Enterprise Products Partners LP

NYSE:EPD

Earnings Call Transcript 2019-Q1

[Operator]

Good morning and thank you for standing by. Welcome to the Enterprise First Quarter Conference Call. I would now like to turn the call over to Randy Burkhalter. Please go ahead, sir.

[Randy Burkhalter, VP, IR]

Thank you, Christie. Good morning, everyone, and welcome to the Enterprise Products conference call to discuss first 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.

Now, during this call, we will make forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, based on the beliefs of the Company as well as assumptions made by and information currently available to Enterprise’s management team. Although management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Please refer to our latest filings with the SEC for a list of factors that may cause actual results to differ materially from those in the forward-looking statements made during the call.

And with that, I’ll turn the call over to Jim.

[Jim Teague, CEO]

Thank you, Randy.

First, let me express my regrets for missing our Analyst Day. I would have much rather been with you guys, but three broken ribs and unbearable pain kept me away. I was glad however that you really got to see the quality of our people, have an appreciation for our culture, and hopefully get the message of the promising outlook for our business.

And I wanted to know there was a research note out titled “what would drive investors back into energy stocks”. The report said the answer is “show me the cash”. In the first quarter, Enterprise did its part to “show me the cash”. Consistency and execution is critical in all facets of our business. We demonstrated it in the first quarter by completing the conversion of one of our Seminole NGL pipelines into crude service and with initial operations on the Shin Oak pipeline four months ahead of schedule. Successful execution also includes our ability to deliver returns on invested capital. We have consistently returned capital to our investors for 20 consecutive years of distribution growth and counting, while maintaining healthy coverage. We call that “show me the cash”. We also take very seriously that many of our long-term investors rely on this income.

Our balanced approach of returning capital, maintaining coverage while conservatively using leverage has provided us the financial flexibility to not only weather the cycles, but continue to grow our business during those cycles. That balanced approach has us well positioned to capitalize on organic growth opportunities without relying on the equity capital markets. We believe this will lead to future growth in DCF per unit, distributions and the value of our equity.

We had an exceptional first quarter with three of our four business segments reporting higher gross operating margin. We set five operational records and six financial records, and that’s on the heels of a strong 2018.

Excluding noncash mark-to-market earnings, gross operating margin, adjusted EBITDA and DCF, each increased by approximately 18% in the first quarter compared to the first quarter of last year. DCF excluding nonrecurring items was a record $1.6 billion, giving us a healthy 1.7 times distribution coverage for the quarter. We retained $665 million in the first quarter that is available to reinvest in our growth. This record performance was driven by contribution from assets that began operations during the past year, volume growth on existing assets, our marketing group’s ability to capture some of the west to east spread opportunities, and crude oil and natural gas which more than offset the effect of weaker gas processing margins and temporary closure of the Houston Ship Channel due to the fire at the ITC terminal.

As to capital projects on the supply side, our focus on the Permian continues. We placed the initial phase of our Shin Oak NGL pipeline in service at the end of February and it’s currently running at 250,000 barrels a day. As I said, we completed the conversion of one of our Seminole pipelines from NGL to crude service. We refer to that as Midland-to-ECHO 2 and it is flowing greater than 200,000 barrels a day. Note that given its location and interconnects, we will always have flexibility to convert this pipeline back to NGL service depending on the pipeline supply demand balances for crude oil and NGLs in the future. I doubt that anyone else will be able to offer this type of future flexibility to Permian producers and to markets.

On the demand side, we expect to complete our LPG dock expansion in the third quarter, our IBDH plant at the end of the year and partially initiate service of the ethylene export terminal also in the fourth quarter. We recently completed the restart of 55,000 barrels a day of fractionation capacity at our Shoup and Tebone facilities in South Texas and Louisiana respectively. We expect fractionation capacity to be tied again in the second half of 2019.

Anticipating further NGL supply growth, we’re currently constructing two new fractionators at Mont Belvieu. We’re also developing PDH 2. And we feel confident that this project will be successfully commercialized.

On the natural gas, natural gas liquids side, we expect to complete the third processing train at Orla this quarter and Mentone 1 in the first quarter of next year. Orla 1 and Orla 2 were placed in service last year and are running full. When all of these facilities are completed, we’ll have about a 1.6 DCF a day of natural gas processing capacity and 240,000 barrels a day of liquids production out of the Permian. We’re in discussions with customers that could lead to our underwriting two more processing trains at Mentone. We also expect to complete the expansions of Front Range and Texas Express NGL pipelines in the third quarter.

Many of you have seen that we filed permits to construct another crude pipeline out of Midland. If successful, this would be our Midland-to-ECHO 3 pipeline . We’re quite creative in naming these pipelines. We are receiving serious interest from customers who value Enterprise’s ability to provide flow and quality assurance and market choices on our integrated system. This integrated system joins together our pipeline storage, Houston distribution system and Marine terminals, safeguarding quality for both producers and end users by way of uninterrupted delivery from the wellhead to the -- to refineries or docks. If we are able to successfully underwrite this third pipeline, we would have a lot of flexibility to convert Midland-to-ECHO 2 back into NGL service should demand is supportive.

While on the subject to flow assurance, I want to share with you how we performed during the ITC fire and fog days that temporarily limited the traffic on the Houston Ship Channel. None of our upstream customers saw any disruptions while Ship Channel traffic was impaired. And in fact, some of our facilities were used by the authorities during the event. This is the value that a large integrated company like Enterprise provides. This is also the value of being in the Houston market. We have access to 4.5 million barrels a day of refining and 300 million barrels of storage. With our loading capabilities, we made up a significant portion of our vessel backlog in April and expect to load all of the remaining vessels in early May.

During our Analyst Day, our fundamentals team covered the subject of light oil, how much growth that we see from the Permian and where we see the demand. I think they did a good job explaining that light oil will find a home and petrochemicals and gasoline demand. However, after that, we received a lot of questions about LPG demand and the world absorb all the future LPG supply. I know a lot of you have to think about these things and you have to ask these questions, and Tony and his group doing a lot of analysis on these subjects. And if you want a deeper dive, I’m sure we’ll be happy to do it during the Q&A. But let me give you my personal perspective. I don’t worry about this for one second. The reason, I have a fundamental belief, price creates demand just as price creates supply. You can ask Tony about demand growth for propane in India.

Despite record LPG exports from the U.S., propane is currently worth 40% of WTI and normal butane at 48%. These are historically low relationships that were not typical during the old days. I think that’s a reference to me. In those -- back in the day, propane always sold at 70% to 75% crude. At 40% of crude, price will create demand.

I want to turn the call over to Randy. Let me say again how proud we are of our performance this quarter and how much we are looking forward to the opportunities we see in 2019. None of this is possible without the extraordinary efforts and team work of our employees. I could go on for an hour about the quality of the people we have here at Enterprise. Our strong results this quarter after the record setting year we had last year is a tribute to their work ethic, their creativity and the team work you see within our company.

And with that, I’ll turn it over to Randy.

[Randy Fowler, President and CFO]

Thank you, Jim. And good morning, everyone.

Starting off with the income statement, for the quarter, net income attributable to limited partners for the first quarter of 2019 was $1.3 billion or $0.57 per unit on a fully diluted basis. This included $96 million or $0.04 per unit in non-cash mark-to-market gains. This represents an 11% increase in earnings per unit after adjusting for the effects of mark-to-market amounts versus the comparable adjusted EPU in the first quarter 2018. As Jim mentioned, we did report six financial records for the first quarter including record adjusted EBITDA of $2 billion and DCF excluding non-recurring items of $1.6 billion.

If we follow the recent sell-side thing of converting adjusted EBITDA into distributable cash flow, for the first quarter, we made this conversion of EBITDA to DCF at 82% for the quarter. This illustrates the benefits of having lower leverage, lower interest rates and a simple structure which is very efficient in converting cash flow all the way down to the unitholder level. Cash flow from operations was $1.2 billion for both the first quarter of 2019 and 2018. Of note, our cash flow from operations for the first quarter was reduced by $560 million for working capital purposes. And this is compared to a use of $203 million for working capital purposes in the first quarter of last year. In traditional terms, our payout ratio, cash distributions paid to limited partners as a percentage of cash flow from operations was approximately 80% for the first quarter 2019. And if we take a look at the trailing 12 months which would sort of snooze out the noise of working capital since the seasonality, the payout ratio was 62%. Free cash flow was $1.9 billion for the trailing 12 months ended March 31, 2019, which increased 89% compared to the trailing months ended March 31, 2018 and is $97 million less than the trailing 12 months for December 31, 2018. And again, some of that due to changes in working capital.

We placed approximately $1.9 billion of major growth capital projects into service through April of this year including the initial capacity on the Shin Oak NGL pipeline and the conversion of Seminole into crude service. We have approximately $5 billion of major capital projects under construction that we expect to come into service between now and the end of 2020. Our capital investments in the first quarter were $1.2 billion which includes $62 million of sustaining CapEx. We currently expect growth capital investment for 2019 to be in the range of $3.4 billion to $3.8 billion and another $350 million for sustaining CapEx. For 2019, we still expect to receive approximately $625 million of cash contributions from business partners in projects that are jointly owned.

Moving to our balance sheet, at March 31, 2019, our total debt principal outstanding was $27.1 billion. [Ph] Assuming the first call date for our hybrids, the average life of our debt portfolio was 14.1 years. Assuming the final maturity date for the hybrids, the average life of the debt portfolio was 19 years and the effective average cost of debt was 4.5%.

Adjusted EBITDA for the trailing 12 months, March 31, 2019, was $7.5 billion and our consolidated leverage ratio was 3.4 times, after adjusting for the partial equity treatment of the hybrid debt securities. On consolidated liquidity, it was approximately $4.7 billion at quarter end, which included available borrowing capacity under our credit facilities and unrestricted cash.

Moving on to equity issuances and purchases, Enterprise received approximately $43 million in net proceeds from the distribution reinvestment program and the employee unit purchase program during the first quarter of 2019. The level of the participation in the DRIP program after turning off the discount was less than half of what it was in the prior quarter, which again would have been with respect to the distribution paid out in November 2018 and we anticipate it may come down further at the next reinvestment day. As we continue to transition to equity self-funding, we are nail evaluating applying the reinvestment of distributions to open market purchases instead of new issuances.

During the first quarter 2019, we repurchased 1.9 million units for $51.6 million or approximately $27.83 per unit, which more than offset the 1.5 million units issued through the dividend reinvestment plan and the employee unit purchase plan in February 2019.

And with that Randy, I think we’re ready to open it up for questions.

[Randy Burkhalter, VP, IR]

Okay. Thank you, Randy.

Before we open the call up to Q&A, I’d like to mention that we have posted some slides on our website as supplemental information with respect to first quarter earnings listed under the caption Presentations in the Investor section of our website. So Christie, we are now ready to take questions from the audience.

[Operator]

[Operator Instructions] You do have a question from Tristan Richardson of SunTrust.

[Tristan Richardson, SunTrust]

Hey. Good morning, guys.

[Jim Teague, CEO]

Good morning.

[Tristan Richardson, SunTrust]

We’d have to say the five beats in a road doesn’t go unnoticed. The only thing is you’re making our modeling skills not look so great. Just a quick question on your project execution and just pulling forward some of the projects, specifically Midland-to-ECHO, presumably that allowed for some beneficial spreads exposure. Fast-forwarding today, does that capacity start to shift to your -- to third party use all at once or is that a gradual shift over time?

[Brent Secrest, SVP, Commercial]

Yes. So, Tristan, this is Brent Secrest. If you look at Midland-to-ECHO 1, I want to say contractually, J., we’re at -- for the first quarter, we’re at 475?

[Jim Teague, CEO]

Yes. That’s correct, Brent, 475.

[Brent Secrest, SVP, Commercial]

Then, we’ll ramp up. So, second quarter contracts come on, additional contracts come on. And I want to say we peak at 535 in the case of Midland-to-ECHO 2 starting April 1 that was -- pipeline was going to go over to the committed shipper and that volume is at 205,000 barrels a day.

[Tristan Richardson, SunTrust]

Helpful. Thanks. And then just similar question on the natural gas side, do you see more commercial activity for third party or is some of that space that gives you that spread exposure stay throughout the year?

[Brad Motal, SVP, Natural Gas Assets and Marketing]

Hi. Good morning. It’s Brad Motal. I think it’s going to stay there for the rest of the year and beyond. And frankly, I’ve been impressed with the amount of continued commercial opportunities we’ve had in the Permian. I felt like it was going to start to slow down a little bit. And frankly, it has and it’s kept up its pace pretty nicely.

[Operator]

And your next question comes from Jean Ann Salisbury of Bernstein.

[Jean Ann Salisbury, Bernstein]

The LPG export arb has really widened recently, your export expansion should help with that. Can you share if it’s mostly sold fixed fee or if you would have material exposure to the arb when that comes on?

[Justin Kleiderer, VP, NGL Marketing and Supply]

Yes. This is Justin Kleiderer. Yes, from a spot perspective, you’ve certainly seen widening of the arb and that expansion is going to give us access to capitalizing on that wider arb. However, we maintained our focus on our long-term strategy to offer competitive rates on the term supply business. So I think as we think long-term, we’re not going to deviate from that long-term strategy of ensuring that we capitalize on the long-term supply at competitive rates.

[Jean Ann Salisbury, Bernstein]

And then, how do you see Shin Oak capacity ramping between now and the end of the third quarter?

[Tug Hanley, VP, Distribution]

This is Tug Hanley. Shin Oak is, Jim mentioned currently, at full at its initial capacity, 250,000 barrels a day and we’ll be bringing on pumps between now and the end of the year. Call it another 100,000 barrels a day by the end of third quarter.

[Operator]

And your next question comes from T.J. Schultz of RBC Capital Markets.

[T.J. Schultz, RBC Capital Markets]

Just on the unit buybacks in the quarter, you noted it covered the DRIP and purchase plans, just anything to read into that as far as strategy on buybacks and maybe this change if you’re going to open market purchases. Just any more color on how you view this as opportunistic time on the buybacks?

[Randy Fowler, President and CFO]

T.J., frankly, I don’t think there is -- our perspective has changed that much since our analyst meeting three weeks ago, I think we’re still looking to be opportunistic with the buyback program. As we highlighted at Analyst Day and we’re looking at a number of projects in development, frankly we’re feeling pretty good about. And so we may need capital needs there. So I think right now we’re just, like I said, being very deliberate and keeping our financial flexibility now. So really no change is really more opportunistic in approach.

[T.J. Schultz, RBC Capital Markets]

Okay. And then you have crude dock in Corpus through the Eagle Ford JV that’s coming online. Would you expect any more storage around that as more pipes in the Corpus are complete. And just if you can provide any color on the capacity to load across that dock?

[Brent Secrest, SVP, Commercial]

That dock is operational now and we’re working with our partner over there to bring that dock in operation. I want to say currently with the air permit, it is -- the capacity is just shy of 200,000 barrels a day, J?

[Jim Teague, CEO]

At 200,000.

[Brent Secrest, SVP, Commercial]

At 200,000 barrels a day. So we think it’s -- I think we’re on record about this, but we do think there will be opportunities to help clear that market as pipelines come online, docks come on at different times and there is some potential misalignment between pipelines and docks. So certainly, we’re looking for opportunities like that.

[Operator]

And your next question comes from Spiro Dounis of Credit Suisse.

[Spiro Dounis, Credit Suisse]

First question is just on the Permian. Just curious if you’re seeing any near-term impact on NGL volumes at the Permian as a result of the Waha basis. I think most of the shut-ins were on the gassier acreage, but just curious if that’s also resulted in any sort of meaningful impact on liquids and processing economics?

[Brad Motal, SVP, Natural Gas Assets and Marketing]

It’s Brad Motal again. We have not seen any impact from shut-in gas relative to our processing volumes on our equity gas plants out in the Permian.

[Spiro Dounis, Credit Suisse]

And then, I believe you made the comment at the Analyst Day that you see -- I think you’re seeing or finding it increasingly harder to offer NGL customers transportation without also offering frac and export capability. And just curious if that’s resulted in ability to maybe charge premium prices just given that you’re integrating obviously differentiated on that front? And then are you able to sort of see that same dynamic either in crude or refined products as well?

[Brent Secrest, SVP, Commercial]

Hey, this is Brent. I think that the ability to offer all of those services is a benefit to Enterprise. And I think we’re shy about saying that we leveraged the integration to offer those type of services. I think the customers that we have the most success with are probably typically a larger type customers who want to be in that game, they want to be in the export game. In the case of crude oil, I do think that us having control of that barrel all the way through from the field all the way to the dock when it comes to maintaining quality and executing what that producer wants us to do with that barrel, I do think it gives us an advantage. And I think frankly you’re seeing it with our volumes are coming on quarter-by-quarter.

[Jim Teague, CEO]

Is it fair to say, Brent, on your -- on Midland-to-ECHO 1, I think you have only one contract that doesn’t have an associated dock deal with it?

[Brent Secrest, SVP, Commercial]

That’s right.

[Jim Teague, CEO]

I think that one contract is in negotiations with us for a dock deal?

[Brent Secrest, SVP, Commercial]

That’s correct.

[Jim Teague, CEO]

So, that’s evidence that to your point, the bundled service is quite valuable to us.

[Operator]

And your next question comes from Justin Jenkins of Raymond James.

[Justin Jenkins, Raymond James]

I guess, maybe thinking about the propylene market seemed like that was one of the few headwinds in 1Q. Maybe just your thoughts on how operations unfold here in 2Q and market outlook in the near term for that particular business on?

[Jim Teague, CEO]

I’m going to let Chris D’Anna jump on that, but I think it was headwinds because last year first quarter we had 20-plus spreads, refiner grade to the polymer grade. That’s not something that you would expect long term. I think our spreads were more in the range of what we would have expected. Chris?

[Chris D’Anna, SVP, Petrochemicals]

Yes. That’s absolutely right, Jim. Our first quarter of last year the spreads were just historically very wide and we’ve returned more to a normal. Now our pricing here in the U.S. is much lower than other regions. So that’s also opened up the opportunity to export quite a bit of volumes. So we’re exporting record volumes of propylene across our dock.

[Justin Jenkins, Raymond James]

And I guess, maybe follow-up here on the CapEx bump for 2019. Is that an acceleration of some existing projects or is that a combination of that and maybe some new projects to the fold?

[Randy Fowler, President and CFO]

The Company is looking at it. The increase was approximately about $250 million and I’d say almost 60% of that is in projects that are $10 million and less. And then frankly that’s normally where we get our best returns on capital are from those smaller projects.

[Operator]

And your next question comes from Christine Cho with Barclays.

[Christine Cho, Barclays]

In your prepared remarks, you guys talked about the propane price being lower as a percentage of crude than where it’s historically been. How much of that is a function of price pressure at Mont Belvieu because it looks like we’re at export capacity and with the winter demand domestically for propane going away, more of it I’m sure needs to clear the market. Do you expect that we’re going to see more pressure on propane and butane until your explore expansion comes on?

[Jim Teague, CEO]

I think you could see a little more pressure on both of them. And you’re right that it’s at 40% of crude because the winter is over and there is a lot of supply. I mean you nailed it.

[Christine Cho, Barclays]

Okay. And then I guess just as a follow-up on your LPG export expansion, what -- if you are doing contracting, what are the rates and tenure looking like for those contracts versus what you’ve historically -- what you historically assigned on your first round of export?

[Brent Secrest, SVP, Commercial]

This is Brent. I think in terms of the experience in the sense, I think you’re seeing in the U.S. producers step in for this type of contract. So, and the first kind of wave on these it was traders, it was potentially end users who were trying to open up the U.S. market, so they had alternative sources of supply. I think now, to go back to your prior question, in the case of HD5 propane, it’s got to find somewhere to go. And so it’s going to get turned into export quality propane. So, I feel confident on terms of the length. Obviously, we’re not going to get the rates that we got the last time around. Frankly, we’ve been fairly public that that was probably a mistake. And we got -- we probably asked for too higher numbers and we lost our market share. So you’re going to see rates that are quite a bit less than we got the first time around. You will see a different type of customer for us, but in terms of term, I think we’ll see longer term.

[Jim Teague, CEO]

And let me say, when Brent says lost our market share, he’s talking about going from 80% to 45% to 50%. You can’t -- with all the volume, I don’t think continue being the only game in town. But the other thing he is saying is we’re not going to make the mistake of having prices that and invite more competition. People are going to have to compete hard to meet our pricing.

[Brent Secrest, SVP, Commercial]

In fact, the matter is we have a brownfield project. And for us to expand, it’s much more economical than to allow greenfield projects to start up.

[Christine Cho, Barclays]

And then, can you remind us the hedges, like when the hedges that you have on your volume to Midland-to-ECHO roll-off? And should we think that you guys are going to continue to hedge on basin and any uncontracted capacity you have on Midland-to-ECHO 1 and 2.

[Daniel Boss, SVP, Accounting and Risk Control]

This is Daniel Boss. The hedges that we have on Midland-to-Echo, primarily roll-off toward the end of 2019 and then there is a small portion that goes into 2020. There’s about $26 million of gains left on those hedges that will come off mostly in the second quarter and fourth quarter of this year. So beyond that, we’re on the capacity that’s not contracted under long-term agreements and that’s pretty, pretty wide open.

[Christine Cho, Barclays]

And should we think that you guys are going to continue to hedge that out?

[Brent Secrest, SVP, Commercial]

I think in terms of how we use the space and Brad talked about it and you’ll hear potentially Zach Strait talk about it is we have opportunity with that space. And our plan and our methodology is to allow people who are willing to do long-term contracts with us to use that space. So we’ll try to convert that to long-term deals. If we’re having difficult time getting that done and if we feel like the market is at a number that we like then we could step in and hedge it. But right now the focus is to get long term deals.

[Jim Teague, CEO]

That’s the same thing with the capacity we have on natural gas from Waha to the Gulf Coast. We’re taking advantage of it right now, but we plan to leverage it into Mentone 3 and Mentone 3, right Brent?

[Operator]

And your next question comes from Keith Stanley of Wolfe Research.

[Keith Stanley, Wolfe Research]

Just some quick clarifications. On crude marketing being so strong in the first quarter, is it fair to say most of the year-over-year increase there is just Seminole ramping up before the contracts kicked in, in April or were there other areas of strength in crude marketing?

[Brent Secrest, SVP, Commercial]

I think if you look at Midland-to-ECHO 2, I want to say we averaged just shy of a 100,000 barrels a day on that that was unhedged space. So that drove the value of what the market was at the time. There is some unhedged space we have on other pipelines. In terms of what you can expect quarter-over-quarter, I mean you’ll see obviously increased volumes on Seminole. The rate will probably go down or will go down, but at the end of day, that’s the highest rate we have on any crude transport out of the Permian Basin. And the fact of the matter is there will be other opportunities. And it’s hard for me to sit there and say the opportunity is going to be at the dock or the opportunity is going to be in storage, but we talk about all the opportunities we have at this company across all the different commodities. In the case of maybe this quarter, there was an opportunity on crude basis.

[Keith Stanley, Wolfe Research]

And on frac 10, did frac 10 get accelerated now, I just want to make sure I’m reading this right to the fourth quarter of 2019 instead of early 2020?

[Jim Teague, CEO]

Zach, you’re too nervous to answer questions?

[Zach Strait, VP, Unregulated NGL Commercial]

It’s just getting started.

[Jim Teague, CEO]

It’s a nice short answer.

[Operator]

And your next question comes from Colton Bean of Tudor Pickering Holt.

[Colton Bean, Tudor Pickering Holt]

Thanks. And just to follow up briefly on the crude oil basis discussion there, you -- to some degree was Q1 impacted at all by the Cushing-to-Houston spread? And I guess if so, when he has expanded Seaway last year, was there incremental spot capacity associated with that or is that all thought of a third party?

[Brent Secrest, SVP, Commercial]

The Enterprise Marketing has Seaway space. And then when the expansion came out last year that space was fully contracted for. If you look at Seaway pipeline, the fact that achieves market base rates, there can be an arb, but obviously that’s shared with our partner. But in the case of volumes, Enterprise from the marketing standpoint is moving crude oil down Seaway as it makes sense. And sometimes those volumes are less and sometimes they’re more.

[Colton Bean, Tudor Pickering Holt]

Got it. And I guess just to circle over to the Shin Oak, given last week’s update on the Alpine High, does that change your view on the ramp over the course of 2019? And if so, is there any potential to backfill that with other counterparties?

[Tug Hanley, VP, Distribution]

Yes. This is Tug. No, it doesn’t. Just for example, the Shin Oak mainline is in service right now, flowing at 203,000 barrels a day and we have yet to complete the lateral down to get those volumes which will be in sometime around June. So we don’t see that impacting us. And then furthermore, I believe some of the curtailments reductions are dry gas not rich gas, that’s what we’re seeing.

[Jim Teague, CEO]

The other thing on Shin Oak is the most valuable or the most reliable supply to Shin Oak and to our fractionators comes out our own processing plant. And I don’t think we’re through -- we’ve mentioned the possibility of two more Mentone plants, I mean that’s another 80,000 barrels a day, Tug. And I don’t think that’s going to be the end of our processing plants in the Permian, all of which would be in Shin Oak.

[Tug Hanley, VP, Distribution]

And Shin Oak, just a reminder is not just connected to the Permian, it’s connected to our entire system which touches just about every basin there is.

[Operator]

And our next question is from Shneur Gershuni of UBS.

[Shneur Gershuni, UBS]

First off, just wanted to say really appreciate the increased disclosures that you guys disclose with today’s earnings. Just a couple of questions here. Kind of a follow-up on the buyback and the DRIP questions from earlier. Just kind of what are your thoughts on just turning the DRIP completely off at this point right now? And in your responses on buybacks, you talked about wanting to be opportunistic and at the same time you’re evaluating a lot of large projects.

If I recall correctly, at the Analyst Day you talked about $5 billion to $10 billion worth of projects that you were hoping to FID at some point. Is there something more than that that you’re thinking about, because I mean your results, Jim, as you said, you showed us the cash, you’re producing very healthy excess distributable cash flow that can certainly fund that kind of a backlog. So is there something more that we should be thinking about or could we actually see some -- a more elevated pace of buybacks?

[Jim Teague, CEO]

Yes, Shneur. On the DRIP, again, you have some participants in the DRIP that just like to reinvest without broker fees frankly and some of that cash is going to continue to come in. Rather than come in and just turn that program off all together, we could come in and maintain our flexibility by continuing the program. But instead of the units being sourced from newly issued units, you just source the units by doing open market purchases. So I think, one, I think it still provides the company some flexibility on a longer term basis, but then also comes in and continues to those participants that want to continue to purchase through the DRIP even without a discount still keeps that option, a low cost investment options for them. As far as being opportunistic on the DRIP, Shneur, really like I said, not much changed from three weeks ago. I think we still see $5 billion to $10 billion worth of projects under development. The guys are continuing to chase other projects as well and right now just looking to come in and maintain flexibility and be opportunistic on the buyback. Really not a lot additional perspective I can give you.

[Shneur Gershuni, UBS]

And maybe as a follow-up question, obviously, you’re talking about your LPG export capabilities now strong it is, you have some peers or should I say competitors that are expanding theirs and others that are evaluating and so forth. Is there an opportunity for you, I’m not sure if the word opportunity is the right word, but just sort of given the competitive landscape, I mean you kind of want to keep the export capacity to something that’s obviously manageable for the market. Do you sort of sit there and say, let’s take a lower price on our export fees for a period of time to ensure that all this proposed capacity and potential capacity doesn’t actually end up getting built? Just kind of wondering about your thoughts on the competitive dynamic there.

[Jim Teague, CEO]

I think Brent, put -- said it and as did Justin, we’re going to be very competitive on long term deals. And that translates to we’re not going to make the mistake we’ve made last go around. We’re not looking at $0.12 fees, we’re looking at fees that I doubt can build greenfield on. Is that right, Justin?

[Justin Kleiderer, VP, NGL Marketing and Supply]

That’s right.

[Shneur Gershuni, UBS]

All right. I guess that answers the question, perfect. Thank you very much, guys. Really appreciate the color.

[Randy Burkhalter, VP, IR]

Christie, this is Randy. We have time for one more before we cut the Q&A off. Okay?

[Operator]

Yes, sir. And your final question comes from Michael Blum of Wells Fargo.

[Michael Blum, Wells Fargo]

I have two related questions on Midland-to-ECHO 3. So I guess the first question is I think consensus view is that within a year the Permian will be pretty overbuilt in terms of crude takeaway capacity. So I just wanted to understand in the context of that, is that a bad assumption or what are you seeing that you think you’re going to have demand for another incremental crude pipeline out of the Permian? And then the second part of that question is, a competitor pipe recently increased the costs pretty substantially of their crude pipe and they pretty much talked about rising steel and labor costs. And so I wanted to kind of see what you guys thought in terms of if you’re seeing any of that?

[Jim Teague, CEO]

Hello, Michael. This is Jim. I’ll take the first part, latter, I’ll let to Brent and then we’ll let Graham answer the last part. But when you have a large producer that wants you to build a pipeline, you take a hard look at it. We differentiate, but you see all the pipe coming out of the Permian, I agree, there’s a lot of pipe. But there’s -- we differentiate what’s going to Corpus, what’s going to Cushing as it relates to what’s going to Houston. Houston is the big sponge and most of your major producers want to go to Houston and they want to go to the big sponge. And they like the fact that when they come through Enterprise, they’re going to make sure their quality is going to be -- we’re going to keep the quality high, and we’re going to give them 4.5 million barrels a day of market or refining market, we’re going to give them 300 million barrels of storage, we’re going to give them the ability to export their barrels. So, when we look at, oh God! There’s a lot of pipelines; we say, there is not enough to Houston. And I think that’s what the major producers think.

[Brent Secrest, SVP, Commercial]

And I’ll add to that, Jim. Fact of the matter is we have a decent number of producers who are coming to us asking us to build another pipeline. And so when they ask you to do that then obviously you have to take a look at it. And if you look at what we have upstream of our system in Midland and what we have downstream of our system in Houston and you put everything together, it looks like a really good project. Now, if you want to take out all the production and Tony has is curve, but you want to apply the capacity, pipeline capacity on there, I would agree with you that it does look overbuilt. But to Jim’s point, so what doesn’t happen. And so I think barrels going to Cushing probably don’t happen. To apply a 100% capacity factor, the pipelines that go to Corpus, I think that’s very optimistic. And then if you apply the pipelines that go to Corpus, they have acreage dedications, I’m not sure that equals to a 100% capacity factor. So, our contracts, if you look at our contracts and our essentially all 10-year contracts won’t expire until 2026. Then we kind of look at that timeframe and find out what’s overbuilt. And at that point in time, it looks like the Permian is under built when it comes to pipeline capacity. Jim alluded to his comments about converting crude oil back to an NGL line that was converted to crude line back to an NGL line, that’s an opportunity, that’s an optimization that we have. But ultimately, we don’t have any contracts expiring during this overbuilt time. If we did, I probably would be more concerned about it.

[Jim Teague, CEO]

Graham, what about the costs?

[Graham Bacon, EVP, Operations and Engineering]

As far as the costs, we’re seeing slight increases in costs from the time we did Midland-to-ECHO 1. Nothing substantial, but I think we’ve been able to lock in cost for steel and pipe, steel prices have actually gone down, pipe stayed relatively flat during that time period just due to the impact of the tariffs, but all of that we can do is make a project work for Brent and his team.

[Michael Blum, Wells Fargo]

Great. Thank you.

[Jim Teague, CEO]

Okay. Christie, if you would, would you please give our listeners the replay information before we close the call? Thank you.

[Operator]

Yes, sir. And thank you all for participating in today’s conference. This call will be available for replay beginning at 1 o’clock p.m. Eastern Time today through 11:59 p.m. Eastern Time on May the 9th, 2019. The conference ID number for the replay is 6667747. Again, the conference ID for the replay is 6667747. The number to dial for the replay is 1800-585-8367 or 855-859-2056 or 404-537-3406.

[Jim Teague, CEO]

Thank you. Thank you, Christie. And thank you everyone for joining us today. And have a good day. Good bye now.

[Operator]

And, thank you again for attending. You may now disconnect.