Enterprise Products Partners LP (EPD) 2009 Q3 法說會逐字稿

Welcome to the Enterprise Products Partners and Duncan Energy Partners third-quarter earnings conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. (Operator Instructions)

Today's call is being recorded. If you have any objections, you may disconnect at this time. I would now like to introduce Mr. Randy Burkhalter, Vice President of Investor Relations. You may begin.

Thank you, Molly. Good morning and welcome to Enterprise Products and Duncan Energy Partners conference call to discuss third quarter earnings. Mike Creel, President and CEO of Enterprise and General Partner will begin the call followed by Randy Fowler, Executive Vice President and CFO; and Hank Bachmann, President and CEO of Duncan Energy Partners, General Partner who will discuss third quarter results for Duncan Energy Partners.

Also in attendance for the call today are Dan Duncan, our Chairman and Founder; Jim Teague, our Executive Vice President and Chief Commercial Officer, and other members of our senior management team. Afterward we will open the call up for your questions.

During the 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.

Good morning and thanks for joining us today. We are pleased to report another quarter of strong results from all of our businesses, supported by increased volumes across the board. We had record NGL, crude oil and petrochemical pipeline volumes of 2.5 million barrels per day this quarter.

Natural gas pipeline volumes were 9.6 trillion BTUs per day, 9% higher than the third quarter of 2008. And NGL fractionation volumes were a record 453,000 barrels per day, 10% higher than last year. Butane isomerization volumes were also a record at 104,000 barrels per day, an increase of 46% over the prior year.

As a result, we reported record gross operating margin of $561 million this quarter which if adjusted for the TOPS charges would have been $594 million. Adjusted EBITDA was $514 million for the quarter and without TOPS and the merger related costs, adjusted EBITDA would have been $557 million compared with $453 million for the third quarter of last year.

Based on Enterprise's strong cash flows, the Board approved our 21st consecutive quarterly increase in the cash distribution to $0.5525 per unit, a 5.7% increase over the rate paid with respect to the third quarter of 2008. Enterprise generated distributable cash flow of $402 million for the quarter, including $43 million of distributable cash flow attributable to TEPPCO which includes about $40 million of TOPS and merger related charges.

Since Enterprise will pay quarterly cash distributions on November 5 on the Enterprise common units issued to complete the merger with TEPPCO, we include TEPPCO's distributable cash flow in calculating our total distributable cash flow for the quarter. Distributable cash flow provided 1.03 times coverage of our quarterly cash distribution declared with respect to the third quarter and enabled us to retain $10 million of excess cash flow.

Year to date, we've retained approximately $100 million of distributable cash flow. Without the TOPS and merger related costs at enterprise and TEPPCO, total distributable cash flow for the third quarter would have been $484 million and would have provided 1.3 times coverage of the cash distribution.

Now I'd like to take a few minutes to review the business environment and the performance of our business segments for the quarter. Generally we continue to see strong volumes coming into our system from producers, particularly from the Piceance Basin in Louisiana where some offshore production was restored after service was resumed on pipelines that were impacted by last year's hurricanes.

Despite lower rig counts in most of the areas where we operate, volumes held up well due to a backlog of well connects, new gathering systems being connected to prior facilities and shallow decline curves in the San Juan basin. We also saw strong demand from our hydrocarbon consuming customers.

NGLs continue to benefit from the high relative cost of crude oil to natural gas. NGLs were the preferred feedstock for the petrochemical industry and additives from motor gasoline due to its cost vantage of the more expensive crude oil derivatives.

During the third quarter, ethylene steam crackers operated at an annual production rate of about 50.5 billion pounds, essentially flat with the operating rate for the second quarter. Ethane demand was approximately 812,000 barrels per day for the third quarter. This compares with a five-year average rate of 52.6 billion pounds of ethylene production and ethane consumption of 745,000 barrels per day.

Looking at the forward curve for the next 12 months, ethane continues to be the only feedstock that is consistently profitable. As a result of ethane profit margins and the petrochemical industry's long-term expectation that crude oil will be more costly relative to natural gas, ethylene producers have completed or are in the process of making modifications to their facilities to enable them to consume more ethane or ethane-propane mix.

These modifications could result in over 100,000 barrels per day of incremental demand for ethane and EP mix. We began to see the impact of these modifications this month. Currently we estimate that industry is operating at an annual rate of approximately 50 billion pounds and consuming 850,000 barrels per day of ethane, including ethane contained in EP mix.

For the third quarter of 2009 gross operating margin for the NGL pipelines and services segment increased $56 million or 17% to $392 million with all three of the underlying businesses reporting improved performance versus the third quarter of last year. The NGL pipelines and storage business accounted for $50 million of this increase on a 223,000 barrel per day increase in volume.

While the Mid-America and Seminole pipeline system and our NGL export facility accounted for the majority of this increase, most of our NGL pipelines reported increases in gross operating margin and volume for the quarter. Our natural gas processing business recorded another good quarter with gross operating margin of $239 million.

Equity NGL production increased 6% to 116,000 barrels per day due to higher volumes from our Meeker and Pioneer processing facilities in the Rockies and from our Louisiana plants. We currently have about 74% of our Rockies equity NGL production for the remainder of 2009 hedged at a margin of approximately $0.66 per gallon with the margin being the price at which we sold our NGL (inaudible) less the natural gas cost of the shrink.

We've also hedged about 52% of our equity NGL production from percent of proceeds contracts. We have not executed any natural gas processing hedges for 2010 but we're continuing to evaluate opportunities. Current processing margins for ethane in the Rockies have remained attractive at approximately $0.32 per gallon before transportation and fractionation, supported by strong demand by the petrochemical industry.

Gross operating margin from our NGL fractionation business increased 21% to $31 million for the third quarter based on record fractionation volumes and lower fuel costs. Our NGL fractionators continue to run at near capacity.

Our onshore natural gas pipelines and services segment reported gross operating margin of $62 million this quarter compared to $88 million for the third quarter of last year. This decrease was due to a $27 million decline from the San Juan gathering system that had lower transportation fees which are indexed to natural gas prices and also from lower revenues from condensate sales.

San Juan natural gas prices averaged $2.88 per MMBTUs this quarter compared with $8.48 for the third quarter of 2008. And while lower gas prices reduced profits for this segment, Enterprise as a whole benefited from these lower prices through a decrease in fuel costs in our NGL pipelines, fractionators, butane isomerization facilities and propylene fractionators.

Total onshore natural gas transportation volumes increased 9% to 8.2 trillion BTU's per day in the third quarter of 2009. This month, the Collbran Valley pipeline in the Piceance Basin began service, flowing an incremental 30 million cubic feet a day of natural gas into our Piceance gathering pipeline.

Volumes are expected to increase to about 80 million a day by year-end. The Piceance gathering pipeline is currently moving over 900 million cubic feet a day of natural gas into our Meeker gas processing complex.

Our Sherman extension expansion of the Texas intrastate system began service at the beginning of August, earning approximately $5 million per month in demand revenues, irrespective of actual throughput. The Sherman extension is currently flowing about 700 million cubic feet a day.

Last month, we announced a long-term agreement to provide natural gas transportation and processing services on dedicated acreage owned by one of the largest and most active producers in the developing Eagleford Shale play in South Texas. This agreement covers more than 150,000 acres in the heart of the Eagleford Shale region.

We are strategically positioned to benefit from this emerging gas play with processing capacity of more than 1.5 billion cubic feet a day over 8000 miles of natural gas gathering and transportation pipelines and a direct link to the largest NGL hub in the world at Mont Belvieu. Because of the close proximity of our facilities to the Eagleford Shale, only modest capital expenditures will be needed for us to provide additional midstream services for producers in this important region.

Yesterday we announced our plans to extend our Acadian pipeline system into the Haynesville region in Northwest Louisiana. Our Haynesville extension will provide producers in the rapidly expanding Haynesville Shale play access to attractive markets through connections with Acadian's existing 1000 mile pipeline system in South Louisiana which has over 150 end use markets, rapid cycle salt dome storage capacity and an ability to make physical deliveries into the Henry Hub.

The Haynesville extension will also connect with nine major interstate pipelines. Based on current estimates, the Haynesville Shale play covers almost 2 million acres and current production is more than 1 BCF a day from over 200 wells. This shale play is estimated to have the lowest finding and development cost per MCF compared other shale plays except for the Barnett.

I will stop there since Hank will discuss more about this pipeline project a little bit later. I will just say that we are excited about the prospects of having a foothold in yet another major shale play in the United States.

Gross operating margin for the offshore pipelines and services segment increased to $56 million from $18 million last year. Gross operating margin for the third quarter of this year included a charge of $33 million for a litigation settlement and $18 million of recoveries under business interruption insurance related to the 2008 hurricanes. The third quarter of 2008 includes $35 million of hurricane repair expenses.

After adjusting for these nonrecurring items, the comparable gross operating margin numbers were $71 million for the third quarter of this year compared with $53 million for the third quarter of last year, an increase of 34%. This increase was primarily attributable to the Shenzi, Poseidon and Cameron crude oil pipelines as well as the Independence Hub and Trail.

Our petrochemical services segment reported a 35% increase in gross operating margin to $50 million for the third quarter. The Partnership's octane enhancement business reported an $18 million improvement in gross operating margin this quarter due to higher volumes and lower operating expenses and our butane isomerization business reported a $4 million increase in gross operating margin due to record volumes this quarter.

On Monday of this week, we completed the TEPPCO merger, creating the largest publicly traded partnership with a current enterprise value of more than $30 billion. With approximately 71% of the outstanding units voted and 97% of those units voting in favor of the merger, there was overwhelming support of the merger by the TEPPCO unitholders.

The addition of the TEPPCO assets will diversify our portfolio of midstream assets and with the addition of the refined products and onshore crude oil businesses, our gross operating margin from fee-based assets will increase. We expect a seamless transition since the Partnership has been under common control since 2005 and we look forward to serving our customers and investors with a stronger and more diverse Partnership. And with that, I would like to turn it over to Randy Fowler to discuss other financial items.

Thank you, Mike. I would like to briefly discuss the income items below gross operating margin. Depreciation and amortization expense and operating costs and expenses for the third quarter of 2009 increased to $161 million from $138 million for the third quarter of 2008, primarily due to increased property, plant and equipment from the additions in the first half of 2009 and $7 million attributable to accelerated depreciation and the retirement of certain assets.

G&A expense increased to $34 million this quarter from $22 million in the third quarter last year primarily due to $10 million of merger related expenses. We reported $128 million of interest expense this quarter compared to $103 million for the third quarter last year.

Average debt outstanding increased to $9.4 billion this quarter from $8.1 billion in the third quarter of 2008 primarily due to debt incurred to fund growth capital investment and working capital needs. About $11 million of this increase is attributable to a lower amount of capitalized interest due to a decline in the amount of construction work in progress.

Turning to capital expenditures, we invested approximately $167 million in growth capital projects and $44 million in sustaining capital expenditures in the third quarter 2009. In terms of capitalization at September 30, 2009; Enterprise had $9.1 billion of debt, including the 100% of our $1.23 billion of hybrid securities and $463 million of debt at Duncan Energy Partners.

Adjusted EBITDA for the 12 months ended September 30, 2009 which is defined as EBITDA less equity earnings plus actual cash distribution from unconsolidated affiliates was $2.1 billion. Our consolidated leverage ratio of debt adjusted for 50% equity content in the hybrids to the last 12 months of adjusted EBITDA was 4.1 times at September 30, 2009.

Last 12 months adjusted EBITDA and leverage were negatively affected by approximately $33 million for the TOPS settlement and $14 million of merger related expenses that were incurred in the second quarter and third quarter of this year. Excluding these costs, the debt to adjusted EBITDA would have been closer to four times.

Leverage is elevated at September 30 due to the higher level of working capital that we have. We expect leverage to be less than four times at year end.

In September, we priced a public offering of $500 million of 10 year senior notes at a yield of 5.33% and $600 million of 30 year senior notes at 6.17%. We also raised $380 million in equity the markets in September, comprised of $230 million from a public offering of 8.3 million units which included the full over-allotment option exercised by the underwriters and $150 million from a private placement of 5.9 million units sold to EPCO Holdings, a private company controlled by Dan Duncan.

At the end of September, including the proceeds from the $1.1 billion offering of senior notes which closed on October 2, Enterprise had liquidity of approximately $2.3 billion. Adjusting for the repayment of a $500 million note maturity on October 15 and the repayment and termination of the TEPPCO credit facility on October 26 for approximately $819 million, Enterprise had liquidity of approximately $1 billion. Enterprise completed the exchange of approximately $1.66 billion of TEPPCO senior notes and $286 million of TEPPCO junior notes for new Enterprise notes with the same ranking, maturity and interest rate.

Enterprise's $12 billion debt portfolio pro forma for the TEPPCO merger is now approximately 17% floating with an average interest rate of approximately 5.8% and a weighted average maturity assuming the first call date for the hybrids of 9.1 years. Later today we expect to file on 8-K tabular financial and operating data for TEPPCO for the three months and nine months ended September 30, 2009.

This tabular data will be consistent with the data TEPPCO has historically provided in their press releases. Enterprise is scheduled to file its 10-Q for the third quarter on November 9. TEPPCO will not file a 10-Q for the third quarter. However, we will file interim financial statements for the three months and nine months ended September 30, 2009 for TEPPCO on an 8-K on November 9.

The merger will be accounted for as a reorganization of entities under common control which is similar to a pooling of interest. By December 1, we expect to file a recast of Enterprise's 2008 Form 10-K which includes the financial statements for Enterprise for the years ending 2006, 2007 and 2008.

In addition, we will also file a recast of the Form 10-Q for the period ended September 30, 2009 and we also plan to provide recast quarterly data for the first and second quarters of 2009 as well. This information will also include the reorganization of our business segments in light of the merger with TEPPCO which will be described in the recast of our 2008 Form 10-K. With that, I'll turn the call over to Hank Bachmann to discuss Duncan Energy Partners.

Thank you, Randy. We were pleased to report another strong quarter for Duncan Energy Partners, supported not only by a 134% increase in net income, but also by a significant increase in distributable cash flow.

In both cases, the increase was primarily attributable to the Midstream businesses that we acquired from Enterprise in December 2008 which we call the DEP II Midstream businesses. For the third quarter of 2009, we reported net income attributable to Duncan Energy of $24.8 million or $0.43 per common unit on a fully diluted basis compared to $10.6 million or $0.18 per common unit on a fully diluted basis for the third quarter of 2008.

Distributable cash flow increased to $34.6 million for the third quarter of 2009 from $7.6 million for the third quarter last year. Not only as a result of $21.6 million of cash distribution received to the Midstream businesses acquired from Enterprise in December of 2008, but also because of a $6 million increase in cash distributions we received from the businesses we acquired in connection with our IPO.

We continue to benefit from the cash flow generated by the DEP II Midstream businesses. And based on the Partnership's preferred return on its investment in these businesses, we expect to receive in the future at least $22 million each quarter.

On October 15, 2009 the Board of Directors of our General Partner declared a quarterly cash distribution rate of $0.44 per common unit which represents a 4.8% increase from the $0.42 per common unit paid for the third quarter of 2008. This latest increase in our quarterly distribution is our fourth consecutive increase and will be paid on November 5, 2009. Distributable cash flow for the quarter provided a solid 1.4 times coverage of this increased cash distribution. Now I would like to briefly discuss the performance of our segments for the third quarter.

This quarter our onshore natural gas pipeline business segment reported gross operating margin of $40.5 million compared to $41 million for the third quarter of last year. Natural gas throughput volumes for the segment averaged 4.69 trillion BTUs per day in the third quarter of 2009 compared to 4.7 trillion BTUs per day in the third quarter of last year.

Gross operating margin from the Texas intrastate system decreased $3.1 million this quarter compared to the third quarter of last year, primarily due to lower transportation volumes, decreased condensate sale and higher operating expenses.

Partially offsetting this decrease in gross operating margin was approximately $9 million of gross operating margin as a result of firm capacity fees from the Sherman extension pipeline that commenced commercial service on October 1 this year. The Acadian pipeline system and Wilson natural gas storage facility together generated a $2.6 million quarter to quarter increase in gross operating margin due to increased transportation volumes and lower pipeline integrity expenses on Acadian and higher firm storage reservation fees from the Wilson facility.

Mike mentioned the new extension of our Acadian pipeline system called the Haynesville extension to the Haynesville shale play in Northwestern Louisiana. This pipeline is initially designed to transport up to 1.4 billion cubic feet per day of natural gas from the Haynesville Shale to our Acadian pipeline system and additionally, nine major interstate pipelines.

By leveraging our existing Acadian and Cypress systems, we will be able to provide Haynesville producers additional takeaway capacity and market access for their production and better equalized natural gas supply and demand on our Acadian and Cypress pipeline systems. The pipeline will connect Haynesville producers to markets other than Perryville and will keep significant quantities of gas in Louisiana as opposed to exporting all of their production into intrastate markets.

If additional long-term commitments are received before pipe orders are placed within the next week or so, the capacity of the Haynesville pipeline could be increased up to 2 billion cubic feet per day. We expect the new extension pipeline to be in service in September 2011.

Turning now to our NGL pipelines and services business segment, gross operating margin for this segment increased to $28.3 million for the third quarter of 2009, up from $20.2 million for the third quarter of 2008. After adjusting for measurement gains associated with the Partnership's Mont Belviue storage facility recorded in both quarters, gross operating margin this quarter increased 44% over the third quarter of last year.

This increase was attributable primarily to higher storage fees and volumes and lower operating expenses at our Mont Belvieu storage facilities. As a reminder, operational measurement gains and losses at our Mont Belvieu Texas storage facility are allocated to Enterprise and reflected in our financial statements as an adjustment to noncontrolling interest.

NGL transportation volumes decreased to 105,000 barrels per day in the third quarter of 2009 from 115,000 barrels per day in the third quarter of 2008. NGL fractionation volumes averaged 74,000 barrels per day this quarter versus 78,000 barrels per day in the same quarter of last year.

Our petrochemical services business reported increased gross operating margin of $2.8 million this quarter and $2.5 million for the third quarter of last year due to higher transportation volumes and lower operating expenses on the Lou-Tex propylene pipeline.

Total petrochemical transportation volumes averaged 35,000 barrels per day this quarter versus 33,000 barrels per day reported in the third quarter of 2008. Sustaining capital expenditures were $13.8 million in the third quarter of 2009 compared to $13.5 million spent in the third quarter of 2008.

Approximately $11 million of this $13.8 million spent this quarter was for the Midstream businesses acquired in December 2008. Through nine months, we have spent $37 million in sustaining capital expenditures. We expect to spend approximately $55 million for the entire year. This compares to $54 million spent in 2008.

Interest expense increased to $3.4 million for the third quarter of 2009 from $2.8 million recorded in the third quarter of last year, due to higher average debt outstanding as a result of our borrowing $282 million to fund the cash portion of our acquisition of the DEP II Midstream businesses.

Total debt principal outstanding at the end of September 2009 increased to $463 million from the $212 million at the end of September of last year, primarily as a result of our December 2008 borrowing. We had total liquidity of approximately $147 million at September 30, 2009 which includes availability under our $300 million revolving credit facility as well as unrestricted cash.

In closing, we are excited about both the Haynesville extension pipeline project and the completion of the Sherman extension. And as I said the last few quarters, we are pleased to report another quarter of solid results and strong coverage of the cash distributions paid to our partners.

Randy, we are now ready to take questions on Enterprise or Duncan Energy.

Okay Molly, we're ready to take questions now.

(Operator Instructions) Steve Maresca, Morgan Stanley.

This is Spencer and I work with Steve. You guys talked about your presence in the Eagleford Shale earlier and said that CapEx is going to be modest. Can you elaborate a bit more on that? And is there much there that needs to be built or are you just going to benefit from your assets already there? And what are you hearing and seeing from the producers in that region?

Well in terms of capital, our guess is over the next year it's maybe 50 or $60 million. We've got pipeline assets in the Eagleford Shale. We've got seven gas processing plants in South Texas. We've got NGL pipelines coming out of there. So really it's some de-bottlenecking extending into some of the producing areas.

Okay and also, now that you have TEPPCO, what opportunities do you see with crude storage?

Recognize we've only owned them for 48 hours, but we are looking at what we might be able to do with the TEPPCO assets that may be a little different from what TEPPCO had historically done. Certainly interested in some of the assets they have near the Marcellus basin. So we are looking at opportunities there. We're looking at ways to further expand their crude business and really just apply some of the approaches that we used on the marketing side for our businesses to increase throughput through existing assets and really just organic growth around their existing assets.

Brian Zarahn, Barclays Capital.

On the Haynesville extension, is there potential expansion eastward outside Louisiana?

East out of Louisiana?

You guys are building an extension within Louisiana currently, right?

Yes, you're breaking up just a little bit. But suffice it to say that the pipeline we are planning comes out of Northwest Louisiana, down into our Acadian system and there it crosses a number of interstate pipelines. So there are multiple opportunities for production to move from the Haynesville into the interstate markets.

Is there -- I'm just looking down the road. Is there possibility for you to build an interstate pipe or are you just going to have interconnects with the existing interstates?

Our plan is to connect -- we already have existing connections through the Acadian system but we will have other connections with the Haynesville extension. We're not currently contemplating building an interstate pipeline.

Okay, in terms of the in-service date about two years from now, does that just give you time for permitting? I thought it may have been a little sooner than September 2011.

If we can get it in sooner, we will. But obviously there's permitting, there's right of ways, there's -- you've got to manufacture the pipe. There's a lot that goes into building one of these.

And then on TEPPCO, you mentioned you're going to give some results later at sort of high level. I know there's some issues with the charges for TOPS and the merger related expenses. But anything on pipeline volumes for TEPPCO and also anything -- how are you thinking about structuring your segment now post merger?

Brian, that's where we will come in and again, we will have data available for you at the end of the day today as far as the operating data and financial results for TEPPCO. And then as far as a recast of the segments, I don't think we can do it probably justice here. It would probably be better to come in and once we file the recast Form 10-K for Enterprise for 2008, we will go into quite a bit of detail as far as the segments and which assets are in each segment.

Let me go back to your question on the Haynesville. One of the things that we think gives an advantage over other pipelines at the interstates is that because we are an intrastate, we have a much shorter timeline. It's about a year less time to construct because of the regulatory process required for an interstate pipeline. So we think we've got a distinct advantage there as well.

Darren Horowitz, Raymond James.

First question, Mike, for you on the NGL side of the business, specifically the NGL export facility. With the cheaper relative price of the US dollar certainly here in the past few weeks and obviously cheap feedstock costs, it looks like your export docks probably going to be running full at about 250,000 through the end of this year. But can you give us a little bit more color into how you think the export dock could run into the first half of 2010 with the existing price curve?

I'm going to let Jim take that one.

We are already selling space on that export dock through -- in some cases, through all of 2010. We are getting inquiries. So we are quite bullish on what will be doing across the terminal at a minimum through the first half.

Jim, as you see the conversion of more of the heavies over to the light end crackers, how has that helped your ability to capitalize on the propylene market?

I guess Jerry is not here, is he? We are finding ourselves with propylene to be very strong and we are not -- we understand that as these guys crack lighter, we get kind of a double benefit. We sell more ethane and there's more of a pull for the propylene we produce.

So we are running pretty strong on our propylene plants, I think all but one small train. And we are getting a lot of interest not only for current sales, but a lot of interest for more term business.

Randy, a quick balance sheet question for you. You talked about your leverage getting down to under four times at the end of the year. And I know as of the end of the second quarter, you had about $640 million of NGLs that you had taken ownership of and were storing in your tanks and had sold forward. Can you give us a sense for how much that came back to you in the third quarter and more importantly, how much you think is going to come back to you in the fourth quarter?

Darren, I think actually in the third quarter, we probably utilized probably at the margin more working capital in the third quarter for some of these opportunities. At the end of the third quarter, we estimated having about $740 million worth of capital tied up in inventories, tied to forward sales and we think that balance will be reduced by $500 million going into year end.

Okay and then just one big question picture question, if I could. And it's really more centered around cost of capital and the competitive landscape for acquisitions. But when you look at your recent term debt issuance and your current equity yield and consensus or our estimates for your distribution growth, is it fair to say your cost of capital is about 7 to 8%? And taking that a step further, when you look to lever off that financial platform and you're looking at what's probably north of $100 billion in qualifying assets owned by the majors, where do you see the best return of potential cash invested?

Well, I think looking at the kind of snapshot cost of capital, it's kind of right there. In terms of opportunities to acquire assets, we look at all kinds of opportunities whether they are from companies that are just trying to shed parts of their business, whether they're companies that are in play, certainly waiting on majors to decide that it makes more sense for them to shed some of their mainstream assets.

And frankly weighing the benefits of those types of transactions against organic growth. And one of the advantages that we talked about in terms of our organic growth is that we're better able to control the outlay of capital and many times, those have higher returns because we plan those projects to take advantage of our downstream assets. So sitting here today, I can't tell you exactly what what we might be looking at over the next 12 to 24 months in terms of acquisitions, but suffice it to say that we look at a lot of things and you've got to kiss a lot of frogs.

Well as long as you're kissing the frogs and you're putting up the type of rates of return on your organic projects, it's all that counts. So I appreciate the color. Keep up the good work.

Michael Blum, Wells Fargo.

A couple of questions. One, Jim, can you go back to the propylene discussion? I guess if I read it correctly in your press release, you talked about seeing lower margins for propylene fractionation in the quarter. Can you talk about what's going on there?

Go ahead, Randy.

Yes, Michael, what we saw -- again, remember this goes back to compared to third quarter of last year. I guess unit margins we were seeing as being lower but we did see an increase in volume, propylene fractionation volume overall.

Okay, got it. And then going back to the question on the NGL inventories, it sounds like you're going to see --

Hey, Michael, one more thing. On those unit margins, one thing you could be also picking up in there is the value of some of the coal products in the third quarter of last year which just had a higher value than what they had in the third quarter this year.

Okay, got it. Just going back to the working capital and the NGL contango inventory you have got, is there any way to quantify I guess what kind of return you're going to see from that trade you made and that $500 million that's going to come out of working capital?

There is for us. We typically don't advertise -- give forward-looking information but those transactions generally have returns anywhere from 18 to 30%. In some cases, it's as low as 15. That's kind of unusual. In some cases, it's darn near 100%. But 20 to 25% on average is probably a ballpark.

Do you (multiple speakers)

That's an annualized number. So don't think $700 million times 25%.

Okay, got it. Just two more quick ones for me. One, I didn't see, unless I missed it, what you think you will spend on this new Haynesville project that you announced and how you would allocate capital between Enterprise and Duncan.

You didn't miss it. Good eye. When we presented that to the Enterprise Board and it was also presented to Duncan Energy Partners Board, what we both agreed was that as we develop the project, that we will agree upon a way to finance it and allocate the costs. But we have not announced the cost.

Okay, last question. Can you just talk a little bit about what you saw in the third quarter in your Texas intrastate pipeline system? Thanks.

Chris, you want to take that?

Texas intrastate, the pipeline itself, the volumes were down slightly, just a lot of it due to weather, a lot of it due to the spreads west and east across the pipe. When you throw in the increase on the Sherman offsetting last year our throughput and Sherman not in service, we were hauling gas out of the Barnett back west to (inaudible). This year that gas just went straight out the Sherman lateral out to the eastern pipes.

So the volumes on Enterprise Texas were down slightly. Remember we have a lot of our Enterprise Texas system sold out on a firm basis. So revenues were not off as much as the volume throughput. We still get our reservation fees irregardless of the throughput.

Okay, great. I lied, one more question. Chris, how do you see basis differentials, particularly across Texas, kind of shaking out over the next year?

We see a fundamental shift in the spread across the pipe. Last year at third quarter, I think the Houston Ship Channel spread was in access of $1. This year it was in more to the $0.20 range when you look at the three-month average. If you look at the last 30 days, it was more flat.

Due to the Haynesville coming on and due to the Sherman extension being able to displace the Barnett out to the eastern seaboard, not having to haul that gas back to the west, we see the demand out of Barnett staying flat, with supply decreasing. So that basis is coming in tighter with the Haynesville gas showing up over on the East Texas, North Louisiana corridor. We see congestion over in that side of the world. So the demand -- more supply, less demand over in that part of the world bringing the spread back into a more normal historical spread in the $0.15 to $0.20 range across Texas.

Great. Thank you very much.

Ross Payne, Wells Fargo.

On Haynesville, I just want to make sure, is Enterprise going to have their pro rata share of that project as defined as their ownership stake in DEP or can that change?

Ross, the way that this project is being developed by Acadian which is owned at 34% by Enterprise, 66% by Duncan Energy Partners, again as we develop the project a little further and think about how we are going to fund it as between Enterprise and Duncan Energy Partners, ownership of Acadian could shift. There's a lot of things that could happen. It may be that the ownership remains exactly the same. We just really haven't gotten to that point yet.

Fine, second of all, in the press release, I noticed that I guess South Texas volumes might have been down a little bit. If you can just kind of talk about that, I guess that's just laying down of rigs.

In the South Texas, it was just more or less lying down of rigs. But what you're seeing on the throughput side as far as the NGL is concerned, what's coming on on the Eagleford [is coming on in richer] content of the NGL value.

So you're not seeing it proportionate on the NGL side. Just your volume throughput is lower but you're getting higher GPM gas coming out of the Eagleford, what we are seeing thus far.

Also on the Piceance Basin, I guess volumes were up and yet profitability was a little down. I just wondered if you could speak to that a little bit.

Sorry, Ross, you were talking about the Piceance -- you were breaking up just a little bit.

I think I read that the Piceance volumes were up for the quarter but profitability was down a little bit.

Versus last year (multiple speakers)

Yes, it's just a matter of the margin last year, Ross -- this is Jim -- compared to the margin this year. I guess in the third quarter last year, you had quite a lot -- you had a much bigger spread then you have got today. But it's (multiple speakers)

Gotcha. Okay, that's helpful. Great job guys on all the other segments. Thanks.

Barrett Blaschke.

Couple of DEP questions. First of all, just some housekeeping stuff. Maintenance CapEx expectations for 2009-2010 at this point?

Maintenance Cap -- we said that we're going to spend 55 million for 2009. We really haven't done our budget, finished our budget yet for 2010. So we don't really have a good handle on that yet.

And remember, the $55 million also includes spending CapEx and maintenance cost for the DEP II businesses which really won't affect to any great degree our distributable cash flow.

The other thing was on the petrochemical business, it looked like the volumes improved pretty substantially. And just was wondering, are we back at a better rate for that now in your opinion?

If you're looking at the segment for a whole, the isooctane facility was profitable because we had some big expenses earlier. So (multiple speakers) quarter to quarter (multiple speakers)

Yes, but I think our pipeline -- our propylene pipelines are also doing better. We expect that to happen through the end of the year.

Finally with the Sherman extension, or I guess the Gulf Crossing finally flowing up closer to the expected levels, obviously this helps the Sherman extension. Any further designs on wanting to expand there?

Chris?

At this point, we're looking at just -- we're always looking at opportunities to sign up additional customers in the area. There's power plants that are located near our system that we're negotiating with to try and increase throughput. But right now with the rig count in the Barnett just holding flat and everybody running over to the Haynesville, we're pretty satisfied that we signed up everything under firm demand fees.

Sharon Lui, Wells Fargo.

Just a couple of follow-up questions for DEP also. For the Texas intrastate for DEP, is the variance primarily attributable to I guess the lower transportation volume, similar to EPD?

The answer is yes.

And for the NGL transport and frac volumes for DEP, I was surprised that the numbers were down year over year given the favorable fundamentals.

I think a lot of it has to do with South Texas gas production.

We have seen throughputs fall. That's one area in our whole system that we have seen some reduction in gas throughputs here. But again, when the Eagleford comes on, we think that will come back up.

Finally, a question about the Haynesville extension. Can you just give more color on who the anchor shippers might be and maybe the length of the contract?

Sharon, this is Chris. We won't give the names of any of the individual parties. But I will tell you we have signed up seven different parties. So we don't really have an anchor shipper which is very unique about a project of this type.

We have seven different parties, the lowest one being 100 million cubic feet a day. I won't give you to the range end of the range, what the high end were. As you saw in the press release, we are signed to nine different producer locations. So what we feel is very comfortable with is the diversity of the producer base, the diversity of credit risk and we don't have that one 900 pound gorilla driving this project; this is a nice project that the producers really wanted to drive home.

And maybe just the length of the contracts?

All of the agreements are 10 year agreement and some have options to extend beyond 10 years, all firm demand, very little commodity. It's 99% demand, 1% commodity. So all firm reservation fees.

John Edwards, Morgan Keegan.

Just what kind of processing volume increases are you expecting to come out of Eagleford?

(multiple speakers) how many of the producers sign up -- Jim (inaudible)

Yes, probably -- we've had reservoir people look at this thing and I mean it's all over the map. But I think a conservative one is what -- 1.5 Bcf a day that you could see out of kind of the sweet spot of the Eagleford? I think we -- that's about the best I can do.

(multiple speakers) the thing we are excited about is we're just all over the Eagleford with pipe and plant. So more and more, we are hearing people talk a lot more positively about it. We have -- I think you saw a press release where we have one producer that we have gotten a rather large acreage dedication from.

We're talking constantly to everybody that's down there, sending maps of our system to virtually all of them. I think now it's basically let's see how it develops. It's really rich, 6 to 8 GPM in some cases as high as 9 GPM down there (multiple speakers) incidentally a lot of condensate also which we think plays well with our TEPPCO deal.

Okay and the 1.5 Bcf sweet spot, that's where you're expecting to operate at or is that how much more you're expecting to capture?

That's new (multiple speakers) declines, of course.

Hey, John; this is Dan. Let me add a little bit more color to it. On the natural gas liquid side, I think we are the only company that has natural gas liquids pipeline that flows from the South Texas into the Mont Belvieu, Beaumont, Louisiana area for the petrochemical and the refineries and everything.

So we are the main one for the NGL takeaway. Those other people down there would be after the gas takeaway. You have got Kinder Morgan, they're heavy down there. You've got Energy Transfer that's heavy on takeaway. Then you've got some smaller people down there. But the NGL side, we're the only one that as of today I think is the only takeaway of natural gas liquid from South Texas into the Houston Beaumont refinery petrochemical world.

The real advantage that gives us is that market down there is fully served today. So anything that is extracted from that gas down there in terms of liquids has got to move out because the market is already being served. And you can almost say the same thing about natural gas. So we know exactly what we want to look like coming out of the Eagleford whenever this thing fully develops and it will require the liquids to move out and in large part, the gas to move out.

So you'll be able to capture quite a bit of basis spread on that?

We will be able to collect a lot of fees.

Okay and then in your NGL segment this quarter, the fee-based processing, I noticed it was down from the prior quarter, about 500 a day or so. What is driving that?

Yes, that is primarily based on just reduced volumes for the quarter compared to last year.

No, I mean quarter over quarter.

I think the same story.

Okay, but what was driving the decrease in volumes?

You had production laying down and rig activities less moving into this quarter from prior quarters. It's a continuing trend.

Primarily probably -- I will look at it. This is Jim. Where we have seen -- the only place we have seen a real significant decrease -- and it's not really significant -- but a decrease is in South Texas and that's where we do have a lot of our fee-based business. But I need to double check on it.

John, I'm not sure what you're calling fee-based. But also we have a lot of shut-in that happened in the Piceance Basin and the Jonah/Pinedale. To some extent, it's fee-based. To some extent, it's gets driven into the processing side.

But these are wells shut in because of price. It wasn't because the wells wasn't out there. They just shut the wells in, effective -- I think I'm right on this -- November 1. All the shut-in wells that we are familiar with I think is back on full stream starting November 1 and that includes Jonah/Pinedale, some South Texas deals and other places we feel that are coming back on stream effective November 1 because of price.

Okay, because I just noticed that you were 2714 last quarter. You came in at 2247 this quarter. So you are expecting that to come back up November 1?

Jonah/Pinedale All the shut-in gas that we know right now, all the people that shut in their gas, they have come back on November 1, I think 100% because of the price of natural gas.

Okay, and then any chance you could break out how much was provided by marketing?

Well marketing only takes product when -- they only take product -- it goes to our facilities. I don't know that we actually break down what's provided by our own marketing people versus what's breaking down. Because the producers themselves bring it on. Then from there, all we're doing is -- they may market but they'll put it in one end of our facility and take it out the other, the same as anyone else on the system. They all have the same choices.

I was thinking more along the lines -- it just looked like the margins per gallon that you were able to earn were pretty strong. And you indicated in the press release there was some marketing contribution there that contributed to that $239 million figure but the marketing number was not broken out. I was just wondering if you could give us an idea of what contribution was coming from that if you have it. I don't know if you have it.

We don't break out marketing separately because we really view marketing as part of the assets. It's really there to fill up the assets. Now clearly (multiple speakers) we've got these contango plays. Then that's a little different but it's just additive.

Okay and then I was just curious on the fractionation margins that -- those were down Q over Q. When you had mentioned that you were going to do a 75,000 barrel a day expansion. So I was curious, I think last quarter you were around $0.021, this quarter it looks like about $0.018. I was just curious, given the shortage, why the margins came down a little bit.

I think part of that is gas prices being lower. When gas prices go up, we usually collect a little more on fuel than we do when gas prices are down. We collect a little bit of margin on that fuel. And also, I think we've shipped more barrels to Louisiana through the joint venture fractionator of pro mix this quarter than we did in the third quarter last year. So the margins aren't quite as good in Louisiana because we're full at Mount Belvieu.

And then do you have what the equity and earnings from the unconsolidated affiliates contribution was from onshore?

John, we do not have that information broke out, not in front of us for this session. But we should be able to come in -- Randy should be able to follow up with you on that.

When we talk later, I'll give (multiple speakers)

Okay and then how much gas storage capacity do you have online now? I think you were supposed to -- you were scheduled to bring something online this quarter? Something was coming on at Mont Belvieu so for more gas storage?

Nothing on the gas side. It's December of next year we're supposed to come on with 5 BCF of additional Wilson's capacity and we're constantly looking at Petal for alternatives. But nothing was planned that I can think of unless it's on the NGL side.

Okay, so I'm wrong on that. What is the working gas storage capacity now?

Only about 27 BCF.

27 BCF. Okay, and then five is scheduled from Wilson for next year.

Yes, fourth quarter next year.

Okay and then in the press release, you mentioned that Shenzi, Cameron and Poseidon combined, they increase by $20 million. Do you have a breakdown on that?

John, we generally don't get that granular.

I can follow up later. (multiple speakers) and then how much was Independence processing?

Processing?

Yes, the Independence Hub, what was the volumes?

It was around 7 -- a little over $700 million for the quarter.

Remember the volumes were down a bit in the third quarter because we had work being done on the separators.

Okay and then are you running back up around 900?

No, we're at 700, 750, somewhere in that range.

We're running about 750 now with anticipation that it may increase a little but it will stay down in that range.

Okay and then finally, maintenance CapEx for the full year, what are you expecting now?

It is -- I think we're still -- still what we were talking about last quarter. I think it's about $186 million.

So there's quite a bit coming in the fourth quarter. Okay, great. Thank you very much.

Phyllis Gray, Dwight Asset Management.

I wondered if you could go over what drove the decline in cash from operations for the quarter and year-to-date?

Bear with us while we get back to that schedule. Probably the largest one item -- I'm looking back on Exhibit C of the EPD earnings announcement, second line from the bottom, the net effects of changes in operating account was $245 million for the third quarter 2009 and that's probably the most significant part of it. And that's again utilizing some capital for the contango opportunities, the forward sales opportunities.

John, coming back to you, you had asked about the maintenance CapEx. Probably closer to about $170 million for the full year. Sorry about that Phyllis. Just wanted to get that corrected out there.

Jet Theriac

Might be too soon to tell, but how can you better utilize TEPPCO's barge business? Is there a significant opportunity on the marketing side for you guys?

I think you're right. It may be too soon to tell. But with 48 hours, I know that Jim's probably got a better answer.

The one thing there is the barge business at TEPPCO has been operating at rates of 92% plus. So they've had a pretty good history of high utilization rates to begin with.

They do have some LPG barges that have recently gone into service. And so certainly with our business, there may be a way to utilize those a little differently. With our NGL production in South Louisiana, there may be a fit. But things that we will be looking at.

This is Dan Duncan. By being in the position I was, I sit in at a lot of TEPPCO -- well I set in on all the TEPPCO meetings. But basically I think the deal that we brought -- TEPPCO brought back in July, I think first that is ramping up and is doing a lot better on the Balkan side.

I think the overall barges -- and I'm going by memory now. I think both of the prices have leveled out. There's no more downside on pricing and they are actually picking up a little bit. So we feel that the potential in that business will be greater in fourth quarter and going on.

Where I think we're operating at now, probably 85, 87% of the capacity of all the barges which [that with operating] problems and everything, I think that's probably operating basically where full barges [always have]. We are expanding (inaudible) we have four big barges of natural gas liquids coming on.

But they have all been leased out for the next few years with an international oil company that's going to use them for propylene and other types of products. So we think the barge business will benefit to Enterprise and the things that Enterprise is thinking about doing and it would be -- it greatly benefit (inaudible) probably TEPPCO [which is coming from] because of the marketing facilities around the assets of crude oil, same as we have marketing facilities around natural gas and natural gas liquids.

Molly, we have time for one more question.

Selman Akyol, Stifel Nicolaus.

Just one quick question, if I may. In the quarter you recognized $18 million in insurance recoveries and I guess, what could we expect to come in Q4?

I think total recoveries were about $19 million. Mike, we might have another $6 million.

Maybe 5 or 6. Fortunately we're kind of winding it up.

Molly, if you would -- would you give our participants the replay information?

Thank you for participating in today's conference call. This call will be available for replay beginning at 1 PM Eastern time today through 11:59 PM Eastern time on Wednesday, November 4, 2009. The conference ID number for the replay is 38090382. Again the conference ID number for the replay is 38090382. The number to dial for the replay is one 800-642-1687 or 1-706-645-9291.

Okay; thank you, Molly. And thank you everyone for joining us on the call today and have a good day. Thank you. Good bye.