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Good morning, and welcome to HollyFrontier's Fourth Quarter 2017 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 call is being recorded. It is now my pleasure to turn the floor over to Craig Biery, Director, Investor Relations. Craig, you may begin.
Thank you, Lisa. Good morning, everyone, and welcome to HollyFrontier Corporation's Fourth Quarter 2017 Earnings Call. I'm Craig Biery, Director of Investor Relations for HollyFrontier. This morning, we issued a press release announcing results for the quarter ending December 31, 2017. If you would like a copy of the press release, you may find one on our website at hollyfrontier.com. Before we proceed with 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 security 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 the GAAP financial measures. Also, please note that information presented on today's call speaks only as of today, February 21, 2018. Any time-sensitive information provided may no longer be accurate at the time of any webcast replay or rereading of the transcript. And with that, I'll turn the call over to George Damiris.
Thanks, Craig. Good morning, everyone. Today, we reported fourth quarter net income attributable to HFC shareholders of $521 million or $2.92 per diluted share. Certain items detailed in our earnings release, that Rich will discuss in his prepared remarks, increased net income by $397 million on an after-tax basis. Excluding these items, net income for the current quarter was $125 million or $0.70 per diluted share versus a net loss of $10 million or $0.06 per diluted share for the same period in 2016. Adjusted EBITDA for the period was $334 million, an increase of $233 million compared to the fourth quarter of last year. This increase was principally driven by improvements in our Refining & Marketing segments, where higher sales volumes, refining margins and crude differentials combined to increase adjusted EBITDA to $261 million versus $24 million in the fourth quarter of last year. Our Lubricants & Specialty Products business had a good fourth quarter with $40 million of adjusted EBITDA. The Rack Forward portion of this business posted adjusted EBITDA of $48 million, representing a 14% EBITDA margin and had operating cost of $38 million. For the 11 months that we owned PCLI in 2017, adjusted EBITDA for Rack Forward was $179 million, representing an EBITDA margin of 13%. Rack back margins were lower in the fourth quarter compared to the third quarter due to operational and speeds back supply issues from a major supplier to our Mississauga Plant. We expect these issues are one-off events. For full year 2017, base oils represented 31% of our sales, while 45% was finished products and 24% was light products and intermediates. Going forward, we see a significant opportunity to high grade a portion of our existing base oil sales into higher finished product sales. On average, finished products realized a margin uplift of approximately $50 per barrel of our base oils. Our growth strategy is centered on organic initiatives to achieve this downward integration, and provides a positive outlook for the earnings power of our Lubricants & Specialty products business. For 2018, we anticipate Rack Forward EBITDA of $175 million to $200 million with an EBITDA margin of 10% to 15% of sales, in line with the guidance we provided at our Analyst Day in December. In late 2017, we are pleased to see the passage of the Tax Cuts and Jobs Act, the reforms to the U.S. tax code, encourage capital investments and lower the corporate rate to better enable manufacturers to compete in the global market. We applaud the administration and Congress for enacting comprehensive legislation, which recognizes the value of our industries' global supply chain and the importance of master limited partnerships and improving our nation's energy infrastructure. We expect a meaningful benefit from reduction in our effective tax rate going forward. We are excited about 2018 based on our improving refinery reliability, our outlook for both crude spreads and product racks as well as the growth and improvement potential of our Lubricants & Specialty Products business. Our capital allocation strategy will continue to focus on disciplined growth, while maintaining our current assets and balance sheet strengths. First and foremost, we will continue to make the investments necessary to operate our existing assets safely and reliably. Second, we'll maintain a healthy level of liquidity to preserve our investment grade rating. Third, we intend to maintain a competitive regular dividend yield. Fourth, we'll look for opportunities to grow, both organically and through M&A. We have stated our aspirations to grow each of our 3 businesses and remained confident that we are well positioned to do so. When we have transparency to cash in excess of these 4 uses, we will return cash to shareholders in the form of stock repurchases. I'll now turn the call over to Jim for an update on our operations.
Thank you, George. For the fourth quarter, our crude throughput was 461,000 barrels per day, that's slightly above our guidance of 450,000 to 460,000 barrels per day. It is also our second best quarter ever. On a consolidated basis, we set a monthly crude charge record of 484,000 barrels per day for November. And for the full year 2017, we achieved our highest annual crude charge averaging 439,000 barrels per day. The Rockies region continues to improve operationally, running an average combined crude rate of 80,000 barrels per day in the fourth quarter. We set a monthly crude charge record running an average of 40,000 barrels per day at our Woods Cross Refinery in November. Our Navajo Plant ran well during the quarter, averaging approximately 111,000 barrels per day. Navajo's operating expense per throughput barrel was $4.76 in the fourth quarter and was a 15% improvement versus the same period from 2016. Our consolidated operating cost of $5.79 per throughput barrel was slightly elevated versus the $5.59 in the same period last year. This increase is primarily due to approximately $18 million of environmental and insurance accruals we incurred during the quarter. For the first quarter of 2018, we expect to run between 410,000 and 420,000 barrels per day of crude oil, mostly impacted by our planned turnaround at our Tulsa West Plant. I will now turn the call over to Tom for an update on our commercial operations.
Thanks, Jim, and good morning, everyone. As Jim previously mentioned, we ran a total of 461,000 barrels a day of crude oil in the fourth quarter. This lag was composed of approximately 26% sour and 19% WCS and black wax crude oil. Our average laid-in crude cost in the Mid-Con was flat against WTI and under WTI by $3.06 in the Rockies and $0.26 in the Southwest. In the fourth quarter of 2017, we witnessed global and U.S. product inventories becoming rebalanced as they receded from 5-year average highs to current lows, signaling an increased global demand. Gasoline inventories in the Magellan system, while increasing by 1 million barrels at the end of fourth quarter, 7 million barrels were still lower than the last year levels at this time. Diesel inventories were down by 1.8 million barrels versus last year to close in the Magellan system at 4.67 million barrels. In terms of days of supply in the group, fourth quarter gasoline was at 19 days and diesel at 23 days. Each of these ratios is at or near 6-year lows. Lower inventories and higher demand helped cracks in all the regions during the fourth quarter. When compared to the third quarter of this year, cracks in the Mid-Con were lower in the fourth by $1.25 and approximately $4.50 in both the southwestern Rockies. However, when compared to fourth quarter cracks of 2016, cracks in our markets were some $5 to $8 higher. Crude differentials widened across heavy slates during the fourth quarter. On the Canadian side, a pipeline leak on the Keystone system precipitated widening differentials for Canadian heavies. The majority of the price impact will not be seen until the first quarter of 2018 due to the timing of the trade window and the in transit time for the physical delivery of this oil. To put this in a better perspective, the average December trade differential was $13.93 per barrel compared to current differentials for April delivery of upwards of $30 per barrel. HFC, due to its firm space commitments on various pipelines, is well positioned to purchase and deliver volumes of price advantaged heavy crude oil from Canada. Fourth quarter consolidated gross margin was $12.54 per barrel sold and 85% increase over the $6.77 recorded in the same quarter of 2016. We continue to see improvements in our Rocky Mountain region with the realized gross margin of $12.19 per produced barrels, which represents a 96% increase from the fourth quarter of 2016. With a tailwind from WCS differentials and improving black wax production levels, we anticipate higher realized margins in 2018 in the Rockies. Our RIN expense in the quarter was $78 million, including a $27 million benefit we received for the Woods Cross 2016 small refinery exemption. For the full year, our RIN expense was $288 million, including the Woods Cross and Cheyenne small refinery exemptions for 2016. And with that, let me turn the call over to Rich.
Thank you, Tom. As George mentioned, the fourth quarter included a few unusual items: earnings were positively impacted by a $307 million reduction in deferred income taxes due to the Tax Cuts and Jobs Act and $93 million pretax lower of cost or market benefit; a $27 million pretax reduction in RINs cost as a result of our Woods Cross Refinery's small refinery exemption; and a $21 million pretax gain for the remeasurement of ATP's preexisting interest in the SLC and Frontier Pipelines. 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. In the fourth quarter of 2017, cash flow provided by operations was $166 million, including turnaround spending of $24 million and HollyFrontier's stand-alone capital expenditures totaling $65 million. As of December 31, our total cash and marketable securities balance stood at $631 million, essentially flat versus our balance on September 30. Cash flow from operations and consequently our cash balance was impacted by the timing of tax and interest payments and an increase in inventory in preparation for the first quarter turnaround of our Tulsa Refinery. During the fourth quarter, we announced and paid a $0.33 regular dividend, putting our yield at 2.9% at last night's close. As of January 31, we have $1 billion of stand-alone debt outstanding and no drawings on our $1.35 billion credit facility, puts our liquidity at a healthy $2 billion and debt to cap at a modest 17%. Total HEP distributions received by HollyFrontier during 2017 were $131 million, a 25% increase over 2016. On October 31, HollyFrontier and HEP closed their previously announced IDR simplification transaction. HFC now owns 59.6 million HEP limited partner units, representing 57% of HEP's units at market -- with a market value of over $1.8 billion as of last night's close. We believe this transaction provides fair value for the IDRs to HFC and strengthens HEP's capital structure for long-term sustainable growth. Beginning with the fourth quarter of 2017, our segment reporting was reorganized to reflect our 3 business segments: HollyFrontier Refining & Marketing; HollyFrontier Lubricants & Specialty Products, or HF LSP; and Holly Energy Partners. HF LSP includes the Rack Forward operations of both PCLI and Tulsa and the rack back operations of PCLI. SG&A is allocated in the 3 segments, with stewardship and certain integration costs reflected in the Corporate segment. SG&A in the quarter was elevated due to seasonal fourth quarter compensation payments, onetime expenses related to our IDR restructuring and PCLI integration costs. For the full year of 2018, we anticipate G&A expenses of $105 million to $115 million for Refining & Marketing, $125 million to $135 million for HF LSP, $12 million to $15 million for HEP and $10 million to $15 million in Corporate. With respect to tax rate, due to the impact of the Tax Cuts and Jobs Act, we estimate our consolidated effective tax rate will be 23% to 25% for 2018 versus the 36% to 38% in prior years. In 2018, we expect to spend $375 million to $425 million for both stand-alone capital and turnarounds at HollyFrontier Refining & Marketing; $70 million to $80 million at HF Lubes & Specialties, including the scheduled turnaround of our Mississauga base oil plant; and $40 million to $50 million capital at HEP. As George mentioned earlier, we are committed to returning excess cash to shareholders. We are targeting a minimum cash balance of approximately $500 million. Based on our positive outlook for 2018 and the impact of recent tax reform, we expect to resume share repurchases. We currently have approximately $179 million remaining on our existing $1 billion share repurchase authorization. And with that, Lisa, we're ready to take questions.
[Operator Instructions] Our first question comes from the line of Paul Cheng from Barclays.
I think that this may be for Jim. For HollyFrontier, you won about 80,000 to 100,000 barrel per day of Canadian heavy oil. How much of them -- is it 100% that you have their lines they commit? Or that you don't -- I mean, what is the nice base cut that you already have the firm commitment?
Yes, Paul, this is Tom Creery. In terms of -- we typically run 80,000 to 100,000 barrels a day of Canadian crude. And we have enough line space at the current apportionment rates than what we are forecasting to be future forecast rate to support these run rates at this time.
So that is basically a one-to-one benefit that you ran the Canadian heavy oil expand for you guys?
At this point in time, the answer is, yes.
Okay. And on the other one that -- the second question is, when I look at the fourth quarter, are cost of region, your margin capture rate have declined comparing to the third quarter, which is a near bit surprising given you should have [indiscernible] branding benefit? As far as in the third quarter due to the hurricane, we get a certain rise in margin in September, which typically as a result people will not be able to fully capture that. So I was expecting you should see better margin capture weight itself worse off. Any one-off issue or special item that we should be aware of the situation?
Paul, this is Rich. I think there's kind of a host of really random things that went on in the quarter. Gasoline margins kind of fell out in the back part of the quarter, in particular. We had a couple of conversion rate and unit issues during the quarter, which probably hit production and really sales of kind of a higher value of finished products at the margin. And then to your point, look, we really didn't realize any of the benefit of crude differentials in the fourth quarter itself. So we've got that lag effect that comes through there.
And, Rich, on the conversion units -- can you tell us that which unit...
Paul, we have a number of small issues. That's why I kind of said, look at the host of little mix and cuts kind of thing. It's really not one to call out.
Our next question comes from the line of Blake Fernandez from Howard Weil.
Maybe just following onto Paul's question, but more on the cost side. I guess, we were a little surprised throughput was fairly strong. But it seemed like on a per barrel basis, the costs were a bit elevated compared to maybe what we were thinking. So was there anything kind of driving that or thoughts on that going forward?
No. I think -- Blake, this is George. I think Jim tried to address some of that in his prepared remarks. We had a number of accruals and/or onetime costs come through our books in the fourth quarter in OpEx. Jim called out roughly $18 million in environmental and in insurance accruals. I think Rich highlighted the IDR fees and PCLI integration costs. I think if you total all that up, it comes out to around $30 million pretax, roughly $20 million after tax, roughly $0.10 or $0.11 a share, I think that's the majority of what you're looking at.
Okay, and that PCLI piece, would that have been in the refining cost piece? Or that wouldn't have been there though, right, George?
That's been -- it has been the G&A piece.
Okay, okay, okay. And then secondly, you may have kind of tackled this, George, in your prepared remarks, but the one piece that kind of through us for a little bit of a loop to us on the lubes business. It looks like the Rack Forward business is trending broadly in line with your full year guidance range. But the rack back piece was fairly kind of negative compared to our expectations. It sounds like maybe there's a one-off item in there, but could you just elaborate a little bit?
No. I think, we buy our gas oil for that facility from others. A major supplier to that plant had operational issues that they couldn't supply us as much as they normally do. We had to find alternative supply. That alternative supply had higher logistics costs associated with it. I think that's what you're seeing here.
Okay, that seems to be alleviated though going forward here.
Correct, correct.
Our next question comes from the line of Brad Heffern from RBC Capital Markets.
George, you mentioned in your prepared comments sort of the pecking order of cash uses and M&A, I think, was forward than that. I was just wondering if you could go through your sort of outlook on the M&A front. What you are seeing in the market right now?
What I think, we're seeing a good flow of opportunities. We're working on them hard. I wouldn't say there's anything imminent, but we are pleased with the deal flow we're seeing. And I think I'll just leave it at that. I don't think there's again anything imminent, but we'll continue to look and as we've said before, we want to emphasize our disciplined approach to this. We've seen a number of deals in 2017 that we participate in the process, but didn't end up winning, obviously, otherwise we'd have announced the deal. We're going to continue to look. And when we pull the trigger, we'll see value.
Okay, got it. And then, on the RIN's front, nice to see that you guys got the way over of Woods Cross. Can you talk through sort of what you're seeing on the vertical front at this point?
Yes. I think we're pleased to see that there's dialogues between senators from the corn states, senators Grassley and Ernst as well as our Texas Senators, Cruz and Cornyn, are very involved in the process. I think nothing happens without dialogues. We're pleased to see that dialogues occurring. But having said all that, there is a long way to go between dialogue and resolution. But at least, we think that the dialogue and the PES bankruptcy situation is highlighting the need to get something done here, and we view that all as positive momentum towards that objective.
Our next question comes from the line of Roger Read from Wells Fargo.
Maybe we'll follow up there on the RIN. So you get the release at Woods Cross. So just curious, did you ask for relief or request relief at more than that location? And if so, kind of any idea what the criteria appeared to be to the EPA?
Yes. I think, like you said, we announced the Wood Cross relief for 2016. As you probably recall earlier in the year, we received relief at Cheyenne and both of those are small refineries and those are the types of facilities that are applying and being considered for that type of relief.
Does that mean we can -- we're still waiting to hear on Cheyenne? Or do you think this is the result for the year?
I think that's what we've gotten for 2016 again. So both Cheyenne and Woods Cross received relief for the 2016 year. 2017 -- the books haven't closed on RINs for 2017 yet.
Okay. So potentially more to come I think is the way we could look at this in terms of future relief?
I think that's a reasonable statement.
Okay. And then back to the kind of rack forward, rack backwards discussion. And then just in a sense, this may be again affected by some onetime items. If you would look at the total sort of net income margin of the lubes business, it actually declined versus '16, which is a little surprising given the addition of PCLI. So I was just wondering as you look at the sort of total income margin was 16% in '16, 9% in '17. Kind of what the impacts of PCLI really were? Is that some onetime issues in OpEx? Is that a functional depreciation that get ratcheted it up? I'm just curious, it was definitely advertised as a much profitable business we see at EBITDA line, but didn't necessarily translate to net income.
So Roger Read, we're really reporting net income by this business. And it will be really hard to do given tax implications. Really -- as we highlighted at the Analyst Day, you really cannot much -- can't model a refining business on sort of an EBITDA margin. So in as much as there's a rack back business, that looks like a refining business and EBITDA margins on a percentage basis are going to move around a fair amount. The rack forward part of the business is ratable and you can think about it that way. We'd encourage you to think about it that way. But I don't think you can look at the entire business that way given it is integrated.
No. I appreciate that, I guess, I was just a little surprised at -- I said net income, I should have said just net income from operations, it's listed here. But just surprised in the end that kind of a net margin turned out to be lighter. And I was just curious again, is there -- are there some onetime items in there? As we look forward, we should expect a better margin? Or kind of this is the right baseline to go from? We don't have a lot of background with it, so it's something that we're struggling we're still to model properly.
Yes, Roger, again, as George highlighted in the rack back side in the quarter, we had some onetime issues. So really we don't expect that portion of the business to be ratably losing money going forward. And then, we gave you very specific guidance with respect to the Rack Forward part of the business going forward. We still think it's valid though.
Our next question comes from the line of Kristina Kazarian from Crédit Suisse.
When I'm thinking about capital allocation strategy, you guys mentioned a handful of things in the opening comments. Can you just remind us all of priorities between them? So whether it's M&A, which you entered in the previous question? Or share repurchases, which you talked about in the opening comments? Can you just help us frame those up priority-wise?
Yes, I think, Kristina, I tried to do that as explicitly as I could in my prepared remarks, giving specific numbers of specific capital allocations. But again, first is defending the 4 types of stuff, making sure we operate our plants -- our adjusting facilities safely and reliably. Second is keeping some cash on the balance sheet to preserve our investment grade rating in our balance sheet. Third is the dividend. And then fourth is growth. And I think as Rich mentioned in his prepared remarks, we're targeting about $0.5 billion of cash on our balance sheet, I think, to the extent that we have cash in excess of that and we don't have uses for that cash in any of these 4 categories. We just went through again. Then you should be looking for potential share repurchases.
Perfect. And then I am going to follow up with the macro one. When I'm thinking about Brent TI, can you guys talk to us a little bit about what you guys are seeing that's driving the strong inventory depletion and cushioning in the short term and then also longer term when you're thinking about things like IMO 2020? Do you think it drives the drive of a global, wider heavy light spread? But when you're kind of switching to sweeter crude, do you think you're expecting Brent WTI to kind of widen out as you see demand for Brent and other light -- lighter crudes increased? Or this is both on the short term and on the long term there?
Yes. You're going to try to take that?
Sure. Kristina, it's Tom Creery. Brent WTI differentials going forward, we sort of hang our head on that $4 to $6 range, which is based on logistics and transportation. We've probably seen some degree of decline to that in the short term here. We've seen an awful lot of exports with the United States back into Asia as well as India now. So there seems to be a great degree of interest in taking crude from the United States and other markets, but we expect this to go back to historical level, that $4 to $6. In terms of the IMO market, we think we're pretty favorably positioned here at HollyFrontier to our coking refineries, our ad hoc sales and our specialty sales through blocks. What we do see with IMO 2020 is an increasing in the heavy crude spread as well as potentially increased demand in gas oil. So we think we're pretty well set up to take advantage of that as well.
Our next question comes from the line of Phil Gresh from JPMorgan.
Rich, you had mentioned several factors that led to some usage of cash in the quarter, including the turnaround planning. Could you just elaborate a bit on how you see working capital playing out into 1Q '18 or just 2018, in general? Because when I was looking at the Analyst Day slide deck, where you had done in some of the cards, the ending cash balance there for November was quite a bit different than December.
Fair question, Phil. So December, we mentioned that -- I think I mentioned timing of interest and tax payment, which had a fall in December. So to your point, additionally, we're building inventory ahead of the Tulsa turnaround that was very year-end loaded. Realistically, we'd expect to release working capital in the first quarter and certainly in 2018, in general. So we should be seeing a tailwind on that side.
Okay, got it. So I guess, the broader question on that would be, if you only want to have $500 million of cash in the balance sheet, likely you have positive free cash flow in excess of the dividend and then you have the working capital piece. I mean, do you want to bring cash all the way back down to the $500 million level? Or do you want to still have flexibility to pursue M&A as well above and beyond that? I guess, that would be for George.
Well, I think you stated it accurately that we are going to try to keep $0.5 billion on the balance sheet and again to the extent that we don't have M&A deals, we'll try to get to that level. If we think we have a deal coming, we'll probably float cash above that $0.5 billion level.
And, Phil, there's a little bit of heart to this because we do have to manage cash around turnarounds, around capital spending, around potential transactions and all while trying to make sure we're not building cash. I think just conceptually what we wanted to highlight is we think $500 million is the right number. We certainly don't expect to be structurally building cash over that amount.
I guess, the essence of the question was do you feel like you can continue buybacks on an ongoing basis? Or is this just you're kind of more opportunistic until M&A comes along?
So, again, Phil, if we think about it, obviously, we can't forecast cracks and everything else to come with this business. So in as much as things are going well, which as we said here now, we expect 2018 to be a good year. We'd expect to be returning cash in the form of buybacks.
Our next question comes from the line of Doug Leggate from Bank of America Merrill Lynch.
Guys, I wonder if I could take you back to the heavy oil discussion. I just wonder if you've got any perspective as to how long you expect these extraordinary spreads to last? And what else you can do to maximize exposure to that in terms of swinging in your relative crude diet?
Yes, Doug, this is George. I'll try to start with that and then Tom Creery can try them and he will. But I think we see the heavy oil differentials staying wide for an extended period of time. Obviously, there's increased production in Canada. There's no imminent additional takeaway capacity from Canada. And I think even when the next pipeline gets completed out of Canada, you've got the IMO 2020 rate behind it. That will definitely impact the crude differential for heavy Canadian crudes and other heavy Canadian crudes. So we think because of again production, takeaway capacity and the IMO impact, there'll be wide crude differentials in Canada for a protracted period of time. As Tom mentioned earlier, we feel like we're in good shape for our own pipeline capacity to get those barrels out of Canada to both El Dorado and Cheyenne. And I think we've indicated in earlier calls that we're looking at coker projects, most specifically the El Dorado and we're continuing to evaluate that project.
I appreciate the answer, George. I've got 2 quick follow-ups, if I may, and they're both kind of follow-ons from some of my colleagues' questions. On the lubes' rack back, I am just wondering was the rapid increase in crude price a factor in addition to what you called out? And finally, I wonder, Rich, when you do your some of the part's consideration, what is the sustaining or sustained-through cycle level of working capital required given that that's obviously a fight through in your cash balance?
Okay. So I'll take the first one on lubes' rack back. I think the rising crude price did impact it some because our feedstock costs react quicker to crude oil than our product prices do. But it's still primarily due to the supply issue that we highlighted earlier in the call. Rich, you want to try and put...
Yes. So, Doug, on a working capital piece, typically we're either keeping about 30 to 40 days of inventory on both sides, if you will, both speed and product. I think there's going to be sides that were elevated versus that number right now. So I expect that to come down. In terms of payable versus receivables, that does move a little bit in terms of volume. Our receivable terms are shorter than our payable terms. So depending on crude rate is fluctuating, you can see movements there as well. But broadly speaking, we'd expect to be balanced on working capital through the cycle. That's definitely going to be north, quarter-to-quarter, month-to-month.
[Operator Instructions] Our next question comes from the line of Matthew Blair from Tudor, Pickering & Holt.
I was hoping you could talk about the black wax situation in the Rockies. We've seen a nice improvement in Utah crude production. Looks like you ran about 18,000 barrels a day of black wax at Woods Cross. So first part, can you keep pushing these black wax volumes higher in your Rocky segments? And then the second part, currently, we're seeing differentials about $5 to $6 off TI. In the good old days, that was more like $15 or at least double-digit levels. Do you have any hope of getting differentials back to the $10 to $15 range?
Yes, Matthew, this is Tom Creery. You're right. We're around 18,000 barrels a day of black wax. We still have probably a little bit more capability to run some more as we -- as we're bringing on Phase 1 and some of it is economic driven and also in the winter, we get some problems with specification. So we expect a pretty good summer coming up on black wax. You're right. We're always hoping for wider differentials going from that $5 on the spot prices to higher rates after realized that we've got some long-term contracts that have different pricing structures in them. So that helps mitigate some of the tightness that we see in the prices. Like any other market, that's driven by supply-demand economics. And as more supply comes on and further markets have to be accessed by black wax, we would expect to see the differential widen as a result just like we see in Canada today.
I'll just add a few points there. I think we're presently pleased with what we're hearing from the producers in the region and the technology advancements that they are making that allows them to produce more crude at even better economics. The crude production is growing, even in a $50 to $60 WTI environment. So that's a good thing to see. We do have the ability to process more wax crude at Woods Cross. We think there is healthy upside to the 18,000 you're talking about. One last note is, just remember when we were seeing the wider differentials, the WTI price was roughly $100 too. So that differential is a little bit a function of the flat price for WTI as well.
Got it. And then I was hoping you could share any comments on the Southwest gasoline market. It looks like Phoenix gasoline cracks have been really quite weak quarter-to-date, trading even below Los Angeles, which you wouldn't really expect given the LA barrels are really the marginal source of supply to that market. Any color on what's going on with Southwest gasoline?
No. I think your assessment is pretty accurate. And I think it's primarily due to nobody having a turnaround this year in the Southwest region. There've been turnarounds in Southern California, but primarily the majority of that -- the supply in the Phoenix were from a gasoline perspective comes from the east, not from the west. And again, it's just a function of everybody running well. We've highlighted our higher utilization rate at Navajo. We suspect others are seeing a similar performance from their plants. But the biggest single item is nobody had a turnaround so far this year in the Southwest, which is -- which we typically have at least one plant in that region in turnaround.
Our last question comes from the line of Corey Goldman from Jefferies.
Just one from us. Rich, it's probably for you. I appreciate the color on the effective tax rate, that's 23% to 25% in '18. Any color based on just the cash tax rate expectation in '18 and beyond? I'm assuming it's 1-for-1, but just anything you could provide there would be helpful.
Yes, Corey, roughly speaking, it should be 1-for-1.
Got you, and that's beyond '18, I assume?
Yes.
And we have no further questions in queue. I'll turn the floor back over to Craig Biery for closing remarks.
Thanks, everyone. We appreciate you taking the time to join us on today's call. If you have any follow-up questions as always, reach out to Investor Relations. Otherwise, we look forward to sharing our first quarter results with you in May.
Thank you. This does conclude today's teleconference. Please disconnect your lines at this time, and have a wonderful day.