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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. [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 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 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 returned and as we work towards 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 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% 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. At Coffeyville utilization, 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 used by over two million acres compared to last year. Nitrogen fertilizer prices currently remained soft, due to ample supply in the market and lower natural gas price, although cheap natural gas lowers our fee stock 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 and 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, as compared to 76% in the second quarter of 2019. Derivative gains for the second quarter of 2020 total $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 and 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 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 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 CBR 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 spendings 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 impact, 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-a- 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 can 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 very light crude slate, and we are running our system to have maximize light crude throughputs as limited by light NAFA 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 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 forecast at $100 million.
On our last call, I mentioned 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 a 6,000 barrels to 7,000 barrels per day of processing capable capacity, which currently estimates to complete all the components of the project of approximately $100 million. On a per gallon basis, we estimate total capital cost between $1.00 and $1.20 per gallon of renewable diesel capacity. The 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, 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 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. [Operator Instructions] Our first question comes from the line of Prashant Rao with Citigroup. Please proceed with your question.
Hi, this is Joe [ph] 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, and stabilize, and wait to see when demand will recover, and then we'll address de-levering 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 [ph]? Thank you.
Well, I think it's very dependent on absolute crude price for number one, but volumes come back -- before the pandemic hit, we were -- 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 120,000 barrel range. And we see no reason why that isn't sustainable to some degree. You do have depreciation -- or wells basically age and they start to lose some of their capacity. And that I don't think, we'll -- 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 year or two years if crude price doesn't recover.
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 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 this 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.
Well, I think you summarized it very well. I think, as I said in my prepared remarks, with demand a million barrels a day each of gasoline, diesel, and jet fuel, the cracks are just sitting here floating on off costs to basically. If you look at where they've been the last month has just been right at people's operating costs, frankly, and generating very little income. And I think the board looked at that as a -- 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 now stated they're going to work from 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
Offsetting that to some degree is 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 four 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 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. 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 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 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. 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, tank engine, and loading unloading systems for the most part. There are a couple 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 -- nets 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, and refined, and cleaned up, it's just that much less complexity you have to do on getting going. And our real strategy's 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 to renewable diesel, and there's varying degrees of opportunity cost there, depending on what cracks do. And we like that 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?
Well, I think, Neil, you pretty well know the story there. 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 pad four 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 that 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 I don't know that we'd want to do that either. So, I think we're keeping all our options open. And if the opportunity presents itself, we'll deal with the finance side of it.
And then the follow-up around that would be just 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. And I don't -- we're not afraid of this business in any away. We think it has a future. We think people are going to drive their cars no matter what. So, they need gasoline and 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 and capability we have. And 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 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. And 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. 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 the cash. And 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, 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. 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 why do you have excess hydrogen at the plant?
Well, you hit it primarily. We have an existing hydrogen plant that's idle today, about 10 million scuffs, but we also have a CCR that generates a lot of hydrogen and we burn today and 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 that we have a fairly large hydrocracker and that's if you look at what is its complexities around 11, which is pretty complex for a small refinery as it is. And taking that out and putting it into an alternative service means we don't have enough cutting crude rate to some degree, but not nearly -- you're still feasible as a refiner. So that keeps the cost down. 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 it with a renewable diesel. The other piece the third piece I'd say to that is that we're also keeping the complexity down here by going after Washington 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 pretreatment in, you don't have to do much of anything except offload it and charge it right to the hydrocracker. So those three things really make it cheap.
On that last point, would you have the flexibility down the road to run different feedstocks like use 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 expires at the end of 2022. So getting to market quick and fast is what we're after. But we would leave provisions for additions to other revamps to the hydrocracker to get that rate up even higher and the initial rate even higher, but also to add pretreatment that allows us to run virtually any stock out there.
Sounds good. And then the final question just on rent. So the rent 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 rent 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 increased 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 base volume. But you're right, RVO is down some, but green costs have basically doubled since the beginning of the year. So 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 provide. But at the same time, you're saying that is at most 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 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 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 disc, 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 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 to you. So I think we have incremental margins and even on a full cost today and will continue to run to meet our customer needs as they dictate.
The second question. I think earlier that you mentioned that you will want to prefer the pet for asset than what DK has. You guys purchased the share very nicely and at a very low price so congratulation on that. I mean, from that standpoint -- I mean, why hold on to the stock? I mean, is there a timeline 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 exit plan or exit timeline. How should we look at that investment?
Well, today, the timing is, I believe we have six months that we have to at least hold the stock to avoid short sale loss, which is I think September -- call it mid-September 15 that expires. So I think you'll see us take action either one way or the other around that time. I think I favor ahead for the reasons I stated is really 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 in each and every direction. But mid-September will be a pivot point.
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 that you may be able to do on the early treating and be able to expand the full capacity of that refinery. So just curious that the thought process because U.S. is already a net exporter on 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 loss production against the renewal 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, and at the time when you make that decision, and that 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 that, David how you look at the window of both diesel as a business. I understand why that this may be very attractive for when it would. But as a standalone business that the long haul, do you have big inspiration wonder maybe as a much bigger business, and maybe even a standalone business in certain location given that the margin is actually very good. But on the other hand, take into consideration both the demand and margin are basically government mandate and the barrier of entry is as you can see from your decision going in, you can do it pretty quick. It's quite low. So how should we look at yield in the long haul for you in this business? Is this just one-off opportunistic investment or that this is something far more than that?
I have 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 for until 2022. Our logic is, well we can pay this project out this $100 million out in 18 months of gathering that dollars blenders credit. So it gives us optionality to play on 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, 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. But the thought is that California penetration of the RD right now is about 30%. There's a lot of room for more. And the first hitters will get there 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 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 the long term as well?
Well, I think on the Brent-TI I can give you four parameters that result in a tight Brent-T. Low crude price is number one. Depressed shale oil volumes, excess pipeline capacity, and normalize tanker rates. You put all four of those together and you get a very tight Brent-TI. 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 the demand for products worldwide. But that has a way of correcting itself rather quickly too. They're drilling and whether it'll pick up again, this is all a function of that price and that's where the Brent-TI has -- for it to recover, something has to give.
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. 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, around I think $3 today, roughly. There 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 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.