Enterprise Products Partners L.P. (EPD) Q3 2007 Earnings Report, Transcript and Summary

Welcome and thank you for standing by. At this time, all participants are in a listen-only mode. [Operator Instructions]. Today's conference is recorded; if you have any objections you may disconnect at this time. Now I will turn the meeting over to Mr. Randy Burkhalter, Director of Investor Relations. Sir, you may begin.

Thank you, Marsha. Good morning and welcome everyone to the Enterprise Products Partners' conference call to discuss earnings for the third quarter. Mike Creel, Enterprise's President and CEO will lead the call, followed by Randy Fowler, the Company's Executive Vice President and Chief Financial Officer. Also with us today is Dan Duncan, our Chairman and Founder as well as the other members of our senior management team. Afterwards we will open the call up for your questions. During this call, we will make forward-looking statements within the meaning of Section 21E of the Securities and Exchange Activity of 1934, based on the beliefs of the Company as well as the assumptions made by and information currently available to Enterprise's management. Although management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Please refer to our latest filings with the Securities and Exchange Commission for a list of factors which may cause actual results to differ materially from those in the forward-looking statements made during this call. With that, I'll turn the call over to Mike.

Thanks Randy. Good morning and thanks for joining us on the call today. Our businesses had strong operating results this quarter with our integrated network of pipelines transporting a record 7.9 BTUs per day of natural gas and 1.8 million barrels per day of NGLs, petrochemicals and crude oil. It is difficult to compare this quarter to the third quarter of last year, when records were set for just about every financial measure and operating measure. However, excluding recoveries from business interruption insurance and the unusual items for both periods, this quarter compares favorably with the third quarter of 2006. We had a nice run of record quarterly results dating back to the third quarter of last year and while we didn't set record this quarter, each of our segments turned in a strong operating performance, driven by a resilient economy and robust demand for energy. We reported net income of $118 or $0.20 per unit for the third quarter this year, compared to net income of $208 million or $0.43 per unit for the third quarter of last year. Net income this quarter was adversely impacted by about $21 million or $0.05 per unit and Randy will discuss those factors or more detail in a few minutes. Our recently completed projects are beginning to generate additional cash flow for our partnership; projects such as the Independence Hub and Trail which earned $19 million of gross operating margin in the third quarter or about 125 million cubic feet per day of throughput. As we work through the startup phase on these and other projects, our earnings and cash flow should increase significantly. Now I would like to update you on the status of some of our major capital projects. The Independence Hub platform, our largest project to-date began receiving first flows of natural gas in July and is currently receiving 640 million cubic feet a day of natural gas from 10 wells. With 15 wells initially scheduled to tie into the platform this year, we're well on our way to approaching full capacity of Bcf per day by year end as the producers have expected. The October Gulf of Mexico lease sale 205 drew $2.9 billion in high bids and has been called the most competitive sales since 1983. In this lease sale, producers acquired rights to explore 80 blocks within a 50 mile radius of the Independence platform. This reinforces the future value of the platform to producers as they continue to develop these new offshore areas. We've also dedicated about $1.9 billion of gross capital on the Rocky Mountain region to expand our integrated value chain and to provide value-added services for our customers. Earlier this month, we announced the completion of the first phase of our Meeker gas processing complex in Colorado's Piceance basin. With an inlet capacity of 750 million cubic feet a day of natural gas, this plant is capable of extracting up to 35,000 barrels per day of natural gas liquids. We are still in the start up phase with Meeker plant. It's been earning mostly in Dupont recovery mode since the start up as we work through some mechanical issues with the trading system. But we currently expect to be back up in cryo mode by tomorrow night. The plant has had throughput of about 430 million cubic feet a day of gas and as alluded, about 25,000 barrels a day of liquid in cryo mode. As an example of its earnings power, had the Meeker facility been up in cryo mode for the full month of September, it would have generated about $30 million in gross operating margins for the month. In order to meet expected demand for natural gas process and services by producers, we are well underway on phase II with the Meeker processing complex, which is expected to be completed in the third quarter of next year. Phase II will double the processing capacity at Meeker to 1.5 Bcf a day of natural gas, and extraction of 70,000 barrels per day of natural gas liquid. This processing capacity escorted by long-term commitments from producers including EnCana and ExxonMobil. The Piceance basin where Meeker complex is located is one of the most prolific natural gas producing areas in the country, with production growing at an annualized rate of about 25% over the past five years. And with current production exceeding 1.2 Bcf a day, it's on a pace to continue that growth this year. ExxonMobil has stated publicly that their largest onshore drilling program is slated for the Piceance basin, with interest in 300,000 acres and ultimate recovery of up to 35 Tcf of natural gas. In total, the Piceance basin is estimated to have potential natural gas reserves of approximately 45 Tcf, surpassing the Barnett Shale as the largest future onshore gas play. Our Meeker complex will complement other rock completed projects as part of our Rocky Mountain growth initiative, including the 50,000 barrel per day of our Mid American pipeline and the Hobb NGL fractionator. The Hobb NGL fractionator has been in service since August fractionating at an average of 40,000 to 50,000 barrels per day and as much as 70,000 barrels per day. Of course this was without any NGLs from the Meeker processing plant. With the recent start up of Meeker, this facility is expected to be offering nearest design capacity of 75,000 barrels per day this quarter, providing customers with additional options for accessing the most attractive markets. Before the Hobbs fractionator was built, shippers on our Mid America Pipeline could only transport their mixed NGLs to Mont Belvieu to be fractionated. Our Hobbs fractionator provides the flexibility of ship purity products from Hobbs to Kansas [ph] to an ethylene facility in Orgasa [ph] area to a local refinery as well as to propane markets in the West Texas and Mexico. We also completed a 50,000 barrel per day expansion of our Mid America pipeline systems, increasing the capacity at the Rocky Mountain segment of that pipeline by 22% to 275,000 barrels per day, thus enabling the system to accommodate increased volumes of the NGLs that would be extracted at Meeker and at Pioneer. The Jonah Gathering System averaged 1.7 Bcf per day of natural gas gathering in the third quarter and that compares with 1.3 Bcf per day in the third quarter of last year. We expect production to continue to grow as producers drill more wells in the Jonah/Pinedale area. To accommodate this expected growth in production, we are adding 102,000 horsepower of compression which will increase the gathering capacity of Jonah from 2 Bcf a day up to 2.3 Bcf a day. This final portion of the Phase V expansion program for Jonah is expected to be completed during the first quarter of next year. Construction of about Pioneer cryogenic gas processing plant in the Jonah/Pinedale area southwest Wyoming is progressing and is expected to be completed by the end of the year. The state-of-the-art facility is designed to process up to 750 million cubic feet a day of natural gas and extract after 30,000 barrels per day of natural gas liquids. It has natural gas connections with Current River, Northwest Pipeline, Hawaii Interstate Gas and Rockies Express pipeline. We're currently conditioning about 525 million cubic feet a day of natural gas to the silica gel plants we own at this location. So when the Pioneer plant begins operations, it will start off at a relatively high level of throughput. We are strengthening our energy value change in the Rockies with project that have already begun operations or soon will, starting with the Jonah gathering system and the Pioneer processing plants in Wyoming, the Meeker complex and the White River Hub in Colorado and the expansion of the Mid America Pipeline that extends all the way down to the new Hobbs fractionator in New Mexico. In August, we announced the installation of our fourth propylene fractionator at Mont Belvieu, which increased our capacity to produce polymer grade propylene by 26%, going from 3.8 billion pounds per year to 4.8 billion pounds per year. Mont Belvieu now accounts for approximately 19% of the domestic polymer grade propylene manufacturing capacity in the U.S. Construction continues on our Sherman Extension pipeline in the Barnett Shale region. This 178 mile 36 inch pipeline segment will connect our Enterprise Texas pipeline from Morgan Mill, Texas which is southwest of Fort Worth to Boardwalk's Gulf Crossing pipeline near Sherman, Texas. Combination of our Sherman pipeline and capacity that we have on the Gulf Crossing pipeline will provide producers with multiple market outlets for up to 1.1 Bcf per day of their production originating from the Barnett, Bossier [ph] and East Texas. Gulf Crossing will cross 14 interstate pipelines that serves the northeast, southeast and Midwest markets. This extension is on track to be completed in the fourth quarter of 2008. Demand continues to grow for natural gas storage, especially in and around the Gulf Coast. Currently, we have 27 Bcf of natural gas storage capacity in Petal and Hattiesburg Mississippi, and Napoleonville, Louisiana, Mont Belvieu, Texas and at Wilson Storage, south of Houston. With planned additions, we expect to have approximately 67 Bcf of capacity by the end of 2012. At Mont Belvieu, we are developing four caverns in two phases. Phase 1 is a 5 Bcf cavern that is fully contracted and we expect that to go into service in the Spring of 2010. Phase 2 of the expansion will be an additional 15 Bcf of storage capacity from 3 caverns and the first of these 3 caverns expected to be in service in the spring of 2011 with the remaining two becoming operational in spring and fall of 2012. We're also looking forward to the Wilson natural gas storage facility which is located south of Houston returning to full commercial service. Of the 3 storage wells at the facility that we're taking out of service in the second quarter of 2006 for repairs, one well has resumed limited operation this month and remaining two storage wells are expected to resume limited operations later in the fourth quarter. We expect all three of these facilities to return to full commercial service in time for the injection season that begins in the second quarter of 2008. We recently added 1.6 Bcf of storage capacity at our Petal facility; bringing the total capacity up to 13.5 billion cubic feet. This capacity is now fully subscribed. We are now developing a new 5 Bcf cavern and expect to place that into service in the second quarter of 2008. Of that 5 Bcf, 3.2 Bcf is committed for an average of 7.5 years and the remaining 1.8 Bcf is there to be marketed. We're also developing additional caverns and expect firm contracts for another 10 Bcf of capacity as a result of the non-binding open season that was held recently. We mentioned in the press release this morning that our NGL import volumes, principally propane were significantly lower than in previous years and lower than our internal expectations. Strong demand of NGLs in the European markets have led to more cargos being diverted there in the second and third quarter of this year rather than coming to the U.S. markets. That reduces our spot market opportunities and leaves us primarily with only contract volumes. Volumes for our import terminal and the related channel pipeline system were approximately 260,000 barrels per day less than the third quarter of last year and 183,000 barrels per day less than the third quarter of 2005. This diversion of propane cargoes to international markets coupled with the strong demand for propane by the petrochemical industry has resulted in U.S. propane inventories of 60 million barrels, which is about 16% lower than last year. Petrochemical demand for ethane and propane remains very strong. In the third quarter prior to Hurricane Alberto in September, the ethylene steam crackers were operating at 90% of capacity. The gas to crude oil price ration has consistently been 45% to 50% compared to a 5-year average of nearly 70%. As currently, ethane and propane have been the preferred feedstock for ethylene producers rather than Naphtha which has been relatively expensive due to the price of crude oil. Prior to the hurricane, ethylene producers have been consuming about 800,000 barrels per day of ethane and about 385,000 barrels per day of propane. In September, 8 crackers were down, at least three were related to hurricane that made landfall in the [indiscernible] area. As a result, September ethylene cracker operating rates declined to 84% and ethane demand decreased somewhat to 740,000 barrels per day, so we have seen estimates for our October rate to rebound to 87% and for ethane demand they come back close to 800,000 barrels per day. With the combination of favorable gas to crude ratio, strong petrochemical demand and a low level of propane inventories, [indiscernible] ethane and propane natural gas processing spreads are at historically high levels of approximately $0.55 and $0.80 per gallon respectively. All the more reason we are anxious to get the Meeker and Pioneer processing plants completed, out of the start up phase and at high operating rates. Adjusting to our offshore activity recent statements by a major producer in the Gulf of Mexico were very encouraging. BHP said its giant Atlantis project is on track to produce 15,000 to 20,000 barrels of day of oil from 7 wells by the end of this year and they expect it to ramp up to peak capacity of 200,000 barrels per day by mid 2008. This production will flow through our Cameron Highway Oil Pipeline to onshore markets. Gas production from Atlantis is expected to peak at 180 million cubic feet a day by the end of this year or early 2008. This gas will be transported through our Manta Ray and Nautilus Pipeline to our Neptune gas processing plant. BHP also stated that their Genghis Khan project, which started producing crude oil this month, will eventfully ramp up to 55,000 barrels per day of production. This oil will flow across our Marco Polo platform and then either through our Cameron Highway Pipeline or through our Poseidon pipeline. BHP indicated that their Neptune platform is expected to reach 50,000 barrels per day of crude oil and 50 million cubic feet a day of natural gas production during the first quarter of 2008. The oil from this platform will also flow through out Cameron Highway Pipeline or through our Presiding pipeline and the gas will be delivered onshore through our Nautilus Manta Ray pipeline and processed at our Neptune plant. We are excited about these developments and how they will benefit our offshore and onshore integrated value chains. The outlook for Enterprise is very promising and is supported by strong fundamentals, increased volume of hydrocarbons into our pipelines in downstream facilities and a significant amount of organic growth projects coming online. These developments will serve as a foundation to increase gross operating margin and provide new sources of cash for the partnership. And with that, I will turn it over to Randy.

Okay, thanks Mike. Good morning. Enterprises' solid operating performance was somewhat hidden with the difference in the recoveries under business interruption insurance, by our being transitional start of phase for a number of our growth capital projects and also against some very difficult comparison to our record quarter in the third quarter 2006. Items of note, natural gas transported via our pipelines was a record at 7.9 trillion BTUs. Our NGL fractionators had record volumes of 371,000 barrels a day and our 1.8 million barrels of NGL, petrochemical and crude oil transported was about 134,000 barrels a day less than our record volumes in the third quarter of 2006. But this was really explained by the 260,000 barrel per day decrease in import activity. Gross operating margin in this quarter was $364 million compared to $400 million in the third quarter of 2006. Again when taking into account the $48 million difference in business interruption insurance recoveries and the unusual items in the third quarter of 2007 including the start up expenses and the write-off of some conversion costs in Petal, Mississippi where we were looking to convert a natural gas liquid storage cavern to natural gas service. We made the determination that the cavern was not going to be suitable for natural gas service so we had between $2 million and $3 million worth of costs associated without that, that we did write-off here in the quarter. So when you adjust for all that, we actually had third quarter 2007 goes up pretty margin was the ahead of third quarter 2006. In terms of distributable cash flow, we had $223 million during the third quarter of '07 compared to $302 million in the third quarters of '06. Again, the biggest difference there been 48 million delta in the recoveries under business interruption insurance. This provided 0.9 times coverage of our cash distributions that we paid to our limited partners or will pay to our limited partners here in it beginning of November. For the nine months, September 30 2007 distributable cash flow was $739 million, which compares the $738 million for the first nine months of 2006. And this has provided a one coverage for distribution declared with respective for the first nine months. Of note, the Board of Directors of general... our general partner did declared an increase in the cash distribution rate to $0.49 per common unit. This is the annualized rate of the $1.96 and is about 6.5% greater than the distribution that we paid out in the third quarter of 2006. I think the press release came in and provided fairly comprehensive analysis of the changes in gross operating margin by segments. So now I would like turn to the income statement. Our G&A for the third quarter 2007 was $18.7 million compared to $15.8 million in the third quarter of last year, if you would, an increase of about $3 million. Employee expenses were up about $1.2 million; legal fees were up about $1.3 million. Item of note there, about $1 million of that is with respect to a legal settlement, so if you would, non-reoccurring, with the reminder is really legal fees around the Mid America rate case. Finally, 1 million of this increase represents the non-cash amortization of an employee compensation plan that EPCO Inc. actually bears the entire economical liability associated with that plan, so EPD has no cash cost with respect to that plan. On interest expense for the third quarter, interest expense was $85 million compared to $63 million in the third quarter 2006. This $22 million increase reflects interest on a higher average debt balance. Average debt balance in the third quarter of 2007 more $6.6 billion compared to $5 billion in the third quarter of 2006. Now the increase in debt was used primarily to fund our capital investment program and also one important item to note of this $1.6 billion increase in average of debt, $913 million of it is attributable to our junior subordinated or as we refer to it, our hybrid notes. Of which we received on average 58% equity credit from Moody's S&P and Fitch. Our quarterly interest expense on the $1.25 billion in hybrid that we have outstanding is about $24 million after taking into account the hybrids that we issue at a premium. And so if you would apply in the 58% equity credit to that $24 million about $14 million of our interest expense quarterly is really attributable to the equity component of our hybrid securities and I think as you guys come and evaluate the other MLPs in the sector, this is going to be pretty unusual for Enterprise that we are actually bearing the cost of equity capital or piece of our cost of equity capital on our income statement, which again there are only well now, two other MLPs that we are actually doing that. During the third quarter, we issued $800 million of 6.3% 10-year notes that we'll do in September 15th 2017, the proceeds were essentially to pre-fund a retirement of our $500 million of 4% notes that matured on October 15th of this year. And the remainder went in to reduce the debt balance on our revolver. Capital expenditures for the third quarter 2007 were approximately $528 million and that for the growth capital projects. $47 million was for sustaining CapEx. To-date, we have invested approximately $1.6 billion for growth capital projects and $120 million for sustaining capital expenditures. At September 30, we had a total debt balance of approximately $6.8 billion including 100% of our hybrid securities and also that includes the $215 million of debt that gets consolidated up with Duncan Energy partners. Of note, we don't... EPD does not bear the payment obligation for the Duncan energy debt. We have liquidity... EPD had liquidity of approximately $ 1.2 billion as of September 30 which is capacity available under our credit facility and unrestricted cash. $500 million of this liquidity was utilized on October 15 to retire the 4% notes that were maturing. Our floating rate, interest rate exposure was approximately 20% of our total debt outstanding at September 30. And after giving pro forma effect to the retirement of the 4% notes, the average life of our debt is approximately 19 years and the average cost of our debt is 6.3%, which again fully reflects 100% of the hybrid dense securities. Coming in and looking at our leverage ratio at September 30, looking at our debt balance to the last 12 months of EBITDA at September 30 and if you would go on and consolidating EPD and Duncan energy partners. This ratio was approximately 4.5 times and this is also after adjusting for the 58% equity credit of the hybrid notes and also we are adjusting for the equity earnings in cash distribution that we were seeing among consolidated affiliates. This is higher than our target range; our target range is between 3.5 and 4 times. We believe as these new projects ramp up both in terms of volumes and cash flow we expect that our debt to EBITDA ratio will return back to the normal range in 2008. Before I close the call I like to briefly make a few comments Duncan Energy Partners, which also reported third quarter earnings this morning. As you know, DEP is partially owned subsidiary of Enterprise that is consolidated. The reported net income was $4.5 million for the third quarter or $0.22 per unit on a fully diluted basis. And really coming in and taking a real quick look or comments on DEP, they did have very strong operating results from principally the South Texas NGL pipeline and also solid results from the NGL storage facility. Phase 2 of the expansion of South Texas NGL pipeline is progressing on schedule and should be completed here in the fourth quarter. Attributable cash flow for DEP was $8.7 million for the third quarter 2007, which provided one-times coverage of the quarterly distribution. The Board of Directors of the General Partner DEP did declare a distribution of $0.41 per common unit or $1.64 on an annualized basis. This is an increase from the $1.60 annualized rate that we went public with back earlier this year. The partnership expects to continue to grow its commercial business through acquisition and organic growth projects and we believe this will lead to new sources of cash flow that should support future distribution increases. Now with that I think its time to go ahead and open up the call for question.

Marsha, I think we are ready to take questions now. Question And Answer

Thank you. We will now begin the question-and-answer session. [Operator Instructions]. Our first question comes from Mr. Darren Horowitz of Raymond James. You may ask your question.

Good morning guys. My first question has to do Randy, with what you said a little bit about the NGL mines fractionation, based on what's going on with cargo deferral over to Europe and looking at your volumes as they reported this quarter end and what's your experience in currently. What's your expectation for that to improve hopefully into the fourth quarter and into the early parts of 2008.

Jim... I will let Jim Teague, Executive VP that runs our NGL business to respond to that. A.J. ("Jim") Teague - Executive Vice President: The question was, what was import volumes?

Yes

As far as I guess with the import volumes being diverted over to Europe, do you see... what you're seeing there, do you see any relief over there. A.J. ("Jim") Teague - Executive Vice President: No, no you know if you look at what's going on in the rest of the world you've got naphtha prices. We saw in northwest Europe at a record level of $720 a ton within the last couple of weeks, which suggest that those guys are going to crack in the LPG that can lay their hands on. So that's what we are seeing being diverted. I will hasten to add, we are not seeing any of our contractors to move us back from their contracts because the expectation is still with new production coming on in the Middle East that we will see import volumes and these guys continue to sign up the contracts with minimum obligations. The other side of that is whenever we've had, with this slow down in imported volumes its created a pretty tight U.S. marketplace and is probably one of the reasons that we see frac spreads up north of $0.60 a gallon on the Bermuda Henry Hub basis, so you can look at the import issue in isolation and say, what's going to happen, there is some knife cuts both ways.

Okay so could you also take and imply that to Duncan as the reason why you the NGL petrochemical storage down about 40 % frequently, is that pretty much the same thing?

NGL storage was --

Is it due to lower NGL impact activity here?

Yes, I think the stores facility I mean if you look at it in total, it's... the import, the reduced import is a contributor to it, its not the only thing, but it is a contribute to that decline. We just got lower volumes in general in storage throughout the month and throughout the country right now. I mean it goes back to what Randy said earlier about the lower propane inventories, I mean all of that has an effect in terms of just reducing overall profitability on that storage facility.

Okay. A.J. ("Jim") Teague - Executive Vice President: This is Jim Teague again. The other thing is you've got that chemicals running at pretty high rates and with ethane, profane, normal butane being the preferred feedstocks, relative to condensates and naphtha they are pulling a heck a lot more than you would typically see them pull, consequently less they are holding less in storage.

And this has been... let me add a little bit of color to TEPPCO deal. The storage revenue at Mont Belvieu has always been this way. We have what we call base storage out there which is up this year over any prior year. So our base storage and what we call our tanker base storage is there. What happens they get a one throughput deal to that storage, what's happened on the NGL and import markets that's what we call extra throughput. So every time a barrel moves to the storage, I think we get like $0.10 barrel. The difference between this year's third quarter revenue and the third quarter revenue of '06 and '05 was that we had large volume coming in through the imports and in effect I think this time last year, we probably had over 800 million gallons or 800 million barrels that we were holding still with TEPPCO deal. So it's a throughput deal not the base storage that vision is down.

Okay, that's helpful, I appreciate it. And my final question is really one on a housekeeping note. When you are looking at the high depreciation that you experienced in the quarter, what should we use as a run rate for 2008 with lot of these new projects online? And the second part of the question is with that being said what does that mean for your maintenance CapEx lines sequentially over the course of next year?

Well, I think in terms of depreciation we don't have a real good number for you to use in 2008. But third quarter includes a couple of new assets, it includes Independence and Trial. It also includes the Hobbs fractionator and our now PB splitter at Mont Belvieu. The only other significant asset going in service this quarter would be Pioneer.

So we probably shouldn't be to much of a variance relative to what you reported this quarter then in D&A?

I'm sorry.

We would have... Hobbs will be the only incremental project that hits the D&A line this quarter crack.

The Meeker plant was in there for a part of the and in the third we've got a few thousand dollars, but you will see a full quarter of Meeker as well.

Okay. And then may be an initial shot at what you think does for maintenance CapEx in the next year?

I think we've put here that we think our run rate for sustaining capital for this year was approximately $160 million. I thing we are still comfortable with that number. Right now what sort of putting together where our sustaining cap is for next year. But I don't really at this point of time see it exceeding that number. In fact if anything, it might be a little bit lower.

Okay, thanks guys I appreciate it.

Our next question comes from Mr. Sam Arnold of Credit Suisse. You may ask your question.

Hi guys, I guess the first question would be in the octane enhancement in the petrochemical services, it looks like that was kind of down from prior quarters and it looks like typically you know third quarter has been one of the strongest quarters that you typically have in this segment. I was wondering is this attributable to kind of a flood of competition from ethanol or, can you give us a little more color on that.

Yes, Sam, this is Gil Radtke. The real reason that that is down compared to last year is that you've got a spread between normal and gasoline has really compressed. The normal butane prices itself with crude and the finished product that we sell out of there is priced against RBOB. So what happened here over the last quarters is we had a big compression in the crack spreads that the refiners have enjoyed, so that's really what happened there. We are seeing plenty of demand for the product, it's just that the value between crude and gasoline has compressed. So I mean going forward, you can look at the fundamentals and you can see that we're still well below where we normally have been on gasoline inventories, so I think seasonally we're kind of where we think we should be, or where we expect to be this time of the year. But I think going forward and looking in 2008, we are going to see a better gasoline season next year.

Hey Sam, this is Mike. As I mentioned before it's difficult to compare the third quarter this year with the third quarter of last year a bit...

. But even going to the last several years beyond that?

No, I understand. But remember in isooctane, the second quarter last year was very strong and we hedged those margins through the end of last year and so we've got a caught a peek in terms of the Isooctane margins to lock in and that's what you are comparing the third quarter this year again.

Sure. Okay, so my understanding would be I mean Octane enhancement is just obviously something you are doing to add to the gasoline to bring up the octane. Some... I am having a little bit of trouble understanding how that's exactly tied to the frac spread. Because it should be an independent supply demand phenomenon correct and only competing with other octane enhancement?

well I think one thing that you got to consider is that we use butane as a feedstock for that, so that contributes to the margins.

I see, Okay, so its really just a perhaps the NGL prices being booed by the crude oil price. So it's a separate market but because your feedstock has increased that's the real reason. Correct?

Correct. The field stock has increased relative to the value of gasoline.

Got you. Okay and the field stock primarily getting broader because it's more like propane and because...

It follows crude oil.

Yes, and it has been brought up by crude oils well as the correlation. Okay, that makes lot of sense. And, if I could ask just one more, you guys stated that you had some better margins with the crude oil transportation and were able to re-negotiate some tariffs and you expect that tariff to be always sustainable, kind of what you saw on the quarter going forward and then can you talk about, you talked about a couple of projects with [indiscernible], how is that going to offset, kind of your natural decline rate in those production going forward?

Its the same, I guess, we're the question that you had on crude oil and tariffs, if you could embellish on that, a little confused on that one?

Okay.On the off shore pipe lines and services, you had page 3 number B says, you had $5 million from higher revenues from high and offshore as a result of new tariff that went into effect in March 2007.

Yes Sam, that's a gas pipeline.

Okay. Highland Offshore.

Bit of a rate increase there.

Okay I see, all right. My mistake and then I guess following that would be kind of what's your natural decline on the gas and crude oil lines?

Sam, this is Dan Duncan. Let me answer the other on the crude oil. Our crude oil pipelines, the capacity of the [indiscernible] Cameron Highway, that was designed with the liners and Genghis Khan and Marco Polo, all 11 being there. None of those fields have come on stream yet. Yet I think the BP Atlantis deal and also the BHP Australian company, the deal went in fourth quarter beginning to be ramped up on the deal. So those two pipeline today is running about 200,000 barrels a day each, we all know approximately 35% to 50% of those two pipelines. The actual capacity of those two pipelines is about 600,000 a day. That's because the product itself hadn't came on there is no decrease in the volume of that were finally moved to it its never come out to start with, so there is not a decline on the crude oil side.

Right. Okay, so you'll have that ramp up and then you will start the national decline so we just --.

Let me add to that, we mentioned several field names and certainly Genghis Khan will benefit, the Marco Polo platform in our gathering line it goes up to tie into Cameron Highway and Poseidon, so we have a very good value chain with that. With Cameron Highway and Poseidon, Cameron highway with some additional pumps can do 600,000 barrels a day, Poseidon, with some additional pumps can do 400, so combined they are moving around 200,000 barrels a day right now, but you've got 800,000 barrels a day of additional capacity, and a lot of that was designed in with knowing that Atlantis and Atlantis has been late coming on, but we still believe it's a very strong field. Atlantis is dedicated to Cameron highway. On top of Atlantis Genghis Khan, we mentioned Neptune. That is coming on either late this year early 2008 and that access is Cameron highway as well as Poseidon and then in late 2008 early 2009 we are building a major gathering for the Shenzi field, which is 100,000 barrel a day field. That is going to come on at that time period and our gathering line is going to connect to Poseidon and Cameron Highway, so that's revenue to not only the gathering line but to our downstream oil pipeline. On top of that there is numerous discoveries out in that corridor and then if you look at the leasing activity and what people paid for blocks in the last lease sale not only in that Green Canyon area, but if you move a little bit west of there, kind of in the western central Gulf there is a major BP discovery called Kaskida. There was a tremendous amount on new leasing over in that area and the way our oil pipelines way out they hug the shale from northern east west before they turn up to the market, so we're not only well positioned for what's going in Green Canyon, but also this future activity a little bit to the west of that area. So taking what's going on in the oil side northern central and then Mike mentioned the leasing around Independence Hub, which we believe is the major gas area. We think we are well positioned for the gas growth in the Eastern Gulf as well as the oil growth in the Central and west Central Gulf.

Okay, great, thank you

Our next question comes from Mr. Yves Siegel of Wachovia. You may ask your question.

Thanks, good morning.

Good morning Yves.

Can you just elaborate, James on those comments, at what of time do you need to start thinking about incremental growth CapEx offshore and so the flip side is that as when you think of the incremental 800,000 of capacity on Poseidon and Cameron highway. It sounds like within a couple of years that might get fully utilized. How should we think about incremental cash flow that you could see without necessarily having to invest any incremental capital?

Well, Yves, let me say one thing, a lot of the pumps are already in on Cameron Highway in anticipation of Atlantis ramping up, we are probably a little bit ahead of the curve just because it's a little late. The incremental capital for both Poseidon and Cameron highway to get to the levels I talked about is very small because we already we own the platforms where we are going to put the pumps, we have the space available, lot of the piping is already been done in anticipation of it, so its just a matter of adding a little bit of pumps, so it's a very small number.

I think he is trying to give a sense for the potential additional gross operating margin without --

Let me give you a feel on 100,000 barrels a day on Cameron highway you are looking at $17 million to $18 million a year of additional gross operating margin in round numbers.

You have built it in, that value in that BP and the two bigger ones, BP coming on and BPH and Exxon on those fields, this is like James said, each one is 100,000 barrels a day is net to about $80 million a year. That's the kind of price is ownership out there. So in theory, if we can get up to what they have announced is around 500,000 barrels a day increase that's about $60 million of revenue on top of what we're doing like now.

Without spending very little additional capital because we are there.

Okay. That's great. But then when you think about growth CapEx next year and beyond in what you've announced already, where do you think the opportunity is for incremental growth CapEx and do you think the Gulf of Mexico is there opportunity as well in the Gulf of Mexico or would you be thinking more the Rockies and where you are today?

Yes Yves, I think the answer is yes. We're looking at all of those areas and we're frankly looking at some priced exit, we happen to announce, maybe premature to talk about now, but suffice to say that we got some pretty exciting prospects, both onshore and offshore, perhaps a little weighed a little more heavily onshore.

Okay any terms of timing?

You know we've already got projects in our capital budgets for next year that are quite in the $1.2 billion to $1.4 billion range and we haven't even finished this year yet so next year is looking pretty robust. In terms of announcing any other growth projects, we're probably still 3 to 6 months out.

I know I am pushing it Sharon Lui has a couple of questions on Duncan, but before I turn it over to her, could you just also, what would you think the time lag is on $1.2 billion of investments next year before you start recognizing cash flow?

Those, we don't have a big project in that number like an Independence Hub that takes 3 years to build, so a lot of these projects are going to be finishing up projects like Meeker 2 for example, and that's already well underway. The Sherman Extension is another one, so a lot of these are finishing projects that we've already done. These project by and large are smaller in scope than an Independence type of project, so you're looking at probably on average maybe 9 to 12 months.

That's great, thanks guys and here is Sharon.

Hey, good morning.

One correct and one mistake I made. The ramp up of crude oil going in to Poseidon and into Cameron Highway is $90 million annualized, not 60 I gave that one.

Okay, thanks. I guess on the Duncan side, if you could may be give some color on the higher OpEx cost, it looks like you guys are incurring its higher integrity cost for both the natural gas pipeline and the NGL storage segment?

Yes I guess from the context of the pipeline integrity cost, primarily at Acadian, those are related to what we have to do associated with regs in Louisiana and those are really, we accelerated some projects from the first quarter of 2008 into 2007 because we have to. So, when we look at that, its money we knew we're going to spend anyway, we just had to accelerate it and so that's why our expectation is that going forward, those operating cost levels will be lower than where they are today and really the same thing, its not pipeline integrity out of the storage facility but its just a maintenance capital that we decided that we need to do now and not wait and do when it was, some of that was also scheduled in 2008, its just it's the prudent thing to do. So, again we don't see that, those high rates continuing, it's just we're getting the work done now.

But is it fair to say that, it will be at the similar rate for the fourth quarter?

There is a good chance of that. Yes, it again comes down to timing and getting everything done but yes, I think that's a fair assessment.

Okay and I guess, if you guys have an update on potential drop down for Duncan in terms of timing?

We don't have anything to really talk about right now. When we did the IPO back in February, obviously we said that Enterprise would not have formed Duncan Energy Partners, it was only for a one-time transaction. We've certainly had discussions internally about what might make sense for both partnerships but again it's a real premature to talk about it.

Okay, thank you.

our next question comes from Mr. Ross Payne, Wachovia Capital Markets. You may ask your question.

How are you doing guys?

Hey Ross.

First question, Independence Hub, it did 124 for the quarter, the 640, is that where it is today or your expectations for the average throughput in Q4 and on top of that if you can throw out any kind of thoughts on EBITDA contribution from the ramp up sequentially there because it is petty significant.

Yes Ross. The Independence Hub and Trail, as we talked about before, we've got $44 million a year demand charge on the platform and the addition to gross operating margin for the Hub and pipeline is about $17 million for every 100 million cubic feet. We are at 640 today, producers have indicated that they might even get closer to that Bcf a day by early December. So you can do some math to figure out what that means in terms of additional cash flow. But it's a much faster ramp up in production than we had counter played when we honestly sanctioned the project and even much higher than we had thought six months ago.

Great, great. Also Mike, can you comment on what you thing start up cost might have been at Meeker and some of these other plants, just you know forget that there is going to be substantial increases in cash flow here. But what kind of cost much you be incurring in this quarter with all the ramps up that are ongoing?

Yeah, it's difficult to say. In the third quarter, we had between $2 million and $3 million of start up cost there. Frankly, these plans when you start them up, you always run into some unexpected issues and then we are working through those now. We did have delays in the construction of the facility. We had some issues with the manufacturer of the valves that we had to work through and we'll certainly be looking for a reimbursement from them. But I think in terms of additional startup costs they are going to be relatively low.

Okay, on this --

If you go back and look at when we... if they would have came on in less than 30 days after we initiate the deal, often third quarter between Meeker and the fractionator Hobbs it is probably close to $40 million to $50 million.

Okay, thank you. Also on the distribution coverage, with the ramp up in cash flows in '08 what are the expectations on that coverage ratio being maybe tail end of '08?

It all depends on what we do with distribution right, but frankly with the ramp up in volumes on Independence, the Meeker and the Pioneer plants, cash flows could ramp up pretty quickly. What we've told investors both on the equity end and fixed income side is that when we look at our distribution, we not only look at distributal cash flow but we also look at our capital program, we look at the projects that we have and how long the construction cycle is to make sure that we have or prudent in the way that we increase our distribution and while we clearly expect to continue increasing distributions we don't want to get ahead of ourselves and put our balance sheet in jeopardy.

Okay and one final question, equity NGL were down a bit and San Juan was down, if you could just touch based on those two items. Thanks.

Yes, on San Juan we had a plant turnaround in August that our Chaco plant, so we were down for five days and that's large plant, over 600 million a day. So, that had an impact to San Juan in the third quarter.

Yes, and were also equity NGL production. It was only down about 3000 barrels a day, I know part of it, when that first hurricane came through the Gulf Mexico when actually went in, over around... well the other one that went towards Mexico, that there was some evacuation of platforms and I think we had offshore production that was offline for call it 3 or 4 days. So that impacted gross operating margin both, on some of the pipelines, on the processing plants which would hit equity NGL production and then also in some of the fracs too, so that may be part of it.

You also had produced your elections in South Texas where they elected the type of processing position rather than unconditionally.

Okay, all right. Very good, that's it from me. Thanks guys.

Thank you, Ross.

Thank you, Ross.

Our next question comes from Ken Liyal [ph] from J.P. Morgan. You may ask your question.

Hi my question is regarding the Independence Hub, when do you think you need to come at additional wells to keep this full or near full when the initial 16 wells start to decline? And what do you see in the pipeline or how many wells are in the completion stage that you can comment them to the Hub?

This is James. Well, I will... the producers have indicated they have other wells that they plan to drill. I think what you are going to see or the tenants kind of watch your volumes, project declines and drill wells accordingly to try to keep the platform as full as possible over the next five years at least. And they find that these wells are fairly quick to grow and they have laid out this major subsea gathering system. So as opposed to having a way of homely system up to the platform, they'll just drill a well and tie it into their existing system so the timing as well as the capital required to get the wells on is going to be low. So I think you are going to see the existing... they have a lot more blocks out there than what's flowing from today, you're going to see those people continue to drill wells to work to keep there capacity full. Over the long-term, I think you're going to see people start to drill in these blocks there, new leases that they have taken in the recent lease sale and if you look out over the next five to 20 years you're going to see areas around the platform as well as these new areas that have been leased up is providing the gas for the Independence Hub and these people are going to EBIT incentivised to use the Hub because one, its there and you can get your gas on a lot quicker. And the cost of building a subsea pipeline to the platform compared to building a new platform is significantly cheaper, so you get the present value benefit to getting on quicker and then obviously the benefit to lower capital to get wells on.

Thank you.

Our next question comes from Mr. John Edwards, Morgan Keegan. You may ask your question.

Yes, good morning everybody.

Good morning, John.

Yes, just I think Dan already mentioned this number, but I just want him to assert I have it straight on the incremental equity and earnings we should expect from Cameron and the Cameron and Poseidon are pipelines and I think you said for Cameron about $18 million or so, is that correct understanding, and what's the... what's your expected timing on that?

John that 18 million was each 100,000 barrels a day.

Each 100,000 barrels a day.

It's a 1,00,000 barrels a day comes on, we own Cameron Highway 50%, so it's $1 tariff, so that is $36 million, our share would be $18 million of that.

Let me add one thing, because I gave you a revenue number. There is a little bit of expense to pumping and I think you're looking at about $16 million on a gross operating margins or added cash per 100,000 barrels.

Okay so you're... so that's why because you saw the producers were coming on with about 500,000 that or I guess more than that, I tell you're getting to the incremental $90 million?

I was using 500,000 barrels a day at the 18 well in 16, under that scenario it would be $80 million. This BP coming on with their production, they say now end of '08. BHP of Australia coming on with their production and I hope IS coming in at the end of the year or early

So we have several fields over the next year that are being --

One other field is

BHP in Atlantis, they are in Genghis Khan, Neptune and then Shenzi.

Okay so BHP's production is coming on, how much production are they contributing there?

You know what, well they are working interest owner in all those fields. Atlantis, their share and BP share of Atlantis is dedicated to Cameron Highway. You know if you add it up, Atlantis is projected to be 200,000 barrels a day, Neptune is projected to be 50. Shenzi is projected to be a 100,000 barrels a day and Genghis Khan BHP has projected at 55,000 barrels a day.

Okay. Okay and then the incremental contribute... you may have mentioned, Dan, I think you may have mentioned this. The incremental contribution you are expecting from Meeker when it is fully ramped up?

Dan, you want to answer that one?

What we've done is we have looked at what the market says these plants will produce is terms of the quoted prices in the forward market, quoted basis. We look at 2008 just the contracts that we have in place not including those that we were highly confident of, taken into account some of the hedging we've already done, the marketplace is saying that Meeker and Pioneer together will produce gross operating margin next year of north of $300 million, what we are saying is that with those that we are confident will get, which is another 300 million a day, we could see that beam toward $350 million.

Okay so 300 to 350?

Again that's based on the forward prices that we are looking at today.

Right, based on forward prices and that's just for Meeker 1, it doesn't count Meeker 2?

That includes Pioneer.

And includes Pioneer?

And a portion of Meeker 2. Meeker 2 is scheduled to come on in the third quarter.

Okay. And then could you talk a little bit about the NGL fractionation, it was at least we are not... we are looking at all variance analysis, is a little bit below what we were expecting? Can you talk a little bit... give us a little color on what happened there. I think you mentioned it in the press release as well, but there were some... it was associated with the fractionation decrease in fractionation volumes at the Norco fractionator.

Yes John, really three things in there, probably the largest thing is in the third quarter of 2006 we had some measurement gains around... measurement gains principally around some wells they were probably about into $12 million. And then that's the biggest piece, and then you did have the decrease in volumes at the Norco fractionators and again that is sort of our highest margin fractionator. And then finally, you had Hobbs that was probably another $1.5 million of start up expenses.

You also had some business interruption proceed, about $10 million more in BI proceed in third quarter of '06 for them.

Okay. So you are expecting that performance to come back up in the fourth quarter and beyond then?

Yes.

Okay. And then I guess similar question with San Juan. I mean for the natural gas pipeline segment, you indicated in the press release that there was an offset of more of a totaling $10 million due to lower volumes of revenues in the San Juan system and some other issues you list there. Can you talk a little, just give little more detail on what was going on there in and why that came in not as well as you expected?

I mentioned, its James Lytal. I mentioned we did have some downtime days in August due to our processing plant going through part of their turn around and actually impact us a little more than 5 days just getting well back on afterwards. Also I think we've talked in the past that the San Juan, a lot of our gathering contracts are based on the percentage of gas price. That can impact the revenues from San Juan although having link to gas over there is an a nice hedge to our shore position of gas, where we buy gas at Mont Belvieu and also for our pumps on our Maple liquid system. So where we may lose some at San Juan, we are getting some in some other areas when processors are little lower, so volume and then the frac gas prices were little lower which affected our gathering fee.

Okay, great

Yes, John gas pipes out in the San Juan were up $0.35 per MBtu lower in the third quarter 2007 compared to the third quarter of 2006

Okay. And then, these future storage projects that are going to be coming on and I realize you mentioned they are out quite a ways in the future, 2010 and 11. Have you... what's the capital budgets you've got associated with some of those?

This is James Lytal again. It ultimately depends on the total amount we build and also we are developing a new cavern at Belvieu initially the first five will be less than $100 million. To do that, that we are designing the path on that first five to give us capacity for to expand up to 20 Bcf in the area. So your capital is going to be a little higher on the front end because you are oversizing facilities in preparation for the other so, when we start adding the incremental 15 Bcf, total capital and then returns and I've talked about our storage business in the past and we've looked at it from the standpoint of depending on how much pipe and compression you have to add, you are probably looking at anywhere from $15 million to $20 million per Bcf of storage that you add. With the market rates that we're seeing in the storage business, it leads you to projects to pay out in 5 to 8 years typically, when these contracts are mainly domain charge contracts and on top of that we can do interruptible business. So, I know I may not be giving you the exact number but I think we're confident we're going to build another ten at Petal, but we could go a lot further than that, we have a lot more land that we're able to develop lot more caverns which could lead to additional pipeline expansions at Petal.

Okay, thanks very much.

Marsha, this is Randy. We have time for one more question.

Thank you. Our next question comes from Mr. Luis Shemy [ph] of Zimmer and Lucas. You may ask your question.

Hi everybody. I guess, two things that I wanted to ask. So, first off, if you can give a little bit of a more detailed break out of how you expect to generate margin on Meeker, in terms of what economics you are assuming there? And then, second question was regarding your financing?

The question is how do we expect to generate margin on meeker?

I think to look at what kind of port prices we are looking at?

You are talking about, is this related to what our earlier answer?

Yes, exactly. So in terms of what the volume assumptions are, operating expenses and then kind of your forward price assumptions?

Our forward price assumptions are a function of what we see uploaded in the market place. Forward price assumptions are not, they are really not assumptions, but they are actual quotes in terms of what we can sell the product at and what we can buy the gas at and what the quoted basis is to the Rockies. For example, we are operating on somewhere or near $1.50 basis to the Rockies for calendar '08.

And volume --.

The volume we're looking at, we expect Meeker 1 to be fill topping that in the mid year, we think when Meeker 2 comes on, we will need Meeker too right at the time it's coming n on. So we see a ramp up in Meeker 1, right now, I think we are at about 450 million a day throughput producing 25,000 barrels a day. We see that ramping up to the full 750 by mid year next year at 35,000 barrels a day and having gas left over to go into Meeker 2. We see Pioneer, right now if you look at our silica gel, we are running 525, 550 in the silica gel, so whenever Pioneer comes up, we automatically have around 550 out of the 750 capacity.

I think in the lower number we have Meeker ramp up from the 470 it is today to about $800 million at the end of the 2008, if on the higher numbers of 350 Jim mentioned that would have Meeker ramping up to about a Bcf a day by the end of 2008. And Pioneer on the lower number goes from about 525 or 550 there to 650 or so by end of '08 and higher number probably adds about 50 to that and takes us to about $700 million by the end of '08.

Okay, great thanks a lot. And then on the financing, just wondered if you guys could give me an overview of how you internally look at your various financing options and which are looking most profitable at this point for whatever CapEx budget you are going to announce for 2008?

Well, I think some of what we are... last year, in 2006 we really front end loaded our 2006-2007 capital expenditure program with a large amount of equity and 2006 with two follow on equity offerings with the $550 million of hybrid being issued. We also had a $100 million of distributable cash flow that we reinvested. Coming into this year, that in fact that gave us a lot of flexibility coming into this year. We came in and issued another $700 million of hybrid securities that brings the hybrids up to about a little less than 10% of our total capitalization, so we still have some flexibility on the hybrid side going forward as far as equity content is concerned. The other thing that we also have... the other component in there is off our dividend reinvestment plan we are probably running on a run rate right now about $60 million a year of the new equity being issued to that program. I think finally, the thing we look at is when you look at the ramp up of the distributable cash flow that we expect coming on in 2008 with Independence ramping up, with these processing plants and fractionators that Jim talked about. I think we will throwing off a huge amount of distributable cash flow in and as we come in and set our cash distribution policy. I think one of the things we have done historically is we retained... just historically if you look at it, we probably retained about 15% of our distributable cash flow to use to fund capital investment, so really as we go into next year we think we've got a lot of flexibility in coming in and financing that growth.

Okay great. And in terms of looking at cost of capital kind of between but they are issuing more hybrids and that kind of tapped at 10% of budget I guess, but between that and unless they are doing a drop into DET or issuing more conventional debt or issuing equity, how do you look at your various cost of capital between those few options?

Well, I don't think we are completely tapped out on the hybrids and certainly markets change frequently and we look at things on a pretty dynamic basis, so to the extent we felt a need to raise equity, which we don't right now, we would look at all 3 methods whether it is additional hybrids, whether it is a drop down, whether it is traditional equity and determine what makes the most sense for the partnership given the current market conditions. But again, we don't have a lot of pressure to do any of that right now.

Sure. And have you considered doing any kind of convertible security or is that kind of not on the horizon?

It's not at the forefront for us now.

Okay great, thanks a lot.

You bet, thanks

Marsha, if you would you give our listeners the replay information?

Thank you. If you would like to listen to the replay, you may dial 1800-728-5839. Once again that's 1800-728-5838, excuse me, 5839. Once again 1800-728-5839.

Thank you, Marsha and thank you every one listening to our call today and have a good day. Good bye.