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Welcome to HollyFrontier Corporation's Third Quarter 2020 Conference Call and Webcast. Hosting the call today from HollyFrontier is Mike Jennings, President and Chief Executive Officer. He is joined by Rich Voliva, Executive Vice President and Chief Financial Officer; Tim Go, Executive Vice President and Chief Operating Officer; Tom Creery, President, Refining and Marketing; and Bruce Lerner, President, HollyFrontier Lubricants and Specialties. [Operator Instructions] Please note that this conference is being recorded. It is now my pleasure to turn the floor over to Craig Biery, Vice President, Investor Relations. Craig, you may begin.
Thank you, Rob. Good morning, everyone, and welcome to HollyFrontier Corporation's Third Quarter 2020 Earnings Call. This morning, we issued a press release announcing results for the quarter ending September 30, 2020. If you would like a copy of the press release, you may find one on our website, 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. The call also may include discussion of non-GAAP measures. Please see the press release for reconciliations to GAAP financial measures. Also, please note any time-sensitive information provided on today's call 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 Mike Jennings.
Thank you, Craig. Good morning, everyone. We're pleased to report solid third quarter results in the face of the economic down cycle caused by the COVID-19 pandemic. We remain focused on the health and safety of our employees, and I'm pleased to report we've had both safe and reliable operations across our 3 operating businesses during the third quarter. As we work through this last quarter of 2020, I remain confident in both the long-term market for our products and the ability of our talented employees.
Turning to our third quarter results. We reported a net loss attributable to HollyFrontier shareholders of $2 million or $0.01 per diluted share. These results reflect special items that collectively increased net income by $65 million. Excluding these items, the net loss for the third quarter was $67 million or negative $0.41 per diluted share versus adjusted net income of $278 million or $1.68 per diluted share for the same period in 2019. Adjusted EBITDA for the period was $66 million, a decrease of $457 million compared to the third quarter of 2019. The refining segment reported adjusted EBITDA of negative $54 million compared to $425 million for the third quarter of 2019. And consolidated refinery gross margin was $4.93 per produced barrel, a 71% decrease compared to the prior period. This decrease was primarily due to continued weak demand for gasoline and distillates, coupled with compressed crude differentials. Third quarter crude throughput was approximately 391,000 barrels per day, above our guidance of 340,000 to 370,000. Our plants operated well, and we saw somewhat better product demand than expected in our markets, particularly in the Southwest and Rockies. In August, we ran the last barrel of crude oil at Cheyenne, and we began the conversion to renewable diesel.
Our Lubricants and Specialty Products business reported EBITDA of $61 million compared to $38 million in the third quarter of 2019. Rack Forward EBITDA was $79 million, representing a 19% EBITDA margin. The Rack Forward segment saw improvement in industrial and transportation-related end markets, which drove higher demand and unit margins during the third quarter of 2020. Sales volumes improved 24% compared to the second quarter and were down 7% versus the prior year. Within the Rack Back portion, demand for base oils increased to fourth quarter 2019 levels, while supply was limited due to a number of factors, including plant closures, reduced run rates at base oil plants co-located with fuels refineries and hurricane impacts on U.S. Gulf Coast. This combination of factors drove higher margins and utilization at our facilities during the third quarter. In terms of maintenance, we successfully completed the planned turnaround on our white oils unit at Mississauga that began in late September, and we're back to running at full rates.
Holly Energy Partners reported EBITDA of $55 million for the third quarter compared to $123 million in the third quarter of last year. Reported EBITDA for the third quarter of 2020 included a $36 million goodwill impairment charge and reported EBITDA for the third quarter of 2019 included a $35 million gain on sales-type leases, both of which eliminated in the consolidated company's financial results.
At HEP, we have continued to see incremental improvement in demand for transportation and terminaling services during the third quarter of 2020, particularly in the assets around the Salt Lake area, and we expect this trend to continue through the fourth quarter of this year. Although the current refining outlook remains challenged, we are encouraged by the resilient financial performance from our lubricants and our midstream businesses in the third quarter. We're making progress on all 3 of our renewable projects, which currently remain on time and on budget. We're confident that demand for transportation fuels will return and will be well positioned for the next up cycle.
And with that, let me turn the call to Rich.
Thank you, Mike. As previously mentioned, the third quarter included a few unusual items. Pretax earnings were positively impacted by a $77 million gain recognized upon the settlement of the company's business interruption claim related to a loss at the Woods Cross refinery, which occurred in 2018, along with a lower of cost or market inventory gain of $63 million. These items were partially offset by charges related to the Cheyenne refinery conversion to renewable diesel production, including LIFO inventory liquidation costs of $34 million, decommissioning charges of $12 million and severance charges totaling $2 million. A table of these items can be found in our press release.
Cash flow from operations was $82 million in the third quarter, which included $25 million of turnaround spending and $53 million of working capital gains. HollyFrontier's stand-alone capital expenditures totaled $75 million for the quarter.
In September, we reinforced our robust liquidity position through a successful $750 million bond offering. The offering consisted of 2 tranches of senior unsecured notes, a $350 million 3-year bond with a coupon of 2 5/8% and a $400 million 10-year bond with a coupon of 4.5%. This opportunistic financing provides HollyFrontier with enhanced liquidity and ensures the necessary capital to fully fund the previously announced renewable diesel units located in Artesia and Cheyenne as well as the pretreatment unit in Artesia.
As of September 30, our total liquidity stood at approximately $2.9 billion, comprised of a stand-alone cash balance of $1.5 billion, along with our undrawn $1.35 billion unsecured credit facility. As of September 30, we have $1.75 billion of stand-alone debt outstanding with a debt-to-cap ratio of 25% and net debt-to-cap ratio of 3%.
During the third quarter, we declared and paid a dividend of $0.35 per share, totaling $57 million. We did not repurchase any shares in the third quarter and do not intend to repurchase equity until demand for our products normalize and visibility improves. HEP distributions received by HFC during the third quarter totaled $18 million. HollyFrontier owns 59.6 million HEP limited partner units, representing 57% of HEP's LP units at a market value of approximately $650 million as the blast lines close.
We have reduced the range of our full year 2020 consolidated capital budget to $475 million to $550 million from $525 million to $625 million. For the full year of 2020, we now expect to spend between $187 million and $212 million of capital at HollyFrontier Refining, $130 million to $145 million in renewables, $30 million to $35 million in lubes and specialties, and $85 million to $100 million for turnaround and catalyst.
At HEP, our capital budget has reduced to a range of $43 million to $58 million from $58 million to $69 million. For the fourth quarter of 2020, we expect to run between 360,000 and 380,000 barrels per day of crude oil, and we expect to adjust refinery production levels commensurate with market demand and economic drivers.
Looking to next year, we are currently finalizing our future operating and capital budget and plan to release guidance later in the fourth quarter. And with that, we're ready to take questions.
[Operator Instructions] Our first question is coming from Paul Cheng.
Scotiabank. Two questions. On the cost reduction side, I mean everyone is trying to rightsize it. My -- if we're looking at your unit cost in the refining, they still seems high. Is there any opportunity what we can do over there to further reduce your unit cost?
Secondly, that lubricant has been very strong in the third quarter report by everyone basically. And can you discuss what does the trend line look like? Do -- have we seen that strong margin and also that improved demand extend into the fourth quarter?
Yes. Paul, this is Tim Go. I'll take the first question on refining OpEx. As you know, last quarter, we announced some strategic decisions to take cost out of our refining business that consisted of converting the Cheyenne refinery from refining into the renewable diesel plant, which significantly will reduce our OpEx load as well as CapEx and turnaround burdens, especially looking into 2021. The other thing we announced was a restructuring, particularly around our SG&A costs. And as you recall, that was $30 million, $20 million of which will show up in SG&A, $10 million will show up in OpEx. We believe both of those steps are not only going to help us here in 2020 but will carry over into 2021 and continue to reduce our overall refinery costs.
The other thing you'll notice, though, is we are driving structural reductions in our refining costs. If you compare year-over-year, refining is down $20 million in the third quarter, roughly 8% versus what we were at last year. And year-to-date, it's about $40 million or 5% year-over-year. We again believe that those reductions will be able to be carried over into 2021, and we're continuing to drive further reductions there.
But look, I'll just be honest with you, Paul. I came to HollyFrontier to drive operations excellence. That involves EHS performance, it involves reliability improvements and it involves operating efficiencies and operating costs. And so we are looking at what we consider to be high relative operating cost per barrel. And we're working through the process to try to continue to drive those costs lower. We're assessing gaps. We're prioritizing those gap closure effectiveness. And in some cases, we've brought in some outside help to help us look at our overall cost structures at some of our plants. So we're not ready to announce or disclose anything further at this point, Paul, but I just want you to know we're working hard on continuing to make our operating cost structure more competitive.
Tim, the $40 million of the lower OpEx, how much of them is related to lower throughput?
Yes. It's -- there's some amount of variable costs, obviously, Paul, that are included in that. But I would tell you most of that is fixed cost that either through deferred maintenance or lower maintenance or just more improved efficiencies in our structural cost center. So again, we've cut some -- some overall structure in our refining business, and we believe that will continue to carry on into 2021.
And how about lubricant?
Okay. Thank you for the question, which I think was related to current quarter and past quarter demand performance. So what I really enjoy about this business is the fact that it has a wide breadth of products serving a diversified portfolio of markets, many of which are inherently more resistant to economic downturns such as food, pharma, personal care and cosmetic applications. Other areas which had strong performance throughout the COVID-19 environment are forestry, mining, construction, heavy industry, all of which we serve. And passenger car motor oil and other auto-related product lines began recovering strongly in the mid-third quarter and have continued to perform. And so while volume is down year-over-year for the same quarter slightly, we've enjoyed higher volumes than we would have expected. We've enjoyed lower cost of goods. And all this leads to a higher gross margin, which further benefited from well managed and reduced SG&A, leading to our stronger EBITDA. Our order book remains strong in the current quarter, along with the same cost and spending trends and the demand side recovery remains robust as we look to fourth quarter, subject, of course, to normal seasonality and the risk of further COVID-19 restrictions such as lockdowns, et cetera.
How about margin?
Margin should flow accordingly. I'm not so sure given some of the seasonality it would be as robust as the third quarter, but it certainly will be elevated in trend line over the earlier part of the year.
Your next question comes from the line of Brad Heffern from RBC Capital Markets.
Starting with the question on renewables. Can you give the CapEx that's been incurred so far and sort of just verify that the trajectory that you guys provided of the $150 million to $180 million for this year and $450 million to $500 million for next year is still sort of approximately what we're thinking?
Brad, it's Rich. So the incurred to date number, I don't have right in front of me. What I can tell you is that we guided -- we reduced the guidance here for 2020 to $130 million to $145 million from the $150 million to $180 million. What's happening here is really timing of invoices are sliding a little bit into the first quarter. As Mike mentioned, the projects are still on time and on budget. So I think what you're seeing is probably going to be a little bit of shift of spend of dollars actually out the door from 2020 to 2021, but no overall impact.
Okay. Got it. I missed that. And then I guess sticking with you, Rich. On working capital, can you just talk about -- are we level on that at this point? Or do you see any puts and takes on that in the fourth quarter? And then additionally, many of your peers have called out a sizable tax receivable potentially in the second quarter or the third quarter of '21. Do you have a balance like that, that you can call out?
So Brad, on working capital, I think we're probably going to be neutral and maybe slightly positive here in the fourth quarter. From an inventory perspective, we're pretty much where we need to be. So as you're aware, right, this is going to turn into a function of what the flat price does primarily. The curve obviously looks pretty flat, so you wouldn't expect a huge move in working capital either way. We are now -- to your second question on tax, we are now forecasting a taxable loss for 2020, so we'd expect to see a refund in the second quarter. But I don't -- we're not in a position yet to give a number.
The good news -- I mean this is one of those good news, bad news stories, right, you would prefer not to have a loss. So we're just crossing the line where we're forecasting that. So again, we do expect to see a refund next year, but I don't have any guidance for you at this point.
Your next question comes from the line of Manav Gupta from Credit Suisse.
This probably would be for Tom. Your renewable diesel production would hit about 200 million gallons. So you get about 1.7x diesel RINs. So technically, that lowers your RIN obligation by 340 million gallons once both the facilities are up and running. So I'm trying to understand what's the current RIN obligation in terms of volume, net of blending. And when the 340 additional gallons do come in, then how much do you lower your RIN volume obligation?
It's Tom speaking. We look at the RIN coverage a little bit differently than just on a volumetric standpoint. And let me walk through with you on how we do look at it. We look at it on a value basis. So we do the same math as you, and then we look at the difference in the price between D4s and D6s and assume that we would sell all the D4s and take those revenues and purchase back the D6s and that's keeping with consistent RVOs. And under that methodology, we see ourselves being balanced when the renewal diesel plants come up and are in operation.
So your RIN obligation technically goes away once you're up and running in these facilities?
That -- based on the numbers that we see right now, the answer to that is yes. There's a lot of things that can go on between now and then. But directionally, that is the case, and that was the main justification for us getting into the renewable diesel or one of the main ones. As you'll recall, we were looking at it as a compliance mitigation factor for the RFS program.
Perfect. Second quick question, sir. The pretreatment unit, should we assume given the location that you will be basically targeting distillers corn oil and maybe some animal fat? Or is it a 50-50 animal flat and distillers corn? Like if you could give us some idea as to the lower carbon intensity feedstock, which is the main one you're targeting with your pretreatment unit?
Well, the PTU that, as you know, is located at Artesia, will be able to run a variety of different low CI feedstocks, including DCO, Kallo, UCO. And what we're going to be doing there is it's just not necessarily a price determination, it's a price yield to CI and sort of like running an LP in a crude oil refinery. We are going to purchase and run through the PTU those feedstocks that give us the best return. And that could also mean that we run soybean, just 100% soybean. So we will be looking that on an ongoing basis.
When you look at the DCO amounts that are across the country and tallow, they are not unlimited supplies. They're lower volumes. They're going to be bid up in price, and we've seen increases year-on-year on those low CI feedstocks. And that's why we're looking at soy as well because it's not -- we're not seeing the same price increases on soy.
Your next question comes from the line of Ryan Todd from Simmons Energy.
I don't ask this as a suggestion, but I'm just curious for your thoughts. Your balance sheet is obviously strong enough to maintain the dividend going forward, and you increase the visibility on the capital programs with the debt raise this quarter. But with the market not giving you a ton of credit with this 7.5% dividend yield, is there an argument for using the excess cash to buy back your undervalued stock as opposed to paying the dividend right now? I'm just curious how you think about the relative benefits of the options of using cash given the steep discount to equity.
Ryan, it's Rich. So look, we see a tremendous opportunity in our equity. That said, we're committed to adding long-run value in what we're doing in the renewables business in particular. So that's really going to be the source of our cash. We also view the dividend very seriously and view it as the primary source of our cash return to shareholders. The cash return is fundamental in a mature low-growth industry like ours, and we've consistently acted upon that in the last 10 years with industry-leading cash returns.
Now that said, like, these are unusual times and visibility is poor. So as we discuss the level of the dividend, in particular, with our Board, who make the dividend decision, we need to balance cash returns, maintaining an investment-grade rating and financing the company. So look, to your point, we see tremendous opportunity in the shares themselves, but we've probably got more immediate needs for cash in the next 12 to 15 months.
Great. I appreciate that, Rich. And maybe as a follow-up -- and there's been a lot of discussion lately in the market on capacity rationalization refining. You guys have obviously already taken action there with the ongoing conversion at Cheyenne and the efforts at Artesia. Can you talk about how you view the resilience across the rest of your portfolio if the environment weakness persists well into 2021? And maybe for the broader sector, how you view that dynamic playing out over the next 12 months between demand recovery and capacity rationalization?
Ryan, this is Mike. I'll speak to our portfolio. As to pundit for the industry, we have an opinion, but I don't know that it's better than anybody else's, frankly. Within HollyFrontier, we feel like we've recently taken action on our least competitive refining asset to create a substantially more competitive renewable diesel business. And that includes the pretreatment unit that Tom spoke of, the strategic nature of that and the ability to optimize feedstocks is going to be real important to these 2 renewable diesel plants. As to the remainder of the refining portfolio, each of these assets has something special in terms of either its geography, feedstock, served markets, et cetera. And so we feel as though the existing asset portfolio has strength and durability. If we take the Tulsa asset, for example, the Group I lubricants production is something that many petroleum refiners simply don't have, and Group I lubes is becoming short in supply and fairly dear, and so that gives a competitive advantage to Tulsa. And as we march through our portfolio, we seek out to create competitive advantage in each of these assets so that it has some durability.
As we look forward, the fuel segment, clearly, we have compressed demand. The question is how quickly does it respond or recover and to what level? We think that hydrocarbon fuels are intrinsically valuable and that there will be a huge market for this product as we roll forward, but the most competitive assets will prevail.
So creating advantage within our portfolio and to the extent that opportunities come up, adding the most competitive assets to that portfolio is something that we want to do. We believe in this business, and our point is to try to get to the right point on the supply curve.
Your next question comes from the line of Matthew Blair from Tudor, Pickering, Holt.
I had a question on the Salt Lake City refining market. It looks like cracks, especially diesel cracks, are actually pretty strong for this time of year. Can you talk about the dynamics here? Do -- are there supply issues that are pushing things up? And could you also talk about the Salt Lake City to Las Vegas arb? Is that open at this time?
Matthew, it's Tom. We'll start with Woods Cross. High level, we've been very pleased with the crack spreads that we've seen in Woods Cross. They've remained high and consistently high and compared to other markets, and we expect them to stay that way. In terms specifically of the distillate markets of late, we attribute that to a lot of the harvest and Idaho sugar beets, potatoes, wheat up there. It's been strong.
We still see -- there's been a big growth in demographics in that Salt Lake City valley. And with limited options to get product into that market, we expect to continue to see pretty good margins as we go forward. The arbitrage between Las Vegas and Salt Lake is volatile and a lot of it depends on the U.S. West Coast supply demand and the pricing there because the Northern Pipeline -- [ Kalama ] pipeline can deliver a lot of product into that market in a big hurry.
The other thing is that we've seen the Las Vegas market pretty much decimated with COVID-19. It's really fallen off there, as you could well imagine, with the casinos being shut down. As they come back in, more people will go to Vegas. So it has and it will continue to be -- our opportunity is to capture the highest margin, whether it's in Las Vegas or Salt Lake, by putting the barrels into the right place at the right time, and we continually do that on a month-to-month basis.
That's helpful. And then what's going to happen to your WCS pipeline capacity to Cheyenne? Are you still going to, I guess, take WCS on those pipes and just resell them into other markets? Or are you giving up that capacity? And could you also talk about your outlook for WCS differentials here?
Okay. On WCS differentials, we are keeping our express base. We view that as a valuable commodity to move barrels out of Hardisty as we move forward. I think we can probably expect XL isn't going to be built anytime soon, nor Trans Mountain Express. So we're going to still be confronted with the same issues that we've had for the past few years, for the next few years, and that's apportionment on the Enbridge system and Keystone being full. So the Express outlet gives us access to various markets, including the Patoka, St. Louis market as well as there is an opportunity to move on Platt and then tie it back into Spearhead to get to Cushing that is in place with Enbridge right now, and we're looking at some other alternatives. We may or may not use that space for WCS. We're also going to be using some of that capacity to supply our Woods Cross refinery with synthetic crude because it's a good fit for us, but there is an -- also an opportunity to move like a mix blend -- mixed sweet blend out of Edmonton down into Cushing and so it is WTI if the differentials are there. So there, again, we're going to use flexibility and picking the right crude to generate the highest netback for us.
Going forward, on WCS, we know that the production restrictions are coming off in December this year. That's a good move by the Alberta government, although they reserve the right to put them back on, I think, until the end of '22. But when you look at production numbers over the past few months, they're not even hitting those levels in the production allocation schedule by the Alberta government, and we're also seeing 22% on apportionment. So there's not enough takeaway capacity, but there is some storage availability. There's only 20 million barrels of storage being taken up at Hardisty, and I think the maximum there is 50,000.
So in the short to medium term, we probably see WCS differentials hanging in around this $10 mark is what we're seeing now in the marketplace. But looking further, we would expect that as producers get back in the field, start drilling again, that there'll be more WCS coming into the market and that differential widening to more historic levels.
Your next question comes from the line of Neil Mehta from Goldman Sachs.
First question is just on the quarter. There's a lot of noise in the refining margins per barrel because of some of the onetime items. Do you mind going by regions calling out what the adjusted gross margins were?
Neil, this is Tim. Let me try to take a shot at it. The messiest region was the Rockies because of the Cheyenne situation that we had. As Mike mentioned at the beginning of the call, we pulled oil August 3 in Cheyenne. The index that we publish does not take that into consideration. And so what you have to do is understand that really you got to adjust that index for only running 1 month up to 3. The other thing is we had some decommissioning and severance costs that flow into our numbers in the Rockies that will also impact the gross margin. So when you look at what we saw on the Rockies and you account for those 2 things, we're about a 70% capture of what we published in our index.
If you look at the Mid-Con, that was significantly lower quarter-over-quarter than where we've been in the past. Primarily, that's driven by compressed crude differentials with the Brent TI spread compressed as well as the WCS. And then over in the Southwest, again, that was probably the cleanest region that we had, and there's nothing specific to call out from that region.
And then sticking with the HollyFrontier Index that you published. The Group II VGO margin for October was very robust. I know we've talked a little bit on the quarter about Q3 lubricant speeding. But was there anything onetime in nature there due to hurricanes or storms that disrupted supply? Or do you view that as potentially a new normal of a higher run rate on rack back in lubes?
We certainly saw some supply disruptions associated with the hurricanes that hit into Louisiana. That -- I think that short-term supply disruption has certainly improved the Rack Back business, both at Tulsa and at Mississauga. We have talked about over the past year or so that we did think that the supply-demand balances would return closer to normal. They were depressed in the last 12, 18 months, as we've talked about. And we believe that we are seeing some of that. So yes, there was certainly a onetime correction through some of the weather disruptions. But we think from a secular trend standpoint that the Rack Back business is improving.
Your next question comes from the line of Theresa Chen.
Barclays. So first, I wanted to touch on the demand picture related to your markets. And just given the uptick in cases in many areas of the Mid-Continent, what are you seeing as far as live demand data points for gasoline and diesel?
Theresa, it's Tom. I'll give it a shot at answering this highly fluid question as COVID rages and ebbs and flows all over the place. And I'm going to talk to all 3 regions because they're all a little bit different, and some of them are following national patterns and some of them aren't. And let's start with the easy one, Woods Cross or Salt Lake City has been very good in demand across both gasoline and diesel, and we continue to expect it to remain that way. The Southwest has been pretty good and has exceeded expectations to some degree by the shutdown of the Marathon refinery in the Four Corners area, which has really helped our markets, and some of the Northern Arizona markets have become better for us. So that's a benefit. Maybe the only benefit of the COVID at this point in time. But it's a nice new little market that we're getting into that could be upwards of 10,000 to 12,000 barrels a day of incrementally priced -- attractively priced barrels.
In the group, we're seeing more supply demand in line with national averages. I think what we're seeing is gasoline demand down through the Magellan system year-on-year by about 11%. Distillate, less than that. Right now, it's probably running 4%, but we attribute that to some of the harvest activity that's going on in the Mid-Continent. The harvest this year is earlier than in prior years. I think on corn, we're at almost 80%. The harvest as compared to last year, we were probably around 60%, 55% to 60%. So that's an uptick. So we expect distillate demand to fall off a little bit as we go into the winter here, as you can well imagine.
We also see fluctuations due to COVID. About when people went back to school, there seem to be a spike in gasoline demand in those areas. That seems to have been settled down. But there again, it's -- when people start to go back to work and we get more commuting going on, we'll see more gasoline demand.
So that's sort of how we see it across the various regions. I did not talk about jet because jet is in its own little category, being down more than 50% year-on-year. And there's a lot of factors that are going to have to change before we see big increases in the jet demand at this point in time.
And Rich, can you just give us an update on your conversations with the rating agencies? And what kind of time line or quantitative measures they're looking for to make a change either way?
Yes, Theresa, absolutely. So we stay in regular contact with the agencies. Obviously, we've spoken to them a lot in September when we were issuing debt. And I'll note that all 3 of the agencies maintain both their ratings and their outlooks when we made that issuance. They look at things broadly on both a mid-cycle and a trough basis. Approximately 3x mid-cycle of debt-to-EBITDA is the threshold they've communicated to us, and we believe we're going to get through 2021 without an issue there. And then in the long run, obviously, as we go into '22, we'll be generating substantially more cash flow. Our growth into renewables is going to be credit positive for both diversification and the stability of earnings it's going to bring. So we feel like we're in pretty good shape on the rating side.
Your next question comes from the line of Phil Gresh from JPMorgan.
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Phil, we're having a really hard time hearing you.
Can you hear me okay now?
No.
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Yes. Can I suggest you drop and dial back in?
[Operator Instructions] Your next question comes from the line of Jason Gabelman from Cowen.
I wanted to ask 2 questions. First, on the Rockies region. Given that Cheyenne is now being shut down for conversion, could you just, one, talk about what the Woods Cross operating cost structure is? Any way to quantify that to help us model it on a go-forward basis? And then also the costs that Cheyenne will be incurring during the period that it's being converted? I believe that there is some overhead costs that are going to be associated with the plant.
And then secondly, I wanted to just get your updated views on the Low Carbon Fuel Standards (sic) [ Low Carbon Fuel Standard ] outlook. I think there's a lot of focus on the fact that other states are progressing legislation to pass programs that's probably going to be a medium-term benefit. But it seems like it's going to take some time for that to get passed. So just wondering, more near term between now and, call it, 2022, 2023, what your thoughts are on the way credits price over that time.
Jason, it's Rich. Let me take a shot at your cost question. In September, we put out an 8-K where we recast our refining regions with cost data. So I'd point you to that for context, in general. As you would expect, Woods Cross has a higher cost plan just because of its size. The other thing I'd point out is there's, call it, $3 a barrel of HEP charges in the Woods Cross operating expenses. So it makes it look a little higher than it really is. But again, I'd reference you to that 8-K to help with the modeling.
Going forward then on Cheyenne. We're going to put out -- we'll put out guidance later in this quarter for both capital for 2021 and, to your point, some cost guidance for '21 around Cheyenne. We're going to put the expenses associated with renewables in our Corporate segment for the next 4 or 5 quarters until we have revenue in renewables to report. So we'll give you some better detail there in a few weeks.
Jason, it's Tom, and I'll answer your question on the LCFS issues. We agree with you that there's probably not going to be any huge markets opening up in the next couple of years as the various states try and go through to get a model in place, whether it's the California model or something else to get renewable diesel into their markets. So we continue and what we've modeled our economics on is the continuation of selling into the California market, which as you know, is already established.
For the next couple of years, we don't expect a lot of renewable diesel plants to be coming onstream because of permitting or COVID problems. We're in a unique position because most of our permits are either in hand and all of them have -- if they're not in hand, they have been filed, and we expect approval to meet our schedules. So we will be up and running and be able to take advantage of the California market. And as a result, we think that -- that the LCFS credits will be in the same range as they are now, that 180 to 200 number that we're looking at, and that's good news for us.
And just another point to make is on the BTC. We have not included any BTC benefit past the year 2022. So our outlook and our economics are very conservative at this point in time. If you ask me off-line, I would probably say that I would expect BTC to be continued past 2022, maybe not in the same form it is now, but it will -- could be. I think it will be continued in some format.
Your next question comes from Phil Gresh from JPMorgan.
All right. Let's try this again. Is this better?
Much better. Thanks.
Better, Phil.
Sorry. My first question is on lubes. Just a follow-up there. Obviously, through this COVID situation, really strong results, notwithstanding the second quarter. As you look ahead to 2021, do you think that -- would you say you're getting more comfortable that you can reinstate guidance there? I know in the past, you've been willing to give guidance on rack forward. But this whole 250 to 275 range, is that still kind of a normalized view for you? Or what are your latest thoughts there?
Phil, it's Rich. So look, we think that is, in the long run and the mid-cycle, what we think that business can do. I think at this point, given the fluidity of the COVID situation, as Tom just referenced, it's probably a little premature to give 2021 guidance. But as Bruce mentioned, we're comfortable with what we're seeing here in the fourth quarter and feel confident about that.
Right. Okay. And then on refining, I just want to follow up on the Mid-Con performance. Obviously, the capture rate was very low there, and you're lapping the second quarter when you had the contango benefits. So it sounded like what you were saying is just that this is low crack, tight diffs, it goes a little capture, but was there anything unique in the quarter that you would point out? Or is this just kind of the run rate as -- when we're in this type of environment?
Yes. So when I look at the numbers in the Mid-Con, it really boils down to the crude differentials. Especially if you look quarter-over-quarter, our crude diff compressed significantly in the Mid-Con to the tune of about $3 a barrel, which really just bridges the difference between the second quarter capture and the third quarter capture.
There are no further questions. I will turn the floor back over to Craig for any closing remarks.
Great. Thanks, Rob. This is Mike Jennings. We appreciate your participating with us today and hearing through our third quarter. The economic environment that we are participating in right now is obviously testing the refining space. And with that said, HFC is really well equipped with an investment-grade balance sheet and approximately $2.9 billion of existing liquidity. We've been investing in our asset base to further strengthen 4 distinct business segments that we believe will provide great diversification through the cycle and through down cycles in refining as we currently see. We're really heartened by the performance in our lubricants and our midstream business through this third quarter. I think that validates the investment thesis that we have. And we see growth in both of those businesses naturally occurring as economic activity sort of recovers to more normal levels.
Finally, we sit in and serve premium niche markets for our products and still have great crude sourcing advantage and flexibility as kind of accentuated by Tom and what we're doing with our express space. We believe that will add value, helped us to improve our capture and ultimately, gross margins due to geographic location and to the logistics assets that we have access to. So strong on our business as we look forward and looking heavily toward investing in our renewables business is something that's exciting and is going to grow a lot of value for this company. So thanks again, and we look forward to talking to you next quarter.
Thank you. This does conclude today's teleconference. Please disconnect your lines at this time, and have a wonderful day.