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Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Welcome to HollyFrontier First Quarter 2018 Conference Call and Webcast. Hosting the call today from HollyFrontier is George Damiris, President and Chief Executive Officer. He is joined by Rich Voliva, Executive Vice President and Chief Financial Officer; Jim Stump, Senior Vice President of Refinery Operations; and Tom Creery, President, Refining and Marketing. [Operator Instructions] Please note that this conference is being recorded.
It is now my pleasure to turn the floor over to Jared Harding, Investor Relations. Jared, you may begin.
Take you, Luke. Good morning, everyone, and welcome to HollyFrontier's first quarter 2018 earnings call. I'm Jared Harding with Investor Relations for HollyFrontier. This morning, we issued a press release announcing results for the quarter ending March 31, 2018. If you would like a copy of the press release, you may find one on our website at hollyfrontier.com.
Before we proceed with prepared remarks, please note the safe harbor disclosure statement in today's press release. In summary, it says statements made regarding management expectations, judgments or predictions are forward-looking statements. These statements are intended to be covered under the safe harbor provisions of federal securities laws. There are many factors that could cause results to differ from expectations, including those noted in our SEC filings. Today's statements are not guarantees of future outcomes.
The call also may include discussion of non-GAAP measures, and please see the press release for reconciliations to GAAP financial measures. Also, please note that information presented on today's call speaks only as of today, May 2, 2018. Any time-sensitive information provided may no longer be accurate at the time of any webcast replay or reading of the transcript. And with that, I'll turn the call over to George.
Thanks, Jared. Good morning, everyone. Today, we reported first quarter's net income attributable to HollyFrontier shareholders of $268 million, or $1.50 per diluted share.
Certain items detailed in our earnings release increased net income by $131 million on an after-tax basis. Excluding these items, net income was $137 million or $0.77 per diluted share versus a net loss of $33 million or $0.19 per diluted share for the same period in 2017. Adjusted EBITDA for the period was $316 million, an increase of $230 million compared to the first quarter of last year. This increase was principally driven by our Refining and Marketing segments, where we were able to capitalize on favorable crude differentials and strong product crack spreads in our market. Our Lubricants and Specialty Products business reported EBITDA of $41 million, driven by strong rack forward sales volume and margins. Rack forward posted adjusted EBITDA of $56 million, representing a 14% EBITDA margin and had operating costs of $36 million. HollyFrontier continues to expect rack forward EBITDA of $180 million to $200 million for 2018 with an EBITDA margin of 10% to 15% of sales. Lower base oil cracks combined with the lumbering impact of our feedstock supply issues hurt rack back earnings in the first quarter. With our feedstock supply issues behind us, we expect significant improvement in rack back as we enter the seasonally strong second and third quarters.
We do have plant maintenance at our Mississauga facility in the second quarter, which will impact both rack forward and rack back volumes. Holly Energy Partners reported EBITDA of $89 million for the first quarter compared to $70 million in the first quarter of last year. This growth was driven by the acquisition of the Salt Lake City and Frontier Pipeline as well as volume growth in HEP's crude gathering system. Distributable cash flow came in at $69 million, delivering a distribution coverage ratio of 1.04. During the quarter, we purchased $25 million-worth of HFC shares. This demonstrates our disciplined capital allocation strategy of first, maintaining our current assets and balance sheet strength; second, sustaining a competitive dividend; third, growing our business, both organically and through transactions; and fourth, returning excess cash to shareholders. Going into the summer, we are optimistic about light products and lubricant markets as well as the sustainability of crude differentials.
Now I'll turn the call over to Jim for an update on our operations.
Thanks, George. For the first quarter, our crude throughput was 415,000 barrels per day, in line with our guidance of 410,000 to 420,000 barrels per day. While our crude throughput was impacted by our Tulsa turnaround and unplanned maintenance at Woods Cross, our Refining system as a whole performed very well.
Our consolidated operating cost of $5.86 per throughput barrel, was a 16% improvement versus the $6.97 in the same period last year. The improvement was driven by increased throughputs along with operating cost reductions across our Refining system. In the Rockies, operating expenses were $9.62 per throughput barrel, a steady improvement over the $9.87 recorded in the first quarter of 2017. This was led by the continued focus on improving operational reliability and operating costs at our Cheyenne refinery. Our Navajo plant ran approximately 106,000 barrels per day in the first quarter. We continue to see the benefits of higher crude throughputs since the completion of our debottleneck project in the first quarter of 2017. In the Mid-Con, despite the turnaround at Tulsa, our operating expenses, per throughput barrel, of $5.28 improved by $0.52 per barrel versus the first quarter of last year. We have completed all the turnaround work at Tulsa safely, and we have resumed normal operating rates there. Our Woods Cross Refinery experienced a fire in mid-March. We are still in the process of repairing the #1 crude unit and expect Woods Cross to run at reduced rates for the balance of the quarter. During the quarter, we also have planned maintenance scheduled at our El Dorado Refinery that will slightly impact our sales volumes. For the second quarter of 2018, we expect to run between 440,000 and 450,000 barrels per day of crude oil.
I will now turn the call over to Tom for an update on our commercial operations.
Thanks, Jim, and good morning, everyone. For the first quarter of 2018, the 415,000 barrels a day of crude throughput was composed of 32% sour and 22% WCS and black wax crude oil. Our average laid in crude cost was under WTI by $8.47 in the Rockies, $2.80 in the Mid-Con, and flat versus WTI in the Southwest. In the first quarter of 2018, we witnessed global and U.S. product inventories to continue to be rebalanced, signaling global economies are continuing to grow and increasing the demand for refined products.
Gasoline inventories in the Magellan system ended the quarter at 9.8 million barrels, which was similar to last year's first quarter ending inventories. Diesel inventories remained static as compared to the fourth quarter of 2017 and approximately 0.5 million barrels lower than last year levels. First quarter cracks in the Mid-Con were $15.56, $13.70 in the Southwest and $15.66 in the Rockies. When compared to 2017, first quarter cracks were higher in the Mid-Con and lower in both the Rockies and Southwest. Crude differentials widened across heavy and sour slates during the first quarter. In the Canadian heavy market, first quarter crude differentials at Hardisty averaged over 20 -- $4.25 per barrel compared to a fourth quarter differential of $12.25 per barrel.
HFC with its firm space commitments on various pipelines was able to purchase and deliver adequate volumes of price-advantaged heavy crude from Canada to meet our refining needs. Our Canadian heavy and sour runs averaged 86,000 barrels per day at our plants in the Mid-Con and Rocky regions. We also refined approximately 174,000 barrels a day of Permian crude in our refining system composed of 106,000 barrels per day at our Navajo complex and 68,000 barrels a day at our El Dorado Refinery delivered by the Centurian Pipeline.
Increase to Permian-based crudes will allow us to take advantage of the widening differentials for Midland price-based oils. First quarter consolidated gross margin was $12.83 produced barrels sold. This was a 70% increase over the $7.54 recorded in the first quarter of 2017. This increase was driven by improved laid in crude costs in the Mid-Con and Rocky regions and the small refinery exemptions at our Cheyenne Refinery With widening Permian differentials and consistent discounts for WCS and black wax crude oils, we anticipate continued margins across our Refining system in the second quarter. RINs expense in the quarter was $6 million, which is net of the $72 million cost reduction resulting from the Cheyenne 2015 and 2017 small refinery exemptions received during the quarter.
And with that, let me turn the call over to Rich.
Thanks, Tom. As George mentioned, the first quarter included a few unusual items. Pretax earnings were positively impacted by $104 million lower cost to market benefit as well as a $72 million reduction in RINs costs as a result of our Cheyenne refineries small refinery exemptions. These positives were partially offset by $4 million of PCLI integration-related charges.
The table detailing these items can be found in our press release, and I am pleased to report we completed the integration of PCLI in the first quarter.
For the first quarter of 2018, cash flow provided by operations was $334 million including turnaround spending of $57 million, and HollyFrontier's stand-alone capital expenditures totaled $57 million. As of March 31, our total cash and marketable securities balance stood at $782 million, an increase of $151 million over the balance on December 31 of 2017. This increase was driven by our strong earnings and supplemented by a drawdown of inventory we had built in preparation for the first quarter turnaround at our Tulsa Refinery. During the quarter, we returned a total of $84 million of cash to shareholders comprised of a $0.33 regular dividend totaling $59 million as well as the repurchase of approximately 550,000 shares of common stock totaling $25 million. As of March 31, we had $152 million remaining on our existing stock repurchase authorization. As of March 31, HollyFrontier had $1 billion of stand-alone debt outstanding and no drawings on our $1.35 billion credit facility. This puts our liquidity at a healthy $2.1 billion and debt-to-capital at a modest 15%. HEP distributions received by HFC during the first quarter totaled $36 million, a 20% increase over the same period in 2017. HollyFrontier now owns 59.6 million HEP limited partnering units, representing 57% of HEP's LP units with a market value of $1.7 billion as of last night's close. For the full year of 2018, we slightly increased our CapEx guidance, driven by higher turnaround scope and costs. We now expect to spend between $380 million and $440 million for both stand-alone capital and turnarounds at HollyFrontier Refining and Marketing; $70 million to $90 million at our Frontier Lubes and Specialties, and this includes our scheduled turnaround at the Mississauga base oil plant; and $50 million to $60 million of capital for HEP.
And with that, Luke, we're ready to take questions.
[Operator Instructions] Our first question comes from the line of Doug Leggate from Bank of America.
George, I wonder if you could just give some prognosis as to how you see the spread outlook. Obviously, you are probably the primary beneficiary, both from Canadian heavy and inland discounts. So I'm just curious, at your Analyst Day, you laid out what now looks like a relatively conservative view of a $4 run rate for TI or for your realized margin under TI -- realized crude under TI. I'm just curious if that's changed. And I've got a quick follow up, please.
Yes, I think, Doug, the best way to answer that question -- those differentials we covered in the Analyst Day, we view as the long-term trend. It's going to bounce around above and below that, depending on the timing of crude production and pipeline capacity. Right now, obviously, things are getting tight at the Permian from a pipeline perspective and you're seeing dips in the $6 to $7 per barrel range and perhaps even spiking up a little bit above that recently. In Canada, we saw dips blow out as wide as $25-ish and have now settled back into the $16, $17 range. So that's going to be a function of how much crude can be taken out by rail in the interim year until the next increment of pipeline capacity is added.
Well you -- better operations, obviously, have done a great job of capturing that margin. So congrats on turning that around, George. I guess my follow-up is also at your Analyst Day, and again, there's a lot of moving parts in the assumptions. You kind of laid out what your view was of midcycle value for Holly, and you're pretty much there. So I am just wondering how that alters your view of share buybacks relative to other uses of cash, specifically stepping up the dividend at a more sustainable basis. And I'll leave it there.
Yes, Doug, I don't think it -- our current stock price impacts our capital allocation strategy. We're going to get monies back to shareholders to the extent that we have excess cash above our other priorities as I laid out in my prepared remarks.
So you're pretty agnostic to the share price on buybacks?
Again, I just view it as a way of getting money back to shareholders.
Your next question comes from the line of line of Brad Heffern from RBC Capital Markets.
A couple of questions on the RFS. Obviously, you've gotten the Cheyenne waivers for 2015 and 2017 here. No mention of Woods Cross. Is that application still outstanding? And additionally, is there a chance that you could get a retroactive 2015 exemption as well for Woods Cross?
Yes, I would say that we're in the process of working through all that, Brad. We haven't heard anything back yet, otherwise we would have reported it.
Okay. And then I guess on the RFS in general. Any thoughts you have, George, about the tack that the EPA seems to be taking of -- giving out a lot more smaller refinery exemptions and how that impacts the potential for broader reform?
Yes, I think the DC appellate court finding late last year, they've found that the previous EPA had erred in their review of applications for small refinery exemptions. So I think that was the key change from previous that opened up the door for what's provided for in the Clean Air Act, to allow the EPA to exempt small refiners from the RFS, from disproportionate economic harm. And, obviously, we view a high RIN cost market as disproportionate economic harm. Longer term, we're pleased by what we're seeing coming out of Washington. We applaud both of our Senators from the great state of Texas for their efforts in this area. Senator Cruz has gotten very involved in this effort and has been very involved through the Philadelphia Energy Solutions bankruptcy. Senator Cornyn is working on a legislative fix. But we're also encouraged by what we're hearing from Congressman Flores and Shimkus working similar legislative action on the House side. So you never know what's going to come out of Washington, but we're pleased with the direction things are going and fully recognize there's still a lot of work to be done here.
Your next question comes from the line of Manav Gupta from Crédit Suisse.
My first question is, can you talk about HFC's role in the Delaware diesel project?
It's a little bit premature to talk too much about it, but what we can tell you is we expect HFC to be the major customer for that facility. And we view it as a great opportunity to sell more diesel into the growing Delaware Basin market at improved netbacks to HollyFrontier versus our other alternatives for that product.
So I mean, going ahead, do you envision HEP growing such businesses like HFC is growing the Lubes business? Is this the kind of group growth that you have in plan for HEP going ahead? Projects like this?
Absolutely. These are exactly the type of projects that -- we view HEP as being a key part of our overall strategy.
Okay. And second question is more on spreads. So when I'm looking at the forward spreads on Midland-Cushing, I'm seeing a $12 discount for November '18. I just wanted to know your view on the spread. And if anything, if you know, what you're seeing on the ground in terms of trucking economics from the region. Anything -- any color you could add.
Yes, this is Tom Creery. Yes, we look at the forward markets as well on the Midland. As George mentioned earlier, that's just an indication of the imbalance of takeaway capacity versus drilling activity, which we believe is going to continue well into '19. So we're well poised to take advantage of those conditions. On the ground levels, we don't really see anything that's happening. There are some recently announced -- or previously announced pipeline production projects that will be completed later this year that will help remedy it, but those are already built into the price.
Your next question comes from the line of Roger Read from Wells Fargo.
I'll echo the good quarter comments. Well done and also on the share repos. It's always good to see that kick back around a little bit. If I could, though, jump into maybe operationally thinking about some things. On the PCLI side, remind me if I'm off here, but I think this would be the third out of fifth -- 5 quarters where we have seen some level of maintenance at PCLI. So I was wondering, is this a function of a lot of different units that need constant maintenance? Or that you're just getting familiar with the units, and so it makes sense to kind of call out the specific turnarounds as well as just sort of fine-tuning them for better product yields?
Roger, it's a fair question. I'd say that the maintenance we have this quarter as well as the fourth quarter was always planned. The maintenance we had last year was really not -- to your point, like it's not -- is there room for improvement, absolutely. But really looking into 2019, we always expected a turnaround at that facility in the fourth quarter, and we have also minor maintenance here in the second quarter.
Okay. So just -- I guess that's kind of what I'm trying to figure out, is how much of it is normal -- what we should consider as normal levels of maintenance going forward, I guess? A little bit each year, or...
Yes, it should be better. I mean, 2019 is a turnaround year, so fairly typical in that sense. And then we would expect a cleaner run, obviously, 2020 and going forward.
Okay, that's helpful.
So at a high-level here, Roger, we have 2 major process units at Mississauga and those units go down every 3 or 4 years on average. And this just happens to be the year, as Rich laid out, that we're taken both those units down this year.
Okay, perfect. And then my follow-up question, looking at your Southwest region, obviously, and following up on Manav's question about the difs, what is your flexibility there between running the light sweet and the sour barrels out there? So while we haven't seen a real separation, I think, between the price of the 2. Thinking about how you're set up for your yield by barrel, what's the swing factor there of sweet versus sour?
We can swing 100% sweet to sour. Now a little bit of that depends on what you mean by light sweet. When you start getting too much above, say, 45 gravity we can't process a lot of that material. As you know, that type of crude has a lot of light ends and we're constrained in our saturates gas plant. But as far as the swing from sweet to sour, we have 100% flexibility.
And Roger, that's where -- this is Tom. That's where the Centurion Pipeline comes in, too. That's a huge advantage of being able to bifurcate those crudes and move them around within the system.
Your next question comes from the line of Ryan Todd with Deutsche Bank.
Maybe a quick follow-up on those last comments. I mean, as you think about the flexibility in your system to segregate crudes and swing between things, how do you think about your positioning into the IMO switch in 2020? How it's likely to impact the way that you run your system and the kind of flexibility that you see to adjust to a changing environment?
Yes, obviously, IMO is going to help us from a crude differential perspective with the Canadian heavy. I don't see it impacting the rate of Canadian heavy we run because even at the recent or past differentials, we tend to run as much Canadian heavy as we can. But net-net, as Tom said in his prepared remarks, we run about 85,000, 90,000 barrels a day of Canadian heavy, and we'll run about those type of levels even in an IMO 2020 scenario.
Does it change much the type of crude slate on the light side that you would look to run?
I don't think so.
Okay. And then I guess switching the -- to use of excess cash. Again, it was good to see a restart of the buyback. I appreciate the comments earlier on buybacks versus dividend. But can you -- you're generating a lot of excess cash. I mean, can you talk a little bit about how you think about priorities for the use of excess cash and how much cash that you'd like to keep on the balance sheet? What's the appropriate level there and how we should think about the excess?
Sure, Ryan. So it really starts with keeping the balance sheet healthy, which we've laid out. We think, given where we are today with debt levels and a credit facility, we feel like $500 million of cash on the balance sheet is a good number. And above that, we would consider it to be excess. So first, it's maintaining the facilities; second will be to keep the dividend competitive; third would be to grow, whether that's organic capital or whether it's acquisition; and then beyond that when we've hit that $500 million threshold, we'll look to buy back stock.
Okay. And the pace of buyback that we saw in -- during the first quarter, is there anything to read in terms of how we should think about that pace going forward? Or is it just going to -- as we look over the near term, will that just change, based on the level of cash flow?
I [ don't ] think it was [ done on a reasonable ] pace, but it's definitely on a -- it will move around a little bit based on what else we have going on. Obviously, we've got a higher level of capital spend in the, call it, last 3 quarters of the year than the first quarter of the year. It will also depend on how cash flow's going here, we're all very optimistic about the rest of the year. But until the dollars are in the door, we're not going to spend them either.
And most of our repurchases were back half loaded.
Correct.
Your next question comes from the line of Paul Cheng from Barclays.
Two questions, if I may. In the first quarter, George, should we assume your WCS run and the Permian run is the maximum that you can go? Announced that this new pipeline is being installed? Or that there's some additional room that you would be able to squeeze more?
Yes, I think on the Permian, we did a really good job in the first quarter moving volume through our Centurion leased space. As Tom said in his prepared remarks, we ran, what, 68,000 barrels per day through that lease capacity. That's really good. So we might be able to squeeze a little bit more, but I would view that as being near the top of the end. And then I think, similarly, on the WCS, Tom mentioned 86,000 barrels per day of WCS runs between Cheyenne and El Dorado. We might be able to squeeze a little bit more, but I wouldn't view it as being significantly more than that.
Okay. If I'm looking at your margin capture, it seems like you have -- at least versus your own HollyFrontier, you were [ bottoming ] in the first quarter '17. Since then, that you've been steadily improved up and down, but on a rolling fourth quarter basis, steadily improved. And that in the first quarter, you reached on a four quarter basis average about 64% versus 56%. So yes, it's a big improvement over the last several quarters. Is there any particular things that you can cite why the improvement has been so sharp? And that the recent performance, could we use it as a baseline to go forward? Or that you think those are not necessarily sustainable?
Paul, this is Rich. There's a couple of things going on there, capture, it tends -- just the way the math works, capture tends to be better at higher cracks, which they've definitely been better in the last, call it 6 months, than they were late -- early '17 and certainly 2016. Second, honestly our benchmark cracks are based on WTI at Cushing. So in as much as crude differentials are widening, that's a big boon to capture rates per se. And then we obviously have a pretty good discussion on that. And last then will be RIN costs again. That gets back to that, at the higher level. If RINs are roughly the same but cracks are higher, the capture's going to look better. So that's the other big factor that comes in here. So to your point, Paul, of we've been running well. We expect to continue to run well at higher differentials and we'd expect to see higher capture rates going forward.
Right. So I guess my question is that, Rich, I understand everything that you just said earlier. So from an operational standpoint, is there any one-off issue that makes the operation to be better? Or that some benefit, whether it is your wholesale margin, price realization, that we should take into consideration may not be repeatable. I guess those are my questions.
I don't really believe so. No, Paul.
Your next question comes from the line of Neil Mehta from Goldman Sachs.
Just wanted to start off on the Lubricants business, PCLI. And as the crude price have ticked up, we've been watching your index here. But how do you see higher crude price impacting the profitability of that business? And can pricing increases keep up with input costs?
Neil, so this is where, frankly, having an integrated business is really helpful. Obviously, we saw some compression on the rack back side. And to your point, we saw base oil, kind of benchmark cracks compress in the first quarter, some of that's seasonality. Some of it was just where we are on the cycle on the Group III side. We expect it to get better seasonally on the second and third quarter, and what we've seen, frankly, is base oil postings have started moving up. On the flip side, then, there is going to be a lag on the rack forward side going through and passing through pricing that's slower to move. But again, this where we're optimistic on the business in general and having an integrated business model is really helpful.
All right. And a follow-up is just on the share repurchases and dividend growth. Again, I recognize that you want to see the cash come in first. But one of the constraints we've viewed historically about being overly aggressive for you guys around different growth has been the fact that you guys are BBB- and so want to protect that investment-grade rating. Do you think there's the balance sheet capacity to become more aggressive around the buyback? And do you think the ratings agencies would give you the space to do that?
Neil, I think, again, we laid out earlier kind of how we think about cash return, and that we view excess cash above, call it, $500 million in the balance sheet. But today's debt loads and revolver capacity, $500 million is sort of our walk around number and beyond that is excess. Keeping in mind that we've got an eye for growing the business, both organically and inorganically. So where we are in those kind of opportunities will affect that pace in rate.
Your next question comes from the line of Phil Gresh with JPMorgan.
Quick question on the cash flow in the quarter. Was there a working capital benefit?
Yes, Phil, there was a small working capital benefit in the quarter. About $80 million or so, just looking for the number exactly.
Got it. So I guess, if we look at the ending cash balance, Rich, about $780 million or so, I think you mentioned on the last quarter call that you did not expect to be building cash on the balance sheet unless perhaps there were M&A opportunities that would be in the line of sight. I think that was how you kind of framed it, relative to the $500 million of cash that you want on the balance sheet? So is the building cash in the quarter because of some working capital timing? Or, I guess, it somewhat comes back to the buyback question. Just trying to understand how you think about managing the cash.
Sure, Phil. So I think in this quarter, to your point, it's a little bit of a working capital build, which is good -- or excuse me, benefit. As I mentioned earlier, we've got just timing of the CapEx for this year. We are a little bit back end loaded, so we've got to keep that in mind. And the reality already is we can't predict necessarily a month or 2 out in our business, given where crack spreads are, so there's a lot of art to the speed of a buyback at the end of the day.
Okay. And I guess maybe more broadly. Obviously, there was other news in the sector this week. We get a lot of questions from investors as to whether the sector more broadly might have an opportunity to consolidate. And you guys have talked about looking for M&A opportunities, but that you really haven't been able to find anything. So do you think that the M&A environment in the sector has improved at all recently? Or is it just more status quo from your perspective?
I think the way we view it is pretty much status quo. I think the macro read that we have is consistent with what we shared at our Analyst Day that we think the issue is going to continue to consolidate. I think the scale is important, which is why we have our desire to double the size each of our businesses in a disciplined manner. But as far as the set of opportunities that we're seeing in the market right now, they really aren't impacted by the announcement earlier this week.
Okay. And just to clarify, building cash on the balance sheet here shouldn't necessarily be a read, Rich, that there are opportunities unfolding?
Yes, Phil, that's correct.
[Operator Instructions] Your next question comes from the line of Matthew Blair with Tudor, Pickering, Holt & Company.
I was hoping you could talk about black wax availability. It looks like Utah crude production is above 100,000 barrels a day for the first time since 2015. And on the screen at least we're seeing some increasing discounts on black wax barrels. Are you getting all the black wax volumes that you want? And are you realizing some of these larger discounts that we're seeing?
Yes, we're very encouraged by what we're seeing and hearing out of the Uintah Basin. To your specific question, we have been receiving all the wax crude that we need, especially prior to our incident at Woods Cross. But I think the producers that are in that region now are very focused on that region. They've made some significant technology improvements in the way they're producing the oil. So I think we think, as long as crude is in the -- above the $60 per barrel range, we're pleased with what we're seeing out of the production in that region.
Sounds good. And then I guess sticking in Refining, if I look at the spread here between your sales of produce refined products and your crude charge, that spread seemed a little elevated in the quarter. Is that a good number to use going forward? Or was it higher maybe due to like selling inventory during the Tulsa turnaround?
Yes, I think you just hit it. I don't think using this quarter is representative for our business because, as Rich said in his prepared remarks, we have built up inventory in advance of the Tulsa turnaround, that we've liquidated through the quarter.
There are no further questions at this time. I turn the call back to the presenters.
Thanks, everyone. We appreciate you taking the time to join us on today's call. If you have any follow-ups, as always, reach out to Investor Relations. Otherwise, we look forward to sharing our second quarter results in August.
Thank you. This does conclude today's teleconference. Please disconnect your lines at this time, and have a wonderful day.