Enterprise Products Partners LP (EPD) 2013 Q2 法說會逐字稿

Good morning, my name is Jennifer and I will be your conference operator today. At this time, I would like to welcome everyone to the Enterprise Products Partners second-quarter 2013 earnings 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.

And Mr. Burkhalter, you may begin your conference.

Thank you, Jennifer, and good morning, everyone. Welcome to the Enterprise Products Partners conference call to discuss results for the second quarter. Our speakers today will be Mike Creel, CEO of Enterprise's General Partner; followed by Jim Teague, 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 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, we can give no assurance that such expectations will prove to be correct.

Please refer to our latest filings with the Securities and Exchange Commission for a list of factors that may cause actual results to differ materially from those in the forward-looking statements made during this call.

With that, I'll turn the call over to Mike.

Thanks, Randy. We reported solid results this quarter, with four of our five business segments posting improved results compared to the second quarter of last year. Record NGL and crude oil transportation volumes and contributions from new assets put into service more than offset the impact of lower NGL commodity prices in our natural gas processing business, leading to an 11% increase in gross operating margin for the quarter.

These increases were primarily driven by growth in NGL and crude oil production in the Eagle Ford Shale, higher crude oil volumes flowing on Seaway, and increased propane loadings at our export facility.

Net income attributable to limited partners was $553 million. And earnings per unit on a fully diluted basis were $0.60 for the second quarter of 2013. This compares with net income of $566 million and earnings per unit of $0.64 for the second quarter of 2012. Included in net income this quarter was approximately $46 million, or $0.05 per unit, of non-cash charges related to asset impairments; non-cash expense for changes to the Texas margin tax; and a loss related to the sale of assets.

Net income for the second quarter of last year included non-cash gains of $45 million or $0.05 per unit related to the sale of assets and insurance recoveries.

Distributable cash flow was $925 million this quarter compared with $876 million in the second quarter of 2012. Included in distributable cash flow were proceeds from asset sales and insurance recoveries of $69 million this quarter, and $159 million in the second quarter of last year. After adjusting for these nonrecurring items, distributable cash flow increased 19% over the second quarter of 2012. Distributable cash flow generated by our predominantly fee-based businesses allowed us to increase the quarterly cash distribution to $0.68 per unit with respect to the second quarter of 2013. This is our 36th consecutive quarterly increase in our cash distribution per unit, and is 7.1% higher than the cash distribution paid with respect to the second quarter of 2012.

Distributable cash flow provided 1.5 times coverage of the cash distribution for the second quarter of 2013. And after adjusting for the proceeds from sales, it would've provided 1.4 times coverage. We retained $318 million of distributable cash flow this quarter, and $621 million through the first six months of the year. We also raised $214 million through our at-the-market, or ATM, program; and $135 million from our distribution reinvestment plan, or DRIP, and our employee unit purchase plan in the first half of the year.

When added to the $487 million of proceeds we received from our equity offer in February, we have raised or retained approximately $1.5 billion of cash this year that is available to reinvest in growth capital projects, reduce our debt, and decrease our reliance on the capital markets.

Absent an acquisition, we expect our ATM and distribution reinvestment plan will be sufficient for our remaining equity needs for 2013, and we do not otherwise expect to be in the public equity markets.

The NGL Pipelines & Services segment reported gross operating margin of $545 million for the quarter, slightly down from the $566 million for the second quarter of 2012. Our natural gas processing and related NGL marketing business had a $75 million decrease in gross operating margin compared to the second quarter of last year. Like last quarter, we had lower processing margins across all of our processing facilities and reduced ethane extraction. Partially offsetting the impact of lower natural gas processing margins was an increase in gross operating margin from fee-based processing and NGL marketing.

Higher sales volumes, which include propane sold for export, more than offset lower margins in our marketing business. Our fee-based natural gas processing volumes increased to 4.6 billion cubic feet per day this quarter, from 4.2 Bcf per day in the second quarter of last year. Fee-based natural gas processing volumes rose 40%, and equity NGL production from our South Texas processing plants increased 460% to 40,000 barrels per day as a result of production growth in the Eagle Ford Shale.

The three natural gas processing trains at our Yoakam facility continues to perform above expectations. The increase in fee-based processing and equity NGL production from the South Texas plants more than offset a decline in fee-based processing and equity NGL production from our Rocky Mountain plants, due to lower production and reduced recoveries of ethane.

Gross operating margin for our NGL pipelines and storage business increased 19% to $188 million this quarter, from $158 million for the second quarter of last year. Our South Texas NGL pipeline system contributed $21 million to this increase, primarily due to a 125,000 barrels a day increase in transportation volumes on increased Eagle Ford Shale production. Our LPG export facility and related Channel Pipeline reported a $12 million increase in gross operating margin on a 202,000 barrel per day increase in propane volumes.

We increased the refrigeration capacity of our export facility in March of 2013, and are now loading an average of 7.5 million barrels a month of propane, compared to 3.5 million barrels a month before the expansion. NGL pipeline transportation volumes were a record 2.7 million barrels per day this quarter.

Our NGL fractionation business reported a gross operating margin of $93 million this quarter, compared to $69 million in the second quarter of 2012. This 35% increase was primarily due to higher average fractionation fees and increased volumes from our Mont Belvieu fractionators. Our sixth NGL fractionator at Mont Belvieu began service in October of 2012. And fracs 7 and 8 are scheduled to begin operations in the fourth quarter of this year.

Gross operating margin from the Onshore Natural Gas Pipelines & Services segment was $198 million this quarter, $22 million higher than the second quarter of last year, primarily due to higher firm capacity revenues in volumes from our Texas intrastate pipeline system, which benefited from increased production from the Eagle Ford Shale.

Our Onshore Crude Oil Pipelines & Services segment reported strong results again this quarter, with gross operating margin of $197 million compared with $96 million for the second quarter of 2012. Total onshore crude oil pipeline volumes were a record 1.1 million barrels per day this quarter, up 58% from 725,000 barrels a day in the second quarter of 2012.

Our South Texas crude oil pipeline system, which includes the new 24-inch pipeline from Lyssy to Sealy that began service last June; and the Seaway pipeline, which was reversed in June of 2012 and fully powered up during the first quarter of this year, were responsible for 83% of the increase in gross operating margin.

Enterprise and Plains All American announced the formation of a 50-50 crude oil pipeline joint venture in the Eagle Ford Shale in the third quarter of 2012. A portion of this system is in service now, and we realized equity income from this joint venture in the second quarter of this year. The remaining part of the system is scheduled to be placed in service during the third quarter.

Our Petrochemical & Refined Products and Services segment reported gross operating margin of $163 million this quarter, compared to $157 million in the second quarter of 2012.

Refined product pipelines and services business reported a $31 million increase in gross operating margin, primarily due to higher transportation fees on our TE Products pipeline. Included in these fees is a $24 million that is recognized in connection with the settlement of a rate case. We also had higher intrastate petrochemical and refined products transportation volumes. Total pipeline transportation volumes for the business were 555,000 barrels a day in the second quarter, compared to 482,000 barrels a day for the second quarter of last year.

Partially offsetting this increase were decreases in gross operating margin from our propylene fractionation, octane enhancement, and high purity isobutylene business. The propylene fractionation business was impacted by lower sales margins, and the octane enhancement facility had an unplanned outage for a catalyst change-out and maintenance. The facility was down 11 production days during the second quarter and 10 production days in July. We estimate lost gross operating margin was approximately $9 million in the second quarter, and will be about $11 million for July.

In addition to the strong operating performance this quarter, we also completed construction and began operations of approximately $700 million of growth capital projects. Included in these projects is the expansion of our propylene splitter at Mont Belvieu; the completion of our NGL pipelines from Yoakam to Alvin, Texas; and an extension of our West Texas crude oil pipeline system. In the first six months of this year, we've placed $1.1 billion of capital projects in service. And we have another $1.5 billion of projects that we expect to be completed in the second half of this year.

These projects include the Texas Express pipeline and gathering system, and the seventh and eighth fractionators at Mont Belvieu, a new pipeline connecting Jones Creek to our ECHO crude oil terminal, and the joint venture crude oil pipeline with Plains that I mentioned earlier.

We are pleased with the solid results generated by our businesses this quarter, especially given the weak NGL prices that affected our processing and marketing margins. We do not expect NGL prices, especially ethane, to improve significantly near-term, given the continued increase in natural gas production from shale plays. This growth in natural gas production and NGL supplies, however, will create additional investment opportunities for our partnership, as Jim will discuss in a few moments.

While new supplies have outpaced demand for some parts of the NGL barrel, the demand side in the US is responding with large projects like new world-scale ethylene crackers and new PDH facilities. In the meantime, increased international demand for domestic LPGs is helping balance the market through expanded LPG exports. Although this transition period has proven to be challenging for some midstream operators, we feel good about our ability to deliver and continue to grow, given our predominantly fee-based diversified portfolio of assets, a solid balance sheet, strong liquidity, and significant growth opportunities.

I'm confident that our team of dedicated employees will continue to execute our growth plans and find new opportunities. And we continue to be excited about the prospects available to Enterprise, and we look forward to working for our investors to create even more value.

And with that, I will turn the call over to Jim.

Thank you, Mike. To put Mike's comments in a little bit of perspective, think about two years ago natural gas was $4.25; oil prices were $100; ethane was $0.75 a gallon; propane was $1.50; and our processing margins were anywhere from $0.80 to $1. And our gross operating margin was just north of $900 million.

Last year at this time, oil prices were $90; natural gas had fallen below $3; ethane had lost $0.35, propane $0.50. And our processing margins were $0.60 a gallon, down from close to $1. And we were just over $1 billion in gross operating margin.

Today you've got ethane trading at gas value, virtually; propane at about $0.95; and processing margins are in the neighborhood of $0.35 a gallon. We come in at something just north of $1.1 billion in gross operating margin. Earnings continue to show the strengths of diversification.

And when I say diversification, I mean the new assets we're bringing on, but also mean how we have changed our contracting strategy on existing assets. The strengths of that diversification can weather that feared processing margin storm so many of you worry about. And as Mike mentioned, over the next couple of quarters we're going to be bringing a large number of new assets into service across all of our business lines.

If you can call $3.50 to $4.00 stable, natural gas has stabilized from a downward spiral. US oil prices have been pretty stable, in and around $100. But NGL prices have really suffered, as demand has not been able to keep up with the rapidly growing supplies from the shale plays.

Led by ethane falling apart, ethane is now firmly in the excess category; and trading, as I've said, at its natural gas values. Processing margins are around that $0.35, and Enterprise's processing income is on the receiving end of that slump. However, petrochemicals finally get it. They understand the size of the shale resource and they know that they have to participate in order to be competitive.

And, as Mike said, the US is witnessing a large petrochemical expansion along the Gulf Coast, most of it focused on low-cost ethane. I started to say that they had the largest petrochemical expansion in history, but I haven't had a chance to compare that to the second half of the 1980s.

At Enterprise, we've said before, we are connected to every major ethylene plant in the US. We understand their needs. And that's why we're building a dedicated US Gulf Coast ethane header to meet their growing needs. Other parts of the barrel have also suffered, and I think sometimes in sympathy to ethane, but generally because of their ability to compete with other hydrocarbons, including their ability to be exported in some form or fashion. These new NGLs are making their way into the domestic and global markets, and we're participating in that.

We've seen propane spreads between the Gulf Coast and northwest Europe almost double over the last two years. We also recently completed agreements, besides waterborne exports, we completed agreements that will enable us to deliver substantial amounts of natural gasoline from Mont Belvieu to customers in the Chicago area; these volumes ultimately bound for the diluent-hungry markets in Western Canada.

The flip side of this wave of NGLs is the investment opportunities it has created for Enterprise. Mike mentioned a lot of the pipelines that we are bringing on. That's about 800,000 barrels a day of new capacity between MAPL, Texas Express, Front Range, ATEX, and Aegis, that are all underwritten by fixed-fee contracts.

We currently have an open season underway to gauge shipper interest in modifying ATEX to also ship propane. Mike mentioned fracs 7 and 8, and to put it in this context, in just three years we will have added over 400,000 barrels a day of fractionation capacity at Mont Belvieu. And when these last two trains are online, we will have over 1 million barrels a day, or right at 1 million barrels a day, of fractionation capacity as a Company. And all of our contracts are fixed-fee contracts.

Mike mentioned Yoakum, which might appreciate. I don't know that Yoakum is the largest plant in terms of gas throughput. But we do believe it's the largest NGL-producing processing complex, in that we are producing somewhere between 100,000 and 135,000 barrels a day.

And last but not least, the LPG export facility is performing beyond our expectations. We are contracted through 2015, and we have contracts that extend out to 2022. We're also looking at another expansion of that dock that's low cost and gets us some pretty immediate capacity.

In crude oil, as Mike mentioned, our gross operating margin is up approximately $100 million compared to last year this time. But it's down somewhat, I think, compared to last quarter, primarily the result of narrowing WTI to LLS spreads. I'm not one that believes in the sustainability of wide spreads. And, realistically, we can't expect the large spreads we saw in the first quarter to continue as the new north-to-south pipeline expansions, including our own, come online. So we expect this windfall has about run its course.

Virtually all of North America's crude oil growth is coming from places that have been proved up in recent years, like Western Canada, the Bakken, the Permian, Eagle Ford, and the Gulf of Mexico. Between the soon-to-be-looped Seaway pipeline, our assets in the Permian, our Eagle Ford assets, and our Gulf of Mexico crude oil pipelines, including the Lucius project we have underway, we're pretty well situated to touch most if not all of these new supplies.

Incidentally, we are not sure these producers are through. We are also watching activities in new plays like the Niobrara, and the Mancos in the San Juan. With significant inland barrels of various crude slates now becoming available to Gulf Coast refiners, we are focused on building downstream crude oil assets through our ECHO and Houston Ship Channel expansions. We really believe that our ECHO terminal and its supporting distribution network that we're building -- we believe that's going to play a strategic role in linking these new supplies to the Gulf Coast refining complex.

Our crude oil position -- summarizing that position, Seaway is fully reversed, and we don't talk about it -- and being looped -- and what we don't talk about a lot is that loop includes an extension to the Beaumont/Port Arthur area. Our Eagle Ford crude assets are in service or nearing completion, and then our ECHO buildout is underway. We remain excited about our progress in crude oil. We are never satisfied, but we're excited, and we're excited about its importance to us.

We recently announced plans to build refined products export facilities in and around what we call our Southern Complex on the Gulf Coast. The US refining industry is running at high utilization rates, upgrading and expanding, and has become significant exporter of refined products. With this project, we will build capacity to export refined products by upgrading our refined products pipeline that connects to 12 Gulf Coast refineries, and connecting it with export facilities at both Beaumont and the Houston Ship Channel.

This project, part of which will be up and running in 2014, is another example of existing assets being repurposed and expanded as industry conditions change. Our Eagle Ford buildout for natural gas, NGL, and crude is just about complete with most of the assets currently in service. In NGLs, we are nearing the completion of the major buildout we started three years ago, with most of our large transportation and fractionation initiatives coming on over the next few months.

Oil continues to be a growing part of our business. And our natural gas assets, situated throughout the Texas and Louisiana Gulf Coast, are seeing growth in both supply and demand, and are perfectly situated to serve some very large demand markets that will be constructed over the next several years. In NGLs, we've always had a strong franchise. And we say that we serve both the supply and demand side of the equation. We're going to also concentrate on both the supply and demand side of the equation for other parts of our businesses.

For petrochemicals, this demand side focus has been confirmed by the Aegis pipeline and our PDH plant. In refined products, our Southern Complex export project is another validation of our determination to be on the demand side of the equation for refined products. And for crude, our buildout of the ECHO terminal and its downstream pipelines to support the very large Gulf Coast refining industry is an example of focus on the demand side of the equation.

As the industry continues its transition from a state of chronic shortage of hydrocarbons that required waterborne imports of natural gas, LPG, crude oil, and refined products; to the significant growth of inland, domestically produced hydrocarbons, we feel like we're pretty well situated to capitalize on that.

And with that, I'll turn it to Randy.

Thank you, Jim. A bit of housekeeping before we get started. Some general business media customarily overemphasize either changes in our revenues or changes in our operating expenses in isolation. This is not necessarily a good use of time or reporting when evaluating a midstream energy company or a utility, for that matter. These income statement items are influenced in large part by changes in commodity prices from one quarter to the next. In general, higher commodity prices result in an increase in our revenues attributable to the sale of NGLs, natural gas, crude oil, petrochemicals, and refined products.

At the same time, however, higher commodity prices will also increase the associated cost of sales as purchase costs rise. Therefore, an increase or decrease in revenues due to an increase or decrease in commodity prices may not generate a corollary increase or decrease in gross operating margin or in distributable cash flow, because cost of goods sold would also increase or decrease with commodity prices. This is why we believe gross operating margin is a better performance-based financial measure than isolating on either revenues or cost of goods sold, and why our earnings press release and this conference call focus on gross operating margin.

So, pardon me for preaching to the choir, to those investors and security analysts who follow us closely.

Now, interest expense increased $200 million in the quarter of 2013 from $187 million recorded in the second quarter of 2012. Our average debt balance for the second quarter of 2013 increased $2.4 billion from same quarter last year. Our weighted average cost of debt decreased to 5.4% at June 30 compared to 5.8% a year ago.

The provision for income taxes increased to $20 million this quarter from $9 million for the second quarter of 2012, primarily due to recording a deferred tax expense and a related liability with respect to certain changes to the Texas margin tax that were enacted in June 2013.

Our capital spending was over $1 billion this quarter, including approximately $990 million spent on growth capital. We expect to invest an additional $2.4 billion in growth capital expenditures through the remainder of 2013. Total growth capital expenditures for 2013 are expected to be approximately $4.2 billion.

Sustaining capital expenditures were $75 million this quarter compared to $90 million for the second quarter of 2012. And they were $132 million through the first six months of this year compared to $180 million for the first six months of 2012. We still expect to spend approximately $350 million in sustaining capital expenditures this year, but we will have to hurry.

Adjusted EBITDA for the 12 months ended June 30 was $4.5 billion. Our consolidated leverage ratio of debt principal to adjusted EBITDA was 3.6 times for the 12 months ended June 30, 2013. And this adjusts debt for the 50% equity treatment of the hybrid securities.

The average life of our debt is 14 years, using the first call date for the hybrids; 18.5 years if you use final maturity. And, as I said, our effective average cost of debt is 5.4%.

We raised approximately $280 million through our ATM, distribution reinvestment plan and employee unit purchase plan programs in the second quarter, which includes $25 million invested by privately-held affiliates of Enterprise Products Company, through the dividend reinvestment plan or distribution reinvestment plan.

EPCO expects to purchase another $25 million of Enterprise common units through the distribution reinvestment plan for the distribution to be paid on August 7, which would bring total purchases this year to $75 million. As you remember, earlier this year they expressed an interest to purchase at least $100 million of Enterprise common units in 2013.

On the liquidity front, in June we had great support from our bank group and increased our liquidity by refinancing and extending the maturity dates of commitments under our multi-year bank credit facilities. In our $3.5 billion multi-year credit facility, we extended the maturity date from September 2016 to June 2018. And we also added a new $1 billion 364-day credit facility. And the additional liquidity will provide us more flexibility in funding our capital investments.

Finally, at June 30, we had consolidated liquidity of approximately $4.5 billion, including availability under our credit facilities and unrestricted cash.

And with that, Randy, I think we're ready for questions.

Okay, Jennifer, we're ready to take questions now from our audience.

(Operator Instructions). Darren Horowitz, Raymond James.

Morning, guys. Jim, I've got a couple questions for you around some comments that you made with regard to how strategic ECHO and the Ship Channel expansions could be, regarding export of refined product. As you guys talk with customers, whether or not it's about moving crude or condensate out of South Texas, West Texas, and moving those barrels East, how big do you think ECHO could be in capacity? And, more importantly, it would seem like you might need greater distribution outlets into Texas City/Morgan's Point/Beaumont, and that doesn't even mention Galena Park, and so your thoughts there would be appreciated.

Yes, I think what we've said is the property we own at ECHO, I think we're seeing about 7 million barrels of tankage that we could store. Is that right, Leonard? In that neighborhood. And the project we announced, Darren, would in fact tie ECHO into all the Texas City refineries; all the refineries in the Houston area, along the Ship Channel; and then through the Seaway lateral over to Nederland, into that refining complex.

So, we're driven by -- everything has always been waterborne in, that's the way the system is designed. As we brought on Seaway and the Eagle Ford, what we've learned is trying to schedule of barrel of crude from point A to point B is typically of three-bank pool shot. We wanted more direct access. We feel like that distribution will be supportive of our storage.

Does that answer it?

Yes, it does. And then the second part to that question is more specifically focused on Morgan's Point. You've talked about moving barrels across Morgan's Point up the Mississippi River. But I'm wondering about the opportunity at that location for either additional gasoline or gas oil exports, or the opportunity for a larger scale condensate splitter where you could start exporting light naphtha across the dock.

Yes, what we're doing in terms of Morgan's Point, as well as Beaumont -- a lot of people don't appreciate -- we had a ship dock in Beaumont that came with our TEPPCO acquisition. We've got a lot of storage; we have a facility at Morgan's Point. This isn't a high-dollar capital project.

The way it all started is with our TE Products pipeline that goes from the Ship Channel over to the Beaumont area, always flowed west to east as a feeder for the TE Products pipeline that went up to the Midwest. We converted that pipeline to be bi-directional and we saw business jump pretty dramatically.

Then we looked at the ship dock we had in Beaumont. We looked at our Ship Channel facilities there at Morgan's Point, and we figured out that we were tied to about 12 refineries -- Kate? Something in that neighborhood. So it just seemed like a natural if we tie all this together and go into business of exporting refined products. So that's what we're doing.

Okay. And then last question for me, Jim, more of a big-picture question around your commentary in terms of looking at expanding that LPG dock capacity. Within the overall context of the market, as you're talking with customers and you're looking at current spreads, and you are also considering how much plant capacity by the industry has already been announced, how much more incremental capacity do you think could be added before it starts to actually have an impact between that Gulf Coast and Northwest Europe spread?

You're asking the eternal question I asked myself constantly. I don't have a clue, Darren. I know this -- we're being pretty disciplined with what we're doing. We are selling as much as we can, as far out as we can. And I think what we're benefiting from is we've been in this business 30 years, or something like that. We know what we're doing.

Our customers have a high level of confidence in us. And unlike a lot of other people that are trying to enter the business, we know how to load a ship. I don't know the answer to your question. I know this -- the expansion we have that we're going to be taking a look at is not high-dollar; it's fairly immediate. And what we've learned is if you can give business to these guys over the next two years, and use that, you can leverage that into multi-year contracts. So that's what we're doing.

Thanks, Jim. I appreciate it.

Brian Zarahn, Barclays.

Good morning. In the NGL pipeline segment, can you talk a little bit about the change in gross operating margin versus the first quarter of 2013? Volumes were up versus the first quarter. And I know seasonality plays a role, but volumes were up. Propane export facility was fully in service but the margin was down. Can you talk a little about some of the moving parts?

Brian, this is Randy Fowler. Without getting too granular on it, I think probably one of the main features in there is just, if you would, propane winter heating load in the first quarter was really strong. And so you probably saw that on Mid-America, you saw it on Dixie, and probably saw it on the Texas Eastern Products Pipeline also. I would say that would be the biggest deltas there.

Okay. And then on Front Range and Texas Express, can you remind us for the volume commitments -- do they kick in immediately when the project is at startup, or is there a ramp? Talk about the contracted capacity.

Yes, Brian, there's always a ramp. I don't know what it is on Front Range. On Texas Express -- where does it start? About 80,000 a day? In that neighborhood. What is it on Front Range, do you know? We'll get it for you. But, yes, there's always a ramp.

Okay.

A lot of people, Brian, look at that and they say, oh my God, we're going to be awash in NGLs. Because they assume that if it's a 300,000 barrel a day pipeline, it's full day-one. It's never full day-one.

Can you give sort of a rough time period of when the volume commitments hit that 90% or so level?

Well, I don't know that we hit 90%. We hit a level that supported doing the project, and I'd guess it's probably -- Russ? -- 3- to 4-year ramp on those, typically on these things?

Typically three years, yes.

Okay. I know you're in the middle of open season on ATEX, but can you give any color on the propane service?

We got some people interested, and some aren't. I don't know what odds I'd give this thing. People get enamored with their wintertime profits, and then they suffer in the summertime. And this isn't a project where we can be seasonal on. So, I think WES is right in the middle of negotiating and talking to some of these people. And, frankly, I don't know where it's going to come out.

I think over the long haul -- I think it's needed, given what I read -- what we see in the Marcellus. So, it could be that it doesn't happen this time but it happens later. Ultimately, I think there's a need.

And last one for me on Seaway. Can you mention how many -- what the volumes were in the second quarter? And then the approximate mix of light and heavy barrels?

Yes, I bet you we average, Randy, around 300. Yes, up in the neighborhood. We've been a size -- where's Robbie? We've been a size 400. We've touched 400 here recently.

Been around 300.

And -- where's Terry? Isn't that right? And what's your mix? Roughly 30% heavy?

Correct.

Thanks, Jim.

Ross Payne, Wells Fargo.

Good morning, guys. I was just curious what kind of EBITDA multiple we can assume for these expansion programs. If you can just give us a wide range, that would be appreciated.

You just keep trying, don't you, Ross? (laughter) It depends on volume, but as Jim said, we've got the commitments to get a rate of return that we're very comfortable with, and there's plenty of upside.

Nice, Mike. Thank you. I appreciate that. Also, can you talk about what percentage of the business now is fee-based, or what your expectation is as we get towards the end of the year? Thanks.

Yes, Ross, this is Randy. We really don't come in and take a look at that from a quarter-to-quarter standpoint. Again, directionally this year, the expectation was for where we were last year at -- we were around 73%, 74%, 75%. And directionally, we were thinking we would head towards 80% this year. And I think that's -- if you come in and you look at the results the first half of the year, I think that's what you're seeing.

Again, if we wind up with a lower percent of fee-based gross operating margin, that's actually a good thing.

Okay, great. That's good color. In terms of the EBITDA multiple, can we assume that it's something close to historical norms? Or maybe even a little better, given the robustness of fundamentals these days?

Yes, Ross, I think it's fair for regulated pipelines, if you are comparing apples to apples. Another thing to consider is that, as Jim and Russ said, these tend to have a ramp-up period. So once they go into service you should see some expansion of cash flows off of them for the first couple of years, at least.

Okay, great. Thanks, guys.

Brad Olsen, Tudor, Pickering.

Hey, good morning, everybody. Recently we've seen some moves in the crude oil market that I think were unexpected to a lot of industry observers and participants, with an onshore rally and a pretty steady contango moving into sharp backwardation. How do those trends change your outlook or maybe some of the opportunities you're presented with on the crude side of your business?

I'm not sure they change those a heck of a lot.

Yes, Brad, in all of our businesses we, from time to time, see contango, and we see backwardation. Whatever the opportunity is, we try to capitalize on it.

Right. I guess I was thinking that we've had basically five years of uninterrupted contango, at least around WTI, which has obviously been very good for storage, as well as a discount between WTI and global crudes. And given the fact that WTI is trading around parity with the rest of the world for the first time in a few years, I don't know that there have been opportunities maybe to move more crude towards LLS on the Gulf Coast, and rallying or something along those lines.

I think maybe -- I'll try to answer it. I think maybe the pricing mechanism has changed down here a little bit and we're seeing more people wanting to sell on an LLS basis. So, it's affected us like that. In terms of storage, we're not keen to build storage on 5-year contracts in Cushing. We're keen to build storage on the Gulf Coast, and will look at 5-year contracts. So, it tells you where we're shifting our focus.

Okay, great. And on the NGL side of things, obviously the NGL -- or the ethane content in the Y-Grade arriving in Mont Belvieu is substantially lower than it has been in the past. Does having low ethane content flowing through your system -- does that cause any issues or present any opportunities in your fractionation business; or, potentially, even create opportunities around providing some kind ethane disposal solution?

There is a point at which, if the ethane content in the Y-Grade falls far enough, it could affect your throughput in your fractionators. We haven't gotten there yet. So, so far, it hasn't been an issue.

And with the start up of ATEX in early 2014, is there any expectation that we might swing into that scenario where the ethane content, or the value of ethane gets so low on the Gulf Coast, that you are effectively being forced to reject more than the system is really capable of rejecting?

I guess anything's possible. But I think what you're going to find -- you're selling at gas value now, virtually. So, as it goes below gas value, I think you will see people reject more if you bring more supply on. I guess that's just intuitive.

I guess my question was more focused on whether or not there's a limit to the amount of ethane that can practically be rejected into the gas stream.

I don't know the answer. I think if it gets bad enough, people get creative and leave more in.

And depends on location.

Yes, and it depends on location, and the type of contracts.

Okay, fair enough. And, finally, at the Analyst Day this year, it sounded -- and maybe this is just my interpretation -- but it sounded as though you guys were getting incrementally more open, or maybe more constructive on the state of the M&A market. Would you mind sharing some thoughts about maybe what you're seeing, or whether or not that's an accurate take on your attitude towards maybe doing something acquisitive?

Yes, I think that was probably a misinterpretation. I think what Jim said was that if there are acquisitions out there that make sense for us, then we're going to look at them. We haven't seen a whole lot just because of the way that they've been priced, the amount of competition. But there are perhaps opportunities for us in the future to find one-off deals that -- for an asset, a single asset that makes sense for us. A big acquisition of an existing company probably won't happen. That doesn't make a whole lot of sense.

Which doesn't say that we haven't looked.

Yes. We look at a lot of stuff.

And, Brad, I think what that also highlights is because we've got a great portfolio of growth opportunities with reasonable returns, we are not forced to go to the more expensive M&A market, and live off acquisitions.

Okay great. That's helpful. Thanks a lot for your time, guys.

(Operator Instructions). John Edwards, Credit Suisse.

Yes, good morning, everybody. If I could maybe ask Ross's question a different way -- are you seeing EBITDA multiples on new projects? Are you seeing them improve, stay the same, or maybe go down a little bit?

And, John, you're asking the same question, and you want a different answer?

(laughter) Well, the answer I got last time was no answer, so I thought maybe asking it that way would get a little insight there.

I don't think returns have changed materially over the years. As we said before, we see a lot of projects or a lot of opportunities that are available to us. And one of the challenges that we have is really sifting through those opportunities and trying to figure out which ones would make the most sense for us. So, I don't think that the returns on our projects are significantly different today than they were five years ago.

What you do see, obviously -- and we've always seen this -- is sometimes these projects take a few years to ramp up to full cash flows. And when we look at them, rarely do we have, for example, a pipeline that's contracted 100%. So we contract in a way where we have available capacity over and above what we've got commitments for. And so there's a lot of upside over and above the returns that we look at when we sanction a project.

Okay, fair enough. And then as far then as your cap spending run rate, are you still looking at roughly $4 billion a year? For modeling purposes, is that reasonable to assume?

Yes, it's probably not unreasonable, given where we've been for the last several years. Frankly, we wouldn't mind being at a point where we're down to $2.5 billion to $3 billion. It's just these pesky projects keep looking so good that we've been at the $4 billion run rate for a few years.

So you're not seeing any kind of slowdown in terms of opportunity.

I haven't seen any slowdown here in 10 years or more -- 15 years.

John, I think we said at the beginning of this year we had $7.5 billion worth of growth projects under construction. And as Mike said earlier, we put $1.1 billion into service. And I think we're sitting here today with about $7.5 billion worth of growth projects under construction. So, the guys are doing a great job with new projects. And when you just look at the projects that are approved, the carryover of those projects into 2014, we're probably already at growth CapEx of $3 billion.

Okay, that's really helpful. And then in terms of ethane rejection, what are you guys seeing on your system now?

It's hard to say exactly. I think as an industry -- where is Tony?

From the industry standpoint -- this is Tony -- we think it's somewhere north of 200,000 barrels a day. You see some larger numbers quoted. I struggle to get there. The other thing I'd like to add on ethane rejection is we perceive sometimes that there's going to be this wall that you're going to hit on ethane rejection as an industry. And that's just not the way it's going to -- it's not the way it happens when it happens today. It happens very, like Mike said, very regionally; happens back in the field in isolated places.

So, if we can get off the concept that we're going to hit this wall as an industry; that's just not what's going to happen.

And I think -- one follow-up on Brad Olsen's question earlier -- I think one of the things, and again on the ethane rejection -- we came out of a, if you would, fourth quarter-first quarter where before our propane dock opened up, where propane was probably the most advantaged feedstock in the slate. And you had less pull on ethane. Well, since the dock has come on, you've had ethane now resume the most profitable feedstock. And now, by our estimation, over 1 million barrels of day of pull. So I think one of the things that will impact that ethane rejection number is the strength of the demand on the downstream side.

And the reliability of the crackers to run.

Okay. And then as far as the dock expansion, what kind of volume are you contemplating? And then if you could remind us -- you said you're running full -- can you just remind us what that export volume number is?

The current rate is about 7.5 million barrels a month.

What are we talking about, 3 cargoes? Yes, 2 to 3 cargoes a month, potentially.

Okay. And then as far as expansion, what's the thought there?

Now, that is the expansion -- that would be the expansion.

Yes, we're doing that in 2014 now.

Yes.

2 to 3 cargoes would be the expansion, okay. And you're running about 7.5 million barrels a month right now?

Right.

Okay, great. All right, thank you very much. That's all I had.

Matt Phillips, Clarkson.

Morning, guys. Apologies if you already covered this, but is there an update on PDH 2? And what are you seeing with regard to space constraints down on Mont Belvieu? Do you have opportunities for NGL storage elsewhere on the Gulf that you could plop an asset like that down?

Say that again on storage, if you don't mind, Matt?

Are there -- elsewhere in the Gulf where you feel like you have access to NGL storage, and where you could put an asset like that?

Well, on the PDH, we're building it. We're pretty pleased.

He's talking about 2.

Oh, PDH 2? We've got people interested in it. Our guys are talking to them. I'm not going to say we're not going to do it, because I've got a propylene guy sitting next to me. But I'm not going to say we're going to do it. If we get the right contracts with the right customers with the right return, we will take a hard look at it.

Okay, thanks.

And what was your question on storage? I didn't --

Yes, sorry. Are you bumping up against any space constraints at Mont Belvieu? And do you have access to NGL storage elsewhere in the Gulf where you could put an asset like that?

Well, we have storage over in Louisiana, but nothing like what we got at Mont Belvieu. We got it in Arizona; we got it up in Kansas. But Mont Belvieu is kind of special. In my mind, I think storage is going to be in high demand in the future, and I think our earnings have upside.

Have we got additional capacity on the dome?

Yes, we've got -- we can wash more wells.

Go ahead.

Okay, thank you.

We've got gas storage in certain locations that we could convert to NGLs if we need that; for instance, in Wilson.

Okay, this is in Mont Belvieu?

It's South Texas.

South Texas, okay. Great, thank you.

TJ Schultz, RBC Capital Markets.

Hey, guys. Good morning. Just two quick ones. First on ATEX -- just construction update -- as we get closer to in-service, can you just discuss the progress on the repurposing of some of the product system and construction of the new pipe? Mainly just looking for the comfort level on in-service time for ATEX with the scope as it stands now.

I think we may be line filling before the end of the year.

Okay, great. Randy, the ATM -- you've obviously had success here. Should we expect you all to continue utilizing that lever? And can you tell me how much remaining capacity you have under the current ATM program?

From our standpoint, again, we're a little bit rookies at the ATM program compared to some of the other companies in the space. But what we have seen is we've liked the results of it. It seems like an effective program. After the $214 million that we issued in the second quarter -- Bryan, do you know what the remaining capacity is?

About $560 million.

Yes, so $560 million.

And we can always recharge it.

And to Mike's point, we can always come back in with another filing and top that back off when we need to.

Great, thanks.

We have no further questions at this time, and I will now turn the call back over to Mr. Burkhalter.

Thank you, Jennifer. At this time, if you would, would you give our listeners the replay information for our call? Thank you.

Absolutely. There will be an audio recording available after this call has ended. To listen to this recording, you may dial 1-800-585-8367 or 1-855-859-2056, and enter in the ID number 19880846. This recording will be available for replay until August 8, 2013, at midnight.

Thank you, Jennifer. And that concludes our call today. Thank you for joining us, and have a good day. Goodbye, now.

Thank you. This does conclude today's conference call, and you may now disconnect.