Enterprise Products Partners LP (EPD) 2011 Q1 法說會逐字稿

Good morning. My name is Tiffany, and I will be your conference operator today. At this time, I would like to welcome everyone to the Enterprise Products Partners and Duncan Energy Partners first quarter 2011 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.

Randy Burkhalter, you may begin the conference.

Thank you, Tiffany.

Good morning, and welcome to the Enterprise Products Partners and Duncan Energy Partners joint conference call to discuss first quarter earnings. Our speakers today will be Mike Creel, President and CEO of Enterprise Products Partners and General Partner; followed by Jim Teague, Executive Vice President and Chief Operating Officer; and Randy Fowler, Executive Vice President and CFO of the General Partner of Enterprise, and President and CEO of the General Partner of Duncan Energy Partners. Also in attendance today 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 the expectations reflected 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 will turn the call over to Mike Creel.

Thanks, Randy.

Before we get started today, I would like to remind everyone the purpose of this call is to discuss first quarter results. So, we won't be discussing the proposed Enterprise Products Partners and Duncan Energy Partners merger and will not entertain any questions regarding the proposed merger.

We're off to a good start with record net income, adjusted EBITDA and distributable cash flow this quarter attributable to higher natural gas and NGL pipeline transportation volumes. Record NGL fractionation and fee-based processing volumes and strong equity NGL production. Our diversified integrated system continues to benefit from increased demands for NGLs as reflected in higher pipeline throughput and improved sales margins. Gross operating margin for the quarter increased 9% to $875 million from $806 million in the first quarter of 2010 with the NGL Pipelines and Services, Onshore Natural Gas Pipelines and Services, and Onshore Crude Oil Pipelines and Services each reporting improved results. This led to record adjusted EBITDA of $890 million and record net income of $435 million.

Our partnership generated record distributable cash flow of $694 million this quarter which provides 1.4 times coverage of the increased cash distribution of $0.5975 per unit with respect to the quarter. We retained $207 million of distributable cash flow this quarter which is available to help fund our growth capital projects. The largest improvement for the quarter came from our NGL Pipelines and Services segment and which reported gross operating margin of $504 million, a 15% increase from the $437 million reported in the first quarter of last year. Our natural gas processing and related NGL marketing business benefited from improved demand for NGL as the higher NGL sales margins and volumes led to an $18 million increase in gross operating margin. Our Rocky Mountain contributed $6 million to the quarter to quarter increase, primarily due to higher fee based processing volumes. We also had a significant increase in fee-based processing volumes in Texas primarily from gas production from the Eagle Ford.

Our NGL Pipelines and Storage business had a 20% increase in gross operating margin this quarter compared with the first quarter of last year primarily due to the mid-America pipeline which had increased long haul movements at higher tariff rates that went into effect last July. We also had higher gross operating margin from the NGL terminals and our South Texas and Lou-Tex NGL pipeline systems. In addition, we exported 10.2 million-barrels of propane for the quarter, a 34% increase over the first quarter of 2010. Production of NGLs in the Rockies continues to be strong with new gas processing plants expected to extract an additional 60,000- to 70,000-barrels a day of natural gas liquids by 2014 from major basins in Utah, Colorado, Wyoming and New Mexico. To meet this expected volume increase last week we announced a planned expansion of the Rocky Mountain portion of our Mid-America pipeline system. This project will include looping the existing pipeline with up to 290 miles of 16-inch pipe and adding more pump station capacity. Shippers executed ten year firm shipper pay transportation agreements with a total initial commitment of 38,500-barrels a day that may ultimately increase to 85,000-barrels per day. Subject to certain regulatory approvals we expect this expansion to begin service in the third quarter of 2014.

Our NGL fractionation business reported record gross operating margin of $46 million, a 70% increase over the $27 million reported in the first quarter of 2010. This increase was largely attributable to our new Frac 4 unit at the Mont Belvieu complex, which began commercial operations during the fourth quarter of last year. The new facility is running at full capacity with rates greater than 80,000-barrels a day. Due to strong petrochemical demand for NGLs we currently are constructing a fifth fractionation unit at Mont Belvieu, also with an expected capacity of over 80,000-barrels a day that we expect to be full when it begins operations in the fourth quarter of this year. With our recent acquisition of an additional 1,200 acres at our Mont Belvieu complex, we have plenty of room to build additional fractionation capacity as needed.

Our Onshore Natural Gas Pipelines and Services segment reported a $29 million or 22% increase in gross operating margin on transportation volumes of 11.7 trillion BTUs per day, 9% higher than the first quarter of 2010, $15 million of the quarter-to-quarter increase was from the State Line and Fairplay natural gas gathering systems we acquired in the second quarter of 2010. Higher capacity revenues earned in South Texas on our Texas Intrastate System and improved natural gas marketing margins accounted for $15 million of the increase. Gross operating margin are for the Offshore Crude Oil Pipelines and Services segment increased $5 million or 19% over the first quarter of 2010, primarily from crude oil marketing which benefited from improved crude differentials and volume growth on the Red River, West Texas, and South Texas pipelines. Our South Texas pipelines benefited from improved crude oil production in the Eagle Ford, and the Seaway pipeline had a 13% decrease in net throughput.

We recently announced our intention to form a joint venture with Energy Transfer Partners to construct a crude oil pipeline from Cushing, Oklahoma to Houston. This pipeline would give producers greater access to the Gulf Coast refining markets and provide an outlet for more than 400,000-barrels a day of crude oil supplies, which currently are stranded at the Cushing Hub and priced at a substantial discount to imported crude oil on the Gulf Coast. The project also includes approximately 500,000-barrels of crude oil storage capacity to be added at our new Echo Terminal in Southeast Houston. We're continuing to work with producers to secure support for the proposed pipeline.

Our Offshore Pipelines and Services segment had a $20 million decrease in gross operating margin this quarter from the first quarter of 2010 due in large part to lower exploration and development activities in the Gulf of Mexico. The first quarter of last year included $9 million of insurance related gains. Naturally occurring production declines have not been offset by new drilling and until replacement wells are drilled, volumes are expected to remain below prior year levels. While the federal government has resumed issuing deep water permits, progress has been slow.

Gross operating margin from the Petrochemical and Refined Products and Services segment was $112 million this quarter compared to $120 million for the same quarter last year. The Refined Products Pipeline business had a $31 million decrease in gross operating margin, primarily due to an estimated $14 million decline as a result of lower revenues and higher expenses related to repairs of a segment of our Products Pipeline System in New York. Other decreases on our Refined Products Pipelines included approximately $10 million from lower transportation volumes originating on the Gulf Coast for delivery to the midwest markets and $5 million from higher maintenance and pipeline integrity expenses. The Propylene Fractionation business had a $6 million increase in gross operating margin to $52 million, as lower operating expenses more than offset the effect of decreased fractionation and pipeline volumes due to refinery outages. The remaining businesses in the Petrochemical and Refined Products Services segment reported increased gross operating margin this quarter, compared to the first quarter last year, with the largest improvements coming from the Butane Isomerization business, which reported an $11 million increase due to increased sales of by-products and higher volumes.

Based on our continued strong performance and record distributable cash flow, we announced an increase in our quarterly cash distribution to $0.5975 per unit or $2.39 on the annualized basis. This is a 5.3% increase over the distribution declared with respect to the first quarter of 2010, and it is our twenty-seventh consecutive quarterly distribution increase and our thirty-sixth increase since our IPO in July of 1998. We're pleased with our results for the quarter and want to recognize our employees for their efforts. Across all of our departments, from commercial, engineering and operations to accounting, finance, legal, and all of our other administrative and support groups, we have an incredibly talented and dedicated team. With this team and our diversified and well-positioned asset base, we believe we should be able to continue to build value for our investors. Our goal, as always, is to be the provider of choice for customers seeking the best in a full spectrum of economic and dependable midstream energy services, and we continue to put capital to work to serve them.

With that I will turn the call over to Jim.

Thank you, Mike.

Let's talk about opportunities to serve our customers, both producers and consumers, and that's what motivates us at Enterprise. Opportunity is normal butane today to RBOB at $1.20 a gallon. Opportunity is ethane in Conway at over $0.20 a gallon below Mont Belvieu. We have seen it at $0.25, and the wide grade barrel at $0.15 to $0.20 a gallon off of Mont Belvieu. Opportunity is $1 a gallon gas processing margins. Opportunity is LLS selling to WTI at $14 over. Opportunity is natural gas below 30% of crude on a BTU basis or propylene approaching $1 a pound. Opportunity is growing production, driven by shale gas, and expanding demand, driven by petrochemicals. It is opportunities like these that continue to provide us with linkage and expansion projects across our business lines, and we believe these fundamentals will remain strong.

Across our businesses in crude, natural gas, NGLs, refined products and petrochemicals, we remain disciplined in pursuing projects that integrate well with our existing system of assets. In the Eagle Ford, we are fully subscribed on our initial 600 million a day gas processing plant, and we're already in negotiations with producers to fill the next phase of that plant. Our Eagle Ford crude oil pipeline is almost fully subscribed, but can be expanded. The Eagle Ford has been a team effort as we have provided our customers with a full spectrum of services, including gas gathering and processing, residue take away, NGL transportation, fractionation and marketing, and crude oil transportation and marketing. Our fifth Mont Belvieu NGL fractionation train will be operational by December of this year, and we recently applied for the required permits for a sixth train should we decide to build it. Interestingly, with our fifth Mont Belvieu fractionation train, we will operate more than 750,000-barrels a day of fractionation capacity in the US. Our pipelines remain strong, driven by wide price differentials, strong petrochemical demand, and production growth.

For the last year, you have heard us say don't under estimate the petrochemical industry's ability to consume more ethane. Given the announcements of -- the recent announcements, we'll probably retire that statement. Those announcements speak for themselves as to the health of the petrochemical industry and those same fundamentals point to a bright future for midstream companies that are aligned with that industry as we are. In our recent analyst meeting, we outlined some of the fundamentals around ethane economics and our view that ethane margins for gas processing will remain robust even as NGL production ramps up from rich gas basins like the Rockies, the Eagle Ford, the Woodford, and the Permian. The primary support for ethane processing margins is coming from petrochemical demand driven by the gas to crude spread. Our internal forecast shows potential ethane demand to increase an incremental 200,000- to 300,000-barrels a day by 2015. That would have raised a few eyebrows just a few months ago, but in light of the announcements from Dow, Chevron, Phillips, West Lake, and announcements we expect from others, incremental ethane demand could reach the high side of the our forecast by that time.

The only way to meet the demand for ethane, that petrochemicals are projecting, is for producers to continue developing rich gas resources and for midstream companies like Enterprise to continue building the infrastructure, pipelines, fractionation storage, and distribution systems to bring those volumes to market. We spend a lot of time analyzing the quality of these gas plays and our forecast calls for ethane production to increase to as much as 1.1 million-barrels a day by 2015. That does not include any production from the Marcellus. The question is quickly becoming, in order to meet the projected demands for ethane on the Gulf Coast, does the petrochemical industry need Marcellus ethane and Mont Belvieu. The US is not just competitive in ethane. Our propane resources and continued demand growth around the world is driven an increased reliance on US propane exports. Our propane export terminal is essentially sold out through the end of 2012 and into 2013. The demand for incremental exports has supported the expansion of our terminal that will allow for loading up to 3 vessels at once and increase our loading capability to more than 10,000-barrels per hour of fully refrigerated propane and more than 13,000-barrels per hour of total NGLs. If that expansion had been in place last year and had been full, Enterprise would have been the second largest exporter of propane behind Saudi Arabia.

While we don't talk about it as much as we should, we spend as much time on the demand side of the equation as we do on the supply side. In doing so, we're supporting the supply growth by ensuring that demand is growing and here is a couple of examples. We have been directly involved in the logistics solution to many crackers that is have modified their traditional naphtha furnaces to use more ethane. We can identify 100,000-barrels a day of ethane usage today that was traditionally naphtha. That represents 275 million of natural gas equivalent. We continue to work with petrochemicals as they seek to further expand their usage. We have been exporting some 36 million-barrels a year of propane to markets not served from the US in the past. That's equivalent to 380 million a day of natural gas.

We also focus on customer quality or demand quality. Our Haynesville extension, while crossing some 10 to 12 interstate pipelines, terminates in the Mississippi River industrial corridor with some 1.5 Bcf a day of continuous natural gas demand; in other words, those manufacturing sites use as much as midnight as they do at noon. We take seriously our commitment to provide our customers with -- our producer customers with two critically important services and this is what we try to differentiate ourselves with. First, flow assurance; second, market choices. We also take seriously the needs of our petrochemical and refining customers to have their wide variety of feed stock choices where they want it, when they want it. Mike mentioned our petrochemical business posting solid results with crackers continuing to crack light, reliance on splitter produced propylene is high, and we think that demand will remain strong for the foreseeable future as they seek to go lighter and lighter. Just yesterday, we announced a 500 million-pound a year splitter expansion, evidencing our belief in continued strong demand and margins in propylene.

As far as natural gas, we gave a pretty extensive review of production, depth, and longevity at our recent analyst meeting. Construction on our Haynesville lateral continues to progress on time, and we anticipate nicely under budget and we're looking forward to getting that project up in the September/October timeframe. Drilling and production results continue to be good in the area of where our pipeline originates, in De Soto and Red River Parishes. Wood McKenzie recently published a paper on the Haynesville and identified this area as the absolute sweet spot from an acreage valuation, total reserves per well, and highest production rates. In our crude business, I think we can skip the questions about the reversal of the Seaway pipeline, as Mike has mentioned our recent announcement to form a joint venture with Energy Transfer for a project to move 400,000-barrels a day of crude from Cushing to our new Houston crude oil terminal. A little more flavor, that project will be comprised of new and existing pipeline. It should be in service at the end of 2012, first of 2013. Existing pipe makes up 40% of the distance and most new pipe will follow existing pipeline corridors.

Last week, we announced a project to extend our Eagle Ford crude oil pipeline 90 miles to a place called Gordon Dale. This extension is anchored by Chesapeake, but it has many more potential shippers, and you can bet we're fully engaged. One only has to look at our crude oil projects we have announced to appreciate the Enterprise Lincoln Leverage Strategy, originally our NGL Strategy adopted by our natural gas business, is alive and well in our crude oil business. A fully integrated system from Offshore, South Texas, West Texas, North Texas, and Oklahoma tied to storage hubs with connectivity to 4 million-barrels a day of refining capacity in Cushing and Houston, soon to be totally integrated. And, finally, in our marine sector, we've re-branded our fleet. We continue to integrate that business and our marketing activities in crude oil, refined products, and NGLs. We have projects under way in virtually every business segment and, rest assured, projects on the drawing board in every business segment.

And, with that, I will turn it over to Randy.

Thank you, Jim.

Now, I would like to take a few minutes to discuss additional financial items. General and administrative costs decreased $2 million this quarter compared to the first quarter last year, primarily due to lower public Company expenses and payroll costs associated with the merger of EPE into EPD. Interest expense increased $184 million this quarter from $158 million reported for the first quarter last year. Average debt balances were $14.1 billion and $12.3 billion for the first quarters of 2011 and 2010, respectively. Partially offsetting the increase in interest expense this quarter was higher capitalized interest, which reduces interest expense for the period it is recorded and increases the carrying value of our related assets. Capitalized interest this quarter was $17 million versus $10 million for the first quarter 2010.

For 2011, we estimate total capitalized interest will be $100 million to $110 million compared to $47 million recorded in 2010, primarily due to increased capital expenditures during 2011. Total capital expenditures were $718 million this quarter, which included $665 million for growth projects; approximately 76% of the growth capital expenditures this quarter were comprised of the Haynesville and Eagle Ford related projects. Based on approved projects, we expect to invest approximately $3.5 billion for growth capital expenditures in 2011, the bulk of which would be for the Haynesville and Eagle Ford projects. Sustaining CapEx were $53 million this quarter. We continue to expect to spend in the area of $250 million to $260 million for this year. In terms of capitalization, adjusted EBITDA for the 12 months ended March 31, 2011, was $3.3 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 was 3.97 times for the 12 months ended March 31, 2011. This is after adjusting debt for the 50% equity treatment of the junior subordinated notes or hybrid debt securities. Our floating rate interest -- our floating interest rate exposure at March 31 is approximately 12% of the total debt portfolio. The average debt life was 10.4 years using the first call date for the hybrids and our effective average cost of debt was 5.4%. In terms of liquidity at March 31, 2011, we had consolidated liquidity of $2.5 billion. This includes available unrestricted cash as well as available capacity under the EPD and DEP credit facilities.

Now, turning to Duncan Energy Partners, this quarter DEP had $30.7 million of distributable cash flow, which provided 1.15 times coverage of the $0.4575 per unit cash distribution that was paid to investors on May 6. Cash flow from fee-based assets enabled us to increase the cash distribution to our partners for the tenth consecutive quarter. DEP had total liquidity of $648 million at March 31, including availability under its revolving credit facilities and cash.

With that, Randy, ready for questions.

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

(Operator Instructions)

Your first question is from Darren Horowitz with Raymond James.

Good morning, guys.

Good morning, Darren.

Jim, I just got a couple questions for you. And let me say, I appreciate all of your comments about light ethylene capacity additions and what you think that means to ethane demand. But on the other side of the equation, even in the last few days we've heard of at least another 200,000 barrels a day frac capacity that's coming on line, and probably more to come. And I realize not all frac capacity is equal when you start considering the connectivity down stream, but is there a point that you get to for total Belvieu frac capacity that starts to make you think that the industry's over built demand projections, such that it would impact liquids pricing?

Dayton is about 16 miles north of Mont Belvieu, and our objective it is to have frac trains all the way to Dayton. Which is a joke, Darren.

I figured, Jim

You said that not all frac is the same. Frankly, our frac train when it comes up is full; it's full with long-term contracts with demand fees. I said we've issued -- we've applied for the permits bill for our sixth train. We're going to take a hard look at that and we're going to try to understand, is that something we want to do.

Jim, is it fair to assume that you could probably back stop the majority of a frac 6 just with the off take that's going to Louisiana right now?

It is fair to assume that 5 is going to be up when it starts. It is fair to assume that we plan to bridge Eagle Ford with Louisiana.

Okay. Last question for me, and this goes back to something you mentioned in your prepared commentary. When you think about leveraging your asset footprint to get more Y Grade from Conway to Belvieu, how do you think about adding more take away capacity without negatively impacting that spread, because that spread is obviously very delicate?

Okay, let me think about this, Darren. With that spread, if you added capability to move product from Conway to Mont Belvieu effectively, you are trading guarantee for margin. Does that make sense?

It does, yes. I am just trying to figure out if you would be more incentivised to add Y Grade, or just maybe expand hobs and drop more ethane down.

We are probably incented to have more Y Grade.

Okay. I appreciate it, Jim. Thank you very much. Congrats on a good quarter.

Your next question is from Brian Zarahan with Barclays Capital.

Good morning.

Good morning, Brian.

On the MAPL expansion, just curious the in-service dates not for a little more than 3 years. Is that more of a demand issue or is it more permitting and construction issue?

It is permitting and construction issue.

Okay. And can you remind us what the capacity is on the Rocky Mountain portion, currently?

Today, we can do 275,000 barrels a day, and with all plants producing its full and we're offloading.

Okay. And then turning to the Cushing Gulf Coast pipeline, how are discussions with shippers? Do you also continue to expect to have commitments in about 1 month or 2?

Yes. This is Mark Hurley. We have been talking to all segments of the crude oil business, producers, traders, refiners, and we're seeing strong interest from all of those segments. We're talking to folks in Canada, and those discussions are going very well. We expect to come out with a commitment period here within the next two weeks or so, and we expect a good response.

In terms of cost estimates for the project, are they changed at all and are you willing to provide a preliminary cost estimate?

It is a little premature. We haven't disclosed that yet.

Okay. Just final question on the Haynesville extension, I saw the press release had $1.6 billion for the cost. I thought it was lower than that. Have things changed?

I think $1.6 billion is what it was originally advertised. We expect it to come in lower than that.

Thanks, Mike.

Your next question is from John Tysseland with Citi.

Good morning.

Good morning, John.

Real quick, on the total number of growth projects out there, I think in the press release you guys mentioned $5 billion that you had under construction and that was kind of similar to what you had in the analyst day a few months ago. Is that number-- you think is it relatively low? You have had several announcements since the analyst day and it seems like that has an upward bias at this point. Is that fair to say?

John, the numbers continue to grow, but a lot of that is going to be spending in 2012 and 2013, so I think we're still comfortable with the ballpark estimate that we had for spending in 2011. But as you might imagine, as we continue to move forward in time, we keep seeing more and more opportunities, so that number will continue to build.

All right. Fair enough. We have seen a number of, obviously, fractionation expansions, cracker expansions, pipeline construction. We saw this back a few years ago when we went through the long haul natural gas pipeline build out. How are you handling the cost of construction and your dealings with the ENCs at this point? Are you seeing price escalation? If you could give us a feel for comfort and the cost estimates at this point?

This is Bill Ordemann. We're seeing prices, with the exception of steel prices, pretty much staying flat, and actually I met with someone last year saying labor rates were actually coming down a little bit still. We're seeing steel increase modestly, and we think we're able to control that.

Is it at a point where you can still get flat fee or turnkey type arrangements with ENCs on fractionators, or some of these expansions, or is it still cost plus?

No. We have been doing almost all turnkey work.

And you're still able to lock those in today?

Yes.

Excellent. And then lastly, on the propylene splitter, you guys mentioned that some of that was going to existing customers, you're increasing connectivity to other customers and then you also were planning to connect it to the export market. How much of that is actually destined for the export market at this point, or is it most of that just demand domestically as a result of the by-product availability going down?

We anticipate the bulk of that new production to go to domestic consumption.

And how much can you export if you wanted to?

30,000 tons a month.

Okay. Thank you, guys, appreciate it.

Your next question is from Mark Reichman with Madison Williams.

Good morning. Some of my questions have been answered, but in terms of the export market, the ethylene exports last year were crowded out a little bit by strong domestic demand, and I was just curious, it seems like the export outlook still remains pretty favorable and for ethylene derivatives. And also you're expanding your NGL import/export terminal to take the propane. And so my question is, is what do you see in terms of the growth outlook for exports, and how important is that market to sustain growth for the industry?

Are you talking about ethylene or propane?

Ethylene, first.

Polyethylene and everything.

I probably can't give you a good answer. The sense we get is they're pretty excited about their competitive position, globally, and I would assume they got to believe that some percentage of that production will be exported. You would rather be cracking ethane in the US Gulf Coast than naphtha in northwest Europe.

Okay. Just secondly on the -- you mentioned the Seaway pipeline. I know there has been a lot of conjecture around that. At this point, if Conoco Phillips decided to reverse it tomorrow, and basically what you're saying is you would just continue to move forward as part of the joint venture with ETP?

I think that's probably a stretch they would decide tomorrow to do that. Certainly if they did, since they're a partner of ours, it's something we would have to consider.

Thank you.

Your next question comes from the line of Ted Durbin with Goldman Sachs.

Thanks. Just asking a little bit about, into the Rockies, we saw a dip in your equity NGL volumes, but then a big jump in processing volumes. Is that less Rockies equity volumes, or what's going on -- that mismatch between equity NGLs versus the processing?

This is Tom. What you are seeing there is a shift in the contracting structure that we pointed out; more fee-based processing revenue, versus percent of liquids and the equity volumes, of course, would reflect that.

Right. Okay. No big change in terms of the volumes from different basins? I am also thinking about your MAPL expansion here, which I think you said you had 38,000 a day of commitments, but you can go up to 85,000. I think you would probably get that full, ultimately, but I am just thinking about what the Rockies are doing.

This is Jim Collingsworth. The variance there is giving the producers a little longer to lock up their volume, so they can meet the commitments. The open season gave them an opportunity to give us an initial number, which totals 38,000, and they had until the end of this year to up size that. We have got several producers that are waiting on permits to build additional plants, and once they get those permits they're telling us they're going to come in and lock up higher volumes. We will not build spec. It will be fully subscribed. That's what we'll go to.

Okay. And still under ten year commitments?

Yes. Plus an extension of their current commitment.

Right. Okay. And then just, if I could switch over just to the NGL, the pricing itself, are you more actively hedging in the market now with where NGL prices have gone? How far out are you going out in '10? Can you talk about your hedging strategy?

We have, I don't know the exact percentage, but we have hedged a good percentage of our propane plus through the end of the year. We have been -- we're watching ethane, and we have a little bit of that hedged, but it is so backward dated and looking at the fundamentals we see, we think it will come to us as it approaches the front.

Okay. Those are my questions. Thanks, guys.

Thank you.

Your next question is from Yves Siegel with Credit Suisse.

Good morning, everybody.

Hi, Yves.

Jim, could you just elaborate on what your thinking is around the Marcellus right now?

Confusion. Not sure, Yves. We said at the conference, we've got a project, and we visited with the key producers about that project. We have got some petrochemical customers that are excited about it, but it doesn't seem to be going anywhere, just to be frank.

Well, how do you -- has the strategy of the pet-chem guys changed at all in terms of how they're approaching their feed stock, and where do you think that may go?

I don't understand the question, Yves.

The question is are they trying -- I guess Dow is locking in feed stock evidently, from the Marcellus, you've got Nova trying to lock in ethane as well, and I am just wondering how do you think about that? Is that a new paradigm within the market?

I think they're consistent with their past. The more they have, the better they like it, so they're going to do everything in their power to attract more feed stock to the Gulf Coast. I would imagine that they're looking at it from a portfolio perspective, so that they might have some -- it wouldn't surprise me if they had some that was gas related and then other contracts or Mont Belvieu related. I think they're looking to attract more, and they're probably looking at it from a portfolio perspective, tying some to natural gas and some to Belvieu.

And then if I could, in terms of thinking about the proposed pipeline from Cushing down to Houston, what are the hurdles that you need to get through to get this project done, in addition to getting the contractual commitments? Are there any major obstacles that you see or that you need to jump through, jump over?

This is Mark. It is really pretty straight forward, both from a permitting standpoint and acquiring right of way. We already have the work under way to do that. There are some long lead time items, but we understand what those time lines are. And so we have things in progress, already under way, to meet the dead line that we've set out, so we see it -- it is a big project and, of course, it is challenging, but it is pretty straight forward compared to other projects that we do.

Okay. And then two quick ones. One is what are you seeing on the natural gas marketing side? It looked like you had a good quarter on gas marketing.

Yves, this is Chris. Basic thing is the spreads have opened up a little bit, this year over last year, on some of our long haul stuff. In the northern border capacity, especially, we're 100% hedged off the first quarter, and we're covering full demand costs there. And in our then Gulf crossing, our strategy is in place and is ramping up, and by October the Gulf crossing will all be behind us with -- pretty sure dedications to our volume commitments will be up to our commitment levels to cover that whole capacity, so that problem will be 100% behind us.

Okay. And then the last question is, can you just review how you are looking at asset dispositions? It looked like you had a couple of sales during the quarter. Can you talk about the rationale for that and do you have additional assets that you might try to monetize?

Threw you off there, Yves, huh? We're not used to selling things that people don't force us to. Frankly, we're looking at all of our as assets and from time to time, we see assets that really don't fit our value chain, a couple of fractionators up in the Rockies that we don't operate, a couple of marine assets. Those made sense to sell because they really just didn't add value, they weren't core to what we're doing.

We will take that cash and redeploy it in some of the other project that, frankly, is a lot more exciting to us, but we will continue to look at assets. I don't think you'll see anything near term that's earth shattering; there may be a few odds and ends, but that doesn't mean that we're not going to look at all of our assets.

I am sorry, Mike, but I just got to ask the last one. How wedded are you to the Gulf of Mexico?

The Gulf of Mexico is important in some respects; it brings supply on shore to some of our plants, and so you can tell what we're doing there. We have really reduced our spending in the offshore. We do have some projects that we're doing and we're looking at others. But, frankly, as we look at our capital spending going forward, this year, we've got some things that we to want do in Louisiana and Texas that have a little bit higher priority over some other things that we might do in the Gulf.

Okay. Thanks, gentlemen.

Your next question is from Noah Lerner with Hartz.

Good morning, everybody. Just a quick question, probably a short-term effect, but with the potential for down river flooding from the Mississippi as this thing plays out over the next couple of weeks, I was wondering what impact you think it could have on refinery demand for ethane and other products? And what the impact will be backing up the entire value chain throughout the summer and into the fall?

Bill, do you have any ideas on that?

I think the only announcements I have seen so far, Noah, is that Exxon was going to have to shut down their docks in Baton Rouge and may have to reduce refinery runs a little bit. We're certainly monitoring the situation, and don't expect a significant impact at any of our plants or customers, other than what I have heard there. So I hadn't heard anything that would be problematic at this point in time.

One thing to consider is that even though it may cause some disruptions, as you saw in prior years with hurricanes causing disruptions in certain geographic areas, it might provide opportunities elsewhere, so I think from an impact on enterprise, it shouldn't have much, but certainly we're all hoping that it doesn't impact our customers.

Great. Okay. Thanks for the information.

Your next question comes from Michael Blum with Wells Fargo.

Thank you. Good morning, everybody.

Good morning.

Just a couple of questions, one, Jim, you gave a projection for ethane production out to 2015. I guess two questions on that. One, should we assume a similar trajectory for propane, based on your guys internal work? And then, the second question is, if you could just broadly talk about the big picture assumptions behind that, where is that production growth coming from and what is your assumption on base production declines, and what's going on with the Gulf of Mexico?

Jiminy Christmas, Michael. (Laughter) You got a book. (Laughter)We formed a new fundamentals group. They have done a heck of a job in analyzing what we expect and where we expect it from, and they just kind of wind me up and I talk. I think what we're seeing is growth in the Eagle Ford. Mike already talked about what we're doing in the Rockies, so obviously we see growth in the Rockies. We see growth in the Permian and the Woodford, so that's the areas. As far as a decline rate, I think that's a $64,000 question. Everybody -- what decline rate are you using Don, on legacy?

2%.

We just plug in 2%, Michael. There is no science to that.

Okay.

What was your last question?

Just if propane -- would you assume the same trajectory for propane supply as ethane?

We'd say it's growing, but not on the same trajectory, because the stream is getting lighter and has more ethane.

Okay. And then my last question is, turning to refined products pipelines, if you look at the year-over-year changes, you had $10 million down because effectively the spread between WTI and LLS, and then $5 million for maintenance and integrity spending. Assuming that spread remains, would you assume those flows stay as they are? And then is there something going on that your integrity costs are going up?

The refined products pipeline, remember we had some repair costs up in New York state, and then also with high cost of gasoline you had reduced demand in the Midwest, so that affected it.

Okay. Thank you.

Your next question is from Ross Payne with Wells Fargo.

How are you doing, guys?

Great, Ross.

Looks like a nice uptick in volumes in South Louisiana and Lou-Tex. Are you moving product to Louisiana for fracking because you're full in Mont Belvieu or what's going on?

That's exactly what's happening, Ross.

Okay. Second question. Any impact from the floods on the marine business here in the next several weeks?

Yes. This is Jerry Cardillo. We are abiding by, and very cautious, and there will be impacts on marine traffic going east and west. There has been impacts on traffic north and south, but all with solid due diligence and in compliance with industry and regulatory agencies.

What's your impact?

We have had two enterprise marine tugs and barges idled in Paducah, Kentucky, unchartered for ten day periods and we expect them to be in a congested spot for the next 7 days. And based on -- and, I am sorry -- yes, we're still on charter, and then basis what our gauge looks like on the Morgan city area and the intercoastal canal, we could have up to 19 tows impacted all on a revenue earning basis.

Thank you. Also, you know, obviously there is a change in mix here going from a POP to fee based. How aggressive is that movement towards fee based by the producers and by yourself, and what do you see the forward impact being on earnings?

I think we'll go back to my comments, $1 a gallon processing spread. Producers want that, so you give them what they want and you take the fee and you try to get it as high as you can. (Laughter)

Ross, I think it is fair to say that we are willing to trade a bit of margin for stability.

Okay. All right.

It is easier to do that today than it used to be.

Okay. All right. Very good. One final question. Keystone is obviously got its Gulf extension; it seems to be hung up somewhat on regulations and what have you. There is a decent amount of that contracted. Is there an ability, in your opinion, for some of those people contracted on the Gulf extension with Keystone to shift over to your project, or any view on that?

Yes. This is Mark. We believe there is. We've talked to all of the folks who we think who will be significant shippers on the line, and not one of them had mentioned that as a barrier to shipping on the line that we will build. We think whatever that commitment is they can transition out of it in some way.

Okay. Very good. That's it for me, guys. Thanks.

Thank you, Ross.

Your next question is from John Edwards with Morgan Keegan and Company.

Good morning, everybody.

Good morning.

Just following up here, you mentioned the about $5 billion or so projects under construction, and you have that expectation for that growing. What do you view is your backlog of opportunities now?

John, if you talk about backlog of opportunities, things that aren't, including the projects that aren't sanctioned, but look really good to us, it is $6 billion, $7 billion, $8 billion, who knows. The question you might want to ask is what do we think we ought to be spending on an annual basis.

That was my next question. (Laughter)

I think that just in terms of what do we need to spend to be able to continue to grow our distribution, for the next couple of years it is probably closer to $1 billion to $1.5 billion. What do I think we'll actually spend? It is probably -- I like to say $2.5 billion. Jim keeps saying it's going to be higher. it may be something like you have seen this year and last year, frankly, but we don't have that kind of spending locked in for 2012.

Okay. And then I am trying to -- this is kind of a follow-up to Ted's question. On the ramp here, you have the equity NGL production was flattish and then the fee-based natural gas processing was way up, 38% up year-over-year. Now, is part of that growth marketing? One of your guys mentioned there was a switch in the type of contracting that you're doing there. I am just trying to get an idea of what kind of ramp should we be expecting between those two elements, that drive your NGL segment margins?

John, this is Tom. I am not sure how I can quantify it in numbers, but our focus has been, as Jim said earlier, to give the producers the type of contracting arrangement they want. They want to see more of the liquids themselves these days, so our contracts take a bend toward fee-based contracts. And that's what you see in the slightly lower equity volumes and lower percent proceeds, particularly with the Eagle Ford contracts coming on in south Texas and a higher fee-based revenue stream for the processing.

How much -- were there marketing volumes in those numbers, or was that all fee-based processing?

I am not sure I understand.

Was there -- I am just trying to get an idea I guess how much -- I am not -- so that is just being driven by customer -- just customer driven demand, because I guess -- how sustainable or what kind of growth outlook should we expect on natural gas processing then?

John, if you're looking at the fee-based natural gas volumes on --

Yes, the volumes, because they were up so strongly. They were up 38% year over year.

Yes. I think -- John, this is Randy. There were two places they were up. They were probably up about 570 million a day up in the Rockies and they were up, call it 450 million a day in South Texas. As far as -- and some of that, like Tom said, maybe you lost 3,000 barrels a day at equity NGL production in the Rockies, maybe 3,000 in South Texas, but again, some of that is just migrating from percent of liquids, keep whole to fee based. And then we did have a pickup in equity NGL production in South Louisiana.

When you come in and look from a plant stand point, plants up in the Rockies are running full. We had capacity in South Texas. We're filling that up with new Eagle Ford volumes. The next growth component to look for in processing would be when the Yoakum plant comes up on 600 million a day. You ought to see more combination of equity NGL production and fee-based volumes come up when that plant goes up.

Okay. Great. That's really helpful. That's all I had. Thank you very much.

Thank you. Tiffany? If we don't have any other questions in the queue, you can go ahead and give our listeners the replay information.

(Operator Instructions)

Thank you for participating in today's conference. This call will be available for replay beginning 11.00 AM Eastern Standard Time today, through 11.59 PM Eastern Standard Time on the May 17, 2011. The conference ID number for the replay is 60983927. Again, the conference ID number for the replay is 60983927. The number to dial for the replay is 1-800-642-1687 or 706-645-9291.

Are you ready for the next question, sir?

We'll take one more, thank you.

Your next question is from TJ Schultz with RBC capital.

Hey, guys, sorry. Good morning. Thanks for taking the call. I just have one quick question on the West storage unit. Can you give an update on the repair work there and if there is any lingering issues?

I am not aware of any lingering issues. We're in the process of demolition. We're still in the process of doing temporary interconnects to get the connectivity restored to the few customers we have remaining without connectivity. We're in the process of emptying the wells over there on a temporary basis. We're not going to be able to use those wells until we get the rebuild complete, but we are able to get the product out of those wells at present.

I think we're emptying 2 of them as we speak, and then we're going ahead with plans. We ordered long lead equipment and going ahead and putting the plans together and doing the engineering on the rebuild. It's going to be rebuilt exactly like it was, but we're going to make it more efficient; and we're thinking early 2012 we'll have it completely rebuilt and have that all behind us.

Okay. Great. That's all I had.

All right, TJ.

Well, Tiffany, with that, I think we're ready to terminate the call. I would like to thank everyone for joining us today, and have a good day.

This does conclude today's conference call. You may all disconnect.