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Enterprise Products Partners LP
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Ladies and gentlemen, thank you for standing by and welcome to the Q3 2019 Earnings Conference Call. At this time, all participants line are in a listen-only mode. After the speakers' presentation, there will be a question-and-answer session. [Operator Instructions] Please be advised that today's conference is being recorded. [Operator Instructions]
I would now like to hand the conference over to your speaker today, Mr. Randy Burkhalter. Sir, you may go ahead.
Thank you, Michelle. Good morning everyone and welcome to the Enterprise Products Partners call to discuss third quarter 2019 earnings. Our speakers today will be Jim Teague, Chief Executive Officer; and Randy Fowler, President and Chief Financial Officer 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 1934 based on the beliefs of the company as well as assumptions made by an 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 so with, that I'll turn the call over to Jim.
Thank you, Randy. This morning I'll cover our earnings first and then give you an update on our projects list. Starting with earnings, we had $1.6 billion of distributable cash flow in the third quarter that provided another 1.7 times coverage of our distributions.
Year-to-date our DCF was $5 billion which provided a 1.7 times coverage. We retained $665 million of DCF in the third quarter, bringing our total to $2.1 billion for the first nine months of this year. Adjusted EBITDA for the third quarter was $2 billion, that's up 6% compared to third quarter of last year, or a total adjusted EBITDA of $6.1 billion for the first nine months, which is up 14% compared to the first nine months of last year.
Similar to prior quarters, our results continued to provide healthy free cash flow, giving us the flexibility to fund our growth projects, while maintaining a solid balance sheet and not having to issue new equity. During the third quarter, we set six operational records including total equivalent pipeline volumes, natural gas pipeline volumes, NGL fractionation volumes, crude oil marine terminal volumes and DIB and propylene production volumes.
With our upcoming distribution payment in November, we began our 22nd year of consecutive distribution growth. We continue to get closer to the 25-year Dividend Aristocrat benchmark, which is a select group of stocks with over 25 years of consecutive dividend increases, sort of, the best of the best of dividend growth -- in best of the best of dividend growth stocks.
Over this time, we have increased our quarterly distribution rate 71 times through numerous business cycles, including the financial crisis in the last commodity cycle for energy. We manage Enterprise to provide the financial stability and growing distributions.
In addition to projects already under construction, we were again successful in terms of underwriting new growth projects during the third quarter. Based on project sanctioned to date, we currently expect our growth capital expenditures in 2020 will be in the range of $3 billion to $4 billion.
Given the size and integrated nature of our systems, we are always evaluating our alternatives to reduce the capital intensity of some of these projects, while enjoying the benefits of incremental volumes in our system. We're evaluating joint ventures with strategic partners, not financial partners, on certain projects and are always looking for ways to optimize our systems based on market conditions, which could include physically changing the service or direction of our pipes.
Sometime our options are contractual. This includes using contract provisions to clawback unused natural gas processing capacity from producers under acreage dedication contracts. This would provide us immediate long-term capacity, while eliminating the need to build another processing plant.
Our ability to keep customers crude oil neat through segregated storage in Midland and Houston and batch it through our pipelines coupled with our water access has been a key differentiator of Enterprise for large producers and large trading firms looking to sell crude into international markets that demand quality.
We recently sanctioned two expansions of our Midland-to-ECHO pipeline system M2E3 and M2E4. We announced M2E3 in July and M2E4 in October. Our M2E3 expansion will add 450,000 barrels a day of capacity. This pipeline is expected to be completed in the third quarter of 2020. The M2E4 expansion is our latest expansion of our Midland-to-ECHO pipeline system that ties into our Eagle Ford crude oil pipeline and provides up to 450,000 barrels a day of incremental capacity, further expandable up to 540,000 barrels a day.
By utilizing our Eagle Ford assets, shippers and producers will have the ability to match their pipeline capacity to their allocations of capital between the Eagle Ford and Permian Basins. Simply put this type of flexibility for our customers is unmatched. Further more, these expansions will allow us to optimize cost across our Midland-to-ECHO system, while DRA has enabled us to maximize the throughput of M2E1 and M2E2, it has come at an increase in variable cost.
Across these pipelines, we see variable cost of the last segment of incremental capacity, exceeding $2, which works when the spread is over $2.50, but it doesn't work in the current spread environment. By optimizing volumes across the Midland-to-ECHO pipeline system, variable cost should approach to more normalized variable operating cost of $0.10 to $0.20 a barrel.
In addition to savings from optimizing volumes across the Midland-to-ECHO pipeline system, these expansions also give us the flexibility to divert crude off of M2E2, our Seminole pipeline and then convert Seminole back into NGL service. We think we will eventually need this additional NGL capacity. In doing so, M2E4 will only add a small amount of incremental capacity to our Midland-to-ECHO system. If market supported, M2E4 could add up to 540,000 barrels a day of incremental capacity.
In short, look at the map in our crude oil system. Enterprise can transport an optimum cost 1.3 million barrels a day. If the market needs more capacity, Enterprise can ramp that capacity to 1.8 million barrels a day with zero capital. The third major project we announced during the quarter is our PDH2 plants. Lyondell is one of the largest petrochemical companies in the world and they have been an important customer to Enterprise since the early 80s with our first butane isomerization facility.
To build that plant, we've negotiated a fixed cost engineering procurement and construction contract with S&B to build PDH2. We have a long history with S&B dating back to 1995. They led construction on nine of our NGL fractionation -- fractionators plus several others assets at Mont Belvieu and numerous other assets on our system. Relative to market for natural gas, we've also recently announced construction of the Gillis Lateral, which is an LNG oriented natural gas pipeline extension of our Haynesville Pipeline system that allows us to move Haynesville gas and interconnect volumes to the growing Gulf Coast LNG corridor.
We also announced the successful open season for the expansion of ATEX Ethane Pipeline. Similar to other expansions on our system, this incremental capacity is expected to be achieved largely through improvements and modifications to existing infrastructure versus new pipes. Work also continues on our other major projects with most of them to be in service within the next 18 months. Those projects are a healthy mix of supply and market system additions, including fractionators 10 and 11 at Mont Belvieu, gas processing plants at Mentone in the Permian and Panola in East Texas and crude oil petrochemical ethane and LPG dock expansions.
With the second PDH, our iBDH plan and our ethylene export project, we continue to grow our fee-based petrochemical midstream services value chain. This model follows our NGL and crude business models, aggregate supplies, transport, upgrade, store, optimize and then distribute products to end users including exports. The U.S. petrochemical industry is significantly advantaged to virtually all the world because of low-cost feedstocks and significant infrastructure and will continue to play an increasing role in value -- in our value chain for the years to come.
In summary, today's earnings capital [discussion] [ph], our portfolio of assets, continue to perform and provide us with opportunities to grow over the long term. We have a strong history of capital discipline and continue to add to our systems with projects that will generate attractive returns on capital and free cash flow for years to come. We're always evaluating our alternatives to reduce the capital intensity of some of our growth, while still enjoying the value chain -- the value that incremental volume brings to our systems.
We have a long history of optimizing our systems, attracting strategic partners, converting assets and shunning overpriced acquisitions. We're a company that prides itself in consistency and distributions, solid balance sheet and extremely supportive general partner. And what Randy Fowler has emphasized as no surprises in a company that our stakeholders and shareholders can depend on. Looking ahead expect more of the same.
With that I'll turn it over to Randy.
Thank you, Jim and good morning. Starting with the income statement, net income attributable to limited partners for the third quarter of 2019 was $1 billion or $0.46 per unit on a fully diluted basis. Net income included the $39 million non-cash loss for asset impairment charges or $0.02 per unit fully diluted and $86 million in unrealized non-cash mark-to-market hedging losses or $0.04 per fully diluted unit.
Included in the non-cash mark-to-market losses was a $95 million hedging loss related to financial instruments used to hedge interest rates for anticipated debt offerings in 2020 and 2021, which is reflected in interest expense and a $9 million hedging gain on financial instruments, primarily related to our crude, oil and natural gas segments. Adjusting for these non-cash items, EPU increased 2% versus the comparable adjusted earnings per unit for the third quarter of 2018.
Moving onto cash flow. Cash flow from operations was $1.6 billion for both the third quarter of 2019 and 2018. In traditional terms, our cash distribution payout ratio was approximately 59% with respect to the third quarter of 2019 and 58% with respect to the trailing 12 months ended September 30, 2019.
Our cash distribution yield is currently 6.4%. In our last 12 months, cash flow from operations yield is approximately 11%. Free cash flow, which we defined as cash flow from operations minus net capital investments was $2.7 billion for the trailing 12 months ended September 30, 2019, which was a 28% increase compared to the trailing months ended September 30, 2018.
To follow what Jim said regarding capital investments, we have approximately $9.1 billion of major capital projects under construction with $3.6 billion of these major projects added since our last earnings call including our second PDH Midland-to-ECHO 4 pipeline and the Gillis lateral -- natural gas lateral in Louisiana.
Approximately, 77% of the contracted volumes associated with these projects under construction are with investment-grade customers and 70% of the volume weighted contract links are 14 years or more.
Assuming our historical returns on capital, these assets have the potential to generate approximately $1 billion to $1.3 billion of incremental gross operating margin per year. Our total capital investments in the third quarter of 2019 were $1.1 billion, including $1 billion of growth capital investments and $91 million of sustaining capital expenditures.
Total investments year-to-date have been $3.4 billion, including $3.2 billion of growth capital investments or $2.6 billion if you net contributions from JV partners and $233 million of sustaining capital expenditures. We expect full year growth capital investments for 2019 net of contributions from JV partners to be $3.8 billion. Note that the number in the press release was rounded to $4 billion.
The largest component of the increase from last quarter was the purchase of 30-inch pipe for Midland-to-ECHO 4 and the Gillis natural gas pipeline lateral, which together was $370 million. We expect $350 million for sustaining capital expenditures for 2019.
Looking ahead to 2020 and given the projects recently announced, we currently expect growth capital investments to be between $3 billion and $4 billion. In terms of capitalization, our consolidated liquidity was approximately $6.2 billion at the end of the third quarter 2019, which included available borrowing capacity on our credit facilities and unrestricted cash of $1.2 billion.
As of September 30, 2019, our total debt principal outstanding was $28 billion, assuming the first call date for our hybrids, the average life of our debt portfolio was 14.7 years. If you assume the maturity date of the hybrids, the average life of our debt portfolio is 19 years.
Our effective average cost of debt was 4.5%. The partnership used cash on hand to retire $800 million of debt principal that matured on October 15, 2019.
Adjusted EBITDA for the trailing 12 months ended September 30, 2019 was $8 billion and our consolidated leverage ratio was 3.2 times after adjusting debt for the partial equity treatment of the hybrid debt securities and reducing the debt by unrestricted cash on hand. If we normalize adjusted EBITDA for the last 12 months to eliminate the certain spread related activities, we estimate that our leverage ratio would have been 3.5 times at September 30, 2019.
Moving on to distribution payments. Our distribution with respect to the third quarter of 2019 was $0.4425 and will be paid on November 12. This distribution represents a 2.3% increase when compared to the same quarter of 2018. As mentioned last quarter and until further notice, the delivery of common units under our distribution reinvestment program and our employee unit purchase program is now satisfied through open market purchases instead of the issuance of new units. Even with our expanded growth capital investments for 2020, we still intend to self fund equity component of our growth rather than relying on equity capital markets.
With that, Randy we can open it up for questions.
Okay, Michelle. We're ready to take questions from the audience. And I would remind our audience that we would limit our questions to one question and one follow-up.
[Operator Instructions] Your first question comes from the line of Shneur Gershuni. Your line is now open.
Hi. Good morning everyone. Maybe just to start off on the CapEx front a little bit here. Appreciate the color that you gave around Midland-to-ECHO in the prepared remarks, just wanted to, a, to clarify that the total net increase in capacity was about 500,000 barrels. And then as part of that in terms of your CapEx number for this year -- sorry for 2020, does that also include the spot terminal or is that not part of 2020 number?
I don't think that is a part of the 2020 number. No.
And the net increase in terms of crude capacity around the Enterprise system as a result of Midland-to-ECHO that's -- what was the number that you've set on the net basis on the prepared remarks?
On a net basis, I think what we're saying is we're adding the Midland-to-ECHO 4, which is 450,000 barrels a day. If -- by optimizing the system, I think what we're taking of or reducing is about 370,000, yeah.
With Haynesville so.
Yeah. So I think the net addition is about 70,000 barrels a day, Brent?
I believe.
And you heard in the prepared remarks, yeah, we're moving a lot of crude. For example, in Midland-to-ECHO 1, I think we're moving 620,000 barrels a day, and in the variable cost on that has gone up significantly. So if you -- we can take that to 450,000 barrels a day and reduce our cost dramatically. And then we could convert Seminole back to NGL service, which we think we'll have to do.
So overall, we're adding 70, we could add an optimum cost we move about 1.3 million barrels a day. But if the market wants it, we can ramp that up to 1.8 million barrels a day. So there is an unbelievable amount of flexibility within our system to change what we're moving.
Okay. That makes perfect sense. And then for my follow-up question. I think it was about two years ago this quarter that you would reset the distribution growth policy, just wondering has anything changed in terms of your views on buybacks and distribution growth rates? Are you comfortable with the current distribution growth rate? And then on the buyback side, is it just for offsetting the DRIP and the employee purchases? Or is there an evolving view on that?
Hey, Shneur, this is Randy. I think currently on the what we've said around buyback program anyway is, we were looking to be opportunistic with that given our success in underwriting attractive growth projects, I think that's still where our mindset is. And again, we get asked from time-to-time about programmatic buyback, but again, I think we'd rather allocate our capital to good growth projects as opposed to coming in and doing programmatic buyback.
And then as far as distribution growth is concerned, really we take a look at that year-by-year, we're in the early stages of our planning process for 2020, and we'll take a look at that and probably will come in and provide some guidance on 2020 distribution growth in January really about on the same timeline that we did earlier this year.
All right, perfect. Thank you very guys. Appreciate the color.
Your next question comes from the line of Jeremy Tonet. Your line is now open.
Hi, good morning. Just want to start off with the CapEx -- and the range that you guys have provided there, the $3 billion to $4 billion, was wondering what would drive the lower end versus the higher end there? You mentioned JV potentially being a part of that but it's kind of $3 billion what's secured and the upper end could be JVs or maybe there's some other project announcements that you could secure over the course of the year that could drive you to the higher end or any other things driving the moving pieces there?
Jeremy, honestly I think we're still in that range of $3 billion to $4 billion. We've got a couple of things that we're working on that if we are successful in underwriting that that would -- frankly that would still key -- grow CapEx under that $3 billion to $4 billion range.
And then as Jim mentioned earlier spot is not included in 2020; while we've sanctioned the project, the project is still subject to government approval. So, we have elected not to include that in our forecast for growth CapEx for 2020.
Okay, that's helpful. Thanks. And one more question I think you talked about flexibility between crude oil and NGL pipelines kind of being able to flex back and forth. I was just wondering if it -- there ever be a scenario where one of them could be swapped into natural gas service if the market really demanded it in the near-term and then swapped it back to liquid service at a later date if that could ever make sense if that's possible?
Well, Jeremy I wish it was possible, but it's not. It's strictly going to be a liquids pipeline with flexibility between NGLs and natural gas I mean crude oil unless -- Randy think differently.
No, I don't see that happening.
Well, wish it could.
That's all from me. Thanks for taking my question.
Your next question comes from the line of Colton Bean from Tudor Pickering Holt & Company. Your line is now open.
So, appreciate the detail on the CapEx program. Just with that 2020 midpoint of $3.5 billion any preliminary thoughts on financing for the year? Should we anticipate debt funding is basically the balance between your retained cash flow and your CapEx? Or would you still target something closer to 50% and may be any excess cash allocated towards some of those opportunistic buybacks?
Yes, we'll see what we have next year. I think we're still -- we still think about funding at 50% debt and then if you would 50% retained cash flow that's sort of our going in position.
Got it. And if that resulted in excess cash would that be where you guys look at doing something beyond the DRIP offset?
We'll just take a look at market conditions at that point in time.
Understood. And just a quick one on operations so fairly significant step down equity NGLs this quarter. I think historically you've all talked about a number in the 130,000 barrel a day range as kind of your C3 plus your propane plus type of recovery. So, it doesn't seem like this quarter's result would be solely attributable to more rejections and just any incremental context you can provide on that 111,000 equity NGLs?
I think most of that's probably ethane rejections. Where's Natalie or Brad…?
Yes, this is Brad. Most of that – I’ll agree with Jim, most of that's attributable to ethane rejections across the system whether it be the Rockies or some of the other places.
Got it, that's helpful.
Your next question comes from the line of Jean Ann Salisbury from Bernstein. Your line is now open.
Good morning. Are you may be able to comment on whether CapEx cost for the two new Midland-to-ECHO pipelines are expected to be noticeably lower than the first one?
Just really comparable.
Yes, comparable. It's not noticeably lower.
Okay. Thank you. And as a follow-up the Apex expansion announcement kind of comes as rig count is falling in Appalachia. Can you just give any more color on whether this is -- like customers are still expecting growth or if it's more of a backup solution for when or if Mariner East is down?
Yes, this is Tug here. I can just comment that you know customer approach us the valuable -- the viable takeaway down to Mont Belvieu and we close the successful open season. That's all -- that all I can comment on that one.
Okay. Is it possible to comment on if there has been any change or lengthening to the existing Apex term?
To the existing Apex term, there has not been a change, no.
Okay, cool. Thanks. That's all for me.
Your next question comes from the line of Tristan Richardson from SunTrust. Your line is now open.
Hey good morning guys. Just following-up on some of your comments on identifying strategic partners on projects in some of your markets. Do you see the greater opportunity on new projects that may not be in service yet or more on existing capacity currently in place?
You know it's kind of hard to do it on existing capacity. I think probably its more new projects that we would look at. I mean, you never say no to anything. If it depends on what a person to bring into the table, if you got to for example a petrochemical customer that wants to have a big off-take and you might do some on existing assets, but by and large it's new assets.
Helpful. Thank you. And then the follow-up. You also talked about opportunities to optimize existing processing capacity. Could you talk about to the extent this is EPD reacting to the U.S. production environment shifting or also more just looking at assets that have utilization upside?
Everybody, there is a big – there is – there is take or pay contracts, which means you're going to get paid, but that mean you're going to get the production. Typically, we have downstream numbers in our economics. So that's an issue. One of the things we have on our acreage dedications, if people aren't performing up to the production profile that the plant was built on then as a certain point we have the right to reduce their MDQ and use that capacity somewhere else. So it is safeguard that we always have the right to at a certain point in time to call back and use – reduce the MDQ and use it with someone else.
Helpful. Thank you guys very much.
Your next question comes from the line of Spiro Dounis from Credit Suisse. Your line is now open.
Hey, good morning everyone. First, question just for with respect to the overall growth strategy. I think we've seen you guys lean in somewhat aggressively year to the next part of the cycle, where we're seeing maybe a lot of your peers retrenched a little bit. So you just sort of stand out in that respect. Securities, is it fair to say that you're deploying maybe a similar strategy LPG exports where your major focus at this point is on capturing market share and dissuading competition or is it a little more nuance than that?
You want to have a part of that, and then forward back to me.
This is Brent. And I think you hit it is that we've seen people pull back as it relates to midstream competitors. What we've seen as people pullback is probably over the last six months to nine months we've seen some incredible opportunities in front of us that have very, very good returns that have upside either downstream or upstream. And on top of that, it's with very creditworthy customers. So at some point when we're seeing the returns that we're seeing on these projects, it's just a very good project for Enterprise.
I think the other thing where you're seeing us and it's along the same lines, but we have a broader product line than we could offer. Our petrochemical midstream services business, we are very focused on that building the BDH2, but also what we're doing is opening up our storage and distribution systems such that petrochemicals, it's the same model we have in crude and NGLs stored, distributed or exported.
But I think you saw Enterprise back out of certain projects two years ago and three years ago, and we were pretty vocal about the projects that we wouldn't go after. And I think at the end of the day is served us well. But when we look at where to deploy capital right now whether it's an acquisition or whether it's still organic growth is still makes much more sense to do organic growth projects to work for Enterprise.
Yeah. Makes lot of sense. On the petrochemical comment seeing octane enhancement really strong again this quarter. I'm guessing that's just a continuation of kind of what we're seeing along Tier 3 shortages of octane, and I think we get a sense of maybe octane is going to be tight again or even tighter next year in 2020. Just curious do you think about margins the same way going into next year on octane enhancement and is there any sort of expansion or anything that you can do in that business to capture more of that?
This is Chris. We're seeing – we expect to see the same sort of spreads next year as we have this year and in fact we talk about how we hedge forward and we've done some of that are ready for 2020. And then in terms of expansions, we have our iBDH project that's coming online at the end of this year and so some of that volume also goes into the alkylation market.
Great. If you look through the Astros.
Next question comes from the line of Pearce Hammond from Simmons Energy. Your line is now open.
Thank you, and good morning. Given the fast declining Baker Hughes rig count and the likelihood the 2020 E&P capital spending activity and production will be lower than current consensus estimates, how do you see that impacting EPD's 2020 outlook and what are you hearing from some of your customers?
One of the things if you look at who our customers are they are large producers. I don't see someone like Exxon or Chevron slowing down. I don't know about EOG. I'll throw it to Tony. But -- we see what you're talking about, but the people that we have that are really the anchors to our system are the very large gas. I don't think we have – we have any small cap people at all?
Not -- not on -- or actually...
It's minimum. Tony you want to throw some in.
When we say that I am talking to people, we talk to our customers a lot what we hear time and time again and we read everything that they say is that their capital is going to be down, but their production is going to be up because of efficiency and in some cases completion DUCs.
So while the industry, probably will never repeat what it did in 2018 relative to growth when -- and I'm speaking for Enterprise, when we read people project that the production is actually going to rollover. It's very, very hard in our type curve models in our forecast to make that happen. Brent?
We've met with numerous producers customers over the last -- throughout the last month and every single one with the exception of one has said that volumes are going to be up; capital is going to be down. And usually it's about a ratio of 10% to 15% down on capital 10% to 15% up on volumes.
There's only one customer who said that crude oil volumes would be flat. And they said, capital will be down but our gas production is going to decrease. And so, I think anybody that's going after crude oil that has the associated NGLs with it, I think what we've heard is their volumes are going up. But I think gas centric type volumes will be going down.
Great. That's super helpful. Thank you. And then my follow-up, do you see enough customer interest to consider further LPG dock expansions above and beyond what you've already announced?
I think if you look at what we have on the table and the expansions that we have and the cost associated with the returns that we get, at the fees we're getting, I certainly as our expansion comes up in the fourth quarter of 2020, we've evaluated further expansion opportunities and that's obviously the past that will probably go down. Actually -- that's a relative question.
So in terms of capacity that we have contracted right now, there is a little bit of a gap of opportunity that we have out there and we'll let crude oil or NGLs determine how we use that capacity. But in terms of what we have contracted for the next several years it’s north of 90%.
Great, thank you very much.
Next question comes from the line of T.J. Schultz from RBC Capital Markets. Your line is now open.
Great, thanks. Just a question on the Acadian expansion; is that driven more by growth in Haynesville production, you are expecting or are you bringing more Permian gas ultimately through that system is something you guys have talked about before with the combo plan of Enterprise North Texas moving gas over into the area?
I think it is mainly given the market to those Haynesville producers. The market was either the river corridor or Perryville. Help me here, am I right? And this just gives them a market and I'll tell you that lateral, if I'm not mistaken Brad, it's so completely out our badly. I'll let Natalie answer some.
Well, like any other project that we do, it's definitely sold out with creditworthy producers behind it. It will get producers to the LNG export facilities in South Louisiana and Southeast Texas. A promising and exciting project for us.
Okay, thanks. So moving out of the Haynesville, do you still expect to move gas in the Beaumont, I think you guys had talked about the Lumberjack pipe before, is the primary demand pull into Louisiana here?
I'll take it and let Natalie to jump in if she wants to. We're still working that project but I will be honest, it's not plan off the shelves right now. Is that fair Natalie?
That's fair.
Okay understood. Thank you.
Next question comes from the line of Keith Stanley from Wolfe Research. Your line is now open.
Hi good morning. Randy, you mentioned how the backlog I guess you added $3.6 billion of new projects to it and I assume PDH2 and Midland-to-ECHO 4 are the larger parts, but are there any other chunkier additions? I wasn't thinking in those two alone would be really near the $3.6 billion? I'm not sure if ATEX or the Gillis lateral are meaningful capital.
Yes it's -- what may have also been included in that was also Midland-to-ECHO 3 could have potentially been in there as well; and PDH Midland-to-ECHO 4 and Gillis.
Okay sorry to clarify; Midland-to-ECHO 3 is not part of that?
I think it was included when we announced earnings in the second quarter.
Okay. So mainly those two projects aren't Gillis. Follow-up question just can you give any more color on Midland-to-ECHO 3 in terms of I guess what's involved in the project? You guys announced it just this past summer. It's a pretty tight time line to the third quarter of 2020. I'm just wondering how much is new pipe versus expansion of infrastructure or repurposing on that line?
On new pipe and we started working -- you're talking about how quick we're doing it. We were working on that project long before we announced it. So we're running head start. Is it fair to you Graham [ph]?
I think that's fair. We were doing a lot of work upfront and make sure we're ready to hit the ground running. So yes, that's fair.
Got it. Thank you
Next question comes from the line of Michael Lapides from Goldman Sachs. Your line is now open.
Hey guys, thanks for taking my question. Real quick, can you just talk about the returns on capital or the build multiple or the operating margin, however you wanted to discuss it, from Midland-to-ECHO 3 and 4 versus kind of what you got when you first built some of the Permian crude pipes, meaning maybe Midland-to-ECHO 1 and 2 for example?
Yes. Michael, this is Randy. I would take first shot at it. Again, we won't get into talking returns on any specific project. But I mean, if you come back in and I'd just say that they are comparable to our historical returns and most midstream projects fall in that range of 10% to 15%. I think what we have said is the flexibility that Midland-to-ECHO 4 does provide us is just by coming in and being able to save on those variable operating cost that Jim spoke to earlier. We could come in and that provides us a good base level return on Midland-to-ECHO 4 that really weren't available in some of the other pipes.
Got it. Yeah. I'm just kind of asking that given a lot of people expect a sizable Permian overbilled in the next year or so actually really starting now and just trying to think about how that impacts you differently than how it may impact some of the other players the midstream operators in the business?
Brent, why don't you -- perhaps you try to take a shot at it.
It's a good question. And if you look at -- we've talked about this before, but if you look at total capacity that's coming out of the basin, you can run the numbers and say whether there is excess capacity. So I think you're seeing it on the pipeline that have come up recently and the pipelines that will come up over the next six months is you really have to go back to what is their supply source. And the beauty of our system is the fact that we have that midland pricing point and that we have supply to fill up our pipes.
And then we have to look to see where those barrels are going. And the reason we're getting contracts and the people that are typically signing these contracts are people that are going to continue to drill that are re-upping for increased volumes with Enterprise and they want to go to Houston. If you look at Midland-to-ECHO 4, there is one crude pipeline that we have that's not full. So we have one crude pipeline that's not full and that's the Eagle Ford pipeline system. The issue with it is probably not a whole lot different than some of the new pipelines that have come up in the Permian Basin recently. It does not have a daily supply source. So what you're dealing with is you have barrels that are trucked in.
You have small gathering lines that go into that Eagle Ford pipeline system. And ultimately it's underperforming on a much greater scale than any other pipeline we have in our portfolio. So what we did is went back to Midland and brought a daily supply source into that pipeline. And we also have the opportunity to do dual contracts where people that have Permian acreage and people that have Eagle Ford acreage. So going forward, our expectation is that pipeline is going to be full, no different than the rest of our crude pipelines. So that was the thought behind that and recognize the fact that we have contracts that support that capacity.
Got it. That's super helpful. And then one follow-up. You all talked in your opening remarks about potentially reclaiming some of the capacity on the gas processing plants and I don't know whether those were the new ones built or whether those were legacy ones in the Permian. But just curious, you then later in the Q&A talked about how most of your customer base are the majors and that they haven't really been reducing production. So what's driving the open capacity on your process and if you're biggest customer, the bulk of your customers aren't really cutting production growth rates?
This is Brent again. So in terms of the majors, the majors for a reason are probably majors because they have a lot of acreage. So when you look at processing plants that is specific acreage to an area. If you look at crude oil in our total portfolio, they are achieving what they are signed up for in most cases exceeding what they are signed up for. But when you look at -- so their issue is some areas are better than other areas. And so there may be an instance where we have a plant that has certain acreage that probably when they go tier up their acreage it's number or number five on the list and are focused on probably a more crude-centric play. So it benefits us on the crude oil side. But on a processing side, they are underperforming. And so we have provisions in their contracts to allow us if you underperforming to go back and reclaim that capacity and that's what we look to doing.
And we have people we're working with that, we know that we could build that capacity with.
Got it. Thank you guys. Much appreciate, you all taking all three of my questions
Next question comes from the line of Ujjwal Pradhan from Bank of America. Sir, your line is now open.
Good morning, everyone. Couple of questions from me. First I wanted to touch on the recent increase in VLCC freight rates globally? And how that has exported -- that has affected your export volumes? Although the spike has subsided recently, I think the rates still are elevated. Can you share what you're seeing on your end?
Well, Brent, I think you're dominating this. Good for it.
So, I think we saw the spike like you all did and I'm not going to plug in here on this. So there is a spike. And we saw a record freight rates on VLCCs and that's an issue. And that's an issue for producers who go to markets that are forced to export. So in Houston what we saw is people basically backed off and they backed off from exporting and the market was trying to fill itself out and things get a reset but that takes time. And in this case it took probably couple of weeks and we saw it, kind of, settle into a number.
But the luxury we have and why people choose to go to Houston is because you have that luxury. And you have the ability to store barrels and you have ability to move barrels to refiners and you have the ability to move barrels to downstream. So, what you're seeing in other markets that are forced export is either they are severely discounted to Houston or the barrels aren't flowing to the water. And you saw big players that are going to terminals outside of Houston being forced to sell back in the field in the Permian Basin.
So when stuff like that happens to me going to Houston is an opportunity for Enterprise and opportunity for our customers. It's been reset and volumes are increasing. You will see volumes probably -- when we come out with our earnings, you will see volumes for October very, very strong but there was a period in time of there where I think it caused the market to pause and say, is this the right idea to go to this is terminal. And to me, it's probably so important for us going forward.
Got it. And maybe a follow-up to your comment on ethane rejection earlier. Can you discuss what the dynamics is right now across your system in terms of pipeline volumes? And also downstream, how that has impacted the frac spreads that you're seeing?
I think the rule of thumb in general is the further away you are from Mont Belvieu, the more pipeline capacity that is available based on ethane rejection. In terms of frac use, people, and so I mean when you look at fractionation, the closer you are to the pricing point, the more likely you are to be full. So when you look at tertiary fractionators and we got some in Louisiana, there’s also a bunch in the Mid-Continent but the closer you are to the pricing point, all these NGLs are leaving we’ll call that the water, the more full you are.
In October, I think we set a record on ethane and LPG exports of over 21 million barrels. I don't know what we're doing in crude do you?
It's -- that will probably set a record.
Got it. That’s helpful. Thank you guys.
Our last question comes from the line of Chris Sighinolfi from Jefferies. Your line is now open.
Hey good morning guys. Thanks for all the added color. I have two. The first question just to circle back on the NGL side of your business. Tristan and Michael asked about the idea of pulling back the gas processing capacity from your acreage dedicate producers. I'm just -- you had noted this is a function of contract terms and something that's always been available to you. So I'm just curious in mentioning it now, are you signaling you're going to be more aggressive in pulling back this capacity because you're seeing mismatches now that didn't exist before and because investors are more focused maybe on CapEx avoidance? I guess, is there's a change in strategy? Or are you simply flagging it, so that we're all aware of the contract optionality?
Yeah, I think it's to make you aware that we get so many questions on capital discipline. We have ways to increase our business with our throughput without spending money. And I think what we're saying is that's one way and I don't think we're -- it's not a change in strategy. It's just we're going to start doing it when we're going to do it, like we always have.
So if you look at producers when they go to rank their acreage, there are certain acres that we have in that area that ranks number one for one producer, and it ranks number five for another producer. And so at the end of the day for producer A, that capacity should probably go to producer A because producer B is not going to produce it for some period of time. That's what we're doing.
I think it's really not a change. It's -- Natalie or Brent, I think it's in every acreage dedication deal we have in it.
I agree. It's just an optimization technique that we're highlighting here. It is not saying we are something new. We've done this the whole time we've contracted these plants.
Okay, that's helpful. I suspect I just wanted to clarify. And then final question from me and this might be for Randy, but I'm not sure it's probably collaborative answer. But earlier questions on buybacks and you noted, EPD's preference to invest in projects that exceed the hurdle rate versus a ratable buyback program. I'm just curious and we get a lot of questions about terminal states and how you weigh sort of the terminal state consideration of that analysis.
For example, another crude pipeline project, realizing that Brent talks about, not every landed location is equal and there are contracts in place to justify the expansions there is also a downstream considerations. But I'm just curious when you get to beyond the contract term market, how do you view that investment versus the permanent retirement of a unit and all future distributions tethered to it contracting?
Yes. Chris a little bit what you're talking about is really how do we feel about recontracting when based contracts are up, so I'll pass it to Jim or Brent on that?
I think a good example would probably be the Haynesville, when we put that pipeline in service I think we were getting $0.25 -- between $0.25 and $0.30 was what we're getting. And now this -- now what we're getting on that spread is what $0.12 to $0.15. But what we did -- so you would look at that and say that's a recontracting issue. But what we're getting in our gathering is probably $0.20 to $0.30. And so if I look at it all in, we get the same revenues just shifted as to where we're getting.
The Eagle Ford pipeline that Brent talked about, one of the things that tied it back to Midland does, it really mitigates our recontracting risk because we've tied it back to a daily market that we can move crude out of.
Now I don't know what the spreads are going to be but we have contracts that support that. I think if I look at all of our crude contracts out of the Permian, Brent, you're 90% contracted on those and those terms going in for seven or eight years is what I remember?
Teague, 10 years, nine years.
Yes so. Remember, every one of those contracts I think with the exception of one having associated dock deal. So we've got nine years to 10 years left at pretty decent fees on the transport but every one of them have a dock deal and some of them may have storage deals to go along with that.
Great. I appreciate that color.
Yes and Chris a little bit, I mean when you think about it, as far as recontracting in the underlying cash flow assumptions, that enters into your buyback consideration too because it's all embedded in the cash flow stream of -- what you can think about a cash flow per unit.
I think what I was just noting is Jim is talking about the Dividend Aristocrats and you guys have had a really phenomenal schedule quarterly raises here through some pretty tumultuous period. So, I think we look at it -- when we look at this growth and the payout and that feels fairly secured obviously, everybody is susceptible to risk on the business longer-term. I was just kind of trying to frame up Randy, how you guys think about that uncertainty versus sort of the certainty of cash distribution growth? And when you think about buybacks and the retirement of that stream, how it all factors together? Appreciate the color.
Michelle, this is Randy. With that being our last question, the company is going ahead and sign off here. We would like to thank everybody for joining us today. If you would give our listeners replay information for the call? Thank you, very much and have a nice day.
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