Enterprise Products Partners LP (EPD) 2017 Q4 法說會逐字稿

Good morning. My name is Amy and I will be your conference operator today. At this time I would like to welcome everyone to the Enterprise Products Partners Q4 2017 earnings call. (Operator Instructions). Thank you. Randy Burkhalter, you may begin your conference.

Thank you, Amy. Good morning, everyone, and welcome to the Enterprise Products Partners conference call to discuss earnings for the fourth quarter. Our speakers today will be Jim Teague, Chief Executive Officer of Enterprise's General Partner; and Bryan Bulawa, Chief Financial Officer. 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 that may be made during this call.

And with that, I'll turn it over to Jim Teague.

Thanks, Randy (technical difficulty)

Amy, are we on? I hear some interference there.

No, you are the only one I hear.

Okay. Thank you, Randy. As we said in this morning's press release, our businesses continued to perform well in 2017, and, frankly, throughout the turmoil over the last three years. With higher crude oil prices, production of oil and gas in the US is growing dramatically. Meanwhile, demand globally continues to exceed expectations.

The downturn that started in 2014 has been painful, but it did have a silver lining: the downturn taught the market a lesson about the staying power of the US oil and gas industry. Abundant, short cycle, highly reliable supplies priced by free markets and made possible by a workforce who have produced from rock that was previously thought to be worthless. As indicated by record liquid pipeline volumes and record marine terminal volumes, the amount of this new production that is in our pipes, in our plants, and moving across our docks is continually growing.

Given our size, our reach, and our business model, we have significant operating leverage across all our systems to handle growing production, serve new markets, and handle the significant increases we're seeing in exports.

In addition, we have a number of our long lead time projects coming online and several new initiatives that are under construction.

For 2017, Enterprise reported a 10% increase in operating income to $3.9 billion. Gross operating margin for 2017 increased 8% to a record $5.7 billion from $5.2 billion in 2016. Net cash flow provided by operating activities for 2017 increased 14% to $4.6 billion from $4.1 billion. Distributable cash flow, excluding proceeds from asset sales, increased 10% to a record $4.5 billion in 2017 from $4.1 billion in 2016. We retained $860 million of distributable cash flow in 2017 to reinvest.

It's been a long time since we've reported record, in quotes, financial and operating results like these. Actually, the last time was in January 2015, when we were reporting 2014 results at much higher commodity prices.

During 2017, Enterprise completed construction and either began service or commissioning on projects represent $4.5 billion. In the fourth quarter, we began limited service on our Midland-to-Sealy pipeline, moving one grade of crude from the Permian Basin to the Houston refining and export market. This pipeline is expected to be in full service in the second quarter after we complete construction of pump stations and storage facilities.

We're operating our PDH facility, which has been running and producing polymer grade propylene. We expect commissioning activities to last another month.

Other major growth projects completed in 2017 included an expansion of our ATEX ethane pipeline, expansion of propylene pipeline infrastructure on the Gulf Coast, and expansion of our refined products and crude oil marine terminals in Beaumont.

In addition, we have another $5.5 billion of growth projects under construction. In the Permian Basin, we are scheduled to bring on two natural gas processing plants at our Orla complex in the Delaware Basin this year, one in the second quarter and the other in the third quarter; put our Midland-to-Sealy crude oil pipeline system in full service; and continue working on our third Orla plant, which is scheduled to be put into service in 2019.

When you look at a map of our systems, you couldn't have put the Permian Basin in a better place. It's close to our assets all along the Gulf Coast, and literally in the fairway of many of our natural gas and natural gas liquids assets. We're finding opportunities to connect the dots around our assets, including expanding existing assets, converting assets, and building new projects like our Orla processing complex, Shin Oak, and Midland-to-Sealy crude line.

We're not done finding opportunities in what is now the world's hottest basin. As to Mont Belvieu and petrochemicals, we'll soon be putting our ninth NGL fractionator in services, and we're expanding our NGL crude oil and refined product storage facilities.

Our iBDH is under construction with completion expected in 2019. Half of this plant will help fill excess capacity in our high purity isobutylene and MTBE plans, which will allow us to upgrade more NGLs into higher valued products. The other half of this capacity is committed to an investment grade customer through a 15-year fee-based contract on a feedstock plus cost basis.

Also in petrochemicals, we've begun building an ethylene logistics system to support the nearly 50% increase in ethylene capacity we are seeing on the Gulf Coast. Like we've seen in natural gas, NGLs, and crude oil, petrochemical expansions of this magnitude don't come without opportunities for Enterprise. We are converting a storage cavern to a high-capacity ethylene salt dome well at Mont Belvieu, which is expected to begin service in the first quarter of 2019. The system will be designed around the eight ethylene pipelines that are within a half a mile of our storage system.

We also announced this morning that we have entered into a 50-50 joint venture to build a new ethylene export facility along the Gulf Coast that will have the capacity to export 1 million tons of ethylene per year. These new ethylene assets leverage and extend our existing NGL and petrochemical systems, and we believe are the beginning of a Gulf Coast ethylene distribution system.

A lot of folks don't realize that by 2021, just of the state of Texas will be the largest producer of ethylene from steam cracking in the world, and that's not counting what is happening across the border in Louisiana. That's in our backyard. And the resulting rapid growth in ethylene, combined with increased international demand from markets like Asia, creates an ideal scenario in which markets abroad can diversify their supply towards cost-advantaged US feedstocks.

Finally, some comments on exports. With the continuing increases in production, more and more products are being exported. Our Midland-to-Sealy pipeline has delivered initial volumes to the Houston area; and, as predicted, we're seeing most of this crude being exported. Obviously, the same can be said for NGLs, including ethane, and for petrochemicals and refined products.

Our dock activity has increased by approximately 50% in the last year. We expect continued increases in market share for the hydrocarbons from our dock.

We mentioned in our press release that our success in 2017, and, frankly every day, would not have been possible without the daily creativity and hustle by our folks -- of our team of over 6,700 employees. In 2017 -- and this is something we're quite proud of -- in 2017, Enterprise had the best safety performance ever, with a total recordable rate of 0.41 and a lost time rate of 0.17.

This is because of the hard work and diligence of all of our folks at Enterprise. Sincere thanks to the entire Enterprise team for 2017, and the bright future that you continue to give our Company. We feel pretty good about 2018 and our longer-term opportunities.

And with that, I'll turn it over to Bryan.

Thank you, Jim, and good morning, everyone. I'd like to echo Jim's earlier comments that we are very pleased with our record operational and financial performance. Our operational DCF per unit, or, if you will, which excludes asset sales, insurance proceeds, and monetization of interest rate derivatives, was $2.05 per unit for 2017. This compares favorably to the same metric in 2016 of $1.93 per unit, and approaches DCF per unit levels enjoyed prior to the most recent commodity cycle downturn, or again, if you will, 2014.

Before diving further into our discussion, one of the most popular topics during our recent investor calls and meetings relates to the expected impact associated with tax reform. The Tax Cuts and Jobs Act passed by Congress in December 2017 appropriately preserves the favorable tax attributes for master limited partnerships, and encourages MLPs to continue investing in infrastructure growth opportunities which contributes to US job and GDP growth.

Now, having said that, I will review a few income statement items for the fourth quarter, provide 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 income statement items, net income attributable to limited partners for the fourth quarter of 2017 was $774 million, or $0.36 per unit on a fully diluted basis, compared to $659 million or $0.31 per unit on a fully diluted basis for the fourth quarter of 2016. Net income attributable to limited partners and fully diluted earnings per unit for the fourth quarters of 2017 and 2016 include non-cash impairment charges of approximately $15 million and $24 million, or $0.01 per unit for both quarters, respectively.

Depreciation, amortization, and accretion expenses were $21 million higher when compared to the same quarter of 2016 due to assets being placed into service such as our Midland-to-Sealy crude oil pipeline, which began interim service in November; our Morgan's Point ethane export terminal; the Azure asset acquisition; and a number of expansions.

Total capital spending in the fourth quarter of 2017 was $1 billion, including $80 million for sustaining capital expenditures. For the full year 2017, we invested $3.4 billion for growth capital projects and acquisitions, including the $191 million we paid in connection with the Azure acquisition, and $244 million for sustaining capital expenditures. For 2018, we currently expect to invest approximately $3 billion for growth capital expenditures and approximately $325 million for sustaining capital expenditures.

Moving to our balance sheet, at December 31, 2017, our total debt principal outstanding was $24.8 billion. The average life of our debt portfolio was 13.9 years, assuming the first call date for our hybrids. And our effective average cost of debt was 4.6%. Approximately 87% of our debt outstanding is fixed rate, thereby insulating our debt portfolio in a rising interest rate environment.

Adjusted EBITDA for the 12 months ended December 31, 2017, was $5.6 billion. And our consolidated leverage ratio was 4.1 times after adjusting debt for the partial equity treatment of the hybrid debt securities by the rating agencies, and further reduced for cash and cash equivalents.

Working capital requirements remained elevated by approximately $700 million or 0.1 times leverage, with self-liquidating short-term marketing opportunities along with higher inventory levels attributed to the continuing effects of Hurricane Harvey.

When further applying the pro forma impact of our contracted growth projects under construction during the quarter, namely PDH and Midland-to-Sealy, our leverage ratio would have been 3.7 times.

Our consolidated liquidity was approximately $3.7 billion at December 31, 2017, which included available borrowing capacity under our credit facilities and unrestricted cash.

With respect to the upcoming distribution, which will be paid next week on February 7, Enterprise Products Company and certain of its affiliates plan to reinvest an aggregate of $100 million in EPD common units through the Partnership's distribution reinvestment program. This continuing level of support from our General Partner will further reduce our external equity funding needs for 2018.

This year represents the 20th year since our IPO. And with this latest investment, the Duncan family's support of our Partnership through purchases of EPD common units, contribution of assets, and waiver of distributions totals over $2.5 billion.

Finally, during 2017, we funded through excess distributable cash flow or retained earnings approximately 55% of our equity funding requirements attributed to 2017 growth capital investments. We anticipate this level to continue to rise in 2018, and to reach a self-funding equity model in 2019, with a $2.5 billion to $3 billion growth capital investment profile, while preserving our targeted leverage objective of 3.75 to 4 times.

And, with that, I'll turn the call back over to Randy.

Thank you, Bryan. Amy, we're ready to take questions now from our listeners.

(Operator Instructions). T.J. Schultz, RBC Capital Markets.

Good quarter, guys. I think just first on the ethylene export terminal, to reach FID you mentioned you need acceptable arrangements with local tax authorities. Is that just procedural? Or if you could expand what still needs to get done to reach FID, and any reason it would not be at Morgan's Point.

The reason it wouldn't be at Morgan's Point is we can get a tax abatement that's better somewhere else, and there's another location that we could put it at.

Got it. Okay, thanks. Just on Shin Oak, the volumes from the converted pipe, do those move over at the startup for Shin Oak? And then beyond the volumes you get from the Orla additions, what traction are you getting on adding other customers? And is there any change to your initial design capacity, I think at 250,000 barrels a day?

I fully expect that we'll have to bring it on at a little more than 250,000 barrels a day, and we're having positive discussions with several people.

Okay, great. Thanks, guys.

Tom Abrams, Morgan Stanley.

I wanted to understand a little better about the mix on the Midland-to-Sealy, Midland-to-ECHO, inasmuch as you've got the uncommitted tariff volumes that might decline and committed flows coming onto it. Will that impact the EBITDA temporarily at all in the next couple quarters?

I think when you look at -- this is Brent Secrest -- if you look at the walk-up rate and where the margin is currently for the first quarter, and if you extrapolate that over the rest of the calendar year, you'll see volumes increase and the per-barrel fee decrease. But I wouldn't say there's a major delta between the dollars.

Okay. That's good. The other one, a couple of long ball questions. One is -- actually one might be more short-term. Inasmuch as the capacity on Midland-to-Sealy is filling up faster than some might have thought, and there's a lot of people hunting around for additional barrels to put on new pipes, can you -- are you in a position, perhaps, to do something earlier than your NGL conversion idea after Shin Oak? Literally, could you have either an expansion of Midland-to-Sealy, or yet participate in another project in the next couple years?

We can wrap Midland-to-Sealy up beyond what our initial capacity is going to be relatively easy with just pump stations. I think we say -- we can do that and we can use DRA, which is fairly inexpensive. So yes, there's upside there. I'm not sure exactly what --

All right. And then a couple of the long ball questions are, if you are hearing anything tentatively about additional petchem facilities on the Gulf Coast?

Yes. Tony believes there's a second wave coming. We have companies in here whose name I can't hardly pronounce pretty routinely talking about wanting to evaluate putting ethylene plants in the US.

Tony?

Absolutely. With the plentiful ethylene that we have, and that number growing, especially when you look at the Delaware Basin, people understand this. So they are coming, I believe.

Yes, one of the things, and it gets back to our ethane export also, it is a big -- when crude oil goes up and natural gas doesn't, it makes this a heck of a lot more attractive than it was this time last year.

Are you moving the timing of that wave forward?

It's hard for us to predict when these folks are going to have FID, so it really is. These plants take a while to come on and people to plan for them. But at the end of the day, the macro look is that people are coming to the US to make ethylene because ethane supplies are so plentiful.

Lastly I was just wondering, when you get to 2019 and you are self-funding, what happens next with -- assuming DCF per unit keeps growing -- what do you do with that extra coverage? What are the priorities?

I think we'll wait till 2019 and see what the opportunities look like, at that point in time. To come in and speculate on that now is a little bit premature.

Fair enough. Thanks, Randy.

Darren Horowitz, Raymond James.

Jim, my first question: on the petrochemical value chain, specifically on propane versus propylene, if we end up tracking towards 32 million or 33 million barrels of propane at inventory exiting March, obviously that's below five-year lows, and that supports higher propane prices.

Does that mean, for you guys, the way you look at it -- do you have more of an opportunity to arb the propane price curve, or to arbitrage what could be an even wider propane to polymer-grade propane spread?

And then that kind of legs me into my next point: that means that quote-unquote commissioning activity on the PDH could actually capitalize on that before enacted -- it ends up entering commercial service. How does the math work for you?

I think you answered your own question, Darren.

I guess I just wanted to hear you say that, Jim. (laughter)

Randy, you want to take it? R.B.?

Well, every pound that we produce in PDH while we are commissioning is sold to our customers as we go. So we're selling PGP right now on a propane basis.

How wide do you think that spread, R.B., could get over the next couple months?

I don't think I'm the right person to speculate on that.

Okay. And then just one quick housekeeping question for Bryan. As it relates to contango opportunities across the commodities, let's just generically call it, how much do you guys have out on the working cap facility currently?

Well, we -- our working capital facility really is -- we have $5.5 billion of credit facilities. So the -- what we have outstanding, or what we had at December 31, was about $1 billion of working capital associated with short-term marketing opportunities as well as some elevated inventory levels; again, from the effects of -- the ongoing effects of Hurricane Harvey.

(multiple speakers) Everything is backward today. So we either have contango rolling off, or we're putting -- or we're taking advantage of backwardation, which is bringing money in.

And from a short-term perspective, with regard to that $1 billion that's out on the facility, how much of that do you expect to be mark-to-market in 1Q?

Well, Darren, it's always -- it's dangerous territory because markets shift. But currently it -- we declined from September to December by about $300 million. And I think we'll see that pull back by at least that amount from now to the end of March.

Okay.

There was a decent amount just in the commissioning of Midland-to-Sealy. And as contracts roll on, you'll see some of those crude working inventories roll off.

Okay. That's all I had. Thank you very much.

Brian Zarahn, Mizuho.

A follow-up on Midland-to-Sealy. Can you give an estimate of how much additional capacity could be added through DRA and pump stations? And how long would you estimate it would take to add additional pump stations?

I don't think we'd need additional pump stations. We wouldn't need additional pump stations, just DRA. And it's somewhere between, what, 520,000 and 550,000?

A little bit more than that.

Okay. Let's call it 550,000 barrels a day. Total.

And then I guess switching to NGLs, as you -- as of today, how do you see the ethane uplift opportunity on your system, with the crackers making progress coming online?

Brian, this is Tony. We publish a slide as to how we see ethane balances west of Appalachia, and we think that drives ethane prices. So I don't want to tell you that we think ethane is going to blow out. Obviously, you could have periods of volatility. We acknowledge on our slide there'd be times where ethane could be tight, and people could be reaching into storage or going to other products.

But at the end of the day, especially with the new production forecast -- we're not finished with it yet -- but incremental ethane volumes, we're not predicting that you're going to have a big blowout in ethane prices.

Probably if you are in the Permian or the Eagle Ford, you're going to see -- I mean, it's going to be transportation-related, and it's going to be the appetite that petrochemicals have for ethane. If they have an appetite, then you're going to see higher margins, the closer you are to the marketplace. So in the Permian and the Eagle Ford, you're going to get -- it's going to be -- you're going to enjoy it. If you're further away, it's going to be marginal.

On the -- not as much on the price side; on the volume side in your system, are you optimistic this year about upside? Processing volumes, transportation, frac volumes, related to ethane recovery?

This is Brent. If you look across our portfolio and our expectation of the ethane and the Y-grade, I mean it's quite healthy in terms of the increase in volumes. So I think where the margins are right now, it makes sense for people to recover ethane.

Thank you.

Ted Durbin, Goldman Sachs.

PDH, just coming back there, still in commissioning. Just feels like that continues to push out a little bit to the right. What's happening with why we're not at full commercial service? And then can you speak to -- are you actually producing on-spec product now? Was there any kind of earnings contribution in the quarter from that? Or where is all that product going?

We have produced on-spec product. These things are -- these are really big plants, and it's not unexpected that commissioning takes a little longer. All you got to do is look back at Dow and PetroLogistics and see that. We expected that. But yes, we have been gradually ramping up, and we have been producing on-spec propylene.

Graham, you got anything else to add?

We've been producing on-spec propylene at capacity. As we go through this there's a certain amount of activities in terms of conditioning the catalyst that require us to do some different things. But overall, the plant is up and running, and we're just taking it through the normal steps of commissioning right now.

Okay, great. And then as you're in the commissioning phase, I think there was a thought that you might be able to run a bit above nameplate. Is that still potentially in the cards on the plant, or what's your view there?

Ted, we'd just like to get to nameplate right now and hold it there. We would hope -- if it's like every other Enterprise plant that's built, we'll probably have excess capacity. But we're not selling it yet.

Understood. And then just I heard the quick comments on tax reform, but I know one of your -- one of the questions we've gotten and you've thought about over the years is the optimal corporate structure for Enterprise. And one of the uncertainties there was what happened with tax reform, so we have that behind us now.

I'd just love your thoughts on whether you do think you're in the right corporate structure as you think about access to capital, M&A, or other strategic ideas.

Ted, this is Randy. I think where we are is -- I think we still feel like the MLP structure works for us as far as access to capital is concerned; access to equity capital at a reasonable price. We will continue to monitor, frankly, how the market values midstream C-Corps versus midstream MLPs. Frankly, we haven't seen a lot of difference over the last couple of years. But frankly, there was a lot of noise in the space, whether you were a C-Corp or an MLP over the last three years.

So I think we will continue to monitor that and see what develops on that front. But that's a forever election, so it's not to be taken lightly. And we will continue to come in and evaluate, but we think we got good access to capital now.

Understood. I'll leave it at that. Thanks, Randy.

Colton Bean, Tudor, Pickering, Holt.

Just on the ethylene export project, there's some US petchem producers who are long ethylene capacity relative to their polyethylene. So do you think there's potential to add to the current level of commitments, or are you comfortable with where they sit today?

We think we're going to add to the current level of commitments.

Okay. Any sense as to where we sit versus capacity?

Excuse me?

Just in terms of commitments versus capacity, any comments there?

No. Enough to make it accretive.

Understood. And just switching gears, on the LPG export side of things, it looks like the spread between US and global pricing has widened out a bit, presumably tied to the naphtha linkage. But shipping rates are still relatively muted. So any sense as to where the margin is accruing, whether that be on the terminal side of things, or just offtake or trading margins?

This is Brent talking. I think the feedback that we're seeing, the traders are struggling with it. The guys who are taking it across the water are struggling with it. And so the folks who did the take-or-pay terminaling fee, I think those are the ones that are probably making money in this market. When these contracts first started, it was a different deal. Those were the guys making most of the money and the terminaling guys were just making their standard fee. But it's definitely swung the other way.

Okay, perfect. Appreciate the time.

Jean Ann Salisbury, Bernstein.

I just want to make sure I'm thinking about Midland-to-Sealy right. You averaged 333,000 over the fourth quarter, but started up in November. Does this mean that you were running at close to 500,000 in November and December? And if so, is this higher than nameplate because you're not blending, and it'll come down once your blending infrastructure is in?

I don't think we were running at 500,000 at any point in time.

Yes, Jean Ann, I think part of it is with a pipeline, the base capacity before we did -- added pump stations, was 300,000 barrels a day. So pretty much when you bring up a pipe, it's coming up. And so we -- I'd say there wasn't that much of a ramp from November into December.

So does that mean that in October, you had some line fill and some numbers that were included there?

I think that numbers are -- if you look at the days that crude was flowing on the pipeline, we averaged 330,000 barrels a day.

Okay, got it. But not necessarily over the entire fourth quarter?

That's right.

Okay, perfect. And then are you currently marketing the volumes on the NGL to crude conversion pipeline from the Permian? It sounds like there might be significant downward pressure on rates from newly FID'd pipelines like EPIC and Cactus 2, or at least that is what the E&Ps are saying. So I was just wondering if you could say what you are seeing in the marketplace.

Tug, you want to take it? Or Brent?

I think your color on the rates, I mean there's a lot of competition for crude pipelines right now. And you guys can read the announcements just like we can. But we are still pursuing the conversion of the NGL line. We got -- talking to a handful of customers who value having essentially their own pipeline and their own quality of crude oil, so that project's -- we're still pushing forward on it.

Okay, that makes sense. But in general, as a blanket statement, we should expect the next wave of crude pipelines that are FID'd to be at materially lower rates than what's there now.

I would say so.

Okay. Thank you so much.

Jeremy Tonet, JPMorgan.

Just wanted to come back to Midland-to-Sealy here, and wanted to make sure I had your comment straight as far as what the ultimate size of the pipeline could be. It sounds like it's on track for 450,000 right now, but adding DRA could bring it to 550,000, and then pumps could bring it bigger? Or could you just help clarify that for me, what's the ultimate potential size Midland-to-Sealy could reach if market demand is there?

Right now we've got the capacity to go in the 540,000 to 550,000 range. There's a few other studies that we can do to tweak it that we might be able to get slightly higher than that, but we haven't completed those yet. Those are underway.

Got you. So that would just be pumping -- adding a little pumping could maybe get a little bit more than that?

That's just some optimization of equipment that is involved that we didn't have in the initial installation that we are taking a look at. And we just haven't published a number on that yet.

Okay. And then for the earnings capacity of the pipe right now, if it was a -- just over $60 million contribution, and that was only part of a quarter. It seems like there was some benefits there with the spread. And just wondering if you could help us think about what the normalized earnings power of this asset is, just so that we don't get ahead of ourselves as far as our estimates are concerned.

And then the $36 million uplift in South Texas in the Eagle Ford, I was just wondering if you could parse out how much was Midland-to-Sealy related versus maybe other drivers, so we could just better model what's happening in the segment.

Okay, Jeremy. I'll take the first part of that. On Midland-to-Sealy, Midland-to-ECHO, I think that, if you would, that $60 million, $65 million for the quarter from a modeling standpoint, that's probably a good run rate over time. Again, it will -- as we bring it up into service, that will move around, but that's probably a good run rate.

On the Eagle Ford, if you could repeat your question on the Eagle Ford.

It seemed like there was a $36 million uplift in the quarter in South Texas in the Eagle Ford on the crude side there. And it seems there was some knock-on effect from the Midland-to-Sealy pipe. At least that's how I was reading the press release. I was just wondering if you could add a little bit more color to that.

That's exactly it. That was all -- or I'd say almost all of it was Midland-to-Sealy related for those volumes to go on Rancho II. It's not a significant increase in Eagle Ford, by any stretch.

Got you. That's helpful. And then one last one, if I could. It looked like the fee-based nat gas processing volumes ticked down a little bit in the quarter. I was just wondering if -- from looking quarter-over-quarter there, I was just wondering if that's any seasonality or shift to commodity sensitive, or anything else that you can help us with there?

This is Brad. Biggest driver was the South Eddy fire. South Eddy was down for 5 to 6 weeks, and that was a big driver in the quarter for the delta.

That's very helpful. That's it for me, thanks.

Keith Stanley, Wolfe Research.

Just wanted to first circle back on equity needs for this year. So CapEx is going a little higher here. Just curious if you think it's still possible to only need the DRIP this year, based on the current plan.

Keith, this is Bryan. There's several factors that it is dependent upon. Certainly the ultimate size, as you cite, with respect to our growth capital, which is at $3 billion today; and we certainly hope more opportunities come our way and that grows.

We are also -- in our assumptions, and we talked about this last quarter -- we have modest assumptions around the participation in the distribution reinvestment program. It certainly will be dependent on the timing around PDH coming fully online, as well as Midland-to-Sealy or Midland-to-ECHO performing as we anticipate, and the two Orla trains that are coming on this year. So there's a lot of moving parts.

But having said all that, with the potential shifts in those factors, still anticipate our external equity needs to be very light.

Okay, great. And one follow-up just on the Q4 results. Obviously a lot of strength across the businesses overall, but the NGL and crude marketing businesses continue to see some pressure here. Can you just give a little more color on what's going on there?

This is Brent. On the NGL side, you are seeing a compression of spreads. And we've talked before in the past that we are somewhat resilient to decreased commodity prices because of our storage presence. So there's a lot of contango opportunities that marketing gets to realize. But as the market gets backward, barrels start to flow down pipes. They don't stay in storage, and that limits some of our opportunity.

Crude oil, you're seeing some compression on spreads. I feel that things are getting better, especially from a crude purchasing side. But just overall, storage is one of our plays, and storage and contango opportunities are somewhat limited right now.

Okay. That makes sense.

Is it fair to say we like it better when our pipes are full than when there are contango opportunities, Brent?

That's right. So I think as Enterprise -- when barrels are flowing and going through us, that's a good thing for us. But from a marketing side, we're probably more there to help insulate when that's not happening.

Thank you.

Michael Blum, Wells Fargo.

Just two quick ones for me. One, just a point of clarification on PDH. When this year do you expect it to be fully up and running?

I think we said in the earnings script that we figure by the end of February, things ought to be humming along. That's our plan.

Okay. And then the second question is: can you give us your thoughts on a Front Range Pipeline expansion? It seems like the NGL market in the DJ is getting -- or could get tight. And just wanted to get your thoughts on if that's possible; and, if so, what would the dynamics need to be to make you go ahead with that?

Do you want to take it, Tug? Do you want me to take it? It's because you don't know the answer, right? (laughter) Michael, yes, we can expand that pipeline. We're looking at expanding that pipeline. And we've got producers on that pipeline that are working with us to make that happen.

You think that's a 2018 event?

Early 2019.

Early 2019, Tug says.

All right. Thank you so much.

Becca Followill, U.S. Capital.

One question left that hasn't been asked: ATM program, anything done in the quarter on that?

Hi, Becca. None.

Okay, thank you.

Nick Raza, Citi.

Just turning to the Permian real quick, do you still have an interest in building your natural gas pipeline down to Agua Dulce? Could you just give us your view of that or recent projects have been announced?

This is Jim. Yes, we still have an interest. Whether we can get traction on it is a different thing. And we've brushed it off here recently; and, frankly, we're taking a look at it. I think ultimately, personally -- I'll look to Tony and Brad -- I think a second pipeline is going to be required out of there. And whether it's to Agua Dulce or Katy or wherever, but there will be a second pipeline needed.

Tony?

No question. No question whatsoever.

Okay. And what do you think the spread needs to be, roughly, to entice a midstream company to FID a project, after all the projects that have been announced and FID'd right now have come through?

You are talking about on a natural gas pipeline?

Yes.

I'd see a natural gas pipeline as being a way to produce crude oil. So I'm not sure it's just the spread of natural gas. I think it has to do with our ability to produce crude.

Tony?

I agree. And I'll tell you, if you look at the spreads today, it'll sort of take your breath away as far as what basis is trading at: well over $1. And then basis markets assumes that a pipe is going to be built, and then it still is over $0.50 for as long as you can look at it. So, the market is saying another pipe is needed and will be built.

This is Brad. I'll just echo what Jim and Tony said. A lot of the conversations we have with producers, it seems as that the first wave did take capacity on that pipeline. But there are a lot of people out there that are still trying to understand what their long-term plan is, and how much capacity that they are really going to need.

Okay. That's helpful. And then just to switch gears a little bit on the northeast side. Any updates you can provide us on Centennial, and what your thoughts are about that, going forward?

I wish we had updates on Centennial, but right now we don't.

Okay. That's all I had. Thank you very much.

Dennis Coleman, Bank of America.

Just I guess to dig a little more into the export facility that you announced today. Obviously you didn't include any capital estimates. But I wonder if you might just talk broadly, or if there's anything you might say as to directionally what those would be. Would the ethane facility be an example or something that we could look to, to sort of estimate the number?

I doubt it.

Okay.

And really around the ethylene refrigeration and storage facility, really you're talking pretty nominal capital dollars.

Okay, okay. That's helpful. Thanks very much.

(Operator Instructions). Kristina Kazarian, Credit Suisse.

Thanks for the update on timing around Frac 9. I was just wondering if you could talk a little bit more around demand supporting, or timeframe for potential Frac 10. I know you announced 9 at the Analyst Day last year, and we got another Analyst Day upcoming. Or maybe even 11. Thoughts on that?

Well, we have it permitted. We can build it. And I think if we are successful on what we're doing on Shin Oak, I think it's a strong possibility that we would build it. I would expect that it would probably be sometime after 2019.

Great. And then a follow-on as well. Could you just talk a little bit more on the NGL opportunity, especially on the export side? I know you guys have a slide in there that -- in your deck that keeps talking about tight capacity after 2019. Would you mind just talking a bit more about that trend as well, and opportunities there?

Kristina, this is Tony. It's just a matter of supply and demand. And as we see supply grow, we've been really outspoken. And it's really not rocket science, that demand in the US really isn't going to grow a great deal. So it has to price to export. And we all model and have a pretty good idea of what the export facilities' capacity are today. And that's why we published the slide that we published that shows export capacity is going to be added. When we publish again, the gap is going to be even bigger because the NGL number will be up.

This is Brent. To echo Tony, so if you believe in the production numbers and especially if you believe in the Permian Basin, the net barrel has to go somewhere. And so probably there will be a period of time where it can be handled in storage. But at some point, the price will get to a level where that price will increase demand, and that barrel will move across the water.

So Tony, do you expect production growth to exceed export capability -- today's export capability?

The answer to that is absolutely.

Great. Thank you, guys.

I'll add one thing to that. One of the things we've had -- it's amazing how crude to gas gives people an appetite. We talk about LPG, but we are beginning to get a lot of interest in ethane exports. And that's driven primarily by that gas to crude spread or the price of naphtha in Asia or whatever.

Danilo Juvane, BMO Capital.

Amy, this is Randy. We have time for one more, so you've announced and this will be our last one.

Actually all the questions have been asked already.

Okay. Amy, would you give our listeners the playback information, please?

Certainly. Thank you for participating in today's conference call. The call will be available beginning at 2 PM Eastern today through 11:59 PM Eastern on February 7, 2018. The conference ID number for the replay is 49822183. Again, the conference number for the replay is 49822183. The number to dial in for replay is 1-800-585-8367 or 1-404-537-3406.

Thank you, Amy. And thank you all for joining us today, and have a good day. Goodbye now.

This concludes today's conference call. You may now disconnect.