CVR Energy - Earnings Call - Q1 2025

Executive Summary

• Q1 2025 was weak on reported metrics due to Coffeyville’s planned turnaround and unplanned January downtime, plus a $112M unfavorable RFS mark-to-market, driving net loss of $105M, GAAP EPS of -$1.22, and EBITDA of -$61M; adjusted EBITDA was $24M and adjusted EPS was -$0.58.
• Versus S&P Global consensus, CVI materially beat on revenue ($1.65B vs $1.39B*) and on normalized/adjusted EPS (-$0.58 vs -$0.88*), while EBITDA missed (-$61M actual vs -$9.5M*), reflecting downtime and RFS headwinds (Values retrieved from S&P Global).
• Q2 2025 guidance was raised for petroleum throughput (160–180kbpd) and renewables throughput (16–20MM gal), lowered for turnaround spend, and signaled no planned refinery turnarounds until 2027, setting up better operating leverage into driving season.
• Dividend remains suspended for Q1, but management reiterated an intent to delever and consider dividend resumption as cracks improve; jet fuel and distillate recovery projects aim to lift capture and reduce RIN exposure in H2 2025.

What Went Well and What Went Wrong

What Went Well

• Renewables delivered a positive margin and EBITDA: renewables margin of $16M ($1.13/gal) and EBITDA of $6M; adjusted renewables EBITDA was $3M, aided by higher D4 RIN and LCFS pricing and improved feedstock basis.
  Quote: “Despite the loss of the BTC, we generated positive adjusted EBITDA in the renewable [segment] primarily driven by increased RIN prices and reduced feedstock basis.”
• Nitrogen fertilizer strength: EBITDA $53M on $143M sales, ammonia utilization 101%, and gate ammonia prices up 5% YoY to $554/ton, underpinned by strong spring demand.
• Execution on refining projects: tie-ins completed for Coffeyville distillate recovery (target ~+2% distillate yield) and jet fuel initiative to enable up to ~9kbpd by end-Q3, positioning for margin uplift and reduced RIN burden.

What Went Wrong

• Coffeyville downtime drove Petroleum losses: Petroleum segment EBITDA of -$119M and adjusted EBITDA of -$30M; total throughput fell to ~120kbpd from ~196kbpd YoY.
• RFS volatility: $112M unfavorable RFS mark-to-market burdened results; net RIN expense (ex-MTM) was $27M in the quarter, with average RIN prices rising ~25% YoY.
• Cash burn and FCF: cash decreased by $292M in Q1 and free cash flow was -$285M, reflecting turnaround and working capital build during downtime.

Transcript

Operator (participant)

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. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. 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.

Richard Roberts (VP of Financial Planning and Analysis and Investor Relations)

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 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 reconciliation to the most directly comparable GAAP financial measures, are included in our 2025 first quarter earnings release that we filed with the SEC in Form 10-Q for the period and will be discussed during the call. With that said, I'll turn the call over to Dave.

Dave Lamp (President and CEO)

Thank you, Richard. Good afternoon, everyone, and thank you for joining our earnings call. Yesterday, we reported a 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 3 2-1-1 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 3 2-1-1 crack spread for the quarter.

Regarding the RFS, we were pleased with the Fifth 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 venues for challenges to the EPA's denial of small refinery exemptions lies exclusively within the D.C. Circuit. We currently expect a ruling on that venue case in the second quarter, although the ruling should make little difference in this case since the D.C. 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 Refining Company filed its 2024 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's small refinery exemption petitions for 2019, 2020, 2021, 2022, and 2023. 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 $0.10-0.15 per gallon on all transportation fuels. We believe that 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 the 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 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 small refinery exemptions in the renewable fuels legislation. For the first quarter of 2025, we processed approximately 14 million gallons of vegetable 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 renewable section, primarily driven by increased RIN prices and reduced feedstock basis. In the fertilizer segment, both facilities ran well during the quarter with a consolidated ammonia utilization rate of 101%. 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. 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.

Dane Neumann (EVP and CFO)

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 RIN mark-to-market impacts, inventory valuation, and unrealized derivative gains was $7.72 per barrel, representing a 44% capture rate on the Group 3 2-1-1 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 capture 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. The increase in direct operating expense per barrel was primarily driven by lower throughput volumes.

Adjusted EBITDA in the renewable segment was $3 million for the first quarter, an improvement from the first quarter of 2024 adjusted EBITDA of -$5 million. The increase in adjusted EBITDA was driven by a combination of higher throughput volumes, increased RINs prices, and reduced feedstock basis, partially offset by the expiration of the BTC. 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. The 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 use 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 2025, we estimate total consolidated capital spending to be approximately $180-$210 million, and turnaround spending to be approximately $180-$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 160,000-180,000 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% and 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 renewable segment, we estimate second quarter 2025 total throughput to be approximately 16-20 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.

Dave Lamp (President and CEO)

Thanks, Dane. Refining market conditions began to improve in the first quarter in part due 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 Mid-Continent where we operate, days of supply 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 in the Mid-Continent and our limited exposure to Canadian crude oil. Unlike other refineries in PADD 2 that 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 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 shift 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 opportunity through increased production of premium gasoline.

In the renewable segment, we completed a 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 due in part to the significant decline in D4 RIN generation after the expiration of the Blender's Tax Credit at the end of 2024. As we continue to evaluate whether the renewable business makes sense, we currently intend to operate the renewable diesel unit at similar rates, while we wait clarity on the BTC and/or see the final rules on the PTC. As we stated in 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 inventory carry-out 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 3 2-1-1 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 -$1.47 per gallon.

As of yesterday, Group 3 2-1-1 cracks were $27.15, Brent TI was $3.65, and WCS was $9.60 under WTI. The HOBO spread was a -$1.62 per gallon, and RINs were approximately $6.42 per barrel.

Prompt fertilizer prices are approximately $600 a ton for ammonia and $3.80 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.

Operator (participant)

Thank you. We will now be conducting a question-and-answer session. If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star two if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. One moment, please, while we poll for questions. Thank you. Our first question comes from a line of Manav Gupta with UBS. Please proceed with your question.

Manav Gupta (Executive Director)

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. I am 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? Help us understand what you are seeing in terms of refined product demand out there in the markets you operate.

Dave Lamp (President and CEO)

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. Some of that may be due to the heavy turnaround season for the spring. In general, I think it shows a little bit more discipline in the market. As that wears off, it would be interesting to see what demand does in the summer season and how much of an uptick we get in gasoline. Diesel is still a little bit slow, but inventories are telling me that the cracks are probably a little bit low from where it should be. Of course, offsetting it all is this increase in the RVO and the RIN price that accelerated almost $2 in the quarter.

Manav Gupta (Executive Director)

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. That is one. The 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. How do you see this playing out? 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.

Dave Lamp (President and CEO)

This is, as you know, a highly controversial issue. We do believe decoupling fours from sixes is an important move. The only way it can really happen is if the D6 mandate is lowered or is something below an E10 that 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. The BTC expired, which automatically increases the RIN price.

Who suffers out of all this? It is the driving public, the American citizen, the hardworking men and women who really depend on low-cost fuel to drive the economy. I think the government's got a lot of thinking to do. In our minds, what they should do is 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 renewable diesel and biodiesel to what the production capabilities are, which they have not done. The law kind of implies that is what should be done. As I have said many times, this RFS was poorly conceived, poorly written, poorly implemented, and poorly managed. I do not see that changing.

Manav Gupta (Executive Director)

Thank you, sir.

Dave Lamp (President and CEO)

You're welcome.

Operator (participant)

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

Matthew Blair (Managing Director)

Hey, good morning, Dave. And congrats on the positive RD EBITDA result in the first quarter, even without the 45Z. Can 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 45Z benefit. So could you talk about what you need to see to get more comfortable in recording the 45Z for CVI?

Dave Lamp (President and CEO)

Sure. I do not know that we see much changing other than RINs going up in the second quarter. That obviously is helping our margins in renewable diesel. Bean oil has also gone up, and HOBO, as I mentioned, has gone more negative than ever. All those offsets all depend on what basis does, as well as our hedging strategy on the feedstocks and the product. That is 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. We don't lose the ability to book that going forward. It's just we want more certainty before we take it. A little bit of a conservative position while things shake out.

Matthew Blair (Managing Director)

Thanks. That's helpful. My follow-up is around refiner M&A and the potential for industry consolidation. 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. If we look forward, futures curves on the product side are a little weaker. Futures curves 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. My question is, do you agree with this assessment? Do you think that small refiners need to get bigger? If so, do you think it'll actually happen? Thank you.

Dave Lamp (President and CEO)

A lot in that question, Matt. I think we would definitely agree with you. Economies of scale are the only way to survive these days. Some of our problem is that we're highly concentrated in the Mid-Continent only. Anything we can do to diversify that is helpful as long as it's profitable. 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. We definitely agree with your approach on that.

Matthew Blair (Managing Director)

Great. Thank you.

Dave Lamp (President and CEO)

Thank you.

Operator (participant)

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

Neil Mehta (Head of Americas Natural Resources Equity Research)

All right, Dave and team. Thanks for taking the time. My first question is 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.

Dave Lamp (President and CEO)

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 Hydrotreater really, really hurt us. That was in the dead of winter, of course, which did not help either. We had a pretty cool, I will call it cool, not necessarily cold winter. When you get out of sequence, all kinds of things happen. 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. It shows in the duration it was extended. Whether or not we have an insurance claim to do, we are still contemplating.

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 the weather events and the other factors that happened that were out of our control. When you hit the 45,000 man-hours of pre-turnaround work that you needed to complete before you start the turnaround and shove that into the turnaround, you can see how it is very disruptive. I think we're through it largely, and we're going to recover strong. We're looking forward to improved margins. It's been a bit of a drought since we've had the kind of margins we're seeing right now. Obviously, even despite RINs being elevated, our profitability should be improved.

Neil Mehta (Head of Americas Natural Resources Equity Research)

Yeah. Makes sense. Assuming margins start to come back a little bit, how do you think about the potential to return the dividends? It's been a big part of the CVR Energy story for a long time. I was curious on that. I have a couple of other questions.

Dave Lamp (President and CEO)

Well, you.

Neil Mehta (Head of Americas Natural Resources Equity Research)

I'll cue back in.

Dave Lamp (President and CEO)

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 2024. 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. Of course, the board looks at it every month or every quarter, and I think they'll continue to do that. If margins stay where they're at, we'll be looking at a dividend in the future.

Neil Mehta (Head of Americas Natural Resources Equity Research)

Okay. I'll cue back in. Thanks, Dave.

Operator (participant)

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

John Royall (Executive Director)

Hi. Good afternoon. Thanks for taking my question. My first question is on the jet expansion at Coffeyville. When you spoke about that in Q4, you mentioned at the time one big constraint to think about or one 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?

Dave Lamp (President and CEO)

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 2025. I mean, we're anticipating that we'll achieve some of that business. 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. 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.

I don't think it's going to be a big problem.

John Royall (Executive Director)

Okay. Thank you. My follow-up on the renewable side, you talked about needing further assurance to get to a positive investment decision on a 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? Would you need some sort of longer-term assurance? Is it more than just the near-term rules?

Dave Lamp (President and CEO)

If there's one thing we've learned in the renewable diesel business is that you can't count on credits. They change. The government administrations change. You get different philosophies. The approach we've taken is largely we're willing to do SAF if somebody's willing to take the credit risk. We'll give them the credits that are there, but we're not going to take it ourselves. That 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 on it. It's a 500 million-gallon-a-year plant, and it's costly. If SAF's really needed and renewable diesel, 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. That's a low-CI feedstock.

There is a lot we can do. However, we are not going to do it if we cannot trust the government to provide a steady stream of credits. When you are taking a $4 or $5 oil and trying to shove it into a $2 market, it just does not work.

Neil Mehta (Head of Americas Natural Resources Equity Research)

Thank you.

Dave Lamp (President and CEO)

You're welcome.

Operator (participant)

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

Paul Cheng (Managing Director)

Hey, guys. Good morning. Oh, good afternoon. Thanks. Maybe you can help me. I still couldn't understand why the renewable result is so good. In the fourth quarter, your gross margin is $1.13. In the first quarter, $1.15. In the first quarter, you are doing about $0.93. I mean, you lost BTC; that's $1 per gallon. I mean, what else is in there? In other words, is the first quarter really a good baseline or is there something related to your hedging program or the way you count the inventory? As a result, that's not a totally good baseline.

Dane Neumann (EVP and CFO)

Yeah, 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, $0.10-$0.15 a gallon. Those two just gave us a lift right away. There were some inventory impacts, maybe another $0.10-$0.15, something like that. To say it's a good baseline, there were some items that were, you 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.

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. From that component, I would say you could baseline there that we've improved that. 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.

Dave Lamp (President and CEO)

Yield was up too, Paul. I mean, do not underestimate that. A 5% yield improvement goes a long way.

Manav Gupta (Executive Director)

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

Dane Neumann (EVP and CFO)

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

Manav Gupta (Executive Director)

Right.

Dane Neumann (EVP and CFO)

Yep. The $0.08 improvement, I mean, you got $0.15 from hedging. You have another dime or so. If you take out that $0.20, you would be in the $0.70 range. That is excluding PTC, which would be an incremental kicker. Again, I think the market is so volatile that I would not want to set a baseline of expectations for how much these markers move around.

Manav Gupta (Executive Director)

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

Dane Neumann (EVP and CFO)

Yeah. Paul, that hedging is really around price-exposed inventory or excess inventory. We will take a protective position, a short position on any excess inventories. From that perspective, again, subject to what the market does and how our feed performs.

Manav Gupta (Executive Director)

I see. Dave, I think in the past that, and you say it here again, about the economy of scale, the desire 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 to come to you, or that it is still being actively pursued, or is there any colors that you can share?

Dave Lamp (President and CEO)

Nothing I can really share, Paul. As we've said before, we look at everything that comes on the market and try to screen it through our picture. Historically, to date, the bid-ask has been too wide for us. Thank goodness because the market really took a hit in 2024, come off a record year in 2023, and go to just a record low year in 2024. I think we're pretty conservative. I won't say we're bottom fishers, but we're pretty close to that. We're not going to overpay for an asset.

Manav Gupta (Executive Director)

Can I just make one clarification? I think, Dane, you earlier said that $2 million for the PTC, if you would be able to fully book it for the quarter, do I get the number right?

Dane Neumann (EVP and CFO)

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

Dave Lamp (President and CEO)

Could be double that.

Manav Gupta (Executive Director)

Okay. Will do. Thank you.

Dave Lamp (President and CEO)

You're welcome, Paul.

Operator (participant)

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

Neil Mehta (Head of Americas Natural Resources Equity Research)

Two quick ones. Dave, you always have 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?

Dave Lamp (President and CEO)

I think I've said many times is I think we're in a it depends on the company you're talking about. A lot of them are break-evens are being approached with the numbers we're at or just slightly break-even, slightly below that. Very much depends on the region you're in. Obviously, Permian's probably the lowest, and the Anadarko or DJ Basin or some of those others are probably the higher or Bakken too. It really depends on where you're at. Rigs are falling. I expect that to continue. We've had in our basin, the Anadarko 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 I'm anticipating they're going to fall off a little bit.

Neil Mehta (Head of Americas Natural Resources Equity Research)

All right. We will 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 do not know if anything you can comment around that. It is unusual, so.

Dave Lamp (President and CEO)

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

Neil Mehta (Head of Americas Natural Resources Equity Research)

Okay. Thanks. I figured. Thanks, Dave.

Dave Lamp (President and CEO)

You're welcome, man.

Operator (participant)

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.

Dave Lamp (President and CEO)

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.

Operator (participant)

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.