Greetings, and welcome to the CVR Energy’s Third Quarter 2020 Conference Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation [Operator Instructions]. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Richard Roberts, Senior Manager, FP&A and Investor Relations. Thank you, sir. You may begin.

Thank you, Kristine. Good afternoon, everyone. We very much appreciate you joining us this afternoon for our CVR Energy third quarter 2020 earnings call. With me today are Dave Lamp, our Chief Executive Officer; Tracy Jackson, our Chief Financial Officer; Dave Landreth, our Chief Commercial Officer, and other members of management. Prior to discussing our 2020 third quarter results, let me remind you that this conference call may contain forward-looking statements as that term is defined under federal securities laws. For this purpose, any statements that are made during this call that are not statements of historical facts may be deemed to be forward-looking statements. You are cautioned that these statements may be affected by important factors set forth in our filings with the Securities and Exchange Commission and in our latest earnings release. As a result, actual operations or results may differ materially from the results discussed in the forward-looking statements. We undertake no obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise, except to the extent required by law. This call also includes various non-GAAP financial measures. For disclosures related to such non-GAAP measures, including reconciliation to the most directly comparable GAAP financial measures, are included in our 2020 third quarter earnings release that we filed with the SEC and Form 10-Q for the period, and will be discussed during the call. With that said, I'll turn the call over to Dave.

Thank you, Richard. Good afternoon, everyone, and thank you for joining our earnings call. Yesterday, we reported the third quarter consolidated net loss of $108 million and a loss per share of $0.96. EBITDA for the quarter was negative $39 million. Narrower crack spreads, elevated rim prices and a decline in our investment in Delek all impacted our results for the quarter. In light of the ongoing challenges to our business presented by the pandemic, preserving the balance sheet remains a key focus. As a result, the Board of Directors did not approve a dividend for the third quarter of 2020. The board thinks the Wynnewood renewable diesel project that I will discuss shortly in potential acquisition opportunities could offer better returns to shareholders. For our petroleum segment, the combined total throughput for the third quarter was approximately 201,000 barrels a day as compared to 222,000 barrels per day in the third quarter of '19. We experienced some weather related power outages at both facilities in August that modestly impacted our throughput rates for the quarter. Total throughput was also constrained by naphtha capabilities as tight crude differentials have favored running a very light crude slate. Across the board, benchmark crack spreads and crude differentials deteriorated significantly from a year ago. Group 3 2-1-1 crack averaged $8.34 per barrel in the third quarter as compared to $18.30 per barrel in the third quarter of '19, a decline of nearly $10 barrel. The Brent TI differential averaged $2.42 in the third quarter compared to $5.59 per barrel in the prior year period. The Midland Cushing differential was $0.13 per barrel over WTI in the quarter compared to $0.26 per barrel under TI in the third quarter of '19. And the WCS to WTI differential was $9.82 per barrel compared to $12.59…

Thank you, Dave, and good afternoon everyone. Our consolidated net loss of $108 million and loss per diluted share of $0.96 includes a mark-to-market loss of $68 million related to our investment in Delek and favorable inventory valuation impact $16 million. Excluding these impacts, our third quarter 2020 loss per diluted share would have been approximately $0.57. The effective tax rate for the third quarter of 2020 was 22% compared to 25% for the prior year period. The petroleum segments EBITDA for the third quarter of 2020 was $15 million compared to $228 million in the same period in ‘19. The year-over-year EBITDA decline was driven by significantly narrower crack spreads, elevated RINs prices and lower throughput volumes. Excluding inventory valuation impacts of $16 million, our petroleum segment EBITDA would have been a negative 1 million. In the third quarter of 2020, our petroleum segment’s refining margin excluding inventory impact was $4.61 per total throughput barrel compared to $16.37 in the same quarter of ‘19, a 72% decline. The increase in crude oil and refined product prices through the quarter generated a positive inventory valuation impact of $0.86 per barrel. This compares to $0.03 per barrel negative impact during the same period last year. The cash rate excluding inventory valuation impacts was 55% in the third quarter of 2020 as compared to 89% in the third quarter of 2019. The most significant item impacting our cash rate for the quarter was elevated RINs prices, which reduced margins capture by approximately 23%. Derivative gains for the third quarter of 2020 totaled $5 million, which includes unrealized gains of $1 million associated with Canadian crude oiil derivatives. In the third quarter of 2019, we had total derivative gains of $18 million, which included $14 million of unrealized gains. RINs expense in the…

Thank you, Tracy. The reduction in refined product demand due to the ongoing pandemic continued to weigh heavily on crude oil and refined products in the third quarter of 2020. We continue to do everything we can to manage the business through this difficult environment. Our focus continues to be on operating in a safe reliable manner, controlling our costs and maintaining a strong balance sheet and liquidity position. In the near-term, our outlook remains cautious as market fundamentals -- as strong market fundamentals that we see. Crude oil differentials have tightened considerably with the decline in crude prices and domestic shale oil production. We expect differentials to remain weak until shale oil production recovers. Inventory of drilled but uncompleted wells are expected to decline as well, with depletion likely at WTI prices under $40 per barrel. Crude oil prices will need to rise further to incentivize new wells to stem production declines. US refined product inventories have benefited from product exports returning to pre-COVID levels. Gasoline inventories are now within a five year average while distillate inventories remain elevated, mainly due to weak jet fuel demand. The loss of jet fuel demand is more than half of the total demand destruction for transportation fuels. We need jet fuel demand to recover in order for oil to recover. Commercial air travel made up primarily of business and leisure travel accounts for 75% of the total jet fuel demand and remains depress. Ultimately, we will likely need to see additional run cuts and/or permanent refinery shutdowns for crack and crude differentials to improve. As we work to maximize the profitability at our plants under these conditions, CVI is running a maximum light crude slate, maximizing premium production, maximizing RIN generation and selling 100% of our WCS in Cushing, while continuing to…

[Operator Instructions] Our first question comes from the line of Phil Gresh with JPMorgan.

First question, I just want to follow-up on the RIN discussion. Obviously, it sounds like headwinds here into the third quarter [Technical Difficulty]…

You're cutting out, Phil.

With RINs prices having gone up here in the fourth quarter, how are you viewing the potential headwind into 2021 relative to the 2020 guidance that you provided?

Well, a couple of factors. One is an election that, depending on those results, I think RINs could go multiple directions. I think the other thing I'd say on the longer-term is the number of announced renewable diesel projects is an astounding number of new RINs to the market. I'm not sure anybody has really analyzed this very much, but there's over about 1 million gallons of renewable diesel been announced in '20 and '21, with several of them in the process of starting up now, but that represents about 1 billion new RINs to the market. So I think longer term, and you're starting to see that even in the forward RINs that are selling now for 2021, on the renewable diesel side are lower-priced in the future than they are today. But I think even further than that, that volume of RINs hitting the market will bring parity between ethanol RINs and renewable RINs, and all of them will trend down.

The only thing that I would add to that is that we anticipate with the RDU coming online midyear, we'll have a portion of RINs that we generate ourselves in addition to what we already generate that will offset that obligation also.

And I guess for my second question, just to clarify, when you backed out the 23 percentage point capture rate impact, kind of mid 70s capture. Is that what you would view as kind of a fair capture rate in an environment where Brent-WTI spreads are in this $2 range?

It's not far off from that, Phil. I think we were also hit with the premium -- was spread narrowed quite a bit, almost $0.10 a gallon. And now we're heading into the season where Y-grade comes in that's the number one ultra-low sulfur diesel, which usually carries $0.20 to $0.30 premium. So all those factors will bring up, I think, would bring it back to the normal levels, assuming RINs moderate.

Second question, I guess it's a little bit hypothetical, but if we move into a situation here with the Biden administration, I think people are focused on the shutdown risks with DAPL. And I think you guys get barrels on Pony Express and White Cliffs to some extent. So I was just curious if there's any -- if we get into a difficult situation in the Bakken, how much ability do you have to potentially capture those barrels and benefit from any spread widening?

Well, we are Cushing-based. So I think we're somewhat immune to that situation, should it occur, although, it would dry out barrels in Cushing to some degree. But we get very little barrels off of White Cliffs, and most of our light crude comes from the Oklahoma gathering systems that we have and the Kansas gathering systems we have. So I think I would tell you, we're pretty immune to that impact.

Our next question comes from the line of Manav Gupta with Credit Suisse.

I just want to kind of get a clarification. You mentioned that with your first phase of renewable diesel project, you'll probably end up making 100 million gallons of renewable diesel. And I think you get 1.7 times credit for the D4 RIN. So I'm just trying to understand where your current RIN obligation is in terms of gallons, and what that 100 million gallons of renewable RINs does to that RIN obligation once the plant actually comes online. How much short RINs would you be once that plant is up and running?

The renewable diesel at 100 million a gallon throughput would be about, what 170 million RINs. Our obligation today is around 310, 320, somewhere in that neighborhood and we generate internally about 21%, 22%. So you can pretty much do the math from there. I will tell you that we kind of view renewable diesel as a separate segment. So we will account -- refining will have to pay for its full amount of RIN obligations and it will show up as a credit to the renewable diesel as another form of credit. So keep that in mind. We put all the incentive on the renewable diesel that it earns.

So I get the accounting. So basically, what you're saying is 66% of your RIN obligation gets mitigated with this 100 million gallons of D4 RINs coming in by mid-July or mid of next year. Is that the right way to think about it?

Yes. I think we're going from -- it's nominally about 250 down to 135, somewhere in that neighborhood of net, net across the whole company.

On to something which dragged down your earnings, $65 million or $68 million in marketing security losses associated with Delek. I'm just trying to figure out how you're thinking about the company at this point with all the investment opportunities you highlighted in renewable [diesel] Phase I, Phase II, Phase III and versus spending capital in getting additional interest in Delek, which is kind of pulling you back a little at this point of time, definitely pull back your 3Q earnings. So trying to understand how you're viewing the opportunity in renewable diesel expansion versus putting the same capital towards getting more interest in Delek?

Well, as I mentioned that we're interested. We believe that the industry needs to consolidate more just to drive out fixed cost. Typically in a commodity business, the fixed cost is the enemy of everyone. And separate private public companies have significant cost associated with maintaining that scenario. So the more consolidation that happens, the more efficient the fleet is. And we'd like to participate in that and that's what -- it really made our investment in Delek to start. And we still think it's a pretty interesting proposition, getting even more interesting every day with the current stock prices. That said, we don't have any plans to do anything at this point. And then we continue to watch the market and look at the other alternatives we have in PADD IV, and we'll make a decision at the appropriate time.

One last question. The pretreatment unit is a part of Phase 2 of renewable diesel expansion that doesn't change the total capacity. It still remains at 100 million, but what you're basically going to do is use more animal fat, used cooking oil and maybe some other feedstocks versus soya bean oil. Is that the plan for the Phase 2 expansion?

Yes. I think we'd probably focus mostly on inedible corn oil because a lot of the used cooking oils are spoken for today. But I think this will end up being -- transportation will drive a lot of it and we'll be able to gather some of it, but that's yet to be seen. And what is available is an edible corn oil and we're really after a lower CI material, carbon intensity material and that just makes you earn more credits in California. The other thing I did mention in the prepared remarks is if we do this at Coffeyville, we will need a substantially larger sized pretreater. And we may consider even whether we build it, the pretreater at Coffeyville, or at Wynnewood or some other location. And we're rallying at in any way and trying to do whatever is most efficient from a permitting standpoint, as well as a cost standpoint of where we actually do that pretreatment.

David, the Phase 2 and Phase 3 sound very exciting, and we look forward to more details on those two future phases of the renewable diesel project, as well as you hitting that July mark of getting the first phase on. Thank you.

Our next question comes from the line of Prashant Rao with Citigroup.

I wanted to talk about the industry consolidation approach from a non-Delek angle, Dave. Maybe if we could talk about the PADD IV opportunities and specifically thinking about your long WCS barrels, and we're in a tight WCS, this environment. There's some moving parts there with Alberta production quotas being lifted. However, economic cuts were below what the quotas were anyway. So it's arguable as to what that impact might be. So I wanted to get your view on how you're thinking about that WCS position that you have and how that maybe relates to where a potential PADD IV asset, the bid-ask spread is -- how those two play with each other versus the other opportunities you have in the portfolio in terms of capital investment. And then I have a follow-up on Wynnewood. Thanks.

I think, again, there's money to be had in the consolidation play. Our main drive in PADD IV is really around diversification of EBITDA in, what I'll call, a similar market to what we have today where there's a little bit of a niche status to it. And we think PADD IV does that in a lot of ways. A lot of these come with marketing assets, which allows you to earn a RIN or a portion of your RINs that you generate. And most of them are associated with in some form or fashion with WCS, because the proximity to Hardisty and Western Canada. And you're somewhat competitive advantage to -- because the delivery cost is only $3 to $4 a barrel compared to $6 to get to Cushing. So all those kind of play into our portfolio quite well. We've been successful to date, really recouping our pipeline tariff on the 35,000 rate that we have secured in Keystone and the other one [Multiple Speakers] Spearhead. And as far as what's happening in Canada, there's -- I think last time I added it up, it was about 4.2 million barrels a day of pipeline capacity out of Canada. We haven't -- Canada has not been producing that much WCS to date. With the curtailment being removed, the thought is that we should -- it should result in production going up even at these prices because the cash cost is so low in Canada for incremental WCS, assuming there's diluent available. But that fact should go back to the pricing mechanism to be more related to rail than to pipeline tariffs and that will make a big difference. WCS really competes against mine on the Gulf Coast and we're selling it today at about $3.30 under WTI in Cushing, and it's landing in the Gulf Coast at about $2. So it's still very competitive with mine and it will probably be that way for the near term…

And then on Wynnewood on the renewable diesel project, one specific aspect that I wanted to get a little bit more color on. If the market dynamics dictate, you mentioned the ability to switch between by or renewable production and traditional fossil fuel based production. Could you maybe elaborate a bit more on what that would take to make that switch back? What's the time window and is that something that gets done within a short turnaround? Just sort of, I guess, it's a bit more of a mechanical question. But for a mechanical question for nonengineering dummies and analysts. If you could give us a bit more color, that would be helpful. Thanks.

The basic difference between -- even though you upgrade some metallurgy in the hydrocracker unit, the unit is basically the same. It's just metallurgy metaled up, so to speak. And then catalyst is a bit different. So to really switch it back to hydrocarbon service, you just basically change the catalyst, which is a 20-day outage period. So it's rather rapid that you can do it. And the real conditions that would matters here is do more states opt into the low carbon fuel standard game, what are RIN prices and what happens with the blenders credit. You can paint scenarios where all those can go the wrong way. And we would just view this as an option. We can jump back and forth fairly quickly and harvest whatever is the best, whatever makes the most money for CVI and considering all factors. So that's when I say it's an option that's what it really is within, let's say, 30 days, one month, you can switch it back and forth between the two services.

And would you be able -- would you be thinking about some similar sort of optionality with Coffeyville as well if you go forward with that?

It's actually the exact same scenario. And I've mentioned the Coffeyville is probably even a higher capacity than this 100 million, it's probably more in the 150 million range because it's a much bigger unit and much bigger hydrogen plant.

Our next question comes from the line of Neil Mehta with Goldman Sachs.

The first question I have for you, David, is historically, and I think the market has historically viewed the business as one of having one of the stronger balance sheets in the refining sector, and I think it might be a function of a lot of technical dynamics too. But we have seen the credit sell off pretty hard here over the last couple of weeks. And I just want to give you an opportunity to kind of talk about the way that you see the balance sheet playing out, liquidity, cash flow burn. And how you guys are getting -- how are you guys are comfortable about managing through this tougher period?

Well, I think the primary focus we have is to run safe reliable operations and to reduce our cost and capital spending to levels that frankly, we probably have never seen. That's what it takes to survive in this environment. Protecting the balance sheet is very important to us and maintaining our cash for what we consider some great opportunities. And frankly, when the markets on its rear end, it's the time to consider buying assets and we want to be in that position as much as possible. So we actually generated a little cash this quarter. I don't know that we'll repeat that in the fourth quarter, but those are the kind of activities we're doing. The amount of cost-cutting we've done to date, I think Tracy mentioned $25 million quarter-over-quarter and you do that on a run rate basis, you can see we're close, quickly approaching $4 or less a barrel operating cost. And we've equally cut a significant amount of money out of the SG&A side too. So I don't think those go away. They stay around for a while. We're trying to make sure we don't defer any maintenance that's needed for safe, reliable operations in any way or things that we're obligated to do by the government or whatever they be. But we are really improving the competitiveness of our facilities, which are frankly, pretty competitive anyway, considering our configuration and the kind of crudes we can run and process. So I'm not sure I got to what you were looking for, Neil, but…

No, it's directionally very helpful. So to just put some numbers around it, as you think about 2021 capital spending, I know it's still early. But any thoughts on where you can flex it down to, if needed, and maintain that safe and reliable level? And then just as you think about cash flow neutrality, do you think as you look at the forward curve for both Brent-WTI and refining margins, recognizing that I think there are a lot of us who were skeptical that the forward curve is right. But do you still think that you can minimize cash flow burn in that environment?

Yes. Well, I think we'll do some hedging around forward cracks that we think are advantageous. We'll do all we can on crude buying and buying the best discounting crudes we can with the highest value, which since we're directly coupled to the field, we do have a lot of optionality there that others don't have. And really we're trying to drive our -- we don't have our budget done for '21 yet, but we're trying to drive below $80 million on sustaining capital. That doesn't include the R&D project. But at those kind of levels we don't have any turnarounds planned immediately in this next year. As Tracy mentioned, we think we can ride until easily the end of '21 without any problem. And at that point, then we start making some other decisions. But the forward curve is somewhat in a little bit in contango but not enough for my liking. And as I mentioned earlier, really it's all hinges on the virus and what happens with the jet fuel demand to see, and the number of impaired operations or other refineries or actual shutdowns. There's still a lot of those that need to happen in this environment and I think they will. If I did the math right, we're already at about 1.7 million barrels a day that's been mothballed in some form. If we -- even that includes us, which we're downgrading Wynnewood, when we do R&D, we're actually cutting crude. Coffeyville would be the same way. And we're reconfiguring for a different crude slate that actually reduces cost even more at both facilities. So there's a lot to come and a lot of knobs we still haven't turned.

Our next question comes from the line of Paul Cheng with Scotia Howard Weil.

Dave, can you remind me that what is the preliminary CapEx for the Phase 1 of the renewable plan?

We are targeting $100 million for Phase 1.

$100 million for 100 million gallons. And the feedstock you will decide, you said going to be soybean oil?

Yes. It's washed, refined and bleached soybean oil.

And I think you have said that. But can you just remind me how much is the Wynnewood throughput will be reduced by, and how that product yield is going to change?

Well, we retooled the refinery for more condensate processing, Paul. And what that really means is we keep our reformer full and equipment around that. And it basically puts -- taking the hydrocracker out of the fuels processing means our CAC cracker rate directionally goes up, but we make similar type yields, probably a little less diesel, more gasoline, but not a lot, just on that shift.

And what is the total throughput will be changed by?

Total throughput today is about a little under 75,000 barrels a day, and that will go to about 59,000 barrels a day, between 55,000 and 59,000.

So it will drop by somewhere between 15 to 20 million barrel -- 20,000 barrels per day in…

That's right, when we're in R&D mode.

And maybe I get this wrong on the math. I think you're saying that assume the Phase 1 is on stream, your net win exposure will drop from 310, 320, down to about 135 going in?

No. Yes, you're close, but you forgot our internally produced RINs, which is about 20%, 21%, 22% of our RVO. So those are 65 million.

I thought that would be about 60, 70 because your RIN obligation is 310 to 320, right? So 20% will be 60% to 70%, and the renewable diesel plan will be 170…

Right.

And so should we be down to 80 only on your net exposure?

That's pretty close. Let's see. Something less than 100 million.

Yes, because I thought I heard you saying that as a higher number. So I'm not sure that I thought I did…

I think I said 135. But the RVO goes down with the crude rate cut too, remember. So you've got to adjust both numbers, the top number and the bottom number.

But I mean in theory, that you're running at -- because that has only dropped by about 10% on your obligation, given that your throughput for the total company will only drop by about 10% at 20,000 barrels per day. So we will be talking about 270. So that should still be -- if anything, that it should be even less in terms of your obligation. It should be less than 80, it should be more like in the 60.

Yes, I came up with 70 -- 77, I think, Paul, but I think you're on the right numbers.

Yes, I just get confused that when you say 135. And Dave, just curious that when you're talking about consolidation and the benefit of the M&A, how should we look at the CVR Partner, given it's less than $1 per share or per unit on the price? And you also have the option that you can essentially buy or at least that, that is a possibility that you can buy at the current price or that close to that? Does it make sense that for you to eliminate that MLP structure, given the outlook for the MLP structure going forward? And how low is the equity value anyway already? Or that you think that better value somewhere else and is still not -- because on one hand, that CVR Partner is actually, as you indicate that you are buying back some stock, so I would imagine that the Board believes the valuation is attractive. And so if that's the case, why not just take it out, patronize it, and that you can have some saving on the regulatory fund so that you don't have to report it as a separate unit?

Well, you laid out a pretty good case there, Paul. We continue to look at that at all times. We don't know that the time is right now but it's something we evaluate all the time. And it is an option for us to do. I think with the debt level that’s expiring in '21 that we want to kind of see what we end up doing in that in '23, I guess if that's in '23. So that's on the table. And the way we view fertilizer side of the business, it's kind of -- it's been a great performer for us this year frankly. And it shows the value of the diversified portfolio that can make sense. Now the thing I'd say that may offset that a bit, depending on who gets elected if taxes go up a lot, the MLPs may come back in favor again too. So who knows. So we evaluate it all the time, though, it's a good idea.

And just curious that if there's a good asset or asset that fit you with the right asset, what is the maximum leverage you're willing to go to?

Well, we're always looking at that. And if you did do something -- a major acquisition like that, I think you'd do it on a pro forma basis, which would change the numbers a bit. But I don't know that anything above two is anything we're interested in, in terms of leverage. And that is kind of there right now on our EBITDA basis.

So is that net debt-to-EBITDA maximum 2 times?

I don't think anybody in this space goes much above that. On purpose, I meant. don't go much above it on purpose.

A final question for me, maybe it's for Tracy that how much is the tax refund you expect next year from the CARES Act? Do you expect in the second quarter or third quarter to receive it? And also whether the third quarter unique cost a good baseline to be used for the future forecast, or that's an adjustment or one-off item that we need to take into consideration?

So the first question, I would just use our 21% corporate average. I would anticipate that you should look at what we expect our full year production to look like with the curves and get a full year loss number or gain number, whatever you're predicting and apply a corporate percentage rate to it, and that is going to be a good proxy for what our cash return from the net loss carryback that we're expecting. Can you restate your second part of your question, please?

For the third quarter, your unit cost is very low. Is that a reasonable level that we can use as a baseline to forecast into the future, or that's one-off items whether plus or minuses that we need to take into consideration and adjustment.

I think you can look to our current operating cost run rate to be a new normal for us for the short term. And certainly, we will look to hold cost at that level, should we see an economic return. We do have projects that are not related to safe and reliable operations that we're deferring that we will bring back at some point. But right now, we don't need to be painting tanks.

So Tracy, when you say that, are you talking about on a per unit basis or on an absolute nominal? Are we talking about 420 per barrel? Is it reasonable baseline or 77 million is that reasonable baseline.

420 a barrel is a reasonable baseline.

I think we're going to drift, Paul, more towards 4 and we do have some more, like I said, more ammo in our belt that we can fire should we need to from a cost saving standpoint. So we don't really want to go there because we've already had a reduction in force, and done quite a few things to conserve cash. But I really think the $4 level is doable.

And Dave, is there any reason we should expect your throughput in the fourth quarter will be much different than the third quarter given the market conditions?

No. We're running basically 94% of capacity on a light slate, which is about all we can do. And we're not having trouble moving any product or any other constraints. So we plan to stay at the same rates.

Our next question comes from the line of Matthew Blair with Tudor Pickering Holt.

Dave, you mentioned the crude slate reconfiguration. It looks like you're already making some changes here. Condensate up to 10% of your slate, WTL up to 5%. Could you talk a little bit more about that? Is it possible to quantify the benefit in Q3? And do you expect to run a pretty light slate into Q4?

Well, the condensate spread was approximately $0.50 in Cushing under WTI. So when you look at our gathering system, that's actually wider than that. So you can kind of tell what we're after there. And the yield on condensates, is with our configuration, is a high percentage of gasoline but still makes significant diesel and really has a great volume yield. So it's just win-win for us all the way around.

And then I also wanted to ask about the BTC. So obviously, something pretty hard to forecast. But in your internal modeling, what are you assuming for BTC into like 2023 and 2024? There's some talk that it might get phased down or it might go away completely. So what are you assuming? And do you think the election results would make a difference in that?

If you look at the history of the Blenders Tax Credit, it has always been there at $1 level. It's been delayed for as long as two years but retroactive back to those two years. I don't see that changing much. I do think the state of the deficit and other things, it's going to put pressure on it to reduce it some way, but to eliminate it. I mean what happened with RFS is that created an industry, it created actually two industries. One on ethanol and ethanol production and one on biodiesel, now renewable diesel on top of it. And when Congress creates industries, they just can't abandon them. And this is a bipartisan issue for a large part. So I think you see it kind of gravitating towards the renewable diesel more than the biodiesel, and that should naturally will happen, I think. The market forces will force that. But I think they're going to have to support it somehow some way because they created an industry around it.

Your next question comes from the line of Matt Vittorioso with Jefferies.

Most of it's been asked. Maybe just quickly on fourth quarter cash flow. You mentioned in the third quarter, you got a big boost from working capital. Some of that was payables and accrued expenses. Do you expect that to reverse in the fourth quarter or any big movements in working capital for the fourth quarter?

We do expect working capital in the fourth quarter to continue to be a source of cash for us. And I don't really want to comment on the net cash position for the fourth quarter. But specifically, working capital will likely be a provision of cash.

It all depends on cracks to some degree, and we don't know. We won't know those until its over.

And then I don't know how much you can say here, but maybe just -- you've gone through where some of the benchmark differentials and industry markers are here early in the fourth quarter. How should we think about just generic refining margin, you did $4.60 in the third quarter. Based on sort of what you're seeing in the market today. Are we kind of at that same level in the fourth quarter or any big movements there?

We haven't seen much change, no. But I will say that where these numbers where they're at are just not sustainable for the world, frankly, both on crude price and cracks. You're sitting here competing on the cost curve and that, again, most people will say and I tend to say, too, is when you have to make a big decision like a turnaround, is when you really -- the rubber hits the road. Because again, we're not -- basically, at these numbers, you're not recouping your turnaround accrued costs. There's just no way at these numbers. So something is going to have to give either on demand or on production. Supply demand will come back because it's just an economic fact that you either have to increase margins or cut round, there's just no other way around it.

We have reached the end of the question-and-answer session. I would now like to turn the floor back over to management for closing comments.

Again, I'd like to thank you all for your interest in CVR Energy. Additionally, I'd like to thank all our employees for their hard work and commitment towards safe, reliable, environmentally responsible operations. They have been under extra strain with the virus and done a really good job of keeping our operations running and successful. And we look forward to reviewing our fourth quarter results at our next earnings call, and good day, everyone.

Ladies and gentlemen, this does conclude today's teleconference. You may disconnect your lines at this time. Thank you for your participation, and have a wonderful day.