Earnings Call Transcript - CVI Q1 2021

Operator, Operator

Greetings, and welcome to the CVR Energy First Quarter 2021 Conference Call. As a reminder, this conference is being recorded. 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, Senior Manager, Financial Planning and Analysis 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 Lamp, CEO

Thank you, Richard. Good afternoon, everyone. Thank you for joining our Earnings Call. Yesterday, we reported the 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 than 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 and in 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 maximum 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. The WCS to WTI differential was $11.82 per barrel compared to $17.77 for the same period last year. Life product yield for the quarter was 100% on crude oil processed. 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 during 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 planting this year of 91 million acres, the 2020 inventory carryout could be at the lowest level since 2014. This should set up for a continued strength in crop prices, which will be positive for fertilizer demand and pricing as well. Now let me turn the call over to Tracy to discuss some additional financial highlights.

Tracy Jackson, CFO

Thank you, Dave, and good afternoon, everyone. Our consolidated net loss amounted to $55 million, reflecting a loss per diluted share of $0.39. This figure includes a mark-to-market gain of $62 million related to our investment in Delek, as well as a favorable inventory valuation impact of $66 million. For the first quarter of 2021, the effective tax rate provided a benefit of 43%, compared to a benefit of 27% in the prior year period, mainly due to state income tax credits. We are still expecting an income tax refund related to the CARES Act of approximately $35 million to $40 million, which we anticipate will be received in the latter half of 2021. The EBITDA for our Petroleum segment in the first quarter of 2021 was negative $61 million, which included an inventory valuation benefit of $66 million. This is an improvement compared to an EBITDA of negative $77 million in the first quarter of 2020, which faced an unfavorable inventory valuation impact of $136 million. If we exclude the inventory valuation effects for both periods, our Petroleum segment's EBITDA would show a negative figure of $127 million for the first quarter of 2021, contrasting with a positive $59 million in the previous year. The decline in year-over-year EBITDA was primarily driven by high RINs prices along with our open RIN position, unrealized derivative losses, and increased operating expenses due to winter storm Uri. In the first quarter of 2021, our Petroleum segment's refining margin, not accounting for inventory impact, was negative $0.88 per total throughput barrel, versus $11.06 in the same quarter of 2020. Throughout the quarter, the rise in crude oil and refined product prices generated an inventory valuation benefit of $3.93 per barrel, compared to an unfavorable impact of $9.54 per barrel in the same period last year. Excluding inventory valuation effects, 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%, down from 86% in the same quarter of 2020. Additionally, RINs expense lowered our capture rate by 65% in the first quarter of 2021, with a 36% impact related to the mark-to-market of our 2020 RIN obligation. Derivative losses for the first quarter of 2021 were $32 million, which includes unrealized losses of $43 million, primarily linked to frac spread derivatives, countered by gains on Canadian crude oil. In the first quarter of 2020, we had total derivative gains of $46 million, including unrealized gains of $12 million. Our RINs expense in the first quarter of 2021 reached $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 RINs expense for the first quarter was inflated by $98 million due to the mark-to-market impact related to our 2020 accrued RFS obligation, valued at an average RIN price of $1.39 at quarter end. Our accrued RFS obligation at the end of the first quarter remains consistent with our 2019 and 2020 obligations at Wynnewood, for which waivers have been applied. We anticipate Wynnewood’s obligation for 2021 should be exempt under RFS regulations. For the full year 2021, we forecast a net obligation of about $230 million in RINs, excluding waivers but including the RINs we expect to generate from renewable diesel production in the second half of the year. Our consolidated capital spending plan does not include blend turnaround spending, which we estimate to be about $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, and despite increased natural gas and utilities costs, capital spending, and the closing of the Oklahoma pipeline acquisition, we achieved free cash flow of $61 million for the quarter. Working capital contributed approximately $218 million in the quarter due to an increase in our RINs obligation and an increase in lease pre-payable. Our total consolidated cash balance includes $53 million in the Fertilizer segment. As of March 31, excluding CVR Partners, we had around $1 billion in liquidity, consisting of roughly $655 million in cash, $235 million in securities available for sale, and about $364 million available under the ABL, minus $208 million in cash included in the borrowing base. Looking ahead to the second quarter of 2021, for our Petroleum segment, we estimate total throughput to be around 200,000 to 220,000 barrels per day. We expect total direct operating expenses to be between $75 million and $85 million, with total capital spending ranging from $6 million to $12 million. For the Fertilizer segment, we project our ammonia utilization rate to exceed 95%. We anticipate 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. In the Renewables segment, capital spending is expected to be between $65 million and $70 million. With that, Dave, I will turn the call back to you.

David Lamp, CEO

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. 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 U.S., helped in part by the shutdowns after the winter storm. U.S. 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 pressed jet fuel demand. U.S. 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. RINs remain high, driven by government inaction and regulatory uncertainty. For the CVR Refining system, we continue to run our refineries at maximum 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 down. The spring run has been strong, and NOLA urea price is around $385 per ton with UAN at nearly $300 per ton. Our net debt 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 underway of our Wynnewood renewable diesel unit; however, severe weather in February and delays in equipment deliveries are causing us to project 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 towards 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 opportunities to add biomass as feedstocks 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 WTI differential at $0.14 per barrel under WTI; and the 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. The Supreme Court curbed arguments in our appeal, 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, and 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 the EPA might finally provide a renewable volume obligation for 2021. The EPA has also yet to rule on the 2019 and 2020 small refinery exemptions. The lack of actions by the 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.

Operator, Operator

Our first question comes from Manav Gupta with Crédit Suisse.

Manav Gupta, Analyst

My question here is, again, you have been making a very effective case for small refineries. A lot of people understand the pain that small refiners feel here. But for some reason, it looks like the EPA doesn't really want to even look at it. I think a few days ago, there was news that there were three small refinery exemptions given to Sinclair, and the 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 wonder your comments on this, like does this actually make any sense to take away the SREs that have already been issued?

David Lamp, CEO

Well, Manav, I would say that the EPA is making a significant change after ten years of consistently applying the RFS, shifting to a new direction that will likely result in higher gasoline and diesel prices for consumers across the nation. It's difficult to see any logic behind this, aside from the recent green initiatives that require increased prices for petroleum products to make alternatives more appealing. I can't think of any other reason for this change. It feels completely unfair to me. They are taking away something that was previously granted, and the Sinclair case is notable because they had a settlement after being unjustly denied small refinery waivers. Now, with a new administration, there's a shift in policy. This demonstrates that the whole RFS process is politically driven and is in need of revision to ensure fairness for everyone.

Manav Gupta, 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 if CVI is looking to secure some of its feedstocks, are you looking at some alternate feedstocks, covered crops, corn oil, just how will you try and mitigate this sudden headwind that we are seeing in soybean oil prices? And I'll leave it there.

David Lamp, CEO

Sure, Manav. In my prepared remarks, I mentioned that we are very close to selecting the technology for Phase 2, which is the pretreater. This will give us the flexibility to run various feedstocks, including corn oil, tallow, and unused cooking oil, although the availability of the latter may be limited. The significant factor for all these new units remains the large volume of soybean oil. It's important to note that currently, a lot of soybean oil is used for biodiesel, but I believe it will shift back to renewable diesel due to the improvements in carbon intensity and the difference in RIN values. It will take some time for the market to adjust to this reality. In the past couple of months, several large renewable diesel units were brought online, including those by Marathon, Dickinson, and Phillips 66 in California. The market has not yet adapted to these changes. Looking at soybean oil futures, they are showing backwardation, with prices dropping from the mid-60s to the low 50s over the first two months. We anticipate this will be the timeframe in which we start securing feedstock for this unit.

Operator, Operator

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

Prashant Rao, Analyst

To follow up on that, Dave, now that Phase 1 for Wynnewood is projected for the end of the third quarter, are you close to selecting the technology provider for Phase 2 of the project? Since Phase 1 has been pushed to the third quarter, what are your thoughts on the timing for the pretreatment, especially considering the current environment with high RINs and elevated feedstock costs? How should we perceive the timing of Phase 2? Initially, the plan seemed to lean towards the end of next year, but is there any possibility of accelerating that? I also have a follow-up question regarding feedstocks.

David Lamp, CEO

Well, the technology we're looking at is not particularly difficult to build. It does take some certain amount of alloy-type metals. 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, Analyst

Would you still proceed with your Phase 1 and Phase 2 projects in Wynnewood and then consider Coffeyville? Or is there a possibility for some overlap, considering Wynnewood has fallen behind by a quarter, and given the economics, might you want to initiate Coffeyville before completing or while finishing up Phase 2? I'm just thinking about the overall timeline for the total asset base and whether there's a way to accelerate that process a bit.

David Lamp, CEO

We're beginning a feasibility study for a conversion at Coffeyville, which involves some preliminary engineering work. This will cost a modest amount but will provide us with a head start on the design if we choose to move forward. However, I want to caution that California's market is becoming saturated, despite ongoing imports. It remains the top location for low-carbon fuel standards globally. We need broader, nationwide initiatives to accommodate the influx of new production units and position our products favorably. There's an impending reset of the Renewable Fuel Standard in 2022, and the EPA is soliciting feedback on it. Some advocates are pushing for a nationwide low carbon fuel standard as a fairer alternative, focusing on carbon intensity rather than specific fuel blends that may not be viable. A carbon intensity-based approach could serve as a reasonable substitute. Additionally, discussions around carbon tax are emerging, though I haven't fully formulated my thoughts on it yet, and I don't think others have either. Any of these initiatives would be beneficial and could expedite decisions regarding Coffeyville.

Prashant Rao, 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 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 a call on tallow or are there factors you should be thinking about that maybe slow that down a little bit? What are some of the barriers to building that or accessing that resource or building that network? I'll leave it there.

David Lamp, CEO

Yes. The fact is that when you compare the total production of unused cooking oil and even corn oil, that volume is significantly smaller than what is available from soybean oil. This is true globally as well. Recently, Belgium announced a ban on soybean oil and renewable diesel, along with a ban on palm oil. If this kind of ban spreads, it could have a considerable impact. However, the availability of soybean oil far exceeds that of the other three oils, which are quite limited. I strongly believe there is another effective resource out there, likely better, but its use is not well understood yet. This includes biomass such as wood chips, grass cuttings, and corn stover. Most of this material is concentrated in the Midwest, which is where we are located, giving us an advantage. Additionally, we will have some advantage with tallow as well, due to our proximity to many feedlots in Kansas and Oklahoma, where there are also numerous slaughterhouses. This proximity gives us a transportation edge, if nothing else.

Operator, Operator

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

Philip Gresh, Analyst

Yes. 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 startups. So I was just curious as you track 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 Lamp, CEO

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, 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 as well. 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, Analyst

Right. Okay. 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 Lamp, CEO

No, we haven't brought it up yet, but previously we discussed creating a pretreater that could serve both Wynnewood and Coffeyville. To clarify, we want to design one that is expandable to accommodate both. After further investigation into the technology, we found that these systems can only handle a maximum of 10,000 barrels per train. If we need to go beyond that, a second train is required. This works well for us because if we achieve between 10,000 and 12,000 barrels a day from the Coffeyville conversion and 7,000 here, that aligns with a two-train configuration, providing us with significant flexibility in processing various feedstocks. However, we must consider the very real cost increases we are experiencing. For instance, steel prices have risen about 75%, lumber has surged nearly 300%, and copper prices have roughly doubled or tripled in recent months. These factors will influence our overall costs. We are estimating around $60 million for the initial train.

Philip Gresh, Analyst

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

David Lamp, CEO

Yes, I'd hope.

Philip Gresh, 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 Lamp, CEO

Well, you've heard no announcements yet. That's pretty much 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. With the current trends and the things we're seeing, investments in refining are a tough row. There need to be more closures in noncompetitive refineries. 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 market needs. They won't eliminate it, but you'll need only your most competitive facilities will remain. Keeping 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. 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. I mean, there should be some action taken here soon. Don't know exactly when, but the Board continually looks at this, and we'll make a decision soon, I think.

Operator, Operator

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

Neil Mehta, Analyst

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 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 in the capital returns part of the business extent you do want to monetize them?

David Lamp, CEO

Well, as you know, Neil, we are currently involved in a proxy fight. We are attempting to get three of our nominated directors onto the Board, replacing three longstanding members. We are still engaged in this process; the shareholder meeting is in a few days, and we will see where that leads us. We are patient and not rushed. We believe there is still value to be had. However, we do feel that the management at Delek needs to take action soon, rather than waiting for a decade. Their business dynamics have shifted, particularly with changes in the Permian Basin and the increase in pipeline capacity, so they need to respond accordingly.

Neil Mehta, 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: buybacks, or dividends, which you've historically done, do you have a preference?

David Lamp, CEO

I believe that decision rests with the Board. They are certainly considering all aspects, as you noted. Some preferences exist among them, but any of the options are viable from a shareholder return perspective. We firmly believe that share buybacks should occur only when the stock price is low, and it is currently quite low. However, that does not necessarily indicate the direction we will pursue. The Board constantly evaluates this situation and is actively engaged, so stay tuned.

Operator, Operator

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

Paul Cheng, Analyst

Dave, I’d like to understand your strategy regarding the current liability for the 2020 RVO. It appears to be around $300 million on your balance sheet. Considering your $700 million in cash, this would leave a $400 million liability. Should this be taken into account in your cash returns to shareholders? Will you be holding off on any decisions until a Supreme Court ruling is made? Additionally, given the EPA's recent actions, there's no guarantee that the small refinery exemption will be granted. What is your approach here? Are you simply waiting, or do you plan to take a more proactive stance, such as purchasing RINs as a precaution?

David Lamp, CEO

Yes, Paul. Let me make a couple of comments, and Tracy will chime in. The Supreme Court's 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. That alone, should the Supreme Court invalidate the Tenth Circuit's ruling would consume most of our short position. Just because you get the Supreme Court ruling doesn't mean anything; like you pointed out, you're going to have to probably sue the 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. Wynnewood is a classic example to me of a hardship refinery. It meets all the definitions. There's 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. The mandate is 8.5 and some change ethanol and 5% diesel. It immediately puts you in a deficit position anyway. It's a classic example. We are banking on winning the Supreme Court ruling and 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 will take that long to settle any lawsuits.

Paul Cheng, Analyst

Can I ask this? If you plan to sue the EPA and the Supreme Court makes a clear ruling, that lawsuit is likely to continue into next year. I thought the RVO for 2020 needed to be resolved before March of next year. Does this mean you won't receive a judgment until the lawsuit is concluded, or do you need to settle that first anyway?

David Lamp, CEO

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

Paul Cheng, Analyst

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

Tracy Jackson, CFO

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. With the RV unit coming online in a few short years with the pretreater and potentially Phase 3 at Coffeyville, we could be long RINs. 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.

Matthew Blair, Analyst

I thought the comments on the 45Q tax credits at Coffeyville were pretty interesting. 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 do something similar on the refining side? Would you expect any upfront cost? Or just any more details on this would be helpful.

David Lamp, CEO

Sure. Coffeyville is kind of a unique operation because it uses pet coke and the gasification process to produce the hydrogen for ammonia. It also produces a lot of CO2, which is recovered today through a partnership with an oil company that uses it for downhole flooding and increases its oil production via a pipeline and compression system that was installed several years ago. We've been doing this for a while there. The 45Q credits are a matter of doing the life cycle analysis and all the proper documentation around the sequestration of CO2. 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. You've probably seen the Valero announcement with Navigator on building a CO2 pipeline, which would then sequester CO2 somewhere in Illinois. We're talking to those people, and we're involved with them, 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, will produce a concentrated CO2 stream. That has the potential to reduce the CI of renewable diesel if we could recover that, piggyback off the existing system at Coffeyville and connect to the pipeline and put compression in at Wynnewood. 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 not green, but it is substantially reduced carbon produced fertilizer that we think will help us in our sustainability efforts as well.

Matthew Blair, Analyst

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

Tracy Jackson, CFO

246 million in RINs.

David Lamp, CEO

Yes.

Operator, Operator

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

Matthew Vittorioso, Analyst

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 seems to be creating a situation where EBITDA is not very much a cash number anymore. So just trying to think about how to have a more cash-oriented EBITDA figure, if that makes sense?

Tracy Jackson, CFO

So Matt, we're going to report for the refining segment, the $61.5 million or $61 million loss. Dave quoted RINs revaluation on mark-to-market is $98 million. We've also disclosed in the press release the unrealized derivatives losses of $43.5 million. We've quoted in this script the inventory valuation benefit that we received. But I'd like to avoid 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, Analyst

Right. So just so I'm clear because I feel like I'm trying to get straight on all the RINs accounting. 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 Jackson, CFO

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, Analyst

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

Tracy Jackson, CFO

Yes.

Matthew Vittorioso, Analyst

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

Tracy Jackson, CFO

That is correct. We will 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.

Operator, Operator

Our next question is a follow-up from Paul Cheng with Scotia Howard Weil.

Paul Cheng, Analyst

Tracy, I want to clarify the ongoing RIN expense you report: Did you actually purchase the RIN? Is the cash already spent, or did you just record the expense as a noncash item? Does that mean you are still accumulating the obligation?

Tracy Jackson, CFO

So Paul, we don't get into the details of actual RINs purchases or RINs 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, Analyst

Okay. So from a cash obligation standpoint regarding the short position, I understand that the $246 million represents your total net short obligation from a cash perspective related to RIN at the end of the first quarter?

Tracy Jackson, CFO

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, Analyst

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

Tracy Jackson, CFO

It's the number of RINs total; it is not a dollar number.

Operator, 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 Lamp, CEO

Again, I'd like to thank you all for your interest in CVR Energy. Additionally, I'd like to thank all our employees for their hard work and their commitment towards safe, reliable, environmentally responsible operations. We look forward to reviewing our Second Quarter results during our next earnings call. Thank you.

Operator, Operator

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