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. At this time, all participants have been placed in a listen only mode and the floor will be open for your questions following the presentation. 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 Q3 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 1 on our website at hollyfrontier.com. Before we proceed with remarks, please note the Safe Harbor disclosure statement in today's press release.
In summary, it says statements made regarding management expectations, judgments or predictions are forward looking statements. These statements are intended to be covered under the Safe Harbor provisions of federal security laws. There are many factors that could cause results to differ from expectations, including those noted in our SEC filings. 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 Q3 results in the face of the economic down cycle caused by the COVID-nineteen 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 Q3. 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 Q3 results, we reported a net loss attributable to HollyFrontier shareholders of $2,000,000 or $0.01 per diluted share.
These results reflect special items that collectively increased net income by $65,000,000 Excluding these items, the net loss for the Q3 was $67,000,000 or negative $0.41 per diluted share versus adjusted net income of 278,000,000 dollars or $1.68 per diluted share for the same period in 2019. Adjusted EBITDA for the period was $1,000,000 a decrease of $457,000,000 compared to the Q3 of 2019. The Refining segment reported adjusted EBITDA of negative $54,000,000 compared to $425,000,000 for the Q3 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. 3rd 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 $61,000,000 compared to $38,000,000 in the Q3 of 2019. Rack Forward EBITDA was $79,000,000 representing a 19% EBITDA margin. The Rack Forward segment saw improvement industrial and transportation related end markets, which drove higher demand and unit margins during the Q3 of 2020.
Sales volumes improved 24% compared to the 2nd quarter and were down 7% versus
the prior
year. Within the Rack Back portion, demand for base oils increased to Q4 2019 levels, 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 the U. S. Gulf Coast. This combination of factors drove higher margins and utilization at our facilities during the Q3.
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 $55,000,000 for the Q3 compared to $123,000,000 in the Q3 of last year. Reported EBITDA for the Q3 of 2020 included a 36 $1,000,000 goodwill impairment charge and reported EBITDA for the Q3 of 2019 included a $35,000,000 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 terminalling services during the Q3 of 2020, particularly in the assets around the Salt Lake area, and we expect this trend to continue through the Q4 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 Q3.
We're making progress on all three of our renewable projects, which currently remain on time and on budget. We're confident that demand for transportation fuels will return and we'll be well positioned for the next upcycle. And with that, let me turn the call to Rich.
Thank you, Mike. As previously mentioned, the Q3 included a few unusual items. Pretax earnings were positively impacted by a $77,000,000 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 to market inventory gain of $63,000,000 These items were partially offset by charges related to the Cheyenne refinery conversion to renewable diesel production, including LIFO inventory liquidation costs of $34,000,000 decommissioning charges $12,000,000 and severance charges totaling $2,000,000 A table of these items can be found in our press release. Cash flow from operations was $82,000,000 in the 3rd quarter, which included $25,000,000 of turnaround spending and $53,000,000 of working capital gains. HollyFrontier's standalone capital expenditures totaled $75,000,000 for the quarter.
In September, we reinforced our robust liquidity position through a successful $750,000,000 bond offering. The offering consisted of 2 tranches of senior unsecured notes, a $350,000,000 3 year bond with a coupon of 2.5eight and a $400,000,000 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 $2,900,000,000 comprised of a standalone cash balance of $1,500,000,000 along with our undrawn $1,350,000,000 unsecured credit facility. As of September 30, we have $1,750,000,000 of standalone debt outstanding, the debt to cap ratio of 25% and net debt to cap ratio of 3%.
During the Q3, we declared and paid a dividend of $0.35 per share totaling $57,000,000 We did not repurchase any shares in the Q3 and do not intend to repurchase equity until demand for our products normalize and visibility improves. HEP distributions received by HFC during the 3rd quarter totaled $18,000,000 HollyFrontier owns 59,600,000 HEP limited partner units, representing 57% of HEP's LP units at a market value of approximately $650,000,000 as the blast lines close. We have reduced the range of our full year 2020 consolidated capital budget to $475,000,000 to $550,000,000 from $525,000,000 to $625,000,000 For the full year of 2020, we now expect to spend between $187,000,000 $212,000,000 of capital at HollyFrontier Refining, dollars 130,000,000 to $145,000,000 in Renewables, dollars 30,000,000 to $35,000,000 in Lubes and Specialties and $85,000,000 to $100,000,000 for turnaround and catalyst. At HEP, our capital budget has reduced to a range of $43,000,000 to $58,000,000 from $58,000,000 to 69,000,000 For the Q4 of 2020, we expect to run between 360,000,380,000 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 Q4.
And with that, we're ready to take questions.
Thank you. The floor is now open for questions. Thank you. Our first question is coming from Paul Cheng. Please state your company.
Your line is open.
Scotiabank. Hey guys, good morning.
Good morning, Paul.
Thank you. Two questions. On the cost reduction side, I mean, everyone is trying to right size it. If we're looking at your unit cost in the refining, there still seems high. Is there any opportunity what we can do over there to further reduce your unit cost?
Secondly, that Louboutin has been very strong in the 3rd quarter, report by everyone basically. And can you discuss what is the trend line look like? Have we seen that strong margin and also that improved demand expansion to the Q4? Thank you.
Yes. Good morning, Paul. This is Tim Goh. 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 and A costs. And as you recall, that was $30,000,000 $20,000,000 of which will show up in SG and A, dollars 10,000,000 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 $20,000,000 in the 3rd quarter, roughly 8% versus what we were at last year. And year to date, it's about $40,000,000 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 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. 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 in some of our plans. 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 $40,000,000 of the lower OpEx, how much of that is related to the 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 overall structure in our refining business. We believe that will continue to carry on into 2021.
Thank you. 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-nineteen 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 of this leads to a higher gross margin, which further benefited from well managed and reduced SG and 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 Q4 subject, of course, to normal seasonality and the risk of further COVID-nineteen restrictions such as lockdowns, etcetera.
How about margin?
Margins should flow accordingly. I'm not so sure given some of the seasonality that would be as robust as the Q3, but it certainly will be elevated in trend line over the earlier part of the year.
Thank you.
Your next question comes from the line of Brad Heffern from RBC Capital Markets. Your line is open.
Hey, good morning everyone.
Hi, Brad.
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 $150,000,000 to $180,000,000 for this year and $450,000,000 to $500,000,000 for next year is still sort of approximately what we're thinking?
Hey, Brad, it's Rich. So the incurred to date number, I don't have right in $1.40 $5 from the $150,000,000 to $1.50 $1.80 What's happening here is really timing of invoices are sliding a little bit into the Q1. 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. Thanks for that. 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 Q4? And then additionally, many of your peers have called out a sizable tax receivable potentially in the Q2 or the Q3 of 'twenty one.
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 Q4 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, 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 it. Again, we do expect to see a refund next year, but I don't have any guidance for you at this point.
Okay. Thank you.
Your next question comes from the line of Manas Gupta from Credit Suisse. Your line is open.
Hey, this probably would be for Tom. Your renewable diesel production would hit about 200,000,000 gallons. So you get about 1.7x D4 RINs. So technically that lowers your RIN obligation by 340,000,000 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 3.40 additional gallons do come in, then how much do you lower your RIN volume obligation?
Good morning. 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 RBOs.
And under that methodology, we see ourselves being balanced when the renewal diesel plants come up and are in operation.
So your rent obligation technically goes away once you're up and running in these facilities?
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 diesels are one of the main ones. As you recall, we were looking at it as a compliance mitigation factor for the RFS program.
Perfect. 2nd 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 fifty-fifty 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 is located at Artesia will be able to run a variety of different low CI feedstocks, including DCO, tallow, EUCO. And what we're going to be doing there is it's just not necessarily a price determination. It's a price to 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. Thank you
for taking my questions.
Thank you.
Your next question comes from the line of Ryan Todd from Simmons Energy. Your line is
open.
Thanks.
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 increased 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.
Good morning, Rhino, 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 months to 15 months.
Great. I appreciate that, Rich. And maybe as a follow-up, I mean, there's been a lot of discussion lately in the market on capacity rationalization refining. You guys have obviously already taken action there with 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?
Ron, this is Mike. I'll speak to our portfolio. As to fund it 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, etcetera. And so we feel as though the existing asset portfolio has strength and durability. If we take the Tulsa asset, for example, the Group 1 lubricants production is something that many petroleum refiners simply don't have and Group 1 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 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.
Okay. Thanks, Mike.
Yes.
Your next question comes from the line of Matthew Blair from Tudor, Pickering, Holt. Your line is open.
Hey, good morning, everyone. 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. Could you talk about the dynamics here? 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?
Yes. Good morning, 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 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 in 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 hurry. The other thing is that we've seen the Las Vegas market pretty much decimated with COVID-nineteen. 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 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. Thanks. 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 types 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?
Thanks. Okay. On WCS differentials, we are keeping our express base. We view that as a valuable commodity to move barrels out of Cardisty. 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 Platte and then tie 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 isn't also an opportunity to move like a mix blend, mix sweet blend out of Edmonton down into Cushing and sell it as WTI if the differentials are there. So there again, we're going to use flexibility and picking the right crude to generate the highest netbacks for us. Going forward on WCS, we know that the production restrictions are coming off in December of 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 2022. 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 20,000,000 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.
Great. Thank you. Okay.
Your next question comes from the line of Neil Mehta from Goldman Sachs.
Your line is open.
Hey, good morning guys. First question is just on the quarter, there's a lot of noise in the refining margins per barrel because of some of the one time items. Do you mind going by regions calling out what the adjusted gross margins were?
Yes. Neal, 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 after 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 in the Rockies and you account for those two things, we were 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.
Thanks, Tim. And then sticking with the HollyFrontier Index that you published, 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 one time 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 loops?
We certainly saw some supply disruptions associated with the hurricanes that hit into Louisiana 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 one time correction through some of the weather disruptions.
But we think from a secular trend standpoint that the Rack Back business is improving. All right, guys. Thank you.
Your next question comes from the line of Theresa Chen. Please state your company. Your line is open.
Hi, Barclays. So first, wanted to touch on the demand picture related to your markets. And just given the up tick in cases in many areas of the Mid Continent, what are you seeing as far as live demand data points for gasoline and diesel?
Hey, Theresa, it's Tom. I'll give 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 three regions because they're all a little bit different and some of them are following national patterns and some of them are. 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 10000 to 12000 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% of 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 people who went back to school, there seemed 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.
Thank you. And Rich, can you just give us an update on your conversations with the rating agencies and what kind of timeline 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 spoke with them a lot in September when we're 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 3 times 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 'twenty two, 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.
Thank you.
Your next question comes from the line of Phil Gresh from JPMorgan. Your line is open.
Bill,
we're having a really hard time hearing you. Can I suggest you drop and dial back in?
Your next question comes from the line of Jason Gabelman from Cowen. Your line is open.
Hey. I wanted to ask 2 questions. First, on the Rockies region, given that Cheyenne is now being shut down for conversion. Can you just, 1, 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 outlook. I think there's a lot of focus on the fact that other states are progressing legislation to pass programs and 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 2023, 2023, what your thoughts are on the way credits price over that time? Thanks.
Hey, Jason, it's Rich. Let me take a shot at your cost question. In September, we put out an 8 ks 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 is a higher cost plant 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 ks 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 2021 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.
Thanks.
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 various states try and go through and 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 a continuation of selling into the California market, which is already established. For the next couple of years, we don't expect a lot of renewable diesel plants to be coming on stream 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 the LCFS credits will be in the same range as they are now, that $180,000,000 to $200,000,000 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 offline, I would probably say that I would expect BTC to be continued past 2022, maybe not in the form it is now, but it will probably could be I think it will be continued in some format.
Great. Thanks for the color.
Okay. Thank you.
Your next question comes from Phil Gresh from JPMorgan. Your line is now open.
All right. Let's try this again. Is this better?
Much better. Thanks better, Phil.
My first question is on lubes. Just a follow-up there. Obviously, through this COVID situation, really strong results notwithstanding the Q2. As you look ahead to 2021, do you think that would you say you're getting more comfortable that you could reinstate guidance there? I know in the past you've been willing to give guidance on Rack Forward, but this whole $250,000,000 to $275,000,000 range, is that still kind of a normalized view for you or what are your latest thoughts there?
Hey, Phil, it's Rich. So look, we think that is in the long run-in 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 is probably a little premature to give 2021 guidance. But as Bruce mentioned, we're comfortable with what we're seeing here in the Q4 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 2nd quarter when you had the contango benefit.
So it sounded like what you were saying is just that this is low crack, tight diffs equals little capture. But is 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 between the Q2 capture and the Q3 capture.
Right. Okay. All right. Thank you.
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 Q3. 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 $2,900,000,000 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 Q3. 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 talk to you next quarter.
Thank you. This does conclude today's teleconference. Please disconnect your lines at this time and have a wonderful day.