MLP.

Slide 145 – Investment Scenario B: 12.5% ROI + 2% Growth: Cash Accretion to Existing Limited Partners

Now it becomes a little more interesting if you’re assuming it’s a 12.5% rate of return project with 2% growth. Again, significantly more accretive for Enterprise. We’re 39% more accretive to our limited partners than the generic partnership is. And, again, looking at the environment we’re in where there’s a lot of competition for acquisitions, you’ve got MLPs paying what we think are very lofty prices for mature assets.

Slide 146 – Investment Scenario C: 10% ROI No Growth: Cash Accretion to Existing Limited Partners

If you’re investing in a 10% rate of return asset with no growth, look what happens to the generic MLP because of their cost of capital that goes up every year. It’s actually dilutive to the limited partners by $35MM as opposed to Enterprise where there’s actually accretion of $50MM. That’s a 243% difference and that’s why we keep going back to the importance of several things: Having the lowest cost of capital, the lower take by the general partner, investing in organic growth projects that have higher returns, and investing in assets that bolt on to our existing asset base providing downstream economics.

Slide 148 – Capital Expenditures

Figured you didn’t have enough numbers yet, so we’re going to throw some numbers at you showing what our capital expenditures are for the next couple of years. And this shows what we’ve done for 2005 and prior. The second column is this year, 2006, and the third column is 2007 through 2010. Admittedly a lot of that is going to be in 2007. And we’ve broken it out by segment. So you can see for NGL Pipelines and Services, we’ve got about $1.2 billion in this year. And a couple of those to point out is the Meeker Cryo plant number one, $276MM; the Pioneer Cryo plant is in there; we’ve got the Hobbs Fractionator that we’ve talked about; we’ve got the Jonah project that’s in there at $111MM; and we’ve got the Piceance gathering and processing that gets started at $47MM. It’s $967MM of organic growth plus some acquisitions to get you to that $1.163 billion.

Slide 149 – Capital Expenditures (continued)

On the Onshore side of things, we’ve got about $400MM of capital to spend this year. The biggest piece of that is the Cerrito acquisition, $325MM that James Lytal talked about, funded 55% equity. You can see that we’ve got a bit more to do in 2007. We’ve got some projects expanding our gas storage and we think that that’s going to be a great business for us.

On the Offshore we’ve got $362MM in there for 2006. Most of that is around the Independence Hub and Trail project. We’ve also got another $72MM building a propylene splitter. Grand total of about $2.1 billion in 2006. Again, a significant amount of that, most of that, is organic growth projects where you’re going to have higher returns. We think it’s a great position to be in.

You can see for 2007 through 2010 it’s about $1.4 billion. Probably about $900MM to $1 billion of that, maybe a touch more, is for 2007. Frankly, we’re a little early looking at 2008, 9, 10 but there are some projects specifically around the Mid-America, the Western Growth Initiative, new cryo plants that are going to be calling on capital in those out years.

Slide 150 – Major Organic Growth Projects: Expected Investment & Timing

This is our organic growth projects, and we’ve not shown this before, but what we’ve done is we’ve taken the total capital for each of these projects and we’ve showed you the quarter where we think they’re going to go into commercial operation. And so from that you can kind of deduce what impact that might have on our earnings and cash flow. But you can see that first quarter 2007 is going to be an important quarter for us. We’ve got the Jonah joint venture that goes into service first quarter 2007. We’ve got Independence Hub and Trail that, as James mentioned, when that platform is mechanically complete, we start realizing $4.6MM a month in demand fees and when the production starts flowing we get even more. So that’s an exciting thing for us in the first quarter 2007. In the third quarter 2007, you see the Meeker cryoplant number one. You can see also the Mid-America expansion, as well as the Hobbs fractionator coming up. Out in the fourth quarter 2008, we’ve got a cryoplant at Meeker, this number two plant, as well as Piceance gathering and processing. So we’ve got things fairly spread out but you can see the first quarter 2007 we’ve got $800MM of project capital that goes into operation, another $860MM in the third quarter 2007 and $400MM in the fourth quarter 2008. That’s money that has largely been spent, just not generating any cash flow yet.

Slide 151 – Hybrid Offering Summary

We talked a little bit about our hybrid debt offering that we recently completed. We are very pleased with the way that offering went. There was a bit of choppiness in the market before we went to the market. There were a couple of deals that frankly didn’t trade as well as we would have liked, and so faced with that, we were very cautious about going into the market, making sure that we got to the right investors, that we explained our story. We explained why we were issuing this security; why we thought it made a lot of sense for them. We did not try to squeeze the last basis point out of the pricing; we did not try to jam the market with a big offering. We wanted to go in with a relatively small deal that had enough liquidity to get investors comfortable and then let the security seek its own level.

Slide 152 – Hybrid Offering Benefits

They priced at Treasuries plus 331, trading inside Treasuries plus 300 today. We had 61 investors in the deal. We had demand of over $1 billion, so three times over-subscribed. We have 22 investors in the deal that had not previously invested in Enterprise fixed income. The largest investor was about $30MM, so we had good broad distribution across that group. We think it’s good for Enterprise because it enables us to tap a new set of investors that would have liked to have invested in either a high coupon debt offering that we, as an investment grade issuer, aren’t willing to do. But it also enables people that couldn’t invest in our equity, either because of UBTI issues or because they had K-1 issues, a way for them to invest in an equity-like security. There really wasn’t much of an overlap with our common unitholders and it did reduce our reliance on the traditional equity market as the sole source of capital. We also think that it provides an additional layer for our senior unsecured debtholders in that this is essentially a very deeply subordinated piece of debt.

Slide 153 – Hybrid Offering Summary

You can see the ratings on this – it’s rated Ba1 by Moody’s, B+ by S&P, BB+ by Fitch. The B+ S&P rating is largely a function that our senior unsecured debt is rated BB+ by S&P non-investment grade, and as a result, they had to notch it three times. The equity content, as we understand it, Fitch assigned 75% equity content. S&P and Moody’s is more in the 50% range. We were the first partnership to issue a hybrid security. We’re only the fourth non-financial institution, a corporate issuer, to issue a hybrid security. We did three days of marketing. We talked to a lot of investors, not all of whom came in. We think that there were a lot of our equity investors that were participating in the one-on-one calls just to find out what the impact might be on the equity markets. Again, 3.3 times over-subscribed; we had the ability to upsize it to $500MM, but we elected not to. Again, we wanted to do an offering that was big enough to be liquid but really wait to see how it traded in the aftermarket, make sure that investors were comfortable with it. We think everybody that bought in that offering had a pleasant experience.

Slide 154 – Equity Markets Realize Benefit of Hybrid in EPD’s Capital Structure

This was something that we focused on, and last night a number of people commented to us, that after we priced the hybrid security that the unit price for Enterprise and Enterprise GP Holdings both went up. And what we’ve got here are the unit prices for Enterprise and Enterprise GP Holdings plotted against the Alerian MLP index. I told Gabe that we were going to use the index and he was happy. The Alerian MLP index is an index of large MLPs. This is really masked a little bit by the fact that Enterprise represents about 15% of the Alerian MLP index. So, but for that, you would have seen even a bigger lift.

What we think this has done is shown the hedge funds, speculators, people that were waiting for Enterprise to come back with another secondary, that there is an alternative, that we’re not going to be held hostage to one method of funding our growth and the speculative nature of people that were waiting to buy at a discount in the secondary offering. All of a sudden that overhang kind of dissipated. So it’s not that we intend to use the hybrid security exclusively in lieu of equity, traditional equity, but we do think that it is an important part of our capital funding. We think it’s got an important position there and it certainly will kind of take some of the speculation out of the marketplace with the respect to timing of any secondary offerings.

Slide 155 – Hybrid Potential in Capital Structure

This is something that we’ve taken a look at to just see how much of the hybrid security could we potentially do, what does it mean to us and, again, looking at our actual debt to cap structure. You can see our capitalization at the end of the second quarter is about $10.9 billion. Adjusting that for the Cerrito transaction, again, where we issued the 7.1 million units as well as the issuance of the hybrid security, our pro forma capitalization is about $11.3 billion as of the end of the second quarter. It shows you that we could potentially issue $920MM of additional hybrid securities based on our current cap structure, maintaining only 10% of our cap devoted to hybrid securities. Now that’s not to say – and I know we’ve got some rating agency guys in the room – we’re not planning on doing $920MM of hybrids next week. But it’s something that we can use over time to augment issuances under secondary offerings.

Slide 156 – 10 Largest Energy Partnerships: Ranked by Enterprise Value

One of the things that we think is important for investors to focus on is the size of the partnerships. Certainly there have been a number of small MLPs that have come to market. There is a perceived ability of a small MLP to grow quickly, and that may be the case but there’s also more risk attendant to that. They’ve got a smaller scope of assets; they don’t have the diversification of a larger company. You can see Enterprise here at $16 billion is currently the largest MLP ranked by Enterprise value. We’ve grown considerably. We think we’ve grown in a very reasoned method. We think we’ve got the best set of assets in the business and the best growth prospects.

Slide 157 – 10 Largest Energy Partnerships: Ranked by Average Daily Trading Volume

One of the other things to focus on, particularly on the equity side, is what is the daily trading volume? Investors want to have liquidity and we have the highest liquidity of any MLP with the daily trading volume of $14.7MM. We think, again, that’s something that investors should focus on and we think they are focused on it.

Slide 158 – Proven Growth, Superior Returns

What does all this mean for Enterprise? We’ve grown our assets since our IPO in July 1998 from $700MM of assets to over $13 billion today. It’s a 47% compounded annual growth rate (CAGR). We’ve increased our distributions from $0.90 per unit at the time of the IPO, that’s on a split adjusted basis. We expect to end the year at $1.87. That’s a 9% CAGR. The total return since our IPO has been 348%. That compares with a pipeline partnership median of 261%. And we just like throwing the S&P 500 out there to remind people that MLPs are a good investment.

And last but not least, just to show you where we rank today, looking at growth rate versus yield, we’ve got a yield of roughly 7%. The Street expects us to grow by roughly 8%. That’s a total return of 15%. We certainly think the yield ought to be lower. If you look at the MLP index, that’s more of about a 7% yield with only a 6% growth prospect. Both of those are significantly more exciting that the utility index with a 4% yield and about a 6.5 to 7% growth. And the REIT index just pales by comparison. We think that partnerships at $80 billion of market cap are undervalued today. We expect that to change over time.

Slide 159 – Financial Summary

And we certainly want to get the message out to explain why Enterprise is a superior investment, why we think we’ve got the best growth prospects, the best management team, and the best set of assets. We have done a lot, as I said, in growing the partnership to make sure that we’re funding in a financially disciplined manner. Investment grade credit ratings are important to us for a host of reasons, not the least of which is the importance to our customers and our business partners that we’ve provided our LP unitholders with distribution growth, and at the same time retaining a significant amount of cash flow for reinvestment in the business.

The general partner gave up the 50% splits in December 2002. That’s going to make a big difference to us, already seeing that in terms of the amount of cash that we’re retaining in the business. But in terms of our cost of capital going forward, it’s going to give us a tremendous leg up. And the visibility that we’ve given you to our organic growth profile, the projects that we’ve got, specifically the dollar amounts that we’re investing, when we expect those to come online, should give you an idea of our growth and distributable cash flow and our ability to continue to grow this company.

And with that I’m happy to open up to any questions. You won’t hurt my feelings. Randy?

Questions and Answers

Q:	Thanks again. The one criticism might be that you’re highly leveraged to higher oil prices and there’s an element of risk to that. Could you just address that for us? Thanks.

Mike: That we’re leveraged to higher oil prices?

Q:	Your commodity price list is relatively higher than other MLPs.

Mike: I’ll let Bob talk about that in a few minutes, but frankly, we have little commodity exposure directly. The exposure that we’ve historically had is the natural gas liquid prices and that’s a function of natural gas prices relative to crude oil. As Jim Teague mentioned before, this is a great time to be in that business, but frankly, we have reformed most of those contracts where we have very little keepwhole contract exposure. The keepwhole contracts that we have are largely discretionary. If the processing economics become unattractive, then we can bypass that gas. The exposure that we do have is to the extent that processing economics become uneconomic or unattractive; then there is an ability for processors to bypass some of that gas that you have fewer liquids coming into our downstream assets. But, again, as Jim pointed out looking at the ethylene business, ethylene producers have very little choice in their feedstocks and, as Gil mentioned, just looking at the expansion of new plants, a lot of those are light end plants that are going to require the ethane to be extracted. So that will force or better incentivize producers to extract those ethane volumes.

Q:	Mike, some other MLP yesterday issued a paid-in-kind security. I was wondering, given the long lead times for some of your organic growth projects, whether in terms of how they are streamed in paid-in-kind security, or project financing some of these projects is under consideration?

Mike: Yeah, Gabe. We’ve looked at whether it makes sense to project finance some of these longer-term transactions. Frankly the transactions that we’re looking at, building the cryoplants, expanding the Mid-America system, those really don’t have the long window that some of our other projects that are just now beginning to be completed do. But certainly if we had a multi-year project, we would look at different ways to finance it. The pay-in-kind approach might not be bad on a project discreet basis. Certainly it hasn’t worked too well on the i-Shares on a permanent basis, but it certainly would be something to look at, again, if we had a long-term construction project ahead of us.

Sir, you’ve talked about the robust demand for ethylene feedstocks and some, a little bit about the ethane versus math, the cost advantage. Could you speak a little bit about the implications for EPD in your customers, so the construction of some of these large ethylene crackers using stranded gas that are slowly coming online that force these?

Mike: Well, you know, Hank Bachmann let me play lawyer a little bit today. I’m not sure that Jim Teague and Bob are going to let me play an industry guy. So I think I’ll defer to Bob. Where’s Gil? Do you want to take that question?

Gil: Yeah, I think the easiest way to answer that is the majority of those construction projects that you’re referring to are overseas and that’s where the demand is, that the demand growth into China and some of those regions. And so the expectation is that while that’s stranded gas that’s going to produce ethylene, that ethylene is going to be absorbed in that part of the world. So it’s not really impacting the US market the way you’d think it would. It’s really all being absorbed by the demand growth that you’re seeing in the Far East.

Q:	Mike, I know this is a little bit of a tough question, but how should we look at pro forma EBITDA for some of these capex programs so that we can model increases over time?

Mike: Again, I’m going to punt to Bob and let him cover that in his closing remarks. But what we’ve tried to do is give you an idea of the amount of capital in some of these projects. We’ve talked in the past about the kinds of returns you’d expect to see from these assets on a discreet basis, looking at perhaps a regulated pipeline project in the low double digits; something with a higher risk perhaps in the Gulf of Mexico may be in the mid to higher double digits or teens. So with the capital coming in the quarters and laying over those kinds of returns, you can get a feel

for the EBITDA impact. Admittedly some of these projects are going to have a bit of a ramp up period, but there’s, the Independence Project has a lot of production pent up behind it. That’s certainly been a more robust project than we had contemplated when we had initially started it. I think the same thing that we’re seeing in the Rocky Mountains. If anything, we’ve got more ability to move product than we’re even suggesting here today. So, why don’t I just turn it over to Bob and let him address some of these.

Robert G. Phillips – Closing Remarks

Let me pick up on a couple of those questions. First, the exposure to crude oil prices. As a practical matter, the vast majority of our businesses, we get paid for our services in a fee, a monetary fee. In the processing area, though, and if you refer to slide 71 in Jim Teague's presentation, there’s a chart in there that breaks out the portion of our processing business where we get paid in-kind, in barrels in-kind. And it ranges from about 17 MBPD to a little over 20 MBPD, depending on the frac spread environment. So if you believe in a tight correlation between crude oil prices and the absolute price for NGLs sold into the market, then you could see there would be some impact on our earnings to the extent crude oil prices come down and NGL prices follow. When we take those equity barrels, we get paid for that processing service and we resell those in the market. Other than that, I don’t believe the company has any significant direct exposure to crude oil prices.

Q:	[Inaudible]

Bob: To the extent that impacts extraction economics, that would impact indirectly throughputs, but as a practical matter those of you that have followed the company, you remember just 3 or 4 years ago even when keepwhole economics were upside down, we only lose a little bit of throughput on the marginal ethane barrel. So we’re well set up for that and I think well protected for that going forward.

Let’s see, Ross, what was your...did we follow up on your question?

Q:	[Inaudible]

Bob: Right. The company has not had a history of giving a lot of detailed guidance, and I’m very comfortable with that having come from El Paso where we gave far too much detailed guidance and things didn’t work out the way you planned. I think as a practical matter though, we study our investment portfolio in a detailed fashion. We look at it from a timing standpoint; we look at the returns; we measure the base returns – that’s the outlay of the capital and what we get just from that throughput – and then we factor in the downstream economics as well. And I think for us to bring a project to Mr. Duncan for his approval, we’ve got to have all-in returns in the mid- to high-teens. And I don’t know of a single project that we have where we have committed capital with a base return of less than 10 or 11% plus another 5 to 6 to 7% downstream economic return, as that throughput works all the way through our integrated value chain. So I would be comfortable in saying, as a general rule, when we lay capital out and the visibility of this capital I think is absolutely clear, we’re showing you exactly where the projects are, when we’re going to spend it and when we expect those to be in service. If you’re working with a mid-teens all-in return on that capital outlay, I think we’re very comfortable with that. Would you say, Dan, mid-teens return?

We have so many projects, and I refer you back to the chart, to the schedule Mike just showed. I think there’s 45 or 50 individual projects. There are others that we have that are even smaller; we don’t necessarily put them on there. And then there are numerous projects in development. So let me quickly take you to find of a couple of summary takeaways here.

We’ve spent 4 hours now explaining why Enterprise is different. It’s different for a lot of reasons. We’ve got a robust and dynamic set of assets that we think are incomparable in this industry. The size and scale alone generates these organic growth opportunities. It causes us not to be dependent upon acquisitions or being a consolidator in the industry for our growth. The key question here is how do you keep growing a $16 billion partnership year after year on a sustainable basis? And the answer very clearly should be now one deal at a time. And because of the assets that we have and the management team that we have and the balance sheet that we have, we are in the sweet spot of the midstream industry. So therefore we have the highest degree of visibility on where our growth is going to come from.

Slide 161 – Major Growth Projects Overview

Now this roughly represents $5 billion worth of projects. And you go back to that schedule Mike showed you, over a 5 year outlay we are investing a lot of capital, all of it in one of two areas – organic projects that are only considered through the full downstream economics and bolt-on acquisitions that are only considered if they expand or extend the value chain. There is a financial discipline and an investment discipline there that honestly I don’t see in other partnerships. So if you’re looking at us as a competitive investment, you have to say, (a) they’ve got the largest set of opportunities, (b) they’ve got the most discipline built into their program, and (c) we’re also making investments over a long period of time. We’re not stuffing these in. We’re not in a hurry to get these done. These are simply the result of the investment opportunities that we have. The key takeaway here is over 50% of the investments are now in the NGL side of the business onshore, and you can see the clear trend over the next few years. We’re decreasing our exposure to the offshore and we’re increasing our exposure to the onshore NGL business. That’s where the opportunities are and that’s where we’re going to invest our dollars.

Slide 162 – First Half 2006 Recap

Final point, and that is we have had one heck of a first six months of this year, and don’t misunderstand how important that is. When we first met with a lot of you in January, I think it was an equity offering, we said 2006 is going to be a bridge year. We have exceeded our expectations. We’ve done better than we thought. Our assets have performed better than we expected given our forecast at the time. Record gross operating margin, record EBITDA, 30% increase compared year-over-year. This is basically the same company, same partnership that we created 2 years ago through the merger of GulfTerra, and we’re already seeing margin expansion as a result of the size and scale of the business.

We’ve had some significant accomplishments on the business development side. We’ve made some major announcements that will give you a peek into what the next few years looks like for us. We’ve been very clear and very visible about where we’re investing and why we’re investing, and I think to a large extent the returns that you ought to expect when these projects come online. We’ve made some good acquisitions. We’ve clearly shown we’ve got the ability to go into areas like the Houston metropolitan area, where we were an outsider, and go in and put a package of assets and services together where we can be competitive, and we took business away from Energy Transfer. And we stood toe-to-toe with Kinder Morgan in an area where we didn’t serve. Those are the kinds of things that we have the ability to do at Enterprise and we’re going to continue to build on those relationships with customers and suppliers and continue to be competitive in the marketplace.

Slide 163 – Summary

You guys have been a very, very patient audience and I know we’ve thrown a lot at you, but really, having not had an analyst meeting since the merger 2 years ago, we felt like that we wanted you to have a better understanding of how strong our assets are and how focused our growth strategies are. A quick summary. We think we’re the best positioned of all the midstream companies. We’ve got a very visible set of projects. We’re not concerned about where the growth’s going to come from. We’ve got $5 billion worth of projects on the list right now over about a 5 year period of time, and we’re continually developing new opportunities. Our low cost-to-capital advantage, I think Mike really nailed it for us, that’s not just creating more return, that is a competitive advantage for the business guys when they’re competing with the Williams and the Targas and the other guys who don’t enjoy the same cost of capital advantage that we do.

Long-term relationships is what Mr. Duncan has built this organization on. We would put ours up with the Exxons, the Shells, the ChevronTexacos, the BPs. We’d put our business up against anybody else out there with those relationships. We know those guys are going to be here for the long-term. We know that they give us more and more of their business every single year. It’s impressive to me that they expand their business and they ask Enterprise to go there with them in partnership to build the infrastructure. So that gives us a lot of confidence about the future.

And I think our management team is second to none in the business, and our investment in this company is going to keep us quite busy and quite focused on our success over the next 10 years. We’ll summarize with that.

Dan, would you like to make any comments before we go to final questions?

Dan: No, I would just like to thank all of you all for the patience to sit here for 4 hours, and probably a lot of you all have heard us talk about this. We have been, we’ve probably, some of our people, I know all of you, most of us know most of you, but we appreciate the opportunity of making this presentation to you. We appreciate the opportunity of you letting us tell the Enterprise story. There’s another afternoon conference that’s still part of the Enterprise story. I think the deal that Mike all of a sudden, I know that he’s a great Chief Financial Officer. He’s also President and CEO on the EPE side, but also he’s a great lawyer, too. So I think, Hank, you may have future competition and all in being a legal guy, too, because... But I know all of the Enterprise people and the TEPPCO people that will be here this afternoon and making the presentations from their point of view and long range. I think the Enterprise family of companies has a lot of great possibilities.

I think the key that we have in this, you’ve heard me say this before, is the 3 things any company has to have. It doesn’t matter if you are an Exxon all the way to the smallest mom and pop type business out there. The first thing you’ve got to have is financial support. You can not do anything in the business world today without financial support. You’ve got to have good ratings and you’ve got to be rated by the peer group, the rating agencies and people like that. Also, every company in the business has a financial people that rates outside businesses because they give a lot of credit to a lot of people. So you have rating agencies discipline to you. You have credit managers that discipline to you. You have financial people with all the companies. The other thing you have to have is good people. Without good people in the company, the deal that someone can do it all themselves, I’m not sure an inventor or an artist, that’s about the only 2 things that I can think of real quick like that you just do by yourself. Because you’ve got to have the best people that you can have in your business and I’m not saying this to get a whole bunch of people holding their hands up of ages. I’m talking about the Enterprise people. But you have to have the best people out there. If you have the best people out there, no matter what you pay those people, they’re going to make you money. They’re going to make the company money. They’re going to build that company into a bigger and better company. I don’t care what you pay a guy that’s not worth anything. He’s going to cost you money. You can’t get him cheap enough. If he worked for free he’s still going to cost you money in the long run. And the other thing you have to have is you’ve got to have a partner. If we didn’t have the major oil companies that supported us, like the Exxons, the BPs, the Chevrons, everybody out there, the Anadarkos, the smaller companies, the major independents in Canada, all those type of people, you’d have to have those three phases of business. At the same token, we’ve got to have people like you all to issue markets. We have to go out there in into the markets. All companies have to raise capital. So if everybody’s involved in raising capital we have to have the analysts. The sad part about it over the last 3 or 4 years, everybody’s limited to what you can say to analysts unless you get everybody together, which is impossible all the time and tell everybody at the same time. You cannot have one-on-one meetings with the analysts anymore or anybody and give them the information unless you file, I guess it’s an 8, 8-something you file with somebody that says, “Okay, it’s on your webcast right now.” So we’re limited to what we can say. So we’re using this type of deal to actually broaden our deal to be able to talk to you, but mainly also to be able to listen to you.

Any questions that anybody has, do not feel embarrassed about asking any question, and in my life, my personal life is my business life. So that means just open up for personal questions, too. So if you have any personal questions, other than my wife or children, I’m talking about, whether they like me or dislike me. I’m talking about the financial world of the personal business. I have no problem at all answering any type of a personal question that’s involved in the financial world or involved in the Enterprise family of companies. So we’re just, we’re open completely for questions. I know we’ve had, you’ve had a long meeting this morning. We’ve had good speakers, I’ll tell you. We have given the Enterprise story very, very great. I think we’ve given it in very good fashion, and I know Bob and Mike is kind of running the deal right now, talking and overseeing all the business measures himself. But we really do sincerely appreciate all of you all being here. So I’m going to turn it back over to you, Bob.

Bob: Time for 1 or 2 questions. Anybody? Anything we didn’t cover? Looks like we nailed it. Thanks a lot for your attendance and your patience. We’ll promise to carve it back a little bit next year, and we’ll also promise to make sure we have one maybe a little earlier in the year hopefully. I would encourage you to stay around for the afternoon. Our friends at TEPPCO have a good presentation in store for you as well. So, thanks for coming. Mike?

Mike: Just a couple of housekeeping notes. First of all, there’s one thing that I forgot to say and I promised Dan I was going to say it. It’s not like me, but we’re having a great year. Third quarter we think, based on what we’ve done already this quarter and some of the contracts Gil’s got to lock in margins for the rest of the year, that our earnings are going to be substantially higher than consensus. We do expect to get about $46MM of business interruption insurance proceeds in the third quarter which will be income. But even without that, we’re going to have a banner third quarter. So, I’ve said it.

Somebody lost a claim check and we’re happy to pillage through it to find out whose it is, but if it’s yours, come get it after the meeting. We are going to have lunch downstairs – same place we had dinner last night at Peacock Alley. But we need to go in on the right side of the room. And I do want to recognize Sheila Callaway here in the back for putting all of this together, and Pam Frederick, who’s not here – she’s holding down the fort in Houston – that was largely responsible for putting the presentation together. They’ve done a great job – couldn’t have done it without them. So with that, we’ve got lunch downstairs, Peacock Alley, and back here at 1:30 for TEPPCO.

END

Exhibit Number	Exhibit
99.1	Transcript of Enterprise Products Partners L.P. investor and analyst presentation, August 16, 2006.