HF Sinclair Corporation (DINO) Earnings Call Transcript & Summary

Good afternoon. My name is Josh, and I will be your conference call operator today. Welcome to the HollyFrontier Corporation Management Update Call. I would like to remind listeners at this time, please refresh your browser if you're having trouble viewing the slides. I would now like to turn the call over to Craig Biery. Please go ahead, sir.

Good afternoon, everyone. I'm Craig Biery, Director of Investor Relations. Thank you for joining us to discuss the strategic initiatives we announced this morning. A slide deck for the conference call can be found through the webcast link provided in the press release and is also in the Investor Relations, Events and Presentations section of our website. Joining us today are Mike Jennings, President and CEO; and Rich Voliva, Executive Vice President, CFO; and Tom Creery, President of Refining and Marketing and Leader of our Renewables Business. Before Mike, Tom and Rich proceed with their remarks, please note the safe harbor disclosure statement in today's press release. We will be making forward-looking statements on today's call. There are many factors that could cause results to differ from expectations, included those noted in our SEC filings. Today's statements are not guarantees of future outcomes. And please also note that any comments made on today's call speak only as of today, June 1, 2020, and may no longer be accurate at the time of any webcast replay or transcript rereading. With that, I'll turn the call over to Mike.

Great. Thank you, Craig. And good afternoon, everybody. Thanks for joining us. As Craig mentioned, you can follow the presentation through the webcast, and it is also available on our website. We will run through the highlights of the deck and take questions thereafter. Today, we announced a significant expansion of our renewables business with the planned conversion of our Cheyenne refinery from a traditional petroleum fuels refinery into a renewable diesel facility and construction of a pretreatment unit located at our Artesia refinery, where construction of our previously approved renewable diesel unit is currently underway. Investment in pretreatment is expected to enable our facilities to process a wider variety of feedstocks, allowing us to minimize single feedstock risk and maximize low carbon fuel standard, LCFS, value. Together, these projects are expected to bring our renewable diesel production capacity to over 200 million gallons per year and generate $165 million in annual free cash flow excluding the blender's tax credit. Total capital spend for the Artesia and Cheyenne renewable diesel projects and the pretreatment unit is expected to run in the $650 million to $750 million range with an expected consolidated internal rate of return of 20% to 30%. HFC expects the renewables segment to become a meaningful part of our cash flow going forward and allow more diversification from traditional fuels refining. Demand for renewable diesel as well as other low carbon fuels is growing and taking market share based on both consumer preference and support from substantial federal and state government incentive programs. This represents an exciting opportunity to advance -- enhance both the profitability and the environmental footprint of HollyFrontier through organic investments. We are advantaged by our geographic footprint and asset scale, where we can leverage existing utilities and infrastructure at locations in close proximity to emerging LCFS markets. Moving to Slide 4, Cheyenne conversion. The conversion to renewable diesel production will result in HollyFrontier ceasing petroleum refining and reducing workforce at the Cheyenne refinery. This decision was primarily based on the expectation that future free cash flow generation in Cheyenne would be challenged due to lower gross margins resulting from economic impact of the COVID-19 pandemic and compressed crude differentials resulting from dislocations in the crude market, coupled with forecast uncompetitive operating and maintenance costs and finally, the anticipated loss of the environmental protection agency's small refinery exemption. As a result, we do anticipate several onetime charges and costs. And based on the initial review of its long-lived assets over the second and third quarters of 2020, HollyFrontier expects to record noncash charges of $225 million to $275 million for impairment and depreciation charges -- and $3 million to $12 million for asset retirement obligations. Additionally, over the next 12 months, HollyFrontier anticipates pretax costs of $25 million to $45 million for decommissioning of the assets and an additional $5 million to $7 million for severance obligations alongside proceeds of $50 million to $70 million from the liquidation of working capital. After 86 years as a petroleum refinery, Cheyenne will take on a new challenge. We realized that this decision affects many employees, their families and the community, and we're thankful to all of our colleagues in Cheyenne, and we'll work closely with those impacted by this decision. Let's turn to Slide 5, renewable diesel defined. After the completion of the Artesia and Cheyenne projects, HFC expects to have the capacity to produce over 200 million gallons per year of renewable diesel and to pretreat over 80% of our feedstock demand. Renewable diesel is a clean burning fuel with over 50% lower greenhouse gas emissions than conventional diesel. It is important to note that renewable diesel is not biodiesel. Both use the same feedstock, but have different production processes and produce different fuels. Renewable diesel is chemically identical to ultra-low sulfur diesel and is therefore, compatible with existing engines. Renewable diesel has better cloud point and cold flow properties as well. And as a result, unlike biodiesel, which is typically limited to about 5% blends, renewable diesel has no blend limit. The existing diesel engine fleet can run 100% renewable diesel with no modification or risk to engine operation. Demand for renewable diesel is driven by diesel consumption and by the low carbon fuel policy. In California, CARBOB generates 80% of the LCFS obligation. Ethanol and biodiesel blend constraints limit credit generation, therefore, renewable diesel, which has no blend limit, will therefore be heavily relied on to generate credits. There are many countries and states that have either already passed or are in the process of evaluating or adopting LCFS programs. Our current plan is to sell renewable diesel into the California diesel market, but we are geographically well placed to capitalize as new LCFS programs emerge that are in close proximity to our production. While converting soybean oil and other feedstocks into ULSD earns a negative margin, we are able to make these projects economic by working within the renewable fuel standard and low carbon fuel standard mandates. The key economic drivers are the D4 RIN and LCFS credit prices. Each gallon of renewable diesel will earn a CARB diesel price plus 1.7 D4 biomass-based diesel RINs and LCFS credit value, resulting in a positive margin. On December 20, 2019, the blender's tax credit was retroactively passed back to 2018 and extended through 2022, which provides $1 per produced and sold gallon of renewable fuels. We've assumed no further extension beyond 2022 and have included only calendar 2022 benefit in our project economics. If the legislation is extended, this provides meaningful upside of over $200 million annually from 2023 and beyond. I'll now turn the call over to Tom, who's going to walk you through the 3 projects.

Thanks, Mike. So let's move to Slide 6. The Artesia RDU. As previously announced in November, HollyFrontier is in the process of constructing a greenfield renewable diesel unit at the Navajo Refinery in Artesia, New Mexico, with an estimated in-service date in the first quarter of 2022. Once completed, the unit is expected to have the capacity to produce approximately 120 million gallons per year of renewable diesel. This new venture is incremental to our existing petroleum refineries at the Navajo Refinery. The estimated capital cost is $350 million with approximately $140 million spend in 2020 and the balance in 2021. This project has an expected internal rate of return of an estimated 20% to 30% with average free cash flow of $100 million per year, excluding BTC. BTC will add an incremental $120 million to free cash flow in the year 2022. Turning to Slide 7. Cheyenne renewable diesel. HollyFrontier intends to repurpose Cheyenne's current footprint with a portion of its existing assets to produce approximately 90 million gallons per year of renewable diesel. As Mike previously mentioned, Cheyenne is advantaged by its geography and asset scale, where we can leverage existing utilities and infrastructure at locations that are in close proximity to emerging LCFS markets. Cheyenne is attractively located between Canada, whose national clean fuel program is scheduled to go into effect in 2022, and Colorado and other inland states that are currently evaluating the LCFS program. We currently plan to sell renewable diesel into the California market, but we are geographically well placed to capitalize as new LCFS markets emerge. Utilizing the existing processing units and infrastructure allows for a shorter construction time and lower capital cost than does a greenfield project. HFC expects this project to cost between $125 million and $175 million and generated an internal rate of return of 20% to 30% and provide average free cash flow of approximately $40 million per year, excluding any BTC benefit. BTC, in this case, will add an incremental $90 million to free cash flow in 2022. The estimated in-service date is the first quarter of 2022. Looking at Slide 8, the pretreatment unit. We also announced board approval for construction of a pretreatment unit at the Navajo Refinery. The pretreatment unit, or PTU is expected to provide feedstock flexibility by mitigating single feedstock risk and generate value through low carbon intensity feedstock. The pretreatment unit has the capability to cover approximately 80% of our total renewable feedstock requirements at Navajo and Cheyenne. The project is designed to treat degummed unrefined soybean oil and lower intensity, bleachable fancy tallow and distillers corn oil. The project is scheduled to come online in the first half of 2022. Estimated total costs are between $175 million and $225 million with a $25 million spend in 2020 and the balance in 2021 and '22. HFC expects the project to generate average free cash flow of approximately $25 million per year and expects base internal rate of return of 10% to 15%. However, it is important to note that pretreatment unit provides both RDUs with protection against feedstock volatility, similar to that of higher complexity at a refinery. And now I'm going to turn the call over to Rich.

Thank you, Tom. Slide 9 show -- break -- provides detail on the size and timing of capital expenditures. In 2020, we expect to maintain our total capital spending guidance of $525 million to $625 million. In refining, we now expect to spend between $202 million and $221 million. This lower range reflects further optimization of our refinery capital budgets and lower spending at the Cheyenne refinery. For renewables, we now expect capital spend in 2020 of $150 million to $180 million. This includes capital costs for the Artesia renewable diesel unit, the Cheyenne conversion and the pretreatment unit. There is no change to the $30 million to $45 million of capital spend for lubes and specialties or the $85 million to $110 million of turnaround and catalyst. Capital expenditures at Holly Energy Partners also remains unchanged at $58 million to $69 million. The second table on this slide breaks down the timing of total capital spend of $650 million to $750 million for our renewables segment over 2019 to 2022. As you can see, the bulk of this spending will occur in 2021. We are evaluating financing options to support this capital. We expect to finance our spending in a manner that maintains our investment-grade rating, and this will likely be through a combination of cash on hand and capital markets activity. Given our existing strong balance sheet and the fact that the associated capital is heavily weighted into 2021, any capital markets activity is most likely occur -- to occur in the second half of 2020. And with that, I'll turn the call back over to Mike to wrap things up.

Thank you, Rich. By expanding our presence in the renewables space, our goal is to create a company comprised of 4 scalable business segments. We are positioned for value creation across each segment and see a great opportunity to create long-term value for our shareholders. As Tom mentioned, demand for renewable diesel continues to grow, and we are positioning HollyFrontier to meet this shifting dynamic. With the announcement today, we are leveraging our existing asset base and supply network to meet this growing demand. Additionally, the expansion of our renewables business further strengthens our company's ESG profile by providing cleaner burning transportation fuels and reducing our carbon footprint. And with that, Josh, we are ready to open the floor for questions.

[Operator Instructions] Our first question comes from Brad Heffern with RBC Capital Markets.

So I guess, my main question is, what gives you guys the confidence in the economics of the renewable diesel business, the ability to execute these 3 projects at once and then also finance them in what's obviously a very difficult environment?

Well, we'll start with the economics. We'll go to execution and then financing thereafter. But the economics of the projects, as we've laid them out, we see growing demand for the renewable diesel. We think it's going to fill the key role in California LCFS program going forward. And that there will be additional states as well as likely a program in Canada, causing demand for this product to approximately double over the course of the next 10 years. It is a product that requires government programs, credits in order to be competitive. But the way we see this market, those programs are becoming more entrenched and stronger rather than less. So having been on the receiving end of the RFS program for many years, we believe that these are actually opportunities for us. And thus, part of the purpose in investing is to take advantage of that opportunity, while also, as you probably appreciate, insulating our petroleum fuels business from rising value of RIN costs. In respect of project execution, we have 3 significant projects ongoing. The Cheyenne project is the one that's -- it's really more of a conversion using existing assets, taking existing distillate hydrotreater and naphtha hydrotreater units and existing hydrogen capacity and converting that into alternative service. So we consider that to be more like a turnaround than it is like a new unit build. The Artesia project is well underway in terms of its engineering and long-lead procurement, and we have high confidence in our ability to make that project work. The pretreatment unit project, similarly, is based on existing technology, working with existing vendors and engineering firms. So we have high confidence in both that project and its price and time line as well. Rich, in terms of financing, if you can take that?

Sure. Brad, so like, we're coming into this next 18- to 24-month period of spend from a position of real strength. We've got over $2 billion of liquidity, very low leverage. I think we're the only refinery who has not needed to raise capital so far this year, and we do not expect to raise capital for any form of short-term liability or working capital management. As we mentioned, we expect to maintain our investment-grade rating. And any financing we do will be with that in mind. We're comfortable that the capital markets are open and will remain open. Then look, with the commitments that we've made in renewables and our maintenance schedule for 2021, this is really going to come home in 2021, and we're also confident that the economy will recover, and there'll be some cash flow from operations. So we feel comfortable with the financing here.

Okay. And then, maybe, for Rich as well, just on Cheyenne, is there any color you can give us on historical margins and OpEx that would help us, sort of, model that region without Cheyenne in it?

Well, so Brad, we'll be revisiting how we're reporting internally. What I can tell you is that Cheyenne has struggled historically on the free cash flow line and our expectation is it would be free cash flow negative for the next several years.

Your next question comes from Theresa Chen with Barclays.

I wanted to ask about the macro strategy at this point. The reasons you've cited to take the plunge in the conversion and -- I mean, the 3 projects in general, things getting greener, the government mandates becoming more entrenched, not less and the macro headwinds on the legacy petroleum refining side, be it COVID or long-term demand destruction or narrow inland diff. How do you view the rest of your business in this light, the facilities are not up for conversion? Do you think that this will be a trend potentially? Are you evaluating this outcome for your other facilities? And within that framework, can you help us think about your assumptions that you previously laid out for the mid-cycle refining EBITDA? How do you view cracks in diff at this point?

Yes, Theresa, I'll take a poke at that. The traditional fuels business is one that we have a lot of confidence in going forward. We do foresee more flat demand. But each of our refineries, of the 4 refineries that will continue in petroleum processing have sort of special differentiation around them. In terms of the types of crude that they can process or obviously, in the case of Tulsa, the ability to make lubricants products. So I think we have some nice diversification and differentiation within these inland assets that we operate. In terms of additional conversion, I don't think we have additional conversion on the list. We may, at some point, make additional investment in co-located renewable diesel production capacity. But converting further refineries isn't on the table for us right now. And looking forward, I think [Technical Difficulty] is really one of how comfortable are we around our existing asset portfolio? And the answer is we like where we are. We have a great fuels business and fairly unique in terms of the particular refineries and their characteristics. We have a growing lubricants business, and now this renewable diesel segment, which we have a lot of confidence in looking forward.

Got it. And how does this affect cash flows at the MLP, given that it owns assets that has historically supported the petroleum refining aspect of Cheyenne?

Theresa, it's Rich. So let me break this into 2 pieces for you. Inside the gate, if you will, HEP owns the tanks and the product rack at Cheyenne. These are under contract through 2026 on minimum volume commitments that represent about $17.5 million a year of revenue to HEP and for context, right, HEP's revenue in 2019 was $533 million. So call it, 4% or 5%. HFC and HEP, we believe, are aligned and we'll work together on the best path forward to maximize the value of those assets. They're not going to go to 0 at all. But it's way too early in this process to know what exactly that's going to look like, and it's -- as you can appreciate, we have not had the ability to work on this to date. It's something we will focus on a lot the next few months. Outside the gate, the primary asset to speak about is the Cheyenne pipeline. HollyFrontier does have a minimum volume committed to that joint venture. We expect that commitment to stay in place, and we believe we're going to have use for that pipe space going forward. Order of magnitude, that's much smaller to HEP and the $17.5 million of inside-the-gate assets.

Your next question comes from Phil Gresh with JPMorgan.

First one, I just want to make sure I understood. The commentary around Cheyenne, talking about the COVID impacts and tighter differentials moving forward. Could you just elaborate on your view on the differentials? Were you talking about more of the local crudes? Or were you talking about WCS, which I think you sourced there? And just trying to understand what that commentary meant at a higher level, more macro level?

Yes, Phil, I think effectively, what we're talking about is 2 things. But both flat price related, okay? The WTI price following the COVID slowdown or shutdown and oversupply by OPEC-Plus, frankly, has put differentials into a lower zone for the time being. And the correlated price differential of WCS versus flat price WTI might be 30% through time. And that -- a differential at that level produces considerably different and lesser economics for the Cheyenne plant. Similarly, as it pertains to Rocky Mountain barrels at $30, $35 flat crude price doesn't prompt the kind of new drilling and production that tends to generate wide dips locally. So really that's the commentary around crude differentials.

Okay. Okay. Got it. Second question, I guess, just a follow-up for Rich. I mean, if the environment stays tougher for longer in terms of how you're thinking about financing options, I guess, help us think through or remember what the rating agencies care most about? Is it [indiscernible] leverage or consolidated leverage? Is it certain metrics that we should be thinking about? And how that might influence what your financing solution would be?

Sure. Thanks, Phil. I think the -- probably the easiest way to give you a 1-point answer would be think of this as consolidated leverage of sustained at 3x or greater is where we start to run into trouble. And we're underneath that today, and we expect to be able to -- if things stay bad, to your point, we'd expect to be able to recover from that pretty quickly. So that's really the line. We've got plenty of room on that line right now, and that's why we feel very comfortable with where we're at from a financing and rating perspective.

Okay. Okay. So at this point, you would -- to the extent you needed to look at financing, you'd be looking more at the debt capital markets.

I believe so, yes. And the one thing I'll flag for you, Phil, is obviously, again, thinking about consolidated leverage, HEP is on a course now to start to delever, which does have a benefit to HFC in this -- from this perspective.

Right. Okay. Last quick one. In the free cash flow numbers that you were providing for each of the projects, is there a certain amount of ongoing CapEx beyond the project spending that we should be thinking about that's embedded in that?

Yes, Phil, there is -- it looks -- it's not quite pipeline level maintenance CapEx, but it's -- what I'd say is it's less than what a refinery looks like. So there is "turnaround activity." But it's not really of the magnitude either in certain time or dollars that you would think of from a kind of a refinery turnaround perspective.

Your next question comes from Manav Gupta with Crédit Suisse.

Rich, could you clarify if the return of 20% to 30%, is it EBITDA? Or is it EBIT?

Those are internal rates of return, Manav.

After-tax cash flow.

Yes. Unlevered.

Okay. So essentially, to get to that rate of return, you'll need an after-tax cash flow of about $180 million to $200 million a year going ahead, if that number is right? And so I'm just trying to understand what's the gross margin assumption here, given you'll need to have a rate of -- the margin will have to be close to $0.90 after taxes. So I'm just trying to understand what's the gross margin embedded in the calculation of trying to get to that about 25%, 30% rate of return?

So Manav, I can give you a couple of high points here. I think Mike spoke about the margin between diesel and soy. So usually, you're net negative at that point. Obviously, getting 1.7x the D4 RIN value, which in today's market will be approaching $1 on its own. And then you're going to get the LCFS value, which we assume and believe quite strongly is going to continue to be fairly strong. So you can -- your numbers where you're getting, I think, sound a little high to be honest, but directionally correct. And yes, we feel very comfortable with those gross margins.

The -- and the second question as I see the chart at the back where you're projecting a capacity, there's some capacity growth, and there's some demand growth. I mean we are looking at multiple project expansions within United States, one of your competitors is going from 275 million to 1.1 billion. Like would this all be -- can the market absorb all this increased capacity that is coming online between now and 2024?

Yes. Manav, we believe so and I think that chart speaks exactly to that. This reflects -- and this is on Slide 12 on the deck, reflects all the announced capacity. To be honest, I don't think we believe all that capacity will actually make it at the end of the day. But even with these numbers, right, you can see that the market's got plenty of demand coming by 2022, 2025 range.

Another way to look -- Manav, it's Tom, another way to look at it, if all these projects come on stream and run at 100%, that will basically fill the California market, and there won't be anything left over for anyone else at that point in time. That's what gives us comfort.

Your next question comes from Neil Mehta with Goldman Sachs.

The question I had was around -- first question was around capital spending, especially for 2021, thanks for breaking out the CapEx associated with the project, but how do you think about early thoughts on consolidated CapEx for HollyFrontier? The big swing, of course, is kind of what happens to the rest of your base as you layer in the renewable investment?

Neil, it's Rich. So I think realistically, outside of renewables and our maintenance capital in '21, we're going to have fairly minimal levels across the rest of the business. To be fair, we do have a heavy turnaround schedule on for this year, and we're not even really early in the budget process. We're aware it's out there. But it's a bigger number. So if you think about our cash waterfall where we talk about kind of $350 million of mid-cycle sustaining and maintenance capital, it's definitely going to be north of that in 2021. I just can't tell you how much.

So that sustaining CapEx at the higher end to above that range, plus layer in the $450 million to $500 million for renewables, and you add those 2 up, and that's a good proxy for 2021 CapEx? Or is there anything else that we're missing there?

Those are the 2 big blocks. There'll probably be some capital spending at lubes and HEP. Typically, HEP spends $30 million to $50 million a year. And, obviously, it has its own balance sheet, source of funding. Lubes is that same order of magnitude, but you're on the right path.

All right. And the second is specific to the renewables business. How do you think about LCFS scoring for these 2 projects? And can you talk about what feedstock you intend to use and how you think about the relative economics? There's been a lot written about soybean economics being more challenged, for example, versus some of the other animal fats that are being used in these projects?

Yes. I'll start with the feedstocks, Neil, it's Tom. We are looking at soybean oil. And just let me say that off the top, there's no shortage of soybeans in this country. We crushed less than 50% and the exports, the balance. And the -- what we crush, 80% goes back into meal and not into the oil market. So the oil is a relatively small part. So it's either driven by the food industry or the protein industry or the export. So a lot of it is on the crush side. And from what we know at this point in time, the crush increase is going to be about 3.5 billion tons of additional soybean oil as we go forward. So we're fairly comfortable in getting to that point. And when you start looking at our volumes of RBD, that's exactly why we invested and are proceeding with the PTU so that we can buy more readily available degum soy as opposed to the RDB -- RBD and gives us that much flexibility. The other feedstocks distillers corn oil I'm sure you know that, that comes from the ethanol industry. So as it goes, the ethanol production will dictate the distiller corn oil. Tallow comes from cows. It depends on how many people are going to eat beef as we go forward. And what happens as the COVID-19 impact, which is having some impact on processing plants, but we don't expect that to continue into the future. And the wildcard in all this is, we feel pretty confident at this point in time that canola is going to achieve a pathway for renewable diesel. We probably expect this to happen in the next 12 months. And if that happens, that's going to add another 4 billion pounds onto the supply in 2025. So when you add all these up, the ability to acquire feedstock and our ability to buy all these different feedstocks and process it through our PTU is going to make us feel very comfortable on feedstock economics. We're going to have to, as everyone else does, you buy feedstocks, basis on their price and their carbon index. The distiller corn oil and fancy tallow have a lower carbon index, that means you generate more credits than you do to soybean, but it all comes down to economics. So that flexibility gives you the ability to maximize your margins and maximize economics.

Your next question comes from Paul Cheng with Scotiabank.

The first question, I think, is for Rich and Tom. Tom, can you tell us maybe [indiscernible] what's the conversion ratio between your different feedstock into a gallon of renewable? That how much is the feedstock that you need in each one? And for which, when we're talking about the free cash flow, whether it's $100 million or $40 million or $25 million, what's the underlying assumption that you use for the low carbon credit, the D4 RIN and also your OpEx per gallon. And also that why the Cheyenne and Navajo on a free cash flow per gallon are so much different, nearly double in the case of Navajo versus Cheyenne? So that's the first question. The second question that -- seems that you are processing about 10,000 to 20,000 or 25,000 barrels per day of WCS in Cheyenne, and you currently have allocation for about 80,000 barrel a day. So how that change your future WCS purchase? And whether [indiscernible] going to be able to increase the run to absorb it? Or you're just -- you're going to maintain it, you're just going to sell it to the market. And also that when we're talking about the pretreat, I'm not sure I understand how exactly that shield you from the feedstock for the pretreat? Maybe you can elaborate it better for me?

Okay. Let's start first. So Paul, you were asking about the yields on the different feedstocks, and roughly, they're fairly similar, and they're well north of like 95%. We also get a little bit of renewable naphtha and renewable propane depending on the feedstock, and that will be sold into the market or utilized internally. For example, the propane will either go back into fuel gas or hydrogen production. So the yields stay fairly constant. In terms of the LCFS. We...

Tom, can you tell me that how many pounds of soybean in order for you to get 1 gallon of renewable and so on and so forth for the other feedstock also?

Okay. Roughly, I'll do it this way. For example, at Artesia, Paul, we're going to process 1 billion pounds of feedstock to make 120 million gallons per year of renewable diesel and 7 million gallons per year of renewable naphtha. Does that help?

And it's pretty constant you're saying regardless which feedstock that you use? It's been constant.

It's pretty close, yes. So hopefully, that helps you on that conversion.

Paul, let me give you a try on the couple of the others then. LCFS credits, we're expecting to remain in the range they've been in the last few years. You asked about -- yes, cash -- on LCFS, basically, when we were modeling it, we took the latest information on LCFS prices and then just increased it by consumer price index, CPI, very, very conservative.

So you're using the basis, like $1.50, $1.75?

On LCFS, it's like $200.

$200 per ton?

Okay. Right.

Because I thought the low sulfur credit is like $1.75 per gallon or something like that.

Right. If you're converting dollars per ton into dollars per gallon, that's kind of where the math works out to.

Right. So you are $200 per ton, right?

Correct.

On D4 RINS, Paul, that number's in the range we've seen in the last few years, call it, $0.40 to $0.70. To your overarching question on Cheyenne versus Artesia on unit free cash flow. The way I think about it at least is CapEx per unit is lower at Cheyenne because this is a conversion of existing assets versus Artesia, where we are building some greenfield assets. On the flip side then, the operating expense per unit Cheyenne is going to be a little bit higher because the renewable diesel unit doesn't have anyone to share utility costs with, and that flows through on OpEx per unit.

So that mainly is because of the utility cost, but...

Primarily.

Because the technology will be the same, right?

Correct. There is some difference in metallurgy, so they're not perfectly the same. But...

How about the transportation costs?

The transportation cost from Artesia to California and Cheyenne to California are very similar.

And I assume that the feedstock transportation cost are also similar?

Pretty close, yes.

Okay. And then Tom, can you help me understand how the pretreat is going to help you to shield the volatility in the feedstock costs?

Sure. Well, the pretreatment, what it does is it allows us to buy degum soybean as opposed to RBD. So when you look at the market today, there is a spread between degummed and RBD, and it's -- roughly it trades between $0.045 and $0.06 a gallon. And we what we've done is we've assumed economics in the PTU that we would be able to buy degummed and do that upgrade to RBD ourselves. And that's where we generate the IRR. As compared to what we think the market is going to be for RBD going forward in the future. So that's the shield that it provides us.

I see. And that -- can you talk about WCS?

Our plans for...

Sure our plans for WCS at El Dorado remain unchanged at this point in time. We are going to consistently process that amount on a go-forward basis. And we still believe that that's the right choice given the fact that we are able to compete with a Gulf Coast refiner because we pay less transportation. They have to go further in the pipes for WCS. And subsequently, if they move product back into the group, they have to pay a tariff to get those products from the Gulf Coast. So we think that we will be able to collect that premium by processing WCS. And that's also assuming that we're not in the current situation that we're going to revert back to typical transportation-based economics on differentials at Hardisty in the Gulf Coast.

And will you still buying about 80,000 barrels a day based on your historical allocation? Or that you will scale down the purchase?

We will scale down our purchase because without -- that 80,000 barrels a day -- the 80,000 to 100,000 included the demand at Cheyenne. So...

Your next question comes from Roger Read with Wells Fargo.

Yes. I guess I'd like to ask as you thought about making this turn towards, well, I guess I shouldn't say towards it, you already were at Artesia, but expanding in biodiesel, how did you think about it as you compare what happened in ethanol, which obviously had a government mandate aspect behind it? This one obviously does too. But then ethanol, we see a struggle for profitability on a consistent basis, maybe in line with some of the other questions, how do you get comfortable that you'll continue to see the profitability in renewable diesel that we haven't seen in some of the other renewable fuels?

All right. Roger, this is Mike. First off, this is a superior fuel. It's a drop-in fuel, meaning that the existing diesel fleet can burn the stuff without modification. And without concession in terms of the underlying infrastructure to distribute it. And that's really one of the great challenges with ethanol is just the corrosive nature of it on elastomers and such like that. So getting to higher blends has proven to be very difficult for the ethanol industry, whereas I think this renewable diesel product has a long way to go. Ultimately, we're all competing for effectively the low carbon fuel credit market. And that's what brings the negative gross margin to positive. We believe that this product made from the most competitive feedstocks is the best way to do that. It also happens to be a product that works well in hydrotreating technology and as co-located with petroleum refineries, and it's a process that we know well. So it fits us better. It's strategically a better fuel in terms of being the source of a low carbon fuel credit or otherwise providing a lower carbon footprint per BTU. And the market is well supported by not just the state of California, but obviously, Oregon, British Columbia, prospectively, Canada as a country. So we think there's a lot of running room here.

Yes, I understand that. I guess, just the cost structure overall. Do you think there's a way over time, maybe it's through scale, maybe it's through technology, where the cost to make the renewable diesel comes down. Is that anywhere in your expectations? Or should we think of it as -- I mean, it really is a major component between LCFS as an example, but let's just call it, broadly speaking, a government mandate to expand the use of renewable diesel or biodiesel in general?

Yes. So the renewable diesel and biodiesel are 2 different products. But I do think that it's government mandate based and consumer preference based, quite frankly. And then around the world, Europe, in particular, you're seeing greater adoption of this. So while a more expensive product on its face, I do think that has a significant place in the fuel slate going forward.

Okay. Just 1 final question for me. As you step back and look across what'll be the, I guess, we'll call it the third leg of the business, right? Investment in lubes, investment in refining as they compete at this point. CapEx has obviously spoken for the next 2 years. But as we think about longer term, the attractiveness of refining and the lubes business relative to renewable diesel kind of equal, you see renewable and lubes is clearly ahead of refining? I mean I'm thinking if you're willing to shut Wyoming, that's likely the case. But just curious how you're kind of viewing that at this point?

Well, we've called out that we see the renewable diesel market doubling over 10 years. We don't see conventional fuels market in North America doubling over 10 years. In fact, our view is that it's more flat. And that's premised on efficiency and the typical things that we see adoption of other technologies for transportation fuels. So a much more substantial growth profile. Our refining strategy is one of trying to find niche opportunities that have strong product markets and good crude economics supporting them. So that's not changing. I wouldn't tell you there's a wealth of those assets available for our own growth. And in terms of volumetric expansion, that's going to have to follow the market. We're not going to invest in advance of market demand in our conventional fuels business. That leaves lubes and we've put a decent amount of money into lubes. We feel like we have a good platform there. It's, at its present state, a real opportunity in terms of integrating the various pieces and getting the production economics in terms of our base oils and blend stocks into a better place. So there's a lot of opportunity within that portfolio. And probably in terms of growth, it would be toward distribution of finished lubes that would be most prospective for us.

Your next question comes from Doug Leggate with Bank of America.

Just a quick -- couple of quick ones from me. If I look back to your EBITDA guidance, $1 billion to $1.2 billion. Just to try and summarize everything you've said today, Cheyenne commanded incremental renewable business going in, what is that mid-cycle EBITDA? What's that new range, if you like, on a mid-cycle basis once the projects are complete?

Doug, this is Rich. There's not going to be a material change there to refining EBITDA at all.

Okay. So that kind of answers the question. Cheyenne wasn't a big contributor. That's great. My follow-up question is really about the stand-alone on -- you did mention earlier how you're going to look at how you adjust the Rockies region reporting. I'm curious, it's probably not something you want to get too in the detail in, but when you take out over 50,000 barrels a day, what happens to the regional margin in your mind? Do you think -- is that included in that no change to refining EBITDA? Or would you expect an uplift in regional margins as a consequence?

So Doug, let me give it a try, and Tom will probably want to chime in. Yes. Look, I think if you're on the East side of the Rockies, this is a positive for regional margins. We expect to be able to capture some of that through our access to the Rockies out of the group refineries. We can get there from both El Dorado and Tulsa. So we do expect -- to your point, if you take supply out versus demand, you'd expect price, if you will, or in this case, margin to rise, but we expect to participate in that.

And Doug, as you well know, there's other pipelines that feeds the Denver market per se from Texas, whether it's McKee or Borger, and there's also the Montana refinery production that comes down that goes into that market. So they will get realigned accordance to margins. So the margins may go up, but it's not that the market is going to be short supplied. The markets are very efficient, and there's more than enough supply capacity to fulfill that market as it moves forward and grows. And Rich alluded to the Magellan chase line that's got lots of -- it's got -- it's a big volume pipeline that delivers both jet and transportation fuels into that Denver market.

And just one last one, and I promise you it's a simple one. So if I look at the mid-cycle free cash flow, you've been very careful to avoid, including any blender's tax credit. So it looks to be about $165 million a year of free cash. I assume you've done some scenario planning here. If you look to where blender's tax credits have traded, let's say, on an average basis over the last 2 or 3 years, what would that $165 million look like?

Yes, we called that out. So if the blender's tax credit is a direct -- it doesn't trade. It's a dollar per gallon. And the question about blender's tax credit is whether it is continually extended by Congress. The annual increment to cash flow is nearly $200 million. So it's a meaningful number. And it is physically attracted to each gallon we produce. The question again is whether Congress extends this past 2022.

Yes, so it's not that the economics look pretty compelling without it. But I guess what I'm really trying to get to is when you think about the scenarios as to why and whether that would continue when you were making this investment decision, what's your -- how are you framing the sort of worst case and best case as to how long you think that thing gets -- how long it stays in place? I know it's a nefarious question, but I'm really just trying to understand that as clearly as...

It's a pretty easy -- it's a pretty easy one. We assumed the minimum. So this is statutorily in place through 2022. That's always assumed in our economics.

So the political driver for this is to try to keep the conventional biodiesel market, which is an esterification process. It's a little different than the renewable diesel. But these conventional biodiesel manufacturers tend to be under water without the blender's tax credit in terms of their production economics. So the political push for the BTC is typically from that group trying to stay viable. And insofar as they're successful, we get the knock-on benefit of additional tax credit.

It's an option. I get it completely.

Your next question comes from Matthew Blair with Tudor, Pickering & Holt.

I was curious if you looked at selling Cheyenne as a refinery? And if so, could you talk about the appeal of that option versus what you ultimately chose to do to shut the refinery and invest in turning it into a renewable diesel plant?

Yes. So the short answer to your question is, we have done that work. And we're not going to share the results other than to say we believe this is the highest value alternative for HollyFrontier shareholders and for the longevity of the site.

Sounds good. And then you highlighted the $50 million to $70 million of working capital release as you decommission Cheyenne. Do we need to be thinking about any sort of a working capital build as you grow and expand your renewable diesel business?

Yes. Matthew, we built that into our models. Typically, what we're doing is running a 21-day inventory on both finished and feedstock. Whether that's in a railcar or in a tank or a silo at the location itself. So we've built those working capital assumptions into the model. And we also assumed, at least at this point that we'd be buying the feedstock on a delivered basis and selling the renewable diesel on -- at location. So we wouldn't be incurring any working capital coming in or leaving the plant itself.

Okay. So that 20% to 30% includes a working capital assumption, the 20% to 30% IRR?

Yes. It does.

Your next question comes from Chris Sighinolfi with Jefferies.

A lot has been asked and answered, and I appreciate all the color. Just have a couple of cleanups, Rich. It looks like about $25 million of capital avoidance at Cheyenne and as you guys were just discussing $50 million to $70 million of working capital liquidation proceeds. I'm just curious, are there assets within Cheyenne that could be repurposed to some of your other refineries as they go through maintenance activities in subsequent periods that could lead to some savings of any notable regard?

Yes, Chris, it's a good question. I think we'll begin that work now is the answer. I don't know the answer, sure, top of my head, but certainly, we're going to look to maximize the value of everything on the ground there.

Okay. And Phil had asked a question earlier about what you were assuming CapEx wise and the free cash flow numbers. I'm just curious, is the cadence of these renewable facilities, do you involve the type of turnarounds that you wouldn't -- you would be facing at a traditional petroleum refinery? Are they different in any meaningful way? Can you just talk about that?

Yes. Typically, it's catalyst -- it's pulling catalyst out of the units and replacing that, and that's on its own cycle, just like it is at a refinery. So we've built that into the model as well. It's every 6 years, I believe, that we're going to do a catalyst change-out. And that's the industry norm and what we've learned to be, what's to be expected.

And Chris, at a high level, just think about it, there are in a renewable diesel unit, you're basically talking about a hydrotreater, you need a hydrogen plant. You're talking about turning around a handful of processing units as opposed to a refinery where you're talking about dozens and dozens. So the complexity and by extension, the downtime is much less.

I figured that. I figured it. Confirm it while I had you guys. And then the 6-year cycle is helpful for modeling purposes. And I guess final question from me. You talked about the pretreatment unit at Navajo. I'm just curious, how does the pretreatment volume get to Cheyenne? And is that part of the pipeline -- sorry, the rail and storage infrastructure that you quote in the capital number?

The short answer is yes, it will be railed. We'll take it to the pretreatment unit, pretreat it there and then put it on a railcar and then take it to Cheyenne. So -- and those incremental transportation costs have also been built into our costing COGS numbers as well.

And does any of that infrastructure spend qualify for involvement at the HEP level? If you were to decide to do that at some point when the balance sheet there is delevered?

Yes. So Chris, the short answer, obviously, in theory, yes. It's probably worth pointing out, renewables, in general, do not -- are not qualifying income under the IRS regulations. So you're quickly into the game of if you want to bring your -- an MLP into this of what your nonqualifying income tolerance and levels are and everything else. So it's not an immediate growth avenue for HEP on the surface.

Your next question comes from Jason Gabelman with Cowen.

I wanted to go back to the free cash flow assumptions, specifically the LCFS portion of it. Is that just assuming soybean oil based on the California standard? Or are you assuming some uptick from using some different feedstocks that maybe generate higher credits in LCFS? And are you assuming any of these other programs get implemented that may have more attractive credit profiles than the California standard?

Jason. So yes, short answer is, yes. The math that you're seeing here is based on using soybean oil and selling the product into California seizing California LCFS. I think our belief is that demand will grow over time to other geographies. But as Tom mentioned earlier, the reality is that everything that's been announced can get built, and that would only satisfy California's demand. So a lot of running room on the demand side.

Beyond that, we believe we have some upside in terms of the carbon intensity, carbon index pathways for different feedstock sources and the pretreatment capacity to run those and metallurgy as well, particularly in Artesia. But for the time being, we're using soybean as proxy for project economics.

Are these other LCFS programs from other states, are they similar to what California currently has in place? Or would they be an uplift to economics if they get implemented?

They are to a large extent, CARB has done a very good job in selling their model across the United States, especially in the New England states. But we expect that to be -- form the formation of anything within the United States as well as Canada, they're sort of using that as the stake in there, the pole in the sand or the benchmark to which they come up with their own policies.

Market-wise -- I was going to say market-wise, you're going to need to pull a barrel from the California market to put it somewhere else. And so the most likely outcome is that the other states adopt a very similar standard in terms of setting these credit prices and carbon intensities and thus, the economics.

Understood. And then if I could just ask about maybe just on pulling in other parties into the projects. Was there any acceleration of pulling in either companies that could supply with advantaged feedstocks to reduce maybe the capital outlay that you'd have to put into the project in terms of bringing in an equity partner or maybe bringing in another group that's looking to implement one of these renewable diesel projects, just given the amount of growth that the industry is going to see over the next few years?

Yes. We feel like we're probably a fairly attractive strategic partner. To date, we are developing these projects internally and having conversations with others, which start out typically as vendor purchaser-type conversations through time, we'll see where it goes. If there's value to us and our shareholders and our projects and growth in this business, then absolutely, for the time being, though, it's more of a procurement discussion.

There are no further questions at this time. I'll turn the call back to Craig for closing remarks.

Thank you, everyone. We appreciate you taking the time to join us on today's call. If you have any follow-up questions, as always, please reach out to investor relations.

This does conclude today's teleconference. Please disconnect your lines at this time, and have a great day.