Enterprise Products Partners LP (EPD) 2018 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 L.P. Second Quarter 2018 Earnings Call. (Operator Instructions) 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, 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 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 will turn the call over to Jim.

Thank you, Randy. As we said in this morning's press release, our business continues -- 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 1.5x coverage of the quarterly distribution, which has allowed us to retain nearly a $1 billion year-to-date. This puts us well ahead of the equity self-funding goals we laid out at the 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 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'm 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 a barrel equivalent pipeline transportation volumes were almost 10 million barrels a day at 9.82 million barrels. I'm 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 & Services was a record $913.7 million. Segment gross operating margin for Petrochemical and Refined Products Services was a record $281.8 million. If I've 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 the gathering and processing area, we announced that our first plant at Orla began operations and construction of 2 more plants are underway at Orla. In addition, we announced a strategic deal for all of the NGLs from Apache's Alpine High discovery in the Permian.

Production from this basin will support our Shin Oak 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 idle since 2012.

We concluded a successful open season on Front Range and Texas Express pipelines and are underway on 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 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 a vessel bunker fueling service at the Ship Channel facility, which is a nice add-on for Enterprise and timesaver 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 exports, propylene exports 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 become -- 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 3 years, we have been very open about our long-term outlook for U.S. 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 today by thanking the Enterprise people, we don't do that enough. These are the same people that performed historically during Harvey, and these are the people that made this record-setting quarter possible. Whether its operations, accounting, engineering, commercial or wherever, we aren't 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 financial performance during the second quarter, which is traditionally a weaker seasonal period. We clearly benefited from improving fundamentals and contributions from new assets that mitigated seasonality and accelerated the meeting of many of our financial objectives. Specifically, we have reached our equity self-funding objective through the combination of strong excess DCF and proceeds from our distribution reinvestment program, leaving 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 but be excited about 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, reiterate 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 noncash mark-to-market loss during the second quarter of 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 facility, the Midland-to-ECHO pipeline, our Orla I 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 put 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 $350 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 I gas plant and our ninth 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 Shin Oak upon start up 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 hybrids. 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 3.9x after adjusting debt for the partial equity treatment of the 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 our 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 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, had 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 24 and is expected to result in annual interest savings of approximately $19 million and a modest increase to leverage of 0.04x.

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 11 of 2017.

With respect to the upcoming August 8 distribution payment, private affiliates of Enterprise Products Company, or EPCO, elected to reinvest $106 million to the DRIP program. This brings their total reinvestments through 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 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 enhanced 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 through 2019.

With respect to our approach on distribution growth, I'd like to reiterate comments we've made on previous calls. We intend to continue recommending to our Board to grow our quarterly distributions in 2018 at a $.025 per unit per quarter, and we will 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 re-read a few chapters in Benjamin Graham's classic The Intelligent Investor. As many of you recall, Mr. Graham uses the metaphor of Mr. Market to explain market sentiment. Every day, Mr. Market tells us how he is valuing the worth of a business. Some days, he is enthusiastic. And some days, he's fearful. To provide some context for Mr. Market's current sentiment, we compare today to July 31, 2015, 3 years ago. The 12-month forward curve for WTI crude oil futures is up 32%. Enterprise's distributable cash flow for the first 6 months of this year compared to the first 6 months of 2015 is up 40%.

Similarly, distributable cash flow per unit for the first 6 months of 2018 compared to 2015 is up 26%. And our excess distributable cash flow for the first 6 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 postulate that when Mr. Market is fearful, there can be good opportunities for value-oriented investors.

Randy with that, we can open it up for questions.

Thank you, Randy. Jennifer, we are ready to take questions from our participants.

(Operator Instructions) And our first question comes from the line of Jeremy Tonet with JPMorgan.

Just want to touch base with regards 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 wider spreads that were captured? Or just how ratable was the print this quarter?

This is Brent Secrest. A lot of it 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 mainly just overall throughput on the crude system.

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

Well, what we hedged was a heck of a lot lower than what we could have done if we had not hedged. So $3 on average, Randy, what do you think?

Yes. Jeremy I'd note just a little bit just as we're -- if you would, ramping up 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 they'll continue to ramp up through 2020. We had more opportunity to come in and contract it at higher rates. And so that's where, just focusing on the Midland-to-Sealy aspect, along with if you would the 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 top number may be 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 it will be in that $100 million a quarter area, on Midland-to-Sealy anyway.

In addition Randy, what we're seeing is that docks are becoming more valuable. So I think there's an offset there.

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

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

I'll take that. We are 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. And 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 crude, but just call it 950.

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

So just sticking with the crude oil segment there. I think you called out about a $14 million step-up for the Houston terminal on export loadings. Just given the volume increase that you guys saw, it looks like may be 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 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, $1.00 or $1.25.

I think -- incrementally, I think your number's notionally correct on kind of crude export, loading fees. And then if you look at the incremental for a -- for that dock, at probably at around $0.50. But to me, there's a lot of value chain upside with that investment.

Got it. Very helpful. And then just on the NGL pipeline network. So the release noted about 120,000 uptick on Seminole and Chaparral but MAPL was quite a bit lower, just 30. So does that indicate that, I mean, effectively are the vast majority at least of that increase on Seminole and Chaparral were Permian volumes, not a whole of Rockies 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, MAPL was up, but run allocation in a lot of our pipelines right now. And variable cost is higher. Transportation costs are higher. We're moving every single gallon we can but the specific answer to your question in regards to Permian, we're seeing a lot of Permian volumes come through, but Rockies lines are maintained as well. So I want to say it's negative in the sense that Rockies lines are turning off.

I think what he just said is we're on allocation and we probably don't have any incremental capacity until we bring on Shin Oak.

Your next question comes from Shneur Gershuni with UBS.

I guess, I just wanted to start off. I mean, you just printed a very strong quarter. And it's 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 the time line of converting an NGL to crude once Shin Oak 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 it because it seems like there's 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. Yes, there's -- on the NGL conversion, I think all we're saying is, we're still in the evaluation mode. In terms of more fractionation, you know, after we built the 4th train I said, we're never going to build another fractionator. And now we're bringing up the 9th train and looking at the 10th train and see opportunities that probably add more. I've got Randa Duncan snapping the whip, wanting to build more trains. So yes, there's opportunities for more fractionation. I think there's 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's a strong possibility we'll build another PDH. In terms of LPG exports, when Brent said, there's 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 -- do you publish that?

Yes, sir.

Tony's group publishes that. Soon? I think what you will see is that Tony -- our fundamentals group is predicting that there will be more LPG export capacity required. So to the extent if we're able to pull off an offshore port, that gives us the opportunity to put more LPG through our Ship Channel facility. Does that answer it?

It does. Maybe as a follow-up. Bryan, you mentioned in your prepared remark that you've generated $948 million of excess DCF in the first half of this year and expect to continue to be able to fund and so forth. I realize you've sort of stated the distribution growth goal 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 the 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?

I think it's still -- I appreciate the question. And quite frankly, all those options remain certainly on the table. I would say that probably 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 than look for opportunities to buy back our units. We would rather look for opportunities to continue to grow and to extend the life of the durability of our partnership. So there's really no more guidance to give you except that all those items that you brought up are yes, those are the items that we debate. And then you have to also -- one thing you didn't bring up is they 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 unit holders.

Your next question comes from Jean Salisbury with Bernstein.

Everyone is talking about looming Mont Belvieu fractionation capacity shortages over the next year. What happens in this scenario? And how can Enterprise benefit? Can you flex the fee rates up on any of your fracs or use Y-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 on any new frac deal you do. And we are in the process of pulling a few levers.

Okay. That make sense. And do you have significant Y-grade storage at Mont Belvieu or around it?

We've got a lot of storage. But us storing Y-grade is probably not something we're going to do, but we'd certainly be willing to store people's Y-grade for them.

Got it. Yes, that make sense. And you have, I guess, up to the 4 million barrels a day of export capacity from Houston. But some of that space is needed for refined products and imports and stuff, do you guys 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 crude specific -- and that's just Houston. It doesn't include Texas City, Freeport, Beaumont. 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. We also have the capability to load crude. And we have before when the crude down to Texas City and loaded it out of our Seaway dock that we share with Enbridge. And Bob just said we could do a over a million barrels a day there.

Same number in Freeport.

Your next question comes from Keith Stanley with Wolfe Research.

Just on CapEx, Bryan, just any more color on what's driving the increase specifically for 2018? Is it just Shin Oak 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 of $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 Shin Oak, that's probably the largest contributor. And 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 have enough to do organically and see more value in growing organically from here?

I'm going to throw it to Randy, but first, Randy has a saying that I think we embrace and that is: price matters. But what also matters is it's got to fit our system. And it's got 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 capital from organic growth projects than what we're seeing in the acquisition market.

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

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.

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 backwardated to steep. It's obviously tight in the [prop] months. And I think a lot of folks are calling for ethane 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 ethane fracs swinging even more positive, the Conway to Belvieu arb widening further? You talked about 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 bad did you miss it?

It was -- obviously, I missed it by a long shot.

Darren, this is Brent again. I mean, in terms of the ethane upside, there's a bunch of factors working in the favor of ethane prices now. Obviously, demand's ramping up. Pipelines run allocations. So there's a fight for pipeline space between Conway purities and the recovery of ethane. And then I think Jean Ann talked about just the overall tightness of frac space. So there's a reason the market's backward. I think from a company perspective, in the short term, we could see some tightness in ethane. I think when Shin Oak comes online, when fracs come online, I think there's 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's a fight for pipeline space. There's a fight for fractionation space. So I don't know how long this is going to last, I don't know if it's 6 more months or 9 more months. But there's some period of time when it gets back to normal.

Okay. And then just as a quick follow-up. And Jim, you kind mentioned this about the value uplift for propylene and the opportunity for you guys to consider doing another PDH. Do you think that we'll 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 for the arb between normal butane and high-purity isobutylene could extend to where you guys could do another iBDH facility? And maybe we would start thinking about what that means out into 2020, 2021?

I kind of doubt it, Darren, to be honest with you, but I doubted PDH, so...

Okay. I'm just trying to get a feel for as you think guys think about upgrading to C4 olefins 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 of it is going to go across the docks.

Your next question comes from Tristan Richardson with SunTrust.

Just a quick question on your Seaway terminal JV. Can you talk about the nomination process for VLCC cargos? And how maybe that differs from the Ship Channel and just any visibility you have there for some of these large chunky loading events?

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

Helpful. And then just on the ethylene export project, you noted the time line 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 firming up the project schedule with the contractor and being more confident in the time frame we could bring that in.

Your next question is from Michael Blum with Wells Fargo.

To circle back, I wonder if you could list 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?

You want to answer?

We're pretty highly utilized on the fracs.

On the frac side, I would say we're about as full as we can get and we're -- you heard the theme over and over, we're doing everything we can to reoptimize to get more volume.

We have some fracs, take Hobbs, with Y-grade being as heavy as it is we probably can't get the throughput that it was designed for. But in reality, our fracs are virtually chockablock full. We move to Y-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 maximize and optimize the total. And like I said earlier with the earlier question, we're pulling levers to be able to take care of customers.

This is Tony. From the production side, we've been publishing a slide for about a year that shows what we think happens as far as LPG exports, that it has to happen. That people like Enterprise that have existing capacity are going to expand it. This LPG is headed for the water, there's no question.

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

I mean, you're talking about frac fees, Michael?

Frac fees and LPG export dock fees.

We used to get $0.12, $0.14 a gallon on LPG exports. That's not -- 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 think you're going to end up with...

I don't know.

Mid-single digits, Brent?

Instead of going forward, I mean it's going to go back to capital recovery for new fractionation if you believe the production numbers. So I think it's a fairly strong market. And then, certainly, over the next 18 months or 20 months, however long it takes to build a fractionator, the value of frac space is the value of crude commodity. I mean, this stuff has to keep flowing.

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

If I can I'd 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 is sort of more biting it? The permits, you're talking about state and federal, I think when you get out into the deeper water, or is it customer demand. And for this, is it international customers? Or 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 do you have to deal with in order to get this thing permitted?

It's numerous, it falls under the Deepwater Port Act, but there's probably on the order of 15 to 20 state and federal licenses we have to deal with before the permit is complete.

So what kind of time frame might that be?

We're up to 15 months on permitting, Graham? Or is that aggressive?

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 Christopher Sighinolfi with Jefferies.

Jim, I have, if I could, 2 quick questions. One is just related to your dialogue with Shneur and Michael Blum on LPG exports. You've been at it a long time, you've 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 it? Is there an activity level around sort of next batch of contracts on that?

Are you asking me are we seeing new customers or...

I'm saying when we look at it and agree with what Tony said in terms of there's a million barrels a day of new fracs that have been announced through 2020, there's 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 with you for it? Or is it likely to be more of a spot market activity? I'm just curious where an international buyer is at this point?

Well, I don't know that I can't speak for them. We're pushing to get term contracts. We recognize that you're not going to get them at $0.12 to $.14 a gallon. In retrospect, I wish we'd have gone out at $0.07 or $0.08 a gallon, we'd still be the only export facility on the Gulf Coast, but we didn't. So yes, we're pushing for term contracts. And I guess, Brent, or Justin, we're seeing some appetite for that.

Yes. I mean, the guys who stepped up, I mean, there hasn't been a friendly market for the last couple of years for them so trying to go hit them again, for another commitment -- some of them have a less of an appetite. But at the end of day, there's still a global short for LPG so obviously the U.S. has the global long. These barrels will clear. They're not going to sit in storage, they're not going to sit in the ground. And ultimately, people will step up. But as Jim said, I think the fees of $0.12 to $0.13, I think, is just not realistic.

I think what Brent is saying, whether it's a spot market or it's a term contract market, these barrels have to price to export, if Tony is anywhere close to being right.

Yes. And I guess, related to that, Jim, what so -- 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 you could do within a year? Or is it more like the 2-year time frame we saw in the last...

This is, Bob Sanders, there's 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, a new unit is...

18 to 24.

18 to 24.

Okay. And then if I could just switch gears, IMO 2020 has been actively discussed by the refined fleet. But I'm a little bit surprised by how little it's discussed by other potentially impacted sectors. And so 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 slow steaming past 2020? Or any other related impacts? Any thoughts there will be really appreciated.

Yes. This is Tony. Look, we look at IMO 2020, and it's a positive. It's just screaming positive for Enterprise's position on the water. This's no question. So we'll see as that develops. It's good for U.S. refiners. It's great for exports of U.S. crude. I mean, it's a very low-sulphur crude that the world is going to want. There's just 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.

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 our access to water. It's just our entire infrastructure is really set up for displacement, if you will. And that's what IMO 2020 is going to be.

Jennifer, if you would, 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 p.m. Central Time, and will 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) 585-8367 or internationally at (404) 537-3406. This will be an automated system, and you will enter in the conference ID number of 969-6849 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. Goodbye now.

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