Enterprise Products Partners LP (EPD) 2012 Q3 法說會逐字稿

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 third quarter 2012 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 Randy Burkhalter. Please go ahead, sir.

Thank you Tiffany. Good morning, everyone and welcome to the Enterprise Products Partners conference call to discuss results for our third quarter. Our speakers today will be Mike Creel, President and CEO of Enterprise's General Partner, followed by Jim Teague, Executive Vice President and Chief Operating Officer, and Randy Fowler, Executive Vice President and CFO. Other members of our senior management team are also in attendance.

During this call, we will make forward-looking statements within the meaning of Section 21E of the Securities and Exchange Act of 1934, based on the beliefs of the Company as well as assumptions made by and information currently available to Enterprise's management team. 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 & 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. Tiffany, before I turn over to Mike, how is the quality of the call? Can you hear us?

Yes, you are coming through loud and clear.

Okay. Alright, Mike.

Thanks, Randy. Before I start, I would like to let our friends in the Northeast know that our thoughts are with you. We know what it is like to go through a hurricane, and how much damage and disruption they can cause. And you just got hit by the largest hurricane ever to have been formed in the Atlantic Basin. All of us at Enterprise are wishing the best for you and your families, and a speedy recovery for the affected areas.

Moving on to earnings, we are pleased to report strong results again this quarter, with four of our five business segments showing improved performance over the third quarter of 2011. Record onshore crude oil and natural gas transportation volumes, record fee-based natural gas processing volumes, and near-record NGL transportation and fractionation volumes, led to $167 million, or 17% increase in gross operating margin, to a record $1.14 billion, compared to $973 million in the third quarter of last year.

Our NGL pipelines and services segment accounted for $68 million of this increase, with substantially all of the increase attributable to our fee-based NGL pipeline, storage, export and fractionation businesses. Our Mont Belvieu fractionators reported an $18 million increase in gross operating margin, primarily due to our fifth NGL fractionator that began service in October of last year. Our South Texas NGL pipeline, including our new Eagle Ford NGL pipeline that began service in April of this year, reported a $16 million increase, while the Mid-America and Seminole systems reported a $15 million increase. Our NGL storage, export terminal and related facilities had a $19 million increase compared to last year.

Gross operating margin from our natural gas processing and NGL marketing business increased by $4 million for the quarter compared to last year. Our fee-based processing volumes include 17% for a record 4.5 billion cubic feet a day, while our equity NGL volume decreased 13%. This shift reflects a desire by producers to retain the value of their NGL production and the associated commodity risk to increase their return on investment. We view this development as a win/win. It provides producers with a greater economic incentive to drill, and provides Enterprise with an increase in fee-based volumes and cash flow.

Our onshore crude oil pipeline and services segment reported a $51 million increase in gross operating margins compared to the third quarter of 2011, on record pipeline volumes of 820,000 barrels per day. Our South Texas crude oil pipeline system, including the new 24-inch pipeline from Lyssy to Sealy that began service in June of this year, accounted for $20 million of this increase, plus a 75,000 barrels per day increase in volume. Our share of Seaway's earnings increased by $18 million, with a full quarter of revenues after the reversal of the pipeline to flow volumes south from Cushing to the Texas Gulf Coast.

We also had record onshore natural gas transportation volumes this quarter of 14.2 trillion BTUs per day, which led to a $28 million increase in gross operating margins from our onshore natural gas pipelines and services segment compared to the third quarter of 2011. This segment continues to benefit from the Acadian Haynesville extension pipeline that began service in November of 2011, as well as from increased Eagle Ford production that feeds our Texas Intrastate system.

Excuse me.

Yes.

The line is break up a little.

Should we turn the volume down?

Okay, could you say a few words for me?

Can you hear it any better now?

Okay, yes. That is much better.

Alright, good. Talking about the Haynesville extension pipeline that began service in 2011 and the Eagle Ford production that feeds our Texas Intrastate system has added to the profitability of that segment.

Our petrochemical and refined products services segment reported a $36 million increase in gross operating margin for the third quarter of 2012 compared to last year. $24 million of this increase was attributable to proceeds we received in connection with a settlement of certain litigation in our marine business. The remainder of this increase in this segment was the result of higher propylene fractionation margins, increased octane enhancement sales margins, and improved results from marine transportation.

Enterprise generated distributable cash flow of $743 million for the third quarter of this year, providing 1.3 times coverage of the cash distribution declared with respect to the quarter. Distributable cash flow was reduced by $70 million from a loss on the settlement of interest rate hedges associated with our issuance of senior notes in the quarter. Excluding this loss and the $24 million benefit from the litigation settlement, distributable cash flow would have been $789 million, and provided 1.4 times coverage. We retained $177 million of distributable cash flow this quarter to reinvest in the growth of the partnership, and to reduce our reliance on the capital markets.

We continue to complete capital projects on time and on or under budget, and the ramp-up of volumes on these new assets is generally meeting or exceeding our expectations. Through the first nine months of this year, $1.7 billion of organic growth capital projects commenced operations, and another $1.3 billion of projects are expected to begin operations in the fourth quarter.

In 2013, we expect complete an additional $2.4 billion of capital projects. In total, we have approximately $7.9 billion of growth projects under construction that are scheduled to be completed between now and the first half of 2015. Revenues from these projects are predominantly fee-based, and are supported by long-term contracts, and Jim will provide an update on these projects later in the call.

In September we recommended that our Board raise the quarterly cash distribution for the third and fourth quarters of 2012 by 6.1% and 6.5%, respectively, over the same quarter of last year.

Last month, the Board approved the first of these two recommendations by increasing the cash distribution to $0.65 per unit with respect to the third quarter. This is our 33rd consecutive quarterly distribution increase. Our second recommendation to increase the quarterly distribution with respect to the fourth quarter of 2012 of $0.66 per unit will be considered by the Board at the appropriate time.

We have taken steps in recent years to streamline and simplify our organizational structure, in order to be more transparent to investors, to remove potential conflict of interest, and reduce public company overhead. With the help of our general partner, we also eliminated all of the incentive distribution rights it was once held, and now Enterprise has one of the lowest costs of capital in the MLP sector.

It clearly is a long-term benefit to investors in our common units and our debt securities. We want to be able to focus on our business and growth opportunities, rather than trying to decipher the added complexity of a web of leverage related qualities affected by each other. Having once had a complicated structure, we believe simple is better. We would like to thank our debt and equity investors and our bankers for their continued support. With that, I will turn the call over to Jim.

Thank you, Mike. This year, we have been pretty busy. That is reflected in all of the major projects that we have recently completed, or we have under construction. Out West, we are building our Texas Express Pipeline, which will be on in the second quarter of next year. Our Front Range Pipeline which will be on in the fourth quarter of next year. And our Rocky Mountain Mid-America Pipeline Expansion, which will be on the first quarter of 2014. These pipelines will have a total combined initial capacity of 465,000 barrels a day with significant expansion capability. They will serve the Niobrara, Granite Wash, West Texas, Permian, Mid-Continent, and the Mancos. Our ATEX Ethane Pipeline is under construction. We expect that in service in the second quarter of 2014. It will have approximately 200,000 barrels a day of capacity.

In Mont Belvieu, we are commissioning, as we speak, our sixth fractionation play, and our trains seven and eight are under construction. They are expected to be on line by the fourth quarter of next year. By the end of next year, Enterprise will have over 1.1 million-barrels a day of fractionation in capacity Company-wide, with somewhere between 650,000 and 700,000 barrels a day at Mont Belvieu. Also at Mont Belvieu, we are finishing our rebuild and upgrade of our West Storage facility, which we expect on line next month, which will give us added operational and commercial flexibility, and storing and moving more volumes. In the Eagle Ford, our Yoakum trains one and two are running, and they are both exceeding at design specs and train three will be on in the first quarter of 2013.

In NGL and natural gas pipelines and storage projects that support these three plants, have either been put into service or are nearing completion. Phase one of the Seaway Crude Oil reversal came on line in June of this year. Seaway will be fully reversed by the first quarter of next year, and the loop will be completed by the first quarter of 2014. The pipeline will have 850,000 barrels a day of capacity. Our 150-mile pipeline and associated 2.5 million-barrels of storage out of South Texas which support the Eagle Ford field production was recently put into service, and our 180 mile joint venture line with Plains coming out of Gardendale is currently under construction.

We are in the process of bringing the first phase of our ECHO terminal into service, which initially includes three 250,000 barrel tanks for this first phase, with an ultimate capacity of 6 million barrels when fully built out, and we are, in fact, in the permitting process for that. As a matter of fact, we are introducing first oil into ECHO today. When our crude oil pipelines are complete, we will be able to move Seaway and Eagle Ford crudes into ECHO, and have access to all Houston area refineries and all Beaumont/Port Arthur area refineries, to give these pipelines access to over 7.5 million-barrels a day of Gulf Coast refining capacity. Our export dock expansion is nearing completion. We are expecting to increase our export volumes from our current 40 million-barrels a year, to approximately 60 million-barrels a year. Last but not least, we are beginning construction of our propane dehydrogenation plant at Mont Belvieu which we expect on line in 2015. Year-to-date we have brought on eight projects, totalling over $1.5 billion, six of those we are either ahead of schedule or on time. Two or one to two months late but most important, in total, we were 4.5% below budget.

The earnings performance that we announced today and the list of projects that I went through, demonstrate that our businesses and our employees continue to deliver. The industry continues to present opportunities on both the supply and demand side of the equation. An exciting time to be part of this industry, and exciting to be working for Enterprise. I believe in the future, we are going to see a lot of opportunities on the demand side of the equation. As far as products, crude oil prices have been relatively stable in spite of some really divergent fundamentals.

Both in the US and Canada, producers continue to find and develop new supplies, and refiners are positioned to be able to process more domestic crude. The growing supplies that exist north of Cushing into Eagle Ford and into Permian, and shrinking imports confirm the crude oil infrastructure that we are building will play a key role in the changing flow patterns for years to come. Natural gas prices continue to rebound from the very low levels of early summer, and the price collapse that most predicted, including us was averted, with low prices creating significant additional demand through strong coal to gas switching.

For Enterprise, our Texas and Louisiana assets including Haynesville continue to perform better than expected. Our gas assets are backed by firm demand fees. Also, incremental purchases and sales and incremental fees attributed to the flexibility around our interconnects, and are creating more value. Looking to the future, in natural gas we have direct access for growing industrial markets and power generators all along the Gulf Coast. We see significant growth potential in markets that are near our assets in both Texas and Louisiana. This is a function of the globally competitive price of natural gas.

NGL processing margins continue to be depressed especially for ethane. In general the demand for ethane is meeting our projections in both the near term and with all of the new build announcements. But with most drilling now concentrated on rich gas and oil, supplies have exceeded our expectations. That said, ethane cracking is clearly the most profitable feedstock for petrochemicals, and we don't need to look at too many of their presentations and press releases to realize that they get it. As I know, we are likely to get questions about ethane. Yes, it appears ethane will be oversupplied until new build ethylene plants come online. We don't see the $0.50 a gallon ethane margin we enjoyed last year.

That oversupply will be mitigated by fewer turnarounds in 2013 by ethylene plants and by less propane inventory because of increased exports. Propane enjoyed increased demand as a feedstock this past summer, and for export the feedstock-- summer inventory builds at much lower levels than many were predicted. The demand for domestic propane in the export market which was already strong has gotten better, the demand for spot barrels in our dock space continues to be strong, not just this year, but several years out. Refined product inventory both motor gasoline and distillates are low, because of strong global demand and refinery outages including Hurricane Isaac, and now Sandy. As a result, demand for butane, natural gasoline, and specialty fuels has been brisk. We continue to enjoy both short and long-term demand for these products, and our assets realize its premium value accomplished by our--

Excuse me.

Yes.

This is the operator. The line was going in and out a little.

Okay. We are trying to get them to speak more in the microphone.

Can't speak more than that. I am hollering.

Go ahead.

I have said that the next wave of opportunities for Enterprise could be on the demand side of the equation. Our PDH project is an excellent example of this, and an excellent fit with our existing operational and commercial capabilities. But more importantly, it demonstrates how Enterprise's position continues to provide the link between plentiful and growing NGL supplies, and growing opportunities in petrochemicals.

In summary, as fundamentals change, we continue to find ways to increase our contribution along the value chain, whether it be —in NGLs, crude oil, natural gas, petrochemicals or in exports. We have a lot going on with the Eagle Ford build-out, our western NGL pipelines, our fractionation trains at Mont Belvieu, Seaway, our ECHO terminal, and our expanding export capabilities in PDH. We have gotten a lot done over the last couple of years with projects that fit our capabilities. As Mike pointed out, there is plenty to be done, and new opportunities are on the horizon. Our principals, our strong customer focus, our employees, and our reputation will allow us to capture even more opportunities. And with that, I turn it over to Randy.

Thank you, Jim. I would like to take a few minutes to discuss some additional items on the income statement. As far as we reported net income of $588 million, and earnings per unit of $0.66 per unit. That is on a fully diluted basis for the third quarter of 2012. Net income and earnings per unit were reduced by $43 million or approximately $0.05 per unit on a fully diluted basis for noncash asset impairment charges. Most of these charges were related to small pipelines located in the Gulf of Mexico. Net income and EPU included the $24 million, or $0.03 per unit benefit from the settlement of a litigation in our marine business. G&A expense was $41 million in the third quarter 2012, compared to $50 million for the third quarter of 2011. The primary reason for the decrease was $10 million of merger-related expenses recorded in the third quarter of last year, with respect to the merger of Duncan Energy Partners.

In terms of interest expense, it increased to $200 million this quarter from $189 million recorded in the third quarter of last year, primarily due to an increase in our average debt principle outstanding. Provision for income taxes decreased $9 million due to a decrease in Texas margin tax expense accruals this quarter. We spent $1.1 billion on capital expenditures this quarter, including approximately $1 billion on growth capital investments. We are on track to invest approximately $4 billion in growth capital projects this year, having invested $2.8 billion in capital expenditures for the first nine months of 2012. Sustaining capital expenditures were $102 million this quarter. It now looks like we will come in at around $330 million to $340 million for sustained CapEx in 2012.

In terms of capitalization, adjusted EBITDA for the 12 months ended September 2012 was $4.4 billion. Our consolidated leverage ratio of debt principle to adjusted EBITDA was 3.45 times for the 12 months ended September 30. This adjusts debt for 50% equity treatment of the hybrid securities. We accessed the debt and equity capital markets for $2.4 billion of capital in the third quarter to fund our growth projects.

We had strong demand for our senior notes offering in August. We issued $650 million of three-year notes at 1.25% interest, and $1.1 billion at 30-year notes at 4.45%. Both of these issues have traded tighter since offering. Also in the third quarter, we raised approximately $600 million of equity through the aggregate sale of $11.6 million common units through an overnight offering, our ATM program, and our distribution reinvestment plan. The average life our debt is now 12.9 years using the first call date for the hybrids. And our effective average cost of debt is with 5.6%, and this was all as of September 30, 2012.

During the quarter, third quarter, we also established a commercial paper program in August. That allowed to issue up to $2 billion of short-term commercial paper notes backed by a $3.5 billion multi-year credit facility. The program is rated A2/P2. Any commercial paper notes issued under this program will be treated as senior unsecured obligations. To date, no notes have been issued under this program.

At September 30th, we had consolidated liquidity of approximately $3.4 billion, which includes the availability under our credit facility, as well as unrestricted cash. With that, Randy, I think we are ready for questions.

Tiffany, we are ready to take questions now.

Thank you. (Operator Instructions). Your first question comes from the line of Darren Horowitz of Raymond James.

Hello, Darren.

A couple of questions for you. First, I want to go back to the comments that you made regarding the short-term outlook around the ethane market in pricing. A couple of things to point out. It looks like you have got a handful of crackers that are going to be coming back up online in the next couple of months, so ethane demand should increase. But at the same time we have got north of 30 million-barrels of ethane in inventory, and we are probably rejecting somewhere between 120,000 and 125,000 a day, when you look at the Rockies and the Mid-continent. I am wondering if all of these things happen as you kind of described, what do you think happens to Mont Belvieu ethane pricing over the next couple of months, and more importantly, the spread between Belvieu and Conway?

I don't think the spread between Belvieu and Conway is, until more pipelines are in place, I don't think that changes them significantly. What was your other question? What happens to the ethane price at Mont Belvieu?

Yes. Let's just say demand goes to 1 million or 1.1 million-barrels a day in November or December we start drawing down inventories, do you think there is a tailwind to ethane price?

It could be, Darren. You are not going to have the overhang of propane from a mild winter. So you are not going to have, I don't believe you are going to have propane competing with ethane as a cracker feedstock, and we are going to export a heck of a lot more barrels next year than we did this year. So by definition, theoretically, you ought to get a little bit of a tailwind. I am just saying it is not going to get you back to those margins that we enjoyed last year.

Sure. Jim, how do I think about your ability from an equity NGL perspective to be long Conway and sell Belvieu pricing to maximize the profitability coming out of the tailgate of Meeker and Pioneer? How do I think about that over the next couple of quarters?

Say that again, Darren.

Your ability to be long Conway ethane at depressed pricing and sell it at Belvieu prices, pick up the margin, effectively pay yourself on the transport from Conway down to Belvieu. I am just trying to think about the opportunity cost or potential upside in opportunity processing that we could get from Meeker and Pioneer in the fourth quarter? Maybe even in the first quarter of next year?

What we look at every day, and we crunch this constantly, we are looking at where do we make the most money across the system. So if we make more money rejecting ethane at Meeker, and buying EP at Conway, and selling Mont Belvieu because it frees up the pipeline capacity, that is what we do. I don't know if that answers your question.

Yes, I am just trying to quantify the potential upside there?

We try to quantify that every day.

I know you keep it close to the vest. That is okay. Last question, and this is intriguing. This goes back to your comment about the next wave of opportunities here on the demand side. When do you start thinking about the potential for butane dehydrogenation if you are due to capitalize on either the butadiene or butylene demand, or maybe even more isomerization capacity to arb the normal to isobutane spread, recognizing that it is seasonal? Is that what you were talking about, Jim?

You are pretty good, Darren. We did our PDH plant because we have got customers that recognized that they wanted an on purpose supply in their portfolio. I think we were public that we were promoting the same thing, in terms of on-purpose butadiene. Those customer have not crossed the threshold of recognizing that they want on-purpose butadiene. However, butadiene is a coproduct out of crackers. At some point, in my mind, they are going to recognize that need.

Yes. That makes sense. I appreciate it, Jim. Thanks for the time.

Your next question comes from the line of Brian Zarahn of Barclays.

Good morning.

Good morning, Brian.

The onshore crude business had another pretty solid quarter, and you highlighted that South Texas did well. Can you comment a little bit more on your other systems about West Texas and the Bakken, have they contributed to results at all? Or contribute to improved results?

West Texas, we are full, our pipeline systems out there are full. We just put in a new project. Rob, is that an eight inch pipeline at Trinity? Eight or ten? To help. It is not a big project. But what we found out there is we are stretched to the limit on trucks. And we are constantly battling to get our loads on the books down. So West Texas, I don't know what the results were but our volumes are strong. Of course in the Eagle Ford, they are strong. And Mid Continent, Oklahoma --

It is a little more flat in the Mid-continent area.

Robbie is saying it is a little bit flatter in the Mid-Continent, Oklahoma area. But by and large between West Texas and South Texas, we are continuing to see growing volumes and a shortage of trucks.

Are you seeing that also in the Bakken with your gathering business?

In the Bakken, we don't really have any pipeline assets, we have a trucking company. They have done pretty good up there. I can't remember how many barrels a day we are handling, but Mike, we doubled our truck fleet up there in just 18 months. Yes.

150,000 barrels a day.

Yes, call it 150,000 barrels a day.

I was asking more for the trucking in the Bakken, if you are seeing any sort of shortages?

We are stretched. We bought this Mike, when did we buy that? Two years ago? I think it had 24 trucks. We are up over 50 now. So hopefully that--, we are growing.

I think you see the same thing in the Bakken as you do in Texas, there is a shortage of trucks, but we don't want to ramp up our truck capacity, and be long trucks when pipelines come online. There is a bit of a balancing act there.

Okay. And then obviously some crude projects under construction. That coupled with pretty solid growth in the South Texas business. Do you expect the onshore crude business to eventually surpass the onshore gas business, in terms of operating margin? Down the road?

Mike, you take that one.

I think we have got to get more capital projects in the mill.

Even looking at 2015, you still think it would be smaller than the onshore gas business?

I don't know. We have got a couple of big things that we are doing with the Seaway pipeline, in terms of expanding existing capacity and looping it. The ECHO Terminal has a lot of potential as we have the capacity to get up to 6 million barrels of storage capacity. We will see where it takes us, but Robbie is continuing to look for additional ways to spend money on that business.

Okay. Last one for me, in the press release, you mentioned and you have commented previously that your fee-based cash flow mix obviously is growing with the organic projects coming online. You mentioned the mix will, fee-based mix will exceed 80% in 2014. As you look to 2014 and 2015, roughly what is your thought process of how much above 80% do you think the fee-based cash flow mix could be?

I think we need to update those numbers. I think they are a bit stale. I think our fee-based cash flows will be higher than we previously indicated, primarily because we have got some producers that have elected to redo their contracts. As we have said before, to retain the NGL upside from their production, and as a result, we are moving from some keep-whole contracts to more fee-based contracts. That has been fairly recent. We will update those numbers and have more guidance on that, probably the next conference call.

Thanks, Mike.

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

Ted, you there? Hello?

Hello.

Ted, can you hear us?

Can you hear me?

Yes.

Yes. Sorry about that. Just picking up on the last comment from Mike there. In terms of the shift away from keep-whole, is that something where you are actively out there renegotiating these keep-whole contracts? Or is it more you are just letting the contracts roll off, and then they are switching to fee-based? I am trying to get the sense of the trajectory of how the contract mix is changing?

Yes. I think this is really producer dependent. If you have producers that have keep-whole contracts, and their economics are really based just on natural gas, there is not a lot of incentive for them to drill. So this is an opportunity where it provides them some economic incentive. It provides us something in terms of more stable cash flows. It really is a win/win. But it is not something that we are going out and beating on every customer that we have. We are talking to people, and when they want to talk about reforming their contracts, we are certainly willing to listen to them, and do something that works for both of us.

Okay. That is helpful. And then just thinking about the distribution policy, I guess I was a little unclear on the language. You said a special increase of a half a penny here this quarter and next quarter. How should we think about that? Is that something that is going to be a discretionary increase we will get, and you will just make that decision every quarter, or is this something that you can continue at this higher level of quarterly increases?

I think the way to think about it is if we had just increased it by a penny for the quarter, we would have been at $0.645, and we are trying to get rid of the half cent, just to make it easy for investors and for us. So we think good round numbers are good. Part of our simplification project.

Appreciate that. Okay. Okay.

Reset the distribution at $0.65. That is where it will be until the next increase.

Got it. That is fine. Last one for me is just there is another MLP that is talking about doing ethane export. And realizing that this is Marcellus, and it is kind of challenged in terms of with ethane. Is it something you would ever consider doing along the Gulf Coast?

We consider anything if we can make money at it.

Ted, one of the things that we think about in the Gulf Coast because ethane supply is there, petrochemicals are going to build new assets where the supply is, so why spend the extra money to export it someplace else. That is what we are seeing the petrochemicals do. If you look at the numbers that we have been hearing about for theoretical ethane exports, is kind of twice the cost it costs someone to move it by pipe, by our pipe, down to the Gulf Coast. We think we have got a better solution. But as Jim said, if somebody is willing to pay the freight to have us construct an export facility and enter into a long-term contract and provide the right returns, it is something we would consider.

But you have got to remember who are some of our key customers. Our key customers are the US petrochemicals. That is who we are primarily focused on serving. It is very expensive to export ethane. I would rather some of those guys come build crackers in the US.

Understood. I guess maybe thinking about the, you are bullish on the propane export market. You just feel like it is more limited export market for ethane, is that what you are coming down on?

There are a lot of propane shifts. There aren't any ethane shifts.

Ethane, if it is going to be moved by ships, it will be at a much lower temperature, it is more expensive. It is just more, it is more difficult.

Okay. Okay. That was it for me. Just wanted to check on that. Thanks, guys.

Your next question comes from the line of T.J. Schultz of RBC Capital Markets.

Hey guys, good morning. I guess just first on the West Storage at Belvieu, bringing it back on line next month, can you just provide a little bit more color on what if any kind of material constraints this may have caused for you, just trying to quantify what type of impact bringing it back on line may have?

I will probably turn it over to Rudy at a point. But we got most of our capabilities back before we brought, I mean we did things to be able to have the same capability. We spent money after that event as we had before it. What I think this brings back is a heck of a lot more flexibility and more capability to store. Rudy?

That is correct, Jim. We have got a couple of customers that we don't serve in a traditional manner, because of the West Storage event. We will bring them back on before the end of this month is out. As Jim said, it will just give us a lot more flexibility and some more storage capacity.

Rudy, some redundancy?

Absolutely some redundancy. Absolutely. Just more flexibility and some, the west wells are fairly deep. That gives us a lot of pressure. That keeps the petchems happy, when we are giving them a lot of pressure.

What we have done in the course of this rebuild is we are going to have pipeline systems that, if we ever have any, then again, there will be absolutely zero interruptions. We have modified how we are putting our pipeline systems back in place around Mont Belvieu.

Okay, great. Thanks. I guess on the TE Products pipeline, you have talked before about reconfiguring pumps to allow for some reversal there, and the ability to flow product south. Is there any update there with respect to discussions of customers?

In terms of our ethane pipeline?

The products pipeline in Pet2?

You are talking about refined products and propane going up north?

Right. I think you talked about maybe being able to reconfigure some pumps to kind of flow some of the volumes further back down south. And you talked about it at the Analyst Day a little bit. But I think there was some--?

Want to take it, Rudy, do you know? I think what you are talking about is, and this thing has not grown legs as fast as we would have liked it to. But you are talking about being able to move refined products out of the Midwest refineries back down the system, but we are still working that but frankly, so far it hasn't grown legs.

Okay. Fair enough. Thanks, guys.

Your next question comes from the line of John Edwards of Credit Suisse.

John?

Can you hear me?

Yes, we can hear you, John.

I am just curious with all of the construction projects, what kind of cost escalation are you seeing going on right now?

I will turn it over to Leonard but just in general, our projects have been coming in on or under budget, and we think it is because Leonard has figured out how to game the system.

I have been accused of sandbagging. But it is my position that we are just good. Actually, as far as labor costs have gone, maybe 1% or 2% escalation, but nothing significant. I think we have an advantage because we have a very large number of projects, and we get some very favorable bids from our contractors. So we have really been benefiting from all of our activities.

John, I think Mike mentioned that we had $1.7 billion worth of assets that have gone into service for the first nine months of this year. Those have come in on average about 4.5% under budget. Again, doing a great job in managing the costs.

That is great. And you are not seeing any significant shortages, either labor or material-wise?

No. Again, I think we have an advantage because when we call these contractors, they give us a preference, because they know we will have the work for them. A good example is we have had one set of contractors at Mont Belvieu building fracs for the last four years. They like that stability.

Alright. That is helpful. And then just your thoughts as far as natural gas liquids prices as a percentage of crude over the next year? How do you think that will play out? It has been below 40% just recently, gone up to around 50%. What are you thinking on that?

Do you want to take that?

Yes, I will take it. They have come up a bit so the numbers are slightly better than 40% today. Ethane is probably going to be what drives it. You are not going to see big, big jumps in it. I don't believe.

One of the problems is you are trying to figure out what is the right relationship. If you look historically, propane should be 65% to 75% of crude. But crude wasn't $100 a barrel. So as the price of crude goes up, the cost basis is still natural gas. So what is the norm in a relationship to crude given this environment, and I am not sure anybody knows at this point.

Okay. And then just following on Ted's question so for next year, since you got everything evened up here, we should think about one cent per quarter per unit increase going forward, nice and simple?

Good try, John. (laughter)It sounds logical but we have never given a forward forecast for distribution growth.

I have to try.

I know.

Okay. Just on the Seaway, and the press release said the equity income was up $18 million per se. What was actually the number on that?

On the absolute dollar amount?

The absolute dollar number. I didn't have a chance to go back and look, I thought you might have it handy?

Hey, John, Randy here. It looks like it is the absolute number would be $16.5 million.

Ok. Alright.

We want to reverse it.

Yes. Now as you bring the additional capacity on, are you expecting that to go up sizeably? Or how does that, how do those contract terms work, I guess?

It is based on volumes, obviously. If we are flowing something less than 150,000 barrels a day, and we have got the ability with the looping and the expansion to take it to 850,000, we are not going to spend that money unless we expect to see bigger returns.

Sure. Is the relationship going to be similar in terms of say, amount per barrel? That's what I am trying to get to.

I am confused, John, what you are asking?

You could back into sort of what the dollar per barrel shipping rate was based on this. I am just wondering is it reasonable to assume it will be a similar rate going forward?

It ought to be. Given the mix.

Depending on what the mix is between light and heavy.

It is safe to assume a linear relationship there?

I think you guys ought to look at that.

This is Randy. I will call you back and follow-up with you, okay?

Okay, great. Alright. And just last thing, maybe I missed it. Is the propane export facility, is that up and running now?

You mean the expansion?

The expansion, Yes. Sorry, the expansion?

We are looking hopefully in January.

Okay. Alright. That is all I had. Thank you very much.

Okay, thanks.

(Operator Instructions). Your next question comes from the line of Michael Blum of Wells Fargo.

Can you guys hear me okay?

We can.

Great. One quick question from me. I apologize, I got bumped off the call if this was asked already. Obviously, Jim, you talked about the upside, the future being on the demand side in terms of opportunities. I am sure you obviously saw the PLR for ethylene crackers. Just wanted to get your thoughts, in terms of maybe looking at an ethylene cracker, especially in light of the fact that a lot of your customers have ethylene crackers. Thanks.

You mean would we look at one, Michael?

Yes.

I don't want to speak for Enterprise. I speak for me. I hope not. (laughter). We have got a bunch of customers that I think would be a little bit irritated at us. So no.

Alright. Thank you very much, guys.

Thanks, Michael.

Your next question comes from the line of Bernie Colson of Global Hunter.

Hello, Bernie. Bernie, you there?

Yes, can you hear me?

We can hear you.

Okay. So over the past six quarters, you have had kind of way, I would call way in excess of your coverage ratio of what you need to run your business comfortably. As we transition here into a lower NGL price environment, and then earlier you said you are transitioning to an 80% fee-based business model, how do we think about that coverage ratio, and where you want to manage the business, after we kind of undergo that transition fully?

Bernie, we just announced an increase in the rate of growth in our distribution so we have kind of taken that into consideration. If you look at our distribution coverage this quarter, it is 1.3 times. We have talked about all of the capital we have got to spend the remainder of this year and next year, and frankly through 2015. We continue to find ways to develop more projects. So as we have talked about in the past, our ability to retain some of this cash flow for reinvestment in those projects reduces the capital churn that we would otherwise have, reduces our need to go out and issue new equity in the market. And we think it provides better long-term returns for our investors. So I don't think you are ever going to see us at a point where we have got a one-time distribution coverage, and if anything, I think you see more MLPs being like us, and retaining cash flow, because frankly it makes financial sense.

Understood. Okay. And then change gears a little bit. Thinking about ATEX as it comes online, obviously it is going to, I think the tariff is at around $0.15 on your contract capacity, is that correct?

$0.14, $0.15, something like that.

It seems like with the amount of ethane that is expected to come from the Marcellus that you are going to shift from a situation where the marginal barrel of ethane comes from the Northeast instead of the Rockies. I was just really kind of wondering thoughts about the impact of what you thought kind of long-term floor prices of ethane could be, given that potentially that stuff is going to be coming from further away?

I think what will flow in the Marcellus until you see ethylene plant and new builds, I think what we have gotten subscribed is what will flow. Because those are demand fees and that is on cost. I think marginal incremental supply above that is going to require more demand, because you just nailed it. Our tariff is $0.15, and their frac fee up there is probably $0.07, so they have got probably a $0.20 or $0.22 hurdle before the next incremental barrel flows, and there has got to be an ample pipe for that incremental barrel.

Okay. So if you think about, I guess this stuff is locked up. But any commentary on what the potential market rate on any excess capacity you may have on ATEX will be until it is completely full?

You mean are we going to reduce our tariff?

Yes. If you have some excess capacity on ATEX, and until you have that demand flow from the Gulf Coast, is that just going to be, are there any prospects of filling that up, or is that 100% full at this point?

Have we been public on what we have got in that? I think we peak at about 135,000 or 140,000 barrels a day. We start out at about 75,000 barrels a day. I don't think you can, I don't see any incentive for us to try to use our variable economics to increase flows down that pipeline. We have got a lot of production in the Yoakum and up in the Rockies. So I don't see that.

Okay. So it is 190,000 to 200,000 barrels a day pipelines?

Only if we expand the capacity.

Okay. Okay. It is going to come on at more like that 150,000 range?

I think what it is going to come on is about 75,000 to 80,000 ramping up to somewhere in the neighborhood of on our subscriptions of 135,000 or 140,000, or in that ballpark in five years. That is over a five-year period. So in other words, you have got new ethylene plants by the time we are at the peak on our ramp.

Okay. Understood. Thanks a lot.

Your next question is a follow-up from the line of T.J. Schultz of RBC Capital Markets.

Any update on the potential ethane header system?

We are still working it and we are getting closer. And I am a Dow retiree, so I understand how those guys work. They are pretty methodical. But I think ultimately, I think that system grows legs. Frankly, we will do that system at a return that some other systems we wouldn't do. Because we see a heck of a lot of upside. So what we are trying to do is get over the hurdle that we have kind of targeted, and it is not outstanding, but it is accretive. We think there is a lot of upside on that.

Okay. Thanks.

There are no further questions at this time. Presenters, do you have any closing remarks?

No, Tiffany. If you would, would you please give our listeners the replay information?

Of course. Thank you for participating in today's Enterprise Products Partners third quarter 2012 earnings conference call. This call will be available for replay beginning at 1PM Eastern Standard Time today through 11.59 PM Eastern Standard Time on Thursday, November 8, 2012. The conference ID number for the replay is 49928406. Again, the conference ID number for the replay is 49928406. The number to dial for the replay is 1-855-859-2056 or 404-537-3406. Again, the number to dial for the replay is 1-855-859-2056 or 404-537-3406. Thank you. This concludes today's conference call. You may now disconnect.

Thank you. Everyone have a good day. Thank you for joining us.