Enterprise Products Partners L.P. (EPD) Q3 2012 Earnings Report, Transcript and Summary

John R. Burkhalter - Vice President of Investor Relations Michael A. Creel - Chief Executive Officer of Enterprise Products Holdings LLC, President of Enterprise Products Holdings LLC and Director of Enterprise Products Holdings LLC A. James Teague - Chief Operating Officer of Enterprise Products Holdings LLC, Executive Vice President of Enterprise Products Holdings LLC and Director of Enterprise Products Holdings LLC W. Randall Fowler - Chief Finance Officer of Enterprise Products Holdings LLC, Executive Vice President of Enterprise Products Holdings LLC and Director of Enterprise Products GP-General Partner Robbie Leffel - Senior Vice President - Crude Oil of Enterprise Products Holdings LLC Rudy A. Nix - Officer of Subsidiary Leonard W. Mallett - Group Senior Vice President of Engineering - Enterprise Products Holdings Llc

Darren Horowitz - Raymond James & Associates, Inc., Research Division Brian J. Zarahn - Barclays Capital, Research Division Theodore Durbin - Goldman Sachs Group Inc., Research Division TJ Schultz - RBC Capital Markets, LLC, Research Division John Edwards - Crédit Suisse AG, Research Division Michael J. Blum - Wells Fargo Securities, LLC, Research Division Bernard L. Colson - Global Hunter Securities, LLC, Research Division

Good morning. My name is Tiffany, and I will be your conference operator today. At this time, I would like to welcome everyone to the Enterprise Products Partners Third Quarter 2012 Earnings Conference Call. [Operator Instructions] Thank you. I 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 today, 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, 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 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. And Tiffany, before I turn it over to Mike, how's the quality of the call? Can you hear us?

Yes, you are coming through loud and clear.

Okay. All right, Mike.

Thanks, Randy. And before I start, I would like to let all of our friends in the Northeast know that our thoughts are with you. We know what it's like to go through a hurricane and how much damage and destruction it can cause, and you just got hit by the largest hurricane to ever 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 4 of our 5 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 & Services segment accounted for $68 million of this increase with substantially all of the increase attributable to our fee-based NGL pipelines, 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 pipelines, 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 increased 17% to a record 4.5 billion cubic feet a day, while our equity NGL volume decreased 13%. This shift reflected the desire of our producers to retain the value of their NGL production and the associated volume risk to increase their return on investment. We view this development as a win-win that provides producers with greater economic incentive to drill and provides Enterprise with an increase in fee-based volume and cash flow. Our Onshore Crude Oil Pipelines & Services segment reported a $15 million increase in gross operating margins compared to the third quarter of 2011. Our record pipeline volume is 820,000 barrels per day. Our South Texas crude pipeline system, including the new 24-inch pipeline [ph] from [indiscernible] that began service in June of this year accounted for $20 million of this increase or a 75,000 barrel 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 [indiscernible] from the Texas Gulf Coast. We also had record onshore natural gas transportation volumes this quarter of 14.2 trillion cubic meters per day, which led to a $28 million increase in gross operating margin from our Onshore Natural Gas Pipelines & 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 some increased Eagle Ford production in the Texas NGL pipeline system. Our Petrochemical & Refined Products Services segment reported a $37 million increase in gross operating margin for the third quarter of 2012.

Excuse me. The line is breaking up a little. [Technical Difficulty]

All right. 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 & Refined Products Services segment reported a $37 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 a result of higher Propylene fractionation margins, increased octane enhancement sales margins, improved segment results from rain [ph] transportation. Enterprise generated distributable cash flow of $743 million to the third quarter of this year, providing 1.3x coverage of the cash distribution declared with respect to the quarter. Distributable cash flow was reduced by $70 million from a loss from 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 1.4x 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 9 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 to 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've recommended that our Board raise the quarterly cash distribution for the third and fourth quarter of 2012 by 6.1% and 6.5%, respectively, over the same quarters of last year. Last month, the board approved the first of these 2 recommendations by increasing the cash distribution to $0.65 per unit, as reflected in the third quarter. This is our 33rd consecutive quarterly distribution increase. Our second recommendation, they increase the quarterly distribution with respect to the fourth quarter of 2012 to $0.66 per unit, will be considered by the board at the appropriate time. We've taken steps in recent years to streamline and simplify our organizational structure in order to be more transparent to investors, to remove [indiscernible] expenses and reduce public company overhead. With the help of our general partner, we also eliminated all of the incentive [ph] distribution rights that we once held, and now Enterprise has one of the lowest costs of capital in the MLP sector. This clearly is a long-term benefit to investors in our common units and our debt securities [ph]. We want you to be able to focus on our business and growth opportunities rather than kind of decipher the added complexity of the leveraged related qualities [indiscernible] by each other. But being quite a [ph] complicated structure, we believe simple is better. We'd like to thank our debt and equity investors and our bankers for their continued support. And with that, I'll turn the call over to Jim.

Thank you, Mike. This year, we've been pretty busy, and that's reflected on 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 in the first quarter of 2014. These pipelines will have a total combined initial capacity of 465,000 barrels a day with significant expansion capability that will serve the Niobrara, Granite Wash, West Texas, Permian, Mid-Continent, and the Marine [ph]. 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. At Mont Belvieu, we are commissioning, as we speak, our sixth fractionation crane. And our cranes 7 and 8 are under construction. We expect them be online 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 capacity, coupling [indiscernible], with somewhere between 650,000 to 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 to open [ph] next month, which will give us added operational and commercial flexibility in storing and meeting more volumes. In the Eagle Ford, our Yoakum trains 1 and 2 are running, and they're both exceeding at-design spikes. And train 3 will be on in the first quarter of 2013. The NGL & natural gas pipelines and storage projects that support these 3 plants have either been put into service or are nearing completion. Phase 1 of the Seaway Crude Oil reversal came online in June of this year. Seaway will be fully reversed by the first quarter of next year and the load [ph] will be completed by the first quarter of 2014, and that 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 crude oil collection, was recently put into service, and our 180-mile joint venture line with [indiscernible], coming out of Gordondale [ph], is currently under construction. We're in the process of bringing the first phase of our ECHO terminal into service, which initially includes 3 250,000-barrel tanks for this first phase with an ultimate capacity of 6 million barrels when fully built out and we're, in fact, in the permitting process for that. As a matter of fact, we are introducing first oil [ph] into ECHO today. When our crude oil pipelines are complete, we'll be able to move Seaway and Eagle Ford crudes into ECHO and have access to all Houston area refineries and all Beaumont/Port Arthur [indiscernible] refineries, with those pipelines access to over 7.5 million barrels a day of [indiscernible] refining capacity. Our [indiscernible] export [indiscernible] expansion is nearing completion. We expect an increase on export volumes from our current 40 million barrels a year to approximately 60 million barrels a year. And last but not least, we are beginning construction of our propane dehydrogenation plant at Mont Belvieu, which we all expect online in 2014. Year-to-date, we've brought on 8 projects totaling over $1.5 billion. 6 of those we're either ahead of schedule or on-plan, 2 are 1 to 2 months late, but most important and notable, we were 4.5% below budget. The earnings performance we announced today and the list of projects that I mentioned demonstrate that our businesses and our employees continue to deliver. The industry continues to present opportunities in both the supply and the demand side of the equation. It's 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 U.S. and Canada, producers continue to find and develop new supplies and the refineries are positioned to be able to process more domestic crude. The rolling supplies that exist north of Cushing -- the growing supplies that exist north of Cushing from the Eagle Ford and into Permian and shrinking imports confirm that the crude oil infrastructure that we're building will play a key role in the changing flow patterns for years to come. Natural gas prices [indiscernible] including the 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, continued to perform better than expected. Our gross assets are [indiscernible] backed by firm demand feeds. Also, incremental purchased set and sales and incremental feeds attributed to the flexibility around our interconnects are creating more value. Looking to the future in natural gas, we have direct access to growing industrial markets and power generators all along the Gulf Coast. We see significant growth potential in markets and near our assets in both Texas and Louisiana, and 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 more projections in both the near term and with all the new build announcements. With the most drilling now concentrated on rich gas and oil, supplies have exceeded our expectations. That said, ethane cracking is clearly the most profitable feedstock in Petrochemicals, and we don't need to look at, to the -- both presentations and press releases to realize that they get it. As I'll note, we are likely to get questions about ethane. Yes, it appears ethane will be oversupplied until new build ECHO 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 [indiscernible], by less propane inventory other than [indiscernible] because of new and -- because of increased exports. Propane enjoyed increased demand as a feedstock this past summer. And for export, that these factors [indiscernible] much lower levels than many were predicting. Demand for domestic propane in the export market, which was already strong, has gotten better. The demand for spot barrels and [indiscernible] space continuing to be strong, not just this year but for several years out. Refined product inventory, both motor gasoline and [indiscernible], and all because of strong global demand and refinery outages, including hurricanes [indiscernible]. As a result, demand for butane, natural gasoline and specialty fuels has been brisk [ph] and we continue to enjoy both short and long-term demand for these products and our assets will realize its premium values...

Excuse me. This is the operator. Your line was going in and out a little. [Technical Difficulty]

I've 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 bip with our existing operational and commercial capabilities. But more importantly, it demonstrates how Enterprise's position continues to provide the link between plentiful and rolling 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 in order to be an NGLs [indiscernible], natural gas, petrochemicals or exports. We have a lot going on with the Eagle Ford buildout, our west NGL pipelines, our fractionation trains at Mont Belvieu, Seaway, our ECHO terminal and our expanding export capabilities in PDH. We've gotten a lot done over the last couple of years. We're quite confident in our capabilities. But as Mike pointed out, there's plenty to be done and new opportunities are on the horizon. Our strong customer focus, our employees and our reputation will allow us to capture even more opportunities. And with that, I'll turn it over to Randy.

Thanks, Jim. I'd like to take a few minutes to discuss some additional items on the income statement. As far as -- we recently reported net income of $588 million and earnings per unit of $0.66 per unit. That's 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 ETUs [ph] included the $24 million or $0.03 per unit benefit from the settlement of the 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 principal 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 in capital expenditures this quarter, including approximately $1 billion on growth capital investments. We're on track to invest approximately $4 billion in growth capital projects this year, having invested $2.8 billion in growth capital expenditures for the first 9 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 of 2012 was $4.4 billion. Our consolidated leverage ratio of debt principal to adjusted EBITDA was 3.45x for the 12 months ended September 30, and this adjusted debt for 50% equity treatment of the average [ph] 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 3-year notes at 1.25% interest and $1.1 billion of 30-year notes at 4.45%. Both of these issues have traded to idle 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 of our debt is now 12.9 years using the first call date for the hybrids. And our effective average cost of debt is 5.6%, and this was all as of September 30, 2012. During the quarter, third quarter, we also established a commercial pipeline program in August that allowed us to issue up to $2 billion of short-term commercial paper notes backed by a $3.5 billion multi-year credit facility. The program was 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 30, we had consolidated liquidity of approximately $3.4 billion, which includes the availability under our credit facility, as well as unrestricted cash. And with that, I think we're ready for questions.

Tiffany, we're ready to take questions now.

[Operator Instructions] Your first question comes from the line of Darren Horowitz of Raymond James. Darren Horowitz - Raymond James & Associates, Inc., Research Division: 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 and pricing. And a couple of things to point out. It looks like you've got a handful of trackers [ph] that are going to be coming back up online in the next couple months so ethane demand should increase, but at the same time, we've got north of 30 million barrels of ethane in inventory, and we're probably rejecting somewhere between 100,000 or 125,000 barrels a day when you look at the Rockies and the Mid-Continent. So I'm wondering, if all 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?

Well, I don't like the spread between Belvieu and Conway 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? Darren Horowitz - Raymond James & Associates, Inc., Research Division: Yes. Like, 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's a tailwind to ethane pricing?

Well, yes, it could be, Darren. I mean, it's really, -- you're not going to have the overhang of propane from a mild winter. So you're not going to have -- I don't believe you're going to have propane competing with ethane as a cracker feedstock and we're going to export a heck a lot more barrels next year than we did this year. So by definition, theoretically, you'd ought to get a little bit of a tailwind. I'm just saying, it's not that we'll get you back to those margins that we enjoyed last year. Darren Horowitz - Raymond James & Associates, Inc., Research Division: Sure. Jim, how do I think about your ability, from an equity NGL perspective, to belong [ph] Conway and set our Belvieu pricing to maximize the profitability coming out of the tailgate at Meeker and Pioneer? How do I think about that over the next couple quarters?

Say that again, Darren. Darren Horowitz - Raymond James & Associates, Inc., Research Division: Your ability to be long Conway ethane at the press pricing and sell at the Belvieu prices, pick up the margins, effectively pay yourself on the transport from Conway down to Belvieu. I'm just trying to think about the opportunity cost or potential upside and opportunity processing that we could get from Meeker and Pioneer in the fourth quarter, maybe even in the first quarter next year.

What we look at every day is, and we crunch this constantly, we're 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's what we do. I don't know if that answers your question. Darren Horowitz - Raymond James & Associates, Inc., Research Division: Yes, I'm just trying to quantify the potential upside there, but that's okay.

Yes, we try to quantify that every day. Darren Horowitz - Raymond James & Associates, Inc., Research Division: Yes, I know you keep it close to the vest. That's 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're 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 as seasonal? Is that what you were talking about, Jim, or...

You're pretty good, Darren. We did our PDH plant because we 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 customers have not crossed the threshold of recognizing that they want on-purpose butadiene. However, butadiene is a coproduct out of crackers. To some -- at some point, in my mind, they're going to recognize that need.

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

The Onshore Crude business had another pretty solid quarter and you highlighted that South Texas as well. Can you comment a little more on your other systems, about West Texas and the Bakken, have -- did they contribute to the results at all, or contribute to improved results?

West Texas, we're full. Our pipeline systems out there are full. We just put in a new project. Rob, is that an 8-inch pipeline at Trinity? 8 or 10 to help. It's not a big project. But what we found out there is we're stretched to the limit on trucks, and we're 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're strong. And Robbie, Mid-Continent, Oklahoma?

It's a little more flat in the Mid-Continent area...

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

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

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

150,000 barrels a day.

Yes, call it 150,000 barrels a day.

Yes, I was asking more on the trucking in the Bakken, if you're seeing any sort of shortages.

We're stretched and we bought this -- Mike, when did we buy that? 2 years ago?

Yes.

I think it had 24 trucks and we're up over 50 now, so hopefully that -- yes, we're growing. I think you'd see the same thing in the Bakken as you do in Texas, is that there's a shortage of trucks, but we don't want to ramp up our truck capacity and be long [ph] trucks when pipelines come online. So it is a bit of a balancing act there.

Okay. And then you guys -- obviously, some quick projects under construction, and 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.

No, I think we've got to get more capital projects in the middle, but...

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

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

Okay. And last one for me. In the press release, you mentioned -- and you had 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 '15, I mean, roughly, what's 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're a bit stale, and I think our fee-based cash flows are going to be higher than we previously indicated, primarily because we've got some producers that have elected to redo their contracts. And as we said, we look forward to retain the NGL upside from their production. And as a result, we're moving from some keepwhole contracts to more fee-based contracts. And so that's been fairly recent, but we'll update those numbers and have more guidance on that by the next conference call.

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

Just picking up on the last comment from Mike there in terms of the shift away from keepwhole, is that something where you're actively out there renegotiating these keepwhole contracts, or is it more you're just letting the contracts roll off and then they're switching to fee-based? I'm just 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 keepwhole contracts and their economics are really based just on natural gas, there's not a lot of incentives 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's not something that we're going out and beating on every customer that we have. It's -- we're talking to people and if -- when they want to talk about reforming their contracts, we're certainly willing to listen to them and do something that works for both of us.

Okay, that's helpful. And then just thinking about the distribution policy, I guess I was a little unclear on the language. You'd said a special increase of $0.005 here this quarter and next quarter. How should we think about that? Is that something that's going to be that a discretionary increase we'll get and you'll just make that decision every quarter, or is this something that you can continue at this higher level of quarterly increases?

Yes, I think the way to think about is, if we had just increased it by $0.01 for the quarter, we'd have been at $0.645, and we're trying to get rid of the $0.005 just to make it easy for us and for investors. And so we think good round numbers is good. It's part of our simplification project.

I appreciate that. Okay. So special but -- okay...

[indiscernible] reset to distribution is $0.65 and that's where it's going to be until the next increase.

Got it. That's fine. And then last one for me is just there's another MLP out there that's talking about doing ethane export, and realizing this is Marcellus and that's kind of challenged in terms of what you do with ethane. But is it something you'd ever consider doing along the Gulf Coast?

We'll consider anything if we can make money at it.

Ted, I think one of the things that we think about in the Gulf Coast is that, of course, ethane supplies there -- petrochemicals are going to build new assets where the supply is. Why spend the extra money to export some place else? And that's what we're seeing the petrochemicals do. If you look at kind of the numbers that we've been hearing about for theoretical ethane export, it's kind of twice the cost for somebody to move it by pipe, by our pipe, down to the Gulf Coast. So we think we've got a better solution. But as Jim said, if somebody is willing to pay the price to have us construct an export facility and enter into a long-term contract to provide the right returns, that's something we'll consider.

You've got to remember who are some of our key customers. Our key customers are the U.S. petrochemicals, and that's who were primarily focused on serving. It's very expensive to export ethane. I'd rather some of those guys come build crackers in the U.S.

Understood. I guess maybe thinking about the -- you're bullish on the propane export market, though, you just feel like it's more limited export market for ethane. Is that also what you're coming at -- down at?

There's a lot of propane shifts. There's not any ethane shifts.

Yes, yes.

Remember, ethane, if it's going to be moved by ship, it's going to be at much lower temperature, it is more expensive, it's just more difficult.

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

I guess, just on -- first, on the West storage at Belvieu, kind of bringing it on back online next month, it sounds like. Can you just provide maybe a little bit more color on what, if any, kind of material constraints this may have caused for you. I'm just trying to quantify what type of impact bringing it back online may have?

I'm probably going to turn this over to Rudy at a point, but we've 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. What I think this brings back is a heck of a lot more flexibility and more capability to store. Rudy?

Yes, that's correct, Jim. We've got a couple of customers that we don't serve in a traditional manner because of the West storage event. But we'll bring them back on before the end of this month's out. But as Jim said, it's just going to give us a lot more flexibility and some more storage capacity.

And Rudy, some redundancy?

Absolutely, some redundancy, absolutely. Just more flexibility and some -- the West wells are fairly deep and that gives us a lot of pressure. That keeps the petrochems happy when we're giving them a lot of pressure.

And what we've done in the course of this rebuild is we're going to have pipeline systems that, if we ever had any, then again, there will be absolutely 0 interruptions. So we've modified how we are putting our pipeline systems back in place around Mont Belvieu.

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

In terms of our ethane pipeline?

Yes.

The products pipeline in PADD II?

You're 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 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're talking about is -- and we -- this thing has not grown legs as fast as we would have liked it to. But you're talking about being able to move refined products out of the Midwestern refineries back down the system, and we're still working that. But frankly, so far it hasn't grown legs.

Your next question comes from the line of John Edwards of Crédit Suisse. John Edwards - Crédit Suisse AG, Research Division: Yes, I'm just curious, with all the construction projects, what kind of cost escalation are you seeing going on right now?

We'll turn it over to Leonard, but just in general, our projects will be coming in on or under budget and we think it's because Leonard's figured out how to gain the system. But Leonard?

I have been accused of sandbagging, but it's my position that we're just good. Actually, for's [ph] labor cost has 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 activity.

And John, I think Mike mentioned that we had $1.7 billion worth of assets that have gone into service for the first 9 months of this year. And those have come in, on average, about 4.5% under budget. So again, doing a great job in managing the cost. John Edwards - Crédit Suisse AG, Research Division: Yes, that's great. And you're 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 preference because they know that we'll have the work for them. A good example is we've had one set of contractors at Mont Belvieu building fracs for the last 4 years, and they like that stability. John Edwards - Crédit Suisse AG, Research Division: All right, that's helpful. And then just your thoughts as far as natural gas liquids prices as a percentage of crude over the next year, what -- how do you think that will play out? I mean, it's been, as you know, below 40%, just recently gone up to around 50%. What are you thinking on that?

You want to take it?

Yes, I'll take it. They've come up a little bit, so that number is slightly better than 40% today. Ethane is probably going to be what drives it. So, this is Tony -- but you're not going to see big, big jumps in it, I don't believe.

One of the problems is you're 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'm not sure anybody knows at this point. John Edwards - Crédit Suisse AG, Research Division: Okay. And then just following on Ted's question. So for next year, since you got everything evened up here, we should think about $0.01 per quarter per unit increase just going forward, nice and simple?

Good try, John. It sounds logical, but we've never given a full forecast for distribution growth. John Edwards - Crédit Suisse AG, Research Division: Well, I have to try.

I know. John Edwards - Crédit Suisse AG, Research Division: Okay. Just -- and on the Seaway, and the press release said that the equity income was up $18 million per se [ph]. What was actually the number on that?

On the absolute dollar amount? John Edwards - Crédit Suisse AG, Research Division: Yes, the absolute dollar number. I just didn't have a chance to go back and look. I thought you might have it handy.

John, Randy here. It looks like it's -- the absolute number would be $16.5 million.

[indiscernible] reverse it. John Edwards - Crédit Suisse AG, Research Division: Yes. Now, I mean, as you bring the additional capacity on, are you expecting that to go up sizably? Or how does that -- how does those contract terms work, I guess?

Well, it's based on volumes, obviously. If we're flowing something less than 150,000 barrels a day, and we've got the ability with the looping and the expansion to take it to 850,000, we're not going to spend that money unless we expect to see bigger returns. So I think that's... John Edwards - Crédit Suisse AG, Research Division: Sure. Is the relationship going to be similar in terms of, say, amount per barrel? That's what I'm trying to get to.

I'm confused, John, what you're asking. John Edwards - Crédit Suisse AG, Research Division: Just -- well, I mean you could back in to sort of what the dollar per barrel shipping rate was based on this. I'm just wondering, is it reasonable to assume it's going to be a similar rate going forward?

Yes, it ought to be given the mix.

Just depends on what the mix is between light and heavy. John Edwards - Crédit Suisse AG, Research Division: So I mean, it's safe to assume a linear relationship there?

I think you guys ought to look at that [indiscernible] not only [indiscernible]...

This is Randy. I'll call you back and follow up with you, okay? John Edwards - Crédit Suisse AG, Research Division: Okay, great. All right. And just the last thing, maybe I missed it. Is the propane export facility is up -- is that up and running now?

You mean the expansion... John Edwards - Crédit Suisse AG, Research Division: The expansion, yes. Sorry, the expansion.

We're looking, hopefully, in January.

[Operator Instructions] Your next question comes from the line of Michael Blum of Wells Fargo.

Just one quick question for me, and 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 for -- in terms of opportunities. I'm 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.

Would we look at one, Michael?

Yes.

I mean, I don't want to speak for Enterprise. Speak for me, I hope not. We got a bunch of customers that I think could be a little bit irritated at us. So, no.

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

So over the past, call it, 6 quarters, you had kind of way -- I would call, way in excess of your coverage ratio of what you kind of need to run your business comfortably. Now as we transition here into a lower NGL price environment, and then earlier, you said you're transitioning to kind of 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?

Well, Bernie, we just announced an increase in the rate of growth in our distribution, so we've kind of taken that into consideration. And if you look at our distribution coverage this quarter, it's kind of 1.3x. We've talked about all of the capital we've got to spend the remainder this year and next year, and frankly, through 2015, and we continue to find ways to develop more projects. So as we've talked about in the past, our ability to retain some of this cash flows for reinvestment in those projects reduces the capital churn that we'd 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're ever going to see us at a point where we're kind of one-time distribution coverage. And if anything, I think you see more MLT's being like us and retaining cash flow because, frankly, it makes financial sense.

Understood. Okay. And then change gears a little bit. If you think -- thinking about ATEX as it comes online, obviously, it's going to -- I think the tariff is around $0.15 on your contracted capacity, is that correct?

Some $0.14, $0.15, something like that.

It seems like, with the amount of ethane that's expected to come from the Marcellus, that you're kind of going to shift from a situation where the marginal barrel of ethane comes from the Northeast instead of the Rockies. And I was just really kind of wondering your thoughts about 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.

Yes, I think what'll flow into Marcellus until you see ethylene plant newbuilds, I think what we have gotten subscribed is what will flow because those are demand fees and that's 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 got probably a $0.20, $0.22 hurdle before the next incremental barrel flows, and there's got to be an appetite for that incremental barrel.

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

You mean are we going to reduce our tariff?

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

No, we've been public on what we got in that. I think we peak at about 135,000, 140,000 barrels a day. We start out at about 75,000 barrels a day. No, I don't think you can -- I don't see any incentive for us to try to use our variable economics to increase -- close down that pipeline. I mean, we've got a lot of production in the Yoakum and up in the Rockies, so I don't see that.

Okay. So -- and it's 190,000 to 200,000 barrel-a-day pipeline, so there's going to be...

Only if we expand the capacity.

Okay, okay. So it's going to come on at more like that 150,000 range, is that...

I think what it's going to come on at is about 75,000 to 80,000, ramping up to somewhere in the neighborhood on our subscriptions of 135,000, 140,000, or in that ballpark, in 5 years. Yes, and that's over a 5-year period. So in other words, you got new ethylene plants by the time we're at the peak on the -- on our ramp.

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

Any update on the potential ethane header system?

We're still working it and we're getting closer. And I'm a Dow retiree, so I understand how those guys work. And they're pretty methodical, but I think -- ultimately, I think that system grows legs. And frankly, we'll 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're trying to do is get over the hurdle that we have kind of targeted, and it's not outstanding, but it's accretive and we think there's a lot of upside on that.

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 1:00 p.m. Eastern Standard Time today through 11:59 p.m. Eastern Standard Time on Thursday, November 8, 2012. 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. Thank you. This concludes today's conference call. You may now disconnect.

Thank you, and everyone, have a good day. Thank you for joining us.