Greetings, and welcome to the CVR Energy Inc. Second 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. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Mr. Richard Roberts, Investor Relations Manager. Thank you, sir. You may begin.

Thank you, Michelle. Good afternoon, everyone. We very much appreciate you joining us this afternoon for our CVR Energy second 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 second 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, they are included in our 2020 second 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, 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 second quarter consolidated net loss of $32 million and a loss per share of $0.05. EBITDA for the quarter was $68 million. Narrow crack spreads, tight crude differentials, and lower throughput volumes all impacted our results for the quarter. The Board of Directors did not approve a dividend for the second quarter of 2020 in light of both ongoing challenges to our business presented by the COVID-19 pandemic, and potential opportunities for higher return uses of cash in the near term. This includes major projects like the Wynnewood renewable diesel project that I will discuss shortly, as well as potential acquisition opportunities. The board felt it was prudent to preserve liquidity while we wait for refined product demand to return and as we work towards a final decision on our other potential uses of cash. For the petroleum segment, the turnaround at Coffeyville was completed in April. Although the plant restarted later than we originally planned due to the impacts of COVID-19, we did avoid some of the weakest product cracks in the quarter while Coffeyville was down. After completing the turnaround in April, we ran the plant at reduced rates until mid-June. Wynnewood operated at similar reduced rates for much of the quarter before returning to full operations in mid-June. The combined total throughput for the second quarter of 2020 was approximately 156,000 barrels per day compared to 216,000 barrels per day for the second quarter of '19. The Group 3 2-1-1 crack spread averaged $8.75 in the second quarter of 2020, compared to $20.67 per barrel in the second quarter of '19. The Brent/TI averaged $5.39 per barrel in the second quarter, compared to $8.56 per barrel in the second quarter of '19. The Midland Cushing differential was $0.40 per barrel over WTI in the quarter compared to $2.27 per barrel under WTI in the second quarter of '19. The WCS differential to TI was $9.45 per barrel, compared to $12.63 per barrel in the same period last year. Light product yield for the quarter was 98% on crude processed. Our distillate yield as a percent of total crude oil throughputs was 42% in the second quarter of 2020 compared to 44% in the prior year. Product prices favored gasoline over diesel at times during the quarter. In total, we gathered approximately 82,000 barrels a day of crude oil during the second quarter of 2020, compared to 120,000 barrels for the same period last year. With the collapse of crude oil prices during the quarter, we saw dramatic declines in production volumes in our gathering regions. As prices began to rebound, we saw those volumes coming back. Our current gathered volumes are over 120,000 barrels per day. In the fertilizer segment, we had strong utilization at both of our facilities during the quarter. At Coffeyville, utilization of the ammonia unit was 98% for the quarter, and at East Dubuque, the ammonia plant operated at 101% utilization for the quarter. Weather conditions were favorable for spring fertilizer application, and planted corn acres increased by over two million acres compared to last year. Nitrogen fertilizer prices currently remain soft due to ample supply in the market and lower natural gas prices, although cheap natural gas lowers our feedstock cost as well. Now, let me turn the call over to Tracy to discuss some additional financial highlights.

Thank you, Dave, and good afternoon, everyone. As Dave mentioned, for the second quarter of 2020, we reported a consolidated net loss of $32 million and a loss per diluted share of $0.05. This compares to net income of $128 million and diluted earnings per share of $1.16 for the second quarter of 2019. Our consolidated results for the second quarter of 2020 included a non-cash goodwill impairment of $41 million in the fertilizer segment, and a mark to market gain of $18 million in dividends of $3 million related to our investment in Delek, as well as favorable inventory valuation impacts of $46 million. Excluding these impacts, our second quarter 2020 loss per diluted share would have been approximately $0.44. The petroleum segment's EBITDA for the second quarter of 2020 was $54 million, compared to $216 million in the same period in 2019. The year-over-year EBITDA decline was driven by narrower cash tax spreads and tighter crude oil differentials, as well as lower throughput volumes. Excluding inventory valuation impacts of $46 million, our petroleum segment EBITDA would have been $8 million. In the second quarter of 2020, our petroleum segment's refining margin, excluding inventory impacts, was $7.18 per total throughput barrel, compared to $15.68 in the same quarter of 2019. The increase in crude oil and refined product prices through the quarter generated a positive inventory valuation impact of $3.25 per barrel during the second quarter of 2020. This compares to a $0.02 per barrel negative impact during the same period last year. The capture rate, excluding inventory valuation impacts, was 82% in the second quarter of 2020, compared to 76% in the second quarter of 2019. Derivative gains for the second quarter of 2020 totaled $20 million, which includes unrealized gains of less than $0.5 million associated with open commodity derivative instruments and open purchases of Canadian crude oil that are scheduled for future delivery. In the second quarter of 2019, we had total derivative gains of $4 million, which included $3 million of unrealized gains. RINs expense in the second quarter of 2020 was $16 million compared to $21 million in the same period last year. The year-over-year decrease in RINs expense was due to our RINs purchasing strategies, trading activities, and RVO decrease, offset by increased RINs prices. Based on recent market prices of RINs and current production plans, we now estimate that our RINs expense will be approximately $95 million to $105 million in 2020. The petroleum segment's direct operating expenses were $5.52 per barrel of total throughput in the second quarter of 2020, as compared to $4.40 per barrel in the prior year period. On a per barrel basis, direct operating expenses were higher, due to lower throughput volumes in the quarter. Total direct operating expenses for the second quarter of 2020 declined by $7 million from the prior period, due to our efforts to lower costs as we worked to phase in our $50 million targeted savings in operational and SGA expenses. The reduction in the second quarter of 2020 was driven by a combination of lower personnel costs, utilities, and repairs and maintenance expenses. For the second quarter of 2020, the fertilizer segment reported an operating loss of $26 million, a net loss of $42 million or $0.37 per common unit, and EBITDA of negative $2 million. Reported results for the second quarter include a non-cash goodwill impairment of $41 million. This is compared to the second quarter of 2019 operating income of $35 million, net income of $19 million or $0.17 per common unit, and EBITDA of $60 million. The year-over-year decline was primarily due to the goodwill impairment and lower prices for ammonia and UAN. During the quarter, CVR Partners repurchased approximately 890,000 of its common units for approximately $1 million. The partnership did not declare a distribution for the second quarter of 2020. Total consolidated capital spending for the second quarter of 2020 was $26 million, which included $22 million from the petroleum segment and $3 million from the fertilizer segment. Of this total, environmental maintenance capital spending comprised $19 million, including $16 million in the petroleum segment and $2 million in the fertilizer segment. We estimate total consolidated capital spending for 2020 to be approximately $95 million to $105 million, of which approximately $80 million to $90 million is environmental and maintenance capital. This excludes planned turnaround spending, which we estimate will be approximately $150 million to $160 million for the year. Total capitalized turnaround expenditures year-to-date were $153 million, primarily related to the Coffeyville refinery turnaround completed in April. Cash flow from operations for the second quarter of 2020 was $9 million, and free cash flow in the quarter was a use of $158 million. Total cash turnaround expenditures year-to-date were $147 million, including $125 million in the second quarter. Turning to the balance sheet, at June 30, our debt to EBITDA at the CVI level was approximately 2.8 times, excluding CVR Partners' standalone debt and EBITDA on a trailing 12-month basis. We ended the quarter with a strong cash balance of approximately $606 million on a consolidated basis, which includes $33 million in the fertilizer segment. Our net debt to EBITDA was probably 1.3 times. As of June 30, excluding CVR Partners, we had approximately $831 million of liquidity, which was comprised of approximately $574 million of cash, securities available for sale of $140 million, and availability under the ABL of approximately $393 million less cash included in the borrowing base of $275 million. Looking ahead, for our petroleum segment, we estimate total throughput for the third quarter of 2020 to be approximately 190,000 to 210,000 barrels per day. We expect total direct operating expenses for the third quarter to be approximately $75 million to $85 million and total capital spending to range between $15 million and $25 million. For the fertilizer segment, we estimate our ammonia utilization rate to be between 95% and 100%. We expect direct operating expenses to be approximately $37 million to $42 million, excluding inventory impacts, and total capital spending to be between $3 million and $6 million. With that, Dave, I will turn the call back to you.

Thanks, Tracy. The impacts of the stay-at-home orders across the country, as well as the result of the COVID-19 pandemic continue to weigh heavily on crude oil and refined products in the second 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, while controlling our costs and maintaining a strong balance sheet and liquidity position so we can be positioned to take advantage of the eventual market recovery. Inventories for crude oil, gasoline, and diesel in the U.S. are all well above five-year averages, and we think refined product inventory levels must come down significantly before we will see crack spreads materially improve. According to data from the EIA, U.S. refined product demand remains approximately one million barrels per day below pre-COVID levels for each of gasoline, diesel, and jet fuel, and refinery utilization remains under 80% on average. We do not expect the situation to change significantly anytime soon. Inventories in the Mid-Con are more in line with a five-year average, and we have seen steady increases in gasoline demands since the lows in April. As product demand has recovered, we have increased our rates at our refineries accordingly. Crude differentials currently favor running a very light crude slate, and we are running our system to maximize light crude throughputs as limited by light NAFTA processing capacity. With this light crude slate, our gasoline sulfur levels are in the five to six parts per million range, well below the tier three standard of 10 ppm. Although we saw a decline in our crude oil gathering volumes in the second quarter, production in our gathering areas has rebounded, and we are currently gathering over 120,000 barrels per day, and we expect that to go higher if crude prices continue to increase. As we continue to navigate the challenging environment, we remain focused on controlling and reducing costs wherever possible. Second quarter spending on maintenance materials, supplies, and other costs at the facilities were down approximately 15% from the second quarter of 2019. We made the difficult decision to reduce our overall headcount in June, which should result in an additional annualized savings of approximately $10 million, and we successfully reduced our sustaining capital needs with our full-year sustaining capital currently forecast at $100 million. I mentioned in our last call that we were looking at utilizing excess hydrogen capacity of the Wynnewood refinery for our renewable diesel project. I'm pleased to announce that our Board of Directors has authorized engineering studies and the preparation of the final cost estimates for the project to produce renewable diesel at the Wynnewood refinery. This project would convert an existing hydrocracker to allow for the production of renewable diesel, and also includes tanks, a rail terminal, and a staging facility. We will retain the flexibility to return the unit to hydrocarbon processing, should the economics support doing so. Our initial design includes processing capacity of 6,000 to 7,000 barrels per day and currently estimates the completion of all the components of the project to be approximately $100 million. On a per-gallon basis, we estimate total capital cost to be between $1.00 and $1.20 for renewable diesel capacity. If final approval is received, renewable diesel production could begin as soon as June 30 of '21. We are also looking at the potential of a $50 million investment to revamp the existing diesel hydrotreater to regain approximately 9,000 barrels of crude oil processing capacity while producing renewable diesel. If approved, this project could also complete approximately one year after the completion of the hydrocracker conversion to renewable diesel, or as soon as the third quarter of 2022. We will be making a decision on the renewable diesel project in September, but expect the diesel hydrotreater revamp decision to be delayed and dependent on further crack spread improvements. Looking at the third quarter of 2020, quarter-to-date metrics are as follows. Group 3 2-1-1 cracks have averaged $8.81 per barrel, with a Brent/TI spread of $2.48 per barrel, and the Midland Cushing differential of $0.39 per barrel over WTI. The WTL differential has averaged $0.05 per barrel under Cushing WTI. And the WCS differential has averaged $8.69 per barrel under WTI. As of yesterday, Group 3 cracks were at $7.74 per barrel, Brent/TI was $3.14 per barrel, and WCS was $10.13 under WTI. Quarter-to-date ethanol RINs have averaged $0.47 and biodiesel RINs have averaged $0.60. While refined products have been compressed with market volatility, RINs remain significantly overpriced and now represent an even greater negative impact on capture rates. As I said before, we believe the tenth circuit got it all wrong when they ruled to vacate three small refinery exemptions earlier this year, and we intend to appeal this misguided tenth circuit RFS ruling to the United States Supreme Court. With that operator, we're ready to take questions.

Thank you. We will now be conducting a question-and-answer session. Our first question comes from the line of Prashant Rao with Citigroup. Please proceed with your question.

Hi, this is Joe on for Prashant. Your consolidated debt to capital ratio was in the mid-50s, and it was in the mid-40s, excluding UAN. What levels are you comfortable with? And how should we think about deleveraging?

I think that right now, we are comfortable with where we're at, given the economic circumstances that we're facing. And we're going to work to maintain our cash and liquidity positions, stabilize, and wait to see when demand will recover, and then we'll address de-leveraging if necessary.

Okay. You also mentioned that the gathering volume averaged 82,000 barrels per day in the second quarter. How did it change during the quarter? And what's your long-term outlook for the gathering volume from SCOOP/STACK? Thank you.

I believe it largely depends on the absolute crude prices. Before the pandemic, we peaked at about 150,000 barrels per day of gathered crude. For the next quarter, we anticipate being in the 120,000 barrel range, and we see no reason why that shouldn't be sustainable to some extent. However, wells will age and may start to lose some capacity, which might not be compensated by new drilling to maintain those rates. As a result, if crude prices do not recover, we could see a slight decline in those barrels over the next year or two.

Thank you. I'll turn it over.

Thank you. Our next question comes from the line of Manav Gupta with Credit Suisse. Please proceed with your question.

Hey, Dave. Question more on the dividend side. I'm trying to understand the thought process behind scrapping the dividend. Was it more of a function of looking at the forward cracks and saying, okay, we're not generating enough cash here, so let's reduce the cash burn? Or more of a function of, okay, we have this renewable diesel project here, but also, we're seeing multiple refineries being shut here, and these distressed assets might just come our way, so let's just preserve the cash just in case we get a great deal in the current environment? I'm just trying to understand what really drove the process of scrapping the dividend.

I think you summarized it very well. As I mentioned in my prepared remarks, with a million barrels a day each of gasoline, diesel, and jet fuel being demanded, the cracks are just floating around off costs. If you examine their performance over the past month, they've been right around people's operating costs and generating very little income. The board viewed this situation cautiously until we have a clearer understanding of what demand will look like. I genuinely believe it has probably shifted a bit. Whether it will ever return to 9.5 million barrels a day of gasoline is uncertain, especially since many companies have transitioned to permanent remote work. It's important to note that 40% of U.S. gasoline demand is related to commuting, so even a slight change there can have a significant impact. On the other hand, there have been some announcements regarding the shutdown of certain refineries, and I anticipate there will be more, as making a decision to invest $100 million in a turnaround requires some assurance of recouping that investment within the next four years. I believe the board acted with appropriate caution and was quite enthusiastic about renewable diesel, which could lead to quick investments if we pursue it. Additionally, there are various M&A opportunities currently available, and we want to be ready to seize those if we can negotiate a favorable deal.

And a quick follow-up on the renewable diesel side. The first question I have, before all the information on the second renewable diesel, just trying to understand, do you want to do it all alone? Are you open to partnerships? Is it only going to be organic? Can you actually look at somebody who's already doing this to acquire it? I'm just trying to understand the thought process on growing renewable diesel. Is it only going to be sold organic or you're open to everything?

Well, I think we're open to everything. But the practicality of it is we're on such a short timeframe to get it done. The main part of this project really is installing the facilities to be able to bring in bean oil and take out renewable diesel to California. So, it's all rail, tank engine, and loading unloading systems for the most part. There are a couple modifications to the process unit, but not a whole lot. That’s why we think we can do it in a year, and we'll probably have multiple phases of it, just because soybean oil could net you the worst of CI or the carbon index credits that are available. But it is readily available feedstock and something you can get your hands on quick, and if it's washed, refined, and cleaned up, it's just that much less complexity you have to do to get going. Our real strategy is around the dollar blenders credit which, if you look at it, if we can get 18 months' worth of 6,000 barrels, that basically pays for the investment, plus some, and gives us optionality. In this case, we were able to run the refinery and process bean oil into renewable diesel, and there are varying degrees of opportunity cost there depending on what cracks do. We like that optionality also.

Very helpful comments. Thank you so much, David.

You're welcome.

Thank you. Our next question comes from the line of Neil Mehta with Goldman Sachs. Please proceed with your question.

Hey, team. Thanks. Thanks for taking the questions. The first one is just to build on the comments you made around M&A. Can you just talk about the landscape? I think you've been pretty public in your long-term intentions around Delek to the extent that that opportunity does materialize? But your latest stuff there? And then you've also, through the years, talked about pad four M&A as well. What is the balance sheet capacity to transact? And any latest thoughts around that?

I believe you have a good understanding of the situation regarding Delek. It's a case that offers potential opportunities, but whether anything comes of it remains uncertain. My focus is more on acquiring a pad four asset, which would provide us with better EBITDA diversity and different crack and crude spreads to enhance our portfolio, addressing what I see as our biggest weakness. I'm prioritizing that over Delek, although we need to stay open to possibilities. Regarding the balance sheet, we would need to consider the market if we pursue a deal. Until then, it's difficult to be overly concerned about it. We would likely need to make moves in that area or involve a partner taking a significant number of shares, although I’m not sure we want to go that route either. We're keeping all options available, and if a solid opportunity arises, we’ll address the financial aspects at that time.

And then the follow-up around that would be just the timeline around M&A. It's really hard and especially hard right now because it must be very difficult to physically evaluate assets. But how do you think about the timeline of execution of M&A? Do you view this as a longer-dated priority? Or is this something you're focused on in 2020?

Well, I'll tell you, I think the competition's been narrowed by the current environment, which may play to our advantage. We're not afraid of this business in any way. We think it has a future. We think people are going to drive their cars no matter what. They need gasoline and they need diesel, and that will be true for the next at least 30 years, if not longer. The current environment presents a bit of an opportunity for a company like ours that has the wherewithal and capability we have. For that reason, we're keeping all our options open.

And then, Dave, the last question for me would just be around the dividend, as a follow-up to Manav's question. As you think about the third quarter, based on the information that you have now, you're kind of halfway through the quarter at this point, is it fair to assume that there would likely be no dividend paid in the next quarter, in the fourth quarter as well because market conditions are still really challenging? Recognizing it's a board decision, but any early thoughts about that?

Now, I think you summed it up. It is a board decision. The board looks at this every quarter. Nothing's automatic in our business. I think that the board will, at the time, make the appropriate decision based on the current environment at that time. We are probably more flexible with our dividend than other companies have been in the past. That's just the nature of our shareholders and our structure. I think it depends on what other higher-return opportunities there are out there for cash. That's about as simple as the decision goes.

Great. I might have a follow-up, but I'll queue back in.

Thank you. Our next question comes from the line of Matthew Blair with Tudor, Pickering, Holt. Please proceed with your question.

Hey, good morning, Dave.

Good morning, Matt.

Hey, good morning, Dave. I just wanted to circle up on the renewable diesel side. The capital costs of $1 to $1.20 per gallon look really good compared to some competing projects we're showing in kind of the $2.50 per gallon to $3.30 per gallon range. Could you just maybe circle back and explain why is it such a low capital cost? Is it because of the excess hydrogen and if so, why do you have excess hydrogen at the plant?

We currently have an idle hydrogen plant that can produce about 10 million scuffs of hydrogen, and we also operate a CCR that generates a significant amount of hydrogen, which we use as fuel. The low cost of hydrogen is largely due to its availability and the fact that we have a relatively large hydrocracker with a complexity of around 11, which is quite intricate for a smaller refinery. By taking it out and repurposing it, we reduce our crude cutting rate to some extent, but it still allows us to be a viable refiner, helping us keep costs down. This equipment is very valuable. While processing light sweet crude, we can achieve higher profits by switching to renewable diesel. Additionally, we are simplifying our operations by sourcing Washington refined soybean oil, which has one of the lowest carbon intensity indexes and allows us to start production quickly without requiring extensive pretreatment; we can just offload it and transfer it directly to the hydrocracker. These factors significantly contribute to our low costs.

On that last point, would you have the flexibility down the road to run different feedstocks like used cooking oil or is this pretty much just going to be a soybean oil plant?

No, we've retained that. It just takes longer. What we're after is the blenders credit, which, if we can get it up by June 30, 2021, make 18 months of the blenders credit, we've got it paid off and we've got optionality. But we would leave provisions for additions to other revamps to the hydrocracker to get that rate up even higher initially but also to add pretreatment that allows us to run virtually any stock out there.

Sounds good. And then the final question just on RINs. So the RIN expense, I think you said $95 million to $105 million. Previously, I want to say that was closer to $65 million to $75 million. Could you just walk through the moving parts here? So RIN prices have moved up ever since the court decision. I would have thought that your volume obligation might have gone down just with lower demand and lower throughputs, lower production. Then also I guess the third part would be how much are you saving year-over-year due to your own internal actions to increase blending?

Well, we've increased our blending to about 25%. That was from probably 18%, 17% somewhere in that neighborhood, and that's through biodiesel blending the 5% and our baseline volume. But you're right, RVO is down some, but green costs have basically doubled since the beginning of the year. That is the main driver.

Got it? Okay, thank you.

I'd say they're way overpriced, and they are.

Thank you. Our next question will be coming from the line of Paul Chang with Scotiabank.

Hey, guys, good morning. David, I was trying to reconcile what you said earlier. It looked like your third quarter throughput is going to run at full capacity based on the guidance that you provided. But at the same time, you're saying that it is of utmost importance for the industry to bring down the product inventory to a more normal level, and right now we have way too much inventory and we have also seen news of some high company in the restarting of the economy. You also said that mean margin is nothing too spectacular. So what's the reason behind why you would be assigned to want such a high run rate?

Well, Paul, I think the bottom line on our markets is that if you look at pad two, and particularly the Magellan system, inventories are pretty normal and demand is there. We're going to fulfill that need as best we can. We're also competitively advantaged because of the gathering system we have and the light crude we process. If you look at the crude differentials, they're just not existing. A lot of analysts are always saying the Gulf Coast is better than the inland refiners. I beg to differ and say when there's no crude discount, there is no difference. I think the fact that light crude is so profitable and we're running as much light crude as we can, that is still meaning we're not up to our $2.15 or the numbers we have reached in the past. We're still cut back from that. But that's what a light slate does for you. I think we have incremental margins, even on a full cost today, and we will continue to run to meet our customer needs as they dictate.

The second question. Earlier, you mentioned that you would prefer the Pad Four asset over what DK has. You acquired the shares at a favorable low price, so congratulations on that. From that perspective, why hold onto the stock? Is there a timeline for when you might decide what to do with it, or will it be held for an extended period without a clear exit strategy? How should we view that investment?

Today, I believe we have six months to hold the stock to avoid a short sale loss, which means it will expire around mid-September 15. So, we will likely take action around that time. My preference leans towards taking action because we need a diversity of EBITDA rather than further concentrating on what Delek primarily offers, which is similar to Mid-Con, or at times Gulf Coast assets. That doesn’t significantly enhance our position. On the other hand, we see consolidation opportunities in the industry. Therefore, we are keeping all options open in every direction. Mid-September will be a crucial point for us.

Earlier you mentioned that as part of the evaluation into the renewable diesel, you could also get activated whether you do it or not. That's also another project and when would you be able to do on the early treating and be able to expand the full capacity of that refinery? So just curious about the thought process because the U.S. is already a net exporter in all ports, and gasoline is already in structural decline. And globally, likely we will be long in finding capacity. Is there any reason at all to expand the capacity, even if it is pretty cheap?

Well, remember we're losing capacity by doing the renewable diesel project, and the way we look at the economics is we assign an opportunity cost to that lost production against the renewable diesel project. If that goes to zero where it is today, I think our opportunity cost was like $0.13 a gallon on renewable diesel basis is very low. That's why I said we would not make that $50 million investment to expand the distillate hydrotreater to get crude capacity back. On the other hand, if cracks normalized and come back to where they were in 2018 and 2019, we'd be all over. It'd be a great project.

The only problem is that we really don't know, right? At the time when you make that decision, the reality is that the macro trend is not looking good for the next maybe five years, at least on the refined product side.

I can't disagree with your logic and that's why we've deferred that decision as long as possible.

Then also, David, how do you look at the window of diesel as a business? I understand why that this may be very attractive for when it would. But as a standalone business, is there any big inspiration wonder maybe as a much bigger business, and maybe even a standalone business in certain locations given that the margin is actually very good? But on the other hand, take into consideration both the demand and margin are basically government mandates and the barrier of entry is as you can see from your decision going in, you can do it pretty quick. So how should we look at yield in the long haul for you in this business? Is this just a one-off opportunistic investment or is this something far more than that?

I have a very similar thought pattern as you have, Paul. This is all government mandates. You look at the blenders credit of $1, there's nothing assured of it anytime. I don't know that we'll ever get a surety that you're going to get that every year. Except the last tax bill did have it in there until 2022. Our logic is, if we can get this project up by June 30, 2021, make 18 months of the blenders credit, we've got it paid off and we've got optionality. The other piece of it is the low carbon fuel standard. What will happen with that? A lot of other refiners are very optimistic it's going to spread everywhere. I guess it depends a little bit on the election and then what happens after the election. The thought is that California penetration of the renewable diesel right now is about 30%. There's a lot of room for more. The first hitters will get it first. Our downside is protected by our investments recovered by the blenders tax credit. That's the wave kind of unit.

Thank you.

The next question is from the line of Neil Mehta with Goldman Sachs.

Thanks. Keep on bugging you guys. I want to follow up on the crude macro here, Dave. You always have great perspectives on crude differentials. Brent-TI is very tight right now. Just how do you see that playing out in the near term and then the long term as well?

I think there are four key factors contributing to a tight Brent-TI. The first is low crude prices, followed by reduced shale oil volumes, excess pipeline capacity, and normalized tanker rates. When you combine these four elements, it results in a very tight Brent-TI. All of these factors heavily depend on crude prices and their future direction. Currently, I believe crude prices are somewhat elevated compared to global product demand, but that imbalance can adjust quickly. The level of drilling activity and whether it will increase again is directly tied to price, and something will need to change for the Brent-TI to recover.

You think about a normalized level here based on transport economics. Where's that number for you, Dave on Brent-TI?

Well, I think it's between $2.50 or really $2 and $3 I think, Neil, just because there's so much excess pipeline capacity out there that are not even recovering tariff in a lot of cases.

You're structurally, the level we're at now is the new normal for you?

I'd say until something gives. As I said geopolitical event or a hurricane or whatever it might be, all those things have a way of changing things quickly.

Okay, the last one for me is WCS differentials. Any thoughts on how it plays out from here?

Well, I think the fact that demand is as low as it is for crude and OPEC curtailments as well as heavy Canadian curtailments. The spread right now is not covering the pipeline tariff between Hardesty in the Gulf Coast. All that leads to pretty tight differentials. Frankly, the Canadian production is down, and the government is interested in getting its share. So that probably bodes to more curtailments even on their end. They haven't fully recovered from where they were pre-COVID anyway, so I don't see that changing a whole lot either. Look at the sales price in Cushing, around I think $3 today, roughly. We need probably $6 to really want to run it in our refineries. But we can make money on our pipeline space in any case.

Great. Thanks, guys.

Thank you. At this time, we've reached the end of our question-and-answer session, and I'll turn the floor back to management for closing remarks.

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, particularly during this pandemic. We look forward to reviewing our third quarter 2020 results in our next earnings call. Thank you.

Thank you. This concludes today's conference. You may disconnect your lines at this time and thank you for your participation.