Plains GP Holdings LP (PAGP) 2018 Q3 法說會逐字稿

Good day, everyone, and welcome to the PAA and PAGP Third Quarter 2018 Earnings Call. Today's call is being recorded. At this time I would like to turn the call over to Roy Lamoreaux. Please go ahead.

Thank you, Ann. Good afternoon, and welcome to Plains All American's Third Quarter 2018 Earnings Conference Call. The slide presentation for today's call can be found within the Investor Relations News & Events section of our website at plainsallamerican.com.

During our call, we'll provide forward-looking comments on PAA's outlook. Important factors that could cause actual results to differ materially are included in our latest filings with the SEC.

Today's presentation will also include references to non-GAAP financial measures such as adjusted EBITDA. A reconciliation of these non-GAAP financial measures to the most comparable GAAP financial measures can be found within the Investor Relations Financial Information section of our website.

We do not intend to cover PAGP's results separately from PAA since PAGP's results directly correspond to PAA's performance. Instead, we've included schedules in the appendix of our slide presentation that contain PAGP-specific information. Please see PAGP's quarterly and annual filings with the SEC for PAGP's consolidated results. Also included in the appendix are some additional reference materials for today's call.

Our call will be hosted by Willie Chiang, Chief Executive Officer; and Al Swanson, Executive Vice President and Chief Financial Officer. Additionally, Harry Pefanis, President and Chief Commercial Officer; Jeremy Goebel, Senior Group Vice President, Commercial; and Chris Chandler, Senior Vice President, Strategic Planning and Acquisitions, and other members of our senior management team are present and available for the Q&A portion of today's call.

With that, I will now turn the call over to Willie.

Thanks, Roy. Good afternoon to everyone, and thank you for joining our call. Let me begin by hitting the high points of the information we released today. As outlined on Slide 3, and as Al will discuss in more detail, this afternoon we reported solid third quarter results that meaningfully exceeded our expectations. Our results for the quarter reflect continued growth from our fee-based segments and over-performance in our supply and logistics segments or S&L. We anticipate both of these trends to continue through the fourth quarter and into 2019, as reflected in our updated and increased 2018 guidance. Al will provide an update to our preliminary guidance for 2019, which reflects continued momentum in S&L and remains in line with our prior expectations for fee-based growth after adjusting for our recent sale of a 30% interest in the BridgeTex Pipeline, which was executed after we provided our preliminary guidance for 2019.

We've characterized 2018 as a year of execution. So far this year we've delivered results ahead of our guidance, and we remain on track to achieve our deleveraging objectives within the first half of 2019. We're excited about what the future holds, and we believe that we're well positioned to continue to execute to the benefit of our stakeholders.

The fundamentals for our industry are constructive, global demand continues to grow and the U.S. leads the world as the largest and most visible source of growing liquid supply. In this regard and as illustrated on Slide 4, we anticipate crude oil production growth across multiple North American basins over the next several years, and our asset base and business model are positioned to benefit.

Specifically in the Permian, we continue to expect production growth to be in line with our year-end exit rate forecast of plus or minus 3.5 million barrels a day, and we expect similar annual volumetric gains in Permian production for the next several years. Additionally, we expect increased activity in other key producing regions including the Eagle Ford, Rockies, Williston and Mid-Continent,which should drive increased flows to key U.S. market centers including Cushing, Oklahoma. This is driving demand for new takeaway solutions that our existing system is well positioned to serve through a combination of capacity optimization and capital-efficient expansion opportunities.

To that end and as illustrated on Slide 5, we continue to progress options to increase capacity on our Red River and Diamond Pipeline systems. Additionally, the Capline owners are finalizing plans to purge the line and are advancing plans to reverse the pipeline. The potential expansion of our Diamond Pipeline capacity would be coupled with a project to extend the pipeline a relatively short distance to connect into Capline. These potential projects leverage existing systems to provide efficient solutions at attractive returns and would be incremental to our current guidance and capital programs.

Meanwhile, our Permian transportation assets remain the largest growth driver for our business. As shown in Slide 6, we expect our full year 2018 average Permian tariff volumes to increase more than 30% or approximately 1 million barrels a day. In total, we expect full year Permian tariff volumes of slightly less than 3.8 million barrels a day. The impacts of the partial BridgeTex sale and timing of completion activity are partially offset by the earlier in-service timing of Sunrise.

For the fourth quarter we expect a meaningful uplift in Permian tariff volumes, supported by the early placement into service of our Sunrise expansion project as well as a continuation of Permian production growth and multiple debottlenecking expansion projects.

With respect to the early commissioning of our Sunrise expansion project, I'd like to publicly acknowledge the hard work, creativity and coordination of our team in making this happen. By bringing Sunrise into service early, we were able to add much-needed capacity to the market.

We also continue to make good progress on the balance of our capital program. Construction of our Cactus II pipeline is on track, with partial in-service targeted for late third quarter 2019 and full service by April of 2020. Additionally, our multiple gathering system expansions and intrabasin debottlenecking projects are advancing on schedule along with complementary expansions of our terminaling and storage capacity footprint throughout the basin.

We also continue to make meaningful progress on the ExxonMobil JV. The project will be anchored by ExxonMobil and we continue to work with third-party shippers on additional commitments. We are also finalizing commercial agreements and working through joint venture documents.

As announced earlier, Lotus Midstream, which recently acquired the Centurion Pipeline system and additional midstream assets from Occidental Petroleum including a terminal at Midland, has signed a letter of intent to participate in the joint venture. We're pleased to have Lotus join the project and look forward to sharing additional updates on the (inaudible) project in the near future.

With that, I'll turn the call over to Al.

Thanks, Willie. As Willie mentioned, our third quarter results exceeded our expectations, primarily due to strong performance in our S&L segment. The strong S&L performance is primarily the result of favorable regional basis differentials in Canada and in the Permian as well as a one-time $20 million audit recovery related to a profit-sharing arrangement in our NGL business.

As shown on Slide 7, we reported fee-based segment adjusted EBITDA of $561 million, reflecting year-over-year growth of $16 million or 3%. Year-over-year transportation segment adjusted EBITDA growth of $25 million was driven primarily by Permian volume growth, partially offset by transportation segment asset sales and a decrease in facility segment adjusted EBITDA, which was primarily due to asset sales as well.

As shown on Slide 8, we increased 2018 adjusted EBITDA guidance by $150 million to plus or minus $2.55 billion, driven by our strong third quarter performance and our expectation for stronger than previously anticipated results in our S&L segment through the balance of the year. I will also point out that our updated 2018 guidance incorporates the impact of our sale of a 30% interest in BridgeTex Pipeline, which closed on September 30, generating net proceeds to PAA of $862 million. We reported a gain on the sale of $210 million. The sale resulted in lowering our 2018 fee-based guidance by approximately 1% or $25 million.

Our updated 2018 implied DCF guidance is approximately $1.84 billion with approximately $1.68 billion available to common unit holders, resulting in implied DCF per common unit of $2.31. This represents a $0.49-per-unit or 27% increase over 2017. Retained cash flow for 2018 is expected to be approximately $810 million.

I will also note that we increased our 2018 maintenance CapEx by $15 million or 7% to $240 million due to our ability to complete more work during the year than previously anticipated and our decision to replace instead of repair certain segments of pipeline. These projects are part of our ongoing commitment to ensure safe and reliable operations.

In addition to 2018 guidance, I will provide an update to our preliminary 2019 adjusted EBITDA guidance. On our August earnings call we discussed directional fee-based guidance for 2019 of 14% to 15% growth over 2018 guidance of $2.225 billion, which equated to approximately $2.55 billion, and we also indicated that our 2019 S&L performance would likely outperform 2018 S&L guidance, which was $175 million, the result being total adjusted EBITDA of approximately $2.7 billion.

The BridgeTex sale represented a reduction to the directional guidance previously provided. Additionally, we intend to continue to gather and incorporate data from producers regarding their 2019 CapEx plans as well as completion timing and will provide more definitive guidance for 2019 on our February call. But based on our current assessment, we are updating our preliminary fee-based guidance for the BridgeTex sale and our current S&L outlook as follows.

We expect 2019 fee-based segment adjusted EBITDA to increase plus or minus 12% year-over-year, which equates to plus or minus $2.46 billion. This is essentially unchanged from our previous 14% to 15% fee-based growth guidance as adjusted for the BridgeTex sale. We expect all of this fee-based growth to be driven by our transportation segment, and our facilities segment is expected to be flat to slightly down, as 2018 results thus far reflect a degree of outperformance relative to our initial 2018 guidance.

We also expect 2019 S&L will likely outperform our 2018 guidance of plus or minus $350 million. Directionally, that would place total adjusted EBITDA at plus or minus $2.8 billion. Although we have the potential for some upside in our S&L segment in 2019, we anticipate this segment will return to a lower level of adjusted EBITDA in 2020, as we expect both Permian and Canadian differentials to narrow as new pipeline capacity comes into service. As a reminder, to the extent we are able to generate outsized S&L earnings, we intend to use such proceeds to either reduce debt or fund capital.

Before handing the call back over to Willie, let me provide a brief update on our deleveraging plan. As illustrated on Slide 9, at September 30 PAA had a long-term debt to adjusted EBITDA ratio of 3.9x and a total debt to adjusted EBITDA ratio of 4.0x. These metrics are closer to our targets, and with the total debt to adjusted EBITDA ratio being down 1.5 turns from a year ago, as Willie mentioned, we expect to complete our deleveraging plan in the first half of 2019.

I will also note that our combined 2018/2019 capital program remains unchanged at $2.6 billion. However, we expect the 2019 capital program of $650 million to increase closer to the $1 billion level, primarily driven by expected progression of the ExxonMobil JV project in addition to sanctioning other new projects. We plan to provide an update on our capital plans in conjunction with updating our full year 2019 guidance on our February call.

As we come closer to completing our deleveraging plan, we wanted to share some thoughts on how we plan to manage our distribution going forward. Multiple factors the Board and management will consider are summarized on Slide 10 and center on our commitment to maintain a significant level of financial and operational flexibility, support metrics that are consistent with mid-BBB credit ratings over time and retain a level of cash flow that limits, if not eliminates, the need to issue common equity to fund routine growth capital programs.

With these factors in mind, upon completing the deleveraging plan, we expect to be in a position to increase the distribution, potentially as soon as the first quarter of 2019 distribution, payable in May.

With that, I will turn the call back over to Willie.

Thanks, Al. As you can see, it continues to be a productive time for our organization. And as summarized on Slide 11, we're real pleased to be making meaningful progress towards each of these 2018 goals.

Before opening the call for questions, I wanted to acknowledge and thank Greg Armstrong, co-founder and 26-year CEO of Plains, who retired as CEO effective October 1. Greg, Harry and the entire team have built an incredible business over the years, and I want to thank them for the trust that they have placed in me and the efforts to make sure we had a smooth transition.

As we look forward, we acknowledge the recent industry cycle and the steps we've taken to position the company for the future. We continue to invest in our business through the cycle while sharpening our focus on operations excellence, portfolio optimization and continue to advance multiple initiatives to further improve our organization for the future. As a result, we believe that Plains is emerging as a stronger entity with an exceptional asset footprint in key North American growth areas.

We expect our deleveraging plan to be complete in the first half of 2019. This should provide us significant financial flexibility, enabling us to self-fund the equity portion of our routine growth capital programs while delivering attractive DCF and unit growth over time. All that said, we remain intensely focused on the safe, reliable and responsible execution of our business plan, which we expect to drive strong results in 2019 and will continue to position the partnership well for 2020 and beyond.

I'll turn the call over to Roy.

Thanks, Willie. Now as we enter the Q&A session, please limit yourself to 1 question and 1 follow-up question and then return to the queue if you have additional follow-ups. This will allow us to address the top questions from as many participants as practical in our available time this afternoon. Additionally, Brett Magill and I plan to be available this evening and tomorrow to address additional questions. And we're now ready to open the call for questions.

[Operator Instructions.] We'll take our first question from Jeremy Tonet with JPMorgan.

I just wanted to start off with Sunrise here and see -- it seems like you've got 350,000 barrels a day capacity online in the quarter, and was just wondering if you could provide a bit more detail, I guess, on how that's flowing. And you said, I think, there was 220,000 of takeaway from there, 120,000 into Cushing and 100,000 to other Valero refineries. Is that what you're seeing moving now, or is there a higher level? Anything you can expand upon this and how much of the EBITDA ramp you'll still see in the fourth quarter versus the third quarter here.

Harry, do you want to cover that?

Sure. So part of commissioning Sunrise in October, full operations with the generators in November, initially we thought sort of takeaway capacity would be in around 200,000 or 250,000 barrels a day. It's probably around 300,000 to 350,000 barrels a day. We've developed a few more markets out of the Wichita Falls area. So the pipeline can move about 500,000 barrels a day, but that's sort of the takeaway capacity that we see today. Of course, our goal is to try and maximize throughput and try and find additional takeaway options.

So Jeremy, an obvious initiative for us is to continue to find those additional markets downstream of Wichita Falls. So using the map between 500,000 of capacity to where we are today is the opportunity set going forward.

That's very helpful. And I want to just touch on S&L here real quick. And I know it's a smaller part of the business, but the number's stepped up a bit there. And just trying to get some -- our hands around what this looks like. And just wondering, is this kind of more front half of the year weighted as far as what you see for S&L, and you kind of lift the guide as you see the prompt couple of quarters higher? Is this more crude or Canadian NGL? There's some wide dips up there. What can you sketch as far as the composition? And when you get these super-sized earnings, you talked about reducing debt or funding capital or increasing the dividend. Any thoughts to maybe putting it back into buybacks when it's kind of onetime in nature?

About 4 questions there.

Were you talking about 2019, Jeremy, on your particular -- Jeremy, maybe I'll -- go ahead, I'm sorry.

Yes, for 2019 in particular, just trying to get a feel for the guide if it's front half weighted. But also just philosophically on S&L, could buybacks come into the picture there or anything else you can share on those thoughts?

So let me start off with the S&L numbers, and then Harry and Al can jump in here as they see fit. When we started the year, I think we all shared that we did not expect the margins to get, or the differentials to really widen until the back half of the year. So we kind of went into the year with that thought, that fourth quarter primarily, we may be able to capture some. And I think what's actually come to fruition is, obviously, the differentials widened out for most of the year and we were able to catch additional crude differentials, primarily around the Permian fourth quarter. There's also some Canadian crude differentials that we've been able to capture. And if you think about the differentials in S&L, that happens when there are constraints in pipelines. So our view of 2019 is there's a limited amount of capacity that -- takeaway capacity that comes online, really, until our Cactus Pipeline starts up late third quarter. So there are opportunities there to be able capture some arbitrage in the S&L segment, but once 2020 hits and there's a lot of pipelines, as Al pointed out during his prepared remarks, we don't expect, certainly, the crude differentials in the Permian to persist after that. So this is really an opportunistic period of time that allows us to capture some of that value. On the flexibility of the buybacks, I don't want to get into commitments on what we're going to do. But I think the message you should take from this is by having this financial flexibility, it gives us a number of different options to be able to bolster the company for the future.

Great. And just to clarify the one point on S&L for 2019, it sounds like it's normal ratability across the year with seasonality as we've seen in the past. It's not weighted towards the first half versus the second half?

Well, no, not necessarily. If you just looked at the curve on the Permian, it's second quarter is probably the weakest quarter of the year. Fourth quarter, the market's sort of pricing in and some of the pipes aren't going to be in service and it's compressed. So there's definitely going to be a curve to the Permian differentials. If you look in Canada, the differentials are wider in the first few months of the year than they are for the balance of the year, so there's obviously some contemplation that some of the turnarounds or other impacts to the market might not weigh in the market as much they do next year, so it's a mixed bag. But it's probably more heavily weighted to the first half of the year than the second half of the year.

And Jeremy, don't forget we still do have a seasonality to the NGL portion of our business. But as Harry said, you've got that crude differential overlay on that. You'll still see some seasonality between first and fourth quarter based on the NGLs.

And Jeremy, I'd just add one follow-up on the point Willie answered on using S&L to buy back. Clearly, maybe at some point in the future, but our first focus is balance sheet. I did mention that we expect our '19 capital program to increase. And clearly, those will be the first priorities with any excess S&L profits.

We'll go next to Tom Abrams with Morgan Stanley.

I was looking at your Page 5 graph of all the -- map of all the pipes. And just wondering if your comments on Permian to Houston line, looking for additional partners, if that implied that maybe some of the other projects out there that are also looking for additional partners may end up combining with your joint venture?

Jeremy, why don't you take that?

Yes, I would say our first and foremost, we're looking at we have an attractive project with Exxon Supply, Exxon in Demand. We have liquidity from Plains and Lotus. We have enough to make the project go on our own. We're looking for third-party shippers. We really can't comment on speculative concepts about merging projects. But honestly, as you've seen with Plains historically, we'll always look at opportunities. But first and foremost, we're advancing the project as we've said on the call, and we're looking for third-party shippers at this time.

And then I don't know if I get a follow-up or not, but I wanted to ask about there's a lot of crude coming into the kind of Corpus -- I'm sorry, the Houston area, your friends at Magellan talking about a connection to Corpus. Is there a need to get more crude from Houston over towards St. James?

Wait, those are 2 different questions.

The differentials would tell you, yes.

I'm trying to think of your -- the additional projects that are in your likely future.

Yes, so the differentials, LOS is about $8.00 and change over WTI, and East Houston's $6.00, so it's a $2.00 to $2.50 differential, so there's clearly demand in St. James.

And some of that's grade-dependent as well. The Canadian barrels are looking for a home to get run in St. James, and for those, it would be the most efficient way to get there. So I think there's 2 components to the projects, and we're excited about both of them.

We'll go next to Shneur Gershuni with UBS.

Just a couple of questions here. I'll try not to keep it to 11 parts. But in terms of the capital being invested for future growth, how much capital is being placed into service into 2019 that will only partially benefit '19 and roll into 2020? And how much of your current CapEx impacts only 2020? Said differently, can we see a material increase in 2020 fee-based EBITDA as well, given the suite of projects that you've FID-ed and are working on?

Shneur, this is Willie. I don't want to get into talking about 2020, because there's a lot of road between now and then. I think what -- the message you can take is we've teed up a number of projects here that aren't currently sanctioned, particularly around the Diamond and the Capline reversal. I think the takeaway should be we've got a number of projects that we've got in the queue to drive growth going forward in 2020-plus, and we do have a number of projects that are kicking in for 2019, with the Cactus II project starting up late Q3, which we should get a full bop into 2020. So there's no shortage of projects or growth that we have.

Okay, fair enough. And as kind of a follow-up there in sort of the other projects that you were considering, I believe at your Analyst Day, you talked about a Wichita Falls extension that could sort of take you all the way to St. James as well as a bullet pipe on potentially, I guess, theoretically a Cactus III. Have those ideas, are they still in the hopper or are they developing? I was just wondering if you can give us some color around that.

Harry?

Wichita Falls extension, we actually laid out 2 alternatives, one to extend it to Cushing; alternatively, to extend it east and connect into the Red River system, which could then tie into Longview and Energy Transfer's got a pipeline system from Longview into Baton Rouge. So those projects are still actively being advanced. Cactus III is -- I would probably say back-burnered, given the fact that we're allocating our resources to the Exxon project.

Yes, Shneur, just another -- this is Willie -- just one more thing to add. There's a lot of talk of new lines going from A to B. One of the things, our strategies, is how do we take our existing system and come up with a, hopefully, a shorter-term solution and certainly a more cost-effective solution? So for us, there may be more connecting the dots between existing pieces of our system to accomplish the same versus some of the other pipes that are just complete announcements of new projects, if that makes sense.

We'll go next to Christine Cho with Barclays.

For the Capline reversal, is this going to be from Patoka down or just from that extension in Memphis? And how much time would you need to reverse it and do your connection? Like if you were to do an agreement tomorrow with all the parties, how much time do you need to reverse and commercialize? Are we talking months or years?

Harry?

No, it's an 18- to 24-month process. If we started today, probably closer to 24 months. We have to purge the line, we need some equipment, we need a little bit of extension of the pipeline from Memphis to Collierville. So maybe the south end of the system could be reversed in an 18-month time frame. The north end would be a little bit longer. So it's not something that could be accomplished in months. It will probably be in phases, where the south end of the system is placed in service on a faster time line.

And when you say south, are you talking from Memphis down, or like what's south?

Yes.

Okay.

Yes, Memphis south.

Okay. And then when you say, and then the north part is from Patoka all the way down?

Correct. And the connecting carriers need some work, too, at Patoka, so it's not all in our control.

Okay. And then with your -- the Permian, like long-haul types that you guys have -- how should, with them running full, how should we think about the risk to volumes in excess of the MBCs moving over to some of the NGL to crude pipeline conversions that have been announced for next year? Are there any protections or mechanisms in place to keep the volumes on your system, in your view? And then to the extent that that happens, how should we think about the impact on transportation and S&L? Like how does that skew?

I think the best way to think about it is our guidance reflects our view on how volumes move, given all the relative projects that are forecasted to come in service next year.

And Christine, don't forget there's different kinds of commitments, right? So you've got minimum volume commitments, which you addressed. There's also acreage dedication, which would be dedicated to our system. And a lot of the contracts we've got, as we've chatted before, are longer-tenured, have longer tenures to them. So there's nothing that falls off a cliff in the next number of years.

And our legacy -- we have some legacy systems that are just common carrier pipes. You can walk up and ship today or not ship today. So our guidance reflects our view on what happens to those volumes.

We'll go next to Michael Blum with Wells Fargo.

Just one quick one on Capline reversal. From Patoka, would you be sourcing heavy barrels from Canada, so that part would sort of have to sync up with Line 3, or could you also source barrels, I don't know, theoretically, from the Bakken so those could be light sweet barrels and come sooner?

Well, it will be driven by a Canadian -- by access to Canadian barrels. That's why I had mentioned earlier that it is dependent on connecting carriers, and the timeframe will probably be longer than a reversal of the Memphis portion south. But it could conceivably receive volume from Bakken sources as well.

Okay, that's helpful, thank you. And then a second question on S&L. Basically I'm just wanting to know, is there any change in your hedge position, either for Q4 '18 or for 2019? In other words, what I'm trying to get at is what gives you the confidence to put out the guidance you had for both years? Should we assume that that's effectively locked in?

I would say that our guidance reflects our hedge position and our view of the market for the unhedged portion. And we, obviously, are always active in the market, so it's not the same position that it was last call.

We'll go next to Jean Ann Salisbury with Bernstein.

Just a couple of quick ones for me. I think you said that $25 million came out of guidance for 2018 from BridgeTex, which I guess would just be for the fourth quarter. It seems a little bit high. Can you just kind of spell out, I guess, what the estimate that you had coming out of 2019 guidance from it was?

If you just walk through the math, principally, the $25 million was BridgeTex. The pipe is obviously close to full with the logistical constraints. If you take the $2.55 billion to the $2.46 billion, that's principally BridgeTex coming out, the vast majority of it. So you had the numbers, right?

Okay, a little higher than I thought. Thank you. And then it seems like once the pipelines to the Gulf are on from the Permian, that will be a bit more of a draw for Permian barrels than Cushing will be, which I think has a pretty long-term differential expectation in the forward curve. Can you kind of give us an estimate for how much of the flow on basin actually, like, doesn't go all the way to Cushing to get Cushing pricing and maybe won't be at risk once there is a more direct path to the Gulf?

Jean Ann, this is Willie. That's a really tough question to answer because as barrels go down, it depends on what happens to Cushing and what the arbitrage is. Unless Harry has a better answer, I think it's really hard. There are definitely barrels at risk, but it's hard to put a number on it.

There are barrels at risk, but there's a certain pull from the Mid-Continent for Permian Basin volume. If you just went back historically, there have been times when the Permian has been, Midland has been a significant premium to Cushing, and volumes still move. So it's hard to pinpoint exactly, but there's definitely refiners in the Mid-Continent that rely on Permian Basin crude.

And we also have contracts for that movement, and we hedge some of that movement for ourselves as well.

Correct.

We'll go next to Colton Bean with Tudor, Pickering, Holt & Co.

So with the Canadian volumes looking like they ticked up there quarter-over-quarter, is some portion of that tied to S&L barrels moving on Milk River and Aurora? Going to capture that light spread, or just any clarity there?

The Canadian volumes are mainly tied to production in Canada. So it's not S&L-driven volume that impacts our Canadian.

Got it. And then just can you give us an update on your thoughts around a potential extension of Saddlehorn to capture PRV growth? And I guess pending Prop 112, does that impact the thought process around that extension?

We already have a pipeline that can source volumes out of the Powder River into Saddlehorn.

Got it. And if the proposition were to go ahead, is there anything you would need to do to increase the capacity to maybe repurpose Saddlehorn to be primarily a Powder River pipeline?

Saddlehorn has committed shippers, so it couldn't totally be a Powder River pipeline. But there are -- we do have the capability of expanding volume -- expanding capacity into Saddlehorn, and there are some enhancements that could be accomplished at Saddlehorn as well. So we think we're in a pretty good position to capture some of the potential volume increases in the Powder River. Jeremy, do you have anything else you want to add to that?

No, I think we have multiple options. So today barrels move from that area through Saddlehorn on a spot basis. But longer term, there's a possibility to expand with the existing footprint with pumps. And then if there's more demand, you could loop segments of the line to create additional capacity. So I think depending on market demand, and we're watching capital budgets just as you are, and our customers' demand on the system, we'll optimize our capital spend relative to demand from the Powder River. But we're actively watching it, and we're honestly contracting some of the capacity in our pipelines in that area to enhance liquidity in our Guernsey terminal to make sure we have as many shots as possible to get those barrels.

We'll go next to Spiro Dounis with Credit Suisse.

I just want to start off with a potential distribution increase. Don't want to get too out of us here, but with the increase coming, and I realize you can't say much on specifics, but can you provide any sort of blueprint on how you decide what that first increase looks like and what the mechanism looks like going forward, just whether or not you increase it quarterly or annually from there?

Al, why don't you take that?

Yes, and clearly, we can't provide specific numbers. The thoughts were all denoted on that slide. If you recall back August in '17 when we made the reduction, we did make a comment that we would consider either starting with small -- just normal kind of increases or a step change or a combination of both. We haven't made any decisions, clearly. As we get closer to that period of time, we'll look at the approach. We are leaning towards going to a more annual basis versus a quarterly basis, which was denoted on the slide as well. But as far as specific numbers, no. Clearly, we want to focus on maintaining liquidity and commercial flexibility, operational flexibility, credit metrics supporting mid-BBB and to make sure we minimize the need for equity capital markets. And so those will all be tenets that we kind of dial through our thought process, assuming it is for the first quarter, payable in May. But that's really all we could share.

Okay, no, that's fair. And we've heard a lot this quarter from your peers just around major crude export expansion projects really tailored to VLCCs. Curious where you guys are on that. It seems like a natural extension to a lot of your pipelines. But just curious if you think there's maybe already a risk of overbuild here on the export side.

I'll make a comment, and then Chris Chandler, I'd like to -- maybe you can follow up. Clearly, there are a lot of deepwater VLCC projects announced. These are all big, big projects, significant expense. When we looked at our Cactus Pipeline, we had been trying to look at not only the pipeline takeaway, but combining that with a dock. And what we found is that different shippers are interested in different docks. So our view is that we can get the pipe, we can get the barrels to the coast, and there is a number of different -- there's plenty of docks that are being built, and we should have flexibility to get access to all those. And if it's a strong return and it's beneficial for us, we may participate. Otherwise, we're going to kind of watch and see what happens.

Yes, the only thing I'd add is that we do believe that one or more single-point mooring projects do make sense going forward as crude oil exports continue to grow. It's, of course, the most efficient way to load a large volume of crude oil for export. And it's an area, like Willie said, that we're closely monitoring.

Hey, before we go on to the next call, I want to circle back just to clarify. We are seeing a little more volume come across the border through our cross-border pipelines like Milk River. It's not a huge volume, but there is some more volume that comes down in through Milk River into our Western Corridor system. Next question?

We'll go next to Dennis Coleman with Bank of America.

I guess if I can just start with S&L and push a little bit more. Al, you talked about sort of normalizing that volume, I guess, for lack of a better description, into 2020. Anything you can say in terms of how we should size that? Obviously, there are some impacts that you talked about in terms of the debottlenecking projects, and I guess Canada plays a big role there as well. What have you assumed in terms of projects coming on there from competitors that you've talked about?

Yes, we wouldn't try to put a specific number for 2020 S&L out yet. What we're trying to do is just make sure -- obviously, we started this year at $100 million for S&L, slowly took it up to $175 million, now $350 million. We think the $350 million is going to be there and likely exceeded in '19. We're just trying to make sure that anybody that's modeling that segment recognizes that as all these Permian pipes get built, it gets sized down. There may be some of the Canadian opportunities go a little longer, but they're probably a little less material for us. So we would think you'd want to make sure you model that meaningful reduction from the $350 million when you're looking at 2020. That's how we're going to run the company as far as how we're thinking of leveraged distribution coverages. We're going to assume we've got a nice opportunity to capture it. It's helping us fund projects, reduce debt. But we're going to run the company in mind with a fairly modest amount of S&L contribution for 2020 in how we're thinking about things.

Great, that's very helpful. Maybe just switching, there was a comment that St. James volumes were up in the quarter, and it seemed perhaps that it was -- that's more crude by rail. But any expectation that that would continue to ramp up, and any comment you can give there?

We think we'll continue to see strong rail demand in 2019 at St. James. It's largely driven by the pipeline constraint. And as pipeline constraints ease, rail lines will likely subside some. But we've had steady business for a long time at St. James. It's just been accelerated due to the pipeline constraints.

So do you have excess capacity there? Is it something that could continue to ramp?

Oh, yes. We have additional capacity.

The limit has been railcar, access to rails. That's been what's been the limiting point through 2018. And, of course, prices -- fixed prices -- and additional railcars have been directed to the markets that need it.

We'll go next to Jerren Holder with Goldman Sachs.

What is the latest on your potential to increase takeaway capacity out of the Bakken and Canada?

Out of the Canadian Bakken or out of the Bakken and Canada?

Bakken and western Canada.

So our footprint is not significant in the Bakken. It mainly consists of some smaller pipes and rail takeaway. So obviously, we try and take advantage of the limited infrastructure we have, but we're not going to be one of the parties that develops a significant takeaway project out of the Bakken. We do have 2 cross-border connections, Rangeland and Wascana, that we are working, how do we get more capacity on those 2 systems, but the volumes are fairly limited.

And ideally, that would be a pipeline system that would be bidirectional, where you could move volumes into the Canadian infrastructure if you had higher demand there, or to the Bakken infrastructure if there was higher demand in the Bakken.

And that's on the Wascana piece, not on the Rangeland piece, being bidirectional.

Yes. And then follow-up on the asset sales. Where are you following BridgeTex? Are you guys looking to do more? Are there any outstanding that are just waiting to close at this point?

Chris Chandler, why don't you take that one?

Sure, Jerren. This is Chris. Our goal for 2018 was to achieve $700 million in asset sales, and we have exceeded that goal. We will continue to evaluate our portfolio going forward, based on valuation and strategic fit, but we don't feel any pressure to sell additional assets. If something changes there, we'll provide updates as warranted.

And no pending deals that haven't closed yet or anything like that?

That's correct.

We'll go next to Tristan Richardson with SunTrust.

Just on the intrabasin side and debottlenecking, can you give an update on your Wink-to-McCamey project as you sort of set the table for Cactus II?

Yes, that's one of multiple projects. We have capacity into Wink and then out of Wink. That will be one sometime within the last month of this year or first month of next year. But more importantly, we need to pass the end of Wink as well because there's a lot of production that's coming online in the Western Delaware Basin. And what that does is it frees up capacity in the Midland on our historical basin system. So it will give us a lot of capacity, just having the first leg on, that helped keep that part of the basin debottlenecked. So it creates additional tariff barrels from us, even if we don't have the rest of Cactus on at that time -- Cactus II.

Tristan, this is Willie. You should think of the Wink-to-McCamey piece -- never mind. I was thinking of something else. Jeremy had it on. Go ahead.

Currently, Jeremy, go from Wink over to Midland and then down to McCamey, and so by basically taking the hypotenuse of the triangle, it makes it easier from a flow perspective.

That's helpful. Thank you. And then just quickly with respect to the preliminary 2019 guide on the fee-based side and the visibility you have on tariff volumes as some of these long hauls come online, could you talk about, generally, where do you see tariff volumes in '19 as it's presumed in your preliminary guide?

We don't intend to provide a volume to go with the EBITDA until February. So look forward -- we'll provide that detail then.

We'll go next to Keith Stanley with Wolfe Research.

I just wanted to clarify on the transportation segment guidance. It implies a pretty strong acceleration in Q4, quite a bit more than what you've seen in the past few quarters, so it's up $40 million. And then you're losing BridgeTex, so it looks like it's up really more like $65 million versus the third quarter. Is that just Sunrise causing a big debottlenecking of the system, or any other color or drivers to think about for Q4 and the nice uptick there in transportation?

Yes, this is Willie. Clearly, Sunrise is a piece of it. But as we stated in the prepared comments, there clearly is an expectation for volumes, production volumes to increase. We saw a slight lull in completions in pushing barrels back. We expect a lot of that to come in the fourth quarter, so that's definitely a component of the growth piece.

Okay, and then it looks like about a $500 million reduction in short-term debt. I'm assuming that's just hedge collateral coming back to you. And is that a sustainable level to model going forward?

What I would say is a little bit of the flips between long-term and short-term had to do with the BridgeTex cash closing at the end of the quarter. So short-term was understated relative to probably what we could have borrowed under the same metric, i.e., hedged inventory and margin. But we have seen our margin numbers come back to what I would say is a pretty normal level, which is what we expected. Clearly, we had done a lot more hedging for the first 8 to 9 months of the year versus the fourth quarter, as we had mentioned. So what I would tell you is that's probably below what you would expect if you look out 6 months or 9 months from now due to the BridgeTex timing and the cash that came in from that.

That cash was received in early October, though, right? Or was it in Q3.

I don't remember. No, it was in Q3, yes.

We'll go next to Patrick Wang with Baird.

As you look toward resuming distribution growth in 219, how does or doesn't preferred equity fit into the picture as a source of funding?

Well, today clearly our view is that we're, when you look at next year, the equity portion of what our CapEx requirements will be would be funded principally with retained cash flow. We have room left on the, quote, basket as far as the rating agencies for hybrid or preferred type of securities, but our thoughts in 2019 would be that we would not raise any preferred to fund that capital program. Clearly, if our capital program grows or we see acquisitions in today's valuation for our common units, we would look to use preferreds.

Got it. That's helpful. And then bigger picture, in the Permian, it looks like crude takeaway really comes before new gas takeaway, so that when you think about flaring levels between now and 2020, how do you think about the risk of a gas-induced activity constraint on the oil side?

This is Jeremy. That is a risk. There's also fractionation risk on the NGL side. We feel like gas is probably a little bit ahead of fractionation risk, but we're monitoring all of the above. I think our view, and I think as Harry pointed out, volumes is predicated on a presumption that producers are not going to -- they're going to continue to run rigs at a much faster rate than completions until they see a line of sight to debottlenecking of infrastructure. So we feel that a ramp towards the second half of next year in completions, as there's a line of sight into oil, gas and NGL takeaway. But there's interim solutions just like there are with oil with some of the others, flaring being one. There's other ways to move NGLs, so we're paying attention to all of them. But I think our guidance reflects our view of the completion cadence we see for next year.

We'll go next to Sunil Sibal with Seaport Global Securities.

I just wanted to go back to the credit metrics that you laid out on Slide 14. So when I look at the target numbers on the extreme right, the leverage metrics that you lay out there, that's consistent with the BBB rating that you're looking for, or mid-BBB rating that you're looking for from rating agencies, correct?

You mean our targets? Yes, they are. But rating agencies have adjusted kind of how they look at things over the recent past. But our intent is to, over time, make sure we get our leverage and our performance to where we will be mid-BBB again. But it won't be instantaneous, we view. But they are consistent. But clearly, the bar has changed over the last few years.

And then within that EBITDA calculation, how do you kind of think about S&L contribution? Is that pretty much netted out, or is it like a minimal level kind of number?

In how we think of leverage metrics?

Yes.

Yes, no, we'll include S&L in the metrics, because clearly, some of the debt that is in the numerator side of the calculation is there to generate S&L profitability. So you really can't eliminate the EBITDA without taking the debt out. That wouldn't make any sense. But the reality of it is, is that, and part of what the comment with trying to advise and look, we recognize S&L's going to drop in 2020, so we can't sit and assume that -- we've got to dial that in to how we're thinking of our leverage, that it's going to revert back to a more normal or lower level. And so we're not going to exclude it, but we're going to have our eyes open and headlights on with regard to the fact it's going to decrease in 2020. I hope that makes sense.

Yes, it does. Thanks for that. And then one -- and a follow-up from a previous question. When we think about close to your 4 million barrels of (inaudible) volumes in Permian, and then you look at your MVCs over the next, say, 2 to 3 years, could you give the sense of a cascading or impact of these MVCs rolling off over the next 2 to 4 years in Permian?

Yes, no, clearly a substantial amount of our long haul is supported by MVCs. Clearly, on the gathering side, you've got more acreage dedications, probably, supporting that. We do not have any material roll-offs on large contracts on our MVC over the next few years. I think -- yes.

We'll go next to Ross Payne with Wells Fargo. Mr. Payne, we're unable to hear you. You might try checking your mute button or picking up your handset. Getting no response, we'll move on to the next caller. We'll go next to Elvira Scotto with RBC Capital Markets.

A couple of quick clarification questions from me on the Exxon JV project. So I just wanted to clarify, are you looking for additional third-party shippers or additional JV partners? And what would Plains' ownership interest ultimately be?

We haven't disclosed the ownership, but ultimately -- and you can imagine that upstream companies and downstream companies, both shippers on pipelines, all, in often cases, whichever pipelines they commit to, take equity. So in many cases, it's both. So we're really looking for long-term partners in the project, and we're judicious in who we talk to and want it to be a long-term partner that preserves quality, has a good balance sheet. And so we're actually talking to parties, that short list of parties that we think would make sense. But candidly, they'll be shippers and equity owners in many cases.

Elvira, this is Willie. You should consider -- you should think about our position as meaningfully less than 50%. We've made that comment before.

Great, thanks. And then just a bigger-picture question around Cushing. Can you maybe provide a little more color on your view on Cushing and its relevance longer term, especially in the context of pipelines moving more Permian crude to the Gulf Coast and Canadian barrels potentially bypassing Cushing, especially with the Capline reversal?

We move over 2 million barrels a day that moves through Cushing. I don't see that materially changing. When you look at it, even if you have fewer Permian volumes coming, you're going to have more local production in the Mid-Continent and you're going to have more of the Rockies production coming into Cushing. So Cushing's going to continue to be a very viable hub. And when you look at what could potentially move down the Capline system through a connection, it's pretty small in relation to total Canadian production. Much more of that production's going to move through Cushing than down a reverse Capline system. Does that answer your question?

Hey, inasmuch as we're at the top of the hour, I think we're going to -- Ann, we're going to go ahead and cut off questions at this point. Those of you that are remaining in the queue, Brett and I can circle back with you individually and address those questions. But thank you, everybody, for your time today, and we appreciate you being on the call.

This does conclude today's conference. We thank you for your participation. You may now disconnect.