CVR Energy Inc (CVI) 2020 Q2 法說會逐字稿

Greetings, and welcome to the CVR Energy, Inc. Second Quarter 2020 Conference Call. (Operator Instructions) 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 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. The disclosures related to such non-GAAP measures including reconciliation to the most directly comparable GAAP financial measures 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 a 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 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 that it was prudent to preserve liquidity while we wait for refined product demand return and as we work towards the 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 in -- 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 as 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 as 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 as 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% 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 as 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. The 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 2 million acres compared to last year. Nitrogen fertilizer prices currently remained 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 noncash goodwill impairment of $41 million in the Fertilizer segment and a mark-to-market gain of $18 million and dividends of $3 million related to our investment in Delek as well as favorable inventory valuation impact 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 narrow crack frac 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 as 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 year period due to our efforts to lower costs as we work to phase in our $50 million targeted savings in operational and SG&A 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 noncash 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 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 and 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 2.8x, excluding CVR partners' stand-alone 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 approximately 1.3x. 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 to $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 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 the 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 5-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 1 million barrels per day below pre-COVID levels for each of gasoline, diesel and jet fuel and refinery utilization remained 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 the 5-year average and we have seen steady increases in gasoline demand since the lows in April. As product demand has recovered, we have increased our rates at our refineries accordingly. Crude differentials currently favor running very light crude slate, and we are running our system to maximize light crude throughputs as limited by light naphtha processing capacity. With this light crude slate, our gasoline sulfur levels are in the 5 to 6 parts per million range, well below the Tier 3 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 spend on maintenance materials and 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 forecasted at $100 million.

On our last call, I mentioned that we were looking at utilizing excess hydrogen capacity at 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 a 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 economic support doing so. Our initial design includes the 6,000 to 7,000 barrels per day of processing capacity, which currently estimates to complete all the components of the project of current estimates to complete all components of the project of approximately $100 million.

On a per gallon basis, we estimate total capital costs between $1 and $1.20 per gallon of renewable diesel capacity. If the final approval is received, renewable diesel production could begin as soon as June 30 of '21. We also -- 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 be complete -- could also complete approximately 1 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 to capture rates.

As I said before, we believe the Tenth Circuit got it all wrong when they ruled to vacate 3 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.

(Operator Instructions) Our first question comes from the line of Prashant Rao with Citigroup.

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 position and stabilize, and wait to see when demand will recover. And then, we'll address delevering, 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?

Well, I think it's very dependent on absolute crude price for number one. But volumes come back, we -- before the pandemic hit, we were -- we -- the highest number we had reached is about 150,000 barrels per day of gathered crude. We're estimating that next quarter, we should be in the 120 million -- 120,000 barrel range, and we see no reason why that isn't sustainable to some degree. You do have depreciation -- wells basically age and they start to lose some of their capacity. And that, I don't think, will probably not going to keep up with new drilling to maintain those rates. So there might be a slight decline in those barrels over the next 1 year or 2 years, if crude price doesn't recover.

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

Dave, question more on the dividend side. I'm trying to understand the thought process, scrapping the dividend, was it more of a function of you're looking at the forward cracks and saying, okay, we're not generating enough cash share, so let's reduce the cash burn? Or more -- was it a function of, okay, we have this renewable diesel project there, but also we are seeing multiple refineries being shut here, so -- and this distressed asset 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?

Well, I think you summarized it very well. I think, as I said in my prepared remarks, with demand down 1 million barrels a day each of gasoline, diesel and jet fuel, the cracks are just sitting here floating on op cost, basically. If you look at where they've been the last month, it's just been right at people's operating cost, frankly, and generating very little income. And I think the Board looked at that as a -- as -- until we can get a better feeling of what demand is going to be, and I truly believe it's probably changed a bit. Will it ever come all the way back to 9.5 million barrels a day of gasoline, I don't know? There's a lot of companies that are working from home and have now stated they're going to work for home permanently.

And you got to remember that 40% of the U.S. demand of gasoline is commuting back and forth to work or some variation of that. So a little bit of impact there can make a long time. And offsetting that to some degree as there's been some announcements of shutdowns of some refineries, which I expect there to be more. Just because when you have to make a decision to spend $100 million on a turnaround, you want to have some idea that you're going to recoup some of that in the next 4 years of that turnaround life. So I think the Board was appropriately cautious, and they were pretty excited about renewable diesel, and that will be a fast spend if we do it. And just some of the other M&A opportunities that are out there, I think, are teed up quite well, and we want to be in a position to jump on those, should they -- should we be able to cut a deal.

And a quick follow-up on the renewable diesel side. On the second, renewable diesel, just trying to understand, do you want to do it all alone? Are you open to partnership? 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 an 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 time frame to get it done. It's not a -- 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, tankage and loading and unloading systems for the most part. There are a couple of modifications to the process unit, but not a whole lot. So that's why we think we can do it in a year. And we'll probably have multiple phases of it just because bean oil is probably the -- it nets you the worst of CI or the carbon index credits that are available, but it is rarely available feedstock and something you can get your hands on quick and if it's washed and refined and cleaned up, it's just that much less complexity you have to do on getting going. And 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, it basically pays for the investment plus some, and gives us optionality. In this case, we're able to run the refinery and process bean oil to renewable diesel. And there's varying degrees of opportunity cost there depending on what cracks do, and we like that optionality also.

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

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 thoughts there? And then you've also, through the years, talked about PADD IV M&A as well, what is the balance sheet capacity to transact? And any latest thoughts around that?

Well, I think, Neil, you pretty well know the story there. The Delek is an opportunistic case. Something may come of it, something may not. You probably know my -- well, my recommendation would be more to a PADD IV asset that gives us EBITDA diversity and a different set of crack spreads and crude spreads to add to our portfolio, which is probably our greatest weakness. So I would tell you, I'm much more focused on that than I am on anything with Delek, but you never know what can come up on the other hand. So we're trying to maintain all optionality and keep it open. As far as the balance sheet goes, I think we'd have to approach to debt market if we did some kind of deal. How we do it, until we get there, it's hard to worry about it too much. But I think we'd have to do something to that area or the partner take a significant number of shares, but don't know that we'd want to do that either. So I think we're keeping all our options open, and we'll -- if the opportunity presents itself, we'll deal with the finance side of it.

And then the follow-up around that would be just time line 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 time line 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'd tell you that I think the competition has been narrowed by the current environment, which may play to our advantage. And I don't -- 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. So they need gasoline, they need diesel, and that will be true for the next at least 30 years, if not longer. So I think the current environment presents a bit of an opportunity for a company like ours that has the wherewithal capability we have. And for that reason, that, we're keeping all our options open.

And then Dave, the last question for me would just be around the dividend as followed to Manav's question. As you think about the third quarter, based on the information that we -- 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 forward quarter, as well because market conditions are still really challenging, recognizing it's a Board decision, but any early thoughts about that?

Yes, I think you summed it up. It is a Board decision. The Board looks at this every quarter. Nothing's automatic in our business. And I think 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, and that's just the nature of our shareholders and our structure. And I think it depends on what other higher return opportunities there are out there for the cash and that's about as simple as the decision goes.

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

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

Well, you hit on primary. We have an existing hydrogen plant that's idle today, about 10 million scf. But we also have a CCR that generates a lot of hydrogen that we burn today in fuel. So part of the reasons it's so cheap is that all availability of that hydrogen. But also add that the other piece of it is, is that, we have a fairly large hydrocracker and that's -- if you look at Wynnewood, its complexity is around 11, which is pretty complex for as small as a refinery as it is. And taking that out and putting it into an alternative service, means we don't have to. We have cutting crude rate to some degree, but not near -- you're still feasible as a refiner, so that keeps the cost down. It's just -- it's a hell of a piece of hardware that sits there. For what we're doing with it running a light sweet crude, we can make more money with renewable diesel. And the other piece, the third piece I'd say to that is that we're also keeping the complexity down here by going after washed and refined soybean oil, which gives you probably the lowest CI, carbon intensity index, but it also gives you the ability to get up and running quick. You don't have to put treat treatment in. You don't have to do much of anything except offload it and charge it right to the hydrocracker. So those 3 things really make it cheap.

And 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. So what we're after is the blenders credit, which expires at the end of '22. So getting to market quick and fast is what we're after. And -- but we would leave provisions for additions to other revamps to the hydrocracker to get that rate up even higher and the initial rate up even higher, but also to add pretreatment that allow us to run virtually any stock out there.

Sounds good. And then the final question, just on RINs. So the RINs expense, I think you said $95 million to $105 million. Previously, I want to say that was closer to 65% to 75%. 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 throughput, lower production. And 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% in our base volume. But you're right, RVO is down some. But RIN costs have basically doubled since the beginning of the year, so that is the main driver. I said they're way over priced than they are. So…

Our next question will be coming from the line of Paul Cheng with Scotiabank.

Dave, I'm trying to reconcile what you have said earlier. It looked like your third quarter throughput is going to run at full capacity based on the guidance that you provide. But at the same time, you're saying that, it's utmost important 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 also have seen news of some hike up in the restarting of the economy, so -- and you also said that, I mean, margin is nothing too spectacular. So what's the reason behind why you will decide to run such a high run rate?

Well, Paul, I think the bottom line in our markets, if you look at Pad II 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 nonexistent. And 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 disk, there is no difference. So 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 at our 215 or the numbers we have reached in the past. We're still cut back from that, but that's what a light slate does to you. So I think we have variable -- we have incremental margin even on a full cost today, and we'll continue to run to meet our customer needs as they dictate.

Second question, Dave, I think earlier that you mentioned that you will be -- want a bigger PADD IV asset than what DK has. You guys purchased a share very nicely and have at a very low price. So that -- congratulations on that. But I mean, from that standpoint, I mean, when he wanted to stop? I mean, is there a time line that you guys may decide what you're going to do with that? Or that is just going to hang on there for a very, very extended period of time and there's really no extra time or extra time line, how should we look at that investment?

Well, today, the timing is -- I believe we have 6 months that we have to at least hold the stock to avoid…

Short sale loss.

Short sale loss, which is, I think, September…

Mid-September.

Call it mid-September, 15th, that expires. So I think you'll see us take action either one way or the other around that time. I think I favor of PADD IV for the reasons I stated is really is we need diversity of EBITDA more than we need additional concentration of what I would call, what Delek is largely Mid-Con or very similar to Mid-Con, even sometimes Gulf Coast. That does really not do a lot to move our equation. On the other hand, consolidation in the industry, we think there's opportunities around that. So I think we're keeping all options open at each and every direction, so but September -- mid-September will be a pivot point.

And earlier, you mentioned that as part of the evaluation into the renewable diesel, you could also -- if you -- actually -- that whether you do it or not. There's also another project in Wynnewood that you may be able to do on the -- how you treating and be able to expand the full capacity of that refinery? So just curious the thought process because U.S. is already a net exporter on all products. And gasoline is already in structural decline. And globally, they look like we would be long in refining capacity, so is there any reason at all to expand the capacity even, yes, 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 of that lost production against the renewable diesel project. If that goes to 0 and where it is today, I think our opportunity cost is like $0.13 a gallon on a renewable diesel basis, it's very low. That's where 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 normalize and come back to where they were in '19, '18 and '19, we'd be all over it. It'd be a great project.

Yes. The only problem is that we really don't know, right? And at the time when you make that decision and that the margins that -- the macro trend is not looking good for the next maybe 5 years, at least on the byproduct side?

I don't -- I can't disagree with your logic, and that's why we've deferred that decision as long as possible and we are not -- we will not proceed…

And then also that, David, how do you look at the renewable diesel as a business. I understand why that this may be very attractive for Wynnewood, but as a stand-alone business that on the long haul, do you have the inspiration? You want to make it as a much bigger business and maybe even a stand-alone business in certain locations, given that the margin is actually very good. But on the other hand, taking into consideration both the demand and margin are basically government mandate and the barrier of entries, as you can see from your decision going in, you can do it pretty quick. It's quite old. So how should we look at it in the long-haul for you in this business? Is this just one-off opportunistic investment or that this has something far more than that?

I'm very -- I have a similar thought pattern as you have, Paul, this is all a government mandate. 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 that the last tax bill did have it in there for until '22. And our logic is, well, we can pay this project out, this $100 million out by -- in 18 months of gathering that dollar's blenders credit. So it gives us optionality to play in this space. And we have the spare hydrogen with nothing to do with it. We're running a light crude slate at Wynnewood. And we won't have -- we have very little future to use that in any way, shape or form, so this monetizes that asset a bit.

So I don't think if we can get it up by June 30, '21, make 18 months of the blenders credit, we've got it paid off and we've got optionality. And 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, then what happens out of the election. But the thought is that California penetration of R&D right now is about 30%. There's a lot of room for more. And the first hitters will get there first. And our downside is protected by our investments recovered by the blenders tax credit. That's the way of kind of viewing it.

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

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

Well, I think on the Brent TI, I could give you 4 parameters that result in a tight Brent TI: low crude price is number one, depressed shale oil volumes, excess pipeline capacity and normalized tanker rates. You put all those 4 of those together and you get a Brent -- a very tight Brent TI. And I think a lot of those, just all of them really depend on the price of crude and where it goes from here. Frankly, right now, I think it's a little overpriced based on just demand for products, worldwide. But that has a way of correcting itself rather quickly, too. And they're drilling, whether it will pick up again. It is all a function of that price. And that's where the Brent TI has to -- for it to recover, something has to give.

And you think about a normalized level here based on transport economics, where is that number for you, Dave, on Brent TI?

Well, I think it's between $2.50 and -- 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.

So you think you're -- structurally, the level we're at now is the new normal for you?

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

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

Yes. Well, I think the fact that demand is as low as it is for crude and OPEC curtailments as well as heavy Canadian curtailments. That -- the spread right now is not covering the pipeline tariff between the Hardesty and 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. And 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 of around, I think, $3 today, it's roughly there. We need probably $6 to really want to run it in our refineries, but we could make money on the pipeline -- our pipeline space in any case.

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, commitment towards safe, reliable, environmentally responsible operations, particularly during this pandemic. We look forward to reviewing our third quarter 2020 results and 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.