Enterprise Products Partners L.P. (EPD) Q2 2018 Earnings Conference Call Transcript

Enterprise Products Partners L.P. (EPD 1.41%)
Q2 2018 Earnings Conference Call
Aug. 1, 2018, 10:00 a.m. ET

Contents:

• Prepared Remarks
• Questions and Answers
• Call Participants

Prepared Remarks:

Operator

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. If you would like to ask a question during that time, you may simply press * followed by the number 1 on your telephone keypad. If you would like to withdraw your question, press the # key. Thank you. And I would like to turn the call over to Mr. Randy Burkhalter.

Randy Burkhalter -- Vice President, Investor Relations

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 exchange act of 1934 based on the beliefs of the company as well as assumptions made by any information currently available to Enterprise's management team.

Although management believes that the expectations are reflected in such forward-looking statements, we reasonably can give no assurance that such expectations will prove to be correct. Please refer to our latest filings with the FCC for a list of factors that may cause actual results to differ materially from those in the forward-looking statements made during the call. And with that, I'll turn the call over to Jim.

Jim Teague -- Chief Executive Officer

Thank you, Randy. As we said in this morning's press release, 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 repay nearing $1 billion year to date. This puts us well ahead of the equity self-funding goals we laid out for the fourth quarter last year. Let me just give you a list of facts from the second quarter that reflects just how strong our year is proving to be.

We set several operational records in this 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, ethylene 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.

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 per NGL pipelines and services was a record $913.7 million. Segment gross operating margin per petrochemical and refined products services was a record $281.8 million.

If I counted right, that's 14 operational and financial records. The 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 plan at Orla began operations and construction of two more plants are under way at Orla.

In addition, we announced a strategic bill 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 idled since 2012.

We concluded a successful open seasonal front range in Texas express pipelines and are under way on an expansion plan to support additional liquids from the DJ Basin. Lastly, we confirm 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.

The 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 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 it's operations, accounting, engineering, commercial, or wherever, we aren't departments, Enterprise people work as a team and that's what truly differentiates Enterprise. And with that, I'll give it to you, Bryan.

Bryan Bulawa -- Chief Financial Officer

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 that mitigated seasonality and accelerated the meaning of many of our financial objectives.

Specifically, we have reached our equity self-funding objective to the combination of strong, excess DCF 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, reiterate our expectations for our growth in 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 2017.

We recognize 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 facility, the Midland-to-ECHO pipeline, our Orla one gas processing plant and frack nine 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 frack nine. 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 depreciably mentioned Orla one 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 a 250,000-barrel per day to 550,000 per day project and the North Texas 36-inch natural gas pipeline expansion project.

Moving to our balance sheet. At June 30th, 2018, our total debt principal outstanding was $26 billion assuming the first call date for our hybrids. The average life of our portfolio was 14.6 years. Our effective average cost to debt was 4.5% and 89% of our debt portfolio is a fixed rate. Adjusted EBITDA for the 12 months ended June 30th, 2018 was $6.3 billion and our consolidated leverage ratio was 3.9 times 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 30th, 2018, which included available barring capacity under equips to lease 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 note 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 upsize commercial paper program to fund the redemption. We satisfied the replacement capital covenant aspect of the redemption through the issuance of Perry Pursue hybrids and equity issued through the DRIP during the past twelve 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 onto equity issuances, during the second quarter we received proceeds from the distribution reinvestment program in 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 Enterprise Products Company, or EPCO, elected to reinvest $106 million through 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 second quarter 2018 growth capital expenditures.

Year-to-date we have retained $948 million in excess distributable cash flow. As our chiefest 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 quarter of a penny per unit, per quarter and will reassess in 2019 our investment opportunities and alternatives for returning capital to investors. I will now turn the call over to Randy Fowler for some closing comments.

Randy Fowler -- President, Enterprise General Partner

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 of Mr. Market to explain market sentiment. Every day, Mr. Market tells us how he is valuing the work of a business. Some days he's enthusiastic and some days he is fearful. To provide some context for Mr. Market's current sentiment, we compare today to July 31st, 2015 three years ago. The 12-month forward curve for WTI crude oil futures 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 for unit for the first six months of 2018, compared to 2015, is up 26%. And our excess distributable cash flow for the first six months of this year, compared to 2015, is up 79%. In contrast, EPP's unit price was $28.33 on July 31, 2015. It closed yesterday at $29, up just 2%. 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.

Questions and Answers:

Operator

Thank you. If you would like to ask a question, please press * and the number 1 on your telephone keypad. Please limit yourself to one question and one follow-up question. We'll pause for just a moment to compile the Q&A roster.

And our first question comes from the line of Jeremy Tonet with JP Morgan.

Jeremy Tonet -- JP Morgan -- Analyst

Good morning. Congratulations on the strong quarter. Just wanted to touch base with regards to the crude oil segment. Results moved up quite a bit there and 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 water spreads that were captured or just how ratable was the print this quarter?

Brent Seacrest -- Senior Vice President, Liquid Hydrocarbons Marketing

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 average 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've got close to 800,000 barrels a day, cost for docks. So it's mainly just overall throughput on the crude system.

Jeremy Tonet -- JP Morgan -- Analyst

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

Brent Seacrest -- Senior Vice President, Liquid Hydrocarbons Marketing

Well, what we had was a heck of a lot lower than what we could've done if we had not hedged. What, $3.00, on average? Randy, what do you think?

Jim Teague -- Chief Executive Officer

Yes. And Jeremy, I'd go 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. But we had 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, the capacity lease on Rancho, I think you've just look year-over-year, that contributed between $95 million and $100 million of year-over-year growth.

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'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.

Brent Seacrest -- Senior Vice President, Liquid Hydrocarbons Marketing

But also in saying that, Randy, what we're seeing is that our docks are a bit coming more valuable so I think there's an offset there.

Jeremy Tonet -- JP Morgan -- Analyst

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

Brent Seacrest -- Senior Vice President, Liquid Hydrocarbons Marketing

As far as NGLs conversion, Jeremy, we're still evaluating that. On Seaway -- is Jay in here?

Jim Teague -- Chief Executive Officer

No, but I'll take that. We're evaluating expanding Seaway. I think there are others out there doing the same thing. The one that we can do immediately is we're adding DRA to Seaway II and that'll be online in September and that adds about 100,000 barrels a day of capacity. So that'll take us to about 950. It depends on the mix of crude but just call it 950.

Operator

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

Colton Bean -- Tudor, Pickering, Holt -- Analyst

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

Jim Teague -- Chief Executive Officer

I think we're still deep in the weeds on the offshore terminal as to what the market will bear. I'm thinking, what, a $1.25?

Brent Seacrest -- Senior Vice President, Liquid Hydrocarbons Marketing

I think incrementally their numbers are notionally correct on crude export, flooding fees, then if you look at the incremental for that dock I'd probably add around $0.50. But to me, there's a lot of value chain upside with that investment.

Colton Bean -- Tudor, Pickering, Holt -- Analyst

Got it. Very helpful. Then I guess just on the NGL pipeline at work as to the release noted about 120,000 uptakes on Seminole and Chaparral but Maple was quite a bit lower -- just 30. So does that indicate that effectively, or the vast majority at least of that increase on Seminole and Chaparral were Permian volumes, not a whole lot of locky slow through? And I guess if so, kind of to Jeremy's question, how much capacity is remaining on that legacy system at this point?

Brent Seacrest -- Senior Vice President, Liquid Hydrocarbons Marketing

Volume metrically, Maple was up but we're on allocation on 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've seen a lot of Permian volumes come through. Our Rockies lines are maintaining as well so I wouldn't say it's a negative in the sense of the Rockies lines trimming off.

Jim Teague -- Chief Executive Officer

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.

Operator

Your next question comes from Shneur Gershuni with UBS.

Shneur Gershuni -- UBS -- Analyst

I guess I just wanted to start off -- 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 this system?

Are you able to move up the timeline of converting and NGL line to crude once Shin Oak comes into service? Could we see another frack 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 are multiple ways for you to continue growing over the next year or so.

Jim Teague -- Chief Executive Officer

I think the answer is yes. I'll let Tony and Randy step in. Yes, there's an NGL conversion. I think all we're saying is we're still in the evaluation mode. In terms of more fractionation, after we built the fourth train I said, we're never gonna build another fractionator. And now we're bringing out the ninth train and looking at the tenth train and see opportunities that probably add more and I've got Randa Duncan snapping the whip wanting to build more trains.

So yeah, there are opportunities for more fractionation. I think there are opportunities for another PDH and in fact, we're working that hard but 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 are value chain opportunities associated with an offshore port, we believe we're gonna need more LPG export capacity.

If you look at our forecast, Tony's group publishes that soon. I think what you'll see is that Tony, our fundamentals group, is predicting that there'll 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 town facility. Does that answer it?

Shneur Gershuni -- UBS -- Analyst

It does. Maybe as a 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 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 thought to turning the drip off it 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?

Bryan Bulawa -- Chief Financial Officer

I appreciate the question and quite frankly, all of those options remain certainly on the table. I would say that it's 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'd rather look for opportunities to continue to grow and to extend the life and durability of our partnership.

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 unitholders.

Shneur Gershuni -- UBS -- Analyst

Alright, great, I guess we'll leave it up to Mr. Market.

Operator

Your next question comes from Jean Ann Salisbury with Bernstein.

Jean Ann Salisbury -- Bernstein -- Analyst

Good morning. Everyone is talking about looming Mont Belvieu fractionation capacity storages over the next year. What happens in this scenario and how can Enterprise benefit? Can you flex the fees upwards on any of our fracks or use wide grade storage?

Jim Teague -- Chief Executive Officer

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

Jean Ann Salisbury -- Bernstein -- Analyst

Okay, that makes sense. And do you have significant y-grade storage at Mont Belvieu or around it?

Jim Teague -- Chief Executive Officer

We've got a lot of storage. Our storage y-grade probably not something we're gonna do but we'd certainly be willing to store people's y-grade for them.

Jean Ann Salisbury -- Bernstein -- Analyst

Thank you. And you have 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 an end of that change with the newly announced project?

Bryan Bulawa -- Chief Financial Officer

I think that number's north of 2 million barrels a day just crude specific. 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.

Jim Teague -- Chief Executive Officer

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

Operator

Your next question comes from Keith Stanley with Wolfe Research.

Keith Stanley ­-- Wolfe Research -- Analyst

Hi, good morning. 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? 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?

Bryan Bulawa -- Chief Financial Officer

For 2019, I think we probably have pretty clear visibility to $2.5 million. So your range, a 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 then we're trying to pull some expenditures forward as well out of 2019 in 2018.

Keith Stanley ­-- Wolfe Research -- Analyst

Got it, OK. And then, changing subjects a little. 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?

Jim Teague -- Chief Executive Officer

I'm gonna 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 just got to fit our system. It's got to be something that's additive to what we already have.

Randy Fowler -- President, Enterprise General Partner

We're consistently looking at opportunities but just, again, when we come back to returns on capital we see better returns on capital from organic growth projects than what we see in the acquisition market.

Keith Stanley ­-- Wolfe Research -- Analyst

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 for crude transportation there? Is that the main thing you're still working on?

Jim Teague -- Chief Executive Officer

We're just trying to see if it's feasible. We're not gonna have a problem getting contracts with these sprints.

Operator

Your next question comes from Darren Horowitz with Raymond James.

Darren Horowitz -- Raymond James -- Analyst

Hey guys, good morning. And Jim, congratulations on all the operational and financial records you guys set this quarter. I've got a couple 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 in steep, it's obviously tight in the prior 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 fracks swinging even more positive, the Conway to Belvieu are widening further. You talked about some lines and 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?

Jim Teague -- Chief Executive Officer

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

Darren Horowitz -- Raymond James -- Analyst

Obviously, I missed it by a long shot.

Brent Seacrest -- Senior Vice President, Liquid Hydrocarbons Marketing

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 are in allocation so there's a fight for pipeline space between Conway Purities and the recovery of ethane. I think Jean Ann talked about just the overall tightness of frack 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 fracks 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 -- there's a fight for pipeline space, there's a fight for fractionation space. I don't know how long this is gonna last, I don't know if it's six more months or nine more months but there's some period of time where it gets back to normal.

Darren Horowitz -- Raymond James -- Analyst

Great. 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'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 or the ARB 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 in the 2020, 2021?

Jim Teague -- Chief Executive Officer

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

Darren Horowitz -- Raymond James -- Analyst

Okay. I'm just trying to get a feel for as you guys think about upgrading to seafloor olefins and getting that value uplift from a lot of purity product coming off your fracks, how you can best position yourself to get further downstream and capture that margin upside.

Jim Teague -- Chief Executive Officer

A lot of it's gonna go across the docks.

Darren Horowitz -- Raymond James -- Analyst

I think that makes sense. Thanks, guys, I appreciate it.

Operator

Your next question comes from Tristan Richardson with SunTrust.

Tristan Richardson -- SunTrust -- Analyst

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

Brent Seacrest -- Senior Vice President, Liquid Hydrocarbons Marketing

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

Tristan Richardson -- SunTrust -- Analyst

Helpful. Thank you, guys. 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?

Jim Teague -- Chief Executive Officer

It's just a matter of a little more detail work; firming up the project schedule with a contractor and being more competent in the timeframe we could bring that in.

Operator

Your next question is from Michael Bloom with Wells Fargo.

Michael Blum -- Wells Fargo -- Analyst

Thanks, good morning everyone. Just to go back -- wondered if you could put some numbers around your current frack 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.

Jim Teague -- Chief Executive Officer

We're pretty highly utilized on the fracks.

...

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

Jim Teague -- Chief Executive Officer

We had some fracks. You take Hobbes, with the y-grade bin as heavy as it is, we probably can't get the throughput that it was designed for. But in reality, our fracks are virtually chock-a-block full. We move y-grade to Louisiana to try to fill those fracks 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. Like I said in an earlier question, we're pulling levers to be able to take care of customers.

Tony Chovanec -- Vice President, Fundamentals and Supply Appraisal

Michael, this is Tony, from a production side we've been publishing a slide for about a year. It 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. That this LPG is headed for the water, there is no question.

Michael Blum -- Wells Fargo -- Analyst

Is there any way to quantify some of it? You know, the tight market pricing power, you don't really quantify where you think the trends will go in terms of rates for the frack market on a go forward basis for incremental capacity and similarly, if you'll expand LPG or just renew contracts, kind of where things shake out versus where they are today from a pricing standpoint.

Jim Teague -- Chief Executive Officer

You're talking about frack fees, Michael?

Michael Blum -- Wells Fargo -- Analyst

Frack fees and LPG export dock fees.

Jim Teague -- Chief Executive Officer

We used to get $0.12, $0.14 a gallon on LPG exports. I don't believe we're gonna get that in the future but it's not gonna be $0.04 either. It's gonna be somewhere in the middle. In terms of frack 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 gonna -- I'd say mid-single digits.

Brent Seacrest -- Senior Vice President, Liquid Hydrocarbons Marketing

I'd say going forward it's gonna go back to capital recovery for new fractionation if you believe the production numbers. I think it's a fairly strong market. Certainly, over the next 18 months, or 20 months, however long it takes to build a fractionator. The value of frack space is the value of crude commodity. This stuff has to keep flowing.

Operator

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

Dennis Coleman -- Bank of America Merrill Lynch -- Analyst

Good morning, everyone. 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? In 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 is it the producers here? Who are gonna be the customers that support this?

Jim Teague -- Chief Executive Officer

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?

Graham Bacon -- Executive Vice President

It's numerous. It falls under the Deepwater Port Act but it's probably on the order of 15 to 20 statements that our agencies will have to deal with before the permit is complete.

Dennis Coleman -- Bank of America Merrill Lynch -- Analyst

So what kind of timeframe might that be?

Jim Teague -- Chief Executive Officer

12 to 15 months on permitting, Graham?

Graham Bacon -- Executive Vice President

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

Jim Teague -- Chief Executive Officer

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

Operator

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

Chris Sighinolfi -- Jefferies -- Analyst

Kind of there 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 the dialogue with Shneur and Michael 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 the next batch of contracts on that?

Jim Teague -- Chief Executive Officer

Are you asking me, are we seeing new customers?

Chris Sighinolfi -- Jefferies -- Analyst

I'm saying; when we look at it and agree with what Tony said in terms of there are a million barrels a day of new fracks that have been announced through 2020, there's a lot of LPG available on the gulf coast. It's got to clear. Are others willing to take that off take 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.

Jim Teague -- Chief Executive Officer

I don't know that I can speak for them. We're pushing to get term contracts. We recognize that you're not gonna get them at $0.12 to $0.14 a gallon. In retrospect, I wish we would've 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 we're pushing for term contracts and I guess we're seeing some appetite for that.

Brent Seacrest -- Senior Vice President, Liquid Hydrocarbons Marketing

The guys who stepped up -- I mean, it 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 the day, there's still a global short for LPG and obviously, the US has the global long. These barrels will clear. They're not gonna sit in storage. They're not gonna 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.

Jim Teague -- Chief Executive Officer

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

Chris Sighinolfi -- Jefferies -- Analyst

And I guess related to that, Jim, what would be the lead-time on a new brownfield or greenfield expansion? Is that something you could do given your activity level today? Is that something you could do within a year? Or is it more like the two-year timeframe we saw in the last round?

Bob Sanders -- Senior Vice President, Asset Optimization

There's steps we can take to probably pick up another 15% to 20% that will be in, what I call, the sub-year range. Granted, a new unit is 18 to 24.

Chris Sighinolfi -- Jefferies -- Analyst

And then, if I could just switch gears, guys. IMO 2020 is gonna actively discuss by the refined fleet. But I'm a little bit surprised at how little its discussed by other potentially impacted sectors. 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 slow steaming past 2020 or any other related impact? Any thought there would be really appreciated.

Tony Chovanec -- Vice President, Fundamentals and Supply Appraisal

We look at IMO 2020 and it's a positive, it's just screaming positive for Enterprise's position on the water, there's just no question. We'll see as that develops. It's good for US refiners; it's great for exports of US crude. It's a very low sulfur crude that the world is going to want, there's just no question in our mind.

Chris Sighinolfi -- Jefferies -- Analyst

Is that positivity you see just because of the installed export capacity you have? Or is there something else you're seeing?

Tony Chovanec -- Vice President, Fundamentals and Supply Appraisal

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.

Randy Burkhalter -- Vice President, Investor Relations Thanks, Chris. Jennifer, if you would, before we end the call, would you give our participants the replay information?

Operator

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 8th, 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 9696849 to listen to the replay.

Randy Burkhalter -- Vice President, Investor Relations

Thank you, Jennifer, and thank you, everyone, for participating with us on our call today and have a good day. Goodbye now.

Operator

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

Duration: 49 minutes

Call participants:

Randy Burkhalter -- Vice President, Investor Relations

Jim Teague -- Chief Executive Officer

Bryan Bulawa -- Chief Financial Officer

Randy Fowler -- President, Enterprise General Partner

Jeremy Tonet -- JP Morgan -- Analyst

Colton Bean -- Tudor, Pickering, Holt -- Analyst

Brent Seacrest -- Senior Vice President, Liquid Hydrocarbons Marketing

Shneur Gershuni -- UBS -- Analyst

Jean Ann Salisbury -- Bernstein -- Analyst

Keith Stanley ­-- Wolfe Research -- Analyst

Darren Horowitz -- Raymond James -- Analyst

Tristan Richardson -- SunTrust -- Analyst

Michael Blum -- Wells Fargo -- Analyst

Tony Chovanec -- Vice President, Fundamentals and Supply Appraisal

Dennis Coleman -- Bank of America Merrill Lynch -- Analyst

Graham Bacon -- Executive Vice President

Chris Sighinolfi -- Jefferies -- Analyst

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