Good day, ladies and gentlemen, and welcome to today’s PAA and PAGP Fourth Quarter and Full Year 2018 Earnings Call. I’d like to remind everyone that this conference is being recorded. And at this time, I’d like to turn the floor over to Roy Lamoreaux. Please go ahead.

Thank you, Greg. Good afternoon, and welcome to Plains All American's fourth quarter and full year 2018 earnings conference call. The slide presentation for today's call can be found within the Investor Relations News and Events section of our website at plainsallamerican.com. Slide 2 contains important disclosures regarding forward-looking statements and non-GAAP financial measures. The appendix includes condensed consolidating balance sheet information for PAGP. Today's 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; and 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 available for the Q&A portion of today's call. With that, I'll turn the call over to Willie.

Thanks, Roy. Good afternoon, everyone. Thank you for joining us today. We're pleased to have delivered solid performance in 2018, and we are well-positioned as we enter 2019. We characterized 2018 as the year of execution, focused on several key initiatives, including our deleveraging plan, our Permian-focused capital program, multiple commercial and operational initiatives, and driving improvement in our safety and environmental programs. I'm pleased to report we've executed across each of these initiatives, and as reflected on slide 3, we delivered solid results against our goals for the year. We've provided a summary of our key highlights on slide 4. With respect to the 2018 financial results, this afternoon, we reported fourth quarter and full year results that exceeded our guidance. Full year adjusted EBITDA totaled approximately $2.68 billion, which was approximately $130 million above our November guidance and $380 million more than our beginning of the year expectations. These results were underpinned by our fee-based business, which grew by approximately 10% year-over-year and was generally in line to slightly above the expectations. Our over-performance was primarily related to our margin-based S&L segment, reflecting proactive coordination among our operations, engineering, and commercial groups to accelerate certain pipeline projects and achieve higher utilization rates on key Permian long-haul capacities. These efforts across the U.S. and Canada, combined with record levels of throughput on certain of our assets, enabled us to participate in capturing regional location differentials, particularly in the second half of the year. In addition to delivering solid operating and financial performance, we also made meaningful progress in delivering on our deleveraging efforts throughout the year. In regards to 2019, we have provided our 2019 adjusted EBITDA guidance of plus or minus $2.75 billion, calibrating for a lower crude oil price environment and the expected impact on producers as…

Thanks, Willie. During my portion of the call, I'll share a brief recap of our fourth quarter and full year results and provide an update on our 2019 guidance, growth capital program and current financial positioning. Our fourth quarter results exceeded expectations as we reported adjusted EBITDA for the quarter of $949 million, which equates to a year-over-year increase of more than 50%. This was driven by strong performance in our S&L segment, resulting from strong execution across the organization to capitalize on favorable regional crude oil basis differentials in Canada and the Permian Basin. As shown on slide 7, on a sequential basis, 4Q 2018 fee-based adjusted EBITDA grew by 8% versus 3Q or 13% when adjusting for the impact of our sale of a 30% interest in the BridgeTex Pipeline. As shown on slide 8, on a full year basis, our fee-based results slightly exceeded our beginning of the year guidance, and our S&L segment materially outperformed. Full year 2018 adjusted EBITDA of $2.68 billion, and DCF per common unit of $2.46 exceeded our beginning of the year guidance by 17% and 21%, respectively. Additionally, diluted adjusted net income per common unit of $1.88 for 2018 represents a year-over-year increase of $0.78 per unit or 71%. As Willie noted, we've provided our 2019 guidance. Our full year adjusted EBITDA guidance is plus or minus $2.75 billion, which is 2% lower for our fee-based segments versus our November 2018 preliminary estimates. This includes our current view on a number of factors, including the impact on production volumes of a meaningful crude oil price decrease that began in late 2018. Our 2019 guidance includes plus or minus $350 million of adjusted EBITDA for our S&L segment. We currently expect the S&L contribution in 2020 will be materially lower than 2019.…

Thanks, Al. 2018 marked a strong year of execution for the partnership. I want to publicly acknowledge and thank our PAA team for their hard work and dedication in delivering these results. Looking forward, we expect 2019 to be a very active year as we execute on our plan and position PAA for 2020 and beyond. So I set forth our goals for 2019 and look forward to providing updates on our performance versus these goals as we progress throughout the year. With that, I'll turn the call back over to you, Roy.

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

[Operator Instructions] And first from UBS, you'll hear from Shneur Gershuni.

Good afternoon guys. Maybe to start off, I wanted to chat about the Exxon JV that was FID, I was wondering if you can give us some color with respect to what percentage Plains will own of the project when it's done? And then, are there any operational leverage benefits that Plains will receive mostly to itself from a gathering perspective? Or is it really just a benefit of the pipeline itself?

Hi, Shneur. Thanks for the question. As we said, we're going to be a 20% owner of the joint venture currently. This is Willie. So I think that answers your first question. And maybe I'll just step back, and as we think about how benefits Plains and ExxonMobil, we've a preeminent position with a lot of flexibility in the basin with the capability to aggregate a lot of volumes in the Permian. And so when you think about matching the strategic needs of an ExxonMobil with their production capabilities and trajectory in the Permian tied to their downstream capabilities on the Gulf coast, it really is quite a natural fit. So as we think about what this brings to us, not only does it bring the capacity on the line, but it's further integrated into our system through many different contexts, and of course the other piece of this is building a strong relation with ExxonMobil as we do other things. Jeremy, did you have anything that you wanted to add?

Willie, I guess, the number one thing though is aligning with our customers to downstream market as the markets move to the Gulf Coast for export and expansion of demand just as they've announced recently, that align for our customers being natural [indiscernible] for Plains All American barrels as well as our guys that shift to third party on our system.

Great. And just one follow-up. With respect to Capline, I recognize it's an open season and so forth. I think you'd mentioned in your prepared remarks with respect to Capline as well as the other project -- the Red River project that it would have attractive returns. How should we be thinking about it with respect to your historical views on returns? I mean, is it kind of like a brownfield type of return and kind of a four [ph] multiple type of thing on EBITDA? Or should we be thinking lower or higher around with respect to those types of returns?

This is Willie, again. I'm going to ask Harry to comment on this. But clearly, having an existing footprint and pipe in the ground gives us a significant advantage of getting the project done as well as a cost-efficient way of capital efficiency. And so when we think about what returns those might bring, I think you can expect them to be significantly higher than what our normal threshold is. I don't want to get into what exact numbers are, because I think it's a little early and we need to let the open season take its course. Harry?

Yes. I mean, I think Willie hit most of the points. I mean, it's really going to be tied to the open season results. And if the open season doesn't generate enough returns to generate the type – enough interest to generate types of returns we're forecasting, we wouldn’t spend the capital.

Great. Fair enough, Thank you very much, guys. I'll jump back in the queue.

Moving on, we have Jeremy Tonet with JPMorgan.

Hi. Good afternoon. Someone in the marketplace had thought that this pipe, Wink to Webster, could be combined with another kind of computing pipe out there. I was wondering if you might be able to talk about the decision tree and what brought you to going with the project alone? It seems like there could be benefits as far as operating leverage that it brings to your system and kind of other synergies that would be uniquely beneficial to you. At the same time, there could be concerns that there's too many pipes coming out of basin could adversely impact other things in your system. I was wondering, if you could kind of walk through some of the gives and takes there?

Jeremy, this is Willie again. As we've articulated before, this has been a great project for us. We’ve remain very excited about it. We were pleased to have enough to sanction the project and move forward. That being said, we're always looking at not only additional shippers on the line, but talking to others on how we might be able to improve the returns for not only us and others. So while open to all that, we're still progressing forward, and what we really wanted to do is to get to the point where we could order pipe and get the process going. So what that says is, we certainly haven't eliminated an opportunity to make the project stronger and conversations continue, but at the base core of it, we've got pipe ordered and we're ready to go.

That's helpful. Thanks. And then, just turning to your guidance here. It looks like the facilities guidance, you've been exceeding it. It seems like the past several quarters. And it points to something a bit lower next year, but it seems like you keep coming in ahead of what you've been saying. Is there asset sale timing or kind of other stuff involved there or could you expand a bit more about what drives the assumptions as far as being lower year-over-year there?

Yes. I'll take a shot at that. This is Al. Yes. It's exactly what you said. If you recall and went back a year, our guidance for 2018 was $665 million, the same guidance where we provided for 2019. The segment performed above expectation this year. Some of that, we aren't forecasting, continues. We'll see if that turns out to be conservative or not. There was a small bit of asset sale that impacted year-over-year, but it's pretty small. We're using a little bit higher of the net FX rate assumption for our Canadian business, which impacts it. But generally speaking, it is just that we've over performed this year and we're kind of using the same forecast for next year.

Sorry, which part over-performed this year?

The facility segment. I mean the throughput at terminals being the primary bid, we picked up more rail activity late this year than we expected, but really a large part of it is some of the throughput that we've seen at some of our market hub terminals like Cushing, Patoka, St. James.

That's helpful. I'll get back in the queue.

Jeremy, one other thing to think about. If you think, for example, the rail impacts on our facilities, we had a very, very wide Canadian differentials earlier in the year, and one of the things that kind of changed our outlook at the end of the year was the production -- the mandated production cuts in Canada, which has taken the differentials much, much tighter. So, it’s things like that that have impacted some of the facilities' earnings.

Forecast.

Yes. Forecast for 2019.

Great, that's helpful. I'll get back in the queue. Thanks.

Next question will come from Spiro Dounis with Credit Suisse.

Hey good afternoon. I just wanted to start off on Capline if we could. Trying to get a sense of the total potential capacity there once you fully reverse it? How do you think about that? And then maybe bottlenecks as well, either upstream at DAPL or even Diamond. Basically, how much flow should we expect to be coming down to the Gulf Coast?

Well, diamond probably has about 200,000 barrels a day of capacity. Well, not today, but can they expand it to work and move about 200,000 barrels a day. It's really going to be a function of how much of the volumes are light and how much are heavy. In North bound service you could move about 1 million barrels a day from north to south. But it will be meaningfully less because with the introduction of Canadian crude moving south, and it would be a function of how many pump. So, it's probably too early to say from Patoka down, but the limiting factors, I think, access to Canadian crude, pumps, and the type of crude that goes into the pipe.

Got it. Appreciate that. And then, just switching gears a bit here on Rockies volumes. They were a lot higher than we had expected this quarter. So, just wondering two things. One, what drove that? And how sustainable are the volumes that we just saw?

I think the Canadian dips drove a lot of it.

All right. Appreciate the color. Thank you.

Next up, we have Gabe Moreen with Mizuho Securities.

Hey good afternoon every one. I'll be the first I guess to ask about us. And now just in terms of, I guess, things having changed a bit since November between West Texas and Gulf's spreads and what happened as Will you alluded to in Western Canada. Can you just talk about -- I think your prior view was basically spreads being wide in the first half of this year and then narrowing in the back half of this year. Can you just talk about kind of what your market view is, to what extent you need that view to play out to hit that plus or minus $350 million and just kind of a degree of confidence in that guidance given where spreads have gone?

Yes, Gabe, this is Willie, I'll take a stab at the start and others can jump in. When we looked at 2019, we did expect spreads to stay wide until line started getting built and put in service. One of the things that's changed is there are some third-party lines that are going into service earlier than we thought, which I think has impacted the differentials, and so there is a piece of that, that is impacting our thoughts on 2019. I think the other perspective I'd give you is that, Al talked about our adjustments -- our mark-to-market at the end of the year. We've roughly $610 million of which a third of it was reversing losses from the previous quarter. But the balance of that was really a mark-to-market on what we hedged in 2019 and 2020. And if you think about what we've done, there's good portion of that that is probably covered under that as part of hedged for this year. And we came out with the guidance of $350 million, which we feel very confident we can meet. I think going forward, if the arbitrage opportunities are very slim between Permian and Midland, it would be harder to capture additional differentials. But that's kind of where we sit.

Okay, great. Thanks, Willie. And then following up basically on the leverage slide. I don't know if currently under review statement around the historical target range on leverage is new or not, but can you speak to that a little bit? And how that might play into your thoughts about capital returns? I guess, everyone's expecting you to announce later this year.

Yes. Gabe, this is Al. I guess, we added that comment there, but the one slide we've been using for probably about six months on distribution management. We are trying to tie all of this together as we think about kind of the financial policies, capital allocation, thoughts, distributions, leverage. So all that is being kind of combined in our thought process, and as we kind of conclude that in the first half of this year, we would expect to come out and discuss it with the broader community. That comment, clearly, we brought our leverage down, gotten back into our range, and what our view is, is that we need to challenge whether the lower range should be reduced, and so that will be part of our thought process.

Thanks, Al.

Okay.

And next from SunTrust, we have Tristan Richardson.

Hey, good afternoon, guys. Just a quick question on the transport volumes you talked about for the budget for 2019. Can you talk about the Permian component of that? And how it compares to the 3.7, which you guys reported for 2018?

Yes. This is Al. We didn't provide a separate number for Permian, but I think on our guidance, you can see -- I think we are showing about a 7 million barrels a day of total transport, and you can see the growth from this year. The vast majority of that growth is coming off the Permian business.

Understood. That's helpful. And then, just thinking about Capline in terms of the discrete time line of different crude grades. Should we think about the majority of the potential return opportunity coming at that later date when you're able to start flowing heavier? Or is there potential to see early cash flows from the project with the lighter grades?

Well, we hope to see earlier capital contributions from higher grades. So the capacity from Cushing down to St. James should be available on a quicker time frame than the heavies moving down from Patoka. We'll see what the open season results are but, certainly, that would be our expectation.

Understood. Thanks guys very much.

Next question comes from Jean Ann Salisbury with Bernstein.

Hi. You have Cactus II for partial service in third quarter and full service in April 2020. I think that the holdup between them is thought to build out at Corpus. I believe both enterprise and Kinder Morgan say that they have room on their pipes from Corpus to Houston and there may also be some spare Corpus export capacity with someone else. Are you guys exploring any interim solutions that might allow Cactus II to run at full service earlier?

Jeremy, why don't you take this one?

Jean Ann, this is Jeremy Goebel. We're well ahead I think of the other parts and connectivity [indiscernible] in our existing infrastructure. This is their first pipes down there. In addition with Cactus II, we've got dock capacity for our customers, so we think we'll be able to ramp up pretty quickly. We're actively engaged on construction to get into as soon as possible in addition to getting connectivity in place. We feel from an aggregation standpoint and from distribution standpoint, we're in good shape with the connections that are planned and really don't see a need for capacity at Houston at this time for Texas too specifically.

Okay, that makes sense. And then just a quick one. What is your internal estimate of your weighted average cost of capital currently?

This is Al. It clearly fluctuates frequently, but roughly 9%.

Okay, and that's kind of what would use for project return plus 300 to 500? Okay. Cool. That’s it for me. Thank you.

Yes, so 12% to 14%, clearly, we would like to do more than the high end, but that's kind of the target.

Make sense. Thanks.

Next from Jefferies, we have Vikram Bagri.

Hey guys. I wanted to understand all the moving parts as it relates to CapEx. What all projects are included in there? Is the estimate for Capline reversal or Diamond extension, the Red River project, is it all in there? And if not, how much higher can this CapEx plan for 2019 be? And is it a plan to do any more asset sales to fund that capital program? And how should we think about all that?

This is Al. No, those handful of specific projects you mentioned are not in the $1.1 billion. We are not planning to provide an asset sale target this year. We don't feel like we need to look to sell assets to fund growth capital. We made substantial progress on our leverage plans. So our view is that we -- if the capital program grows that we will fund it with retained cash flow and some holist amount of debt increase.

Great. And the second question I had was on Capline. The 18-month gap between light and heavy, I just wanted to understand what the limiting factor there is? I recall from the last conference call that, I think you mentioned Memphis, South bound from Memphis can be reversed in 18 months and 6 months after that you can reverse the entire pipeline. Is there a embedded assumption for or Keystone XL or Line 3 in there? And that's why the gap is so wide. And secondly, can there be a potential partner, an additional partner on Capline, who can provide additional volumes at Patoka? You're looking at that option as well?

Harry, you want to take that?

Sure. The limiting factor of Patoka's access to Canadian crude, so we are trying to time the reversal with when we think either Keystone or Enbridge would have additional capacity into Patoka. The base case does not assume any additional parties in Capline. Of course, there will be compelling economics to have but another partner on Capline, we would obviously consider that.

So the assumption is Line 3 comes online sometimes much sooner than 2022. Is it assumption that Line 3 doesn't come online on time or you might not get any barrels from Line 3 expansion 375,000 barrels per day, which is being planned?

I'm not sure we have a good enough handle on when Line 3 is going to come online. But as you know, that Enbridge has – is not able to contract additional capacity until mid- to late 2021. So that's part of the thought process and the timing.

Sounds good. Thank you very much.

Line 3 still has – they still have permits, I think we'd love to see them in service much earlier than 2022 though. But that's – it's – they still have permit to obtain before they could actually complete the project.

Okay. Thank you very much.

Next question will come from Dennis Coleman with Bank of America Merrill Lynch.

Good afternoon, everyone. Thanks for taking the question. I wanted to just circle back to the derivatives gain, if I can. You gave us a little bit of color on sort of two-thirds of it was for positions in 2019 and 2020. Al, you rather lost a number of different things that were driving that Canadian diffs to Permian diffs, Can we get any granularity on which of those might be more of it is – is it half the Canadian differentials and anything would help.

Yes. This is Al. We normally don't provide that level of breakout. But clearly, if you look at it, both those spreads have tightened meaningfully late in the year. The Permian spread, as you know, as well as WCS diffs oil prices came down, which as far as our fractionation hedges for our straddle plants bringing the NGL value down as well. So, all three of those things really drove the bulk of it. All of those results flowed through our S&L segment. And again, that's partly why we haven't had to change from November S&L guidance till today is because we hedged a meaningful part of it.

Okay. Thanks. And then, just more detailed one, if I can. You gave us CapEx for the Wink to Webster, I think, for 2019. Is it – should we assume a similar number for 2020?

No. I would think it – this is Willie. I would think about it as typical S-curve on a construction project, and I think that's most resolution we can give you.

Okay. Thank you. Operator: Next from Wells Fargo, we have Michael Blum.

Hey, good afternoon, everybody. Couple of quick questions on Capline. What is the timing of the open season? And I guess, when would be the earliest you could move to FID status on that?

The open season extends to April 30.

Okay. And then, in terms of any incremental CapEx that you add to the budget for 2019, is it basically, if Red River or Capline reach the finish line, are the kind of the two projects to watch for?

This is Al. Yes, I think those two would be, but there's also I mean, those are the ones publicly have talked about. But we're continuing to look at other stuff, again maybe smaller in nature, but those aren't the only two things that we're trying to advance.

Okay, great. Thank you.

Next question will come from Ethan Bellamy with Baird.

Hi, guys. We've seen a shift in financial metrics and what investors would like to see infrastructure companies from DCF growth, say, earnings and free cash flow. What are the current management compensation metrics? Are they the right metrics to use and would you anticipate any changes to those going forward in the next couple of years?

Ethan, this is Willie. One of the things we've done is, we historically had performance metrics around distributions and hitting certain marks, and we've shifted that to DCF per unit and that's something that already happened, and I think you'll see us further build on that.

All right. Thanks. And then just one follow-up, are you seeing any steel or labor cost inflation related to the tariffs and are the E&C costs accelerating, given how many large diameter long-haul pipes are planned?

E&P costs.

E&P. We're seeing higher costs.

Okay. Ethan, we don't -- I don't have a good price number for you today on what U.S. Steel is. I had some numbers previously when the tariffs were implemented we certainly saw popup, but I just don't know exactly where it stands today.

And would you say, you have a significant exposure to cost inflation or most of your cost locked in at this point?

For Cactus II, all that's locked in was the Houston companies as well as the pipe. And then for the Exxon JV, we actually priced it in September and we priced it again now, and prices honestly came down. So they've kind of peaked earlier and then they've come down some, but it's still higher than probably would have estimated a year ago. On the E&P side, we continue to manage it. Our procurement grew progressively, bid down everything and we'll work to manage those costs. But from a labor standpoint, it is a lot shorter that it has historically been, but we're going to actively manage those costs and we think the capital estimates we're using are very reflective on current markets.

Yes. Ethan, we've actually placed the order for the line pipe for the Exxon -- Wink to Webster project. And just a side point, it's from U.S. steel producers, so it has less exposure perhaps to tariffs and other duties.

All right. Thanks so much.

Moving on, we have with Colton Bean with Tudor, Pickering, Holt.

Good afternoon. Just to frame the 2019 CapEx discussion a bit differently. I appreciate you're probably still working through a few details there on Capline, but any preliminary thoughts on what work may be required in 2019 to hit that Q3 2020 in-service maybe Diamond or the Southern segment there?

Well, the diamond expansion includes pumps and extension of line 30 miles or so. The Capline portion of it just going to be reversing pumps versus cleaning the line versus purging the line, cleaning it and additional pump capacity modifications at manifold as both were seeking delivery locations.

And in terms of timeline on the construction, how much of that would need to be in 2019?

Yeah, Colton, I would think about that project as it's not hundreds of millions of dollars, right? When you think about the exposure for us, it would be -- we would be a partner in that, and I would think about the exposure for 2019 in a smaller number than that. Does that help?

That's helpful. Yeah. And just on the NGL pipes, pretty significant step up versus what we've seen in the last couple of years. You guys have stop for a bit on commentary on what the primary drivers were?

On which pipes?

Which pipe was that Colt?

NGL pipes…

So, a lot of that - it's a little bit on the gathering system, it's mostly movements in the market area around…

Got it. Thank you.

Next question comes from David Amoss with Heikkinen Energy

Hey, guys, I just wanted to see, you wouldn’t mind going into little bit of detail about the revisions to your commodity and volume assumptions between your third quarter guidance and your fourth quarter guidance?

Al?

You're talking about the difference between the $2.45 billion and the $2.4 billion for our fee-based segments?

Right. I think you mentioned earlier in the call that, that was reflective of a revision to your volume guidance based on potential change to commodity outlook?

Yeah, look -- yeah and it was -- basically, what we had provided in November is what we call preliminary guidance. It effectively was our shadow guidance from August of last year, adjusted for the BridgeTex sale. So clearly a lot of things have changed in that period of time. It's roughly a 2% change. Clearly, we do expect to see some impacts on producer’s activity relative to what we had expected previously with the price move. Clearly, there's been some impacts with regard to pipes coming on earlier than what we were thinking before, which is partly why you see the spreads that we've been talking about come in a little quicker. Lower prices does impact the value of our PLA that we collect as part of the tariffs. We also are going with a little higher FX rate, which affects those things. There is no one underlying thing. But the macro environment, I think we feel like we should be a little bit more cautious relative to as a result of the price environment, producer activity levels as well as these pipes coming on earlier.

Al, this is Jeremy. One thing to add is the impact of the Alberta curtailments had an impact on our claims and on the spreads as well.

That’s a good point

Okay, thanks. And then just trying to understand the Red River expansion project a little bit better. Are those -- is there a portion of this 100,000 barrels a day of barrels expected to get consumed in the East Texas region or all of these supposed to go to St. James? And if so how do you connect and how comfortable do you feel about the connection?

This is Jeremy. It will be a mix. Ultimately, it will be demand driven. But it will be a mix of locations and how do they consume.

And there's also some infrastructure in the Longview area down to the Gulf Coast. So there are several markets that [indiscernible] regular system.

That's helpful. Thank you, guys.

Hey, Greg. I think we’ve got time for one more question. If we can -- we will wrap after that.

Okay. In that case, we will take our final question from Jerren Holder with Goldman Sachs.

Thanks. Just a quick one on Capline. And can you guys move light crude from Patoka in 2020?

Yes.

Okay.

We should be able to.

And then a quick follow-up on crude exports. What are the opportunities there for Plains? Obviously, a lot of projects have been announced. So just trying to see how you guys are thinking about that?

We have our facility at Corpus Christi and we have a facility at St. James that could both could explore crude.

And Jerren, this is Willie. The other piece of this, Harry mentioned the assets we do have, we went into this couple of years ago, particularly around the open season for Cactus II. We were thinking about our integrated solutions of pipe and dock, and what we found is that shippers want to our choices of docks, so we shifted at our strategy a little bit. We think we're the best solution to be able to get barrels to the coast and what we strive to do is to have connectivity to the many, many docks that are being expanded to be able to get access to water. And that's so far there's been a lot of interest and us been able to get connections.

Okay, great. Thank you.

Okay. Thank you, everyone, for joining us today. We appreciate your time, and I look forward to talking to all of you very soon. Thank you.

Ladies and gentlemen, that does conclude our call for today. Thank you for joining us. You may now disconnect.