Welcome to HollyFrontier's First Quarter 2018 Conference Call and Webcast. Hosting the call today from HollyFrontier is George Damaris, President and Chief Executive Officer. He is joined by Rich Maleva, Executive Vice President and Chief Financial Officer Jim Stump, Senior Vice President of Refinery Operations and Tom Creery, President, Refining and Marketing. 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. Thank you, Luke. Good morning, everyone, and welcome to HollyFrontier's Q1 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'd 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 reconciliation 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 1st quarter net income attributable to HollyFrontier shareholders of $268,000,000 or $1.50 per diluted share. Certain items detailed in our earnings release increased net income by $131,000,000 on an after tax basis. Excluding these items, net income was $137,000,000 or $0.77 per diluted share versus a net loss of $33,000,000 or $0.19 per diluted share for the same period in 2017.
Adjusted EBITDA for the period was $316,000,000 an increase of $230,000,000 compared to the Q1 of last year. This increase was principally driven by our refining and marketing segment, where we were able to capitalize on favorable crude differentials and strong product crack spreads in our markets. Our Lubricants and Specialty Products business reported EBITDA of $41,000,000 driven by strong Rack Forward sales volumes and margin. Rack Forward posted adjusted EBITDA of $56,000,000 representing a 14% EBITDA margin and had operating costs of $36,000,000 Poly Frontier continues to expect Rack Forward EBITDA of $180,000,000 to $200,000,000 for 2018 with an EBITDA margin of 10% to 15% of sales. Lower base oil cracks, combined with the limping impact of our feedstock supply issues hurt Rack Back earnings in the Q1.
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 2nd quarter, which will impact both Rack Forward and Rack Back volume. Holly Energy Partners reported EBITDA of $89,000,000 for the Q1 compared to $70,000,000 the Q1 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 $69,000,000 delivering a distribution coverage ratio of 1.04.
During the quarter, we repurchased $25,000,000 worth of HFC shares. This demonstrates our disciplined capital allocation strategy of 1st, maintaining our current assets and balance sheet strength second, sustaining a competitive dividend 3rd, growing our business both organically and through transactions and 4th, 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 Q1,
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 of woodscrops, 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 Q1 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 Q1. We continue to see the benefits of higher crude throughputs since the completion of our debottleneck project in the Q1 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 Q1 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're still in the process of repairing the number one 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 schedule at our El Dorado refinery that will slightly impact our sales volumes. For the Q2 of 2018, we expect to run between 440,000,450,000
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 Q1 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, dollars 2.80 in the Mid Con and flat versus WTI in the Southwest. In the Q1 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 9,800,000 barrels, which was similar to last year's Q1 ending inventories. Diesel inventories remain static as compared to the Q4 of 2017 and approximately 500,000 barrels lower than last year levels. 1st quarter cracks in the Mid Con were $15.56 13.70 in the Southwest and $15.66 in the Rockies. When compared to 2017, Q1 cracks were higher in the Mid Con and lower in both the Rockies and Southwest.
Crude differentials widened across heavy sour slates during the Q1. In the Canadian heavy market, 1st quarter crude differentials in Hardisty averaged over $24.25 per barrel compared to a 4th 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 Centurion pipeline. Increased to Permian based crudes will allow us to take advantage of the widening differentials for Midland price based oils. 1st quarter consolidated gross margin was $12.83 produced barrels sold. This was a 70% increase over the $7.54 recorded in the Q1 of 2017. This increase was driven by improved late 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 Q2. RINs expense in the quarter was $6,000,000 which is net of the $72,000,000 cost reduction resulting from the Cheyenne 2015 2017 small refinery extensions received during the quarter. And with that, let me turn the call over to Rich.
Thanks, Tom. As George mentioned, the Q1 included a few unusual items. Pretax earnings were positively impacted by a $104,000,000 lower cost to market benefit as well as a $72,000,000 reduction in RINs costs as a result of our Cheyenne refineries, small refinery exemptions. These positives were partially offset by $4,000,000 of PCLI integration related charges. The table detailing these items can be found in our press release.
And I'm pleased to report we completed the integration of PCLI in the Q1. For the Q1 of 2018, cash flow provided by operations was $334,000,000 including turnaround spending of $57,000,000 and HollyFrontier's standalone capital expenditures totaled $57,000,000 As of March 31, our total cash and marketable securities balance stood at $782,000,000 an increase of $151,000,000 over the balance on December 31, 2017. This increase was driven by our strong earnings and supplemented by a drawdown of inventory we had built in preparation for the Q1 turnaround at our Tulsa refinery. During the quarter, we returned a total of $84,000,000 of cash to shareholders comprised of a $0.33 regular dividend totaling $59,000,000 as well as the repurchase of approximately 550,000 shares of common stock totaling $25,000,000 As of March 31, we had $152,000,000 remaining on our existing stock repurchase authorization. As of March 31, HollyFrontier has $1,000,000,000 of standalone debt outstanding and no drawings on our $1,350,000,000 credit facility.
This puts our liquidity at a healthy $2,100,000,000 and debt to capital at a modest 15%. HEP distributions received by HFC during the Q1 totaled $36,000,000 a 20% increase over the same period in 2017. HollyFrontier now owns 59,600,000 HEP Limited Partner Units, representing 57% of HEP's LP units with a market value of $1,700,000,000 as of last night's close. For the full year of 2018, we've slightly increased our CapEx guidance driven by higher turnaround scope and cost. We now expect to spend between $380,000,000 $440,000,000 for both standalone capital and turnarounds at HollyFront Frontier Refining and Marketing, dollars 70,000,000 to $90,000,000 at HollyFrontier Lubes and Specialties.
This includes our scheduled turnaround at
the Mississauga base oil plant
and $50,000,000 to $60,000,000 of capital for HEP. And with that, Luke,
we're ready to take questions.
The floor is now open for questions. You. Our first question comes from the line of Doug Leggate from Bank of America. Your line is open.
Thanks guys. Good morning everybody and congrats on a really terrific quarter. 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 about a $4 run rate for TI or for your realized margin under TI or realized crude under TI?
I'm just curious if that's changed. And I've got a quick follow-up, please.
Yes. I think 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 out of 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 up to as wide as 25 ish and set now pedal 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 here until the next incremental pipeline capacity is added.
Better operations, obviously, done a great job of capturing our margins. So congrats on turning that around, George. I guess my follow-up is also 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 mid cycle value for Holly, and you're pretty much there. So I'm just wondering how that alters your view of share buybacks relative to other uses of cash specifically stepping up the dividend on
a more sustainable basis? And I'll leave it there. Thanks.
Yes. So I don't think it our current stock price impacts our capital allocation strategy. We're going to get money 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 Brad Heffern from RBC Capital Markets. Your line is open.
Hey, good morning, everyone. Couple of questions on the RFS. Obviously, you've gotten the Cheyenne waivers for 2015 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'd have reported it.
Okay. And then I guess on the RFS in general, any thoughts you have, George, about the tact that the EPA seems to be taking of giving out a lot more small refiner exemptions and how that impacts the potential for broader reform?
Yes, I think the DC applicant court finding late last year, They found that the previous EPA had aired 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 for 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. We're also encouraged by what we're hearing from Congressman Flores and Simpkins 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 Credit Suisse. Your line is open.
Hey, guys. Thanks for taking my question. 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 HSD to be the major customer for that facility and we feel there's 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 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 Middle and Cushing, I'm seeing $12 discount for November 2018. 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 2019. 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 line of Roger Read from Wells Fargo. Your line is open.
Yes, thanks. Good morning. And 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 jump into maybe operationally thinking about some things. On the PCLI side, remind me if I'm off here, but
I think this will be the 3rd out of
5th out of 5 quarters where we've 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 Q4 was always planned. The maintenance we had last year was really not to your point like it's not there's room for improvement absolutely, but really looking into 2019, we had always expected a turnaround at that facility in the Q4 and we have some minor maintenance here in the Q2.
Okay. So just I mean,
I guess that's kind of
what I'm trying to figure out is how much of it it is normal. What we should consider as normal levels of maintenance going forward, I guess, a little bit each year?
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've taken both of 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 diffs, 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 it's a little bit 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 constraining our saturated gas plant. But as far as swinging from sweet to sour, we have 100% flexibility.
Okay, great. Thank you.
And Roger, that's where this is Tom, that's where the Centurion pipeline comes into. That's a huge advantage and able to bifurcate those crews and move them around within the system.
Absolutely good to own infrastructure. Thanks.
Your next question comes from the line of Ryan Todd with Deutsche Bank. Your line is open.
Thanks. Good morning, guys. 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, I mean 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 the changing environment?
Yes. Obviously, IMO is going to help us from a true differential perspective with the Canadian heavy. I don't see it impacting the rate of Canadian heavy we run because even at recent 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, 9000 barrels a day of Canadian heavy and we'll run about those type of levels even in the 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 to use of excess cash again, it was good to see a restart of the buyback. I appreciate the comments earlier on buyback 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, Rainelle. So it really starts with keeping the balance sheet healthy, which we've laid out. I think given where we are today with debt levels and the credit facility, we feel like $500,000,000 of cash on the balance sheet is a good number. And above that, we would consider it to be excess. So first is maintaining the facilities.
2nd will be to keep the dividend competitive. 3rd will be to grow whether that's organic capital or whether it's acquisition. And then beyond that and we fit that $500,000,000 threshold, we'll look to buy back stock.
Okay. And the pace of buyback that we saw in during the Q1, is there anything to read in terms of how we should think about that pace going forward? 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 on a
reasonable pace, but it definitely got 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 Q1 of the year. It also depends on how cash flow is going here. We're all very optimistic about the rest of the year. But till the dollars are in the door, we're not going to spend them either.
And most of our resources were
back half loaded?
Correct.
Okay. Thanks, Rich and George.
Thanks, Ben. Your next question comes from the line of Paul Cheng from Barclays. Your line is open. Hey, guys. Good morning.
Good morning.
Two questions, if I may. In the Q1, George, should we assume your WCS run and the Permian run is the maximum that you can go unless that there's 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 Q1, moving volume through our Centurion lease 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 at 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 Holly Fontein index, you bought them in the Q1 2017. Since then that you've been steadily improved up and down, but on a rolling 4 quarter basis, steadily improved. And in the first quarter, you reached on a 4 quarter basis average about 64% versus 56%. So yes, a big improvement over the last several quarters. Is there any particular things that you can say why the improvement have 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?
So Paul, this is Rich. There's a couple of things going on there. Capture tend 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 2017 and certainly in 2016. 2nd, honestly, our benchmark cracks are based on WTI at Cushing. And as much as crude differentials are widening, that's a big boon to capture rates per se. And then we possibly have pretty good discussion on that. And last then will be RIN costs again, that gets back to that at the higher level.
The RINs are roughly the same, but cracks are higher, capture is going to look better. So that's the other big factor that comes in here. So to your point, Paul, we've been running well. We expect to continue to run well. At higher differentials, 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 operational standpoint, is there any one off issue that make the operation to be better or that some benefit whether it's 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.
Okay, very good. Thank you.
Thank you. Your next question comes from the line of Neil Mehta with Goldman Sachs. Your line is open.
Hey, good morning, guys. Congrats again on a good quarter here. Just want to start off on the lubricants business, PCLI. And as the crude prices 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?
Hey 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 compressed in the Q1 some of that seasonality some of it was just where we are in the cycle on the Group 3 side. We expect it to get better seasonally on the 2nd Q3. 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, it's slower to move. But again, this is where we're optimistic on the business in general and having that integrated business model is really helpful.
All right. Thanks. And a follow-up is just on the share repurchases and dividend growth. Again, 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 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?
Any other thoughts? I think again we laid out earlier kind of how we think about cash return and then we view excess cash above call it $500,000,000 in the balance sheet with today's debt loads and revolver capacity. $500,000,000 is sort of our walk around number and beyond that is excess. Keeping in mind that we've got an eye to growing the business both organically and inorganically. So where we are on those kind of opportunities will affect that pace and rate.
Okay. Thanks guys. Your next question comes from the line of Phil Gresh with JPMorgan. Your line is open.
Yes. Hi, good morning. 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.
Thank you, John. About $80,000,000
or so. Just looking for
the number exactly. Okay, got it. So I mean I guess if we look at the ending cash balance, Rich, about $780,000,000 or so, I think you mentioned on the last quarter call that you would not expect to be building cash on the balance sheet unless perhaps there were M and A opportunities that would be in the line of sight. I think it was kind of how you framed it relative to the $500,000,000 of cash that you want on the balance sheet. So is the build in cash in the quarter because of some working capital timing?
Or I guess this somewhat comes back to the buyback question. Just trying to understand how you're thinking about managing the cash?
Sure, Feltau. I think in this quarter to your point there's a little bit of working capital build which is good or excuse me benefit. As I mentioned earlier we've got timing of CapEx for this year. We're a little bit back end loaded. So we got to keep that in mind.
And the reality right 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 the 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 and A opportunities, but they really haven't been able to find anything. So do you think that the M and A environment in the sector has improved at all recently?
Or is it more status quo from your perspective?
Yes. I think the way we view it, it's 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 industry is going to continue to consolidate. I think scale is important, which is why we have our desire to double the size of 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 in the balance sheet here shouldn't necessarily be a read, Rich, that there are opportunities unfolding? Yes. Phil, that's correct.
Okay. Thank you.
Thanks.
Your next question comes from the line of Matthew Blair with Tudor, Pickering, Holt and Company. Your line is open.
Hey, good morning, everyone.
Good morning, Matthew.
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 Uinta 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 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 produced 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 had built up inventory in advance of Tulsa turnaround that we've liquidated through the quarter.
Got it. Thank you.
Sure.
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 Q2 results in August. Thank you. This does conclude today's teleconference. Please disconnect your lines at this time and have a wonderful day.