Enterprise Products Partners LP (EPD) 2008 Q3 法說會逐字稿

Hello, and welcome to the Enterprise Products Partners and Duncan Energy Partners third quarter earnings conference call. At this time, all participants are in a listen-only mode. After the presentation, we will conduct a question-and-answer session. (Operator Instructions). Today's conference is being recorded. If there are any objections, please disconnect at this time.

I would now like to introduce Mr. Randy Burkhalter, Vice President of Investor Relations.

Thank you, Dorian. Good morning and welcome to the Enterprise Products Partners and Duncan Energy Partners conference call to discuss earnings for third quarter. Mike Creel, President and CEO of Enterprise's general partner will lead the call, followed by Randy Fowler, the Company's Executive Vice President and CFO. Also included on the call today from Enterprise is Dan Duncan, our Chairman and Founder, as well as other members of our senior management team. After Randy Fowler's discussion, we will have a short discussion of Duncan Energy Partners' results led by Hank Bachmann, the CEO and President of Duncan Energy Partners' general partner. Afterward, 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 Act 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 that may cause actual results to differ materially from those in the forward-looking statements made during this call.

And with that, I'll turn the call over to Mike.

Thanks, Randy. Good morning, and thanks for joining us on our call today. I'm pleased to report another quarter of solid operating and financial results supported by our NGL and Pipeline Services [sic] segment, which posted a 77% increase in gross operating margin this quarter over the third quarter of last year, and our Natural Gas Pipelines and Services segment, which had a 17% increase in gross operating margin this year versus the third quarter of last year.

We transported 8.8 trillion BTUs per day of natural gas, and, for the fourth consecutive quarter, 2 million barrels per day of natural gas liquids as our pipelines continue to benefit from strong demand and access to some of the most prolific supply regions in the country.

While it's difficult to follow a record period like the last quarter, natural gas transportation volumes this quarter were 3% higher than the previous quarter, and our NGL, crude oil and petrochemical transportation volumes were only 5% lower than last quarter, despite the effects of two major hurricanes on our Gulf Coast operations.

Excluding the effects of the hurricanes, gross operation margin, EBITDA, net income and earnings per unit for the third quarter of this year would each have been new records for enterprise. Our diversified business mix and broad geographical footprint has served us well as we continue to benefit from our energy value chain strategy.

Distributable cash flow increased 42% to $316 million this quarter from $223 million in the third quarter of last year. Distributable cash flow this quarter was reduced by approximately $64 million from hurricane effects and a reimbursement to EPCO for sustaining CapEx in prior periods. Our strong cash flow enabled us to increase the quarterly cash distribution to our partners 6.6% over the third quarter of last year and provided 1.2 times coverage of the distribution. Distributable cash flow would have provided 1.5 times coverage of the distribution on a normalized basis excluding the $64 million of nonrecurring charges. Year-to-date, distributable cash flow would have provided 1.65 times coverage on a normalized basis. As a result, we've retained $261 million of cash in the first nine months of this year, strengthening our liquidity and providing cash to fund growth projects to reduce debt or to satisfy working capital needs while limiting our need to issue equity.

We've also raised $51.5 million so far this year through our distribution reinvestment plan, and we expect to raise an additional $67 to $68 million next month, including the $50 million of distribution Dan Duncan expects to reinvest through the plan. Our retained distributable cash flow together with our distribution reinvestment plan will have provided about $380 million of equity capital with respect to the first nine months of this year. Our practice of balancing distribution growth with retaining distributable cash flow has provided us additional financial flexibility, which has been particularly beneficial in light of the current state of the capital markets.

We have three large capital projects that are expected to be completed over the next few months. Meeker II, which is an expansion of our Meeker cryogenic processing facility, and the central treating facility for Exxon near our Meeker complex are both located in the prolific Piceance Basin in Colorado and should be completed this quarter. The third project is the Sherman natural gas pipeline extension in the Barnett Shale that will connect with our Texas Intrastate gas pipeline system and provide shippers valuable access to eastern markets via interconnects with interstate pipelines. The Sherman Extension is expected to be completed in January, ahead of the completion of Boardwalk's connecting Gulf Crossing pipeline, although we have been flowing some gas off the Sherman Extension since August.

Given recent market events, we expect next year's growth capital expenditure program will be lower than our recent run rate of $1.5 billion to $2 billion per year. We are evaluating all of our potential capital projects in light of today's capital markets, and we are focusing on those investment opportunities that will give us the best returns. We currently have approximately $700 million to $800 million committed to our 2009 capital program.

Part of this reduction includes the Pathfinder pipeline project. While we believe this is an attractive project and certainly a very valuable natural gas export solution out of the Rockies, we have several other projects under consideration that we believe will generate higher risk adjusted returns. If the capital markets become more attractive, we have other investment opportunities, but we expect to maintain financial discipline and not get ahead of our ability to prudently fund our growth while maintaining an investment grade balance sheet.

We continue to mitigate potential increased cost for our new projects. For example, we've locked in a significant portion of the steel costs and pump and turbine components of the Texas offshore port and pipeline system that we recently announced together with Pepco and Oiltanking, and we have certain escalators in those contracts that provide additional protection.

With that, I'd like to discuss a few business highlights from the quarter. Gross operating margin from our NGL Pipelines & Services business increased 77% over the third quarter of last year. The primary driver of this improvement was our gas processing business, which reported gross operating margin this quarter of $238 million, a 145% increase over the same quarter of last year. A 70% increase in equity NGL production and increased marketing volumes were the major regions for the improved performance.

The increase in equity NGL production was primarily attributable to the Meeker and Pioneer processing plants, which were not yet in commercial operation in the third quarter of 2007, and they're currently extracting a combined average of 63,000 barrels per day. The design capacity of the Meeker facility is currently at 35,000 barrels per day, will double to 70,000 barrels per day upon the completion of Meeker II this quarter.

We've taken steps to preserve these attractive processing margins by hedging approximately 85% of the NGLs we expect to extract from our Rocky Mountain plants during the remainder of the year and about 58% of the expected 2009 NGL production from these plants.

NGL demand for petrochemical production was very strong in July and August, with ethylene crackers operating at 92% and 89% of nameplate capacity. As you would expect, September was significantly lower due to facilities along the Gulf Coast having down time as the result of two hurricanes. According to the Hodgson Report, the [US lean] crackers operated at 47% of nameplate capacity last month, the lowest operating rate in history, or at least since 1988.

The US ethylene industry suffered a large loss of production last month following the double hits of Hurricanes Gustav and Ike, and that was larger than the loss of production in 2005 following Hurricanes Katrina and Rita. 36 units experienced unplanned downtime in September. All but 3 of those were due to hurricanes. And of those 36, 34 have now returned to service.

Gross operating margin from our NGL Pipelines & Storage business increased to $75 million in the third quarter of 2008, from $71 million in the third quarter of 2007. This increase was primarily due to a $6 million improvement in gross operating margin from the Mid-America and Seminole pipelines due to a 138,000 barrel per day increase in NGL volumes and higher tariffs that went into effect July 1st of this year.

Volumes associated with our NGL Pipelines & Storage business totaled 1.8 million barrels per day in the third quarter of 2008, compared with 1.6 million barrels per day for the same quarter of last year.

Our Onshore Natural Gas Pipelines & Services segment reported a 17% increase in gross operating margin to $88 million for the third quarter of this year compared with $75 million for the same quarter of last year. Most of our natural gas pipelines reported improved results this quarter.

Gross operating margin for the San Juan system increased $17 million this quarter, primarily due to higher transportation fees, index and natural gas prices, as well as from NGL and condensate sales, and the Texas Intrastate system was up $3 million due to increased volumes.

Total Onshore Natural Gas transportation volumes increased 15% to a record 7.6 trillion BTUs per day for the third quarter of 2008. Natural gas storage reported an increase of $3 million in gross operating margin, primarily from new capacity and pipeline fees at our Petal storage facility in Mississippi.

Gross operating margin for the Offshore Pipelines & Services segment was $17 million for the third quarter of 2008 compared with $47 million in the third quarter of last year. Included in gross operating margin this quarter are $35 million of expenses for storm-related damages, $3 million of expenses to complete repairs to the flex joint flange on the Independence Trail pipeline, and $16 million for lost business associated with the hurricanes.

Independence contributed a net $41 million to gross operating margin this quarter, and that consists of $28 million for the Hub platform and $13 million from the pipeline. The platform and the pipeline were down for 8 days for repairs to the flex joint flange in July and another 12 days in August and September for hurricanes. After Hurricane Ike, Independence was up within a matter of days, flowing 900 million cubic feet a day of natural gas.

Our Petrochemical Services segment reported operating margin of $37 million in the third quarter of 2008, compared with $51 million in the same quarter of last year. The primary reason for the decrease in gross operating margin were $10 million of lost business due to the hurricanes, a 26% decrease in butane isomerization volumes and octane enhancement facility downtime due to Hurricane Ike and repairs that were completed in September. This facility has now returned to normal operations.

As for the hurricanes, in summary, we've incurred approximately $4 million in actual repair costs and have accrued an additional $42 million for property damage repair expenses that we will have in the future. In addition, we estimate our gross operating margin was lower by $43 million for lost business, bringing the total negative impact to $89 million for the quarter. We estimate the impact of lost business related to Hurricane Ike will be a decrease of about $25 million to $35 million in gross operating margin for the fourth quarter of 2008.

I would like to take this opportunity to recognize the extraordinary efforts of our employees in responding to Hurricanes Gustav and Ike. They worked tirelessly around the clock to return our assets to operations so we could provide critical logistical services to our oil and gas producer and refining and petrochemical customers. I believe they're the best in the business, and I'm proud to be a part of their team.

In closing, I'd like to say again that we are very pleased with our performance this quarter. Despite the impact of the hurricanes, we were able to generate solid gross operating margin from our NGL and natural gas businesses, raise the quarterly cash distribution by 6% year-over-year and retain distributable cash flow to provide us with additional flexibility.

We continue to believe that our strong fundamentals distinguish us, particularly in this market environment. The quality of our assets, our large diversified footprint, our portfolio of organic growth opportunities, our management's focus on creating value for our investors, our lower cost of capital, our investment grade credit ratings and strong balance sheet, together with our consistent increases in quarterly cash distributions to our investors are important factors to consider. We will continue to manage our business with a long-term view, and we believe our investors will be rewarded for our consistent performance, solid results and financial discipline.

With that, I'd like to turn the call over to Randy Fowler for a review of our financials.

Good morning. I'd like to start the review with the income statement below the gross operating margin line. For depreciation and amortization expense and operating costs and expenses for the third quarter of 2008 increased to $138 million from $134 million for the third quarter of 2007, primarily due to increased property, plant and equipment from the additions of the Meeker processing plant, Hobbs fractionator, the expansion of the Mid-America pipeline, the Pioneer natural gas processing plant and the propylene fractionator that we put into service in the third quarter of last year at Mont Belvieu.

G&A expense increased $22 million this quarter from $19 million in the third quarter. On a year-to-date basis, G&A expense this year is about flat with G&A last year at about $66 million. As far as interest expense is concerned, we reported $103 million of interest expense for the third quarter of 2008 compared to $85 million for the third quarter last year. Average debt outstanding was $8.1 billion this quarter compared to $65 billion for the third quarter 2007.

Interest expense for the current quarter also included a charge of $3 million to write off the fair market value of a interest rate swap that we had with Lehman that actually extended out to 2014. So again, some of this was mostly the future value of that swap. Capitalized interest decreased $1 million quarter-to-quarter as a result of the decrease in the amount of construction work in progress.

As far as provision for income taxes, it was $7 million for the third quarter 2008 versus $2 million for the third quarter 2007. This increase was primarily due to higher accruals for the Texas margin tax.

Turning to capital expenditures, we invested $464 million in gross capital projects, including $61 million in sustaining capital expenditures in the third quarter 2008. The majority of the gross capital spent this quarter was attributable to the Sherman Extension pipeline, the Meeker II cryogenic plant, the Mont Belvieu well utilization program and then smaller amounts for the Pioneer plant and the Exxon central treating facility in the Piceance Basin, as well as the Shenzi oil pipeline.

Through nine months of 2008, we've invested approximately $1.4 billion in growth capital expenditure and about $129 million in maintenance capital expenditures.

At September 30, 2008, we had $8.5 billion of debt outstanding. This includes 100% of our $1.25 billion of hybrid securities and $212 million of debt down at Duncan Energy Partners. EPD had liquidity of approximately $700 million at September 30, 2008. September generally represents a peak in working capital usage for us, with our inventories of NGL and natural gas at their highest associated with our forward sales program. Today, liquidity has improved to approximately $800 million.

Our floating interest rate exposure was approximately 22% at the end of the quarter, and the average life of our debt was approximately 16 years, with the average cost of debt of about 5.8%. A key credit metric for Enterprise is our consolidated leverage ratio of debt to the last 12 months of EBITDA, and in consolidated, that means it also includes the debt obligations of DEP. We do exclude 50% of the hybrid debt principal, which is, if you would, the minimum amount of equity credit that the rating agencies give that security.

After making those adjustments, at September 30th, our debt balance was $7.8 billion, and when we come in and look at EBITDA for the last 12 months after deducting equity earnings and adding back the actual cash distribution that we received from unconsolidated affiliates, that number was approximately $1.9 billion. This resulted in debt to EBITDA for the last 12 months at September 30 of about 4.1 times.

If you exclude the $89 million of the hurricane effects, debt to EBITDA would have been 3.9 times. We have improved this ratio from 4.3 times at the end of 2007 and from 4.5 times at its peak at September 30th last year, as construction projects have been completed and beginning operations have started generating cash flow.

With that, I'll turn the call over to Hank to discuss Duncan Energy Partners.

Thank you, Randy. Duncan Energy reported solid results this quarter despite the impact on our businesses from Hurricanes Gustav and Ike.

Net income was $3.8 million, or $0.18 per common unit, for the third quarter of 2008, compared to $4.5 million, or $0.22 per common unit, for the third quarter of last year.

Third-quarter results were negatively impacted by an estimated $1.8 million, or $0.09 per common unit, of property damage repair costs, lost business from downtime of some of our assets related to the hurricanes.

We generated distributable cash flow of $7.6 million in the third quarter of this year, which provides 0.9 times coverage of the third-quarter distributions we paid to our limited partners in November. We believe that lost business due to the hurricanes reduced distributable cash flow for the quarter by an estimated $1.2 million. Even after taking into account the effects of the hurricanes, Duncan Energy's year-to-date distributable cash flow provides 1.1 times coverage of the distributions declared by the partnerships for the first three quarters of this year.

On October 15th, 2008, the board of directors of Duncan Energy's general partner declared a quarterly cash distribution of $0.42 per common unit, a 2.4% increase from the quarterly distribution rate for common unit paid in respect to the third quarter of last year.

Notwithstanding the effects of the hurricanes, Duncan Energy's businesses were able to generate increased revenues in gross operating margin this quarter compared to the third quarter of last year. Revenues increased 46% to $321.4 million from $220.6 million for the third quarter of last year. Gross operating margin for the quarter increased to $20.9 million from $19.1 million for the third quarter of 2007.

Our NGL and Petrochemical Storage business reported an increased gross operating margin this quarter versus the third quarter of last year, primarily due to measurement gains recorded this quarter compared to a measurement loss recorded in the third quarter of last year. After adjusting for measurement gains and losses, neither of which are received by or charged to Duncan Energy, gross operating margin was down slightly this quarter compared to the third quarter of last year.

Increased storage revenues for excess throughput storage fees and volumes were offset by higher operating expenses, which included $600,000 for property damage repair costs resulting from Hurricane Ike.

Gross operating margin this year was also impacted by an estimated $900,000 of lost business due to lower volumes as a result of Hurricane Ike.

The Onshore Natural Gas Pipeline business reported a 37% increase in gross operating margin this quarter of $4.5 million, from $3.3 million reported in the third quarter of last year. This increase was due primarily to improved natural gas sales margins on the Acadian Gas Pipeline System.

Natural gas volumes, which includes both sales and transportation volumes, decreased to $693 billion British thermal units, or BTUs, per day this quarter, from 761 billion BTUs per day in the third quarter of 2007.

Operating expenses for Acadian also included approximately $300,000 of repair expenses due to damages incurred for both Hurricanes Gustav and Ike.

In summary, the total impact on gross operating margin this quarter from damages and lost business due to the hurricanes was an estimated $2.7 million. When calculating the effect on Duncan Energy's net income, you would multiple this by Duncan Energy's equity interest of 66%, or $1.8 million.

Sustaining capital expenditures were $3.3 million this quarter and $9.1 million year-to-date. This compares to $4.4 million and $10.6 million of maintenance capital expenditures spent through the three and nine months ended September 30th, 2007.

Interest expense decreased to $2.9 million for the third quarter of this year, compared to $3.2 million for the third quarter of 2007, due to lower average interest rates associated with the Duncan Energy revolving credit facility.

We had total liquidity of approximately $100 million at the end of September, which includes availability under the partnership's credit facility and unrestricted cash. We remain confident in the partnership's ability to consistently deliver strong results and distributable cash flow, and we expect these businesses to continue to perform well for the remainder of this year and for the foreseeable future.

Now we're ready to take questions, Randy.

Thank you, Hank. One more item that we would like to discuss before we open the call up for questions. It has to do with rumors that have been circulating concerning margin loans of Dan Duncan and his non-public affiliates, secured by common units of Enterprise Products and/or TEPPCO. While we normally do not respond to rumors, we think that in view of the current uncertainties in the equity markets and the reported forced sales by executives of other companies, we need to set the record straight.

While Mr. Duncan and some of his non-public affiliates do have margin loans secured by an immaterial portion of his and his affiliates' common unit holdings in Enterprise and TEPPCO, such loans are on economically favorable terms, are well over-collateralized, and there is no risk of any forced sale of Enterprise or TEPPCO common units. Additionally, Mr. Duncan and his affiliates have sufficient liquidity from their own resources to pay all of such margin loans in full.

Now, we're ready to take questions, Dorian, from our listeners. Thank you.

(Operator Instructions). Our first question comes from Mark Reichman with Sanders Morris Harris.

Mark? Dorian, I think we're having a problem here.

There we go. Mr. Reichman, your line is now open.

Thank you and good morning. Just a couple of questions. First, what is the basis for your lost business estimates? And should we have a pretty high degree of confidence in their precision?

Yes, Mark, what we did is have our [inaudible] guys take a look at the contracts we have in place and the volumes that were lost, and it's pretty simple math. We're not looking at that as business that was speculated that we might have had. It was pretty solid stuff.

Okay, thank you. And then, second, in terms of the growth capital going forward, you mention in the release about taking a more disciplined approach, or a disciplined approach and looking out -- I think in the past you had mentioned $1.5 billion to $2 billion and $700 million to $800 million in 2009. I was just curious if there's any other projects similar to Pathfinder that may have been announced that maybe you've decided not to go forward with or --

No. Yes, Mark, we don't have anything that we've announced that we've decided not to go forward with. Pathfinder was one that was certainly -- we were working on. We had not completed negotiations, and I think with respect to our prudence in developing our capital programs over the years, we've always tried to stay within the bounds of the capital markets and our own financial resources. What we've got right now is about $700 million, $750 million of capital projects that we've committed to for 2009. We can slow down some of those if we need to, but frankly, we've got the resources to handle that with no problems.

If the capital markets come back in 2009, which we fully expect they will -- in fact, we're already seeing signs of that -- we frankly have several billion dollars worth of projects in the wings that we could select from. So we have the ability to ramp up our capital spending, but again, we want to do it within the bounds of our financial means.

I see. And is it primarily -- are you looking at, say, that differential between the $1.5 billion to $2 billion and the $700 million to $800 million? Are some segments of your business more likely to have projects deferred than others? Or are you looking at it just pretty much on a project-to-project basis?

Let me answer that, and then I'm going to turn it over to Jim Teague, our Chief Commercial Officer. I think what we're looking at in this kind of a market, Mark, is that there may be some opportunities that we haven't seen in a number of years. Certainly, we're active in looking at opportunities across each of our business segments, but unlike the last couple years, there may be opportunities in 2009, 2010 to actually do acquisitions at more reasonable prices. There may be less competition for some of the projects that we have considered. So I think it's really across the board. We have pretty open minds, but again, across all of our business segments.

Jim, I don't know if you have anything else you want to add.

No, other than as we look at things, the way we measure them and what we're interested in is it has to have two things. It has to be a good return. We're seeing that become -- in this environment, we feel like we're better positioned to realize that than others. Secondly, it has to be strategic. In other words, it has to fit what we already have. That's where we see we get upside beyond the return of the project itself. We've got a large inventory of projects.

Okay, and then I want to leave questions for others, so just lastly, if you could provide just your outlook for the NGL market and NGL prices, say, over the next 18 months.

Mark, I'm not sure what next week's going to hold.

Fair enough.

What we're seeing -- as a result of the hurricane, when you have -- and Mike mentioned in his comments the number of petrochemical plants that went down. So we have a short-term issue in that production continued to flow while demand went off. Consequently, inventory is built, and prices reflect that build in inventory. As that -- and we're in fact seeing the impact of that because we're seeing some plants -- not ours -- but we're seeing some plants, for example, in ethane rejection.

Where we're advantaged is if you look at our Rockies position, we continue to be in full extraction, get the benefits throughout our value chain because we've got a very strong basis advantage up there in the Rockies that we benefit from. If you look at our situation in Louisiana, we have margin bands and/or fees and/or percent of proceeds so that we're not hurt like a pure keep-whole contract provider would be.

Then if you look in South Texas, by and large those are percent of proceeds and fee-based contracts that we have, as are the ones we have at Chaco and San Juan. So yes, we're seeing over -- in the short-term, we're seeing reduced prices. We're seeing others suffer from reduced margins. We're not seeing any of our plants cut back, primarily because we feel like we're advantaged, either basis or the way we structured the contracts.

Finally, we are seeing through this last year, and we expect that it will continue -- and there will be months where maybe ethane isn't preferred, but by and large we see ethane as much a preferred feedstock in petrochemicals. We've seen traditional heavy crackers move so that they have the ability to consume more ethane. And if you look at that map we've shown many times in many conferences, our connectivity to petrochemicals can't be duplicated. So consequently, we are the guys that are there making the deliveries, and to those traditional heavy crackers, making those deliveries at some pretty attractive fees. So in the short run, the hurricane had an effect on demand inventories built. In the longer term, we're still pretty excited about our position as it relates to prices, margins and petrochemicals.

And Mark, remember, we do have about 85% of our NGL production hedged through the end of this year, about 58% through next year. So that ought to help us through the shakeout as the remaining effects from the hurricanes kind of work their way through the system.

Good point, and thanks for the color.

Your next question comes from Darren Horowitz with Raymond James.

Good morning. Thank you. Mike, my first question is on the retained cash flow. Just building off the nine months-to-date, if we take that, and we build in what we expect excess cash flow to be in the fourth quarter, we get a number where you could be ending the year with about $350 million of excess cash flow. Obviously it would be higher than that if you look at total equity capital retained and it includes the dividend reinvestment. But with that as a backdrop, how do you look at balancing the excess cash that you use for repaying debt versus CapEx funding on a go-forward basis?

You know, where we are right now is that we think consistent increases in our distribution is important, but we don't want to be heroes about it, where we're not intending to distribute all of our cash flow. To the extent that we can keep a reasonable distribution increase going -- 5.5%, 6.5%, that's a pretty good track record. And then, being able to use that cash and not having to rely on the capital markets, that's very important to us. And we've been talking about this for several years, maybe more than several, and have actually been criticized in prior years because we haven't distributed more of our cash flow out. I think people are starting to realize now the reasons that we were trying to preserve some of our capital.

Frankly, this gives us the ability to, rather than distribute all of our cash out, retain some of it, reinvest in these higher return projects. And in this kind of an environment, the projects that we're seeing today are going to yield higher returns than they would have a year ago simply because of the capital markets. A lot of people can't invest because they don't have the capacity to invest. So we think this positions us pretty uniquely and will give us a tremendous opportunity. And remember, as we invest these retained cash flows in new projects, that generates additional cash flows for future distribution increases.

Right. Now, if I'm doing my math right, and I bake in the midpoint of -- let's just say that guided range of 6%. I look at the excess retained cash. I look at how much financial flexibility you have on the debt side. Am I thinking about it correctly that you guys don't need to access the capital markets through the duration of 2009 to fund your growth?

Well, I think that from the equity side, given what we've committed to, that's correct. We do have a debt maturity coming up in the fourth quarter of next year. So I wouldn't say that we wouldn't have to go back to the debt capital markets, but -- so, I think you're right.

And then my second question, kind of building off that financial flexibility theme, when you look at the challenges out there in the marketplace that a lot of others face in order to fund their capital programs, how do you look at the inorganic growth opportunity, either from a consolidation standpoint or possibly a joint venture potential?

I think from a joint venture potential, if other parties are having difficulties funding their growth, they may have difficulties funding a joint venture. Typically, our strategy has been to team up with parties that bring something to the table other than just cash. So if there's somebody that has a business incentive for us to join up with them, it's certainly something we'd consider, and we've kind of built the business on joint ventures over the years.

Or, again, for rollups, for consolidation, MLPs have always been very difficult, although you're actually starting to see valuations separate now, and we've been waiting on that. I'm a bit frustrated that we've tended to trade the MLP universe as a pack rather than looking at individual MLPs and being valued on our merits.

That may lead to an opportunity for a consolidation at some point. But remember, as Jim said, when we're looking at a transaction, whether it's an acquisition, whether it's an organic project, it has to be something that provides benefit to our value chain, that actually does something other than make us bigger. So I wouldn't hold your breath too long waiting for an acquisition, but I do think there's some exciting opportunities that'll unveil in 2009.

Sure. I appreciate it. And then just one final question. When you look at your backlog, and you look at prioritizing your backlog and the composition of that $700 million to $800 million in committed projects, can you give us a sense of the targeted rate of return from a cash-on-cash perspective and how that targeted rate of return has evolved over the past 12 months?

Not really, Darren. I would tell you that for us to do a project, we're going to have to have a return that reflects a risk in today's markets, and if anything, what we're seeing even on our existing assets is that fees are going to go up because there just isn't as much competition. Money's not as easy to come by as it was. We need to get compensated for our investments. So I think that one of our projects is our Texas Offshore Port System that we're working on. That won't go into service until 2011, but I think that some of the competition that we may have been expecting will not be there as a result of today's capital markets, and resulting, those fees will go up and the returns will be higher.

Mike, I appreciate it, and keep up the good financial discipline.

Thanks, Darren.

Our next question comes from Michael Blum with Wachovia.

Hi, good morning.

Good morning, Michael.

Good morning.

Just a couple of quick ones. Most of my questions were answered. Can you just review for us, given the big pullback in commodity prices -- you talked about the NGL market a bit, but just maybe review the different gives and takes as it relates to the impact of lower natural gas prices on the business?

Well, remember, Michael, we've got what we refer to as this natural hedge in the past and what we really look at are the fees that we get from some of our gathering pipelines that are indexed to natural gas prices. So those tend to offset the cost of gas that we use for our fuel and shrink and at the various plants that we have. So we're relatively insensitive on that basis to natural gas prices. The natural gas prices related to our NGLs, our equity NGL volumes are pretty much hedged. So not that much of an impact on us.

Are you seeing or expecting to see any reductions in volumes come through your gathering systems and plants given -- we've heard a lot of announcements from producers about curtailing production and cutting back on rigs, et cetera.

Let me turn that question over to Chris Skoog. Chris is head of our Natural Gas group.

From a -- where our assets are located, we're in traditional basins that have been not subject to a whole lot of drilling expansion other than the Barnett, and our Sherman Extension's fully contracted for on a demand basis only, so whether the gas shows up or doesn't show up, we are fee-based driven up there. So we're not really subject to the slowdown. Although we would like to see it participate and grow, we're comfortable with our position.

Thank you.

Our next question comes from Ross Payne with Wachovia.

How are you doing, guys?

Hey, Ross.

Hello, Ross.

Mike, quick question for you. I think you mentioned a little bit earlier in your comments that the hurricane impact may be around $25 million or $35 million for the fourth quarter. Does that also incorporate the lower operating levels at the ethylene crackers?

No, that's just related to the hurricane impact. The ethylene plants, by and large, are for backup, the ones that were impacted by the hurricanes.

Okay, and they were down for about how many days or weeks, do you think, there?

I can put it in my -- I don't know, Ross. This is Jim. Mike reflected it as September came in at a 47% run rate, whereas the prior month was pushing 90% run rate. So -- yes, a couple of weeks.

Okay, okay. That's fine. And one other quick question. EPCO obviously did some maintenance CapEx. I was just kind of curious -- is that typical or ongoing? Any reflection on that would be appreciated. Thanks.

Yes, Ross. It's not typical. What we have -- as you know, we have a shared service organization that provides services to all of our publicly traded partnerships, and some of those costs include IT, the building and things of that sort. What had happened was EPCO was funding that and not passing those costs down to the various partnerships, so we trued that up in the third quarter. So you shouldn't see that continuing.

Okay, great. All right, good job, guys. Thanks.

Thanks, Ross.

Thank you, Ross.

Our next question comes Sharon Lui with Wachovia.

Hi, good morning. These are questions are related to DEP. Just wondering if the storage and pipeline volumes are back to normal from the hurricane levels.

Yes, they are.

Okay. And also, I guess, given the current capital markets and DEP's valuation, would management consider maybe buying back DEP inter-Enterprise?

I'll leave that to Mike because that's really Enterprise's call.

Yes, Sharon, the short answer is no. We formed DEP with the long-term view to facilitate, among other things, the growth of Enterprise, but we also think it's a good investment vehicle in and of itself. Just because the capital markets are temporarily disrupted, we don't think that means that DEP is not going to be valuable in the future.

Okay, terrific. Thank you.

Thank you, Sharon.

Our next question comes from [Erik Vlasky] with RBC.

Good morning, guys. Just out of curiosity, have you seen any reduction in the cost of organic growth in terms of labor as we see people kind of backing away from some of their growth projects?

I'm going to turn that over to Bill Ordemann, our Chief Operating Officer.

I don't know that we've seen a lot in the way of labor yet. I think we have some expectations that as time goes on, we will see some reductions on the labor costs. It's too soon to tell here. It's only been a few weeks since we've really seen this impact.

We have, I think, seen some of the commodities markets softening a little bit, particularly on the steel side. I think a couple of issues there. One, just the outlook for the future, and two, the strength of the dollar. We have seem steel costs starting to trend downward, and we expect that I think to continue here for the next few months.

Okay. And with regards to the possibility of making some acquisitions, where do you guys see the multiples running at this point? Has it come down 2x versus EBITDA? Or what has that change been in you all's opinion?

First of all, we're not actively looking at any acquisitions, but if we were, yes, the multiples would be down pretty significantly from market multiples, maybe not down quite as much from our expectations. We do think that companies are going to get more rational in valuing acquisitions. Certainly the proliferation of MLP that had easy access to capital in the past are not going to be as big of players.

But frankly, in today's market, rather than looking at a 10, 12, even 14 times multiple of EBITDA, in today's capital market, right now, you might be looking at 5 times. When the markets come back to more reasonable where you actually have access to the capital markets, you may see something return to more of an 8 times multiple.

Okay. And one last one, and that is we've had in the past five years, I guess, two really major hurricanes in the Gulf Coast region where you guys are. Is this affecting the outlook for insurance costs following this one as well?

Yes, we do expect that insurance costs will be affected, and we've got Greg Watkins here, our VP of Corporate Risk, to talk about that.

Yes, we -- it's a little early to tell, following the impact of Gustav and Ike, but we do expect to see some increase in both the cost and the deductibles associated with insurance. A lot will depend on how the reinsurance market sees this as the last quarter comes through and a lot of the reinsurance renewals are done.

The way that we look at that, that is another cost of doing business and that factors in to the current expectations that we have.

Right. Just out of curiosity, on the -- when you said the deductibles increase, is that in dollar terms or in time?

Well, in dollar terms with respect to property damage and potentially in time with respect to business interruption.

Okay. Thank you.

Our next question comes from Noah Lerner with Hartz Capital.

Good morning, everybody. First of all, I hope everybody's life down there is getting back to normal, post-hurricanes. I know it hasn't, probably, been easy on you guys down there.

We've got a cold front, Noah, it's pretty nice.

Well, we got one, too, and I don't like them. I like coming down and visiting you guys, because I get some warm weather in January and February.

That'll work.

I guess my first question, just to tie up some loose ends, piggyback on other people's questions, regarding liquidity, I really like, Dan, what you've done as far as dropping a big number into the DRIP program and everything. Because, curiosity, when I added the, say, $800 million of CapEx next year with what's left for this year, cash on hand, some excess cash and everything, I kind of was getting the feeling that you might be close to -- if the debt and equity markets don't come back next year -- and nobody knows what will happen -- you might be fully tapped out.

So, I guess -- a) how concerned are you that at this time next year, if the debt and equity markets don't come back, you might not have the ability to expand going forward, for the foreseeable future, if we look at that magic 8-ball?

And then a personal question, almost, to Dan is, with the DRIP program, do you intend to leave those units within the DRIP program going into 2009, so that would -- if you had a $50 million pickup this quarter, we could think of that as an additional $200 million of cash flow to the enterprise for next year?

No, let me take a first stab at some of this. First of all, from our liquidity standpoint, we've got at the end of the quarter, $700 million or more of liquidity. As Randy mentioned in his remarks, September 30 is kind of a high point in terms of inventory. We've got forward sales that start rolling off, working capital that starts unwinding, so we get cash back from that.

But in your scenario, where the capital markets, debt and equity, don't come back in 2009, the easy answer is we're going to be living within our means and we may not be investing a whole lot more in 2010, but I think that's a fairly draconian outlook. We don't expect it. In fact, we're already seeing the debt markets come back and we expect that they will come back, more wholesomely, in the first quarter of next year and that the equity markets, once things stabilize somewhat and investor confidence is restored, that you will start to see equity investors come back in and when they do, if you look at an MLP unit that's yielding, depending on the MLP, anywhere from 7.5% to 9%, 10% and the growth prospects that are there, and the tax shield, it's a pretty attractive investment alternative. So we think that there's going to be a market for it.

But the easy answer is, we're not going to go out and spend a lot of money unless we're confident that we have the funding sources for that.

Now with respect to Dan's investment in the DRIP in November, that's largely because he sees it as such a value. Our units have been beaten up so much, that it's a great investment opportunity and, as you know, Dan puts his money where his mouth is. He's not committing to doing anything in the future. That, frankly, is something that Enterprise isn't counting on for our funding requirements. We don't need it. If Dan decides it makes sense for him, in future quarters, he'll do it.

Okay, so, if that's the case -- in other words, if the DRIP program doesn't work where you put shares in there and you leave them there and they constantly do it, you do it quarter-by-quarter?

Actually, yes, our investors can make elections. They can do it recurring. They can do it quarter-by-quarter, whichever way they want to do it.

Okay, great. I guess --

To further -- this is Dan. To give you a little bit more color, the EPCO family of companies has in excess of $400 million a year of cash flow coming in, and that grows every year by all the dividends as they've been increasing on all the companies. So, basically, I mean, under today's conditions we could put $400 million to $500 million a year back into the Company or any of the companies, if we would desire -- if we look at that as the best place to not only help those companies out, but also as the best place for returns.

Right. Makes sense to me. I know we've had some discussions on this call regarding the NGL production and everything and the price volatility and, hopefully, that does turn out to be a short term. But with a slowing and with a slowed economy going out forward and a lot of the natural gas liquids going to the petrochemical industry, which are very economically sensitive, what type of impact do you see a possibility on operations and volumes and everything, if we do go into a either a short but deep recession or a prolonged recession?

This is Jim. We've run some outlooks, some sensitivities, in terms of petrochemical operating rates down around 80%, which is something in the neighborhood that we saw back in 2003. And the difference this time compared to what we were faced with in 2003 -- if you remember, natural gas in 2003, was selling at -- on, basically, a BTU equivalency to crude oil. Consequently, the NGLs were less preferred. And what we see today is, even at an 80% operating rate, much more preference for light feedstocks.

Given that, we think from gas processing, on the low end, you're going to see a demand, at that run rate, of about 700,000 barrels a day. We think there will be ethane rejection from those folks who don't have the value chain that we have. I'll refer back to the answer I gave earlier. We think we're very well positioned to continue to extract ethane at all of our plants and we're uniquely advantaged in our ability to delivery those light-end feedstocks to every petrochemical company in the US, with the exception of one, via pipe. So we're positioned on both ends.

Secondly, to the extent that some of our competitors are in ethane rejection -- and some already are -- this system is quite dynamic. It invariably opens up opportunities to capture margins that would otherwise not be available to us because the pipes would be full with the ethane. An example -- right now, we've got NGLs in Conway selling at anywhere from $0.10 to $0.20 below Mont Belvieu. I can -- you can trust me, we're fully -- we're very active in capturing that arb and, frankly, would love to have a little additional pipeline space to fill it up with $0.20 barrels.

Great.

This is Dan. Let me add a little bit of color to Jim's deal. If you go back to the 2003 timeframe when we were operating at 80% of the capacity -- and I'm going to break down capacity a little bit different way now, what we call heavy crackers that use heavy feedstocks and what we call light-end crackers which uses light-end feedstocks. At that time, when we were operating at 80% of capacity in the 2003-2004 timeframe, the heavy crackers, then, because of the prices of crude oil and the prices of natural gas, the heavy cracker was running at 105% to 110% of capacity and you can do that, probably, for one to two years. The light-end crackers at that time were running 65% to 70% of capacity.

So the capacity deal doesn't necessarily work across the board all the way in a true equal deal. If you look at 2007 and 2008, what we're going through now, and, definitely, 2009, we have the same capacity where 40% of all of your ethylene manufacturers, probably, is running on the heavy and 50% to 60% on the light end. On today's deal -- and Jim mentioned this -- the preferred feedstock today is light-end.

So we can have the light-end for all their crackers. They're going to be operating at 100% to 110% for the next 15 months to 18 months, where the heavy crackers may be down to 60% of the capacity. So when you're operating your chemical plant at 80% capacity, they have a tremendous amount of flexibility on their preferred feedstock.

So what we're looking at now is that the crude oil ratio, relative to gas, is in the 10, 11, 12 times range. What we call a normal parity is at 7 times range and what happened in 2003 and 2004, it was about 5, 5 range of crude oil over gas. So when you have this type of deal now, the preferred feedstock is going to be light-end and that operates until you get out of balance on your [beer-danes] and some of the heavy-feed crackers, of what they produce. But the ethylene itself, all your light-end people are going to be running all out.

Plus the fact, right now, we've got a bunch of the major oil companies, every one of them, is backing off. They've all learned how to operate some light-end in their heavy crackers, so they're all using record amounts right now of ethane and propane in their feed plants. So that makes a big difference. The 80% capacity is always the same, but 80% sometimes is different than 80% other times, if you understand what I've just brought out.

Yes. No, I do. Thank you very much, guys. I'm going to jump off, let other people ask some questions, and I'll see if I can get back in the queue later.

Thank you.

Thanks.

Thank you. Our next question comes from Shaumo Sadhukan with Lotus Partners.

Yes, hi. Can you talk about what you see the effect of economic weakness being on natural gas volumes, say, over the next couple of years? If we go into a very significant recession here, what might that do to your natural gas volumes?

Yes, I'll let Chris talk about that, and I'm sure he'll bring up the new gas supply that we're seeing and kind of the proliferation of some of these basins.

Yes, Mike. Once again, our main natural gas pipeline systems are 100% fully subscribed with firm reservation fees. So if production sits there for the next -- I don't think we have any major renegotiations of long-term contracts of any significant size that are going to impact us in the next 24 months.

We're excited about our access into the Barnett Shale. We've got the Sherman Lateral coming on here in first quarter, which is fully subscribed going forward. I shouldn't say fully subscribed, about a 90%-plus subscription rate. We've got a lot of access. We're working with some people in the area there to further expand some of the laterals down into the basin to help get us more at the retail level, at the wellhead level, within the Dallas-Fort Worth metropolitan area. We're not going to spend that capital in those areas. We're hooking up with people that are spending that capital, getting it to our, what we call, trunk line, to get to our main lines to get out of the basin.

We are looking at -- part of these capital projects that Jim and Mike have talked about, we've got a number of projects that we like that are in the priority queue. We're looking at rates of returns. We're looking at the risk/rewards and what value they bring to the Company overall to get prioritized.

So we're not too nervous about natural gas prices here. We do kind of have a long-term floor in this $5, $6 range, because that's where the marginal production is for all these shales coming on, it seems to be, where our assets are located. So below $5 natural gas prices on the NYMEX, we get a little nervous if it sustains there for the longterm. But, once again, the pipeline is fully subscribed out for the next 24 months, and we're in decent shape.

So even if we were to go below $5, you think that, at least for the time being you're subscribed out, meaning even if there's not production, you get paid, at least for a while, if we go below $5. Is that right?

That's correct.

Let me give you -- this is Dan, again. Let me give you a little bit more color on what Chris has said. It's also the $5 or the $6 range -- no matter what price it is -- is similar to the petrochemical plants I just explained. A $5 price or $6 price in one area could be a real good deal, where a $5 or $6 price in another area would not be a good deal. So not all $5 and $6 are equal.

Like to set up these shale -- all these shale plays that's coming into play now, and they're really coming in. There was a recent announcement in South Texas about a new shale play in South Texas that they've stepped out 15 miles and they've hit the same type of shale play there that looks like similar to the Barnett Shale. But once a company goes into a shale play, they put a lot of free money into a lot of things that they do there.

So, normally, after they put all that upfront money in -- they have to do this in every shale play -- when they put that upfront money in, they're not going to leave that particular shale play because of, probably, $5 or $6 gas. I mean, if it got down to $2 gas, and I think that's what we've been told out in the shale play in the Jonah Field, in the Meeker Field and those type of deals, then they would start cutting back that particular field.

But once you put all that upfront money into that shale play, those are the ones you'll keep developing. Now, some of the new shale plays that they have not put all this lead money into, those will probably be the ones they cut back. But I'm not trying to get into the E&P side of telling you which company may cut back and which won't cut back. I was just giving you some economics of what everybody's going to be looking at.

Thank you. That's actually really helpful.

The other thing I'd add to that is that there's been a lot of talk, lately, in the press, in Washington, about natural gas as a way to reduce our dependence on foreign oil, and a lot of that's because of the relative attractiveness of natural gas relative to crude, because of the price. And so I think that you may very well see more of a demand from natural gas for new uses than you've seen in the past.

Okay. And so I've been reading reports recently about driving demand -- demand for gasoline falling about 9% is the last number that I had seen. Do you think that this trend could have an effect on your crude oil pipelines or your refined products pipelines? Maybe you can comment on that a little bit?

I'll turn that over to James Lytal.

Well, our crude oil pipelines mainly support the deep water, and the deep water takes a very long-term view of prices, because you drill a well and it's probably three or four years before you get first flow. So our two major pipelines offshore, Cameron Highway and Poseidon, are mainly supported by deep-water crudes and we continue to see strong drilling out there, irregardless of price. Unless the producers really just took a tremendously dim view of the future, that's going to stay active.

As far as our oil port, Motiva is moving forward with their expansion. We've got two major, very long-term, commitments from the two major refineries down there, Motiva and Exxon. So they obviously see a demand way out into the future, and on top of them, we see another 1.5 million to 1.8 million barrels a day of refineries that are bringing in waterborne barrels that are potential customers for us.

So we don't see that reduction in demand as impacting our existing assets or our future projects.

And I think you'd have to be pretty pessimistic to believe that a recession would last into early 2011, when TOPS goes into service.

I see. Okay. And I guess the last thing I wanted to ask about is, so one of two things will happen, right? The capital markets will open up at some point early next year, or if the capital markets continue to stay shut, you guys would probably reduce some growth CapEx next year. What's the lead-time on that, if you had to do that? I mean, I understand you're funded for a while, but if things got really bad and the situation were beyond your control, what's the lead-time to scaling back or slowing down on some of these projects? Can you do it on six weeks' notice? Two months notice? Three months notice? I mean, how does that work?

I think we kind of do it the other way around. We don't start projects until we're confident we have the funding for it. So we're fine for what we've already committed to. We just won't commit to new projects unless we're confident the funding will be there.

So, one of the things to think about, again, just taking that doomsday scenario, the capital markets don't come back in 2009, we still have some big projects that are coming online and will be ramping up, generating additional cash flow, and the projects that we've committed to, the $700 million to $750 million for 2009 are going to generate cash flow. So our distributable cash flow is going to continue to rise.

I see. Okay. Thank you. I appreciate all the color.

Maybe add a little bit more color to that, I think. From my side, we don't feel, at no time, that we would ever be restrained on doing good projects. We think with the cash flow that EPCO can put into the equity side, we don't see at any time in the near future, well, in the next three, four, five years, that we wouldn't have $1 billion to $1.2 billion of capital expenditure every year, if the right type of project comes along that fits into our value chain. Because the amount of cash flow that EPCO can put back into it, plus the amount of cash flow that we probably would withhold every year from distribution, we can come $600 million to $700 million a year just about year on our own, without going out to equity markets.

So unless the debt market would completely go away, like it's going away in the last 60 days -- and we do think the debt market is easing up as of last week and beginning to show promise, I mean, even further down this week, because the governments of all the world right now is putting so much liquidity back into the market that, in theory, the people are beginning to worry now from the financial side that -- and you all are in that side, your companies are in that side, but they're now saying we may be worried about inflation in 2010 or '11, because so much liquidity is putting back into the banks and the financial institutions. So I think if that liquidity going in to everybody, they have to start loaning money out. Otherwise, they're not going to be paying government the rate that the government wants for it and just hold on to that money.

Right. Dan, maybe you can comment on this, because this is really the fundamental issue that I see, and then I'll -- after this question, I'll drop off. But if we're -- if we think about your company long-term, here's the way I look at the liquidity profile going forward. You have $800 million of liquidity, right now, and then the uses that I see are you probably have $200 million to $300 million of CapEx in the back half of the year, net of retained -- cash flow you'll retain, and maybe $400 million to $500 million, net of cash flow you might retain next year. And then you have a $500 million debt payment that's coming due at the end of next year.

So, if I add all those numbers up and we get to the point where we have to start repaying that $500 million of debt, that's the trigger point, meaning if the capital markets were to stay closed through the end of 2009 as to where there would be an issue of having to slow down CapEx, and I just wanted to understand, if that draconian scenario happened, what the reaction would be from Enterprise? Would it be a funding from EPCO? Would it be slowing down growth? How you would think about that?

Well, I'll tell you, basically, the first funding that EPD would look for would be a funding from EPCO. So you start with that basis there. So if you went through EPCO's excess cash flow, which is in excess of $400 million a year, then at that time we would be going into some other direction.

But what we're really looking at is, we will not make that excess capital program in 2009, just like Mike explained earlier, until we know for sure the capital market has opened up. If the capital market has not opened up in the second quarter of '09, then we will not commit for any more capital expenditures than we've got right now.

So, in effect, if the $500 million of debt that we got -- I think it's in fourth quarter of '09 -- if the debt market doesn't open up then, or the equity market doesn't up then, then what would happen then would be EPCO, then, would come in and basically fund the majority of that with the $400 million of excess cash flow they have in 2009.

So we feel that we will not -- we won't commit to any other capital expenditure until we know that something opened up, either the debt markets open up or the equity markets open up. We will not get ahead of the game -- and that's what Mike has been talking about. Until we know for sure there is an equity market, or there is a debt market, we're not going to spend any -- we're not commit to any more capital.

Thank you. I appreciate the color.

Dorian, this is Randy. I think we have time for two more questions.

Thank you. Our next question comes from Brian Zarahn with Barclay's Capital.

Good morning. Could you comment on the current price environment in the San Juan and how that's going to affect your gathering?

Well, with prices falling and most of our deals being a percent of the index, obviously, we'll see lower revenues, but that's offset. When you go back to what Mike said earlier, that's offset by our fuel requirements in our Mid-America pipeline system and Mont Belvieu complex. It's pretty much one-for-one on terms of -- if you do a hedge.

And looking at 2009, for maintenance CapEx, is $200 million a reasonable number?

Yes, this is Randy Fowler. I think it's probably a little south of that. Maybe call it in the $175 million to $200 million range.

Thank you.

And our final question comes from John Edwards with Morgan Keegan.

Good morning, everybody.

Good morning, John.

Just on the commodity sensitivity, can you just give us a sense of the sensitivity to the change in commodity prices? I mean, you indicate 58% is hedged next year, but can you translate that into a sensitivity?

I'm not sure how to do that. I'm not sure what the question is, but if you look at 2009, for example, and look at the fact that 58% of our NGL production is hedged, that is -- that 58% is weighted toward propane and heavier. Not so much of the ethane is hedged, but as Jim said, to the extent that ethane is rejected, it frees up space in our pipeline so we can take advantage of price differentials between Conway and Mont Belvieu. There's a lot of moving parts and we have a lot of ways to optimize our system, so it's not as easy as just changing the prices and it's not linear saying that if prices go down, then this is the impact, because it does create additional opportunities for us.

Okay.

Let me add. When we say 58%, we're talking about our total equity barrels from the Rockies, from our percent of proceeds and from South Texas. If you look at what we've hedged next year, where we have the largest part of our margin risk being ethane in the Rockies, we've done 58% of the total, in terms of total liquids. Most of that is propane-plus, but we've hedged 50% of our ethane, thereabouts, in the Rockies, at probably double what the current margin quoted is up there.

And I think the other thing that we may have mentioned earlier in the call is to the extent there is ethane rejection, we believe that the Rocky Mountain plants are going to be the last ones to feel that because of the gas differential that makes it so much more attractive to extract liquids up there.

Okay. So, I guess the bottom line is, you are -- you have nowhere near the sensitivity to the collapsing commodity prices here that others may feel, although others are hedged too. I mean, what I was thinking about, Mike, was just a lot of the companies, they'll say for a given dollar amount change in oil it translates to X in distributable cash flow and for a given amount change in gas prices it'll translate to a change in cash flow. And it sounds like there's just no way you can simplify it to that in your system.

Yes, it's not as simple as that, John, and we remember the days when we were exposed to big swings in commodity prices back after 1999, 2000, 2001 and we've done a lot of work to renegotiate those contracts to take that risk out of the business. The place where we do have the keep-whole risk is up in the Rocky Mountains, but we have it with plants that were specifically designed to be keep-whole plants where we have the ability to turn down the liquid extraction rate.

So we've got a number of ways to mitigate changes in NGL prices and natural gas prices. Jim, I don't know if you want to add something to that.

No, I think the biggest part of our exposure is in the Rockies. We've hedged close to 60% of it, and Mike was right. We have the ability, if that draconian scenario we keep talking about exhibits itself, we can turn these plants back to virtually nothing to mitigate that exposure.

Okay. And then, I don't know, I'm not quite sure how to ask this question. Regarding any kind of impact from -- I know you have an administrative services sharing agreement between Enterprise and EPCO. A lot of companies out there are going to be facing pension funding expenses, and I don't know if there's any administrative costs associated with that or if you have any kind of -- in terms of the benefit to employees of EPCO. Can you comment on that, at all?

Sure.

I mean, is that something we need to be thinking about at all or not?

Well, certainly you can think about it, John, but the fact of the matter is we don't have a defined pension plan.

Okay.

We have a 401(k) plan with a matching, so we don't have any pension obligations.

Okay, great.

And, John, the one thing, there is, in the grand scheme of things, a very small pension plan as far as from an EPD level. It's a pension plan down at Dixie, but, again --

Okay.

-- all that --

It's a rounding error.

It is. It's very small, and we speak to that in our Qs and our Ks.

Okay, great. And then as far as sustaining CapEx run rates, that -- oh, I'm sorry. You already answered that question. And the income tax leakage ---- this quarter it was running at -- it looks like it was running about 3.3%, something like that. Is that a good number, going forward?

Well, John, the good news is that the taxes are up, because that means that Seminole made more money. So it really is a function of the taxable income to Seminole.

Okay.

John, on that particular deal, we've got both the Dixie Pipeline is a C Corp. and the Seminole Pipeline is a C Corp.

Oh, and, John --

So that's where your income taxes come into play. I think, depending on what they do in taxes, as we go forward, then those may be converted from C Corp back to an LLC within the next two or three years.

And, John, Mike Knesek is sitting here telling me to "Tell them that a lot of that has to do with the Texas Margin Tax."

Yes, that's what I was getting at, was the Texas Margin Tax. I mean, I was just doing the simple math of what the income tax paid was against the EBT and the math came out about the 3% change, and we were modeling a little bit lower than that, and I was just trying to get a feel for is this higher level about where you expect to be.

It's ballpark. I mean, we refer to it as the Texas State Income Tax, but, yes.

Okay, great. That's all I had. Thank you very much.

All right, thanks, John.

Thank you, John. Dorian, would you provide our listeners with replay information, please?

Yes, thank you. One moment, please. Anyone wishing to listen to the replay of today's conference may do so by dialing the toll-free number of 800-873-4963. No passcode is required. Once again, anyone wishing to listen to the replay of today's conference may do so by dialing 800-873-4963. This replay will be available through midnight, October 30th.

Okay. Thank you, Dorian. And thank everyone for joining us on our call today and have a good day.

Thank you for joining today's conference. That does conclude the call at this time. You may disconnect.