Title

Presentation

Operator: Greetings, and welcome to the CVR Energy First Quarter 2024 Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Richard Roberts, Vice President of FP&A and Investor Relations. Thank you, sir. You may begin.

Richard Roberts: Thank you, Christine. Good afternoon, everyone. We very much appreciate you joining us this afternoon for our CVR Energy first quarter 2024 earnings call. With me today are Dave Lamp, our Chief Executive Officer; Dane Neumann, our Chief Financial Officer; and other members of management. Prior to discussing our 2024 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. This call also includes various non-GAAP financial measures. The disclosures related to such non-GAAP measures, including reconciliations of the most directly comparable GAAP financial measures, are included in our 2024 first quarter earnings release that we filed with the SEC in the 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: Thank you, Richard. Good afternoon, everyone, and thank you for joining our earnings call. Before I discuss our results for the quarter, I want to address an incident at the Wynnewood refinery that occurred over the weekend, early Sunday morning, during severe weather in the area. The Wynnewood refinery experienced a fire that was later extinguished later that morning. No employees or contractors were injured and we are in the beginning of the process of restarting portions of the refinery. We are still assessing the extent of the damage, and we expect to provide additional details when they’re available. Turning to our results. Yesterday, we reported a first quarter consolidated net income of $90 million and earnings per share of $0.81, EBITDA was $203 million.

Our solid results for the quarter were driven by continued declines in the prices of RINs and increased crude oil and refined product prices in the quarter, offset by lower crack spreads and fertilizer prices were relative to the prior period. We are pleased to announce that our Board of Directors authorized the first quarter regular dividend of $0.50 per share which will be paid on May 20 to shareholders of record at the close of the market on May 13. Our annualized dividend yield of approximately 6% yesterday, based on yesterday’s closing price, remains best-in-class among the independent refineries. In our Petroleum segment, combined total throughput for the first quarter of 2024 was approximately 196,000 barrels per day and late product yield was 101% on crude oil processed.

During the quarter, we completed the planned turnaround at the Wynnewood refinery. We currently do not have any additional turnarounds planned until Coffeyville’s turnaround on a crude unit cat cracker and alky and other associated units currently scheduled for the spring of 2024, ’25. Benchmark cracks softened during the first quarter with the Group 3 2-1-1 averaging $19.55 per barrel compared to $23.66 per barrel for the fourth quarter of ’23. First quarter average RIN prices declined from the fourth quarter and ended the quarter at approximately $0.68 on an RVO weighted basis. While we’re thrilled with the Fifth Circuit’s decision in November vacating EPA’s denial of Wynnewood’s small refinery exemption petitions for 2017 through 2021 and reprimanded those petitions back to EPA.

EPA’s egregious conduct continues. They still have not acted on Wynnewood’s small refinery exemption petitions for 2017 through 2021, though 90 days have passed since the issuance of the Fifth Circuit mandate, nor has EPA ruled on EPA’s small refinery exemptions petitioned for 2023 due last month. We will continue to push for a court ruling to force EPA to do its job and follow the law. The D.C. Court of Appeals heard oral arguments in the small refinery exemption denial cases for a few other small refineries a few weeks ago. While we expect the ruling will take some time, we were pleased with how the hearing went. We also continue to wait for a response from the EPA regarding our petition for rule-making related to the RFS. We believe the law is clear that only obligated parties who overcomply with their RFS obligations can generate excess RINs and that they may sell those RINs only to other obligated parties who need the RINs for compliance.

That EPA allows non-obligated parties to exploit the RIN market for profit is just wrong. It’s not just wrong, it violates the law as written. If EPA does not respond to our petition, once again, we will see them in court. For the first quarter of 2024, we processed approximately 7 million gallons of vegetable oil feedstocks at our Wynnewood renewable diesel unit, and the throughput in the quarter impacted by a planned catalyst change. The HOBO spread improved from the fourth quarter of ’23, but lower soybean oil prices, although prices for these four RINs remain depressed as a result of EPA’s continued mismanagement of the RFS program. As a reminder, our renewable diesel business is currently reported in our Corporate and Other segment. In the Fertilizer segment, we achieved consolidated ammonia plant utilization of 90%, which is also impacted by some planned downtime in the quarter at our Coffeyville facility.

Nitrogen fertilizer prices in the first quarter of 2024 remained fairly steady for the fourth quarter of – with fourth quarter of 2023 pricing. And we saw a strong demand for ammonia with favorable weather conditions during the quarter. Now let me turn the call over to Dane to discuss our financial highlights.

Dane Neumann: Thank you, Dave, and good afternoon, everyone. For the first quarter of 2024, our consolidated net income was $90 million, earnings per share was $0.81 and EBITDA was $203 million. Our first quarter results include a reduction to quarterly RINs expense due to a mark-to-market impact on our estimated outstanding RFS obligation of $91 million, a favorable inventory valuation impact of $37 million and unrealized derivative losses of $24 million. Excluding the above-mentioned items, adjusted EBITDA for the quarter was $99 million and adjusted earnings per share was $0.04. Adjusted EBITDA in the Petroleum segment was $67 million for the first quarter, with the decline from the prior year period, primarily driven by lower product cracks in Group 3.

Our first quarter realized margin adjusted for inventory valuation, unrealized derivative losses and RIN mark-to-market impacts was $10.46 per barrel, representing a 54% capture rate on the Group 3 2-1-1 benchmark. RINs expense for the quarter, excluding the mark-to-market impact was $45 million or $2.52 per barrel, which negatively impacted our capture rate for the quarter by approximately 13%. The estimated accrued RFS obligation on the balance sheet was $294 million at March 31, representing 449 million RINs mark-to-market at an average price of $0.66. As a reminder, our estimated outstanding RIN obligation excludes the impact of any small refinery exemptions. Direct operating expenses in the Petroleum segment were $5.78 per barrel for the first quarter compared to $5.90 per barrel in the first quarter of 2023.

The decrease in direct operating expenses was primarily due to lower natural gas and electricity prices. On a per barrel basis, our direct operating expenses were elevated in the first quarter of 2024 and the prior year period due to lower throughput rates as a result of planned turnarounds. Adjusted EBITDA in the Fertilizer segment was $40 million for the first quarter, with lower feedstock costs and direct operating expenses, somewhat offsetting the decline in prices relative to the prior year period. The partnership declared a distribution of $1.92 per common unit for the first quarter of 2024. As CVR Energy owns approximately 37% of CVR Partners common units we will receive a proportionate cash distribution of approximately $7 million. Cash provided by operations for the first quarter of 2024 was $177 million, and free cash flow was $121 million.

Significant uses of cash in the quarter included $61 million for cash taxes and interest, $59 million of capital and turnaround spending, $50 million for the fourth quarter 2023 regular dividend and $11 million paid for the noncontrolling interest portion of the CVR Partners’ fourth quarter 2023 distribution. Total consolidated capital spending was $51 million, which included $36 million in the Petroleum segment, $5 million in the Fertilizer segment and $8 million for the RDU, primarily related to the pretreatment unit. Turnaround spending in the first quarter was approximately $39 million. For the full year 2024, we estimate total consolidated capital spending to be approximately $225 million to $250 million and turnaround spending to be approximately $55 million to $65 million.

Turning to the balance sheet. We ended the quarter with a consolidated cash balance of $644 million, which includes $65 million of cash in the Fertilizers segment. Total liquidity as of March 31, excluding CVR Partners, was approximately $831 million, which was comprised primarily of $580 million of cash and availability under the ABL facility of $251 million. Looking ahead to the second quarter of 2024. As Dave mentioned, we are still assessing the extent of the damage from the fire of Wynnewood. We will provide an updated outlook for the Petroleum segment and the renewable diesel unit once the impact of the incident is determined. The Coffeyville refinery continues to operate as planned. For the Fertilizer segment, we estimate our second quarter 2024 ammonia utilization rate to be between 95% and 100%, direct operating expenses to be approximately $50 million to $55 million, excluding inventory impacts and total capital spending to be between $15 million and $20 million.

With that, Dave, I’ll turn it back over to you.

David Lamp: Thank you, Dane. In summary, market conditions were challenging for much of the first quarter, particularly in the Petroleum segment as refined product inventories were elevated coming into 2024 and distillate demand has been weak with a warm winter and depressed industrial activity. We would characterize current crack spreads as just above mid-cycles. Starting with refining, elevated maintenance activity and unplanned downtime in the United States over the past few months helped clean up inventories, with gasoline and diesel inventories, both near or below 5-year averages. We believe there’s additional maintenance work yet to be completed in the United States, Europe and Asia, and the impacts to global refining supply from recent drone attacks on the Russian refineries remains a wildcard.

We also continue to monitor the start-up of new global refining capacity expected this year, which could offset some of the supply impacts just discussed. On demand side of the equation, gasoline demand in the U.S. remained steady and is trending above the 5-year average levels recently. While distillate demand remains soft. Looking more specifically at the Mid-Con, refined product demand in Group 3 has remained steady although inventory levels are elevated relative to the U.S. as a whole. As a result, the basis in the Group 3 is unusually wide for gasoline and we have been increasing our fuel by rail shipments to the West through our new transload facility at Coffeyville. The Brent-TI differential has averaged nearly $5 per barrel so far this year, supported by crude oil export volumes averaging over 4 million barrels a day.

With crude prices in the $85 per barrel range, we expect continued strength in shale oil production volumes which should be supportive of our crude oil gathering business. For the first quarter, our crude oil gathering volumes were approximately 130,000 barrels per day. This is an important part of our strategy given the uplift we usually experience by bringing in neat barrels to the refinery gates. I’m pleased to announce that the Board recently approved a distillate yield product – yield improvement project at the Wynnewood refinery. Through some modifications to the vacuum tower in our diesel hydrotreating unit, we believe we’ll be able to increase distillate production at the Wynnewood refinery by approximately 2,500 barrels per day. We completed tie-in work for the project during Wynnewood’s recent turnaround project, and we currently expect final completion in the first half of 2025 at a capital cost of less than $15 million.

We are also studying a similar project at Coffeyville, which if approved by the Board and successfully implemented could be completed in 2026. Turning to the Fertilizer segment. We had good ammonia sales in the first quarter with favorable weather conditions, allowing farmers to apply ammonia earlier in the year. We expect strong demand for spring with planning expectations currently at 90 million acres for corn and 87 million acres for soybeans. We currently do not have any additional downtime planned for either fertilizer facilities until 2025. The pretreater for the renewable diesel unit began operations in the first quarter, and we expect to reap planned production rates during the second quarter. We are optimistic with the combination of new catalyst load in the RD unit plus the PTU when operational, would result in improved – and improvements in our renewable diesel product yield, catalyst life and resulting economics.

We continue to explore opportunities in the renewable space and are currently in discussions related to the potential conversion of the Wynnewood renewable diesel unit up to 100% SAF. As we have discussed previously, our focus is in exploring this project would be the structure of the offtake agreement such that would significantly derisk a margin that could justify the capital we need to invest. On a larger potential project at Coffeyville, we expect to have the project scope, cost and development plan ready to take to the market by the end of the year. We still believe there will be a market for renewable diesel and sustainable aviation going forward despite EPA’s continued mismanagement of the RFS regulation. Finally, in March, we issued a Form 8-K announcing that we were routinely considered and currently considering potential strategic transactions both in refining and potentially related to CVR Partners.

While we have nothing to disclose and certainly provide no assurances that we could successfully close any such transactions, there are some very interesting and transformative opportunities out there for both our refining business and CVR Partners. Looking at the second quarter of 2024, quarter-to-date metrics are as follows: Group 2-1-1 cracks have averaged $20.67 per barrel and Brent-TI spread at $4.48 per barrel and the Midland differential of $1.42 over WTI. Prompt fertilizer prices are approximately $600 per ton for ammonia and $300 per ton for UAN. As of yesterday, Group 3 2-1-1 cracks were $21.01 per barrel, Brent-TI spread was $5.77 per barrel and WCS was $13.21 under WTI. RINs were approximately $3.06 per barrel. As always, we continue to strive to operate our plants in a safe, reliable and environmentally responsible manner, and to explore opportunities to grow our renewables business.

We will continue to focus on maximizing free cash flow, which underpins our peer-leading dividend yield. With that, operator, we’re ready for questions.

Operator: [Operator Instructions] Our first question comes from the line of Manav Gupta with UBS. Please proceed with your question.

Manav Gupta: Good morning, guys. You are considered a good and safe operator, and I understand you’re still evaluating what happened over the weekend, but help us understand a little bit what is it? A weather-related event, exactly what went wrong over the weekend which caused some of the issues that you’re seeing?

David Lamp: Well, we don’t know exactly all the facts yet Manav, but it appears like we got hit by lightning in one of our process areas. And that lightning caused the impending fire and then that spread a little bit as it got hot. I think our response was excellent to it from a community standpoint, our employee’s standpoint and contractor standpoint. But it’s an unfortunate event that we’re sometimes exposed to. If you recall, the town of Sulphur, which is probably, I don’t know, 15 miles from us experienced a very bad tornado. That storms were really bad that night, and lightning was flying all over the place, and we think we took a direct hit, but you never can be sure as it happens so fast.

Manav Gupta: Right. So there’s literally nothing you would have done about it, right? So just was trying to make sure. And my second question is looks like your PTU is now going to be up and running – is running at your RD facility. Help us understand how – what are you looking to transform from refined soybean oil to unrefined soybean oil? Are you looking to do some tallow and stuff? And do you think that does make a material difference to your renewable diesel profitability?

David Lamp: Well, there’s no doubt that we’ve been catalyst starved with the unit without a PTU. We’ve had pretty short runs and poor yields, I’ll call it, on actual renewable diesel. We’re very encouraged with the – even buying treated feed or refined deodorized and degummed feed but still had a lot of impurities in it in the forms of metals and phosphorus and other things. And the results of the pretreater looked really good at this point. And we’re starting this run with the pretreater up. And the catalyst performance is already looking very good yields of 90-plus percent on renewable diesel, and much less byproducts that we had seen before that. So I’m really optimistic that we’ll pick up not only ability to run untreated corn oil and soybean oil, but maybe some other options for some other things.

But right now, we’re really focused on the corn oil as a substitute for the soybean oil. And we think that the margin on that right now is probably in the $0.80 range per gallon on a pretreated basis. So if we look at the first quarter, we ended – we still – we had a margin of about $0.65 a gallon, which if we could have run more barrels, we would have probably shown a profit on that unit. As it is, we were just kind of breakeven.

Manav Gupta: Thank you. Very helpful. Thank you.

David Lamp: You’re welcome.

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

Matthew Blair: Thank you. And good afternoon, Dave. I wanted to follow up on your comments regarding I think you mentioned something about railing gasoline to the West Coast. So I just wanted to confirm that, that you are railing gasoline to California and capitalizing on the higher margins in that space? And also just curious, can you make that carb spec? Or is it a blended spec? And what kind of volumes are we talking about here?

David Lamp: Sure. As I mentioned, I said to the West, not necessarily to California. But no, we have – we put in a transloading facility ahead of third party put it in, and we’re underwriting it with tariffs. But our plan is to be able to load up to 120,000 barrels per month and that’s our capability of the transloader. But we’ll go probably wherever the margins are the best. As far as making carb, we really haven’t looked at that much, although I’m probably pretty sure we could make some of it to some degree if we had the segregated tankage. But we haven’t gone that far yet. If California continues to get shorter and shorter, it might be an attractive move. But the arb is open to other areas such as a Grand Junction even Denver occasionally and other places like Salt Lake City and Phoenix on occasion. So there’s where we’re focused mostly.

Matthew Blair: Is there a good rule of thumb for the rail costs associated with that, like maybe $0.30 or $0.40 a barrel – or sorry, a gallon?

David Lamp: Well, normally, any time you move anything by rail, it’s $6 to $8 per barrel. So that’s a good rule of thumb. It depends on how far you go and where you go. So then you have unloading fees and loading fees on the front side. So – but that’s a good rule of thumb.

Matthew Blair: Sounds good. And then my follow-up, do you think anything will change on your WCS exposure as TMX ramps? Or do you expect to receive the same volumes on – I think it’s at least the Express pipeline. There might be one other – and we’ve noticed that the WCS futures curve, it widens out to about $15 a barrel by the end of this year. Is that just from expectations of continuing production growth in Canada?

David Lamp: Yes. I think mostly what you’re seeing right now is the line fill, which is taking, what, 4.5 million barrels off the market permanently. And that’s what brings it down to the $13 range which it is at today. I would expect it to widen back out a little bit once the line fill is complete. And I don’t think – I think most of the barrels that are going to be replaced are the ones that were going offshore out of the Gulf of Mexico. So I’m not anticipating any problems getting barrels. We don’t run all we can move on the pipes. So we end up selling quite a bit in Cushing. And we plan to continue that effort. I don’t see any reason why it wouldn’t continue where the production is today. I think the real benefit of TMX is really for the future, however, it gives the Canadian producers an outlet that they didn’t have before.

And unfortunately, the Keystone got canceled, which would have given that capacity to the United States rather than shipping to the West and the rest of the world. But I think still, the effect will be there, and that means more Canadian crude in the future.

Matthew Blair: Great. Thanks, Dave.

David Lamp: You’re welcome.

Operator: Our next question comes from the line of John Royall with JPMorgan. Please proceed with your question.

John Royall: Hi. Good afternoon. Thanks for taking my question. So I was hoping for some additional color on refining M&A in light of the 8-K. Could that impact some of the things you would otherwise do on the organic side, particularly thinking about the bigger projects you’re considering with RD? Is it sort of an either/or with M&A or could both be done at the same time?

David Lamp: Well, John, remember that our larger RD project, our SAF project, however you want to call it, is really banked on our contribution being our Wynnewood operation of renewable diesel or SAF. What we are doing is, what equity we’re providing, the location, the land, the permits, the design, all the rest will operate it for or whatever. But we will not do the project without a partner that is strategic in nature and is interested in the space, with the idea that we would IPO that company out as an eventual exit strategy. As far as other M&A, there’s some very intriguing deals out there that are transformative for our company as well as others. And I think as we’ve always said, we look at everything, and we continue to look at everything. And like I said, some unique opportunities in the refining space that really made us pick up our pencil again and look at it again. So more to come on that.

John Royall: Great. And then a follow-up, sticking with the 8-K. On the potential strategic options for UAN, I know this is something you looked at about maybe about a year ago. Now it looks like the idea of potentially separating UAN is back on the docket. Can you talk about the type of transaction that could potentially take place there? And what’s changed between then and now in terms of being back and looking at the some of the parts for fertilizer? Is it just the equity coming back a little bit? Or are there other drivers?

David Lamp: Well, I think you probably heard about the recent transaction that’s occurred with – or it hasn’t closed yet, but it’s been proposed for the Wever plant with OCI that kind of mark-to-market a pretty big value, pretty much twice the value of what UAN is today. So that’s what kind of sparked the interest in it and we’re just exploring opportunities that, that might incur going forward.

John Royall: Great. Thank you.

David Lamp: You’re welcome.

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

Neil Mehta: Thanks. Dave, just building on the M&A comments that you have made and in the 8-K. Are there characteristics that you say define what would be a successful M&A transaction for you on the refining side, whether it’s specific regions? And as you think about potential M&A, do you have a preference for packages versus single assets? Just trying to get a context of the framework by which you evaluate success as you consider different options.

David Lamp: Yes. Sure, Neil. I think one of our biggest impediments to our stock price, I think, is our lack of diversification. So we’ve in the past, have pointed to the West is our desired area. But I don’t – I think what we need is size and scale and diversity of our refining fleet, and any of these actions and the available transactions would scratch that itch. So I think that’s mainly what we’re looking for. When you sit here in the Mid-Con and that’s all you got, particularly Group 3, you’re subject to the realms of the market with nothing to offset it other than fertilizer. So – if you look at the size of our fertilizer business compared to the rest of it, it’s relatively small. So any diversification we can do there is a benefit to the stock and the shareholders is my point of view.

Neil Mehta: Yes. Thanks Dave. And the follow-up is just distillate. You have a distillate heavy mix here, which has been a huge tailwind over the last couple of years. It has softened a little bit here more recently and part of that does seem to be seasonal. But has anything changed in your structurally bullish distillate and diesel view? And are you seeing anything real time that would say that things should turn more positive as we work our way through the summer?

David Lamp: Well, we had – we came off of two very mild winters, frankly. Some people say it was the mildest winter ever in the States. I don’t know because we had some severe weather in our markets that makes me wonder if – how much the climate is really changing. But that said, I think the bigger impact is – really is the industrial activity and just the movement of goods around the country has just been kind of anemic. That said, if you just look at – the other thing I’d add to it, we’re up to almost 5% now of renewable diesel in the pool. That was less than 1%, 1.5 years ago. So it’s really come on and it certainly is changing the California market, but it’s probably affecting everywhere to some degree. Now that’s – all that said, if you look at the practicality of EVs in the heavy trucking industry, it’s poor at best and renewable diesel is by far a better solution.

So I don’t think that the market can’t handle that. It’s just – if we have a little bit of any kind of manufacturing and industrial activity, diesel demand will pick right back up. And that’s kind of our view.

Neil Mehta: Okay. Very helpful. Thanks, Dave.

David Lamp: You’re welcome.

Operator: Our next question comes from the line of Paul Cheng with Scotiabank. Please proceed with your question.

Paul Cheng: Hi, good morning, guys. Good afternoon, guys. Dave or Dane, that in the event if there’s a good transaction in refining, how much of the debt now you will be willing to put on in terms of the balance sheet that – I mean, how should we look at it?

David Lamp: Can you repeat it again, Paul?

Paul Cheng: If that’s a good transaction that an acquisition target that you think is really good for you. How far you will be willing to stretch your balance sheet?

Dane Neumann: Yes, Paul, it would obviously depend on the target and what the earnings power of that target would be. We’ve always kind of said we’re comfortable between the 1x and 2x levered ratio. So depending on the target, I don’t think our – we want to change our debt profile materially long term. So I’d still use that as a benchmark over the long haul.

David Lamp: And we want to use our equity to some degree, Paul. So…

Paul Cheng: Right. But I mean that, Dane, I understand your long-term leverage target you haven’t changed. But in terms of the short-term, how far are you willing to go? What is within an acceptable level of that, say, within the 12 months after you close the deal?

Dane Neumann: I’ll lever off what Dave said. It really would depend on the depth of the equity market. Is there a scenario where we’d potentially stretch if there was a very clear path of delevering? Yes, but probably not too aggressively beyond where our current targets are.

Paul Cheng: Okay. Second question. Dane, can you tell us that what is your remaining hedging position for the rest of the year? And also, Dave, when you talk about the second quarter, the RD will be reaching the capacity. Are you talking about reaching the run at 100% because previously, I think you’ve been talking about running maybe more like in the 70%. So I just want to make sure I understand your comment on that.

David Lamp: Yes, Paul, on the RD side of it is we’re planning to run this run at 5,000 barrels per day, which is about 75 of renewable diesel compared to our nameplate of 100. So we’re probably a little higher in the numbers you said, but right in that angle. And what we’re trying to explore here is catalyst life and find the optimum in that. And we’ll sneak up on that, probably the next load increasing it to maybe 6,000, and then we’ll go from there. Your other question…

Dane Neumann: Yes. On open derivative positions, Paul. So for ’24, we’re at about 8% of gasoline and diesel production. But one thing I want to caveat is that production rate does assume a full run rate of Wynnewood. So we have to – once we know more, we’ll be able to appropriately adjust what that would look like with any downtime that’s associated with the fire. And then for ’25, we’re about 4% of total gasoline-diesel production. That’s 100% of that is diesel production. So 9% on diesel production for ’25.

Paul Cheng: Dane you say 4% in – 4% in gasoline and diesel, but that’s because it’s all in diesel, so it’s 9% in diesel and 0% in gasoline, right?

Dane Neumann: Yes, that’s correct.

Paul Cheng: And is the position for the second quarter right now is making money or losing money?

David Lamp: Making money for the second half.

Paul Cheng: For the second quarter right now. Is your derivative position in the second quarter is making money or losing money?

David Lamp: Yes, we’re making money. It’s in the money right now, Paul.

Paul Cheng: Thank you.

David Lamp: You’re welcome.

Operator: Thank you. We have no further questions at this time. I would like to turn the floor back over to management for closing comments.

David Lamp: Again, I’d like to thank you all for your interest in CVR Energy. Additionally, I’d like to thank our employees for their hard work and commitment towards safe, reliable and environmentally responsible operations. We look forward to reviewing our second quarter 2024 results in our next earnings call. Thank you.

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.