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Enterprise Products Partners L.P. (NYSE:EPD)

Q3 2010 Earnings Call Transcript

October 26, 2010 10:00 am ET

Executives

Randy Burkhalter – VP, IR

Mike Creel – President and CEO

Jim Teague – EVP and COO

Randy Fowler – EVP and CFO

Bill Ordemann – EVP

Christopher Skoog – SVP

Rudy Nix – SVP

Lynn Bourdon – SVP

Analysts

Ted Durbin – Goldman Sachs

Darren Horowitz – Raymond James

Steve Maresca – Morgan Stanley

John Tysseland – Citigroup

Yves Siegel – Credit Suisse

Sharon Lui – Wells Fargo

John Edwards – Morgan Keegan

Ross Payne – Wells Fargo

Lynn Bourdon – Senior Vice President

Bernie Colson – Oppenheimer

Operator

Good morning, my name is Thea, and I will be the conference operator today. At this time, I would like to welcome everyone to the Enterprise Products and Duncan third quarter 2010 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)

Thank you. At this time, I would like to turn the conference over to Mr. Randy Burkhalter. Sir, you may begin.

Randy Burkhalter

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 speakers today will be Mike Creel, President & CEO of Enterprise's General Partner. He will 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, they can give no assurance 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.

And with that, I will turn the call over to Mike Creel.

Mike Creel

Thanks Randy. Before we get started, just want to make sure everybody understands, this is our earnings call, we are not going to talk about the pending merger with Enterprise GP Holdings. We are not going to answer questions on that, but I would point you to the proxy statements 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 & Services business 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, 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 spread between polymer grade or finer 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 Mid West 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 and sales prices. Our onshore natural gas pipelines and services segment reported a $46 million or 42% increase in gross operating margin on record transportation volumes of the 11.7 TBtud, which were 11% higher than the 10.5 TBtud in the third quarter of last year. This quarter-to-quarter increase was primarily related to shale 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 demand 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 access the heart of the Newark field between Arlington and Fort Worth, Texas. You may recall, we began service from 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 volumes.

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 and services segment reported slightly higher gross operating margins 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 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 our 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 its importance 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 to 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 would like to say once again how pleased we are with the strong results our businesses 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 are considered the best in the business as they work tirelessly to create value for our investors.

And with that, I will turn the call over to Jim.

Jim Teague

Thank you Mike. Energy metrics remain favorable where natural gas liquids and natural gas processing over the third quarter, where 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 feed stocks continue to grow.

We have seen light feed stock 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 there are varied opinions, in fact there many opinions as there seems to be consultants and they are all over the map.

For ethane in particular, record high production and consumption has clouded some crystal balls. So, I would 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 that 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 started proclaiming that the sky was falling.

Ethane consumption only averaged 835,000 barrels a day over the second quarter. This was due to not only planned 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 was 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 drawing through the fourth quarter.

Looking forward, we expect ethane extraction to increase the shale drilling expanse in areas like the Eagle Ford and Marcellus. With 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 a 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 U.S. 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 forecast from companies like CMAI and En*Vantage show ethane cracking forecast to top 1 million barrels a day over the next five years.

Do not underestimate that U.S. chemical industry’s ability to consume more ethane. We were supportive in helping cracker operator 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 1 million barrels a day of ethane cracking capability.

We recognized that there will be temporary imbalances in the ethane market such as in the second quarter, but overall, we believe that the U.S. market will balance supply demand and that the glut of ethane that some have predicted will not materialize. As quick as the U.S. is becoming more competitive globally due to the NGL feedstocks and U.S. cracker operators, we will find a way to capitalize on this. We talked about how hard crackers ran last quarter, how much ethane was cracked, but there is a why. 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 with $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 a 1.5 billion pound a year cracker, that 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. U.S. ethane cracking is near the bottom of the global production cost curve according to CMAI. U.S. 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 U.S. 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 U.S. as an export destination for foreign produced chemicals, again we see this story as a positive story not only for NGL producers but also U.S. petrochemicals.

U.S. 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 have seen that terminal flow for the last almost 18 months for exports. Our terminal is sold out through the end of the year, and we are quickly filling the late cans throughout 2011. Our assets remain the heart of our business and we continue to expand. In 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 a new 140-mile crude oil pipeline, a 168-mile rich natural gas mainline, a 600 million a day gas processing plant, expanded natural gas storage, a 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 10-year agreement with Pioneer and our partners for natural gas gathering and processing, residue takeaway, 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 are in active negotiations with several other producers. Should we be successful with all, we will probably be looking at expanding part of what we have announced, we call that a high-class problem. Our Haynesville extension project connect the 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 are 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 today. Our Rockies production remains strong Our plants are close to full, we are producing over 100,000 barrels a day of NGLs for Meeker and Pioneer and margins continue to be strong. Our hedging program for 2011 is active, but 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 have hedged 44% of Rockies production, we have hedged little after that, as we continue to see a steeply backward dated NGL curve. Our C4 chemicals business at Mont Belvieu is benefitting 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 are 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 are creating today. That’s why we are so focused on supply basin such as the Haynesville, the Eagle Ford and our position in the Rockies, but we are also focused on the demand side of the equation. We are supporting petrochemicals’ appetite for more NGLs by upgrading our pipeline systems for deliveries, expanding our brand capabilities at our Mont Belvieu storage, and adding fractionation. We are spending money to create more supply into our refined product assets, and we are expanding our marketing efforts to pull through more products through those assets.

We are 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 are 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 will turn the call over to Randy.

Randy Fowler

Okay, thank you Jim. Good morning. I would like to just hit a few additional financial items. And interest expense, it increased by $19 million this quarter due to higher debt balances in the third quarter of 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 of 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 spent about $2.5 billion and expect to spend approximately $3 billion to $3.1 billion [ph] 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 project for 2010 include the Haynesville extension pipeline, the projects in the Eagle Ford that Jim mentioned, the expansion of the Mont Belvieu fractionater, 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 of 2010 and $177 million through nine months. We still believe we will be in the range probably closer to $240 million to $250 million for sustaining CapEx for total year 2010. In terms of capitalization, adjusted EBITDA for the 12 months ending September 30th, 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 30th, after adjusting debt for 50% equity treatment for the hybrid securities.

Our floating interesting rate exposure was approximately 11% at the end of the quarter. The average life of our debt was 10 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 EPD’s consolidated credit facilities, plus unrestricted cash, but excludes availabilities under DEP’s credit facilities of approximately $1.8 billion at September 30th.

Now turning to Duncan Energy Partners, in this quarter, we are pleased to report record gross operating margin of $74.4 million. We benefited from higher throughput 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 throughput on Sherman extension pipeline in the Barnett Shale. The Sherman extension pipeline began commercial service in August of 2009. So, we have got a benefit of a full quarter this year.

After adjusting for non-recurring 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 eight 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 and we retained approximately $7.5 million of distributable cash flow this quarter.

We are making good progress on conversion of the first two of our NGL storage caverns to refined products at our Mont Belvieu facility. We expect to have the first cavern, which will store up to 2 million barrels of refined products in service by the end of November. We are currently leaching 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’s Haynesville extension pipeline project that’s on a 100% basis. DEP’s 66% portion of this amount was approximately $132 million. The total expected cost of the 270-mile Haynesville extension pipeline project remains at approximately $1.56 billion including capitalized interest of which Duncan Energy’s 66% share would be $1.03 billion. Sustaining capital expenditures were $11.6 million this quarter compared to $13.8 million spent in the third quarter of 2009. At September 30th, 2010, DEP’s debt to LPM EBITDA ratio calculated per its bank credit facility was 3.2 time. Under this facility, DEP’s 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 from our partnership was the execution of the $1.25 billion of senior unsecured credit facilities, which we completed yesterday. We are 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 DEP’s 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 allow DEP to terminate and repay its $300 million bank revolver that was due in February 2011 and its $200 million revolving credit facility with Enterprise, which had $125 million outstanding at September 30th.

The new credit facilities both mature at October of 2013. At December 30th, 2010, DEP had total liquidity of $140 million, which includes cash and availability under the partnerships revolving credit facilities. After adjusting for the execution of the new credit facilities and the related repayment of the terminating facilities, DEP’s liquidity would have been approximately $860 million at September 30th.

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 are all ready for questions.

Randy Burkhalter

Okay, thank you Randy. Thea, we are ready to take questions from the audience now.

Question-and-Answer Session

Operator

(Operator instructions) And the first question will come from Ted Durbin with Goldman Sachs.

Ted Durbin – Goldman Sachs

Hi guys. First question is just, I guess Jim, little bit more, can you talk a little bit more about the potential for these conversions, the timing of when you might see these chemical crackers to turn the lighter in, and what you are hearing in terms of potential, even restarts and things like that, especially on the aluminum [ph] side for ethylene demand?

Jim Teague

I can’t talk too much, because we are in a couple of cases, we are in negotiations with folks, but needless to say, we are in negotiations with one in particular. I don’t have an update on where we are, but it would probably be another, I don’t know, 25,000 to 30,000 barrels a day with a capability to go higher. And I think you have had Williams announce that they are going to expand their Gismer [ph] cracker. I think it’s another 12,000 to 15,000 barrels a day of ethane. Eastman has announced, first quarter – 10,000 barrels a day, ethane, propane on a cracker they have up in Longview. I am talking to Don Johnson who keeps all this stuff for us.

Ted Durbin – Goldman Sachs

Okay, that’s great. Thanks. And then if I could just shift over to just the offshore, you know, now that the moratorium have 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 thing?

Mike Creel

Ted, we have already seen the volumes on independent hub come back a bit. We were down pretty low, we are back up now, bouncing around between 500 million to 550 million a day. We do expect, even though the moratorium has been lifted, I think there is 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 hope some other things are. Jim?

Jim Teague

We were pretty excited. We were also pleased to see Chevron’s recent announcement, what they called the chronicle of floating city. We know they have got several other leases that are in proximity to our pipes mark.

Mike Creel

Yes, we expect to see the volumes bounce back, but it’s going to take a while, and I think realistically we are talking second half of 2011 before we see any significant volume to come back as a result of resumption of drilling.

Ted Durbin – Goldman Sachs

Okay, great. If I could just one more, in terms of the Belvieu frac, it looks like you accelerated the timeline on that. Now, you are talking about getting it done here at the end of November. What kind of change that you could get that bottom line faster and should we expect there is an opportunity to bring the second phase earlier than 2012?

Jim Teague

You make Bill Ordemann real nervous. So, we will let him answer that.

Bill Ordemann

I think the good news is we did declare mechanical completion on that frac. So, that means all the systems returned over to operations here, I believe it was Friday, Rudy. And so operations has them now, they are in the process of commissioning and starting up the equipment. There is 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 here in the very foreseeable future. So, we pulled that back from an original date was I think March of 2011 back, here about mid November I think at the latest.

We are working on the next frac there now and looking at the schedule and trying to pull that back as well. I think there’s a pretty good opportunity we will be able to pull that schedule back into the latter part of 2011 as opposed to the early part of 2012.

Ted Durbin – Goldman Sachs

Okay, I appreciate it, thanks.

Operator

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

Darren Horowitz – Raymond James

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

Jim Teague

We tried there. It’s not as liquid as you would like it to be. So, you could like it Horowitz. So, the answer is, you try, but you can’t do a lot of it.

Darren Horowitz – Raymond James

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 tailwind to ethane and of course what you are experiencing as it relates to Gulf Coast frac spreads, how do you balance how much you hedge versus how much you keep spot, because I would love to know?

Jim Teague

No, I won’t care to comment on what we locked in, primarily because I am a little embarrassed on it, because we were a little early. Things look better now. We are basically to way and right now, we are looking at a forward, you know, the NGLs are so backward dated, and they always will be I guess, but you are getting in the first quarter up into a range where it start to look more interesting in the $0.28 to $0.30 a gallon for ethane.

Mike Creel

Darren, the question that you had is, how do we know or how do we determine how much hedge is, really is based on price and our field, we haven’t historically hit the highs in the market when we hedged, but we lock in strong cash flows that we think are good for the partnership. And that’s what we are doing now, we are looking forward to see what makes sense for us.

Darren Horowitz – Raymond James

Sure. And just one final question if I could for Skoog on State line and Fairplay, can you just give us where you are running right now relative to nameplate capacity?

Christopher Skoog

We are running State line between around 425 million a day, and Fairplay right in the 160 million to 170 million a day, both those are up from where we bottomed, as one of our competitors comes into service in 2011 first quarter, we should see the volume start to ramp up with a significant ramp up occurring in the third quarter when we get our Haynesville takeaway project into service.

Darren Horowitz – Raymond James

Okay, I appreciate you guys. Keep up the good work.

Operator

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

Steve Maresca – Morgan Stanley

Hi, good morning everybody.

Mike Creel

Good morning.

Steve Maresca – Morgan Stanley

Thanks a lot for the detail, Jim. Very appreciated. One of my questions is with regard to that, what do you see is the biggest risk at NGL Storage? You gave a lot of detail on the supply and demand side kind of being favorable. Do you think there is a risk to being wrong, it’s a risk more on the supply side that there is more to come with producers being so focused on liquids rich areas in trying to get the most that they can out of there or how do you view it?

Jim Teague

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

Steve Maresca – Morgan Stanley

Okay. Are you guys seeing in any of the areas a move from producers away from some of the drier gas areas and rigs moving, areas like the Haynesville where you are seeing producer activity declined a little bit in recent weeks and months because of gas prices?

Randy Fowler

Overall, we have seen the rig start to move towards the Eagle Ford, but our area in the sweet spot of the Haynesville, when you look at our – we have a reservoir group on staff, and we are in the sweet spot of the Barnett with this Newark field, and we are in the sweet spot of the Haynesville. So, we are seeing the drillers stay active in both of those areas. In the Haynesville especially, you got a lot of acreage dedication that needs to be held, and so we see pretty robust drilling to hold that acreage through the next six, let’s call it, 12 to 18 months. And that point in time then hopefully if gas prices rebound a little bit, and you see it maintaining, but the southern half of the Haynesville basin where we are focused on our gathering system, where M2 was and where we developed proprietarily down that in the system, is the sweet spot and we have got a two or three stag zone, the Bossier play as well as the Haynesville Shale, we have got two or three payout zones there to play with you really focused on.

Steve Maresca – Morgan Stanley

Okay. 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 that you count EBITDA, use that to apply to the leverage metrics and not essentially do any equity with DEP?

Randy Fowler

We have sort of, if you would, our thoughts around Duncan Energy financing the Haynesville sort of have evolved if you would since the second, or I guess, May when we announced how much of the Haynesville DEP would take, where then we were talking about financing it at DEP with 50% equity, 50 % debt, really we have 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 is as we look out, we could continue to say distribution growth rate similar to what we are doing, couple of percent, 2.5%. And then the excess distributable cash flow that you generated, once the Haynesville extension comes back up in that, we could use that excess DCF to come back in and delever Duncan Energy Partners back down to a leverage metric we would be comfortable with.

So, right now, the way we look at it, we got a lot of flexibility, how we will fund the Haynesville extension, but we are looking as far as from a DEP standpoint, probably we are not going to have nearly the equity requirements that we are talking about back when we were saying 50% funded with equity.

Steve Maresca – Morgan Stanley

Okay. Thanks a lot guys.

Operator

The next question will come from John Tysseland with Citigroup.

John Tysseland – Citigroup

Hi guys, good morning and great overview. Are you guys still seeing positive rollover on expiring NGL transport and frac contracts? And then also secondarily to that, what links of new contracts are you able to lock in these days, if you could elaborate on that?

Randy Fowler

We are working on some renewing them for 10-year term, Jim.

Jim Teague

Yes, basically, I think by and large, John, we try to do 10-year deals if we can. If a guy doesn’t want to do a 10-year deal, we almost do 7. We haven’t been known to walk away from business, but what we are 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 will give you an example. In our fractionation contracts, I think we have 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 really we are up to about 5% [ph] 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. What we have said is, we are not doing that anymore. So, now if you want 20,000 barrels of day of capacity, you got 20,000 barrels a day of 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 clamp 20,000 barrels a day of propane plus to this and meet that obligation. Does that help?

John Tysseland – Citigroup

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

Jim Teague

It’s a dilemma for him, because and I don’t really know if they are 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 not having to place to fractionate your production if you are all out.

John Tysseland – Citigroup

Right. So, you are seeing, well, I guess you just don’t know at least what the producers were thinking at this point, but on the other side, when you look at storage, you saw storage pretty much max out in May or June, and start to come down a little bit in July. You mentioned this in your comments, but any kind of idea like where we stand today with the massive ramp-up that we have seen in demand on the petrochemical side, where those inventories are?

Jim Teague

I have got a real good idea that I can tell you all day. From our perspective, we don’t have as much, Rudy, in storage this time of the year as traditionally we have across the board I think is fair to say.

Rudy Nix

Nowhere near as much as last year.

Jim Teague

And the way we look at that is we spend a lot of time taking a look as we go into the winter, how much bran we have got, and we are balancing that on what we expect the pulse to be, and I will tell you, our bran is not at the levels traditionally we would want it to be, but frankly, it doesn’t need to be given where we are on inventories of finished products.

John Tysseland – Citigroup

Great, thanks for the detail.

Operator

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

Yves Siegel – Credit Suisse

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

Randy Fowler

Yves, as far as the bank credit facility, I would say it was really on top of what DEP/EPD [ph] could have done, maybe EPD could have, maybe an eight [ph], maybe a quarter, but DEP got excellent execution on the bank credit facility, and again, I will come in, I think we have got a lot of questions over the last, gee, last 18 months of access to capital and for what you are 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 appreciate to our bank group for that.

Yves Siegel – Credit Suisse

So, really when you think about cost of capital between the two entities, it doesn’t sound like there is a whole lot of difference.

Randy Fowler

Not when it comes to the bank credit facilities I have known.

Yves Siegel – Credit Suisse

Yes, okay. And then if I could just push a little bit forward in terms of thinking about the Haynesville and Chris’ comments, even though during 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 in a comment, mine’s pretty cloudy too. When you think about next few years, where do you think gas prices go to?

Randy Fowler

That’s kind of a loaded question. Last April, at the analyst meeting we had here in town, I talked about a $4 to $5.25 range. I wish we are at the lower end of that. If you look at the forward curve for the next 12 months, we are below the lower end of that. I am not – if I was predicting gas prices, I wouldn’t be here. I was accurate about it. But just the shale plays overall, I think the Haynesville, it’s the marginal production that’s driving all the natural gas prices, because when the Haynesville well comes on, it’s coming on at 20 million a day IP, 30 million a day IP, it’s the discretionary gas that has to continue to be drilled to hold this acreage or these creatures have to walk away from the acreage. So, they are going to lie on the street or they are going to perform, and that’s the wild card. So, the next 12 to 18 months, we think they are going to continue to drill and in and around our assets, we are just having a rig count of north of 50. So, we are very comfortable with where they are at, and the key producers that we deal with, are all telling us the 12 to 18 month inventory to hold the acreage.

Yves Siegel – Credit Suisse

What about the joint ventures they have entered into, did that have an effect too?

Randy Fowler

Right, and then a couple of the big players in the Haynesville, now down in the Eagle Ford, you are seeing a lot of these good mid-sized to major producers teaming up internationally with foreign money and they are drilling with what I call $0.50. So, they have got equity upfront, 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 are comfortable that where we built our pipeline, we have really focused on the geology and making sure our pipelines are in the right locations to maximize the fields, and I guess I attribute that to our reservoir group internally here that they don’t have a race, a horse in the race, if they are not talking, they are booked. They are looking at just the geology and things. This area makes the most sense for us to be in, and I guess they are not talking their book, they are just talking about real value for us. So, I give them a lot of credit to why we are located, where we are located.

Mike Creel

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

Yves Siegel – Credit Suisse

Okay, appreciate that. And then just thinking longer term here, you are 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?

Mike Creel

Sure, we have got – that $3 billion that we keep backing around for growth CapEx this year includes $1.2 billion for the Momentum Midstream assets that we acquired back in May. For 2011, probably something in the $2.5 billion range is reasonable given what we are spending again in the Haynesville to finish up the Haynesville extension and the Eagle Ford shale project that we have got. After that, we don’t have any really big individual projects. We have got a lot of opportunities to fill out around a system that we are kind of creating the backbone for now, but we think that there is plenty of opportunities. In fact, if you look at our wish list of projects, we probably got a backlog of maybe $6 billion or $7 billion of projects. Clearly, not all those have to be done this year or next year, but we got enough to keep us busy.

Yves Siegel – Credit Suisse

Okay, and I promise, I just got two last ones. One is I couldn’t help it 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 seek potential for future dollar investments?

Mike Creel

Kind of two things, when Valero started that process, the BP incident happened kind of right in the middle of it. So, 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 Eagle Ford do a lot more for the partnership. There is certainly more stable cash flow sources, provide more of an integrated value chain approach, and 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.

Yves Siegel – Credit Suisse

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?

Mike Creel

I will take the first crack at it, and then I will turn it over to Jim, because he may have a different answer. Frankly, acquisitions for us and over the last five years have been pretty opportunistic. There have been instances where we have seen an asset like the Momentum Midstream assets where it was a negotiated transaction. It was an area that played well with our expansion opportunities, and frankly, we could get at a price that we thought was reasonable. There have been some other assets that we have 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 that maybe other people couldn’t see.

But in terms of big, large scale acquisitions, I don’t see anything right now and I think frankly there’s too much money chasing some of those.

Jim Teague

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 have been pretty strong about that, and second thing is there seems to be some money out there that wants it worse than we do.

Yves Siegel – Credit Suisse

Thank you.

Operator

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

Sharon Lui – Wells Fargo

Hi good morning.

Jim Teague

Good morning.

Sharon Lui – Wells Fargo

This question is for Jim. Just wondering what your outlook is for LPG exports and whether there is an opportunity to expand or export terminals?

Jim Teague

Our outlook is that, Sharon, I have been or 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?

Mike Creel

Yes.

Jim Teague

Every month since then and, there any expansion opportunities. You got to be careful expanding something what you don’t have firmed up for the long haul.

Mike Creel

We are seriously looking at it. The key question is whether or not you can get commitments from partners that will be taking the product offshore and we are 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 will update you as we make further progress on them.

Sharon Lui – Wells Fargo

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

Mike Creel

Do you want to take it or you want me to?

Randy Fowler

We think the demand for propylene is going to continue to remain strong especially as the economy improves. With the light cracking, we think that there will be a deficiency in supply of propylene from the cracker pool and even with the start of the petro logistics facility, we think that 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 the highs, we think that they will remain consistently strong as we go into next year.

Sharon Lui – Wells Fargo

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

Mike Creel

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

Sharon Lui – Wells Fargo

Okay. Great, thank you.

Operator

The next question will come from John Edwards with Morgan Keegan

John Edwards – Morgan Keegan

Yes, good morning everybody.

Mike Creel

Good morning John.

John Edwards – Morgan Keegan

Just following up on Yves question on Cameron Highway, where do you see volumes going? I guess you are running somewhere around 40% of capacity there. Where do you see that going over the next few years?

Mike Creel

First of all, we think over a several-year period and that being probably four, five, six years, we think we are 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, somewhat bullish in the long-term. In the shorter term, we have natural decline that impacts the systems and that occurs at a rate of about 20% to 30% per year coming out of the deepwater fields. And so, we are going to see that continue, I think for another year or so before you see the new drilling activity start to cut into that decline. But there is 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 is just going to take some time for the situation to sort itself out with the production companies.

John Edwards – Morgan Keegan

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

Mike Creel

Yes.

John Edwards – Morgan Keegan

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

Jim Teague

You want me to do this? You noticed Marcellus wasn’t (inaudible), you didn’t hear a lot about it from us. Jim Collinsworth group has a project that would be probably better cost position than anyone else’s and Bob is 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 have 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. So, a consortium of producers are going to have to 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 out by now to or that you can’t find a way to blend it down or do something, because you are looking at even on the low end, I think you are looking all in transportation and fractionation, what $0.20 a gallon, Jim? And that’s $3, that’s equivalent $3 off your gas price. It’s not necessarily a value upgrade.

John Edwards – Morgan Keegan

All right. That’s helpful. I am just curious. I know that quarter-over-quarter, it looks like NGL volumes, I mean, obviously they were strong, but on QoverQ, NGL volumes and natural gas processing were off a little bit, any thoughts there, I mean sequentially?

Jim Teague

Randy, do you know? Zulim is not here, or he would – we have some work at Meeker, and it kind of here too, but not mistaken. Well, I think probably that may have been it. 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.

Randy Fowler

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 a equity standpoint on NGL production, that was probably 8,000 barrels a day.

John Edwards – Morgan Keegan

Okay. So, that’s more of an anomaly than –?

Jim Teague

Yes, those plants were pretty aggressive, and keeping those plants close to full, if not full.

John Edwards – Morgan Keegan

Okay. Great. All right. That’s all I have, thank you very much.

Jim Teague

Thank you.

Operator

The next question will come from Ross Payne with Wells Fargo.

Ross Payne – Wells Fargo

Thank you guys.

Jim Teague

Good morning Ross.

Ross Payne – Wells Fargo

First question, any update on just how contracted the Haynesville extension is at this point?

Jim Teague

I think I said in my comments, we got about 1.6 Bcf a day signed up.

Ross Payne – Wells Fargo

Okay. Very good. Go ahead, yes.

Randy Fowler

Remember, we are looking at kind of 1.8 Bcf a day of capacity without additional compression, and we are 10 months away from having to go into service. So, we are not concerned about filling it up.

Ross Payne – Wells Fargo

Okay. Jim, also on the – obviously it sounds like we are exporting ethane etcetera, can you talk generally about history, how much did we import, what kind of market have we kind of taken out in terms of imports with domestic production?

Jim Teague

I am going to get Lynn to help me, traditionally, you import in the summer quite a lot and you export some but not a ton in the winter. I mean, that’s just traditionally how it has worked. A lot of people thought Dan was crazy when he put in his export facility, in fact I kind of wondered myself. I think I was over doubting at the time, but what’s changed is 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, Len can use LPG. They probably are. We know they are using LPG and some of the static crackers that would have traditionally been exported. So, I think what’s happened is it created a void that this market given its price of LPG relative to the rest of the world is a natural place to draw needs from. Lynn, did I get it or not?

Lynn Bourdon

No, I think you did, Jim. Just to give you some color on volume. So, 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 are doing now is basically zero on the import side, and we are 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.

Jim Teague

Were you talking LPG?

Lynn Bourdon

Did you mean propane when you said –?

Ross Payne – Wells Fargo

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, where it might be going?

Randy Fowler

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

Ross Payne – Wells Fargo

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

Operator

(Operator instructions)

Randy Burkhalter

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

Operator

Okay, the final question will come from Bernie Colson with Oppenheimer.

Bernie Colson – Oppenheimer

Hi guys.

Randy Fowler

Good morning.

Bernie Colson – Oppenheimer

Good morning, I guess I was a little slow on the draw because my questions have been answered. So, thanks.

Randy Fowler

Perfect.

Mike Creel

All right. Thank you Bernie. Thea, I think we are ready for you to go ahead and give our audience the replay information if you don’t mind.

Operator

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.

Mike Creel

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

Operator

Ladies and gentlemen, thank you for participating in today’s conference. You may now disconnect.

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