Enterprise Products Partners LP (EPD) 2007 Q3 法說會逐字稿

Welcome and thank you for standing by. At this time all participates 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 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 Ac of 1934, based on the beliefs of the Company as well as 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 trillion 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 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 million 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 in a little 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 on 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 a 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 sale 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 running mostly in Dupont recovery mode since the start up as we work through some mechanical issues with the treating 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 processing 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 2 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 is supported 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. Exxon Mobile has stated publicly 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 Hobbs NGL fractionator.

The Hobbs 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 Conway. Kansas to an ethylene facility in Odessa 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 system, increasing the capacity of 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 Gas 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 5 expansion program for Jonah is expected to be completed during the first quarter of next year.

Construction of our 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. This state-of-the-art facility is designed to process up to 750 million cubic feet a day of natural gas and extract up tor 30,000 barrels per day of natural gas liquids. It has natural gas connections with Current River, Northwest Pipeline, Colorado Interstate Gas and Rockies Express pipeline.

We're currently conditioning about 525 million cubic feet a day of natural gas to the two 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.

The 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, Baja, 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 were taken out of service in the second quarter of 2006 for repairs, one well has resumed limited operations 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 for 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 Humberto in September, the ethylene steam crackers were operating at 90% of capacity.

The gas to crude oil price ratio has consistently been 45% to 50%, compared to a 5-year average of nearly 70%. Consequently, 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 the hurricane that made landfall in the Port Arthur 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, Mont Belvieu 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 up to high operating rates.

Shifting 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 a 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 our Cameron Highway Pipeline or through our Poseidon 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'll turn it over to Randy.

Okay. Thanks, Mike.

Good morning.

Enterprise's solid operating performance was somewhat hidden with the difference in the recoveries under business interruption insurance, by our being in a transitional start-up phase for a number of our growth capital projects, and also against a very difficult comparison to a record quarter in the third quarter 2006.

Items of note, natural gas transported via our pipelines was a record another 7.9 trillion BTU. 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 this quarter was $364 million compared to $400 million in the third quarter of 2006. Again, when taking in to account, the $48 million difference in business interruption insurance recoveries, and the unusual items 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, we made the determination that the cavern was not going to be suitable for natural gas service, so we had between $2 and $3 million worth of cost associated with that that we did write off during the quarter. So when you adjust for all of that, we actually had third quarter 2007 gross operating margin was 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 quarter of '06. Again, the biggest difference there being the $48 million delta in the recoveries under business interruption insurance. This provided .9 times coverage of our cash distributions that we paid to our limited partners or will pay to our limited partners here in -- at the beginning of November.

But the nine months September 30, 2007 distributed cash flow was $739 million, which compares to the $738 million for the first nine months of 2006, and this is provided a 1.0 coverage distribution declared with respective for the first nine months -- of note the Board of Directors of our general partner did declare an increase in the cash distribution rate to $0.49 per common unit. This is an annualized rate of $1.96, and is about 6.5% greater than the distribution we paid out in the third quarter of 2006.

I think the press release came in and provided a fairly comprehensive analysis of the changes in gross operating margin by segment, so now I would like to turn to the income statement.

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, nonrecurring. The remainder is really legal fees around the mid-America rate case.

Finally, $1 million of increase represents the non-cash amortization of an employee compensation plan that EPCO Inc. actually bears the entire economic liability associated with that, 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 of 2006. This $22 million increase reflects interest on a higher average debt balance. Average debt balance in the third quarter of 2007 was $6.6 billion, compared to $5 billion in the third quarter 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 debt, $913 million of it is attributable to our junior subordinated, or as we refer it to our hybrid notes, for which we receive on average 58% equity credit from Moody's S&P and Fitch.

Quarterly interest expense on the $1.25 billion in hybrids that we have outstanding, is about $24 million after taking in to account the hybrids that were issued at a premium. So if you would, applying 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 in 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 a piece of our equity capital on our income statement which again -- well there are only two other MLPs that are actually doing that.

During the third quarter we issued $800 million of 6.3% tenured notes that will be due September 15th, 2017. The proceeds were essentially to pre-fund the retirement of $500 million of our 4% notes that matured on October 15th of this year. And the remainder went to reduce the debt balance on our revolver.

Capital expenditures for the third quarter 2007, were approximately $528 million, and that -- for 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 who -- EPD does not bare the payment obligation for the Duncan Energy debt.

We had liquidity -- EPD had liquidity of approximately $1.2 billion at 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 affect 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 debt 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, going ahead 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 -- of the hybrid notes, and also adjusting for the equity earnings and cash distributions that we received from unconsolidated 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 would like to briefly make a few comments on 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 in 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 the 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 1 x coverage of the quarterly distribution. The Board of Directors of the General Partner of 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 businesses through acquisitions 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 it's time to go ahead and open up the call for questions.

Marsha, I think we're ready to take questions now.

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 were reported this quarter and what you're experiencing currently, what's your expectation for that to improve hopefully into the fourth quarter and into the early parts of 2008.

Jim -- Jim -- I'm let Jim Teague -- the Executive VP that runs our NGL respond to that.

The question was what, import volumes?

Yes, as far as I guess the import volumes being diverted over to Europe? What do you see now? Do you see any relief with that?

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 any 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 contract customers 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 a Belvieu to Henry Hub basis, so you can look at the import issue in isolation and say, what's going to happen, there is some -- you know the knife cuts both ways.

Okay. So could you also take and apply that to Duncan as the reason why you saw the NGL petrochemical storage down about 40 % sequentially? Is that pretty much the same thing?

The NGL storage was --

It is due to -- lower NGL import activity or --

Yeah, I think the -- the storage facility. I mean if you look at it in total, it's -- the import, the reduced imports is a contributor to it, its not the only thing, but it is a contributor to that decline. We just got lower volumes in general in storage throughout the Mont Belvieu 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.

This is Jim Teague again. The other thing is you've got that petrochemicals 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 they are holding less in storage.

This is Dan Duncan. Let me add a little bit of color to [Gil] deal The storage revenue at Mont Belvieu, and it 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 up. What happened is they got 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. So 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 imports, and in fact, I think this time last year, we probably had over 800 million gallons -- 800 million barrels that we was holding to deal with TEPPCO deal. So it's a through-put deal, not the base storage, that's the reason it is down.

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

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 Trail. 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 see too much of a variance relative to what you reported this quarter in D&A?

I'm sorry --

Hobbs will be the only incremental project that hits the D&A line this quarter, correct?

Yeah, the Meeker plant was in there for part of a quarter, and the third quarter we have got a few thousand dollars, so you'll see a full quarter of Meeker as well.

Okay. And then maybe -- and initial shot as what you think it does for maintenance CapEx in the next year?

I think, you know, we're -- you know, we have said all year that we think our run rate for sustaining capital for this year is approximately $160 million. I think we're still comfortable with that number.

Right now, Dan, we're sort of putting together where our sustaining cap is for next year, but I don't really at this point in time see it exceeding that number. In fact if anything we 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 would 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.

Yeah, Sam, this is Gil Radtke. The real reason that that is down compared to last year is that you have gotten a spread between normal and gasoline that has really compressed. Normal butane prices itself with crude, and the finished product that we sell out of there is priced against RBOB. What has happened here over the last quarter is we have had a big compression in the crack spread that the refiners have enjoyed. So that's really what has happened there. We're 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, you know, I think seasonally, we're kind of where we think we should be, or where we expect to be this time of year. But I think going forward and looking in 2008, we're going to see a better gasoline season next year.

This is Mike, as I mentioned before it is difficult to compare the third quarter this year with the third quarter last year --

Right, but even going to, you know, the last several years beyond that.

I understand. But remember in isooctane, the second quarter of last year was very strong and we hedged those margins through the end of last year, and so we kind of caught a peak in terms of octane margins to lock in, and that's what you are comparing the third quarter this year against.

Sure. 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 of the things you got to consider is we use butane as a feed stock for that, so that contributes to the margin.

I see okay. So it's really just a -- perhaps the NGL prices being buoyed by the crude oil price. So it's a separate market, but because your feed stock has increased, that's the really reason, correct?

Correct, the feed stock has increased relative to the value of gasoline.

Got you, and the feed stock is primarily getting brought up because it's more like propane and because --

It follows crude oil.

And -- yeah, and it's being brought up by crude oil as well as a correlation. Okay, that makes a lot of sense. And if I could ask one more, you guys stated that you had some better margins with the crude oil transportation and were able to renegotiate some tariffs, do you expect that tariffs to be able to be 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 Atlantis and Ghengis Kahn.. How is that going to offset, kind of your natural decline rate in -- in those production going forward?

Sam, I guess one -- I guess we're -- the question that you had on crude oil and tariffs, if you could -- if you could embellish on that when -- we're a little confused on that one.

Okay. On the offshore pipelines and services, you had -- page 3, number B it says you had $5 million from higher revenues from Highland Offshore as a result of a new tariff that went into effect in March 2007.

Yeah, Sam. that's a gas pipeline.

Oh, okay. Highland Offshore.

And we did have an rate increase there.

Okay. I see. All right. My mistake. And then I guess following that kind of what is your natural decline then on the gas and crude oil lines?

This is Dan Duncan. Let me answer the deal on the crude oil. Our crude oil pipelines the capacity of the Poseidon done deal and the Cameron Highway, they were designed with Atlantis and Ghengis Kahn and Marco Polo all of them being up. 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 of this year beginning to be ramped up on the deal. So those two pipeline today is running about 200,000 barrels a day each, we own approximately 35% to 50% of those two pipelines. The actual capacity of those two pipelines is about 600,000 barrels a day. And that's because the product itself hadn't came on. So there is no decrease in the volume of that were finally moved to it, its never come on 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 start the natural decline, so we just--

Let me just 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 400,000, 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 and Genghis Khan, we mentioned Neptune. That is coming on either late this year or early 2008, and that accesses Cameron Highway as well as Poseidon And then in late 2008 early 2009 we are building a major gathering system 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 down-stream oil pipelines, so that's revenue to not only the gathering line, but to our downstream oil pipelines.

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 lay out, they hug the shelf moving east to 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 more in the central, and then Mike mentioned the leasing around Independence Hub, which we believe is a 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 point in time do you need to start thinking about incremental growth CapEx offshore, and so on the flip side of that is when you think of the incremental 800,000 of capacity on Poseidon and Cameron Highway, it sounds like that within a couple of years that might be 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 have 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, a lot of the piping has already been done in anticipation of it, so it's just matter of adding a little bit of pumps, so it's a very small number.

I think he's trying to get sense for the potential additional gross operating margin without --

Right. On -- let me give you a feel, on 100,000 barrels a day, you know, on Cameron Highway, you are looking at $17 to $18 million a year of additional gross operating margin in round numbers.

This is Dan. That volume that BP and -- and the two big ones right now, with BP coming on and BPH and Exxon on those fields, like James said each 100,000 barrels a day is net to Enterprise of about $18 million a year. That is Enterprise's ownership out there. So in theory, if we can get up -- 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 right now.

Without spending -- very little additional capital, because we're there.

Okay. That's great. Then when you think about growth CapEx next year and beyond, and -- and what you have 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, you know, the Rockies and where you are today?

Yves, I think the answer is yes. We're looking at all of those areas, and we're frankly looking at some projects that we haven't announced and it would be premature to talk about now, but suffice it to say we have pretty exciting prospects, both onshore and offshore, perhaps weighted a little more heavily onshore.

Okay. Any sense of timing?

You know, we have already got projects in our capital budget for next year that are probably in the $1.2 to $1.4 billion range, and we haven't even finished this year yet. So next year is look pretty robust. In terms of announcing any other growth projects, we're probably still, you know, three to six months out.

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

Those -- you know, we don't have a big project in that number like an Independence Hub that takes three 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 have already done. These projects by and large are smaller in scope than an Independence type of project, so you are looking at probably on average, maybe 9 to 12 months.

That's great. Thanks, guys. And here is Sharon.

Hey, good morning.

One correction on one mistake I made. The ramp-up of our crude oil going into Poseidon and Cameron Highway is $90 million annualized, not the $60 million I gave out.

Okay. Thanks. I guess on the Duncan side, if you could maybe give some color on the higher OpEx costs. It looks like you guys are incurring higher integrity cost for both the natural gas pipeline and the NGL storage segment.

Yeah, I guess -- you know, from the -- the context of the pipeline integrity costs, primarily at Acadian, those are related to what we have to do associated with the regs in Louisiana. And in those are really -- we have accelerated some projects from the first quarter of 2008 into 2007 because we have to. So, you know, when we look at that, it's money we knew we were 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 -- it's not pipeline integrity out at the storage facility, but its just some maintenance capital which decided that we need to do now and not wait and do it when it was -- some of that was also scheduled in 2008. It's 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 safe to say that it will be at the similar rate for the fourth quarter?

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

Okay. And I guess if you guys have an update on potential drop-downs to Duncan, in terms of timing?

You know, 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 if it was only for a one-time transaction. We certainly had discussions internally about what might make sense for both partnerships, but again it's a little 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 million cubic feet for the quarter, the 640 million cubic feet, is that where it is today or your expectations for the average through-put in Q4-- and on top of that if you can throw out any thoughts on EBITDA contribution from the ramp-up, sequentially, there because it is pretty significant.

Yeah, Ross, the Independence Hub and Trail, as we talked about it before, we got a $44 million a year demand charge on the platform, and the addition to gross operating margin for the hub and the pipeline is about $17 million for every 100 million cubic feet. We're at 640 million cubic feet today. Producers have indicated that they might even get close 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 contemplated when we initially sanctioned the project, and even much higher than we thought six months ago.

Right. Right. Also, Mike, can you comment on what you think start-up costs might have been at Meeker, and some of these other plants just, you know, forget that there's going to be substantial increases in cash flow here, but what kind of cost might you be incurring, you know, in this quarter with all of the ramp-ups that are ongoing?

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

Okay.

Ross, if you go back and look when we -- if they came on, let's say 30 days after we initiated the deal. The cost in third quarter between Meeker and -- and the fractionator hub is probably close to $40 to $50 million.

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

It all depends on what we do with the distribution rate. But, you know, frankly with the ramp-up in volumes on Independence, the Meeker, and the Pioneer plants, cash flows could ramp-up pretty quickly. What we have told investors, both on the equity end and fixed-income side, is that when we look at our distribution, we not only look at distributable cash flow, but we also look at our capital program, we look at the projects we have, and how the construction cycle is to make sure we are prudent in the way we increase our distributions. 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.

And one final question. Equity NGLs were down a bit, and San Juan was down, if you could just touch base on those two items.

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

Yeah, and Ross, on Equity NGL production, it was only down about 3,000 barrels a day. I know part of it -- when the first hurricane came through the Gulf of Mexico and actually went i, over around -- the other one it went towards Mexico, I believe that there was some evacuations of platforms, and I think we had offshore production that was offline for call it three or four days, so that impacted gross operating margin both on some of the pipelines on the processing plants, which would hit Equity NGL production and also on some of the fracs, too -- so that may be part of it.

You also had producer elections in South Texas where they elected to take a processing position rather than a conditioning.

Okay. Okay. All right. Very good. That's it for me. Thanks, guys.

Thank you Ross.

Our next question comes from Chen Luiao from J.P. Morgan, you may ask your question.

Hi, my question is regarding the Independence Hub. When do you think you need to commence the additional well to keep it full or near full when the initial 15 well start to decline? And what do you see in the pipeline? How many wells are drilling or in the completion stage that you can connect them to the hub?

This is James Lytal. The producers have indicated they have other wells that they plan to drill -- I think what you are going to see are the anchor tenants kind of watch their 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, you know, these wells are fairly quick to drill, and they have laid out this major subsidy gathering system, so as opposed to having to lay a whole new 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 are going to be low. So I think you are going to see the existing -- they have a lot more blocks out there than what is flowing from today. You are going to see those people continue to drill wells to work to keep their capacity full. Over the long term, I think you going to see people start to drill in these new box -- or new leases that they have taken in the recent lease sale. And if you look out over the next 5 to 20 years, you will see areas around the platform, as well as these new areas that have been leased up, as providing the gas for the Independence Hub. And these people are going to be incentivized to use the hub, because one it is 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 obviously the benefit to lower capital to get the wells on.

Thank you.

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

Yeah, good morning, everybody.

Good morning, John.

Just -- this -- I think Dan already mentioned this number, but I just want to make sure I have it straight. On the incremental equity and earnings we should expect from the Cameron and Poseidon pipelines, I think you said for Cameron about $18 million or so annualized, 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.

Oh, each 100,000 barrels a day.

As each 100,000 barrel 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 revenue. There's a little bit of expense to pumping, and I think you are looking at about $16 million on a gross operating margin added-- as per 100,000 barrels.

Okay. So you're -- so that's why -- you know, because these other producers were coming on with about 500,000 or -- or I guess more than that, that's how you are getting to the incremental $90 million?

Right. I was using -- I was using 500,000 barrels a someday at $18 rather than by $16 -- Under that scenario it would be $80 million. And then BP coming on with their production, they say now that end of '08. BHP out of Australia coming on with their production, and they hope to come in by the end of this year and early in the forth.

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

What other fields?

BHP in Atlantis, they are in Ghengis Kahn, Neptune and then Shenzi.

Okay. So BHPs production is coming on -- how much production are they contributing then?

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

Okay. Okay. And then the incremental contribution -- you may have mentioned -- Dan, I think you may have mentioned this -- the incremental contribution you are expecting from Meeker when it's fully ramped up.

Dan, you want to answer that one?

What we have done is we have looked what the market says this -- these plants will produce in terms of 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, taking in to account some of the hedging we have 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 we will get, which is another -- call it 300 million a someday, we could see that being toward $350 million.

Okay. So $300 to $350 million?

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

Right. Based on forward prices. And that is just for Meeker 1. that does not include Meeker 2--

That includes Pioneer.

That includes Pioneer?

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

Okay. Okay. Could you talk a little bit about the NGL fractionation? You know, it was -- you know, at least when we were looking about our variance analysis, it is a little bit below, you know, what -- what we were expecting -- can you talk a little bit -- you know, give us a little color on what happened there? I think you mentioned it in the press release as well. But there was -- there was some -- it was associated with the fractionation -- decrease in fractionation volumes at the Norco fractionator.

Yeah, 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 that were probably about -- in the $12 million. And then -- that's the biggest piece.

And then -- then you did have the decrease in volumes at the Norco fractionator, and again, that is sort of our highest margin fractionator.

And then finally, you had had Hobbs that was probably another $1.5 million of start-up expenses. You also had business interruption proceeds, about $10 million more in BI proceeds in the fourth quarter of '06.

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

Yes.

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

Well, I mentioned -- this is James Lytal. I mentioned we did have some downtime days in August due to our processing plant going through a five-day turn around, and actually impacted us a little more than five days. It was getting wells on afterwards. Also I think we talked in the past, that San Juan --a lot of our gathering contracts are based on a percentage of gas price. That can impact the revenues from San Juan. Although having linked the gas over there is a nice hedge to our shore position of gas, where we buy gas at Mont Belvieu, and also for our pumps on our MAPL liquid system. So where we may lose some at San Juan, we gain some in some other areas when prices are a little lower, so volume and then the fact gas prices were a little lower, which affected our gathering fee.

Okay. Great.

Yeah, John, gas prices out in the San Juan were about $0.35 per million BTU lower in the third quarter of 2007 compared to the third quarter of 2006.

Okay. And then, you know, these -- and these future storage projects that are going to be coming on, and I realize, you know, you mentioned -- you know, they are out quite a ways the future, 2010 and 2011, have you -- what is the capital budgets you have got associated with some of those?

Well, it -- this is James Lytal again. It ultimately depends on the total amount we build, and also, you know, we're developing a new cavern at Belvieu, initially the first five will be less than $100 million to do that, but we're designing -- the pipe on that first five to give us capacity for -- to expand up to 20 BCF in the area, so, you know, 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, you know, total capital and returns, and I talked about our storage business in the past, and, you know, we have 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 -- it leads you to projects that pay out in 5 to 8 years, typically. You know, and these contracts are mainly demand charge contracts, and on top of that we can do interruptible business. I know I may not be giving you the exact number, but I think we're confident we're going build another 10 at Petal, but we could go a lot further than that. We have a lot more land that we're able to develop a lot more caverns which could lead to addition 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. Lewis Shammy of Zimmer and Lucas. You may ask your question.

Hi, everybody. I guess two things I want to ask about. First off, if you can give a little bit of a more detailed breakout of how you expect to generate margin on Meeker in terms of what economics you are assuming there? I -- and then second question was regarding your financing.

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

I think he's looking at what kind of forward prices are we looking at?

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

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

Our forward price assumptions are a function of what we see quoted in the market place. They are really not assumptions, they are actual quotes.

Uh-huh.

In terms of what we can sell the product at, and what we can buy the gas at, and what a quoted basis is to the Rockies. For example, we're operating somewhere near $1.50 basis to the Rockies for calendar '08.

Uh-huh.

The volume -- the volume we're looking at -- we expect Meeker 1 to be topping out in the midyear. We think when Meeker 2 comes on, we will need Meeker 2 right at the time it's coming on. We see a ramp-up at Meeker 1. Right now I think we're at about 450 million a day through-put, producing 25,000 barrels a day. We see that ramping up to the full 7, 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're running 525, 550 in the silica gel, so whenever Pioneer comes up we automatically have 550 out of the 750 capacity.

This is Bill Ordemann. I think on the lower number we have Meeker ramping up from the 470 it is today to about 800 million at the end of 2008, if -- on the higher number, the 350 Jim mentioned that would have Meeker ramping up to about a BCF a day by the end of 2008, and then Pioneer on the lower number goes from 525 or 550 a day up to 650 by the end of '08, and the high number adds about 50 to that and takes us up to about 700 million by the end of '08.

Great. Thanks a lot. And then on the financing just wondering if you could give me an overview of how you internally look at our various financing options, and which are looking most preferable at this point for whatever CapEx budget you are going to announce for 2008.

Well, I think some of what we are -- you know, last year in 2006, we really front-end loaded your 2006 and 2007 capital expenditure program with a large amount of equity in 2006, with two follow-on equity offerings with the $550 million of hybrid being issued. We also had $100 million of distributable cash flow that we reinvested.

Huh huh.

Coming in to this year -- in fact that gave us a lot of flexibility coming in to 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% 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 -- we also -- the other component in there is off of our dividend reinvestment plan, we're probably running on a run rate right now of about $60 million a year of new equity being issued through that program. And 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 has talked about, I think we'll be throwing off a huge amount of distributable cash flow and as we come in and set our cash distribution policy, I think one of the things we have done historically is we have retained -- historically if you look at it we probably maintained about 15% of our distributable cash flow to use to fund capital investment. So really as we go into next year we think we have a lot of flexibility in coming in and financing that growth.

Okay. Great. And then in terms of -- you know, looking at cost of capital, kind of between let's say issuing more hybrids, and that's kind of tapped out at 10% of the budget, I guess, but between that and let's say doing a drop-down in [DT], or issuing more conventional debt or issuing equity, how do you look at your various cost of capital between those few options?

I don't think we are completely tapped out on the hybrids, and certainly the 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 look at all three methods, whether it's additional hybrids, whether it's drop-down, whether it's 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 a not at the forefront of us right now, no.

Thanks.

You bet. Thanks.

Marsha, would you give our listeners the replay information?

Thank you. If you would like to listen to the replay, you may dial 1-800-728-5839. Once against that's 1-800-728-5838 -- excuse me -- 5839. Once again 1-800-728-5839.

Thank you, Marsha.

You're welcome.

And thank you everyone for listening to your call today. And have a good day. Good-bye.