Enterprise Products Partners LP (EPD) 2010 Q4 法說會逐字稿

Good morning. My name is Julianne, and I will be your conference operator today. At this time, I would like to welcome everyone to the Enterprise Products Partners Enterprise and Duncan Energy Partners Q4 2010 earnings conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. (Operator Instructions) Thank you. I would now like to turn the conference over to Mr. Randy Burkhalter. Please go ahead, sir.

Thank you, Julianne. Good morning, and welcome to the Enterprise Products Partners Enterprise and Duncan Energy Partners joint conference call to discuss fourth quarter earnings. Our speakers today will be Mike Creel, President and CEO of Enterprises General Partner, followed by Jim Teague, Executive Vice President and Chief Operating Officer, and then Randy Fowler, Executive Vice President and CFO of the General Partner of Enterprise, and President and CEO of General Partner of Duncan Energy Partners will follow Jim. Also in attendance are other members of our senior management team.

During this call, we will make forward-looking statements within the meaning of section 21E of the Securities Exchange Act of 1934 based on the beliefs of the Company as well as assumptions made by and information currently available to management of both Enterprise and Duncan. Although management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Please refer to our latest filings with the Securities and Exchange Commission for a list of factors that may cause actual results to differ materially from those in the forward-looking statements made during this call. With that, I will turn the call over to Mike.

Thanks, Randy. Thank you for joining us today. I would like to start off by providing an update on our Mont Belvieu facility since the incident at our west storage facility on February 8. Operationally since last week, we have focused on returning our Mont Belvieu facilities to as close to the same capabilities as we had prior to the event. None of our gas processing plants were curtailed as a result of the event, and we have diverted y-grade to our fractionators and third party fractionators. None of our propylene assets were affected, and our butane isomerization plants continued to run. Our exports facility continued to perform although we did have to short-load two ships.

Our beef facility was in a planned turnaround, but it is coming back up now and should be at full rates by Saturday. We have been operating our fractionators at reduced rates while making the necessary piping changes to avoid the west storage area. We are changing our storage configuration to enable us to recover our receipt and delivery capabilities by using our north and east storage facilities.

Three of our Mont Belvieu fractionators are running now, and we expect to have the fourth fractionator up tonight and to have the Mont Belvieu fractionators running at full rates by tomorrow. We also expect to have full connectivity between our north storage area where our fractionators and other plants are located and our east storage area by the middle of next week. This will enhance our ability to resume service to our customers.

We have also been working with individual customers to make piping modifications to restore their delivery and receipt capabilities. Our y-grade receipt capabilities are 100% of the pre-event level, and we believe our delivery capabilities out of our wells will ultimately be at 85% to over 100% of pre-event levels depending on the product. West storage represented less than 16% of our storage capacity, and our receipt and delivery rates at Mont Belvieu. We're also working on enhancements to our Mont Belvieu system to build in redundancies to ensure that disruptions like those we had this past week will not occur in the future.

You may have noticed in our press release that net income attributable to partners and diluted earnings per unit looked pretty unusual this quarter. That is due to the recent merger of Enterprise GP Holdings with a wholly-owned subsidiary of Enterprise which was completed last November. Enterprise GP Holdings is considered the surviving consolidated entity for accounting purposes, so Enterprise's consolidated financial and operating results prior to the merger have been presented as if Enterprise were Enterprise GP Holdings from an accounting perspective. Enterprise is a surviving consolidated entity for legal and reporting purposes, so reported results going forward should look much more normal. The confusing parts of the income statement are below gross operating margin and do not impact distributable cash flow. The good news is that Randy gets to talk about more about this in his part of the call, and I don't.

Our integrated system of assets handled record volumes in 2010. The oil and gas production growth in the developing shale regions we serve, combined with continued increased demand for NGLs by the US petrochemical industry and international customers, has led to another year of record financial performance. This enabled us to reach an impressive milestone of generating $10 billion of cumulative distributable cash flow since our IPO in 1998. Gross operating margin for the fourth quarter of 2010 totaled $829 million. Our second highest quarter ever, compared to the record $880 million for the fourth quarter of 2009 which included $25 million of insurance proceeds. For the full year, Enterprise generated a record $3.3 billion of gross operating margin, a 13% increase over 2009, and we had record net income of $1.4 billion in 2010.

Our NGL Pipelines and Services segment continues to post strong results, totaling $457 million for the quarter versus a record $511 million in the fourth quarter of 2009. Gross operating margin from our NGL marketing activities declined $41 million due to forward sales of NGLs which were at record levels in the fourth quarter of 2009. Collectively, gross operating margin from the remainder of our natural gas processing and related NGL marketing business declined $20 million due in part to 15 days of downtime at our Pioneer facility to improve NGL recovery levels. Equity NGL production for the quarter was 3,000 barrels a day less than in the fourth quarter of 2009 as a result of the downtime at Pioneer, though we had a 31% increase in fee-based processing volumes due to volume growth in the Rocky Mountains and in Texas. Gross operating margin from the NGL Pipelines' historic business was $180 million in the fourth quarter of 2010, $4 million higher than the fourth quarter of 2009, even though that quarter included a benefit of $29 million from a rate case settlement on the Mid-America Pipeline System. Our NGL fractionation business had record gross operating margin of $38 million for the fourth quarter of 2010, a 7% increase over 2009, primarily due to higher volumes and fees associated with the new Mont Belvieu fractionator that began commercial operations late in the fourth quarter of 2010.

Our Onshore Natural Gas Pipelines and Services segment reported a $26 million, or 24%, increase in gross operating margin on record transportation volumes of 11.5 trillion BTUs per day, 12.5% higher than in the fourth quarter of 2009. This improvement in gross operating margin was due in large part to the $14 million of gross operating margin generated by the State Line and Fairplay systems we acquired in the second quarter of 2010, increased gross operating margin from our Texas intrastate and San Juan systems, and from natural gas storage. We're continuing to make good progress at our Acadian extension project in the Haynesville and our Eagle Ford shale projects in Texas and look forward to the contributions they will make to our distributable cash flow.

Gross operating margin for the Onshore Crude Oil Pipelines and Services segment decreased to $26 million this quarter from $38 million in the fourth quarter of 2009, primarily due to fewer Contango opportunities, lower sales margins, and a $3 million increase in gross operating margins from the Seaway crude oil pipeline due to lower transportation volumes. Obviously, we're disappointed in the volumes on Seaway, but with the amount of crude in storage at Cushing and the price differential between Cushing and the Texas Gulf Coast, there is just not much demand for our northbound capacity. Total onshore crude oil transportation volumes were 645,000 barrels a day for the fourth quarter, 4% lower than in the fourth quarter of 2009. Offshore Pipelines and Services gross operating margin was $66 million, compared with $98 million in the fourth quarter of 2009, primarily because the fourth quarter of 2009 included $21 million of income related to insurance proceeds. And in the fourth quarter of 2010, there were lower expiration and production activities in the Gulf of Mexico due to permitting and other issues.

Our Petrochemical and Refined Product Services segment had gross operating margin of $140 million, a $31 million or 28% increase, over the fourth quarter of 2009. The majority of this increase is attributable to our propylene fractionation business which had a $28 million, or 134%, increase in gross operating margin due to higher volumes and margins. Gross operating margins from our Refined Products business decreased by $6.5 million this quarter primarily due to downtime on a portion of our products pipeline system during the quarter. Somewhat offsetting this was gross operating margin from our new Port Arthur refined products terminal which began service in the second quarter of 2010.

Enterprise generated distributable cash flow of $571 million in the fourth quarter of 2010 which provided 1.2 times coverage of the cash distribution paid with respect to that quarter. We retained approximately $92 million of that distributable cash flow for reinvestment in our organic growth projects. We had a record $2.3 billion of distributable cash flow for the full year, providing 1.3 times coverage of the distributions paid with respect to 2010. Of that, we retained a record $480 million of distributable cash flow to help finance our growth initiatives and to limit our need to rely on the capital markets.

As I mentioned earlier, Enterprise has generated over $10 billion in distributable cash flow and has retained approximately $1.6 billion of it since our IPO. Based on our continued strong performance, the Board approved an increase in the quarterly cash distribution rate to $0.59 per unit, a 5.4% increase over the rate paid with respect to the fourth quarter of 2009. This is our 26th consecutive quarterly increase and our 35th increase since our IPO in 1998.

We're very pleased with another year of strong results as our businesses continue to benefit from strong demand for our products and services. By enhancing our existing asset position in some of the most exciting shale plays in the country such as the Haynesville and the Eagle Ford, we believe we will continue to see even more opportunities to grow and provide additional services for our customers. Organic growth will continue to offer greater returns on capital than most asset acquisitions. And we believe our focus on the organic growth available to us around our integrated system will enable us to provide our partners with sustainable growth and distributable cash flow per unit.

As always, our employees continue to work tirelessly to meet the needs of our customers and to create values for our investors. We appreciate their strong work ethic and dedication which is more important now than ever, and I would particularly like to thank the team we have working on repairs at Mont Belvieu under the direction of Graham Bacon, our Vice President of Houston region operations, as well as everyone in our operations, engineering, commercial, and distribution groups that are working to get things back together as -- back to normal as quickly and safely as possible. They're doing a fantastic job. Working around the clock. Just couldn't be more proud of the effort they're doing. And with that, I will turn the call over to Jim.

Thank you, Mike. My comments today will be more abbreviated than typical to leave you more time for questions. This past quarter, broad energy metrics remain favorable for NGLs and natural gas processing, with the relationship between crude and natural gas averaging about 27% of crude on a BTU basis. In combination with strong petrochemical demand as well as strong export demand, this is keeping fractionation spreads healthy, and we're seeing producers continue to focus drilling and rich gas plays. The movement toward rich gas plays has pushed productions of NGLs from gas processing to record highs in November. It is no secret that we believe that unconventional natural gas production -- shale gas production is a game changer. We continue to make progress on our initiatives in both the Eagle Ford and the Haynesville, and our plants in the Rockies continue to run at capacity. Our pipelines are full. Our fractionators are full.

Relative to staying power, we think that most of the major plays we participate in, be it the Piceance, Jonah-Pinedale, Eagle Ford, or Haynesville, have 20-plus years of drilling locations even without considering refracs, recompletions, and-or the potential of accessing other zones. Most of the shale drilling has been driven by must-drill leasehold obligations, and producer economics should improve when they move to infield drilling since the roads, drilling pads, gathering and treating equipment infrastructure are already established. What's important to note is that in addition to our current footprint, we continue to monitor about 20 additional plays, most of which are near our existing assets which we believe have the potential to add significant amounts of natural gas, NGLs, and oil to our portfolio. We always have a list of 'what next' initiatives, and these 20 plays make up that list of 'what next' initiatives.

Just as we see natural gas and crude production growth in the areas we are actively working in, we see continued growth in the need for NGL transportation and fractionation. This was clearly evident when November production data was released by the EIA. We saw record high NGL extraction of over 2 million barrels a day. Some of them initially appeared surprised by the growth, and over the past few week, some have viewed this data point as negative. Ever the contrarians, we believe that this is positive for the entire value chain, including natural gas producers, processors, chemical companies, and particularly well-positioned midstream companies. We expect that NGL production will continue to grow, though we believe the growth -- the jump in FN extraction from natural gas processing to 873,000 barrels a day in November from 844,000 barrels a day in October is not necessarily representative of the pace of growth that we calculate. Last quarter, we said ethane production could reach as high as 960 barrels a day by 2015, and we still feel that is a reasonable target.

On the demand side, our export dock is sold out for 2011 and virtually sold out for 2012. We can expand that facility to handle another million and a half barrels a month. With our expanded fractionation capacity, we have the high purity propane supply required by the international market to support such an expansion.

On the ethane side, we saw instantaneous consumption of ethane reach historic levels, and the industry's ability to consume ethane even out-paced the growth in ethane production. Last quarter, I said that we expected ethane consumption to top a million barrels a day by 2015. The industry topped that shortly before Christmas. Frankly, that jump in consumption exceeded our optimistic view at that time. However, remember what we said last quarter. Never underestimate the US chemical industry's ability to consume more ethane.

In December, we saw two cracker restarts. Eastman restarted one of their crackers at Longview that had been shut down since late 2008, and CPC restarted its Sweeney 22 ethane cracker that had been mothballed since about the same time. We see more continued growth in demand for ethane as the cost advantage to light feed stocks is impressive. The ethane advantage relative to other domestic feeds is pronounced, but really, we're even more encouraged when we look at US chemical companies' competitiveness globally, and we continue to see the US slide lower on the international cost curve. That global competitiveness is what will keep the US chemical industry healthy, accelerate capital spending to facilitate increased consumption of domestic NGLs.

I was going to say that I didn't think the competitive advantage of the US industry is fully appreciated until we got a sell-side analyst's report this morning on Dow Chemical, and in particular, their joint venture with Kuwait which they call EQUATE. And I would like to read one quote from that to finish up my comments. We visited EQUATE as a part of our Middle Eastern field trip in June 2010, and it was clear that lack of cheap ethane feed stock in Kuwait would mean future capacity expansions would use naphtha as a feed stock, which would likely position the new capacity above the US Gulf Coast on the cost curve. Similar issues appear to be present in Saudi Arabia. And with that, I will turn it over to Randy.

Thank you, Jim. Before I discuss additional income items, I would like to follow up on what Mike said earlier regarding disclosures this quarter that were affected by the merger. The income statement items impacted the most were non-controlling interest and earnings per unit. Net income attributable to non-controlling interest was significantly higher than usual, due to the fact that third party investors of EPD -- other than investors of Enterprise GP Holding, were considered a component of non-controlling interests. This is true for periods prior to the effective merger date of November 22, 2010.

Like Mike said, the good news is this will only occur this quarter. Going forward, your models will not be impacted by this accounting presentation, since EPD will be the reporting entity. The other unusual thing about earnings this quarter was the average units outstanding that was used for the earnings per unit calculation. EPD's quarterly earnings for the prior -- for the period prior to the merger is based on the net income attributable to the former owners of Enterprise GP Holdings, divided by the applicable weighted average outstanding units of EPE, adjusted for the merger exchange ratio of 1.5 EPD units for every EPE unit. So thankfully we won't be dealing with this in the future.

Now, turning to the discussion of additional income items. G&A costs were $54 million for the fourth quarter 2010, compared to $41 million for the fourth quarter 2009. The G&A cost this quarter included about $11 million of merger-related expenses. Interest expense increased $34 million to $213 million this quarter from $179 million reported for the fourth quarter of 2009. Interest expense this quarter includes approximately $31 million for the redesignation and assignment of interest rate swaps that EPE had, that again, were assigned over to EPD as part of the refinancing -- as part of the merger and the refinancing of the EPE debt. There was also some unamortized debt issuance costs associated with the EPE debt that were also written off as well.

The average debt balances were $13.8 billion and $12.8 billion for the fourth quarters of 2010 and 2009, respectively. Total capital expenditures were $694 million this quarter which included about $631 million spent for growth projects. Of the $631 million spent for the growth projects, approximately 67% of those expenditures were related to the Haynesville Acadian extension, and the Eagle Ford shale projects. For the year, we had $3.1 billion of growth capital expenditures which included $1.2 billion spent for the M2 Midstream acquisition in May 2010. Some of the larger growth capital projects in 2010 were again the Haynesville extension pipeline and the Eagle Ford shale projects, as well as the Mont Belvieu NGL fractionator four and the Trinity River Basin lateral, serving the Barnett shale area.

Based on approved projects, we expect to invest approximately $3.4 billion of growth capital expenditures in 2011. Again, of which about 85% of those expenditures, will be related to the Haynesville and Eagle Ford projects. Sustaining capital expenditures in the fourth quarter 2010 and for the year were $63 million and $240 million, respectively. For 2011, we expect sustaining expenditures will be approximately $250 million to $260 million.

Adjusted EBITDA for 2010 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 four times for the year ended December 31, 2010, and this adjusts the debt for 50% equity treatment for the junior subordinated notes. If you include distributions that Enterprise GP Holdings received from ETE in 2010, on a pro forma basis, it would lower the leverage ratio to 3.9 times.

After our January debt offering in which we swapped $750 million of the five-year notes back to floating at a rate of three-month LIBOR plus approximately 97 basis points, and taken into consideration the $450 million February debt maturity, our floating rate interest -- floating interest rate exposure is approximately 11% of the total debt portfolio. The average life -- the average tender of the debt outstanding is almost 11 years using the first call date for the hybrids. And our effective average cost of debt is approximately 5.7%.

At December 31, 2010, we had consolidated liquidity of approximately $1.9 billion, and this includes the availability under both the EPD and the EP credit facilities, as well as unrestricted cash. In January 2011, we received approximately $1.5 billion of net proceeds from the issuance of the five-year and 30-year notes. A portion of those proceeds were used to retire a $450 million note that matured on February 1, 2011. Adjusting for these proceeds and the retirement of the note, consolidated liquidity was approximately $2.9 billion.

We do not currently have any estimate with regard to the impact of the Mont Belvieu incident to first quarter earnings. The focus of our operating, engineer, and commercial personnel, have been to assist federal and state authorities investigating the accident and restore services to our customers. Their pace of progress, much like after hurricane disruptions, has been amazing. We have not distracted them by asking for estimates of the financial impact in such a quickly evolving situation.

In terms of the property damage insurance, we have a $5 million deductible. In terms of business interruption insurance, we have a 60-day deductible. As you can tell from Jim and Mike's update, we currently do not expect to have a BI claim. All in all, we do not currently expect for this incident to have a significant impact to 2011 EBITDA or 2011 distributable cash flow for either Enterprise or Duncan Energy Partners.

Now, turning to Duncan Energy Partners, we're pleased to report another quarter of record gross operating margin of $81.9 million which was 15% higher than fourth quarter 2009. And it surpassed the record established last quarter by 10%. We benefited from record NGL pipeline through-put volumes from south Texas NGL pipelines, and higher storage fees at our Mont Belvieu complex. The Natural Gas Pipeline business reported a 7% increase in gross operating margin this quarter, compared to the fourth quarter last year. Primarily due to higher firm capacity fees, transportation volumes, and lower operating expenses on the Texas intrastate system.

Distributable cash flow this quarter was a record $35.8 million and enabled us to increase the quarterly distribution rate for the ninth consecutive quarter. This represents a 2.2% increase over what was paid to partners with respect to the fourth quarter 2009 and provided 1.4 times coverage of the quarterly distribution. We retained approximately $9.4 million of DCF this quarter and $30 million for the year which was used toward funding the Haynesville extension.

We are excited about our Haynesville extension pipeline which is progressing on schedule and likely under budget. We began construction on the 270-mile pipeline and related facilities in January and began laying pipe this month. We expect to have the pipeline completed and ready for operations in September.

DEP had consolidated capital expenditures of $333 million in the fourth quarter 2010 which included approximately $192 million for the Haynesville extension pipeline project on a 100% basis. DEP funded approximately $128 million, or 66%, of the total cost of the Haynesville extension pipeline this quarter. And for the year, the Partnership spent approximately $348 million for its portion of the capital associated with the project. Sustaining capital expenditures were $14 million this quarter, compared to $11 million spent in the fourth quarter 2009. And for the year, DEP had $55 million of sustaining capital expenditures.

At December 31, 2010, DEP's debt to last 12-month EBITDA ratio per the calculation of the bank credit facility was 3.5 times. Under this facility, DEP's maximum allowed debt to EBITDA is five times. In calculating this ratio, the credit agreement also allows us to adjust EBITDA for a pro rata amount of the forecasted EBITDA associated with the Haynesville extension. At December 31, DEP had total liquidity of approximately $763 million which includes cash and availability under the credit facility. Our debt has an average maturity of two years and 100% of DEP's debt is floating rate debt.

In closing, we were pleased with the strong performance of our business this quarter and for 2010. We established new high water marks in operating and financial performance in 2010, and we are encouraged by the growth prospects for our partnership as we continue to execute on our plans. With that, Randy, we're ready to open it up for questions.

Thank you, Randy. Julianne, we're ready for questions now.

Thank you. (Operator Instructions)Your first question is from the line of Brian Zarahn with Barclays Capital.

Good morning.

Good morning, Brian.

In regards to Mont Belvieu, does the incident there have any impact on the timing of your new fractionator?

No.

No it doesn't. And as we said, the four fractionators that we've got are either up or will be up in full rates by the weekend. So our fractionators were totally unaffected.

But the fifth fractionator building -- so the timing of that -- can you remind us? Is that going to be end of this year or early next year?

It should be -- we spent about $58 million of CapEx on frac five in the fourth quarter, and scheduled to come on, really, at the end of 2011, beginning of 2012.

Okay. There has been a lot of discussion, obviously, about the dislocation of WTI. Can you give us a little color as to all of the variables and reversing -- that would be involved in reversing the Seaway pipeline?

This is Jim. We read the press, and I mean frankly, we see the merit in it. But we're not going to do -- we've got a pretty valued joint venture partner so we're not going to negotiate with them through an earnings call or through the media.

Okay. So you would assess that as sort of more or less likely than more likely?

We're not going to negotiate with our valued joint venture partners on a conference call.

Have to ask, Jim. Final question. On the Haynesville extension, can you give us an update on contracted capacity? And also how much of the $1.6 billion is left to spend?

In terms of the contracted capacity, we have got right under 1.6 Bcf a day, and just to remind you, it is 1.8 Bcf a day of capacity without additional compression. I don't have at my fingertips where we are today on capital spend. Do you have that?

Brian, I think probably we have between $800 million and $900 million left to spend in 2011 on the project.

Okay. Thank you.

Your next question is from the line of Mark Reichman with Madison Williams.

Good morning. While the Onshore Crude Oil Pipeline segments are small relative to the NGL and Onshore Natural Gas Pipeline segments, would you please elaborate on the opportunities you see to serve producers in some of the emerging crude oil resource plays?

You want to speak to Eagle Ford?

As you know, we've got a number of projects in the Eagle Ford. Mark Hurley is our Senior VP in charge of that business, and I will let him address that.

Well, we are -- this is Mark Hurley, and we're very excited about what we have going on in the Eagle Ford. Both with respect to the kind of production that we see coming on there which is in the hundreds of thousands of barrels a day over the next 10-15 years. The quality of the crude oil, which is very good, and very easy to market into the Houston market in particular. We like our position there with the line that we have announced. And in consideration now of an extension to that line, we announced earlier -- or late in 2010, that we would be building a terminal in Houston. And so we're highly focused on having that be a hub for Eagle Ford crude with all of the connectivity that we need to get to the refiners in that area. As well as having the ability to export into other markets as well.

And Mark, it probably won't be a big surprise to you that Mark Hurley and his group are probably working on a number of opportunities that we just haven't announced and aren't prepared to talk about.

Does that include the Bone Spring and Avalon shale play?

We are very active out there, and we're very optimistic about that area and are talking to all of the major producers out there.

Is there anything you could comment about regarding potential you see there, and the investments you might make? Or is that a little premature for that?

I think it is a little premature, Mark.

Okay. And then you mentioned some of the investments in the crude oil transportation and storage assets that were made in, I think, last September and November. I was just curious, how do you think about growing that business, and how are those investments weighed against those in the onshore natural gas segment and NGL segment during the capital allocation process?

Well, we're pretty much done with capital allocation for 2011, and in large part, for the beginning of 2012. And the way that we look at the onshore crude and onshore gas together is we're serving producers that have interests in both of those areas. And so to the extent we can provide natural gas and crude oil solutions for them, it is kind of a win-win for us. So we're looking at ways that we can, again, leverage our value chain, provide services across all of those business segments. So we're not looking at crude oil in isolation. We're looking at the producer relationships, and then how we can best serve those.

Okay. Great. Thank you, Mike.

Your next question is from the line of Darren Horowitz with Raymond James.

Good morning.

Hello, Darren.

Jim, I have got a couple of questions for you. Surprisingly. First, beyond the restart of those two previously mothballed crackers that you talked about, was ethane demand tracking 960,000 a day and crackers running almost 95% of their utilization. Would you have expected to see more cracker modifications by this point? I'm trying to get my arms around how much more idle capacity you think can come back online or be modified to focus on the light ends?

Of mothballed? Of modifications? I'm sitting here with Don Johnson who is in our Fundamentals Group and stays on top of this, and what Don is saying he thinks there is somewhere between 80,000 and 100,000 barrels a day of more modifications that can be made.

Okay. And what about what is idle right now? And more specifically within the framework, I'm just trying to get a feel for if that capacity does come back online, how quickly you could match up with ramping NGL production.

Let me get Don to dig into that because I don't have it right at my fingertips, and get back to you.

That's not a problem. Switching over to your comments around expanding the LPG export terminal. As you mentioned, sold out for the better part of the next two years. What would the associated cost and timing be of that one and a half million barrels a day capacity, if you did decide to move forward with expanding that dock?

I think the timing would probably be in the neighborhood of a year, and I'm not sure -- the capital would not be outrageous. How's that?

Okay, and safe to say given your install base of existing assets, the IRR would probably be north of traditional greenfield projects? Is that fair?

Who knows.

Well, you know, Jim.

Yes, I know.

And you know better than to ask, Darren. (laughter)

I think one thing, Darren, to keep in mind -- one of those things that give us the ability to expand that export facility is our expanded fractionation capacity. You don't build an export facility or fully refrigerated LPG -- propane unless you have the capability to produce propane with no more than 2%, 2.5% ethane. That means you better have a pretty strong -- here we go, a pretty strong fractionation position supporting that export activity. You don't just go build a terminal. You better have the ability to produce the 2%, 2.5% ethane and propane.

Okay. Well you better get to work on building a strong fractionation footprint then, Jim. (laughter) Last question from me, on the Eagle Ford logistics. I'm just thinking about moving volumes east across that rich gas main line expansion and out of the tailgate of that new gas processing plant. And I'm curious if you foresee any additional need to expand Wilson beyond that extra 5 Bcf you're adding this year. And then secondly, maybe any additional opportunities for storage in and around the Sealy area.

Darren, this is Chris. With regard to expansion at Wilson, we're pleased with the facility that we have coming on in service here in April, and it will be a little over 5 Bcf of capacity. We're happy at that level right now. We have been -- at the analyst call last year, I talked about we're not bullish -- storage for natural gas long term. There has been significant amounts of storage developed over the last five years and the deliverability proportion to that, and I think there has been a couple of articles that have talked about that. I think there has been a couple articles that have talked about that. But we don't see a significant growth in storage needs in that area right now. There is ample storage capacity in that area. And our 5 Bcf fits right in there just nicely. Our residue line ties right into that.

And Darren, the other thing is that taking that gas into Wilson interconnects with a number of other interstate pipelines. So we can get that gas moved to other storage facilities and places where they need it.

Sure. I appreciate the color, thanks.

Thank you, Darren.

Your next question is from the line of Michael Blum with Wells Fargo.

Good morning, everybody.

Good morning, Michael.

Back to the WTI-LOS spread situation. Excluding Seaway, is there any other way that you can take advantage of that? Or not really?

This is Mark Hurley again. It is difficult to move high volumes of crude into the LOS market from the WTI market efficiently. And of course, that's one of the reasons that spread exists. Most of it moves today by way of marine transport. And of course, we do have a marine transport fleet. And so we look at those opportunities all the time. So that is the primary way of trying to take advantage of that.

This is Jim. The one thing we are looking at, and this is part of our legacy if you would, is we are taking a look at every pipe we have regardless of the service it is in and seeing if it can be better deployed in another service.

If you did find that pipe, how long would it take to actually reverse it and change the service and all that? What's the time frame for something like that?

Depend on the pipe, Michael. (laughter)

Okay.

We're not there yet.

Got you. Maybe just -- you mentioned the marine transport. So you recently had that sale of the asset. Can you just talk a little bit-- maybe just clarify strategically what your thought process now is with the marine transportation business?

Sure. I don't know that it has changed much over the last year. Certainly what we're trying to do is integrate that with the rest of our businesses more. The piece that we sold was the bunkering operations based out of Florida that, frankly, didn't fit our value chain. It is not a business that we saw integrating with what we have currently. The business that we retain is the core business that TEPPCO bought. We have in 2010 bought the onshore service facilities that go with that business, trying to put it back together. We're looking at opportunities, as Mark said, to integrate that with our crude business, as well as our refined products business. And perhaps some LPG business. So we think it could be a nice addition to our value chain.

Okay. Last question for me. There still hasn't been any final announcements out of the Marcellus in terms of an ethane solution. And just was curious if you had any updated thoughts on where that product ends up? And if Enterprise will play any role in that?

We're -- I will say again what I've always said. It is counter-intuitive to me when you have to take ethane out of natural gas, but assuming you have to -- probably if I were a producer, I would want it where the biggest sponge is, and that is on the Gulf Coast. And I think we've said in the past, we could play a role in that in some fashion. If nothing else, we've got the distribution capability on the Gulf Coast to the petrochemical industry.

Okay. Thank you very much

Your next question is from the line of Yves Siegel with Credit Suisse.

Good morning. Just to go back to Cushing really quick if I could. It seems to me that probably by 2014, that situation sort of gets resolved. Just the other pipeline gets built. How long does it take if -- and I don't want you to negotiate, Jim. But how long would it take to reverse Seaway?

You are putting us in a box, Yves.

Okay.

Yves, I think it is safe to say that we can do it before 2014. How is that?

I've got to get better in asking questions. (laughter) The second question, Jim, when you think about the export facility. What kind of demand do you think is going to persist? And other than propane, what other products do you see robust demand for?

Yves, I've been in this business a long time, and I never thought I would see us exporting this amount of propane year-round. I think as long as you have a gassed crude like we have in the US, then it is going to support continued exports of propane. I'm looking at Lynn Bourdon. Frankly, that's one of the things we're spending time on as we look at our export facility is trying to get our arms around what the demand for that incremental capacity would look like. And what kind of fees it could support. But right now, we're beginning to say -- you know what, this looks like this has got staying power as long as this gassed crude is where it is.

Okay. Any other products you'd think that -- ?

I'm sorry. Occasionally, we see the need to export some butanes, Lynn?

Well, if we also consider refined products, I think we average around 600,000 barrels a day of diesel exports in rough numbers, and we continue to believe that that market will stay there and grow with the strength of the refiners on the Gulf Coast. As well as the growth in the Eagle Ford shale crude, and other crudes coming into this market. So we -- and we believe that will grow as well.

And then how do you think about the propylene? That has to be generating record margins for you right now.

We've had a pretty good year.

We've had a great year in propylene. And you know it is strong when people are looking -- when people build on-purpose plants and continue to talk about more on-purpose plants. That's indicative of the strength of propylene.

So it sounds like you think there may be staying power.

I think we feel pretty good about it.

We don't expect -- let me answer that. You've got a little more production capability today than you had last year. So you may see a little bit of a narrowing. But come on, these heavy crackers produced a heck of a lot of propylene, and they're cracking light. So that supports the margin.

So is there any way to -- do you think about trying to lock in -- go ahead, I'm sorry.

I would love to, Yves. There -- .

There is no way. And then I will just finish up by asking, if -- the acquisitions that you did with momentum. Has the acquisition economics played out the way you thought? And maybe just expand on what you are seeing on the State Line in Fair Play?

Yves, I will jump in here. On the State Line Fairplay system, if you remember the strategy we talked about, remember the 42-inch corridor where the other four pipelines run from Carthage to Perryville. We decided not to play in that corridor. We built south in the Haynesville and went diagonally down into Baton Rouge. Once again, our Fundamentals Group played a key role in helping us to find the sweet spot where we thought the Haynesville was.

If you look at the rig count on the north side of that corridor versus the south side of that corridor, we still have got eight rigs running on our State Line system and two rigs running in our Fairplay system. The Fairplay system is that more easterly edge on the Texas side. But the State Line system, we're still running eight rigs. And in our two proprietary gathering systems, we have got a lot of activity and rigs, and that's the further south you go in that basin -- if you remember, that momentum was our insulation from the north corridor coming down into our area. What we thought was the sweet spot, that was the strategic reason why we bought that. So we're still very pleased to think the through-put today was pushing between the two systems, 670 million, whether it be full volume metric or getting demand payments for it in that range. So we're very pleased with where we are right now.

And Yves, probably from a return standpoint. We may be about 150 basis points on an annual basis light from where we thought. But some of that's oil field services sort of being a bottleneck there. But I think from where we are, like Chris said, I think we're pretty close to where we thought we would be.

And from our standpoint, we think that's primarily timing.

When our project kicks off -- our Haynesville extension kicks off, it really helps exploit the potential upside on State Line.

Any thoughts on Gulf of Mexico and Independence volumes coming back?

Well, they've come back from where they were. And they're running right now around 525 million a day, and we would expect that -- I think there is another well that is coming up before the end of the year. So that will help volumes a bit. I don't see it back at 950 million a day any time soon, but we see some gradual improvement. And then once drilling starts back up in the Gulf of Mexico, there should be some additional volumes.

Thanks.

Thank you.

Your next question is from the line of Barrett Blaschke with RBC Capital Markets.

Hello. Just a quick question on Haynesville extension. And that is, with some expectation that this might come in under budget at this point, how does this affect your outlook for financing the project?

Well, the financing is the same as it has always been. All of our financing is essentially is at that OLP level, so we don't do any project financing there.

And then at the Duncan Energy level, the credit facility that we executed in the fourth quarter gave Duncan Energy Partners, who again are providing the capital for 66% of the project. It gave us plenty of flexibility to finance that on the credit facility. And if the project comes in under budget, that just gives us more flexibility.

I think what it does the most is makes us question the contingencies that engineering builds into all of these products, doesn't it? (laughter)

I guess the only other thing I had there was, did I hear correctly that all of the Duncan debt is currently floating rate debt?

It is.

Is there any chance of locking that in over time -- some of it as it builds up -- especially with project financing?

I think one of the things we're -- as we think about the financing, we go through the stage of -- well, Duncan Energy. We're thinking of it, if you would, at least this Haynesville project, a little bit like a project financing where we're looking to minimize equity issuance and utilize debt down at Duncan Energy to finish the project.

That being said, we would like to come back in and get Duncan Energy's credit ratios on a stand-alone basis back to something that is commensurate with an investment grade rating. Ultimately, we would like to come in and issue term debt at Duncan energy. But to do that, we need to get those credit ratios down. So I think part of our thought process is to finish the project, then use some of the excess distributable cash flow that will be thrown off. Delever Duncan back to a level that is appropriate, and then we will come in and look to go out and do a term debt deal. But by that time, that could be into 2012.

Okay.

And in the near term, your crystal ball may be better than ours. But I guess we're just coming in and seeing where fed funds rate is, where LIBOR rates are. It doesn't seem like they're going to go anywhere fast, and our thought is let's stay floating at least through the construction of the project. And then we can see about either terming some debt out or doing some anticipatory hedges to help lock some of that in.

Okay. Thank you.

Your next question is from the line of John Edwards with Morgan Keegan.

Good morning, everybody.

Good morning, John.

Just Jim, you were talking about ethane demand, and how you were looking for a million barrels a day by 2015. And then you have already hit it. So what is your outlook now?

Hoping we can hold it. (laughter)

Do you expect a higher number now for 2015, or -- ?

I think as petrochemical has become satisfied that the supply is going to be there, I don't know how you can ignore a $0.10 a pound advantage from ethane versus, say naphtha. I don't see how the petrochemical industry can ignore that cost advantage. So if that cost advantage stays, yes, I think you will see more demand. I've said before, if you've got $0.10 a pound advantage, and you've got a billion and a half pound a year cracker, that's $150 million a year. That's hard to walk away from.

John, we saw -- again, Jim mentioned that in December, we saw on the intra-month basis, a million barrels a day of demand or usage by the petrochemicals of ethane. And he said that there is another 75,000, 80,000 barrels a day of expansion. So right there, you're at 1.1 million barrels a day, and the economics are pretty compelling, so.

Okay. All my other questions have been asked. Thank you very much.

Thank you, John.

Your next question is from the line of Sharon Lui with Wells Fargo.

Hello. Good morning.

Good morning, Sharon.

My question relates to DEP. Just looking at, I guess, the gross operating margins for the NGL Pipelines and Services segment, it seemed like it was a pretty significant sequential increase. Just trying to understand the improvement on a sequential basis.

Sharon, I think it was just -- you are just seeing more Eagle Ford volumes begin to show up in the system. I think if you come in and you look at natural gas production coming out of the Eagle Ford, of 450 million a day, I think we're handling about 300 million a day of that. That is showing up at our processing plants. So you're getting incremental NGLs coming out of the plants and going into that pipeline.

And the expanded Shoup .

And Jim points out we did expand the Shoup fractionator. So there is another additional pick-up of volumes coming in and hitting that pipeline.

So these levels should be sustainable then? So this is a pretty good run rate?

Yes.

Okay. And I guess any thoughts in terms of what maintenance CapEx should be for DEP for next year?

Sharon, bear with me. You may have asked the $65 question that stumps everybody. As far as sustaining CapEx for DEP, I guess we were remiss of not putting that in the press release. Probably on 100% basis, at the DEP One assets, call it $20 million, $25 million. For the DEP Two assets, call it $30 million, $35 million.

Okay. And are these good levels, I guess, going into next year for 2011?

That would be. I'm sorry, that is sort of our estimates for 2011.

Okay. Great. Thank you.

Thank you, Sharon.

(Operator Instructions) And there are no further questions at this time. I will now turn the call back over to management for any further remarks.

Yes, before I turn it back over to Randy I would like to thank a number of companies in the Mont Belvieu area that have helped us. In this current events where we had some disruption in service, they've cooperated with us and helped us to provide service to our customers. And our sincerest thanks goes out to them. With that, Randy?

Yes, Julianne, if you would give our listeners the replay information just real briefly for our call today. Thank you.

One moment.

Julianne?

One moment, sir. This call will be available for replay beginning at 12.00 PM Eastern Standard Time today, through February 24, 2011 at midnight. The number to dial for the replay is 800-642-1687. Or 706-645-9291. The conference ID number for the replay is 42407614. Again, the conference ID number for the replay is 42407614.

Thank you, Julianne. And I would like to thank all of our participants for joining us today. And have a good day. Thank you.

Thank you all for participating in today's conference call. You may now disconnect.