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Greetings, and welcome to the CVR Energy First Quarter 2025 Conference Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Richard Roberts, Vice President, Financial Planning and Analysis and Investor Relations. Thank you, sir. You may begin.

Thank you, Christine. Good afternoon, everyone. We very much appreciate you joining us this afternoon for our CVR Energy first quarter 2025 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 2025 first quarter results, let me remind you that this conference call may contain forward looking statements as determined by the federal securities laws. For this purpose, any statements made during this call that are not statements of historical facts may be deemed to be forward looking statements. You are cautioned that these statements may be affected by important factors set forth in our filings with the Securities and Exchange Commission and in our latest earnings release. As a result, actual operations or results may differ materially from the results discussed in the forward looking statements. We undertake no obligation to publicly update any forward looking statements whether as a result of new information, future events or otherwise, except to the extent required by law. This call also includes various non-GAAP financial measures. The disclosures related to such non GAAP measures, including reconciliation to the most directly comparable GAAP financial measures are included in our 2025 first quarter earnings release that we filed with the SEC and Form 10-Q for the period and will be discussed during the call. With that said, I'll turn the call over to Dave.

Thank you, Richard. Good afternoon, everyone, and thank you for joining our earnings call. Yesterday, we reported the first quarter consolidated net loss of $105 million and a loss per share of $1.22 EBITDA was a loss of $61 million. Our results were impacted by the planned turnaround at Coffeyville, the Coffeyville refinery, unplanned events in January and an unfavorable mark to market impact of our outstanding RFS obligation. In our Petroleum segment, combined total throughput for the first quarter of 2025 was approximately 125,000 barrels per day and light product yield was 95% on crude oil processed. The planned turnaround at Coffeyville began in late January following an incident at our Naphtha Hydrotreater during freezing weather conditions. Inefficiencies resulting from the incident, including mobilizing contractors earlier than planned, among other factors, impacted the duration of the turnaround by approximately four weeks. Startup of the refinery is underway and we currently expect to ramp to full rates over the course of the second quarter as we draw down crude and intermediate inventories. For the duration of 2025 and 2026, we do not currently have any additional turnarounds planned in the refining segment with the next planned turnaround at Wynnewood scheduled for 2027. Group 3211 benchmark cracks averaged $17.65 per barrel for the first quarter of 2025 compared to $19.55 per barrel for the first quarter of last year. Average RIN prices in the first quarter of 2025 were approximately $0.84 on an RVO weighted basis, an increase of over 25% from the previous year period. On a per barrel basis, RINs were approximately $4.75 per barrel or more than 25% of the Group 3211 crack spread for the quarter. Regarding the RFS, we were pleased with the First Circuit granting the Wynnewood Refining Company's unopposed motion to stay its 2023 compliance obligations in March. Also in March, the Supreme Court heard oral arguments on whether the venue for challenges to the EPA's denial of small refiner exemptions lies exclusively within the DC Circuit. Recurrent expected ruling on that venue case in the second quarter, although the ruling should make little difference in this case since the DC Circuit like the Fifth Circuit before it, also held EPA's denial of small refinery exemptions were arbitrary, capricious and contrary to the law. The Wynnewood Refinery Company filed its 2025 petition for small refinery exemptions last year, but EPA once again missed its deadline to rule. We urge EPA to meet with us as soon as possible or will be forced to file suit again. At this point, EPA is sitting on Wynnewood small refinery exemption petitions for 2019, '20 '20, ‘21, '22 and ‘23. The prior administration only acted on our 2023 petition when it denied it in January for ridiculous and we think illegal reasons. The RIN market causes higher prices at the pump for all Americans, which EPA has admitted. As a reminder, we currently estimate the cost of RINs at $0.10 to $0.15 per gallon on all transportation fuels. We believe that the EPA should be doing everything it can to keep fuel prices low. At a minimum, EPA should immediately hit the easy button and apply the same alternative compliance strategy it used in 2017 and 2018 for all historical SREs from 2019 to 2024. All these compliance periods are in the past, this harms no one and could save small refineries from risk of closure due to the crushing weight of RFS. Despite EPA's continued lack of action, we are encouraged by the administration's statement that they are reassessing the position on their position on SREs. I'm confident under President Trump's leadership, the EPA will see the critical role small refineries like ours play in supporting rural communities across America, exactly why Congress included the small refinery exemptions in the renewable fuels legislation. For the first quarter of 2025, we processed approximately 14 million gallons of vegetable fuel oil in our renewable diesel unit at Wynnewood. Gross margin was approximately $1.13 per gallon for the first quarter of 2025 compared to $0.65 per gallon for the first quarter of 2024. The blender's tax credit expired at the end of 2024 and we did not recognize any clean fuel production credits in the quarter as the final rules have not been issued. Despite the loss of the BTC, we generated positive adjusted EBITDA in the Renewables section, primarily driven by increased RIN prices and reduced feedstock basis. In the Fertilizer segment, both facilities ran well during the quarter with 1%. Nitrogen fertilizer prices in the first quarter of 2025 were higher for ammonia and slightly lower for UAN compared to the first quarter of 2024. And we continue to see strong demand for both products as we head into the spring planting season. Now, let me turn the call over to Dane to discuss our financial highlights.

Thank you, Dave, and good afternoon, everyone. For the first quarter of 2025, our consolidated net loss was $105 million, losses per share were $1.22 and EBITDA was a loss of $61 million. Our first quarter results include a negative mark to market impact on our outstanding RFS obligation of $112 million a favorable inventory valuation impact of $24 million and unrealized derivative gains of $3 million. Excluding the above mentioned items, adjusted EBITDA for the quarter was $24 million and adjusted loss per share was $0.58 Adjusted EBITDA in the Petroleum segment was a loss of $30 million for the first quarter with the decline from the prior year period driven by reduced throughput volumes due to the planned and unplanned downtime at Coffeyville, along with lower product cracks in Group 3. Our first quarter realized margin adjusted for the mark to market impacts, inventory valuation and unrealized derivative gains was $7.72 per barrel, representing a 44% capture rate on the Group 3211 benchmark. Net RINs expense for the quarter, excluding the mark to market impact was $27 million or $2.47 per barrel, which negatively impacted our tax rate for the quarter by approximately 14%. The estimated accrued RFS obligation on the balance sheet was $438 million at March 31, representing $488 million RINs mark to market at an average price of $0.90. As a reminder, our estimated outstanding RIN obligation excludes the impact of any small refinery exemptions. Direct operating expenses in the Petroleum segment were $8.58 per barrel for the first quarter compared to $5.78 per barrel in the first quarter of 2024, compared to $5.78 per barrel in the first quarter of 2024. The increase in direct operating expense per barrel was primarily driven by lower throughput volumes. Adjusted EBITDA in the Renewables segment was $3 million for the first quarter, an improvement from the first quarter of 2024 adjusted EBITDA of negative $5 million. The increase in adjusted EBITDA was driven by a combination of higher throughput volumes, increased rents prices and reduced feedstock basis, partially offset by the expiration of the VTC. Adjusted EBITDA in the Fertilizer segment was $53 million for the first quarter with higher UAN sales volumes and higher ammonia sales prices driving the increase relative to the prior year period. Partnership declared a distribution of $2.26 per common unit for the first quarter of 2025. As CVR Energy owns approximately 37% of CVR Partners common units, we will receive a proportionate cash distribution of approximately $9 million. Cash consumed by operations for the first quarter of 2025 was $195 million and free cash flow was a use of $285 million. Significant uses of cash in the quarter include $94 million of capital and turnaround spending, $47 million for cash interest, $12 million paid for the non-controlling interest portion of the CVR Partners fourth quarter 2024 distribution and a cash used from working capital of approximately $113 million partially associated with inventories being built during the Coffeyville turnaround. Total consolidated capital spending on an accrual basis was $55 million which included $49 million in the Petroleum segment, $6 million in the Fertilizer segment and less than $1 million in the Renewable segment. Turnaround spending on an accrual basis in the first quarter was approximately $166 million. For the full year of 2025, we estimate total consolidated capital spending to be approximately $180 million to $210 million and turnaround spending to be approximately $180 million to $200 million. Turning to the balance sheet, we ended the quarter with a consolidated cash balance of $695 million which includes $122 million of cash in the Fertilizer segment. Total liquidity as of March 31, excluding CVR Partners was approximately $894 million which was comprised primarily of $573 million of cash and availability under the ABL facility of $321 million. While we ended the quarter above our targeted minimum cash balances, I want to highlight that the majority of the cash spend associated with the Coffeyville turnaround will be incurred in the second quarter, which should be partially offset by a drawdown of inventories built during the turnaround. Looking ahead to the second quarter of 2025, for our Petroleum segment, we estimate total throughputs to be approximately 160,000 to 180,000 barrels per day, direct operating expenses to range between $105 million and $115 million and total capital spending to be between $35 million and $40 million. For the fertilizer segment, we estimate our ammonia utilization rate to be between 93% to 97%, with some downtime planned at East Dubuque in the quarter. We expect direct operating expenses excluding inventory impacts to be between $57 million and $62 million and total capital spending to be between $18 million and $22 million. For the Renewables segment, we estimate second quarter 2025 total throughput to be approximately 16 million to 20 million gallons, direct operating expenses to range between $8 million and $10 million and total capital spending to be between $2 million and $4 million. With that, Dave, I'll turn it back over to you.

Thanks, Dane. Refunding market conditions began to improve in the first quarter due in part to a heavy spring maintenance season and the closure of one U.S. refinery. Several more closures have been announced in the U.S. And in Europe for 2025 and 2026. Recent data from EIA indicates days of gasoline supply are 12% below the five year average, while diesel is currently 17% below. Within the MidCon where we operate, days of supply are currently for gasoline supply are currently 8% below the five year average and diesel is nearly 13% below. Given the improvement in supply and demand fundamentals and the increase in RIN prices, we are surprised that cracks are not higher. In the near term, the evolving tariff environment and associated concerns in the market around potential demand impacts will likely weigh on the market to some degree. As it relates to tariffs and our refining assets, we are relatively well positioned given our location at MidCon and our limited exposure to Canadian crude oil. Unlike other refiners in Pad 2, they are more dependent on heavy Canadian crude oil, we typically only run a few thousand barrels per day of WCS at Coffeyville and sell the remainder at Cushing. If those barrels are ultimately not economic, we can run the Coffeyville refinery at full rates with no Canadian crude oil at all. During the turnaround at Coffeyville, we completed tie-ins for the initial phase of the distillate recovery project. This project should give us the ability to increase Coffeyville's distillate yield by approximately 2% and we have a similar project planned at Wynnewood that has already been received Board approval. Over the next few months, we plan to install some additional piping and revamp some of our tankage at Coffeyville, which should enable us to make up to 9,000 barrels a day of jet by the end of the third quarter. We also have the potential to increase capacity further with additional investment. We believe the opportunity to ship barrels to the West will continue to grow over the next several years and with jet fuel being a likely important part of the mix. As a reminder, jet fuel production is not subject to an RVO and shifting production from diesel to jet fuel would reduce our annual RIN obligations. We also continue to make progress on the Wynnewood alkylation project that when completed, will eliminate usage of HF acid and provide a margin capture improvement opportunities through increased production of premium gasoline. In the Renewable segment, we completed catalyst change in January and we continue to run the unit at 5,000 barrels per day in an effort to optimize yield and catalyst life. RIN prices have increased over the past few months and due in part to the significant decline in D4 RIN generation after the expiration of the blenders tax credit at the end of 2024. As we continue to evaluate whether renewable business makes sense, we currently intend to operate the renewable diesel unit at similar rates while we wait clarity on the PTC and or see the final rules on the PTC. As we stated on our last earnings call, we remain fully willing to participate in the renewable space, but cannot invest additional time and capital without further assurance, the government will support the businesses it created. In the Fertilizer segment, recent USDA estimates are calling for an inventory carryout levels for corn and soybeans at 10% or less. The spring planting season is well underway and the weather has been favorable. With the USDA estimating 95 million acres of corn planted this year, we expect to see strong fertilizer demand for the spring and prices have been increasing over the past few months. Looking at the second quarter of 2025, quarter-to-date metrics are as follows: Group 211 cracks have averaged $24.67 per barrel, with the Brent TI spread at $3.39 per barrel and the WCS differential at $9.55 per barrel under WTI. The HOBO spread has averaged a negative $1.47 per gallon. As of yesterday, Group 3211 cracks were $27.15, Brent TI was $3.65 and WCS was $9.6 under WTI. The HOBO spread was a negative $1.62 per gallon and RINs were approximately $6.42 per barrel. Prompt fertilizer prices are approximately $600 a ton for ammonia and $380 per ton for UAN. With the large turnaround at Coffeyville behind us, we are well positioned to capitalize on any and all continued improvements in the refining sector as we approach the summer driving season. And we look forward to the remainder of 2025 and 2026 with no additional planned refinery turnarounds. In addition to our constant focus on safe reliable operations at our facilities, we will prioritize efforts to reduce debt and restore our balance sheet to targeted leverage ratios as soon as we can, subject to market and other conditions. We also continue to look for ways to improve capture, reduce cost and ultimately grow our business profitably. With that, we're ready for questions. Operator?

Thank you. We will now be conducting a question-and-answer session. [Operator Instructions] Thank you. Our first question comes from the line of Manav Gupta with UBS. Please proceed with your question.

Good morning, guys. I wanted to understand a little bit more on the refining macro. On one hand, you are indicating that you actually believe that market conditions did improve and if it was not for the tariffs you believe the cracks would be higher. So I'm just trying to understand do you see a pretty strong demand or at least resilient demand in the regions in which you are operating versus a possibility of a recession, which could actually mean significantly lower demand. So help us understand what you're seeing in terms of refined product demand out there in the markets you operate?

Well, Manav, I think as I mentioned in the prepared remarks, the days of supply have shrunk quite a bit compared to the five year average, which indicates to us that the supply demand balance is correcting itself. And some of that may be due to the heavy turnaround season for the spring. But in general, I think it shows a little bit more discipline in the market. And as that wears off, it would be interesting to see what demand does in the summer season and how much of uptick we get in gasoline. Diesel is still a little bit slow, but inventories are telling me that it's the crack is probably a little bit low, cracks probably a little bit low from where it should be. And of course offsetting it all is this increase in the RVO and the RIN price that accelerated almost $2 in the quarter.

Perfect guys. A quick question here on the RVO and SRE side. I mean, Trump administration last time in office understood the importance of SREs. So that's one. Other that we are hearing out there is they actually want to raise the RVO on the D4 side, with the multiple participants being involved in the discussion. So how do you see this playing out? And in your opinion, is the right way to decouple D4 and D6 and let them operate separately, help us understand what would be the best solution in your opinion? Thank you.

Well, this is as you know, is a highly controversial issue. But we do believe decoupling 4s from 6s is an important move. And the only way it can really happen is if the D6 mandate is lowered or is something below an D10 that would really -- and is really adjusted for volume, because we're having it fixed at $15 billion which by the way is the majority of the $22 billion, $23 billion mandate, really just drives D4s into having to make it up because the volumes are not there. All that said, again, the government created these businesses and what they did with the RVO that was issued three years ago was just cut the legs out from under it and generate a lot of excess D4s and just kind of mess the whole thing up. And then the BTC expired, which is --which automatically increases the RIN price. So, who suffers out all this? Well, it's the driving public. The American citizen that is the hardworking men and women who really depend on low cost fuel to really drive the economy. So, I think the government's got a lot of thinking to do. In our minds, what they should do is do everything they can to minimize RIN prices just because it affects the driving public. That said, on the other hand, they should set production on the renewable diesel and biodiesel to what the production capabilities are, which they have not done. And the law kind of implies us what should be done. So, as I've said many times, this RFS was poorly conceived, poorly written, poorly implemented and poorly managed. And I don't see that changing.

Thank you, sir.

You're welcome.

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

Hey, good morning, Dave, and congrats on the positive RD EBITDA result in the first quarter even without the 45C. Could you talk about how things are progressing so far in the second quarter? Do you still expect to be EBITDA positive in Q2? And then some of your peers have been recording the 45C benefit. So could you talk about what you need to see to get more comfortable in recording the 45C for CVI?

Sure. Well, I don't know that we see much changing other than RINs going up in the second quarter. And that obviously is helping our margins in renewable diesel. Bean oil has also gone up and the HOBO, as I mentioned, has gone more negative than ever. So, all those offsets all depends on what basis does as well as our hedging strategy on the feedstocks and the product. So that's kind of where we sit today. As far as the PTC and recognizing that, Dane, you want to address that?

Yeah, Matt. The notice that the IRS put out in January just left a number of questions as to what specifically counts as a qualifying sale. We just wanted to get a little more comfort and clarity around the qualifying sale provisions that are out before we go ahead and book anything. In addition to that, there's still a lot of talk around what the actual PTC credit value could be. Just for reference, we could ballpark the number we didn't book around $2 million and we don't lose the ability to book that going forward. It's just we want more certainty before we take it. So a little bit of a conservative position while things shake out.

Thanks. That's helpful. And then my follow-up is around refinery M&A and the potential for industry consolidation. So if we look back over the past 10 years, which I think covers a range of environments, there's been pretty significant outperformance by the large cap refiners. And if we look forward, futures curves on the product side or a little weaker future screws on crude differentials are relatively tight for inland barrels. It really seems like the benefits of economies of scale would be even greater going forward. And so my question is, do you agree with this assessment? And do you think that small refiners need to get bigger? And if so, do you think it will actually happen? Thank you.

Well, a lot in that question, Matt. I think we would definitely agree with you, economies of scale or the only way to survive these days. And some of our problem is that we're highly concentrated in the MidCon only. Anything we can do to diversify that is helpful as long as it's profitable. . So I do think there's potential out there for some more consolidation, although it's getting pretty thin on the counterparties that can even make any sense, but we definitely agree with your approach on that.

Thank you.

Thank you.

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

All right. Dave and team thanks for taking the time. My first question just on Coffeyville. Congratulations on getting that asset up and running. I know the turnaround took a little bit longer and extended into Q2. But just talk about what you achieved during that the time to the next turnaround and thoughts on the ability to start up stay up?

Yeah. Neil, I guess I would tell you this is not the way to do a turnaround having to come down early like we did, I mean losing on Naphtha really, really hurt us. And that was in the dead of winter, of course, which didn't help either. And we had a pretty cool, I'll call it, cool, not necessarily cold winter. And when you get out of sequence, all kinds of things happen, you get different -- you get a different team that may have been occupied somewhere else on your contractors. Just about anything that can go wrong went wrong for us in this turnaround. And that shows in the duration was extended. Whether or not we have an insurance claim to do, we're still contemplating, but it looks like to me that there's a good chance there could be something just because of the delays that hit us and the lack of productivity during weather events and other factors that happened that was out of our control. When you hit the -- you have 45,000 man hours that you pre-turnaround work that you needed to complete that before you start the turnaround and shove that into the turnaround, you can see how it is very disruptive. But I think we're through it largely, and we're going to recover strong. We're looking forward to improve margins. It's been a bit of a drought since we've had the kind of margins we're seeing right now. And obviously, even despite RINs being elevated, our profitability should be improved.

Yeah. Makes sense. And then as assuming margins start to come back a little bit, how do you think about the potential to return the dividend? There's been a big part of the CVI story for a long time. So just curious on that. And I have a couple of other questions queue back in.

Yeah. You've heard me say many times, we're a dividend machine. We have taken a Siesta on that a little bit here just because of where margins were for most of ’24. But our goal, as I mentioned in our prepared remarks, is to pay down this additional debt that we took on get back to normal and start dividend at that time. And of course, the Board looks at it every month or every quarter. And I think they'll continue to do that. And as the margins stay where they're at, we'll be looking at a dividend in the future.

I’ll queue back. Thank you.

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

Hi, good afternoon. Thanks for taking my question. So my first question is on the jet expansion at Coffeyville. When you spoke about that in 4Q you mentioned at the time one big constraint to think about or 1 big challenge to think about was building a book of customers to buy Jet. Is there any update you can give on those efforts? Do you think that the demand will be there by the time you're ready to start producing?

Well, I think it will be, John. I mean where we're at right now is a lot of the major airlines are on three-year bid contracts, and those are coming up for at least two of them in '25. So we're anticipating that we'll achieve some of that business. So that's probably our greatest look. We also have our fuel by rail that we have that if the arbs open to the west, we can move jet that way. And I think -- I don't think it's going to be a big problem, but it's going to take a little time to build a book of business. If you look at what we've done at Wynnewood, we've made Jet there for years and most of it was through military contract. We lost that last year, and we've still been successful in moving jet out of the plant. So I don't think it's going to be a big problem.

Great. Thank you. And then my follow-up on the renewable side. You talked about needing further assurance to get to a positive investment decision on project within renewables today. Can you talk about what would give you that type of assurance? Is it just finalizing the PTC rules and the LCFS plan and getting the RFS complete. Or would you need some sort of longer-term assurance? Is it more than just the near-term rules?

Well, if there's one thing we've learned in the renewable diesel business is that you can't count on credit. They change the government administrations change, you get different philosophies. And the approach we've taken is largely we're willing to do SAF somebody is willing to take the credit risk we'll give them the credits that are there, but we're not going to take it ourselves. And that's just kind of summarizes renewable diesel and SAF to me across the board. We have a larger project at Coffeyville that we've put together and designed and have the cost estimate done and -- but it's a 500 million-gallon year plan, and it's costly. But if SAF's really needed and renewable diesel, and we could design that for 100% SAF if we wanted to. We sit in the middle of the ag area. Certainly for corn oil, we're advantaged, and that's a low CI feedstock. So there's a lot we can do. But we're not going to do it if we can't trust the government to provide a steady stream of credits that when you're taking a $4 or $5 oil and trying to shove it into a $2 market, it just doesn't work. You're welcome.

Thank you.

You’re welcome.

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

Hey, guys. Good morning or good afternoon. Then maybe Dane, maybe you can help me. I still couldn't understand why the renewable we saw is so good. In the fourth quarter, your gross margin is $1.13 and in the first quarter, $1.15. In the first quarter, you are doing about $0.93, but you lost BTC that's $1 per gallon. So I mean what else is in there? In other words, is the first quarter, we is a good baseline or that there's something related to your hedging program or that the way how you can the inventory. And as a result of that, that's not a totally good baseline.

Yes, Paul, I think you hit one of them on the head. There was about a $0.14 per gallon favorable realized hedge in place just associated with the inventory. In addition to that, the elevated RINs price picked up another, call it, $0.01 $0.15 a gallon. So those two just gave us a lift right away. There were some inventory impacts, maybe another $0.09 to $0.15, something like that. So to say to say it's a good baseline. There were some items that were we call it maybe exceptional for the period. We'll, of course, keep deploying the same strategy we have and see what results come out of it in the volatile market of renewable diesel. The one thing that was different that is probably more baseline is just our feedstock basis was much improved. One really one of our highest cost feedstocks was lower than our lowest cost feedstock in the prior period, which is really a testament to having the pretreater on, getting into that feed, getting better yields and running more reliably. So from that component, I would say you could baseline there that we've improved that. But as far as some of the other items go, I wouldn't want to say that's a permanent fixture in the volatile market that RD is.

And yield was up to, Paul. So I mean, don't underestimate that a 5% fuel improvement goes all the way.

Well, I'm trying to say, okay, I mean, if you report $0.93 based on Dane what you say about those three items roughly about $0.45. So is that a good baseline that we can use to project forward is assuming somewhere in the $0.45 and that's not including PTC at all. That seems like it's a phenomenal number comparing to some of your larger competitors than what they report.

So I guess I would say, Paul, for the -- if you're referencing like an adjusted margin, it was $0.85 4Q, $0.93 in 1Q. That takes out that inventory benefit that I referenced?

Right.

Yeah. So the $0.08 improvement. I mean, you got $15 million from hedging. You've got another dime or so. So if you take out that $0.20, you'd be in the $0.70 range. That is excluding PTC, which should be an incremental kicker. But again, I think the market is so volatile that I wouldn't want to set a baseline of expectations for how much these markers move around.

Right. Understand. And Dane, the hedging that the $0.14 benefit from the hedging, are we continue going to see that into the second and third quarter or that the hedging benefit will just disappear or that reverse?

Yes, that hedging is really around price exposed inventory or excess inventory. So we'll take a protective position or short position on any excess inventories. So from that perspective, again, subject to what the market does and how our feed performs.

I see. Dave, you -- I think in the past that -- and you say it here again about the economy of scale, the desire that for diversification beyond your current footprint? Where are we in that whole exercise at this point? Are we essentially say, just waiting for other people that come to you -- or that is still being actively pursued or that -- is there any comments that you can share?

Well, nothing I can really share, Paul. As we've said before, we really -- we look at everything that comes on the market and try to screen it through our picture. Historically, to date, it's been the bid ask has been too wide for us and thank goodness because the market really took a hit in 2024 -- come off a record year in '23 and go to just a record low year in '24. So I think we're pretty conservative. We want -- I won't say we're bottom fishers, but we're pretty close to that, and we're not going to overpay for an asset.

And can I just make some 1 clarification. I think Dane you earlier say that $2 million for the PTC, if you will be able to fully book it for the quarter, is that -- do I get the number right?

That is correct. And as I mentioned, there's ongoing debate around what the value of the PTC is based on your feed and there's some questions out there. So that number I wouldn't say is final. But based on some of the rumors we've heard or some of the conversations that are going on, that could be a conservative number. It could be double that.

Okay, very good. Thank you.

You’re welcome, Paul.

Our next question is a follow-up from Neil Mehta with Goldman Sachs. Please proceed with your question.

Yeah. Two quick ones. Dave, you always have a great perspective on U.S. shale. I mean, TI is pushing on $60 at this point. What's your perspective on U.S. oil growth? And what are the pricing levels that you think activity changes?

Well, I think I've said many times is I think we're -- it depends on the company you're talking about, but a lot of them are breakevens are being approached with the numbers we're at slightly breakeven, slightly below that, very much depends on the region you're in. Obviously, Permian is probably the lowest in the Arco or DJ Basin or some of those others are probably the higher or Bakken 2. So it really depends on where you're at and rigs are falling. I expect that to continue. And we've had -- in our basin, and Arco had really probably pretty big growth, but it's really one player. What they're going to go do from here on out, we really don't know. Our gathering volumes are still pretty strong, but anticipating they're going to fall off a little bit.

All right. Well, we'll keep on watching. The other one is a little trickier that I think a lot of the investment community is a little confused about all the insider activity at the company. I don't know if anything you can comment around that, just -- it's unusual.

We probably can't comment much on that. You probably have to ask them themselves.

Okay, thanks. Thanks, guys.

Welcome, Neil.

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.

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 to our safe, reliable and environmentally responsible operations. We look forward to reviewing our second quarter 2025 results in our next earnings call. Thank you very much. .