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 Product Partners LC Second Quarter 2018 Earnings Call. All lines have been placed on mute to press any background noise. After the speakers' remarks, there will be a question and answer session.
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 2nd quarter earnings. Our speakers today will be Jim Tee, Chief Executive Officer Brian Bilalward, 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 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 the Q2 in a row, we provided 1.5 times coverage of the quarterly distribution, which has allowed us to retain nearly $1,000,000,000 year to date. This puts us well ahead of the equity self funding goals we laid out in the Q4 last year.
Let me just give you a list of facts from the Q2 that reflect just how strong our year is proving to be. We set several operational records in the Q2. Natural Gas Liquid Pipeline Transportation volumes were a record 3,410,000 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 transportation volumes were a record 2,050,000 barrels a day. Crude marine terminal volumes
were a
record 802,000 barrels a day. Overall, NGL Crude, Petrochemical and Refined Products Marine Terminal propane production was a record £19,300,000 a day. Overall, NGL Crude, Petrochemical and Refined Products pipeline transportation volumes were a record 6 point 23,000,000 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 10,000,000 barrels a day at 9,820,000 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 $1,430,000,000 Adjusted EBITDA was a record $1,770,000,000 Segment gross operating margin Petrochemical and Refine Products Services was a record $281,800,000 If I counted right, that's 14 operational and financial records. The Q2 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 fifty-fifty joint venture with Energy Transfer. Let me repeat that. We also announced the formation of a fifty-fifty 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 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 time saver for us and our dock customers.
And we're happy to report that our PDH plant ran at capacity in the 2nd 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 4,000,000 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. With that, I'll give it to you, Brian.
Thank you, Jim, and good morning, everyone. As Jim outlined earlier, we achieved record operational and financial performance during the Q2, which is traditionally a weaker seasonal period. We clearly benefited from improving fundamentals in 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, leading us comfortably within our targeted leverage range without taking into account any pro form a 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 Q2, 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 Q2 of 2018 was $673,800,000 or $0.31 per unit on a fully diluted basis compared to $653,700,000 or 0.30 dollars per unit on a fully diluted basis for the Q2 of 2017. We recognized a total of $322,000,000 or $0.15 per unit in a non cash mark to market loss during the Q2 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 twenty eighteen and into 2019. Depreciation, amortization and accretion expenses were $46,000,000 higher when compared to the same quarter of 2017 due to the PDH facility, the Midland to Echo pipeline, our Orla 1 gas processing plant and Frac 9 being placed into service since the Q2 of 2017.
Interest expense was $275,000,000 for the Q2 of 2018 compared to $246,000,000 for Q2 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 Echo Pipeline and Frac 9. Total capital spending in the Q2 of 2018 was $910,000,000 including $73,000,000 for sustaining capital expenditures. For the first half of the year, total capital spending was approximately 2 $100,000,000 including $235,000,000 in acquisitions and $140,000,000 in sustaining capital. We now anticipate spending $3,800,000,000 to $4,000,000,000 in capital expenditures for the full year and approximately $315,000,000 on sustaining capital expenditures.
We placed approximately $1,100,000,000 of growth capital projects into service during the Q2 of 2018, including the previously mentioned Orla 1 gas plant and our 9th fractionator in Mont Belvieu. We currently have an additional $5,200,000,000 of projects under construction through 2020. The primary additions are increased capacity on Shin Oak upon startup from a 250,000 barrel per day to a 550,000 barrel per day project and the North Texas 36 inches natural gas pipeline expansion project. Moving to our balance sheet, at June 30, 2018, our total debt principal outstanding was $26,000,000,000 assuming the first call date for our 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 $6,300,000,000 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 $1,000,000,000 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 $2,500,000,000 to $3,000,000,000 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 $521,000,000 junior subordinated notes A due in 2,066 6, which are subject to a quarterly rate reset and as of July 31, 2018 an effective interest rate of 6.066 percent.
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 $19,000,000 and a modest increase to leverage of 0.04 times. Moving on to equity issuances, during the Q2 we received proceeds from the distribution reinvestment unit purchase program of approximately $84,000,000 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, 2017.
With respect to the upcoming August 8 distribution payment, private affiliates of Enterprise Products Company or EPCO elected to reinvest $106,000,000 through the DRIP program. This brings their total reinvestments through the DRIP to $206,000,000 year to date demonstrating their continued long term support of the partnership. We retained $491,000,000 in excess distributable cash flow in the quarter, which alone funded 54% or approximately 54% of our Q2 2018 growth capital expenditures. Year to date, we have retained $948,000,000 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 $35,000,000 to $36,000,000 incremental units.
And as we continue to announce incremental growth projects, we remain confident in our ability to self fund the equity 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 $0.25 per unit per quarter and we'll 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.
Thanks, Brian. 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 worth of a business. Some days 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, 3 years ago.
The 12 month forward curve for WTI crude oil futures is up 32%. Enterprise's distributable cash flow for the 1st 6 months of this year compared to the 1st 6 months of 2015 is up 40%. Similarly, distributable cash flow per unit for the 1st 6 months of 2018 compared to 2015 is up 26% and our excess distributable cash flow for the 1st 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%.
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 now open it up for questions.
Thank you, Randy. Jennifer, we're ready to take questions from our participants.
Thank you. And our first question comes from the line of Jeremy Tonet with JPMorgan.
Good morning. Congratulations on the strong quarter.
Thank you.
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 margins? 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 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 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 3.90 a ratable number or is it something lower like 3.50?
Well, what we hedged was a heck of a lot lower than what we could have done if we had not hedged. So
what dollars
3 on average, Randy, what do you think?
Yes. And Jeremy, I'd go in 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 2nd 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. 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 $95,000,000 $100,000,000 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 $65,000,000 to $70,000,000 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 100,000,000 dollars a quarter area on Midland to Seadling anyway.
But then also in saying that, Randy, what we're seeing 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's a very immediate need for evacuation from the Permian and 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 a similar type of question with Seaway as well?
Yes. As far as NGLs 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'll be online in September and that adds about 100,000 barrels a day of capacity. So that'll 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.
Good morning. So just sticking with the crude oil segment there, I think you called out about a $14,000,000 step up for the Houston terminal on 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? Are there any major differences that we should be aware of either to the up or the downside there?
Yes, 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 $1.25 Yes,
I think incrementally, I think your number is notionally correct on kind of crude export loading fees. And then if you look at the incremental for that dock, that's probably at around $0.50 But to me, there's a lot of value chain upside with that investment.
Got it. Very helpful.
And I guess 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 or the vast majority at least of that increase on Seminole and Chaparral were Permian volumes, not a whole lot 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 we're on 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 are seeing a lot of Permian volumes come through, but Rockies volumes are maintained as well. So I wanted to say it's a negative in the sense that the Rockies line is 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.
All right. Well, thank you very much.
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 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 timeline of converting an NGL line to crude once Shin Oak comes into service? Could we see another frac at Bellevue? With all the activity at Bellevue, 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, 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.
And I've got Randall Duncan snapping the whipworm 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. 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'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, Howard, do you publish that? Yes, sir. 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 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, Brian, you mentioned in your prepared remarks that you've generated $948,000,000 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 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?
Well, 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'd 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 unitholders.
All right, great. I guess we'll leave it up to Mr. Market.
Your next question comes from Jean Ann Salisbury with Bernstein.
Good morning. 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 fees upwards 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 in 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 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 makes sense. Thank you. And you have, I guess, up to the 4,000,000 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
I think that number is north of 2,000,000 barrels a day, just food specific.
That doesn't include Texas City.
Yes, and that's just Houston. It doesn't include Texas City, Freeport, Beaumont. So just Houston alone, we have over 2,000,000 barrels of export capacity and still take care of the rest of the products.
How much in Texas City? Texas City, Bob. Okay. So we also have the capability to load crude. And we have before when moved crude down to Texas City and loaded out of our Seaway docks that we share with Enbridge.
And Bob just said we could do a little over 1,000,000 barrels a day there. Same number at Freeport.
Okay, great. And that's all for me. Thanks a lot.
Your next question comes from Keith Stanley with Wolfe Research.
Hi, good morning. Just on CapEx, Brian, 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 $3,000,000,000 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 a pretty clear visibility to 2 point $5,000,000,000 So your range $2,500,000,000 to $3,000,000,000 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 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 have enough to do organically and see more value in growing organically from here?
Yes. 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 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 see 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 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.
Got it. Thank you very much.
Your next question comes from Darren Harrowes with Raymond James.
Hey, guys. Good morning. And Jim, congratulations on all the operational and financial records you guys 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 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 prompt 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 Bellevue are 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 is ramping up, pipelines are in allocation. 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 is 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 of 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 to last, I don't know if it's 6, 4 months or 9 more months, but there's 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'll get to a point even beyond the next IBDH 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 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 guys think about upgrading the 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.
Yes. Yes, I think that makes 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 the nomination process for VLCC cargoes and how maybe that differs from the ship channel and just any visibility you have there for some of these large chunky loading events?
I guess we need to start Natalie. Can you let me start
It's a very similar process. I mean prior to the month there'll be nominations on the Houston asset, then also whether it's a Seaway assets, the same sort of process.
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?
It's just a matter of a little more detail work firming up the project schedule with the contractor and being more confident in the timeframe we could bring that in.
Your next question is from Michael Blum with Wells Fargo.
Just circling back, I wonder if you can put 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? I think it's under I didn't hear Michael.
Utilization rates on the fracs and utilization rates on the LPG export.
Yes. We're pretty highly utilized on the fracs. Where's Zach? Go ahead.
On the frac side, I would say we're about as full as we can get and we're you've heard the theme over and over, we're doing everything we can to re optimize to get more volume.
We have some fracs. You take Hobbs with the 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 chucker block full. We move 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 an earlier question, we're pulling levers to be able to take care of customers.
Michael Frum,
this is Tony. From a 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, that this LPG is headed for the water, there's no question.
Okay. And is there any way to quantify, since obviously you have a tight market, you should have pricing power, Certainly 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, if you either 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 I don't know. Mid single digits, and Brent?
I'd say 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, it's 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.
Hi. 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?
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 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 agencies we'll have to deal with before the permit is complete.
So what kind of timeframe might that be?
Well, up to 15 months on permitting, Graham, or is that
I think we're probably looking at that from this point, anywhere 18 to 24 months.
Yes. And in fact, we are developing our
That's all for me.
Jennifer, we have time for one more question.
And our final question comes from the line of Chris Singhalofsky with Jefferies.
Got it in there under the radar. Thanks for that guys. Appreciate all the color this morning. Jim, I have, if I could, 2 quick questions. One is just related to your dialogue with Shneur and Mike Luma 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 the next batch of contracts on that?
Are you asking me, are we seeing new customers? Chris?
I'm saying, when we look
at it and agree with what Tony said in terms of there's 1,000,000 barrels a day of new fracs that have been announced through 2020. There's a lot of LPG available in 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 that 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 recognize that you're not going to get them at $0.12 to $0.14 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 we I guess, Brent, we're seeing some or Justin, we're seeing some appetite for that.
Yes. There's I mean, 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 day, there's still a global short for LPGs and 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 that's just not realistic.
Okay.
They will price to I think what Brent is saying, and this is 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 would be the lead time on a new brownfield or greenfield expansion? I mean 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 2 year timeframe we saw in the last round?
This is Bob Sanders. There's steps we can take to probably pick up another 15% to 20% that will be in the, 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, guys. IMO 2020 has been actively discussed by the refined fleet, but I'm a little bit surprised as to how little it's discussed by other potentially impacted sectors. And so 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 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 Enterprise's position on the water. There's just no question. So we'll see as that develops.
It's good for U. S. Refiners. It's great for exports to U. S.
Crude. I mean, it's a very low sulfur crude that the world is going to want. There's just no question in our mind.
I know that's on a sum to go ahead.
Sorry, is that positivity you see just because of the installed export capacity you have or is there something else you're
seeing? No, that's a great question. It's our access to crude that Jim talked about today, 4,000,000 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.
Okay. Thanks a lot for the thoughts, guys. I really appreciate it.
Okay. Thank you, Chris. Jennifer, if
you would, before we end the call, would
you give our participants the replay information?
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Okay. Thank you, Jennifer. And thank you, everyone, for participating with us on our call today, and have a good day. Goodbye now.
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