Enterprise Products Partners LP (EPD) 2014 Q2 法說會逐字稿

Good morning. My name is Brandi, and I will be your conference operator today. At this time I would like to welcome everyone to the Enterprise Products Partners second quarter 2014 earnings conference call.

(Operator Instructions)

Thank you. Mr. Burkhalter, you may begin your conference.

Thank you, Brandi. Good morning, everyone, and welcome to the Enterprise Products Partners conference call to discuss results for the second quarter of 2014. Our speakers today will be Mike Creel, CEO of Enterprise's General Partner; followed by Jim Teague, Chief Operating Officer; and Randy Fowler, Chief Financial Officer. Other members of our senior Management team are also in attendance today.

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, it can give no assurance that such expectations will prove to be correct.

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

Thanks Randy. We reported good results this quarter highlighting the consistency of our business model. The diversification we have among our business segments and geographic areas of operation reduce our exposure to temporary fluctuations associated with a single asset or commodity. We continue to move to more of a fee-based business model with approximately 85% of our gross operating margin this quarter generated from fee-based contracts, and that's compared to 75% just two years ago.

This quarter featured record volumes in our liquids pipelines of 5.2 million barrels per day, record NGL fractionation volumes of 840,000 barrels per day and record fee-based gas processing volumes of 4.9 billion cubic feet a day. In what is seasonally a weak quarter we had an 11% increase in gross operating margin over the second quarter of last year, helped in part by approximately $6 billion of new assets that began operations since the beginning of 2013. Adjusted EBITDA increased 13% over the second quarter of last year, and net income increased 17%.

These results led to strong distributable cash flow of $954 million for the quarter. Excluding proceeds from sale of assets in both periods, distributable cash flow increased 9% or $81 million over the second quarter of last year. Earlier this month we declared a $0.72 per unit cash distribution with respect to the second quarter, 5.9% higher than the distribution paid with respect to the second quarter of 2013. This is our 49th distribution increase since our IPO in July of 1998 and our 40th consecutive quarterly increase.

10 years of consecutive quarterly distribution increases is a record we are proud of and one that has not been matched by any other publicly traded partnership. Distributable cash flow provided 1.4 times coverage of the distribution declared. We retained $293 million of distributable cash flow for the quarter and approximately $730 million through the first half of this year to reinvest in the growth of the partnership and reduce our reliance on capital markets.

Gross operating margins from the NGL Pipelines and Services segment was $681 million for the second quarter, a 25% increase over the second quarter of last year. Our natural gas processing and related NGL Marketing business reported a slight increase in gross operating margin primarily due to higher equity NGL production and record fee-based processing volumes, which led to a $26 million increase in gross operating margin from our natural gas processing business.

Gross operating margins from our NGL Marketing business declined $24 million primarily due to lower sales margins and scheduled downtime associated with maintenance and activities in preparation for the 2015 expansion of our LPG export terminal. The export terminal resumed operations on July 7. Gross operating margin from our NGL Pipelines and Storage business increased $73 million or 39% to $261 million for the quarter. Our ATEX ethane pipeline which began commercial service in January of this year generated $35 million of gross operating margin for the quarter on average transportation volumes of 44,000 barrels a day.

As I mentioned last quarter there were third-party upstream infrastructure issues that reduced ethane available for ATEX. Currently three of the four planned NGL fractionator connections into ATEX are completed, and we expect the fourth to be completed this quarter.

Our Mid-America and Seminole pipelines systems reported a $19 million increase in gross operating margin primarily due to fees related to the expansion of the Rocky Mountain pipeline, which began service in January of this year, and higher tariffs that went into effect in July 2013. Partially offsetting these increases were higher operating costs on the Mid-America and the Seminole systems.

The South Texas NGL pipeline system benefited from increased Eagle Ford shale production leading to an $11 million increase in gross operating margin on a 78,000 barrel a day increase in transportation volumes. Our NGL fractionation business had gross operating margin of $154 million for the quarter, a 65% increase over the same quarter in 2013, primarily due to higher volumes and fees from our Mont Belvieu NGL fractionators.

Fractionators 7 and 8 began commercial operations in the third and fourth quarters of last year. Total fractionation volumes increased 25% to a record 845,000 barrels a day for the quarter primarily due to higher volumes from the Eagle Ford and the Rockies. Gross operating margin from the onshore crude oil pipelines and services segment declined $13 million from the second quarter of last year. Lower sales margins from crude oil marketing and related activities resulted in a $55 million decrease in gross operating margin as lower basis differentials continue to impact our business.

This quarter the average indicative price spread between LLS and WTI was $2.56 per barrel, and that compares to $10.41 a barrel in the second quarter of last year. Partially offsetting the decrease in crude oil marketing was a $34 million increase in gross operating margin due to increased volumes in our South Texas and West Texas pipeline systems and our Eagle Ford joint venture pipeline. We also had a $6 million increase in gross operating margin on the Seaway pipeline. Total Onshore Crude Oil Pipeline volumes increased 13% over the second quarter of 2013 to a record 1.3 million barrels per day.

Gross operating margin for the Offshore Pipelines and Services segment declined $6 million to $34 million primarily due to lower volumes on the Independence Hub platform and Trail pipeline. Petrochemical and Refined Products services segment reported gross operating margin of $162 million, and that's relatively flat with the $163 million that we reported in the second quarter of 2013.

Gross operating margin from our refined products pipelines and related marketing activities declined $25 million and that's primarily due to the $24 million benefit that was recognized in connection with a rate case settlement in the second quarter of last year. Gross operating margin from the propylene business increased $16 million largely due to higher propylene sales margins. The octane enhancement business reported a $3 million increase in gross operating margin while butane isomerization had a $4 million increase in gross operating margin.

We completed $1 billion of capital projects this quarter including the Seaway pipeline loop, the modification and expansion of our refined products marine terminal in Beaumont, and the construction of three additional tanks at our ECHO crude oil storage facility. Our asset footprint continues to provide capital growth opportunities with approximately $6 billion of new assets scheduled to begin service between the second half of this year and 2016. Most of these projects are supported by long-term fee-based contracts.

As recently completed projects ramp up and new assets begin service, the cash flows from those investments should support future distribution growth. Unlike some MLPs that seem to add projects to their backlog as soon as they start thinking about them, we only disclose backlog numbers for projects that actually have contracts to support them and that made it through our approval process. We are evaluating a number of capital projects that have not yet been announced, but as we move these products to the development stage, we will share the details with you.

We have been very pleased with the quality of the many new investment opportunities we've seen since the beginning of the shale revolution, and we believe the best is yet to come. With that I will turn the call over to Jim.

Thank you, Mike. Today I am going to spend time updating you on some of our -- the progress of some of our larger projects. But, I also want to spend a couple of minutes reviewing with you our philosophy on how we think about investments, which include both our time and our capital. At Enterprise we are constantly focused on building and improving the systems around which we build our businesses which is very different from managing a portfolio of assets. We work both the supply and demand side of our businesses.

People who come here from other companies have told me that it takes them a while to grasp the Enterprise integrated value chain model. They soon realize it is more than a model. It's our culture. At Enterprise we understand our role on each side of the supply demand equation - the value of bringing supplies and markets together.

Our job is to give producers flow assurance and market choices and give consumers supply reliability and supply choices. Over the last couple of years it's become clear that the US supply buckets were filling up much faster than the demand buckets, and that we need to focus on creating new outlets for producers. Creating avenues to new outlets sometimes takes major new builds like our Aegis ethane pipeline and our PDH plant. Sometimes it takes a combination of both existing assets and new assets like our ATEX ethane pipeline out of the Marcellus.

And sometimes it takes just plain old fashioned thinking out-of-the-box, doing your research, paying attention to the details, and going to the BIS and laying out your facts. Our actions over the last two years should tell you that we believe that the US now finds itself in the envious position of having significant excesses for many of our hydrocarbons, and some of these must be exported or they simply can't be produced. And if not produced, that creates its own consequences. We continue to work at creating outlets for US production.

In April, we announced the world-scale ethane export facility, a concept that we've been discussing for two years. To be honest three years ago I didn't think this was something that we would pursue. When we first started talking about this we knew that the opportunity needed time to be evaluated by the markets, but we felt the supply and demand fundamentals were in favor of US ethane exports. Over the last two years our folks have spent countless hours on airplanes and with potential customers around the world and ultimately they secured the commitments to baseload a project.

Even after we announced our ethane export project, many still doubted its viability, however, today just three months later, our project is 85% subscribed, and I expect it to be fully subscribed in a matter of weeks. And we'll go one step further and tell you we believe, given the continued interest, expansion is imminent, and that expansion will be a lot cheaper than a new build.

In May we announced that we began exports of diesel from our Beaumont refined products marine terminal and will begin exporting motor gasoline from that facility in August. We expect this terminal will also be fully subscribed very soon and with growing supplies and falling demand in the US, the fundamentals of this project will be very successful.

This project is made up largely of repurposed assets. We already know how additional docks will be configured. We have the room and the layout for more tankage. We are progressing on our LPG export expansions with our 1.5 million barrel a month expansion, expected to come online the first quarter of next year, and our larger 7 million barrel a month expansion in the fourth quarter of next year.

When both are completed, we'll have LPG export capacity of approximately 16 million barrels a month. These are exporting both propane and butane, and they are fully committed for the next several years, and we have some contracts that go out to 2024.

And then there's processed condensate. We probably took an untold number of questions in the past about when we're going to announce the condensate splitter. If you follow the news you now know why we weren't building a splitter.

Bill Ordemann had other ideas. Bill and his folks did their homework and did a great job of laying out facts that facilitated focused and thoughtful discussions with the BIS through normal channels. Bill and his people were focused on facts, not loopholes. These discussions led to a proper ruling on the export of processed condensate that is consistent with current regulations and did not require a change in law or a change in policy. This has generated a mountain of questions and policy conjecture, that frankly, we are not going to address. And as you've read these rulings are private, and I hope you can appreciate that at this time we consider the privacy of our ruling to be commercially sensitive.

In other crude oil projects we've completed construction on the 500 mile Seaway loop, the pipeline from Jones Creek to ECHO, that's in the Freeport area to ECHO, and the extension from ECHO to the Beaumont Port Arthur area. We continue to add tanks at ECHO, where we're headed to over 7 million barrels by next year, and given our footprint and interest from our customers, we don't think that will be enough.

With our access to crude supplies and the infrastructure were building, accessing 8 million barrels of refining capacity, ECHO and its distribution network are key our crude oil strategy. Our PDH plant is now fully permitted and under construction. I think we started construction the day after we received the final permit, and commissioning is expected in the first half of 2016. This project is a great fit and is fully subscribed by a very strong customer base.

Work also continues on the Aegis pipeline, that's the ethane header system from Corpus Christi to the Mississippi River, to supply the ethylene expansions happening along the Gulf Coast. While this is not the biggest project we have ever built, it is one of the most a strategic demand-side projects I have been involved in; and it's exciting to see how the list of new petrochemical facilities is developing around this pipeline. When you think about it, we're creating the supply artery for tens of billions of dollars of new petrochemical plants.

We've gotten a little press coverage over the last couple of months. But things really haven't changed here. We're still about building systems that complement our businesses and providing services to both our producers and end-use customers. We still understand our role.

We provide flow assurance and market choices to producers, and we provide supply reliability and supply choices to our consuming customers. With that I'll turn it over to Randy.

Thank you, Jim. I'll take a few minutes to discuss additional income statement items and capitalization. We reported net income attributable to limited partners of $638 million and fully diluted earnings per unit of $0.68 for the second quarter of 2014. A reconciling item between our non-GAAP gross marketing margin and net income are the non-refundable deferred revenues, attributable to shipper makeup rights on certain new pipeline projects such as ATEX, Seaway, Texas Express and Front Range.

Deferred revenues are excluded from net income. Deferred revenues attributable to these makeup rights total $22 million for the second quarter of 2014 which equates to approximately $0.02 per unit. So as a reminder, when you are modeling us, remember to subtract your estimate of deferred revenues from your estimate of gross operating margin to arrive at EPU for Enterprise.

Depreciation and amortization expense for the second quarter of 2014 was up 8% or $23 million to $312 million as a result of new assets going into service over the last 12 months. Interest expense increased $29 million to $229 million in the second quarter of 2014 due to an $18 million decrease in capitalized interest, and an $11 million net increase in interest expenses, due to a higher average debt balance in the second quarter of this year versus last year. This was somewhat offset by lower interest rates.

Capital expenditures for the second quarter were $697 million, which includes sustaining capital expenditures of $77 million. We currently expect growth capital expenditures of $3.4 billion to $3.8 billion in 2014, and we still expect sustaining capital expenditures of approximately $350 million for 2014. Adjusted EBITDA for the 12 months ended June 30, 2014 was approximately $5 billion. Our consolidated leverage ratio of debt to adjusted EBITDA was 3.5 times for the 12 months ended June 30, 2014. And this is after adjusting for the 50% equity credit that we get for the hybrid securities from the rating agencies.

We received net proceeds of approximately $140 million from equity issued through the total of our At The Market equity issuance program, our dividend reinvestment plan, and the employee unit purchase plan, in the second quarter of 2014. This amount included $25 million of common units that affiliates of privately-held EPCO purchased through the partnership's distribution reinvestment plan.

The average life of our debt is now 14.3 years. This is using the first call date for the hybrid securities, and our effective average cost of debt is 5.2%. At June 30, 2014 we had consolidated liquidity of approximately $3.7 billion. This included $242 million of unrestricted cash and $3.5 billion of available borrowing capacity under our revolving credit facility.

On July 15 we announced that our board approved a two-for-one split of our common units. We will distribute one additional common unit for each common unit outstanding on August 21, 2014 to holders of record, as of the close of business on August 14. With that, Randy, ready for questions.

Okay, Brandi, we can take questions now from our audience.

(Operator Instructions)

Our first question comes from the line of Brian Zarahn with Barclays.

Good morning everyone.

Good morning, Brian.

Just a couple of questions on the ethane export project. Of the 85% contracted capacity, does that begin in 2016 or is that sort of a rolling state for the contracts?

It all starts at once.

And then, Jim, any additional color on the geography of the customers for the ethane facility?

No. (Laughter)

I had to try. Is it similar to one of the customers that was announced -- Jim knows geography.

I didn't understand you, Brian.

Brian, some customers may announce themselves, but we are not going to.

Okay. And then since you're making progress, you seem pretty confident that the remaining 15% will be contacted soon, how are you thinking about upsizing the project in terms of additional capacity?

We've got a couple of options, Brian, and we really haven't landed on one. We don't know if we are going to build one big refrigeration or two refrigeration units. We are still working that.

Okay. And then sticking with the export theme, I know you won't want to get too granular on the condensate export, but from a high level, how do you view the export opportunity for Enterprise? Are there any additional midstream investments you'd need to continue to see to optimize that opportunity?

Not really. We're in pretty good shape.

In terms of storage and dock capacity you think you have enough?

We think we're in pretty good shape, Brian.

Okay. And lastly on 2014 expansion CapEx, it looks like it was revised down a little bit. Any color on that change?

I think that is just the timing of the spending on some of our projects. Some of the permits took a little longer to get than we expected, but nothing material.

Thanks Mike. That's all for me.

Darren Horowitz, Raymond James.

Jim, couple questions for you on the ethane export capacity. Now that you've got those contractual commitments for about 85% of the existing terminal's capacity, do you guys have a better feel for how much either Northwest European or Southeast Asian naphtha feedstock capacity could be displaced by Gulf Coast exported ethane?

I know what we contract is going to displace, Darren. (Laughter) I really don't. Tony might.

Not really. We also think some ethane is going to go to new markets, not just displace naphtha.

That's a good point. Not all of this -- we don't expect all of it to displace naphtha. Some could go to fuel.

Are you guys still thinking, let's just say over the next six or seven years, we could be looking at a market that is still 700,000 barrels oversupplied on ethane? Is that still fair?

It is before exports. We show in our materials, I think it's 450,000 to 700,000.

Let me hasten to add, Darren. We don't think this export facility is going to solve the ethane problem if that's what you are asking.

I appreciate that, Jim. I think what -- where I was going with this, is let's just say under current capacity you guys could do 185,000 or 200,000 barrels. I know you're in the early stages of evaluating what expansion potential the terminal could look like. Obviously, it's not just going to be one terminal that solves the problem.

But the way that we see it, there is the opportunity, at least based on initial scale, for you guys to increase how much ethane you export across an expanded terminal by almost 50%, if not more. Is that fair?

That's probably fair, but you know the reason I said possibly -- probably imminent is our capital isn't the only capital being spent. I question how many people are going to step up and spend the money necessary to build the ships, to build the receiving facility. This -- these folks that have signed up so far, they're making a heck of a capital commitment to this program, and it's going to be interesting to see who else will do that.

I appreciate that, Jim. If I could I just want to switch gears over to condensate for a quick second and talk really from a more macro perspective. As you guys are talking with producer customers regarding specifically South Texas Eagle Ford condensate supply growth, do you have a sense of the timing and magnitude as to when that supply growth really hits the Gulf Coast in a big way, and how much oversupplied we could be waiting on export capacity to ramp?

We think the supply growth is hitting the Gulf Coast today, and there's obviously in our view a ramp that is going to continue on through the rest of the decade anyway.

(multiple speakers) Just looking at things right now, and last question for me, is it fair to assume that we might have 500,000 barrels of just South Texas Eagle Ford condensate currently in terms of supply, and that could grow anywhere between 15% and 20% year-over-year for the next couple of years? Is that the right way to think about it?

That's a fair way to think about it.

Okay.

Its a function of these guys having markets, Darren, in the final analysis.

Yes, and I think also too, Jim, it's a function of what their netback economics look like, and if there is a tremendous amount of supply sitting on the doorstep of the Gulf Coast waiting for export, and it starts to dislocate price, that could be a pretty big incentive to get that stuff out of there pretty quick. And we can only send so much North, as a diluent for oil sands production. So it seems like there could be a significant infrastructure response in the short term to handling all of the supply.

Brian -- Darren, you should be sitting here given this presentation.

I don't work for Enterprise, Jim.

It sounded like you just did. We appreciate it.

I'm just a simple analyst trying to make heads and tails of all of this, but I appreciate the color. Thank you.

One last comment. The reality is, you're right. Condensate has been selling at a very deep discount. And for these guys to continue to produce, they got to have markets. That's our position.

Thank you, Jim.

Sunil Sibal, Global Hunter Securities.

Good morning, guys. Most of my questions have been answered, but just a couple of follow-ups on ethane contracts. Could you talk a little bit about the term of the contracts, pretty long-term 10-plus years?

Are you asking about the terms of the ethane contracts?

Yes.

I think all of the ones we have so far are 10 years plus.

Okay. And then on the LPG maintenance downtime that you had during the quarter, I was wondering if you could talk a little bit about the impact of that on the gross margins this quarter, and also what kind of trends you're seeing in terms of the propane exports during this quarter versus last quarter?

We are not going to talk about the impact that it had on the earnings. There were four cargoes that were impacted. The downtime was 10 days and of that there were only three days in the second quarter -- the other seven days was in July.

And any color on the terms for propane exports during Q2 versus Q1?

Did you say propylene exports?

Propane exports.

Propane.

I didn't understand the question.

When you look at the propane exports for the second quarter, how were they trending versus the first quarter propane exports?

The volume.

We are full.

Okay.

It's not going to change significantly until we get the expansion done.

Okay, that's all. Thank you.

Michael Blum, Wells Fargo.

Hey, good morning, everybody.

Good morning.

A couple of questions, wanted to ask some questions about returns. I was curious number one, what you think about the returns you are going to get on the ethane project. Are those similar to what you are getting on the LPG project or is that different? Or how should we think about that?

As you know, we don't talk about returns on specific projects. That does kind of cut against us in some fashions, but suffice it to say that the returns that we're getting on the ethane project are attractive returns to us, and they certainly are well in excess of our cost of capital, or we wouldn't be doing them.

Okay. As it relates to the returns you are getting on the LPG, are there any spot volumes you're getting right now that is contributing to maybe what you'd call an excess return above your baseline return that you're getting from your contracted volumes? And then as more capacity comes online next year, you and Targa, do you think that could continue or do think that gets eroded?

This is Al Martinez, Michael. Our goal -- our direction goal for long-term contracts, we are basically contractually committed for the facility with the expansion through 2017. We only -- we have a very small percentage -- in 2018 we are 90% committed on long-term contracts. That's based on our assessment of the capacity of the facilities. The spot opportunities we create through efficiencies and optimization during each month, and it's very hard to project but we expect based on our conservative nature that we will have sweet spot opportunities on a monthly basis in the future.

But, Michael, we're focused on selling the thing out on long-term contracts. We're not hanging our hat on spot opportunities.

I think it is fair to say that with more experience in operating the facility we have a better idea of how many term cargoes we can load which leaves less opportunities for spots, but nonetheless there's still opportunities.

We are currently -- in 2018 we are at 81% commitment. And I plan to have 2018 at 100% commitment within the next few months.

Okay. That's very helpful. You threw out that 85% fee-based number for this quarter. Is that kind of the new mix going forward, or was there some sort of anomaly this quarter where maybe a commodity was lower for some reason?

Michael, I think it is just a function that all of our new contracts are essentially fee-based, and to the extent that we had take-or-pay, a lot of those got renegotiated, or they are just contributing a whole lot less to our gross operating margins.

Okay. And then just two more quick ones. One just on the condensate exports, I realize you're not going to say much here.

I just wanted to clarify that there was that Reuters article that I'm sure you saw which -- that the government has put a moratorium or a reevaluation whatever you want to -- however you want to say it. But I just wanted to make sure -- I wanted to confirm that does not impact the private ruling that you received. Correct?

Our ruling is intact.

And then last question just if you had any updated thoughts on M&A. I know you've got a big opportunity set in front of you organically. But just given your really attractive cost of capital. Do you see that as sort of strike -- do you see any reason to strike while the iron is hot here, and you've really got a competitive advantage in that market as well?

A couple of things on that, and we see reports from time to time that talk about the fact that we have no backlog beyond 2016 which is why I stuck one of those comments in my remarks. And it is kind of humorous for us in the room, because we had a meeting yesterday talking about other projects that we're looking at that haven't been announced, and it's a bit overwhelming. So we've got a lot of opportunities, but that doesn't mean that we're not looking at acquisitions from time to time.

Frankly, some of the acquisitions that may make sense for us are smaller assets that we can put into a different service, or we can plug into our system and get more value out of than the current owners. For large scale acquisitions, even though we're in a position to be able to do those and to make them work, if they don't return the kind of returns that we can get from our organic projects, or if they don't lend to future growth, there's just not the industrial logic to do those just because we can.

Okay. Thank you very much, Mike. Appreciate it.

Mark Reichman, Simmons.

A few questions. While the construction of the Seaway twin is complete, I think there was a little bit of a delay in the Flanagan South pipeline that will feed the Seaway twin.

And there's been speculation that the Seaway twin shippers that would be getting their oil from Flanagan South that they're not obligated by those take-or-pay contracts until Flanagan South is operational. I was just wondering if you could provide some color on the startup of the Seaway twin and talk a little bit about line pack and when deliveries would begin?

I'm going to leave the Flanagan South questions to our friends at Enbridge, I think. I don't want to speak for them and speak wrongly. I think they've got some ideas of when they are coming on, and I'm sure they'll make that public in due time. As far as Seaway goes, the Seaway twin goes, now that we are complete that essentially started a clock whereby the payments for the Flanagan South shipments will start on a date certain at this point.

Okay. I understand why you wouldn't want to comment on Enbridge. But, because the Enbridge capacity into Flanagan is not sufficient to result in high utilization of Flanagan South pipeline, are you at all concerned about underutilized capacity downstream of Flanagan in the event that Enbridge doesn't get approval to establish a new receipt point on the Lakehead system, or their Alberta Clipper expansion gets delayed? I just mention that because I know that you announced the potential for a Bakken to Cushing pipeline.

Seaway has demand charges on all of the volumes that would be committed out of the Flanagan South system that again will start on a date certain. From a Seaway perspective, I am not worried about that. We will get paid whether the oil ships or not. Frankly, if there's additional capacity and some of that oil doesn't ship, we will look for other ways to utilize it.

Okay. And then on the ethane export terminal, with the new ethane export agreement that was announced this morning, I think the long-term commitments represent 85% of the capacity of the terminal. I was just wondering if you could quantify the capacity. If the terminal has the capability to load 10,000 barrels per hour, how many hours per day and days per week does that 85% represent?

We are thinking operational capacity of the terminal with the efficiency of the docks and movements of ships and everything else considered and ramp-up and ramp down, it's going to be about 200,000 barrels a day.

Okay, and then lastly during your analyst day, I think Jim had mentioned that you might be interested in increasing Enterprise's presence in the Permian. Are you able to comment on some of the opportunities that you've identified, whether it be on the crude or natural gas side?

We continue to work projects in the Permian, and we're probably not in a position to say what they are.

Mark, that kind of goes back to my remarks that we are evaluating a lot of projects that, frankly, we're going to wait until they get more fully developed before we start talking about them in the public.

Okay.

But I think suffice to say to your question we are working on natural gas, crude oil and NGL projects in the Permian.

Right, and then lastly, the distillate loading at Enterprise's Beaumont refined products terminal I think began in May, and gasoline loading is expected to commence in the third quarter. What are your expectations for volume growth beginning in the fourth quarter of 2015, and also could you comment on plans to add tankage and perhaps a second dock?

R.B., I think we expect to have that thing sold out in a matter of two to three months. Is that right?

That is correct.

At that point in time, like I said, we will look at what we think our expansion needs are, and we know what we need to do. We have plenty of land for tankage, and we know how to configure the docks.

Great. Thank you very much.

Ted Durbin, Goldman Sachs.

Thanks. There was this -- I guess press report around you all potentially building a Bakken pipeline, I think 340,000 barrels a day was the number that was out there. Can you just talk about where you are on that? Do you have enough commitments to make that project a go?

That's another one that we're looking at a lot of things, and once we to get further down in the development stage of the project, we will talk about it, but it's premature to talk about it now.

Okay. With something out of the Bakken would you think of that as a stand alone return project, or would it be kind of coming back to that previous question especially around pull through for Seaway volumes if there is maybe not enough coming into Cushing for you?

On all of our projects we look at them on a standalone basis, and then we look at how they might add value downstream. But until we actually have a project that is firmed up, it's hard to tell how we are going to look at it.

Understood. And then just coming back to the gas processing margins again in the quarter. Volumes are up pretty well, but it just seems like we've got the margin pull through. Just anything else that you can help us with terms of what was happening in the quarter there, again equity volumes were up on the NGL side. I'm just struggling a little bit with what the result -- the margins there.

Equity volumes are up primarily because some companies have decided not to elect processing, and we have the option to process if we want to. And if we can make money at it we will, because we're looking at all of the variable costs.

Fee-based processing were up as well, but the overall margin was pretty flat year-over-year.

I think maybe to clarify what Mike said, the fee-based margins are based on the volumes of gas we're processing, and the volumes of gas we're processing continues to rise, so the fee-based volumes are up. The equity volumes are up mainly for ethane elections where a producer has the ability to -- they'll continue to pay their fee-based volumes, but they can reject the ethane and not recover the ethane.

And we have the option to step in and recover that ethane, and again we're doing it on a variable cost, so our economics to do it are much better than the producers. So I think throughout the second quarter anyway, we recovered most of that ethane that the producers were not.

Got it. That's very helpful. That's all I have. Thank you.

John Edwards, Credit Suisse.

Mike, if you could just clarify on the backlog, I think you said in your opening remarks that you're going to put in $6 billion between now and 2016. And then, I guess, first, is that correct? And then what's your total backlog now?

The $6 billion between now and 2016 is correct, if Leonard's guys get it done, which I'm sure they will. They always do. Again, those are projects that have been approved, sanctioned, we are actually doing work on them. It's not pie-in-the-sky stuff.

Beyond 2016, we don't have too many projects that take three or four years to build. So it's a little far out for us to have things that are already defined and Board-approved. We constantly are looking at new things, and we have a lot of projects that we are considering that would fall into the 2016, 2017, 2018 timeframe, but again they are not baked enough for us to put into a backlog if you will. I know a lot of our competitors do that.

Anything that moves, they'll throw into a backlog to look like a big number. We don't do that. You can look at our historic spend rate and see what we are talking about between now and 2016. And I'll tell you that we've got a lot of opportunities.

Fair enough. I'll leave it there. Thanks for the clarification.

There are no further questions at this time. Do you have any closing remarks?

No, we don't, Brandi. If you would again just go ahead and relay the replay information to our listeners, that would be great. Thank you.

Thank you for participating in today's Enterprise Products Partners conference call. This call will be available for replay beginning at 1.00 pm Eastern standard time through 11.59 pm Eastern standard time on Thursday August 7, 2014.

The conference ID number for the replay is 74829671. Again the conference ID number for the replay is 74829671. The number to dial for the replay is 1-855-859-2056 or 1-404-537-3406.

Thank you, Brandi, and thank you for joining us today, and have a good day. Goodbye.