Enterprise Products Partners L.P. (EPD) Q2 2018 Earnings Report, Transcript and Summary

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 L.P. Second Quarter 2018 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 I would like to turn the call over to Mr. Randy Burkhalter.

Thank you, Jennifer. Good morning, everyone. And welcome to the Enterprise Products Partners conference call to discuss second quarter earnings. Our speakers today will be Jim Teague, Chief Executive Officer; Bryan Bulawa, our Chief Financial Officer; and Randy Fowler, President of Enterprise’s General Partner. Other members of our senior management team are also in attendance for the call today. During this call, we will make forward-looking statements within the meaning of Section 21E of the Securities and Exchange Act of 1934 based on the beliefs of the company as well as assumptions made by and information currently available to Enterprise’s management team. Although management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Please refer to our latest filings with the SEC 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 Jim.

Thank you, Randy. As we said in this morning’s press release, our business continue -- our businesses continue to perform exceptionally well, supported by supply growth and strong market demand, both domestically and internationally. We’re proud of the fact that for the second quarter in a row we provided 1.5 times coverage of the quarterly distribution, which has allowed us to retain nearly $1 billion year-to-date. This puts us well ahead of the equity self-funding goals we laid out for fourth quarter last year. Let me just give you a list of facts from the second quarter that reflect just how strong our year is proving to be. We’ve set several operational records in the second quarter. Natural gas liquid pipeline transportation volumes were a record 3.41 million barrels a day. Natural gas liquid marine terminal volumes were a record 597,000 barrels per day. Ethane marine terminal volumes were a record 169,000 barrels a day. NGL fractionation volumes were a record 927,000 barrels a day. Crude oil pipeline transportation volumes were a record 2.05 million barrels a day. Crude marine terminal volumes were a record 802,000 barrels a day. Overall, NGL, crude, petrochemical and refined products marine terminal volumes were a record 1.75 million barrels a day. Overall, crude -- overall, I am sorry, propylene production was a record 19.3 million pounds a day. Overall, NGL, crude, petrochemical and refined products pipeline transportation volumes were a record 6.23 million barrels a day. And then we had a little fun and we converted natural gas to a barrel equivalent. And overall NGL, crude, petrochemical, refined products and natural gas on the barrel equivalent pipeline transportation volumes were almost 10 million barrels a day at 9.82 million barrels. I am not used to quoting this many records. Then we set several financial records. DCF, excluding proceeds from asset sales was a record $1.43 billion. Adjusted EBITDA was a record $1.77 billion. Segment gross operating margin for NGL pipelines and services was a record $913.7 million. Segment gross operating margin for petrochemical and refined product services was a record $281.8 million. If I counted right, that's 14 operational and financial records. Second quarter also included a string of project announcements as there continues to be no shortage of opportunities for Enterprise. In a gathering and processing area, we announced that our first plant at Orla began operations, and construction of two more plants are underway at Orla. In addition, we announced a strategy deal for all of the NGLs from Apache’s Alpine High discovery in the Permian. Production from this basin will support our Chinook NGL pipeline and our assets at Mont Belvieu. We also announced the formation of a 50-50 joint venture with Energy Transfer. Let me repeat that. We also announced the formation of a 50-50 joint venture with Energy Transfer to resume service on the Old Ocean natural gas pipeline which has been idled since 2012. We concluded a successful open season on Front Range and Texas Express pipelines and are underway on our expansion plans to support additional liquids from the DJ Basin. Lastly, we confirmed that our Midland-to-ECHO pipeline is now in full service at an expanded capacity of 575,000 barrels a day and fully subscribed under long-term contracts. As to demand driven projects, we've recently announced the location and capacity for our ethylene export project. We also closed on the purchase of another 65 acres adjacent to our ship channel marine terminal. We recently started at vessel bunker fueling service at the ship channel facility which is a nice add-on for Enterprise and time saver for us and our dock customers. And we’re happy to report that our PDH plant ran at capacity in the second quarter and is now making a sizable contribution to our bottom-line. Projects like ethylene storage, ethylene distribution, ethylene export, propylene export and storage, PDH and our second iBDH fall into that category of being strategic to Enterprise as we extend our value chain into primary petrochemicals. Final thing I want to touch on is exports where the trend has been to break new records almost monthly, with the biggest advances led by crude. In that regard, we recently announced that we are developing an offshore crude oil export terminal off the Texas Gulf Coast. For at least the last three years, we have been very open about our long-term outlook for US crude oil exports and we don’t see these trends changing. What makes this project a natural for Enterprise is the fact that our Houston area systems can aggregate over 4 million barrels a day of crude oil, a terminal without supply aggregation really isn’t a terminal. And I want to end with that by thanking the Enterprise people. We don’t do that enough. These are same people that performed historically during [Harvey] and these are the people that made this record setting quarter possible. Whether it’s operations, accounting, engineering, commercial or whatever, we are departments. Enterprise people work as a team and that’s what truly differentiates Enterprise. With that, I’ll give it to you Bryan.

Thank you, Jim. And good morning, everyone. As Jim outlined earlier, we achieved record operational and financial performance during the second quarter, which is traditionally a weaker seasonal period. We clearly benefited from improving fundamentals and contributions from new assets and mitigated seasonality and accelerated the meeting many of our financial objectives. Specifically we have reached our equity self-funding objective through the combination of strong excess [CCA] and proceeds from our distribution reinvestment program, leading us comfortably within our targeted leverage range without taking into account any pro forma adjustments for acquisitions or expected cash flows for contracted growth projects under construction. With this level of financial flexibility, we can’t help to be excited by what the future holds given the amount of opportunities that are under development to further strengthen the durability of our partnership. I will now review a few income statement items for the second quarter. We iterate our expectations for our growth and sustaining capital expenditures for 2018 and wrap up with an overview of our balance sheet metrics and equity funding objectives. Starting with the income statement items. Net income attributable to limited partners for the second quarter of 2018 was $673.8 million or $0.31 per unit on a fully diluted basis compared to $653.7 million or $0.30 per unit on a fully diluted basis for the second quarter of 2017. We recognized a total of $322 million or $0.15 per unit in a non-cash mark-to-market loss during the second quarter 2018 primarily due to the Midland to Houston and Midland to Cushing basis hedges. Substantially all of these crude oil hedges will roll off in the last half of 2018 and into 2019. Depreciation, amortization and accretion expenses were $46 million higher when compared to the same quarter of 2017, due to the PDH facilities and Midland-to-ECHO pipeline, our Orla 1 gas processing plant and Frac IX being placed into service since the second quarter of 2017. Interest expense was $275 million for the second quarter of 2018 compared to $246 million for the second quarter of 2017. The majority of the quarter-to-quarter increase was due to higher debt principal balances and lower capitalized interest as a result of assets putting into service including the PDH facility, the Midland-to-ECHO pipeline and Frac IX. Total capital spending in the second quarter of 2018 was $910 million, including $73 million for sustaining capital expenditures. For the first half of the year, total capital spending was approximately $2.1 billion including $235 million in acquisitions, and $140 million in sustaining capital. We now anticipate spending $3.8 billion to $4 billion in capital expenditures for the full year and approximately $315 million on sustaining capital expenditures. We placed approximately $1.1 billion of growth capital projects into service during the second quarter of 2018 including the previously mentioned Orla 1 gas plant and our 9th fractionator in Mont Belvieu. We currently have an additional $5.2 billion of projects under construction through 2020. The primary additions are increased capacity on Chinook upon startup from 250,000 barrel per day to 550,000 barrel per day project and the North Texas 36-inch natural gas pipeline expansion project. Moving to our balance sheet. At June 30, 2018, our total debt principal outstanding was $26 billion, assuming the first call date for a hybrid. The average life of our portfolio was 14.6 years. Our effective average cost of debt was 4.5% and 89% of our debt portfolio is fixed rate. Adjusted EBITDA for the 12 months ended June 30, 2018 was $6.3 billion and our consolidated leverage ratio was 3.9 times after adjusting debt for the partial equity treatment as hybrid debt securities by the rating agencies and further reduced for cash and cash equivalents, which as stated earlier is within our long-term targeted range. Our consolidated liquidity was approximately $3.6 billion at June 30, 2018, which included available borrowing capacity under credit facilities and unrestricted cash. In June, we increased the aggregate principal amount under the commercial paper program from $2.5 billion to $3 billion which further enhances our financial flexibility. To that end, we've recently issued a notice of redemption for all of the outstanding principal amount of our $521 million junior subordinated Notes A due in 2066, which are subject to a quarterly rate reset and as of July 31, 2018 an effective interest rate of 6.066%. We intend to use available cash and proceeds from our upsized commercial paper program to fund the redemption. We satisfied the replacement capital covenant aspect of the redemption through the issuance of pari passu, hybrids and equity issued through the DRIP during the past 12 months. The redemption is scheduled to close on August 24th, and is expected to result in annual interest savings of approximately $19 million and a modest increase to leverage of 0.04 times. Moving on to equity issuances. During the second quarter, we received proceeds from the distribution reinvestment program and employee unit purchase program of approximately $84 million and our ATM program continues to be unutilized. As a matter of fact, we haven't issued units under the ATM program since July 11th of 2017. With respect to the upcoming August 8th distribution payment, private affiliates of the Enterprise Products Company or EPCO elected to reinvest a $106 million of the DRIP program. This brings their total reinvestments with the DRIP to $206 million year-to-date demonstrating their continued long-term support of the partnership. We retained $491 million in excess distributable cash flow in the quarter, which alone funded 54 -- or approximately 54% of our second quarter 2018 growth capital expenditures. Year-to-date, we have retained $948 million in excess distributable cash flow. As our cheapest source of equity funding, retained distributable cash flow effectively enhance DCF per unit by avoiding the issuance of approximately 35 million to 36 million incremental units. And as we continue to announce incremental growth projects, we remain confident in our ability to self-fund the equity portion of our growth capital for 2019. With respect to our approach on distribution growth, I’d like to reiterate comments we made on previous calls, we intend to continue recommending to our Board to grow our quarterly distributions in 2018 at a core of a penny per unit per quarter and we’ll reassess in 2019 our investment opportunities and alternatives for returning capital to [investments]. I will now turn the call over to Randy Fowler for some closing comments.

Thanks, Bryan. This past weekend I had the chance to reread a few chapters in Benjamin Graham’s classic, The Intelligent Investor. As many of you recall, Mr. Graham uses the metaphor Mr. Market to explain market sentiment. Everyday Mr. Market tells us how he is valuing the worth of a business. Some day he is enthusiastic and some days he is fearful. To provide some context for Mr. Market’s current sentiment, we compare today to July 31, 2015, three years ago. The 12 months forward curve for WTI crude oil features is up 32%. Enterprise’s distributable cash flow for the first six months of this year compared to the first six months of 2015 is up 40%. Similarly, distributable cash flow per unit for the first six months of 2018 compared to 2015 is up 26% and our access distributable cash flow for the first six months of this year compared to 2015 is up 79%. In contrast, EPD’s unit price was $28.33 on July 31, 2015. It closed yesterday at $29, up just 2%. It seems that Mr. Market is still fearful of the midstream sector. Mr. Graham goes on to pass wordily that when Mr. Market is fearful there can be good opportunities for value or unit investors. Randy, with that, we can open it up for questions.

Thank you, Randy. Jennifer, we’re ready to takes questions from the participants.

Thank you [Operator Instructions]. And our first question comes from the Jeremy Tonet with JPMorgan.

Just want to touch base with regard to the crude oil segment. Results moved up quite a bit there. And I was just wondering if you could provide a little bit more color on what drove the higher per unit margin, how much was induced by supplier water spreads that were captured or just how ratable was the print this quarter?

Yes. This is Brent Secrest. A lot of that has to do with spreads. We've obviously brought on our pipeline from Midland. So when you look at the volumes that we’re doing now in the second quarter, I want to say we averaged right around 570,000 barrels a day. That's the main contributor. And then if you look at just the amount of crude exports that we're doing, I want to say we got close to 800,000 barrels a day across our docks. So it's primarily just overall throughput on the crude system.

So there wasn't a lot of spread capture, is close to the 390 a ratable number or is it something lower like 350?

Well what we hedged was a heck lot lower than what we could’ve done if we’d not hedged. So, yes, what $3 on average? Randy, what do you think?

Yes. Jeremy, I’d add a little bit, just as we're -- if you would -- think of the commitments on the Midland-to-Sealy pipeline, they were probably right around 180,000 barrels a day, 185,000 barrels a day on average for the second quarter. And we'll see that double next quarter as we get commitments and when they'll continue to ramp up through 2020. We have more opportunity to come in and contract at higher rates. And so, that's where just focusing on the Midland-to-Sealy aspect along with if you would capacity lease on Rancho. I think if you just look year-over-year that contributed between $95 million and $100 million of year-over-year growth. And again, I think as we see that ramp up come on, once you get out to 2020 that quarterly type number maybe more in the $65 million to $70 million range. But I think here for the next few quarters as we -- when we're in the early stages of the ramp up, you can see probably several more quarters where we'll be in that $100 million a quarter area on Midland-to-Sealy anyway.

And then also to say in that Randy, what we're saying is that our docks are becoming more valuable. So I think there’s an offset there.

That's very helpful. Thanks. And then clearly there is a very immediate need for evacuation from the Permian and with Chinook coming online early next year, is there any update that you can provide for us there as far as potential to repurpose some NGL pipes into crude oil service. And I guess the similar type of a question with the Seaway as well?

As far as NGL's conversion, Jeremy we're still evaluating that. And on Seaway, is Jay in here?

No, but I'll take that. We're evaluating, expanding Seaway, I think there’s others out there doing the same thing. The one thing that we can do immediately is we're adding DRA to Seaway 2 that will be online in September and that adds about 100,000 barrels a day of capacity. So that will take us to around 950. It depends on the mix of the crew, which has called 950.

Our next question comes from Colton Bean with Tudor Pickering Holt.

Good morning. So just sticking with the crude oil segment there. I think you called out about $14 million step up for the Houston terminal and export loadings. Just given the volume increase that you guys saw, it looks like maybe around $0.75 a barrel of margin. Is that in the ballpark of what we should expect for the proposed offshore terminal? Or are there any major differences that we should be aware of either to the up or the downside there?

I think we’re still deep in the weeds on the offshore terminal as to what the market will bear. But I’m thinking what a dollar down in a quarter.

Yes. I think incrementally, I think your number is notionally correct on kind of crude export floating fees. And then if you look at the incremental for that, that’s probably at around $0.50, but there’s a lot of value chain upside with that investment.

Got it. Very helpful. And just on the system NGL pipeline network. So the release noted about 120,000 uptick on Seminole and Chaparrals but [Maple] was quite a bit lower just 13. So does that indicate that I mean effectively or the vast majority at least of that increase on Seminole and Chaparral were Permian volumes not a whole lot of Rocky’s flow through? And I guess if so kind of to Jeremy’s question, how much capacity is remaining on that legacy system at this point?

Volumetrically Maple, Maple was up by -- run allocation north of pipelines right now and variable cost is higher, transportation costs are higher, we’re moving every single down we can. But the specific answer to your question with regards to Permian, we’re seeing a lot of Permian volumes come through, but Rocky volumes are maintained as well, so I want to say it’s a negative in the sense of the Rocky’s volumes cutting off.

I think what he just said is, we’re on allocation and we probably don’t have any incremental capacity in delivery on Chinook.

Your next question comes from Shneur Gershuni with UBS.

Hi. Good morning guys. I guess I just wanted to start off, I mean you just printed a very strong quarter and obviously against the backdrop of a lot of hydrocarbon production activity. I was wondering if we could sort of talk about opportunities kind of on a go forward basis. I was wondering if you can talk about how much operating leverage is left in the system. Are you able to move up to timeline of converting an NGL line to crude when Chinook comes into service, could we see another frac at Belvieu with all the activity at Belvieu, could we see more propane exports. I was wondering if you can sort of talk about because it seems like there is multiple ways for you to continue growing over the next year or so?

I think the answer is yes. I’ll let Tony and Randy step in. I guess there is -- on the NGL conversion, I think all we’re saying is, we’re still in the evaluation mode in terms of more fractionation. After we build the four train assets, we’re never going to build another fraction either. And now we’re bringing up the 9th train and looking at the 10th train and see opportunities that probably add more. And I’ve got Randa Duncan snapping the whip to build more trains. So, yes there is opportunities for more fractionation. I think there is opportunities for another PDH and in fact we’re working that hard, when we look at how short the market is for propylene given the demand growth we think there is a strong possibility we’ll build another PDH. In terms of LPG exports, when Brent said there is value chain opportunities associated with an offshore port, we believe we’re going to need more LPG export capacity. If you look at our forecast, and I think -- did you publish it? Tony's group publishes that soon. I think what you'll see is that, Tony -- our Fundamentals Group is predicting that there will be more LPG export capacity required. So to the extent that we're able to pull off an offshore port that gives us the opportunity to put more LPG through to our ship channel facility. Does that answer?

It does. Maybe just follow up, Bryan you mentioned in your prepared remarks that you've generated $948 million of excess DCF in the first half of this year. And you expect to continue to be able to fund and so forth. I've realized you've sort of stated the distribution growth going forward for 2018. But I was wondering if you can sort of talk about some of the things that you're thinking about with respect to 2019, if this trend continues, do you debate between potentially increasing the growth rate versus potentially buying back units and so forth. Is there a thought to turning to drip off at some point? Just kind of wondering if we can talk about the debate in the boardroom in terms of how to be thinking about that?

Well I think it's still -- Shneur, I appreciate the question. And quite frankly all of those options remain certainly on the table. I would say that as part of the least likely avenue that you mentioned was the potential for a buyback. I think the growth opportunities that we see in front of us I think that is more of a challenge for us and we'd rather meet that challenge then look for opportunities to buyback our units. We'd rather look for opportunities to continue to grow and to extend the life of the durability of our partnership. So there is really not new more guidance to give you except that all of those items that you brought up, yes, those are the items that we debate. And then you have also -- one thing you didn't bring up is that you have to factor in and Randy sort of referred to it in his comments, as far as how does the market respond to the different actions that we're taking as far as we look at maximizing long-term value to all of our unitholders.

Your next question comes from Jean Ann Salisbury with Bernstein.

Everyone is talking about looming Mont Belvieu’s fractionation capacity shortages over the next year. What happens in this scenario and how can Enterprise benefit, can you reflect if these operates on any of your fracs or use wide grade storage?

This is a kind of an environment where you get really creative and you use every lever you have. And Enterprise has a lot of levers that can create incremental frac space. You create that frac space at a cost and then you have to recover that cost plus and any new frac deal you do. And we are in the process of pulling a few levers.

Okay. That makes sense. And do you have significant wide grade storage at Mont Belvieu or around it?

We've got a lot of storage. And -- but us storing wide grade is probably not something we're going to do but we're certainly be willing to store peoples' wide grade part of them.

And you have I guess up to 4 million barrels a day of export capacity for Houston, but some of that space is needed for refined products and important stuff. Do you have an estimate of what you think the true maximum of crude exports that you could realistically handle out of Houston would be and does that change with the newly announced project?

Brent?

I think that number is north of 2 million barrels a day, just specific. Yes, and that’s just Houston, it does include Texas City, Freeport, Belmont. So just Houston alone we have over 2 million barrels of export capacity and still take care of the rest of the products.

And how much in Texas City, Texas City, Bob? Okay. So, we also have the capability to load crude and we have the crude down to Texas City and loaded out of our Seaway docks that we share with Enbridge, and Bob just said we could do well over 1 million barrels a day there.

Your next question comes from Keith Stanley with Wolfe Research.

Hi. Good morning. Just on CapEx Bryan, just anymore color on what’s driving the increase specifically for 2018. Is it just Chinook and Old Ocean mainly? And then for 2019 do you still expect about $3 billion of growth CapEx or might that be a little higher with some of the opportunities you’re seeing?

So for 2019, I think you probably have pretty clear visibility to $2.5 billion, so your range -- $2.5 billion to $3 billion is probably a reasonable expectation for 2019. As far as for this year, as far as the range, a lot of it has to do with what I mentioned as far as the expansion of Chinook, that’s probably the largest contributor. And then you’re trying to pull some expenditures forward as well out of 2019 into 2018.

Got it. Okay. And then changing subjects a little, so any change in the level of interest for the company in acquisitions at all, or is the message still kind of we enough to do organically and see more value in growing organically from here?

Yes. I’m going to Randy, but first, Randy has a saying that I think we embrace and that is price matters, but what also matters is, you’ve just got a pit our system. And it’s going to be something that’s additive to what we already have.

Yes. We’re consistently looking at opportunities and -- but just again when we just come back to returns on capital we see better returns on capitals from organic growth projects and what we’re seeing in the acquisition market.

Great. One quick clarification, the NGL conversion project is, is that you’re still sort of evaluating it, is it mainly trying to get contracts on a long-term basis for crude transportation there. Is that the main thing you’re still working on?

No, we’re just trying to see if it’s feasible. We’re not going to have a problem getting contracts with these spreads.

Your next question comes from Darren Horowitz with Raymond James.

And Jim congratulations on all the operational and financial record you got set this quarter. I’ve got a couple of questions on the gas processing segment, more specifically the outlook for what could be some pretty meaningful gross operating margin upside in the back half of this year. When you think about the ethane forward curve being backward dated and steep, it’s obviously tight in the prop months. And I think a lot of folks would call for inventories to further drop and we could see as a result of that a meaningful uplift in prices. So, how do you guys think about regional I think fracs swinging even more positive, the Conway to build you are widening further? You talked some lines on allocation. So can you just give us a sense for your ability to capture that upside potentially either on equity NGL volumes or on price? And what you think it could mean from a sustainability standpoint?

Justin, you got any thoughts on that? By the way Darren how about did you miss it?

It was obviously I missed it by a long shot.

Darren, this Brent again. I mean in terms of the ethane upside, there is a bunch of factors working in the favor of ethane prices. Now obviously demand is ramping up, pipelines are on allocations. So there is a fight for pipeline space between Conway purities and the recovery of ethane. And then I think Jim talked about just the overall tightness of frac space. So there is a reason the market is backward. I think from a company perspective, in the short-term, we could see some tightness in ethane. I think when Chinook comes online, when fracs come online, I think there is a case to be made that this kind of normalizes back to what we’ve seen over the last several years. Long-term, we don't necessarily see a case where there’s tightness in ethane. But I think over the short-term, I mean there is a fight for pipeline space. There is a fight for fractionation space. So I don't know how long this is going, six more months or nine more months, but there is some period of time where it gets back to normal.

Okay. And then just as a quick follow-up. And Jim you kind of mentioned this about the value uplift for propylene and the opportunity for you guys to consider doing another PDH. Do you think that we will get to a point even beyond the next iBDH plant that's coming online which obviously gives you more isobutylene exposure, but do you think we'll get to a point here soon where the market where they are between normal butane and high purity isobutylene could extend to where you guys could do another BDH facility and maybe we would start thinking about what that means out into 2020, 2021?

I kind a doubt it Darren, to be honest with you. But I doubt at BDH so.

Okay. I'm just trying to get a feel for as you guys think about upgrading this new for all of -- and getting that value uplift from a lot of purity product coming off your fracs. How you can best position yourself to get further downstream and capture that margin upside?

A lot is going to go across the docks.

Yes, I think that make sense. Thanks, guys. I appreciate it.

Your next question comes from Tristan Richardson with SunTrust.

Hey. Good morning, guys. Just a quick question on your Seaway terminal JV. Can you talk about nomination process for VLCC cargos and how maybe that differs from the ship channel? And just any visibility you have there for sort of these large chunky loading events?

It's a very similar process. I mean prior to the month, there will be nominations on the Houston asset and also whether it's a Seaway assets, the same sort of process.

And then just on the ethylene export project. You guys noted that the timeline was pulled forward a quarter there. Can you talk about what drove that acceleration, and if any of those factors could be applied to sort of other NGL projects in the portfolio?

It's just a matter of a little more detailed work from an outer project schedule with a contractor and being more confident in the timeframe we could bring that in.

Your next question is from Michael Blum with Wells Fargo.

Thanks. Good morning everyone. Just circling back, I’m wondering if you could give us some numbers around frac -- your current frac utilization and your current LPG export utilization and then any numbers you can throw around where you’re seeing the trends in terms of rates going forward? Thanks.

You want to answer? Utilization rates on the fracs and utilization rates on the exports.

Yes. We’re pretty highly utilized on the fracs versus [indiscernible]. On the frac side, I would say we now suppose we can get -- seeing over and over -- we’re doing everything we can to reoptimize to get more volume.

Yes. We have some fracs -- comps with wide grade as heavy as it is. We probably can’t get the throughput that it was designed for. But in reality, our fracs are virtually truck a block full, we move wide grade to Louisiana to try to fill those fracs up. We really run our fractionation regardless of where it is. We run it as if it was in a single location and we’re maximizing and optimizing the total. And like I said earlier, with an earlier question, we’re pulling levers to be able to take care our customers.

Michael this is Tony, from a production side, we’ve been publishing the slide for about a year. So, what we think happens as far as LPG exports that it has to happen, people like Enterprise that have existing capacity are going to expand it. That this LPG is headed further, there is no question.

Okay. And is there any way to quantify tight market sort of pricing power. Is there any way to quantify where you think the trends will go in terms of rates both for the frac market on a go forward basis for incremental capacity? And similarly you expand LPG or just renew contract kind of where things shake out versus where they are today from a pricing standpoint?

You mean, you’re talking about frac fees Michael?

Frac fees and LPG export taxes.

We used to get $0.12, $0.14 a gallon on LPG exports. That’s not -- and I don’t believe we’re going to get that in the future, but it’s not going to be $0.04 either, it’s going to be somewhere in the middle. In terms of frac fees, this is a good time to negotiate 10 year contracts if you could pull the levers to accommodate the volume, but I don’t know it’s going to -- I don’t know -- mid single-digits Brent?

I’d say going forward, I’m going to turn and go back to capital recovery for new fractionation if you believe the production number. So, I think it’s a fairly strong market, then certainly over the next 18 months or 20 months how long it takes to book fractionator, it’s value of frac space, it’s the value of crude commodity, I mean this has to keep flowing.

Your next question is from Dennis Coleman with Bank of America Merrill Lynch.

Hi. Good morning everyone, if I can I would just like to dig into the offshore terminal project a little bit. You talked about the gating factors being sort of permits and obviously customer interest. Which of those are sort of more buying it, is it permits, you talked about state and federal I think when you get out into the deeper water? Or is it customer demand? And for this, is it the international customers or it is the producers here, who are going to be the customers that support this?

I think potentially it’s both in terms of customers. And Graham how many agencies that you have to deal with in order to get this thing permitted?

That’s numerous. It falls under the Deepwater Port Act, but we’re probably on the order of 15 to 20 state and federal agencies, we'll have to deal with for the permit is complete.

So what kind of timeframe might that be?

Well up to 15 months on permitting granters at least.

I think we're probably looking at from this point anywhere 18 to 24 months.

And in fact we are developing our application for those permits and spending money to do that.

Jennifer, we have time for one more question?

And our final question comes from the line of Chris Sighinolfi with Jefferies.

Gotten me under the radar. Thanks for that guys. Appreciate all the color this morning. Jim, I have if I could two quick questions. One is just related to your dialogue with Shneur and Mike Blum on LPG exports and you've been having a long time, previously offered a lot of good color about what international buyers are thinking and what might bring them to the table in terms of contracting. Are they seeing things the way you're seeing and is there an activity level around towards the next batch of contracts on that?

I guess, are we seeing mid-customers, Chris?

When we look at it and agree with what Tony said in terms of there is a 1 million barrels a day of new fracs that has been announced through 2020, there is a lot of LPG available in the Gulf Coast that’s got to clear, are others willing to take that offtake, and are they willing to contract for it or is it likely to be more of a spot market activity? I'm curious where the international buyer is at this point?

Yes, well, I don't know that I can speak for them. We're pushing to get term contracts. We've recognized -- I’m getting to $0.12 to $0.14 a gallon, in retrospect I wish we’d have gone out at $0.07 or $0.08 a gallon, which still be the only connects towards still the end the Gulf Coast, but we [didn’t]. So we're pushing for term contracts. And I guess Brent we're seeing some -- or Justin, we're seeing some appetite for that?

I mean the guys who step up, I mean there hasn’t been a firmly market for last couple of years for them. It's the time to go hit them again for another commitment. Some of them have of less of an appetite. But at the end of the day, there is still the global short for LPGs and obviously US has a global long. These barrels will clear, they are not going to sit in storage and not going to sit on ground. And ultimately people will step up as Jim said, I think the fees are $0.12 to $0.13 I think that just got realistic.

Okay.

I think what Brent said and this is -- whether it's spot market or it's a term contract market, these barrels have to priced to export, if Tony is anywhere close to be in line.

Yes. And I guess related to that Jim, what would be the lead time on a new brownfield or greenfield expansion? I mean is that something you could do given how your activity level is today. Is that something to do with any year or is it more or like a two year timeframe we saw in the last ….?

This is Bob Sanders. There are steps we can take to probably pick up another 15% to 20% that will be in what I’ll call the sub year range. Graham new unit is?

18 to 24.

18 to 24.

Okay. And then if I could just switch gears guys, IMO 2020 has been actively discussed by the refined fleet. But I’m a little bit surprise that how little is discussed by other potentially impacted sectors. And so -- and just given the magnitude of your export activities and given the importance of exports in Tony’s supply demand modeling, I’m just wondering are you concerned at all about first aiming past 2020 or any other related impacts? Any thoughts there would be really appreciated.

Yes. This is Tony. Look, we look at IMO 2020 and it’s a positive, it’s a screaming positive for end prices position on the water, there’s just no question. So, we’ll see as that develops it’s good for US refiners, it’s a great for exports of US crude. I mean it’s a very low sulfur crude that the world is going to want, there is no question in our mind.

Sorry, is that positivity you see just because of the installed export capacity you have or is there something else you are seeing?

That’s a great question. It’s our access to crude that Jim talked about today, 4 million barrels, sitting there ready for export if it needs to be. It’s high access to water. It’s just that our entire infrastructure is really set up for displacement if you will and that’s what IMO 2020 is going to be.

Okay. Thanks a lot for the thoughts. I appreciate it.

Okay. Thank you, Chris. Jennifer, a few word before we end the call. Would you give our participants the replay information?

Absolutely. A replay for this call will be available beginning today at approximately 12:15 PM Central Time. And we’ll be available until August 8, 2018 at midnight. If you would like to access the replay for today’s call, please dial 855-859-2056, or 800-585-8867 or internationally at 404-537-3406. This will be an automated system and you will enter in the conference ID number of 9696849 to listen to the replay.

Okay. Thank you, Jennifer. And thank you everyone for participating with us on our call today. And have a good day. Good bye now.

Thank you for your participation. This does conclude today’s conference call. And you may now disconnect.