Enterprise Products Partners LP (EPD) 2010 Q3 法說會逐字稿

Good morning. My name is Thea and I'll be the conference operator today. At this time I would like to welcome everyone to the Enterprise Products and Duncan 2010 earnings conference call. (Operator Instructions). Thank you. At this time I would like to turn the call over to Mr. Randy Burkhalter. Sir, you may begin.

Thank you, Thea. Good morning and welcome to the Enterprise Products Partners and Duncan Energy Partners joint conference call to discuss third quarter earnings. Our speaker's today will be Mike Creel, President and CEO of Enterprise and general partner; he'll be followed by Jim Teague, Executive Vice President and Chief Operating Officer and then Randy Fowler, Executive Vice President and Chief Financial Officer of the General partner of Enterprise and also President and CEO of the general partner of Duncan Energy Partners. Also in attendance are other members of our senior management team.

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 management of both Enterprise and Duncan. Although management believes that the expectations reflected in such forward-looking statements are reasonable; can give no insurance that such expectations will prove to be correct. Please refer to our latest filings with the SEC for a list of factors that may cause actual results to differ materially from those in the forward-looking statements made during this call. With that I'll turn the call over to Mike Creel.

Thanks, Randy. Before we get started, just want to make sure everybody understands this is our earnings call. We're not going to talk about the pending merger with Enterprise GP Holdings. We're not going to answer questions on that. I would point you to the proxy statement that's on file with the SEC.

With that we reported solid earnings again this quarter supported by record natural gas transportation volumes and near record NGL, crude oil, refined products and petrochemical pipeline volumes. Gross operating margin for the quarter increased 29% over the third quarter of last year with four of our five business segments reporting improved results. Our NGL pipelines and services businesses reported strong results that were only slightly lower than last year. The largest improvement for the quarter came from our petrochemical and refined products services segment, which had record gross operating margin of $166 million, a 138% increase over the third quarter of 2009. Within this segment, our propylene fractionation business reported a $30 million increase in gross operating margin, due to higher spreads between polymer grade and refinery grade propylene. This was a result of lower volumes of petrochemical cracker sourced propylene combined with increased consumer demand for propylene derivative products.

Gross operating margin from our refined products business increased by $49 million this quarter, or $20 million after adjusting for the $29 million of charges taken by TEPPCO for its river terminals in the third quarter of last year, prior to the merger. The improved results were due to higher average pipeline transportation fees and increased volumes at our river terminals. Primarily due to increased demand related to agriculture in the Midwest and drilling in the Haynesville Shale. We also began commercial operations at a new refined products terminal in Port Arthur last June.

Gross operating margin from our octane enhancement business increased $15 million over the third quarter of 2009, due to higher production volumes in sales prices. Our Onshore Natural Gas Pipeline and Services segment reported a $46 million or 42% increase in gross operating margin on record transportation volumes of 11.7 trillion BTUs per day which were 11% higher than the 10.5 trillion BTUs per day in the third quarter of last year. This quarter-to-quarter increase was primarily related to shales plays , including the Haynesville, the Piceance Basin, the Barnett Shale and the Eagle Ford.

Slightly offsetting these increases in volumes were lower transportation of conventional production in South Texas, which was down by about 100 million cubic feet a day. We recently completed the expansion of our newly acquired State Line gathering system in the Haynesville Shale, increasing its capacity 75% to 700 million cubic feet a day. And for a relatively nominal cost, we can further expand the capacity by another 70%, to 1.2 billion cubic feet a day.

Our Haynesville gathering systems continue to benefit from the ramp up of volumes as more wells come on and Jim will go into more detail about our projects and commercial initiatives in the Haynesville and Eagle Ford Shale plays in a few minutes. We began service in late July on the southern half of our Trinity River Lateral Pipeline which accesses the heart of the Newark Field between Arlington and Ft. Worth, Texas. You may recall we began service on the northern half of the Trinity River Lateral last year.

Our NGL Pipelines and Services segment continues to post strong results benefiting this quarter from higher equity NGL production, strong natural gas processing margins and higher NGL transportation and fee-based gas processing values. Gross operating margin from gas processing plants increased by $9 million over the third quarter of 2009, primarily as a result of an increase in processing margins and equity NGL production in the Rockies. Gross operating margin for NGL Pipelines and Storage and NGL fractionation were up quarter-to-quarter due to increases in volumes of 7% and 2% respectively.

The Onshore Crude Oil Pipelines & Services segment reported slightly higher gross operating margin compared to the third quarter of last year due to increased transportation volumes which were up 5% or 30,000 barrels a day. Our South Texas Pipeline benefited from increased crude oil volumes from the Eagle Ford, our Seaway Pipeline had increased transportation from the local refinery market in Houston, our Red River Pipeline saw increased volumes from the Barnett shale and North Texas.

Based on our continued strong performance, we've recently announced an increase in our quarterly cash distribution to $0.5825 per unit or $2.33 on an annualized basis. This is a 5.4% increase over the distribution declared with respect to the third quarter of 2009, and is our 25th consecutive quarterly distribution increase and 34th increase since our IPO in July of 1998.

Enterprise generated $573 million of distributable cash flow, which provided 1.4 times coverage of the limited partner distributions for the quarter. We continue to believe it's important to retain a portion of our distributable cash flow to reinvest in growth capital projects to reduce debt and to decrease our need to access the capital markets. This quarter we retained $ 133 million or 23% of our distributable cash flow and for the first nine months of this year we retained $388 million.

Before I turn the call over to Jim I'd like to say, once again, how pleased we are with the strong results our business has generated this quarter and for the year-to-date. We continue to establish new performance records each quarter as our businesses benefit from strong demand for our many services. We believe our existing asset positions and some of the most exciting shale plays in the country will continue to provide us with new opportunities for additional organic growth and the ability to provide even more services for our customers. And as always, our employees continue to show why they're considered the best in the business as they work tirelessly to create value for our investors. With that I'll turn the call over to

Thank you, Mike. Energy metrics remain favorable for natural gas liquids and natural gas processing over the third quarter with the average relationship between crude and natural gas prices ranging between 30% and 35% on a BTU basis. That relationship is keeping processing spreads healthy and producers continue to focus drilling in rich gas plays. At the same time chemical companies thirst for light feedstocks continue to grow. We've seen light feedstock cracking volumes reach new highs in August and September this year, including some published estimates of ethane cracking at over 960,000 barrels a day in September. The movement toward rich gas plays and improved NGL recoveries has pushed production of NGLs from gas processing to highs not seen since 2001.

What I want to do is take a few minutes to discuss ethane supply demand balances as they're varied opinions. In fact, there's as many opinions as there seems to be consultants and they're all over the map. For ethane in particular, record high production and consumption has clouded some crystal balls, so I'd like to attempt to share Enterprise's perspective. In short, we believe that ethane is a positive story for US ethylene manufacturers and for NGL producers.

Last quarter EIA announced the ethane production from gas processing had reached a record high of over 840,000 barrels a day in March and some folks declared that the flood of NGLs into the market had started,and proclaiming that the sky was falling. Ethane consumption only averaged 835,000 barrels a day over the second quarter. This was due not only to plan, but also unplanned outages at crackers. And as a result, of course, inventories over the second quarter increased as one would expect.

In the third quarter supply-demand balances look a lot different. Over the third quarter, crackers consumed an average of 933,000 barrels a day of ethane, operating in the low to mid 90% range, according to Hodson. At the same time, ethane from natural gas processing dropped off to just under 800,000 barrels a day in July, and this is according to EIA. This shift in supply-demand fundamentals pushed ethane inventories lower, with a draw of nearly 6 million barrels. We continue to see ethane inventories decline through the fourth quarter.

Looking forward, we expect ethane extraction to increase as shale drilling expands in areas like the Eagle Ford and Marcellus. But the decline of natural gas produced from legacy wells must also be calculated in the overall supply projection. So even with layering on new ethane production, total ethane production from natural gas processing could reach just over 950,000 barrels a day by 2015. And this is very manageable level of production given that it ramps up over five years.

The demand side of the equation is dynamic when it comes to ethane. As US crackers continue to demonstrate a strong appetite for ethane, due to its significant price advantage, Hodson estimated last week that September ethane cracking averaged 960,000 barrels a day. That number is a little stronger than what we were expecting. But we believe that the industry can consume that much, and forecasts from companies like CMAI and EnVantage show ethane cracking forecasts that top 1 million barrels a day over the next five years.

Do not underestimate the US chemical industry's ability to consume more ethane. We were supportive in helping cracker operators shift as much as 100,000 barrels a day of feedstocks to lighter feeds in 2009. And we have seen ethane cracking creep at multiple facilities in 2010.

In addition to the conversions completed last year and the projects underway to expand or restart existing capacity, there continues to be evaluations regarding more expansions, debottlenecks and reconfigurations that would add up to over a million barrels a day of ethane cracking capability. We recognize that there will be temporary imbalances in the ethane market, such as in the second quarter, but overall we believe that the US market will balance supply-demand and that the glut of ethane that some have predicted will not materialize. That's because the US is becoming more competitive globally due to NGL feedstocks and US cracker operators will find a way to capitalize on this.

We've talked about how hard crackers ran last quarter, how much ethane was cracked, but there's a why. The why are the margins. Average third quarter ethane margins, according to CMAI, were above $0.15 per pound which compares to third quarter 2009 ethane margins of $0.07 a pound. This quarter's ethane margins beat competing feedstock economics by anywhere from $0.07 to $0.09 per pound. At $0.07 per pound if you had 1.5 billion pound a year crackerthat annualizes to over $100 million a year in advantage. Where I was born in Shreveport that's called opportunity.

The significant ethane advantage over other feeds is not just limited to the domestic market. US ethane cracking is near the bottom of the global production cost curve according to CMAI. US ethane cracking economics beat European and Asian naphtha cracking economics and even competes with Saudi propane and condensate cracking economics according to CMAI data. What that tells us is that not only will US chemical companies be profitable in the domestic market, but they will be competitive globally with downstream ethylene exports and that essentially takes the target off the US as an export destination for foreign produced chemicals.

Again we see this story as a positive story not only for NGL producers, but also US petrochemicals. US cracker operators are not the only beneficiaries of this shift to ethane cracking. Propylene from non cracker production is in high demand and splitter propylene volumes and margins have been strong all year. That's because propylene yields from ethane cracking is negligible, but downstream derivative producers continue to pull hard on propylene.

Splitter produced propylene in the third quarter was up more than 350 million pounds. Over the past year and a half propane exports have been increasing. Our export terminal has been at capacity and we continue to see strong demand. We've seen that terminal full for the last 18 months for exports. Our terminal is sold out through the end of the year and we're quickly filling lay cans throughout 2011.

Our assets remain the heart of our business and we continue to expand. At the Eagle Ford Shale our growth plans are in full swing and we continue to sign long-term firm agreements for processing, transportation, and fractionation. Our footprint in the area continues to expand in crude, natural gas and NGLs including new 140-mile crude oil pipeline, 168-mile rich natural gas main line, a 600 million a day gas processing plant, expanded natural gas storage, 127 mile NGL pipeline to deliver NGLs to Mont Belvieu and a 75,000 barrel per day fractionation expansion in Mont Belvieu.

Just yesterday we announced a ten-year agreement with Pioneer and their partners for natural gas gathering and processing, residue take away, NGL fractionation, and crude oil transportation. As you know, we have agreements now with EOG, Anadarko , PetroHawk, a few smaller companies, and now Pioneer. We're in active negotiations with several other producers. Should we be successful with all, we will probably be looking at expanding part of what we've announced. We call that a high class problem.

Our Haynesville extension project to connect multiple interstate gas pipelines and the Acadian system in South Louisiana is under budget, ahead of schedule and is expected to be in full service by September 2011. In the meantime, we're negotiating with several key parties to significantly expand our gathering footprint in Haynesville which in turn could lead to more capacity commitments. We have signed agreements for 1.6 bcf a day of firm capacity to date.

Our Rockies production remains strong. Our plants are close to full. We are producing over 100,000 barrels a day of NGLs from Meeker and Pioneer and margins continue to be strong.

Our hedging program for 2011 is active though we are being patient as we wait for our targets to come into view, particularly for the second half of 2011 which we think is undervalued. For the first quarter we've hedged 44% of Rockies production. We've hedged little after that as we continue to see a steeply backward dated NGL curve.

Our C4 chemicals business at Mont Belvieu is benefiting from a strong hedging program in 2010. And our hedging plan for 2011 is coming into view. C4 operations in Mont Belvieu this year have been particularly smooth relative to 2009, and demand for our products has been robust, again, due to fewer C4 co-products available from crackers.

We're continuing to invest in our asset base. We believe that what we are today was created in past years and what we will be in five years we're creating today. That's why we're so focused on supply basins such as the Haynesville, the Eagle Ford, and our position in the Rockies.

But we're also focused on the demand side of the equation. We're supporting petrochemical's appetite for more NGLs by upgrading our pipeline systems for deliveries, expanding our brand capabilities at our Mont Belvieu storage and adding fractionation. We're spending money to create more supply into our refined product assets, and we're expanding our marketing efforts to pull through more product through those assets. We're creating market options so that producers of Eagle Ford crude oil have choices as where they sell their production, either Cushing or the Houston ship channel.

In short, we know who we are. We're a midstream company. Our focus is to offer producers flow assurance and market choices and to offer consumers the ability to buy what they need, when they need it, and where they want it. And with that I'll turn the call over to

Okay. Thank you, Jim. Good morning. I'd like to just hit a few additional financial items.

Interest expense increased by $19 million this quarter due to higher debt balances in the third quarter 2010 which averaged about $12.7 billion, compared to last year which averaged about $12.2 billion. In terms of distributable cash flow, as Mike mentioned, distributable cash flow for the third quarter for 2010 was $573 million. This includes approximately $65 million of proceeds from the disposition of certain minor assets.

In terms of capital spending we invested approximately $591 million in growth CapEx this quarter. Through nine months we've spent about $2.5 billion, and to expect to spend approximately $3 billion to $3.1 billion in 2010, which includes the $1.2 billion for the acquisition of the M2 Midstream Pipeline business back in May 2010. Some of the larger approved capital projects for 2010 include the Haynesville Extension Pipeline, the projects in the Eagle Ford that Jim mentioned, the expansion of the Mont Belvieu fractionator, the Trinity River Basin Lateral that was recently completed and the Anaconda Pipeline Extension.

We spent $72 million in sustaining CapEx in the third quarter 2010, and $177 million through nine months. We still believe we'll be in the range of $240 million to $250 million for sustaining CapEx for total year 2010.

In terms of capitalization, adjusted EBITDA for the 12 months ending September 30, 2010 was $3.2 billion. Adjusted EBITDA is defined as EBITDA less equity earnings, plus actual cash distributions received from unconsolidated affiliates. Our consolidated leverage ratio of debt to adjusted EBITDA for the last 12 months was 3.7 times at September 30 after adjusting debt for 50% equity treatment for the hybrid securities. Our floating interest rate exposure was approximately 11% at the end of the quarter. The average life of our debt was ten years, which incorporates the first call date for the hybrids. And our effective average cost of debt was 5.9%. We had liquidity which includes the availability under EPDs consolidated credit facilities, plus unrestricted cash, but excludes availability under DEPs credit facilities of approximately $1.8 billion at September 30.

Now turning to Duncan Energy Partners, this quarter we are pleased to report record gross operating margin of $74.4 million. We've benefited from higher through-put volumes on all of our pipelines and increased NGL fractionation volumes. Our Natural Gas Pipeline business reported a 14% increase in gross operating margin this quarter compared to the third quarter of last year, primarily due to higher firm capacity fees and through-put on our Sherman Extension Pipeline in the Barnett Shale. The Sherman Extension Pipeline began commercial service in August of 2009. So we got a benefit of a full quarter this year.

After adjusting for nonrecurring charges, net income attributable to DEP was $25.8 million or $0.45 per common unit this quarter compared to $24.8 million or $0.43 per common unit for the third quarter of last year. Distributable cash flow for the third quarter was $33.8 million and enabled us to increase the quarterly cash distribution rate for the eighth consecutive quarter and represents a 2.8% increase over what was paid to partners in the third quarter of last year. It also provided 1.3 times coverage of the quarterly distribution. We retained approximately $7.5 million of distributable cash flow this quarter.

We are making good progress on conversion of the first of two NGL storage caverns to refine products at our Mont Belvieu facility. We expect to have the first cavern which will store up to 2 million barrels of refined products and service by the end of November. We are currently leeching the second cavern which should be completed sometime next year. The storage caverns will earn higher storage revenues and refined products service compared to storing NGLs.

DEP reported $292 million in consolidated growth capital expenditures in the third quarter of 2010 which includes approximately $200 million for the Acadian Haynesville Extension Pipeline project. That's on a 100% basis. DEP 66% portion of this amount was approximately $132 million. The total expected costs of the 270-mile Haynesville Extension Pipeline project remains at approximately $1.56 billion, including capitalized interest of which Duncan Energy 66% share would be $1.03 billion. Sustaining capital expenditures for $11.6 million this quarter compared to $13.8 million spent in the third quarter 2009.

At September 30, 2010 DEPs debt to LTM EBITDA ratio calculated per its bank credit facility was 3.2 times. Under this facility DEPs maximum allowed debt to EBITDA is five times debt to EBITDA. The agreement also allows us to pro forma a pro-rata amount of EBITDA associated with growth capital projects under construction in calculating this ratio. That will be a big help as we come in and build the Haynesville extension over the next year.

A significant event for our partnership was the execution of the $1.25 billion of senior unsecured credit facilities which we completed yesterday. We were very pleased with the support of our banks to participate in these facilities and we saw commitments exceeding $2 billion. This is a major accomplishment for DEP as these new credit facilities provide us with significant financial flexibility as well as the ability to substantially fund DEPs entire portion of the Haynesville Extension Pipeline project.

These facilities which consist of $850 million multiyear revolving credit facility and a $400 million senior term loan facility allowed DEP to terminate and repay its $300 million bank revolver that was due in February 2011 and it's $200 million revolving credit facility with Enterprise which had $125 million outstanding at September 30. Both of the new credit facilities mature in October of 2013.

At December 30, 2010 DEP had total liquidity of $140 million which includes cash and availability under the partnership's revolving credit facilities. After adjusting for the execution of the new credit facilities and the related repayment of the terminating facilities, DEPs liquidity would have been approximately $860 million at September 30.

In closing, we are pleased with the continued strong performance of our business, the execution of the new credit facilities which is a major step in funding the Haynesville extension and we are encouraged by the growth prospects of our partnership. With that Randy, I think we're ready for questions.

Okay. Thank you, Randy. Thea, we're ready to take questions from the audience now.

(Operator Instructions). We'll pause for just a moment to compile the Q&A roster. And the first question will come from Ted Durbin with Goldman Sachs.

Hey, guys. First question is, Jim, can you talk a little bit more about the potential for these conversions, the timing of when you might see these chemical crackers convert to run the lighter ends, what you're hearing in terms of potential, even restarts and things like that, especially on the ethane side for ethane demand.

I can't talk too much because in a couple of cases we're in negotiation with folks. Needless to say, we're in negotiations with one in particular. I haven't gotten an update on where we are. But probably be another 25,0000 to 30,000 barrels a day with a capability to go higher. And I think you've had Williams announce that they're going to expand their Geismer cracker. I think it's another 12,000 to 15,000 barrels a day of ethane. Eastman has announced -- first quarter that they're -- go ahead, you can talk.

10,000 barrels a day.

10,000 barrels a day of ethane and propane on a cracker they have up in Longview. I'm talking to [Don Johnson] who keeps all this stuff for us.

Okay. That's great. Thanks. And then if I could just shift over to the offshore. Now that the moratorium has been lifted. How are you thinking about the outlook for what the volumes do there realizing that the drilling may not pick up quite as quickly as some may think?

Well Ted, we've already seen the volumes on Independence Hub come back a bit. We were down pretty low. We're back up now. Bouncing around between 500 million and 550 million a day. We do expect -- even though the moratorium has been lifted, I think there's still some uncertainty about the timing on the resumption of drilling. But at least it does allow producers to get back in and recomplete some wells and hook some other things up. Jim?

We were pretty excited. We were also pleased to see Chevron's recent announcement. What did they call that in The Chronicle? A floating city? We know they've got several other leases that are in proximity to our pipes, Mark.

Yes. And we expect to see the volumes bounce back. But it's going to take a while. And I think realistically we're talking second half of 2011 before we see any significant volume come back as a result of resumption of drilling.

Okay. Great. If I could have one more. In terms of the Belvieu cracker it looks like you accelerated the timeline on that. Now you're talking about getting it done here at the end of November. I mean what kind of change allowed you to get that online faster and should we expect that there's an opportunity to bring the second phase earlier than 2012?

You make Bill Ordemann real nervous. So we'll let him answer that.

I think the good news is we did declare a mechanical completion on that cracker. All of the systems were turned over to operations here. I believe it was Friday, Rudy. And operations has them now. They're in the process of commissioning and starting up the equipment.

There's an outside chance we could have that running in a week. I think two weeks at the most right now. Depending on what we see. Just depending on how the commissioning goes and what kind of problems we run into. But so far things are looking really good to have that up and running in the foreseeable future. So we've pulled that back from the original date of I think it was March of 2011 (sic - see Press Release).

Right.

Here about mid-November I think at the latest. We are working on the next cracker there now. And looking at the schedule and trying to pull that back as well. I think there is a pretty good opportunity we'll be able to pull that schedule back into the latter part of 2011 as opposed to the early part of 2012.

Okay. I appreciate it. Thanks.

The next question will come from Darren Horowitz with Raymond James.

Hey, guys. Good morning. Jim, appreciate the color that you gave on the NGL market. I've got a couple quick questions for you. When you look at the cost advantage of cracking ethane and the expectations for that to continue, of course, as you detailed the associated tightness across the propylene market, how much visibility do you have into the favorable spread between polymer and refinery grade propylene continuing? And is there any way for you guys to lock in the spread going forward?

Well, we've tried Darren. But it's not as liquid as you'd like it to be, so you can lock it forward. So the answer is, you try, but you can't do a lot of it.

yes. yes. And then switching gears over, Jim, to the Rockies equity NGL production. You mentioned that 44% of the first quarter production was hedged. Would you care to comment as to what price? And also secondly, with the positive tail wind to ethane and, of course, what we're experiencing as it relates to Gulf Coast experts, how do you balance how much you hedge versus how much you keep spot? Because I'd love to know.

No. I won't care to comment on what we locked in primarily because I'm a little embarrassed by it because we were a little early. Things look better now. We basically backed away and right now we're looking at a forward -- you know the NGLs are so backward dated and they always will be I guess. But you're getting in the first quarter up into a range where it's starting to look more interesting in the $0.28 to $0.30 a gallon for ethane.

Darren, your question is, how do we determine how much to hedge? It really is based on price in our field. We haven't historically hit the highs in the market when we hedge. But we lock in strong cash flows that we think are good for the partnership.

Sure.

That's what we're doing now. We're looking forward to see what makes sense for us.

Sure. Just one final question if I could for Skoog on State Line and Fairplay. Could you just give us where are you running right now relative to name plate capacity?

We're running State Line between around 425 million a day and Fairplay is riding the 160 million to 170 million a day. Both those are up from where we bought them. As one of our competitors comes into service in 2011 first quarter, we should see the volume start to ramp up with the significant ramp up occurring in third quarter when we get our Haynesville take away project into service.

I appreciate it guys. Keep up the good work.

The next question will come from Stephen Maresca with Morgan Stanley.

Hey, good morning everybody.

Good morning.

Thanks a lot for the detail, Jim. Very appreciated. And one of my questions is with regard to that. What do you see as the biggest risk for this NGL story? You gave a lot of detail on the supply and demand side, kind of being favorable. Do you think, if there's a risk to being wrong, it's a risk more on the supply side? That there's more to come with producers being so focused on liquids rich areas and trying to get the most that they can out of there? Or how do you view it?

Really it's a risk of the economy in general, as far as I'm concerned. Because right now these guys are running over 90% and they've got strong margins, primarily on the back of natural gas liquids. I guess if you saw a compression between crude and natural gas, that could have a mitigating effect.

Okay. Are you guys seeing any producers move from some of the dryer gas areas? Areas like the Haynesville where you're seeing producer activity decline a little bit in recent weeks and months because of gas prices?

We have a reservoir group on staff and overall we've seen rigs start to move toward the Eagle Ford. We are in the sweet spot of the Barnett with the Newark Field. And we are in the sweet spot of the Haynesville. So we are seeing the drillers stay active in both those areas. And the Haynesville especially, you got a lot of acreage dedication that needed to be held. So we see pretty robust drilling to hold that acreage through the next, let's call it 12 to 18 months. And at that point then hopefully gas prices rebound a little bit and you see them maintain. But the southern half of the Haynesville Basin where we're focused on our gathering system and what we've developed proprietarily down that end of the system is the sweet spot. And we've got a two or three [stag] zone, the Bossier play as well as the Haynesville Shale. We've got two or three payout zones there to play with that producers are really focused on.

Okay. And my final question, I guess for Randy on the Duncan side. In terms of now that you have the big financing that you just closed on. Is that the plan going forward for the Haynesville spending, to use the available capacity you have and then with the pro forma allocation, the account with EBITDA, use that to apply to the leverage metrics and not essentially do any equity with DEP?

Steve, our thoughts around Duncan energy financing, the Haynesville sort of have evolved since May when we announced how much of the Haynesville DEP would take. Then we were talking about financing it at DEP with 50% equity, 50% debt. Really we've rethought that. Probably equity will be much less. The credit facility that we executed yesterday gives us the flexibility, where really we could finance the remainder of the capital expenditures off that credit facility. Then what we could do is as we look out, is continue to say a distribution growth rate similar to what we're doing. A couple percent, 2.5%.

And then the excess distributable cash flow that's generated, once the Haynesville extension comes back up, we could use that excess DCF to come back in and delever Duncan Energy Partners back down to a leverage metric we'd be comfortable with. Right now the way we look at it is we've got a lot of flexibility as to how we'll fund the Haynesville extension. As far as looking from a DEP standpoint, probably not nearly the equity requirements that we were talking about back when we were saying 50% funded with equity.

Okay. Thanks a lot, guys.

The next question will come from John Tysseland with Citigroup.

Hey, guys. Good morning. Great overview. Are you guys still seeing positive rollover on expiring NGL transport frac contracts? And then also secondarily to that. What length of new contracts are you able to lock in these days? If you could elaborate on that.

You want to? Have you got anything on the --

We're working on some renewing them for ten-year terms, Jim.

Basically I think by and large, who is that, John?

Yes.

By and large, John, we try to do ten-year deals if we can. Now the guy doesn't want to do a ten-year deal and wants to do seven, we haven't been known to walk away from business. But what we're trying to do on all of our arrangements is to have a longer term and to have a deficiency component as it relates to that asset. I'll give you an example in our fractionation contracts. I think we've been pretty vocal about this. All of our frac contracts now have a deficiency component. We started out giving them maybe 20% leeway. I think, Rudy, we're up to about 5% now. And basically what that says is, traditionally those contracts were designed to be dedications, if you brought your product to Mont Belvieu. Consequently that ethane rejection swing was on us. We're not doing that any more. So now if you want 20,000 barrels a day at capacity, you've got 20,000 barrels a day at capacity. And then we structure the contract so that there is a certain amount of ethane that makes up that capacity. So you can't cram 20,000 barrels a day of propane plus to us and meet that obligation. That help?

Yes. It does. Actually it kind of helps with my other question I was follow up to that. When you are talking to new producers or producers and negotiating new volume agreements with those producers to commit for capacity and transport and frac, do they anticipate doing 100% of their expected ethane production? Or do you see them taking something less than that? Maybe discounting some rejection in the future, for example, some of these new contracts that you have in the Eagle Ford or new areas?

It's a dilemma for them. And I don't really know if they're discounting any ethane volume or not. I don't think so because think about it, fractionation capacity is unbelievably tight. So to the extent you do that you run the risk of not having a place to fractionate your production if you're all out.

Right. I guess you just don't know at least what the producers are thinking at this point. Okay. On the other side when you look at storage you saw storage pretty much max out in May or June. You saw it come down a little bit in July. You mentioned this in your comments. Any idea where we stand today with the massive ramp-up, and we've seen in demand on the petrochemical side, where those inventories are?

Well, I've got a real good idea. But I doubt if I can tell you. I'll tell you that from our perspective, we don't have as much, Rudy, in storage this time of year as traditionally we have across the across the board. I think is fair to say?

Nowhere near as much as last year.

We spend a lot of time taking a look as we go into the winter how much brine we've got and we're balancing that on what we expect the pulls to be. I'll tell you our brine is not at the levels traditionally we would want it to be. Frankly, it doesn't need to be where we are on inventories of finished products.

Great. Thanks for the detail.

The next question will come from Yves Siegel with Credit Suisse.

Thanks and good morning, everybody. I just have several follow-ups. One, Randy, when you looked at the credit facility down at DEP, what's the difference in costs of the debt at DEP versus if you did it up at the Enterprise level?

As far as the bank credit facility, I'd say it was really on top of what DEP could have done. Maybe EPD could have -- maybe an eighth, maybe a quarter. But DEP got excellent execution on the bank credit facilities. And again I come in and I think we've gotten a lot of questions over the last 18 months of access to capital. What are you seeing out of your bank group? What an exclamation point by the support we are getting out of our bank group to have commitments over $2 billion. So we really feel good and appreciative to our bank group for that.

So really when you think about cost of capital between the two entities, doesn't sound like there's a whole lot of difference?

Not when it comes to the bank credit facility side, no.

Yes. Okay. If I could just push a little bit forward in terms of thinking about the Haynesville and Chris' comments. Even though you're in the sweet spot, what kind of gas prices do you think you need to see economic activity down there? And it gets back to also Jim's crystal ball comment. You know mine is pretty cloudy, too. When you think about the next few years, where do you think gas prices go to?

That's kind of a loaded question. Last April at the analyst's meeting we had here in town, I talked about a $4 to $5.25 range. I wish that we were at the lower end of that. If you look at the forward curve for the next five months, we're below the lower end of that. If I was predicting gas prices I wouldn't be here. If I was accurate at it.

Just the shale plays over all I think the Haynesville -- it's the marginal production that's driving all the natural gas prices. Because when a Haynesville well comes on, it's coming on at 20 million to 30 million a day IP. It's the discretionary gas that has to continue to be drilled to hold this acreage or these producers get to walk away from the acreage. They're going to lie to the Street or they're going to perform. And that's the wild card.

So the next 12 to 18 months, we think they're going to continue to drill in and around our assets, worse having a rig count of north of 50. So we're very comfortable with where they're at and the key producers that we deal with are all telling us a 12 to 18 month inventory to hold the acreage.

What about the joint ventures that they've entered into? Doesn't that have an effect, too?

Right. Then a couple of big players in the Haynesville and now down in Eagle Ford, you're seeing a lot of these good mid-sized to major producers, teaming up internationally with foreign money and they're drilling with what I call 50-cent dollars. So they've got equity up front. They get a large infusion of cash and then they get their drilling paid for another bank of dollars. So their economics are a little different than the average little guy that's trying to do it all himself.

So we're comfortable that where we built our pipeline, we've really focused on the geology and making sure our pipelines are in the right locations to maximize the fields. Like I said I attribute that to our reservoir group internally here that they don't have a horse in the race. They're not talking their book, they're looking at just the geology and saying this area makes the most sense for us to be in. And like I said, they're not talking their book. They're just talking about real value for us. So I give them a lot of credit to why we are located where we're located.

And when we run the economics, we're using some pretty conservative cases. We're not assuming that E&P companies are drilling full out. We're using kind of a middle of the road case. Remember on our Haynesville extension, we have demand charges on there. And we're not designing that for peak production in the area either. So we think we're protected all the way around.

Okay. I appreciate that. And then just thinking longer term here, you're going to spend $3 billion, a little bit more this year on growth capital. As you look at your opportunities for the next few years, any thoughts on what that amount could be over the next couple of years? And how do you think you might spend that amount?

Sure. We've got that $3 billion that we keep batting around for gross CapEx this year includes the $1.2 billion for the mid-stream assets that we acquired back in May. For 2011 probably something in the $2.5 billion range is reasonable given what we're spending, again, to finish up the Haynesville extension and the Eagle Ford Shale project that we've got. After that we don't have any really big individual projects.

We've got a lot of opportunities to fill out around the system that we're kind of creating the backbone for now. But we think that there's plenty of opportunities. In fact, if you look at our wish list of projects, we've probably got a back log of maybe $6 or $7 billion of projects. Clearly, not all of those have to be done this year or next year. But we've got enough to keep us busy.

Okay. And I promise. I've just got two last ones. One is, I couldn't help but notice that you did not bid on the Cameron Highway. Can you talk about how you see the Gulf of Mexico and is that a place that you want to see potential for future dollar investments?

Kind of two things. When Valero started the process the BP incident happened right in the middle of it. That was a bit of a turnoff.

But as you said with $3 billion of growth CapEx this year, we had enough on our plate and frankly we think that our projects in the Haynesville and the Eagle Ford do a lot more for the partnership. They're certainly more stable cash flow sources, provide more of an integrated value-chain approach. We thought that was a better use of our money.

Again for 2011, I think our emphasis is going to be onshore again. Finishing building these backbones in the Eagle Ford and Haynesville. And providing a platform for long-term growth for the next several years.

And last question. Where do acquisitions play in terms of your playbook going forward? When you think about your wish list? Are there any acquisition opportunities that may come up that's on that list?

I'll take a first crack at it and then I'll turn it over to Jim because he may have a different answer. Frankly acquisitions for us over the last five years have been pretty opportunistic. There have been instances where we've seen an asset, like the momentum mid-stream assets, where it was a negotiated transaction. It was in an area that played well with our expansion opportunities. And frankly, we could get it at a price that we thought was reasonable.

There have been some other assets that we've acquired, smaller assets where maybe we buy a piece of pipe and we change out the service. We do something different with it, where it adds value to us, where maybe other people couldn't see. But in terms of big, large-scale acquisitions, I don't see anything right now. Frankly, I think there is too much money chasing those.

Yes. I agree with Mike. I think one of the things that will limit us is our discipline that what we acquire has got to fit what we have. We've been pretty strong about that. And second thing is, there seems to be some money out there that wants it worse than we do.

Thank you.

The next question will come from Sharon Lui with Wells Fargo Securities.

Hi, good morning. This question is for Jim. Just wondering what your outlook is for LPG exports and whether there's an opportunity to expand your export terminals?

Our outlook is that, Sharon, I was shocked when last summer that export terminal was full. That hasn't happened and it's been full, virtually full -- is Lynn in here? -- every month since then. And, Lynn, is there any expansion opportunities?

Well, you got to be careful expanding something which you don't have firmed up for the long haul. We're seriously looking at. The key question is whether or not you can get commitments from the partners that would be taking the product offshore. And we're in discussions with those to find out how serious they would be on commitments on a long-term basis to back any investment that we put out there. And we'll update you as we make further progress on that.

Okay. And I guess on the propylene side, do you expect the market to be imbalanced and margins to persist due to light cracking?

Want to take it or you want me to?

We think the demand for propylene is going to continue to remain strong, especially as the economy improves. With light cracking we think that there will be a deficiency in the supply of propylene from the cracker pool and even with the start of the Petro logistics facility we think they will continue to see strong demand for the splitter propylene. So while margins will probably decline from where they were earlier this year from a high, we think they'll remain consistently strong as we go into next year.

Okay. That's helpful. And I guess on the DEP side, just wondering what was the impact on distributable cash flow for those nonrecurring items?

Really, Sharon, the ones that immediately come to mind, and if these are different, I'll come back to you. But on the nonrecurring items, really most of those were non cash in nature. So really did not have an impact on distributable cash flow.

Okay. Great. Thank you.

The next question will come from John Edwards with Morgan Keegan.

Yes. Good morning, everybody.

Good morning, John.

Just following up on these questions on Cameron Highway where do you see volumes going? I guess you're running somewhere around 40% of capacity there. Where do you see that going over the next few years?

Well, first of all, we think over a several-year period and that being probably four, five, six years, we think we're going to see about probably a 30% increase in volumes. And that would be consistent with what's going on or what the long-term projections are for the offshore. And so you know somewhat bullish in the long-term. In the shorter term, we have the natural decline that impacts the systems. And that occurs at a rate of about 20% to 30% per year coming out of the deep water fields.

And so we're going to see that continue I think for another year or so before you see the new drilling activities start to cut into that decline. But there's a lot of oil -- I mean, there remains a lot of reserves in the offshore. And prior to the BP incident, those reserves were at a very, very high level. And so it's just going to take some time for the situation to sort itself out with the production companies.

Okay. That's helpful. And then I guess following up John's question on fractionation. I mean I guess are you saying you're seeing more in effect take or pay -- I guess frac or pay type commitments from the producers?

Yes.

Okay. Okay. And then I was just wondering if you could share any thoughts you have on some of the ethane solutions in the Marcellus Shale play?

You want me to do this? You notice Marcellus wasn't at the -- you didn't hear a lot about it from us.

No.

Jim Collinsworths' group has a project that would be probably better cost positioned than anyone else's and it involves using the TEPPCO line, doing some reversals and some looping. And that project has been pitched. You won't see any press releases. You won't see any open seasons.

But we've pitched that project to the producers in the Marcellus to at least five of them. The issue up there is I don't think that one producer can base-load something. A consortium of producers are going to have get together. We stand ready to do something if it's required.

I got to be honest with you. It's counterintuitive to me that you have to take ethane out or that you can't find a way to blend it down or do something. Because you're looking at, even on the low end, I think you're looking all in transportation and fractionation, what $0.20 a gallon, Jim? And that's $3 on a -- that's equivalent $3 off your gas price. It's not necessarily a value upgrade.

Okay. All right. Well that's helpful. And I'm just curious, a little detail. I noticed quarter-over-quarter it looks like NGL volumes, I mean obviously year-over-year they were strong. But on Q-over- Q the natural gas processing were off a little bit. Any thoughts there? I mean sequentially?

Randy, do you know?

We had some work at Meeker. Huh? And a time here or two if I'm not mistaken. So I think probably that may have been it.

We had some downtime in South Texas as well.

Okay.

I think the bottom line is, we have some maintenance at various plants, including Meeker, Pioneer and maybe a couple of the plants in South Texas.

Yes. As far as equity NGL production, you definitely saw that out of the Rockies. You saw the impact of Meeker and Pioneer. Just from an equity barrel standpoint on NGL production. That was probably 8,000 barrels a day.

Okay. So more an anomaly than --

Yes. We're pretty aggressive in keeping those plants close to full, if not full.

Okay. Great. All right. That's fair. That's all I have. Thank you very much.

Thank you.

The next question comes from Ross Payne with Wells Fargo Securities.

How are you doing guys?

Good morning, Ross.

First question. Any update on how contracted the Haynesville extension is at this point?

Hey, I think I said in my comments we've got about 1.6 bcf a day signed up.

Okay. Very good. And you were -- go ahead, yes.

Yes. Remember we're looking at kind of 1.8 bcf a day without additional compression. And we're ten months away from having it go into service. So we're not concerned about filling up.

Okay. Super. Jim also on the, obviously, it sounds like we're exporting ethane, et cetera. Can you talk generally about history, how much did we import? What kind of market have we taken out in terms of imports with domestic production?

Well, I'm going to get Lynn to help me. But traditionally you import in the summer and quite a lot. And you export some but not a ton in the winter. I mean that's just traditionally how it works.

A lot of people thought Dan was crazy when he put in this export facility. In fact I wondered myself. I think I was over at Dow at the time. What's changed in my mind is LPG is one heck of a favored cracker feedstock, not just here.

So I got to believe to the extent that crackers in places like Northwest Europe and the Far East, Lynn, can use LPG. They probably are. We know that they are using LPG in some of the Saudi crackers that would have traditionally been exported.

So I think what's happened is there is created a void that this market given the price of LPG relative to the rest of the world, a natural place to draw needs from. Lynn? Did I get it or no?

I think you did, Jim. You know just to give you some color on volumes. What we would have said historically is somewhere around 17 million to 20 million barrels imported into the Gulf Coast would have been about an average to low year. Anything greater than 30 million barrels would have been a pretty big year on that side. So what we're doing now is basically zero on the import side. And we're exporting probably roughly 3 million barrels a month, so 36 million barrels a year. So that kind of gives you a color for the swing of import versus export now.

Were you talking LPG? Did you mean propane?

But go ahead and address that as well. And also if you can mention where you think a lot of this product is going? Is it going to Latin America or where it might be going?

That's primarily where the propane is going. We're offsetting imports into those areas that traditionally came from either North or West Africa. Some of our product is going to Europe and some of it is actually going into the Far East.

Very good. Thanks. That gives a lot better perspective on that. Thank you.

Ladies and gentlemen, as a final reminder if you'd like to ask a question please press star one at this time.

Thea. This is Randy. I think we have time for one more question.

Okay. The final question will come from Bernie Colson with Oppenheimer.

Hi, guys.

Good morning.

Good morning. I guess I was a little slow on the draw because my question has been answered. So thanks.

Perfect. All right, thank you, Bernie. Thea, I think we're ready for you to go ahead and give our audience the replay information, if you don't mind.

One moment, please. Ladies and gentlemen, the conference call will be available beginning at 12 PM Eastern time today. You may dial in on 800-642-1687 and enter the pass code of 18752914.

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

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