Enterprise Products Partners LP (EPD) 2010 Q1 法說會逐字稿

Welcome to the Enterprise Products Partners first quarter earnings conference call. At this time, all participants are in a listen-only mode. After the speakers' remarks, there will be a question-and-answer session. (Operator Instructions). As a reminder, today's call is being recorded and if you have any objections, you may disconnect at this time.

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

Thank you, Tina. Good morning, everyone, and welcome to the Enterprise Products Partners conference call to discuss first quarter earnings.

Our speakers today will be Mike Creel, President and CEO of Enterprise's General Partner, followed by Jim Teague, Executive Vice President and Chief Commercial Officer; and then Randy Fowler, Executive Vice President and Chief Financial Officer of the General Partner, will wrap it up. Also in attendance for the call today are other members of our senior management team to assist in Q&A. Afterwards, we will open the call up for your questions.

During this call, we will make forward-looking statements within the meaning of Section 21E of the Securities and Exchange Act of 1934, based on the beliefs of the Company as well as assumptions made by, and information currently available to Enterprise's management. Although management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Please refer to our latest filings with the 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.

Thanks, Randy. We got off to a great start in the first quarter of this year, with record distributable cash flows supported by all-time high volumes for natural gas transportation, equity NGL production, and propylene fractionation. We also had increased NGL, crude oil, and petrochemical transportation volumes and higher NGL fractionation volumes.

This strong performance resulted in an 11% year-over-year increase in gross operating margin for the quarter. The advantages of our large geographical footprint and diverse portfolio of integrated businesses continues to benefit our investors. Based on our continued strong performance, we recently announced the 23rd consecutive increase in our quarterly cash distribution rate, increasing at 5.6% to $0.5675 per unit or $2.27 per unit on an annualized basis.

Enterprise generated $580 million of distributable cash flow, our third consecutive quarterly record. This provided 1.4 times coverage of the distribution declared with respect to the quarter. One of our important financial goals is to retain a portion of our distributable cash flow for reinvestment in growth capital projects, to reduce debt, and to decrease the need to issue additional equity. This quarter, we retained $156 million or 27% of the distributable cash flow we generated. Since our IPO in 1998, we've retained approximately 16% or $1.3 billion of distributable cash flow.

As I mentioned earlier, gross operating margin increased 11% or $81 million to $795 million this quarter. The largest increase was from our NGL Pipelines and Services segment, reporting $437 million of gross operating margin, up 25% from the first quarter of last year. This segment benefited from record equity NGL production and higher gas processing margins, primarily from our Rocky Mountain processing plants.

We also had increased NGL pipeline and fractionation volumes and profits from forward NGL sales transactions that settled in the quarter. Fundamentals continue to be strong for this segment. NGL inventories are low, particularly ethane, and demand continues to be high, resulting in strong natural gas processing margins, and Jim will talk about this more in a little bit.

Gross operating margins from our Onshore Crude Oil Pipelines and Services segment was $27 million for the quarter compared to $50 million for the first quarter of 2009, primarily due to lower sales margins from our crude oil marketing activities. Gross operating margins for the Onshore Natural Gas Pipelines and Services segment decreased $32 million from the first quarter of 2009, primarily due to our natural gas marketing business, which reported a loss of $9 million for the quarter compared to a record profit of $34 million for the first quarter of last year.

This decrease was due to lower unit margins and higher transportation and storage expenses. The delay in the completion of the Trinity River Basin lateral pipeline is resulting in a loss of approximately $3 million per month in the gas marketing business, due to charges being incurred for transportation capacity on the downstream pipelines in anticipation of natural gas volumes originating on the Trinity River Basin lateral pipeline.

Partially offsetting this decline was the San Juan gathering system, which reported a $7 million increase in gross operating margin, attributable to higher fees from contracts indexed to gas prices as well as increased condensate sales. We also had higher gross operating margin from our Piceance gathering system, due to the Collbran Valley system that began service in the fourth quarter of 2009; the Exxon treating facility, which began service in March of last year; and our Acadian and Texas intrastate pipeline systems. Our Texas intrastate system benefited from the Sherman extension being in service for a full quarter, partially offset by lower pipeline volumes.

Gross operating margins for the Offshore Pipeline and Services segment increased by $20 million or 33%. This included $9 million of insurance recoveries and a $20 million increase in gross operating margin from our crude oil pipelines. This improvement of our offshore crude oil pipelines was primarily attributable to the Shenzi pipeline, which began operations in April of 2009, and the restoration of service by other crude oil pipelines that were either out of service or in partial service during the first quarter of last year. Total offshore crude oil pipeline volumes were 354,000 barrels per day compared to 126,000 barrels per day in the first quarter of 2009.

Partially offsetting these increases in gross operating margin was a $9 million decrease in gross operating margin from the Independence Hub platform and pipeline. Natural gas volumes on the Independence system decreased to 717 billion BTUs per day this quarter from 922 billion BTUs per day in the first quarter of last year, primarily due to platform down-time for construction of a deck extension and other maintenance work; the re-completion of the Mondo well this month and depletion of reserves.

Gas flow is increased from the Mondo well, due to the recompletion, and producers expect an additional well will be re-completed and another well added by the end of the year. They also expect two additional wells to be connected in 2011.

The Petrochemical and Refined Product Services segment reported a $30 million or 33% increase in gross operating margin for the quarter. Our propylene fractionation, octane enhancement and the refined product pipeline businesses were responsible for most of this improvement. Propylene fractionation volumes increased 16% to 80,000 barrels per day, reflecting increased demand for polymer grade propylene. Our butane isomerization business also had a strong quarter.

Now before I turn the call over to Jim, I'd like to add that we're still on track to complete our previously announced acquisition of gathering assets from M2 Midstream next week, and I would also like to emphasize the continued efforts of our employees and management team in optimizing our existing assets, while also finding new opportunities for growth and value creation for our investors.

And with that, I'd like to turn the call over to Jim.

Thank you, Mike. Because the petrochemical industry is such an important component of the demand for our natural gas liquids, I'd like to begin with an update on the petrochemical industry as we see it.

We continue to believe the change in the price relationships of natural gas and related NGLs to crude oil and crude oil derivatives, such as naphtha, have led to a structural change in the petrochemical industry. As we said in last quarter's call, this is due to a number of factors, which I won't repeat except to say US ethylene producers are enjoying a competitive advantage over many of their international peers, given the more profitable natural gas feedstocks.

International ethylene crackers have also reacted to the NGL feedstock cost advantage by importing more LPG to feed their traditional naphtha crackers. Consequently, our export terminal on the eastern ship channel continues to be full, and propane exports are expected to remain robust at least through the middle of the year.

Because of the significant margins for olefins, integrated polymer producers saw very healthy margins over the first quarter, while non-integrated producer margins were lower, but were still positive. As was expected, first quarter exports for polymers were down, due to competition from new production assets overseas, such as the Middle East. However, exports of polymers in the first quarter still represented 20% plus of demand.

We still believe that downstream derivatives will be able to compete on a global basis, and we're not the only ones that think the US is competitive. Just this month, Shintech, a large PVC producer, announced that it will go ahead with a project to expand its vinyls production capacity in Louisiana.

That expansion is estimated to increase total vinyls capacity by about 900,000 metric tons by the end of 2011, representing an appetite for over 900 million pounds of ethylene. If that ethylene were produced from methane, that is equivalent to close to 30,000 barrels a day of incremental ethane. We're seeing US ethylene producers continue to modify their furnaces to crack more NGL feedstocks and take advantage of its cost-benefit versus crude oil derivatives.

We have worked closely with a number of customers to provide them with incremental supplies of ethane and propane, and related logistical services, and we estimate that ethylene producers in the process of adding more capacity to crack ethane and propane in the US. We expect NGL consumption at US crackers to continue to increase in the future, as NGL's, primarily ethane remained the most competitive feedstock.

Ethylene supplies are tight, due to planned and unplanned outages over the last couple of months, with ethylene prices increasing to over $0.70 per pound at the end of first quarter. US ethylene operating rates were approximately 88% of capacity for the first quarter, producing an annualized average of 51 billion pounds of ethylene, which equals the average for the last five years.

Industry consultants estimate that in April, crackers will operate at 86% of capacity, producing some annualized 50 billion pounds of ethylene. We've said in the past, and history proves, that when they're operating at this high of a level, they have to rely on inventory draws for light end feedstocks, which is good for us.

During the first quarter, demand for ethane from ethylene crackers were approximately 877,000 barrels a day. That's not only higher than in the fourth quarter of 2009; it's the highest in over 10 years. During the first quarter, over 80% of total feedstocks used by US crackers were light end versus the heavier crude feedstock, such as naphtha and gas oil. We estimate there is a shortfall between current NGL production capability and potential cracker demand.

We did see some anomalies in cracker economics and ethylene prices during the quarter. Plant outages tightened the ethylene market, sending spot prices to over $0.70 per pound at the end of the quarter. The higher prices impacted the ethylene business, with the average cracker margins across the industry at $0.30 per pound; this is for CMAI. That compares to margins that averaged in the low single digits in the fourth quarter. The strong margins provided incentive to cracker operators to run plants as hard as they could, and even some delays of planned maintenance to take advantage of the margins.

Moving to our fractionation business. We're increasing our fractionation capacity, expanding our NGL -- our natural gas pipeline and processing infrastructure, and growing our NGL distribution networks in anticipation of continued growth in both supply and demand for NGLs. NGL fractionation capacity remains tight. Our fractionators at Mont Belvieu and Hobbs continue to run at capacity, and overflow volumes have gone to our Louisiana fractionators since mid-2008. Construction of our new 75,000 barrel a day NGL fractionator at Mont Belvieu is progressing on schedule to go into service the first of 2011. And we expect it to be full on day one.

Additional capacity may be needed, and we are evaluating that to accommodate incremental NGL volumes expected from production growth out of the Eagle Ford Shale play in South Texas. Total Eagle Ford production feeding our system today exceeds 150 million cubic feet a day. By comparison, this was relatively nonexistent at this time last year. This is helping to offset declines we are experiencing from conventional production in South Texas. We've seen both the rig count and production increase by over 50% from the fourth quarter of 2009, which has also led to higher mixed NGLs feeding into our South Texas fractionators.

Fractionation fees at Mont Belvieu have increased significantly since pre-2005, when contracts were done between $0.01 and $0.015 per gallon. Today, fees are in excess of $0.05 a gallon, and unlike in the past, they include throughput commitments in the form of minimum take clauses for new contracts and contracts renewals.

Moving to our NGL pipelines and processing, as Mike mentioned earlier, our NGL business performed well this quarter, with higher NGL transportation volumes and record equity NGL production compared to the first quarter of 2009. Throughput volumes were higher on the majority of our pipelines, driven by strong demand for NGLs. As a matter of fact, capacity is so tight that we're putting shippers on allocation on some of our systems. The Mid-America pipeline, Rocky Mountain, and Seminole systems continue to run at capacity, with Mid-America dedicated processing plants operating at full rates.

Our Rockies business performed surprisingly well this quarter, despite the lack of a significant uptick in drilling. Greater efficiencies were current drilling rigs and a backlog of completed wells that we have connected to our pipeline system led to an increase in inlet volumes into our Meeker complex, which for the quarter were 1.3 Bcf a day -- that's up 20% from the fourth quarter of 2009.

Total volumes gathered on our Jonah and Pinedale systems in Wyoming have remained steady, and our Pioneer cryo remains full at 750 million a day. At full operating rates, Meeker and Pioneer combined to generate almost 100,000 barrels a day of mixed NGLs that feed into our value chain. We think there are still packages of gas and acreage to be captured in both Wyoming and in Colorado. We will pursue these opportunities to maintain a solid base load for these plants and to establish a firm platform for growth.

The Gulf Coast gathering and processing business exceeded our expectations this quarter, due to increasing South Texas production. This is driven by incremental volumes from the Eagle Ford Shale. We increased the loading fees on all of the terminals on our Dixie pipeline, effective January 1. Increased loading fees and a cold winter versus last year drove revenue up by approximately $5 million.

We also completed the expansion of our storage at Apex, North Carolina, which will allow us to supply an additional 800,000 barrels of propane annually to the Southeast market. Also, the LPG terminals on the TE Products mainline were removed from the regulated tariff at the end of the quarter. Those terminals are now part of our unregulated NGL pipeline and storage business.

We receive a lot of questions on our hedging program. And as I said in last quarter's call, we were patient when it came to hedging our NGL production, waiting for the right opportunities. Currently, we are 53% hedged on our equity production for the remainder of 2010. Approximately 57% of our Rockies keepwhole production in 2010 has been hedged at a gross margin of around $0.61 per gallon. We are approaching those levels that we enjoyed in mid-2008.

Approximately 42% of our percent-of-liquids production has been hedged at attractive prices. We continue to have patience, looking for opportunities to put on additional hedges and waiting for the market to come to us.

In natural gas, as Mike mentioned earlier, we had record gas transportation volumes this quarter, supported by higher throughput on our Acadian system, our Piceance gathering pipeline, the White River Hub, and our Encinal system in South Texas. Volumes decreased on our Texas intrastate system due to continued declines in traditional South Texas production and lower West to East spreads. The good news is production is up over 75 million cubic foot a day since the beginning of the year, due to new Eagle Ford production coming online.

We also began collecting demand fees from the Sherman extension in August of last year, and we're looking forward to the Trinity River lateral coming on in early third or late second quarter.

Spreads from West to East Texas have come in significantly, from $0.29 in 2009 to $0.07 this year. As a result of the high spreads during 2009 and a warm winter, it led to low firm transportation volumes. Consequently, we pushed a lot of secondary firm volumes across the pipe. The colder-than-normal winter this year led to higher utilization rates by firm shippers, leaving less room for secondary firm or IT volumes to flow.

Gross operating margin from our Gas Marketing Group was down this quarter, as Mike told you, compared to first quarter 2009, due primarily to two reasons -- lower basis differentials and higher transportation expenses from capacity leased on Gulf crossing pipeline and the Northern border pipeline, which started after the first quarter of last year.

Our Haynesville Acadian extension pipeline continues to gain support in the market, and we're close to having signed up 1.8 Bcf a day of firm capacity. A recently announced acquisition of assets from M2 Midstream in the Haynesville is expected to enhance our opportunities for future development and expansions in that shale play, such that the Haynesville extension ultimately reaches its full 2.1 Bcf a day of capacity.

Turning to the Eagle Ford, rig count has expanded to over 50 rigs operating at the end of the first quarter from just 10 rigs in the first quarter of last year. We expect the rig count will continue to increase, driven by the richness of the gas in the Eagle Ford. We're continuing active negotiations with every producer in the Eagle Ford.

In 2009 and this year combined, we expect to spend more than $200 million to serve the gas gathering, processing, and NGL needs of Eagle Ford producers, and in order to fill our existing plants. Currently, we have over 400,000 acres dedicated to us. This capital program in 2009 and 2010 will support a more comprehensive solution to growing Eagle Ford production.

Before I turn the call over to Randy, I want to spend just a moment to discuss our propylene business, which reported strong results this quarter. They were almost double what we reported in the first quarter of 2009.

Propylene prices increased 27% in the first quarter of 2010 as a result of lower cracker-source propylene and improved product demand. The increased supply of refinery-grade propylene feedstock and strong propylene demand resulted in a growth in sales and processing volumes of close to 200 million pounds compared to the first quarter of 2009.

With that, I'll turn it over to Randy Fowler.

Thanks, Jim. I'd like to briefly discuss some income items that are below the operating income section of the income statement -- liquidity and also some capitalization items.

G&A expense for the first quarter of 2010 increased by $2.7 million, up to $37.6 million, primarily due to higher non-cash unit-based compensation expenses. The provision for income taxes decreased to $8.7 million this quarter from $16 million recorded in the first quarter of 2009. The majority of this decrease was due to lower corporate income taxes, approximately $6.9 million of that, from Dixie pipeline, which had a taxable gain associated with the sale of assets in the first quarter of 2009.

We invested approximately $321 million in growth capital expenditures during the first quarter; and for the year, we currently expect to spend an estimated $2.8 billion, which includes approximately $1.6 billion for growth capital expenditures and $1.2 billion for the acquisition of gathering assets from M2 Midstream that we announced earlier in the month. Some of the larger approved capital projects include the Haynesville extension pipeline, the Mont Belvieu NGL fractionator, finishing up the Trinity River Basin lateral natural gas pipeline, and other projects in the Eagle Ford.

In the first quarter, we spent $33 million in sustaining capital expenditures. We had come in and -- back at the time of the fourth quarter earnings announcement, we estimated maintenance Capex for the entire year of 2010 to be approximately $250 million. Typically, we do get off to a slower start in the first quarter as far as spending those maintenance capital expenditures, most of the time due to weather. January and February of this year was very wet; so, again, we got off to a slow start there. I think we may have to hustle to spend $250 million this year. We should be able to give you a better estimate on that at the end of the second quarter.

In terms of capitalization, adjusted EBITDA for the 12 months ended March 31, 2010 was approximately $2.8 billion. Adjusted EBITDA, as we noted in the press release, is EBITDA less equity earnings from unconsolidated affiliates plus the actual cash distributions received from those unconsolidated affiliates. Our leverage ratio with debt to adjusted EBITDA for the last 12 months was 3.7 times at March 31, 2010, with debt being adjusted for 50% equity content in the hybrid debt securities that we have outstanding.

Our floating interest rate exposure was approximately 10% at the end of the quarter. The average life of our debt was nine years, which incorporates the first call date for the hybrids, and our effective cost of debt was 6.1%.

In terms of liquidity at the end of March, after adjusting for the net proceeds of $485 million from our equity offering in April, we had liquidity of approximately $2.4 billion, which includes availability under our $1.75 billion revolver and unrestricted cash. Affiliates of Enterprise Products Company, a private company controlled by the Dan L. Duncan family, and our largest unit holder, confirmed their willingness to consider to invest up to $150 million in additional partnership units during the remainder of 2010, including their commitment to reinvest $50 million through Enterprise dividend reinvestment plan here in the May 2010 distribution.

With that, Randy, I think we're ready to open it up for questions.

Tina, we're ready to take questions now.

(Operator Instructions). Brian Zarahn, Barclays Capital.

On the Haynesville extension, I think you mentioned 1.8 Bcf of capacity has been contracted. About how many shippers does that represent?

I think what we said is we're getting -- we're moving toward 1.8, Brian. I'll let Chris answer as to how many shippers we're talking about.

We're still on the same seven shippers and we're just upsizing some of the volumes to some of the existing players.

Okay. Jim, I appreciate the color on the propylene fractionation. Do you think this level of performance can continue through the rest of the year?

On what?

Propylene fractionation.

I think our demand is going to be strong, Brian. I think what we're going to see over the next couple of months -- and we've been trying to -- I'm looking at Lynn Bourden -- we've been trying to sell forward. You did have some shift recently to heavier feedstocks driven by a strong propylene prices. I think we're expected to see that soften a little bit in the next month or so. But in the process of doing that, we expect the ethane demand to pick up fairly hard.

And it's just going to be up-and-down and we're going to have good strong demand. We're going to have decent margins. And we're going to have nice margins periodically. And it's really driven by how much ethane is being used. I mean, one of the reasons we had such strong propylene prices in the first quarter is that we're using so much ethane, you didn't get the propylene produced from crackers.

The other thing we're finding is that our term customers have figured out that they don't particularly want the unreliability of people that can switch feedstocks and watch their propylene production vary. So we get more folks wanting to talk to us about term contracts because ours is a lot more reliable.

Okay. And then turning to NGL fractionation, I know you mentioned there was a little gain in first quarter of last year, but you had higher volumes but margins were down. Could you talk a little bit about that and what do you expect to see the remainder of the year?

Ask the question again, Brian. I must be -- I'm getting old.

Okay. On your NGL fractionation business, your volumes were up year-over-year but margin -- your operating margin was down. Can you give a little color as to -- I know there was a gain in there from last year, but a little more color on that will be helpful.

Brian, this is Randy Fowler. It was last year at our Norco facility, we had some operating gains and I think it was probably in the ballpark of about $4 million or $5 million, with the operating gains in the first quarter last year.

Okay. Finally, I know you were evaluating another fractionator to your system. Can you give us a sense of how far along the process is in reviewing that?

No.

All right. I tried. Thanks, guys.

Stephen Maresca, Morgan Stanley.

A question for Jim. I always thought that some ethane and propane price dip over the past couple of months. Was that an aberration or due to some maintenance downtime? And given what you think about demand and where inventories are, what sort of upside do you see in those prices for the remainder of the year?

We don't predict prices, we love margins. That's what we focus on more than the absolute. And margins have stayed at our -- for instance, in the Rockies, I guess, Lynn, we're up around 32 plus cents a gallon. I mean that's -- you can look on anybody's reports and see that.

We think -- you did see a little dip in ethane usage. You had some plant outages, plant maintenance. And you did have a little bit of shifting driven by pretty strong propylene, benzene, and butadiene prices during the course of the quarter. We're seeing a move back to ethane as those prices weaken. And I'm not going to tell you where we think it's going to go, but we've got a -- Lynn's got a graph as to what he think ethane inventories are going to be doing the balance of the year. I will tell you they're going into Southeast.

Okay. And then you guys had talked about the dip in the onshore natural gas pipeline unit margins. Is there any color behind that? Is that something -- a one-quarter event or can things turn around with that?

This is Chris. Versus first quarter last year, and Jim talked about it in the call, we had the warmer weather first quarter last year. We were able to use our secondary permit in our IT business to go West-East across the pipe and capture the benefit of the $0.27 spreads across the pipe.

This year, the colder weather in January and February, the utilization factor of our firm, customers were up and the commodity rates associated with those firm demand contracts are very low, so they were single digits so you just see the delta there.

As you see here second quarter, third quarter, we've talked about it, we see the spreads West-East across the pipe coming back to the more normal historical pattern let's call it $0.08 to $0.12 range. And remember, we're mostly sold out in our firm basis from West-East exposure to central Texas, so we're not so much subject to spread risk from a firm point of view, but it does hurt our upside potential using our secondary space. To state it more succinctly, we like wider spreads but we're not as sensitive to it as other people are.

Okay. Thanks a lot for the color, guys.

Darren Horowitz, Raymond James.

Good morning, guys. Congratulations on the quarter. Jim, a couple of quick questions for you. Trying to get a sense of incremental ethane demand from this point forward. So can you help us by quantifying the shortfall between the current NGL production capability and cracker demand? And also, as a follow-up, how much of that targeted 100,000 barrels of capacity that was transition in the cracked light ends has actually materialized?

I can point to probably, Randy, 100,000 barrels a day of a combination of ethane and propane, that two years ago would not have been used; it would have been naphtha cracking. I can tell you that we continue to work with a couple of crackers that are currently using naphtha and trying to work with them to convert to be able to use more NGLs.

I think the shortfall, we had it in my script and I took it out because I'm not sure it's right -- but I think we were saying something like 30,000, 40,000 barrels a day, Darren.

Okay. And then just a follow-up question. As you mentioned, Jim, given the tighter domestic supplies of gasoline driving the price higher and from a domestic perspective, us moving a bit higher on the cash-cost curve, do you think the domestic export ability for ethane gasoline could be impacted, at least in the short-term?

I think it was in the first quarter. Lynn, was it in the fourth quarter last year? Pushing 30%? 25% to 30%? (multiple speakers) We're saying it's around 20%. Yes, Lynn's got a slide that's kind of good. It says you don't have to outrun the bear; you've just got to have to outrun Darren. (multiple speakers) You don't have to be as good as the Middle East as long as we're competing with naphtha crackers in northwest Europe and the Far East.

I think they're competitive. It's still a good place to produce ethylene and polyethylene. And we're going to get our -- I think they'll get their share of exports. They're not going to compete with ethane crackers in the Middle East, but we don't think they have to. And the latest CMAI cost curve shows that they're pretty competitive with propane and natural gasoline out of the Middle East.

Okay. And just a final question for you, Jim, and I apologize if I missed it, but when you were detailing the 42% of your percent-of-liquids that are hedged, did you mention what price?

No.

Okay. Would you mind mentioning the price?

It's a nice price, Darren.

All right. Well, keep enjoying the nice prices. Thanks, guys.

Ted Durbin, Goldman Sachs.

First question is just -- you talked about the Rockies volumes being up and NGL up. How are you seeing that happening -- you've got low gas prices now. What's the outlook for going forward? And what's really driving the volume increase, given that the rig count hasn't really bumped up as much out there?

I think what we said earlier is we just recently tied into some wells that have been completed, so that's helped. Mike mentioned that we had completed our work to tie in the Collbran Valley. That was down in the southern part of the Piceance where we did shut down a plant that added probably close to 100 million a day.

And frankly, we're doing some pretty creative deals out there to keep our plants full by working with people who have dewpoint plants to make sure that gas flows to our cryos and we give them a piece of the action. So we're doing everything we can to keep those -- we're going to keep the plants full. And we're going to share a little bit of the margin, but it's going to be full.

Okay, so would you say it's sort of taking share from others here and you're giving price discounts to do that? Or how are you actually making that happen?

Ted, as Jim said, part of it is hooking up wells that were already drilled, so that's not taking it away from anybody else. And part of it is with the Collbran Valley system, we're picking up gas that we previously didn't have access to.

Got it. Okay, great. And then just on Independence, the volumes were down. What are you looking at in terms of going forward in 2010 and 2011? Do you sort of see them flat from here? Or how much volume recovery do you see in Independence?

Well, we had volume recovery at the end of the first quarter and now into April. And so we expect the volumes to remain in the 725 to 750 range over the next couple of years. Pretty much flat with where we are here.

Okay, great. And then if I could just the last one -- in terms of just the distribution increase, you've been pretty consistent in terms of the three-quarters of a penny every quarter. Have you thought at all about ramping up the rate of growth on the distribution? Or are you kind of comfortable with where you are right now?

Well, we're comfortable with the increase we just announced, and clearly, we've been pretty consistent over the last several years about raising our distributions. We do have a relatively large Capex budget this year. We started off the year with $1.5 billion, $1.6 billion. We've got M2 Midstream acquisition on top of that, another $1.2 billion, so we're getting close to $3 billion. It's helpful to have cash that we can reinvest in those assets that keep us from having to tap the equity markets as much as we might have and to reduce our leverage.

Okay, that's great. Thanks a lot.

Ross Payne, Wells Fargo.

First question is, what is the cost of the Trinity River Basin lateral? How big is that pipe and what's the capacity looking like from that?

Yes, Ross, probably about 250. We actually had that spiked out in our analyst meeting.

Okay. And can you speak to the producers that are behind that?

The total capacity in that system is going to be close to 1 Bcf. And we've got one producer committed to a long-term tenure agreement and we're continuing to develop in the area, because this is an area that gets us down to the Dallas-Fort Worth area. There's a lot of municipalities along the way there that have been difficulty getting our pipeline approved. That's what has caused this delay. But now that we're all through that, we've seen an abundance of drilling permits issued.

So there's a likelihood of a lot of small independents starting to actively drill in the area to hold their acreage and get the gas produced. There's been a lot of drilling done but we've seen the permitting process more than double here in the last 60 days, now that we've announced that, our project is going to be completed by July 1.

Okay, right. And also, one item that I haven't heard mentioned here today is, any thoughts out of the Marcellus for NGLs? Any update relative to the analyst meeting? Thanks.

Let me take the first stab at that and then I'll hand it off to Jim. Obviously, the Marcellus is getting a lot of attention, a lot of press releases from various partnerships on solutions. We're taking a little more holistic approach.

We're really looking at it from the producer's standpoint, where do they get the best price for their NGLs? Because at the end of the day, they're the ones that are going to bear the cost. So it's not just a matter of extracting the NGLs and shipping them to a point; you've got to have a market that really needs it. Otherwise, the net back price of the producers is pretty underwhelming. So we're really looking for an industry-wide solution that takes care of the producers.

Ross, Mike just nailed it. To put it in context, I think every press release you've seen and we're not real big on press releases for hoax. We're looking at it that you really -- every one of those deals are pipeline projects. What we're looking at is how do you take this ethane and distribute it to crackers throughout the system?

And if you're going to have ethane going to crackers, you better have storage, you better have a way to keep it flowing. So we are talking to people about our project, not going to press release it, give them the reliability of flow assurance and gives them access to a broader range of customers.

Hey, Ross, circling back on your Trinity River lateral question, total Capex on Trinity River is $278 million. And to finish up the project in 2010, we're looking to spend approximately $120 million.

Okay, great. And Randy, while I've got you, just one final question. Your leverage metrics are obviously quite impressive at this point, around 3.7 times or so. Is that the new range you see your Company operating in? Or is it going to vacillate a little bit with acquisitions and kind of be maybe 3.6 to 4.1 type of range?

You know, Ross, I think historically, we've said we're sort of comfortable in that 3.5 to 4.0 times range. We just sort of lived in the four times range and actually, depending on where we were in our construction cycle, saw that tick up to about 4.2, 4.3. Obviously, that's an area we don't want to live in. I think if you would on a steady state basis, we're more comfortable in the 3.5 to 4.0 times range.

Okay, great. Thanks, guys. That's it for me.

Yves Siegel, Credit Suisse.

If you don't mind, I'd like to ask the elephant in the room question, which is, given the passing of Dan, is there any thought in -- what is the thinking as it relates to the Enterprise family of companies? I.e., when you think of Duncan, DEP, and you think of the Acadian expansion, can you address the thought process going forward? There's three entities, publicly traded entities out there. Is there any change at all in the way you think of those three entities?

The easy answer is that nothing has really changed. When we set up the EP and took it public, we said that it was there to facilitate the growth of Enterprise to invest in slower growth assets, and that we expected it to appeal to investors that were looking for higher yield and not as concerned about the growth.

Certainly, the Haynesville extension is a big step for DEP and I'm sure that Randy will talk about that at the next earnings call for DEP. But going forward, our plan really has not changed. Our thought process is that if we have access that we think have a slower growth rate that fits the profile that DEP is looking for, then we would consider a drop-down and DEP might consider it as well. I mean, both sides have to agree. But absent that, there really hasn't been any change in fundamental philosophy.

Okay. Then can I ask -- to beat the Marcellus horse a little bit here -- any sense in terms of timing as when ethane becomes a problem and when a solution has to be effected?

Yves, as we understand it, TEPPCO has a labor that allows them to blend more ethane, that of labor I think expires in 2013. So that's probably as good a benchmark as any as to where there needs to be a solution.

The question is, if production ramps up enough where you can't blend it down to the BTUs, then you can potentially have a problem before then. But if 2013, it's certainly a problem.

Okay. And then my last two-part question is -- Jim, earlier in your remarks you said -- you were talking about supply and demand and as it relates to NGLs -- supply increasing. Can you put that into context with where you think it is? As it relates to -- I guess you have the Eagle Ford and you have the Marcellus, but I'm also thinking that with gas prices being relatively low, I'm just not sure if there might be a sharper falloff in conventional drilling. So I'm still trying to figure out the dynamics moving forward in terms of natural gas.

And then the second part of the last question is, what are you folks thinking about in terms of investing more dollars in the Gulf of Mexico?

Well, I can't help you as to what the supply is going to be, because I tend to agree with you as it relates to conventional at these price levels. I think we do expect, because of the richness of the gas, we do expect oil rigs to be deployed to the Eagle Ford. We think that's a growth area. And if there is a solution to ethane in the Marcellus because of that southwest part of Pennsylvania and the richness of the liquids, assuming the value is there for the liquids that far away from its natural home, you would expect someone to drill there.

I mean, as far as the Gulf of Mexico, I think we're continuing to work -- I'll let Mike answer that one (multiple speakers) --

Yes, Yves, when we look at capital expenditures, we look across all of our business segments. We look at the opportunities that are available; we look at the risk-adjusted returns on those projects. We look to see which of those opportunities are here today and gone tomorrow, which ones can actually wait a year or two. And then we decide which ones make the most sense for the partnership.

And so we're trying to balance the needs of the partnership. As I said before, we're already at $2.8 billion for this year with the acquisition of those midstream assets. So it's a pretty fulsome year already, particularly since we're only in the end of April right now. But we have not ruled out anything in the Gulf of Mexico. In fact, we're looking at some projects. It just depends on when we get close to making the decision on which ones to pull the trigger on and where those stack up.

That's great. Thanks, guys. I really appreciate it.

Michael Blum, Wells Fargo.

Just one question. And I apologize if you reviewed this but I didn't catch it -- in your onshore crude oil pipeline segment, gross margin was down pretty significantly year-over-year. It looks like it was around the marketing business. Can you just talk about what's going on there? Was that a blip or are you running that business differently?

This is Mark Hurley. A couple of things happened there in the first quarter and it was very much margin-related. One is the sweet-sour differential, particularly West Texas and Oklahoma. That differential declined quite a bit, just due to the competition for the sour barrels.

And so while we continued to move quite a bit of volume there, the margins hurt us on the overall marketing side. And secondly, the contango in the market was much weaker than it had been in 2009. And so the marketing of barrels in future months just didn't yield as much margin. And so although the contango has certainly bounced back in April and it's quite strong now.

Michael, as Chris said on the gas side, the same thing holds true on the crude side. Our marketing business is there to fill up our assets and to take advantages of price differentials when they occur, but we're not dependent on them. So both those businesses had a great year in the first quarter of 2009, and we'll continue to capitalize on those opportunities as they become available.

Okay, so, the new way to think about it -- the first quarter number is a good run rate in let's call it a less favorable environment, and the year-over-year number of '09 is in kind of a more favorable environment?

Seems fair.

Okay, thank you.

John Edwards, Morgan Keegan.

Just on the onshore crude oil pipeline services, just kind of following on, so you're saying that where we are right now, this $27 million you expect that you're going to be running about that for the rest of the year, you think? Just following on Mike's question.

I don't think we've said that. I think we said that the first quarter wasn't as opportunistic, if you will. I think the contango market is coming back -- Mark?

Yes. Yes, exactly. I think it will -- I think the first quarter was not particularly favorable in terms of either the marketing margins that we saw, both the sweet/sour differential and the contango. The contango has bounced back and so we expect that to be a little more favorable going forward. The sweet/sour differential I think is going to continue to be under pressure, just due to the demand for the sour barrels.

This is Jim. One of the things we're doing as it relates to our marketing activity in our crude business is -- when did we buy this operation? In October/November?

October.

What we're trying to get our arms around -- and, in fact, we're going to do it -- is we're going to model everywhere we've got margin risk, just like we do in our Enterprise assets. And when we see something we like, we're going to be pretty aggressive in locking it in to the extent we can in the future.

And another thing that we probably aren't ready to talk about in too much detail is we're very interested in building out that system and in improving connections, and making it more akin to what we have on the NGL side.

That's absolutely right. In the process of doing that, you create more of those opportunities to get the upside, just like we do in the natural gas liquids. So connectivity, expanding it, is a key area of growth.

Okay. I appreciate the detail on that. And then, obviously, your petrochemicals are quite strong. You provide a lot of good commentary there. I guess clarifying going forward, do you think it's going to continue pretty strong kind of at these levels?

I think what we're saying is because of natural gas prices and the related costs of NGLs relative to crude, that petrochemicals have a very attractive price of feedstocks. And they're very competitive across the world. And even in a time when the US has been in a recession and is only now starting to come out, the petrochemicals have been doing very well. So you would expect as the economic recovery continues, that they'll continue to do well.

Okay. And just on G&A, what's -- is this quarter a pretty good run rate for the year? Or do you expect it to tick up a bit the next few quarters?

John, I'd say -- I wouldn't expect it to be any more than this level.

All right. And then I think you said maintenance Capex was a little bit light this quarter's, but you expect that to tick up the rest of this year?

You know, it's not unusual for the first quarter to be kind of light. As Randy said, we had a wet first quarter. In a lot of areas you've got snow on the ground, you can't get in. So, typically, the second and third quarters are our busiest quarters in terms of maintenance Capex.

I think Randy is right -- seeing how much we have left to spend in 2010, to meet that $250 million number, we may be pushing it to get there.

John, that's why I think when next quarter when we have our second quarter earnings call, I think we'll be able to come in and hone in on that estimate a little bit more -- if there is any change from the $250 million.

Okay.

I'll tell you, it definitely won't be over the $250 million.

Okay, great. Great quarter. Thank you very much.

Jeremy Tonet, UBS.

My questions have been answered, thank you.

Our final question will come from the line of Mark Easterbrook with RBC Capital.

Just a lot of questions have been answered already, but one question -- have you guys considered the use of hybrid debt again? And exactly how much capacity do you have there that you could potentially go out and use the hybrid debt again to finance some of the needs that you have?

I don't think it's a question of the capacity we have so much as the costs.

Yes, I think a couple of things on there. Mike is right -- as far as from a cost standpoint -- and again, you guys -- we've sort of communicated how we look at our cash cost of capital, both on debt and equity, modeling that out over 10 years, so if you would, a hybrid security is callable after 10 years. So we look at what the cash cost of a hybrid debt security is versus the cost of 50% equity/50% debt, and where's -- is there a breakeven point?

I think when we issued the hybrids back in 2006, 2007, especially 2007, you had a breakover point where the hybrids were a little more expensive, probably towards the first couple of years. And then after that, they were a little more attractive than a 50/50 mix of debt and equity.

Lightly where we've seen that breakover point is out to maybe year five, year six. So not quite as attractive. I think the other thing we need to wait and see also is the way Moody's is looking to come in and change the way, or considering the change, of how they view the hybrid securities. Scratching our head a little bit on the application to industrial companies, certainly understand its application to financial companies.

But with that, I think the security that we have outstanding could be 25% equity credit as opposed to 50% equity credit. So I think there are two or three things happening on the hybrid front, so I wouldn't look to see us issuing hybrid securities any time soon.

Okay, thanks.

Tina, is that our last question?

That is our final question, sir.

Okay. Tina, if you would, give our listeners the replay information real quickly.

Ladies and gentlemen, today's conference call will be available for replay beginning at 1 p.m. Eastern Standard Time. The number to dial for the replay is 800-642-1687 and the conference ID number for the conference is 70292007. Again, the conference ID number is 70292007. This does conclude today's teleconference. You may all disconnect.

Thank you and have a good day.