CVR Energy Inc (CVI) Q1 2021 Earnings Call Transcript

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CVR Energy Inc (CVI -0.57%)
Q1 2021 Earnings Call
May 4, 2021, 1:00 p.m. ET

Contents:

• Prepared Remarks
• Questions and Answers
• Call Participants

Prepared Remarks:

Operator

Greetings, and welcome to the CVR Energy First Quarter 2021 Conference Call. [Operator Instructions] It is now my pleasure to introduce your host, Richard Roberts, Senior Manager, Financial Planning and Analysis, Investor Relations. Thank you, sir. You may begin.

Richard Roberts -- Investor Relations

Thank you, Christine. Good afternoon, everyone. We very much appreciate you joining us this afternoon for our CVR Energy First Quarter 2021 Earnings Call. With me today are Dave Lamp, our Chief Executive Officer; Tracy Jackson, our Chief Financial Officer; and other members of management.

Prior to discussing our 2021 first 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. Let me also remind you that CVR Partners completed a 1 for 10 reverse split of its common units on November 23, 2020. Any per unit references made on this call are on a split adjusted basis. 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 2021 first quarter earnings release that we filed with the SEC on Form 10-Q for the period and will be discussed during the call.

With that said, I'll turn the call over to Dave.

David L. Lamp -- Chief Executive Officer and President

Thank you, Richard. Good afternoon, everyone. Thank you for joining our earnings call. Yesterday, we reported a first quarter consolidated net loss of $55 million and a loss per share of $0.39. Unplanned downtime and increased operating costs associated with the winter storm negatively impacted our first quarter results by approximately $41 million. Our earnings for the quarter were further impacted by a noncash mark-to-market on our 2020 RIN obligation of $98 million.

Our Board of Directors did not approve a dividend for the first quarter of 2021. However, we recognize the absence of any major transactions, we have more cash on the balance sheet currently that we need to operate the business. We will continue our discussions with the Board around the best uses of our cash and the appropriate level of cash to return to shareholders in and what form.

For our Petroleum segment, the combined throughput for the first quarter of 2021 was approximately 186,000 barrels per day as compared to 157,000 barrels per day for the first quarter of 2020, which was impacted by the planned turnaround at Coffeyville. We experienced unplanned downtime at both facilities in February as a result of the winter storm, which reduced total throughput for the quarter by approximately 34,000 barrels per day. Both plants resumed full operations in March and are currently running at max light crude rates.

Benchmark crack spreads have increased since the beginning of the year, however, elevated RIN prices continue to consume much of that increase in the cracks. The Group 3 2-1-1 crack averaged $16.33 per barrel in the first quarter as compared to $12.21 for the first quarter of 2020.

On a 2020 RVO basis, RIN prices averaged approximately $5.57 per barrel in the first quarter, a 250% increase from the first quarter of 2020. The Brent-WTI differential averaged $3.18 in the first quarter compared to $5.04 per barrel in the prior year period. The Midland Cushing differential was $0.87 per barrel over WTI in the quarter compared to $0.06 per barrel under WTI in the first quarter of 2020. And the WCS to WTI differential was $11.82 per barrel compared to $17.77 for the same period last year. Light product yield for the quarter was 100% on crude oil processed and current economics dictate maximizing gasoline.

In total, we gathered approximately 112,000 barrels per day of crude oil during the first quarter of 2021 compared to 136,000 barrels per day for the same period last year. Gathering volumes for the first quarter were negatively impacted by the severe winter weather in the Midwest in February. With the Oklahoma pipelines we recently acquired, our gathering volumes are trending higher. We currently forecast our gathering volumes for the second quarter to be in the 125,000 to 130,000 barrel a day range.

In our Fertilizer segment, we experienced some unplanned downtime at Coffeyville doing an outage of the third-party air separation unit in January. At East Dubuque, we elected to shut in for several days as a result of the severe winter weather in February. Ammonia utilization for the first quarter was 87% at Coffeyville and 89% at East Dubuque. Along with a rally in crop prices this year, fertilizer prices have increased significantly, which should be more evident in the Fertilizer segment's second quarter results. With the USDA estimating corn planning this year of 91 million acres, the 2020 inventory carryout could be at the lowest level since 2014. This should set up for continued strength in crop prices, which will be a positive for the fertilizer demand and pricing as well.

Now let me turn the call over to Tracy to discuss some additional financial highlights.

Tracy D. Jackson -- Executive Vice President and Chief Financial Officer

Thank you, Dave, and good afternoon, everyone. Our consolidated net loss of $55 million and loss per diluted share of $0.39 includes a mark-to-market gain of $62 million related to our investment in Delek and favorable inventory valuation impact of $66 million. The effective tax rate for the first quarter 2021 was a benefit of 43% compared to a benefit of 27% for the prior year period, primarily due to state income tax credits. We continue to anticipate an income tax refund related to the CARES Act of $35 million or $40 million, which we expect to receive in the second half of 2021. The Petroleum segment's EBITDA for the first quarter of 2021 was negative $61 million, which included an inventory valuation benefit of $66 million. This compares to EBITDA of negative $77 million in the first quarter of 2020, which included unfavorable inventory valuation impact of $136 million.

Excluding inventory valuation impacts in both periods, our Petroleum segment EBITDA would have been negative $127 million for the first quarter of 2021 compared to positive $59 million in the prior year period. The year-over-year EBITDA decline was driven primarily by the elevated RINs prices and our open RIN position, unrealized derivative losses and increased operating expenses associated with winter storm Uri. In the first quarter of 2021, our Petroleum segment's refining margin, excluding inventory impacts, was negative $0.88 per total throughput barrel compared to $11.06 in the same quarter of 2020.

The increase in crude oil and refined product prices through the quarter generated an inventory valuation benefit of $3.93 per barrel, this compares to a $9.54 per barrel unfavorable impact in the same period last year. Excluding inventory valuation impact, unrealized derivative gains and losses and the mark-to-market impact of our 2020 RIN obligation, the capture rate for the first quarter of 2021 was 46% compared to 86% in the first quarter of 2020. In addition, RINs expense reduced our capture rate by 65% in the first quarter of 2021, which includes a 36% impact related to the mark-to-market of our 2020 RIN obligation.

Derivative losses for the first quarter of 2021 totaled $32 million, which includes unrealized losses of $43 million, primarily associated with frac spread derivatives, offset by gains on Canadian Crude Oil. In the first quarter of 2020, we had total derivative gains of $46 million, which included unrealized gains of $12 million. RINs expense in the first quarter of 2021 was $178 million or $10.62 per barrel of total throughput compared to $19 million or $1.32 per barrel for the same period last year. Our first quarter RINs expense was inflated by $98 million from the mark-to-market impact related to our 2020 accrued RFS obligation, which was mark-to-market at an average RIN price of $1.39 at quarter end.

Our accrued RFS obligation at the end of the first quarter continues to approximate our 2019 and 2020 obligations at Wynnewood, for which labors have been applied. We believe Wynnewood's obligation for 2021 should be exempt under the RFS regulation; for the full year 2021, we forecast a net obligation of approximately of 230 million RINs without considering waivers yet inclusive of the RINs we expect to generate from the renewable diesel production in the second half of the year.

The Petroleum segment's direct operating expenses were $5.89 per barrel in the first quarter of 2021 as compared to $5.87 per barrel in the prior year period. On an absolute basis, operating expenses increased approximately $15 million compared to the first quarter 2020, primarily due to higher natural gas costs that are currently in dispute and additional repair and maintenance expenditures related to winter storm Uri.

For the first quarter of 2021, the Fertilizer segment reported an operating loss of $14 million, a net loss of $25 million or $2.37 per common unit and EBITDA of $5 million. This is compared to first quarter 2020 operating losses of $5 million, a net loss of $21 million or $1.83 per common unit and EBITDA of $11 million.

The year-over-year decrease in EBITDA was driven by lower sales volumes of UAN and ammonia and lower UAN sales prices. During the quarter, CVR Partners repurchased just over 24,000 of its common units for $0.5 million. The partnership did not declare a distribution for the first quarter of 2021.

Total consolidated capital spending for the first quarter of 2021 was $68 million, which included $10 million from the Petroleum segment, $3 million from the Fertilizer segment and $55 million from the Renewables segment.

Environmental and maintenance capital spending comprised $12 million, including $10 million in the Petroleum segment and $2 million in the Fertilizer segment. We estimate total consolidated capital spending for 2021 to be approximately $235 million to $250 million, of which approximately $106 million to $114 million is expected to be environmental and maintenance capital and $123 million to $128 million is related to the renewable diesel project at Wynnewood. Our consolidated capital spending plan excludes planned turnaround spending, which we estimate to be approximately $9 million for the year in preparation for the planned turnaround at Wynnewood in 2022 and Coffeyville in 2023.

Cash provided by operations for the first quarter of 2021 was $96 million. Despite elevated natural gas and utilities cost, increased capital spending and closing on the Oklahoma pipeline acquisition, we generated free cash flow in the quarter of $61 million. Working capital was a source of approximately $218 million in the quarter due to an increase in our RINs obligation and an increase in lease pre payable.

Turning to the balance sheet. At March 31, we ended the quarter with approximately $707 million in cash, an increase of $40 million from the end of 2020. Our consolidated cash balance includes $53 million in the Fertilizer segment. As of March 31, excluding CVR Partners, we had approximately $1 billion of liquidity, which was comprised of approximately $655 million of cash, securities available for sale of $235 million and availability under the ABL of approximately $364 million less cash included in the borrowing base of $208 million.

Looking ahead to the second quarter of 2021, for our Petroleum segment, we estimate total throughput to be approximately 200,000 to 220,000 barrels per day. We expect total direct operating expenses to range between $75 million and $85 million and total capital spending to be between $6 million and $12 million. For the Fertilizer segment, we estimate our ammonia utilization rate to be greater than 95%. We expect direct operating expenses to be approximately $35 million to $40 million, excluding inventory impacts and total capital spending to be between $4 million and $7 million.

Capital spending in the Renewables segment is expected to range between $65 million and $70 million.

With that, Dave, I will turn the call back to you.

David L. Lamp -- Chief Executive Officer and President

Thank you, Tracy. In summary, the first two months of the quarter were challenging as crack spreads were narrow and the winter storm caused unplanned downtime and elevated operating expenses. We quickly recovered from the storm-related shutdowns. And with the increase in the Group 3 cracks, we have observed positive EBITDA trends in March, absent the 2020 mark-to-market impact for RINs.

I would like to thank our employees for all their hard work during the winter storm to quickly return both refineries and fertilizer operations to full capacity safely. We continue to believe we are well positioned for the eventual upswing in the refining market.

Looking at current market fundamentals, cracks have increased since the beginning of the year and have largely sustained higher levels, although inflated RIN prices have consumed part of that increase. Vaccine data is encouraging, and we're seeing positive increases in demand for gasoline, diesel and jet fuel. Refinery shutdowns in February and March helped further clean up domestic inventories, however, fleet utilization is increasing.

In the near term, we remain cautiously optimistic based on the market fundamentals we see. Starting with crude oil, global inventories are at or near 5-year averages and worldwide demand is projected at 96 million barrels per day for 2021, according to OPEC, a year-over-year increase of 6 million barrels per day. Shale oil production is up slightly in the Permian Basin, but down everywhere else, and DUCs continue to decline. E&P companies are currently focused on shareholder return and debt reduction and not on ramping up activities to significantly increase production volumes. And backwardation is firmly in place, supported by declines in inventories and the action taken by the Saudis.

Moving on to refined products. Inventories are largely normalized in the US, helped in part by the shutdowns after the winter storm. US gasoline demand was up significantly in March and held through April. Refining product demand in PADD II is back to 2019 levels, while PADD II gasoline and diesel inventory levels are both below 5-year averages. Passenger count and TSA checkpoint check-ins are higher, but still down over 40% compared to pre-pandemic levels and the imports of gasoline and diesel are higher while exports of both products are lower than a year ago.

Looking at the current crack spreads and crude differentials. Gasoline cracks are strong, but diesel cracks are low due to depressed jet fuel demand. US refining throughput is down over 1 million barrels per day versus the 5-year average, although EIA reported utilization stats are distorted due to permanent refinement closures and reduced operable capacity. And RINs remain high, driven by government inaction and regulatory uncertainty.

For the CVR refining system, we continue to run our refineries at max rates on a light crude diet. Our gathering system rates are increasing with the addition of the Oklahoma pipeline system, which provides more neat barrels to our refineries and reduces our purchases of Cushing common. We are maximizing the production of premium gasoline and the blending of biofuels, and we do not have any turnaround scheduled for 2021. For the Fertilizer segment, the USDA is projecting 91 million acres of corn planted this year. At current yield estimates, the inventory carryout for '21 could be the lowest since 2014.

Crude inventories are already very low, which has driven the prices higher. The recent winter storm cleaned up excess fertilizer inventories in the Mid-Con as many nitrogen fertilizer plants had to shut in. The spring run has been strong, and NOLA urea price is around 200 -- excuse me, $385 per ton with UAN at nearly $300 per ton. Our net debt[Phonetic] prices have dramatically improved for nitrogen fertilizers by about 40% compared to the first quarter of 2021 levels. We are working hard on 45Q tax credits for the Coffeyville facility, which could provide incremental cash for CVR Partners to delever, and we have a planned turnaround at Coffeyville in October.

Construction is under way at our Wynnewood renewable diesel unit, however, severe weather in February and delays in equipment deliveries, we are now projecting the unit to be online by the end of the third quarter. Costs are also being affected by weather delays and material escalations. We currently expect total cost of the project to be $135 million to $140 million. We have made significant progress and have recently signed agreements for feedstock supply and terminalling, and we are in negotiations on product marketing.

Despite the recent increase in feedstock prices, higher prices for diesel and RINs have partially offset the increase in the renewable diesel feedstocks. In addition, we now believe we'll be able to run the Wynnewood refinery at higher rates post renewable diesel conversion than we previously expected. As we work toward the completion of Phase 1, we are close to selecting technology for a potential Phase 2, which would involve adding pretreatment capabilities for lower cost and lower CI feedstocks. We are also starting a feasibility study for Phase 3 of developing a similar renewable diesel conversion project at Coffeyville and we are exploring the opportunities to add biomasses of feedstock to one or both of our refineries to aid in our sustainability efforts.

Looking at the second quarter of 2021, quarter-to-date metrics are as follows: Group 3 2-1-1 cracks have averaged $19.48 per barrel with RINs averaging $6.92 on a 2020 RVO basis. The Brent-TI spread has averaged $3.62, with the Midland Cushing differential at $0.36 over WTI and the WTL differential at $0.14 per barrel under WTI, Cushing WTI and a WCS differential of $11.29 per barrel under WTI. Ammonia prices have increased to over $600 a ton, while UAN prices are over $325 per ton. As of yesterday, Group 3 2-1-1 cracks were $20.26 per barrel; Brent-TI was $3.07 And WCS was $11.90 under WTI. On a 2020 RVO basis, RINs were approximately $7.83 per barrel.

The Supreme Court heard arguments in our appeal in the Tenth Circuit ruling last week. We feel our attorney was very effective in expressing the intent of Congress that no small refinery should go bankrupt from the impact of RFS compliance and the small refineries like ours with a high diesel output, remote location, lack of meaningful retail and wholesale infrastructure are entitled to relief at any time. We expect to hear a ruling over the next few months, after which EPA might finally provide a renewable volume obligation for 2021. The EPA has also yet to rule on 2019 and 2020 small refinery exemptions. The lack of action by EPA regarding these issues has likely contributed to the dramatic increase in RIN prices over the past year.

Fortunately, our consolidated RIN obligation should become much less of a burden with the completion of the Wynnewood renewable diesel unit later this year.

With that, operator, we're ready for questions.

Questions and Answers:

Operator

[Operator Instructions] Our first question comes from the line of Manav Gupta with Credit Suisse.

Manav Gupta -- Credit Suisse -- Analyst

Hey, guys. My question here is, again, you have been making a very effective case for small refineries. And I mean, I think a lot of people understand the pain that small refiners feel here. But for some reason, it looks like EPA doesn't really want to even look at it. I think a few days ago, there was a news that there were three small refinery exemptions given to Sinclair, and EPA has gone back and said they will void that.

So now they're going back and looking at some of the small refinery exemptions that were given and trying to void those. I just wanted your comments on this, like does this actually make any sense to take away the SREs that have already been issued?

David L. Lamp -- Chief Executive Officer and President

Well, Manav, I would say that EPA is doubling down on their reversal of 10 years of applying the RFS in one direction to a new direction now, which will do nothing but lead to higher gasoline and diesel prices for the nation and all consumers. It's hard to understand what the logic is other than the new green push is it needs elevated prices for petroleum products to really make the substitutes more attractive. And I can't think of any other reason than that. This is totally unfair.

In my opinion, they would take away something that -- and the Sinclair case is kind of a special case from the standpoint that they had a settlement back when Sinclair sued because they were denied small refinery waivers unjustly and won. And now EPA went back and reversed all that and granted them the waivers they were deserving and now a new administration comes in and changes it. It just shows that the whole RFS is a political process that is out of control and needs to be revised and changed toward free -- it's fair for everyone.

Manav Gupta -- Credit Suisse -- Analyst

That's very fair, Dave. I just have one follow-up question here. Things are obviously, as you indicated, looking good for your renewable diesel facility, Phase 1, maybe Phase 2 at some point. We have seen some strong feedstock cost escalation in one of the feedstocks that you are planning to run. So is CVI looking to secure some of its feedstocks, are you looking at some alternate feedstocks, covered crops, corn oil, is this how will you try and mitigate this sudden headwind that we are seeing in soybean oil prices? And I'll leave it there.

David L. Lamp -- Chief Executive Officer and President

Sure, Manav. I think, first, I'd say in my prepared remarks, I mentioned that we have -- we're very close to selecting the technology for the Phase 2, which is the pre treater. And that will give us the flexibility to run just about anything, including corn oil, tallow, unused cooking oil, although there may not be much availability of that. Still the big swing in all these new units, the large volume is soybean oil. I think you got to look at it from the standpoint of today, a lot of soybean oil goes into biodiesel. And that will be, in my opinion, reverted back to renewable diesel because of the fact that the CI and the improvement as well as the 1.7 RINs compared to 1.5. And it will just take time for the market to adjust to that reality.

What happened in the last couple of months is you had several large or two large RD units come on, Marathon Dickinson and then Phillips 66 in California. And the market has not readjusted to that reality. You look at the bean oil futures, and they're very backwardated. First 2 months, I think it drops from -- in the mid-60s to the low-50s. And that will be the time frame that we're looking at to start securing feedstock for this unit.

Manav Gupta -- Credit Suisse -- Analyst

Thank you so much.

Operator

The next question comes from the line of Prashant Rao with Citigroup. Please proceed with your question.

Prashant Rao -- Citigroup -- Analyst

Hi. Good afternoon. Thanks for taking the question. To follow-up there, Dave, on -- now that Phase 1 for Wynnewood looks like end of 3Q, but you're close to picking the technology provider or how you're going to go about Phase 2 of the project? That's right, Phase 1 being moved to 3Q, and now you're looking at Phase 2.

Is there any way in terms of timing to pull up the pretreatment, especially in this environment where we're at elevated RINs and elevated feedstock costs. How should we be thinking about timing of Phase 2? I think originally, the plan was sort of more toward the end of next year, but is there some flexibility in that in terms of accelerating that?

And then I have a follow-up on feedstocks.

David L. Lamp -- Chief Executive Officer and President

Well, the technology we're looking at is not particularly difficult to build. It does take some certain amount of alloys type metals. But we're thinking 18 months from the day we say go, we should be able to have it up and online. So it's still that same time frame we talked about before, but it's very doable in that time frame.

Prashant Rao -- Citigroup -- Analyst

Would you still do your projects of Phase 1, Phase 2 in Wynnewood and then look at Coffeyville? Or could there be some overlap given that Wynnewood has fallen back by a quarter and where the economics are that you might want to start-up Coffeyville before you finish -- or as you're finishing up Phase 2? Sort of, just kind of thinking about overall time line of the total asset base, if there's a way that we first ramp that up maybe a bit faster here?

David L. Lamp -- Chief Executive Officer and President

Yes. As I mentioned in the prepared remarks, we're starting a feasibility study, which is basically the process engineering for a conversion at Coffeyville. That's a modest amount of money, and that gives us a head start to have the design complete should we elect to do it. I will caution, though, on the other hand, I think as most of you, I think, are quickly pointing out that California is getting saturated with this stuff, although there are imports coming in, it's still the best in highest net back of anywhere in the world, I believe, from a low-carbon fuel standard standpoint, even though Washington just voted it in, I believe, and Oregon starts in '22. We need something more to happen that's broader and more nationwide, frankly, with the number of new units that are coming on to really be able to place this material at an advantage.

I think there is a reset on the RFS in '22 and EPA is asking for comments on that. There are people that are supporting going nationwide on the low carbon fuel standard to replace that, which is probably a more fair way to do it because it does look at CI as opposed to ethanol blends and biodiesel blends and advanced and cellulosic that don't exist and other things. So if you do it on a straight CI basis, it might be a reasonable substitute. Of course, you have other people out there talking carbon tax, how this would look in a carbon tax, I haven't really thought through enough to be smart on it yet, and I don't think anybody else has either. But any of those would be positive moves that I think would help make a decision on Coffeyville quicker.

Prashant Rao -- Citigroup -- Analyst

Okay. Last question, specifically on the tallow market, given where the tightness in feedstocks is. And I think going back to your comment from a previous call, Dave, that that sort of is the gold standard that you go to in terms of getting the low CI scores moving to some of these animal fats and tallows.

I just wanted to get a sense of availability. You're in the phase right now where you're looking at feedstock supply, locking in some of those things getting closer to securing that. Just a broader outlook of will there be kind of the pall on tallow or is there some sort of -- other things, factors we should be thinking about that maybe slow that down a little bit? What are some of the maybe barriers to building that or accessing that resource or building that network? And I'll leave it there Thanks.

David L. Lamp -- Chief Executive Officer and President

Yes. I think the reality is, if you look at the total production of tallow unused cooking oil, even corn oil, that volume as much is dwarfed compared to what is available via soybean oil, that's just the reality of the balance. Even that's the same thing worldwide. And I think you've seen some of the actions. I think Belgium was the first country to say they're going to outlaw use of soybean oil and renewable diesel, and they're going to outlaw palm oil. So those are -- if that went wide, that's obviously a big impact. But the magnitude of the numbers of availability of soybean oil compared to the other three is-they're dwarfed. They're just small. So that's just the reality of the situation. I firmly believe there's another molecule out there that's probably even better yet, and nobody really knows how to use it yet, but it's just biomass, which is wood, chips, grass cuttings, corn stover, stuff of that nature. That's -- if you look in the Midwest, that's where most of it is concentrated at, and that's right where we sit.

So I think we'll have some advantages on something like that. We'll also have advantage on tallow, to some degree too, because of our location. There's a lot of feed lots, Kansas and Oklahoma. And a lot of slaughterhouses in those areas too. So we'll have a transportation advantage if nothing else.

Prashant Rao -- Citigroup -- Analyst

Okay. Thanks very much for the time, Dave. Appreciate it.

Operator

Our next question comes from the line of Phil Gresh with JPMorgan. Please proceed with your question.

Philip Gresh -- JPMorgan -- Analyst

Yes. Hey, Dave. So as you look at ramping up the production here on renewable diesel in the fourth quarter, I think we've observed some others that have had some teething issues with start ups. So I was just curious, have you kind of tracked that and do your own ramp up, how do you think about making sure you hit the utilization, making sure the product quality matches your expectations or any other factors that you think about?

David L. Lamp -- Chief Executive Officer and President

Sure, Phil. I think there's always risk when you start something new up and that does take time usually to center in on the sweet spot, so to speak. I don't think that we're going to have particular problems in that area because this is a conversion of a high-pressure unit. Pressure is your friend here, and particularly on catalyst life and just the forgiveness of the process. So we have that working for us. The other piece I am more worried about is just feedstock quality in general. Not all bean oil is created equal. And that is certainly true of all the other feedstocks also, so that's the part that I think we have to watch very closely and be on our game to protect the downstream equipment and make the material on spec as you pointed out.

Philip Gresh -- JPMorgan -- Analyst

Right. Okay. Thank you. In terms of the PTU, I think you said on the last call, an estimate of $50 million. Not sure if there's any update to that? And have you said what the capacity is of the PTU that you're considering?

David L. Lamp -- Chief Executive Officer and President

No. We haven't mentioned it yet, but at one point, we have talked about building a combined pre-treater for both Wynnewood and Coffeyville. Or let me put it this way, build one that's expandable to handle both units. And after doing the more research on the technology, they're really -- these things are just they are 10,000 barrel max per train. And it gets too big and you have to go to a second train anything above that.

So that kind of plays pretty well into our hand. If we get to 10,000 to 12,000 barrels a day out of the Coffeyville conversion, and have seven here, that matches a two train system, which also gives us a lot of flexibility in how we process and where we process the various feedstocks. The cost is -- I will tell you that material escalations is very real right now. I think steel is up about 75%. You've heard lumber, probably up 300%. Coppers basically doubled or tripled in the last several months. And so that's going to affect these costs. I think we're penciling in about 60 for this first train.

Philip Gresh -- JPMorgan -- Analyst

Okay. Got it. Well, the good news is the inflation is transitory, right?

David L. Lamp -- Chief Executive Officer and President

I hope.

Philip Gresh -- JPMorgan -- Analyst

Last question, just your comments around returning more capital to shareholders or at least assessing it. Should I infer from that, that the M&A opportunities that you've discussed in the past may not be as near-term as we might think?

David L. Lamp -- Chief Executive Officer and President

Well, you've heard no announcements yet. That's pretty much about all I can say on that subject. We've had pencils down for a period of time, but they seem to reoccur -- or come back to life every so often. So you never say never in this business. I think the better question to us is really where do we want to put our capital these days. And I think with the current trends and the things we're seeing, investments in refining is a tough row. They're just going to be -- there needs to be more closures in our opinion of noncompetitive refineries. And there needs to be more consolidation to drive out fixed cost because, frankly, if a lot of the plans come to be, if you do go to a low-carbon fuel standard, there's going to be less refining required to meet the market needs.

They won't eliminate it, but you'll need it, only your most competitive facilities will remain. So with that in mind, I think most of our dollars going forward are going to be associated with sustainability and renewables or some form thereof or biomass or some combination thereof as innovation comes to be. We have the fixed assets that can process this stuff with the proper pretreatment and convert it to usable fuel that has a lower CI. So that's where I think a lot of our dollars are going to go.

We do have too much cash on the balance sheet today to run our business, and our Board is looking at that very closely. And that there should be some action taken here soon. Don't know exactly when, but the Board continually looks at this, and will make a decision soon, I think.

Philip Gresh -- JPMorgan -- Analyst

Thank you. Thanks for your time.

Operator

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

Neil Mehta -- Goldman Sachs -- Analyst

Great. Thank you so much, Dave and team. The first question, Dave, you've been very vocal about the Delek ownership position that you have. I think your view has been that you don't want to consolidate the entity, but you want to see the equity appreciate, which it has.

So to talk a little bit about your latest thinking around that story and whether you see yourself as a long-term investor and whether this can be part of accelerating the deleveraging and the capital returns part of the business extent you do want to monetize them?

David L. Lamp -- Chief Executive Officer and President

Well, I think as you know, Neil, we're in the middle of a proxy fight right now. We're trying to get three directors that we've nominated on to the Board, replacing three of that have been there for quite a long time. And we're still active in that process that I think that meeting -- shareholder meeting is in a couple of days. And we'll see where that leads us. We're patient. We're not in a hurry. We think there's still value there.

But we do think the Delek management needs to take action and like soon, not in 10 years. Their franchise has changed and with the Permian Basin changing with excess pipeline capacity coming out of there, and they need to be to act.

Neil Mehta -- Goldman Sachs -- Analyst

And Dave, can I ask you, when you think about returning excess capital to shareholders, net debt is plus/minus $1 billion at the consolidated level. How do you think about it? Is there an absolute level of leverage or net debt that you would want to get to before you think about returning capital to shareholders and as you think about your different options, you have the capacity to do both buybacks or you could do it in the form of dividends, which you've historically done, do you have a preference?

David L. Lamp -- Chief Executive Officer and President

I think, Neil, that's really up to the Board to make that decision. And I think they're looking at all the above, as you mentioned without a doubt. And I think there are some preferences by some. But any of them are perfectly acceptable from a shareholder return standpoint. We are big believers that you only buy back shares when the stock price is low, and it is fairly low, but that doesn't mean that's the direction we'll take in any way, shape or form. So like I said, the Board is reviewing this all the time, and they're hot on the trail and stay tuned.

Operator

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

Paul Cheng -- Scotia Howard Weil -- Analyst

Hi. Just trying to understand what your approach on the current liability for the 2020 RVO? You're sitting on your balance sheet, I think it's probably around $300 million. So whether that you're looking at your $700 million in the cash, if we deduct this liability is $400 million, and obviously, that from a cash return to shareholder should we take that into consideration?

And also that -- I mean, are you just going to sit on your -- not doing anything until you get the Supreme Court ruling on that. But even with that, as we have seen from the actions on the EPA, that not necessarily means that you're going to get granted for the small refinery exemption.

So I'm trying to understand that what's the approach that we're doing? Are we just basically sitting and waiting or that you will take a more proactive perhaps start to purchase the RIN as a insurance policy?

David L. Lamp -- Chief Executive Officer and President

Yes, Paul, let me make a couple of comments, and Tracy will chime in. But the Supreme Court is outstanding. That ruling is a very important one from our standpoint. Remember, we have waivers applications already in for '19 and '20 for the Wynnewood refinery, which are approximately 110 million to 120 million RINs each. So that alone should the Supreme Court invalidate the Tenth Circuit's ruling would consume most of our short position.

And OK, just because you get the Supreme court ruling doesn't mean anything, like you point out, you're going to have to probably sue EPA, which I think the precedence is there that we would have a very, very good case to say they wrongly denied waivers, particularly in this environment. So I think Wynnewood is a classic example to me of a hardship refinery. It meets all the definitions. It'll do irreparable damage to the local rural community that we operate in. It makes a high percentage of diesel. It has no chance to really blend other than what it sells across its own rack through the Magellan system.

And the fact that the mandate is 8.5 and some change ethanol and 5% diesel, it immediately puts you in a deficit position anyway. So it's a classic example. And I think we're banking on winning in the Supreme Court, and we're banking on winning lawsuits on the '19 and the '20 and probably the '21 because it will take that long. We'll have that application in soon, and it'll take that long to settle any lawsuits.

Paul Cheng -- Scotia Howard Weil -- Analyst

Can I ask that? Let's say, you're going to sue the EPA, let's assume the Supreme Court come in, straight up ruling and then you're going to sue the EPA and it's probably going to drag on beyond this year. So that the -- I thought 2020, the RVO, you need to settle before the March of next year. So are you -- that means that you're going to get a injunction[Phonetic] until that lawsuit is over or that you actually still anyway have to settle that first?

David L. Lamp -- Chief Executive Officer and President

Remember, we settled all of '19 already. So we have the right to skip a year should we do it. And we're estimating that EPA will have to extend the 2021 date as they did the 2020 because they still haven't even issued the RVO. So all that adding together, we can skip a year and we're into -- well into '23 before we have to even think about that. And a lot can happen in that time frame.

Paul Cheng -- Scotia Howard Weil -- Analyst

I see. Okay. And then in terms of how that liability will influence on your potential cash return to shareholder initiative? Is that being taken into consideration or that not really?

Tracy D. Jackson -- Executive Vice President and Chief Financial Officer

Paul, there's too much uncertainty as Dave just outlined, between not knowing what the 2021 RVO is going to be, the submission of a 2021 waiver that we anticipate doing shortly. The fact that we believe that we are owed '19, '20 and '21 waivers if we continue to produce at Wynnewood. And with the RV unit coming online in a few short years with the pre-treater and potentially Phase 3 of Coffeyville, we could be long RINs. And so when we look at that liability sitting on the balance sheet, it is a noncash impact for us for the foreseeable future until we get some resolution from the EPA on the many things that they have outstanding.

Paul Cheng -- Scotia Howard Weil -- Analyst

I see. All right. Thank you.

Operator

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

Matthew Blair -- Tudor, Pickering, Holt & Co. -- Analyst

Hey, good afternoon everyone. I thought the comments on the 45Q tax credits at Coffeyville were pretty interesting. So I was hoping you could just expand on that. I mean it sounds like carbon capture on the fertilizer side, would there be any potential benefits or any opportunity to doing something similar on the refining side? And would you expect any upfront cost? Or just any more details on this would be helpful.

David L. Lamp -- Chief Executive Officer and President

Sure. Coffeyville is kind of a unique operation because it uses pet coke N the gasification process to produce the hydrogen for ammonia. It also produces a lot of CO2 and that is recovered today by -- with the partnership we have with an oil company that uses it for downhole flooding and basically increases its oil production via pipeline and compression system that was installed several years ago. So we've been doing this for a while there. And the 45Q credits are -- it's a matter of doing the life cycle analysis and all this, the proper documentation around the sequestration of the CO2 in that. And we're hot on that trail.

The second application in terms of fertilizer is really at our East Dubuque fertilizer plant, which is methane-based feedstock, but still produces a highly concentrated CO2 stream that the same credits could apply. And you've probably seen the Valero announcement with Navigator on building a CO2 pipeline, which would then sequester CO2 somewhere in Illinois. And we're talking to those people and we're involved with them and trying to figure out how we can do the same thing at East Dubuque.

From a standpoint of refining, that's a whole lot different issue; the streams, except for our hydrogen plants, which once the RD units start-up if we do Coffeyville, we'll produce a concentrated CO2 stream. And that has the potential to reduce the CI of the renewable diesel if we could recover that, piggy back off the existing system at Coffeyville and connect to the pipeline and put compression in at Wynnewood. So it all has potential to be there.

Our ultimate goal on fertilizer is really to produce what's called blue ammonia, blue fertilizer, which is -- it's not green, but it is substantially reduced carbon produced fertilizer that we think will help us in our sustainability efforts also.

Matthew Blair -- Tudor, Pickering, Holt & Co. -- Analyst

Terrific. And just to clarify on Paul's question, what exactly was your open RIN position entering the second quarter? I think starting the first quarter, it was 240 million, and then you reduced that to approximately 222 million. So what was it at the end of Q1?

Tracy D. Jackson -- Executive Vice President and Chief Financial Officer

246 million RIN.

Matthew Blair -- Tudor, Pickering, Holt & Co. -- Analyst

246 million?

David L. Lamp -- Chief Executive Officer and President

Yes.

Matthew Blair -- Tudor, Pickering, Holt & Co. -- Analyst

Okay. Thank you.

Operator

Our next question comes from the line of Matt Vittorioso with Jefferies. Please proceed with your question.

Matthew Vittorioso -- Jefferies -- Analyst

Yeah, thanks for taking my question. I guess just a point of clarification. So when we think about first quarter EBITDA from the refining business, it sounds like a lot of the reported negative $126 million when you exclude the inventory adjustment is just RINs and the mark-to-market on the RINs, which don't have cash associated with them, at least not today.

So could you tell us what first quarter EBITDA was excluding any impact from RINs? Because, I mean, I guess, ultimately, we're not sure you're even going to have to pay cash on that. It just -- it seems to be creating a situation where EBITDA is not very much a cash number anymore.

So just trying to think about how to like have a more cash oriented EBITDA figure, if that makes sense?

Tracy D. Jackson -- Executive Vice President and Chief Financial Officer

So Matt, we're going to report for the refining segment, the $61.5 million or 60 -- I don't know if we rounded the millions or not, but $61.5 million of EBITDA loss. And Dave quoted RINs revaluation on mark-to-market is $98 million. And we'll also -- I think we've disclosed in the press release the unrealized derivative losses of $43.5 million. And we've quoted in this script, the inventory valuation benefit that we received. But what I would like to avoid is quoting an adjusted EBITDA number from all of those items so that I don't create chaos for my accounting team this evening, but I trust that you do the math.

Matthew Vittorioso -- Jefferies -- Analyst

Right. But even so just so I'm clear because I feel like I'm trying to get straight on all the RINs accounting. So there's a $98 million mark-to-market in the quarter that is just marking the open position to the current market position. But is that the full expense that went through the income statement related to RINs? Or is that --

Tracy D. Jackson -- Executive Vice President and Chief Financial Officer

No, there's 178 million of RINs expense in the margin for refining for the quarter and $98 million of that is associated with marking to market the 2020 RIN obligation.

Matthew Vittorioso -- Jefferies -- Analyst

Right. And the other is your quarterly obligation based at current RIN prices.

Tracy D. Jackson -- Executive Vice President and Chief Financial Officer

Yes.

Matthew Vittorioso -- Jefferies -- Analyst

And even the non-mark-to-market expense, that just goes and accrues to the liability, and we'll see if you ever -- if you get the exemptions, you may not have to pay cash on that. Is that fair to say?

Tracy D. Jackson -- Executive Vice President and Chief Financial Officer

That is correct. And we'll continue to be transparent about what that RIN number is and what that mark-to-market noncash component is because we do believe that we don't ultimately owe that.

Matthew Vittorioso -- Jefferies -- Analyst

Yes. And to that point, I mean, I just I don't know how hard it would be to do this. But to put those numbers into the press release. I understand you don't want to create chaos, but it's meaningful to think about like what drove the quarter? Because if I look at your EBITDA of negative $121 million [Phonetic] ex the inventory valuation, it doesn't really tell me a whole lot, but if you tell me the majority of that loss was related to RINs, that helps me add a lot. That's all I'll say. But thanks for the clarification. Thank you.

Operator

Your next question is a follow-up from Paul Cheng with Scotia Howard Weil. Please proceed with your question.

Paul Cheng -- Scotia Howard Weil -- Analyst

Thank you. Tracy, just want to confirm that the ongoing RIN events that you charge, did you actually purchase the RIN so that the cash already are out of the door and you have it or that you just booked the expense, but it's a noncash expense. That means that you're still building up the obligation.

Tracy D. Jackson -- Executive Vice President and Chief Financial Officer

So Paul, we don't get into the details of actual RINs purchases or RINs rent transactional activity. But we will be disclosing what our overall short position is quarter-over-quarter and how much of that is mark-to-market on a short position. The way to think about that is that the remainder of the expense charging through is associated with current period operations.

Paul Cheng -- Scotia Howard Weil -- Analyst

Okay. So from a cash obligation standpoint, the short position. I think you're saying that -- so yes, the $246 million is your total net short obligation from a cash standpoint related to RIN at the end of the first quarter?

Tracy D. Jackson -- Executive Vice President and Chief Financial Officer

That's the number of RINs that we owe at the end of the quarter that we have accrued for on our balance sheet.

Paul Cheng -- Scotia Howard Weil -- Analyst

That's not a dollar, that is the gallon, the 246?

Tracy D. Jackson -- Executive Vice President and Chief Financial Officer

It's 246 million RINs.

Paul Cheng -- Scotia Howard Weil -- Analyst

I guess my question is that, is that $246 million or 246 million gallon was the unit?

Tracy D. Jackson -- Executive Vice President and Chief Financial Officer

No, it's the number of RINs total, it is not a dollar number.

Paul Cheng -- Scotia Howard Weil -- Analyst

Okay. Will do. Thank you.

Operator

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

David L. Lamp -- Chief Executive Officer and President

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, their commitment toward safe, reliable, environmentally responsible operations. We look forward to reviewing our second quarter results during our next earnings call. Thank you.

Operator

[Operator Closing Remarks]

Duration: 58 minutes

Call participants:

Richard Roberts -- Investor Relations

David L. Lamp -- Chief Executive Officer and President

Tracy D. Jackson -- Executive Vice President and Chief Financial Officer

Manav Gupta -- Credit Suisse -- Analyst

Prashant Rao -- Citigroup -- Analyst

Philip Gresh -- JPMorgan -- Analyst

Neil Mehta -- Goldman Sachs -- Analyst

Paul Cheng -- Scotia Howard Weil -- Analyst

Matthew Blair -- Tudor, Pickering, Holt & Co. -- Analyst

Matthew Vittorioso -- Jefferies -- Analyst

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