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Greetings, and welcome to the CVR Energy fourth quarter 2024 Conference Call. At this time, all participants are in a listen-only mode. A brief question and answer session will follow the formal presentation. It is now my pleasure to introduce your host, Richard Roberts, Vice President of Life 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 fourth quarter 2024 earnings call. With me today are Dave Lamp, our Chief Executive Officer, Dan Newman, our Chief Financial Officer, and other members of management. To discuss our 2024 fourth quarter and full year 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. We caution 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. Disclosures related to such non-GAAP measures, including reconciliation to the most directly comparable GAAP financial measures, are included in our 2024 fourth quarter earnings release that we filed with the SEC. Form 10-K for the period 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. For the full year of 2024, we reported a consolidated net income of $45 million and an EBITDA of $394 million. At the segment level, we generated $223 million of EBITDA in our petroleum segment, $179 million of EBITDA in our fertilizer segment. We also began separately reporting results from our Renewables segment, which generated $3 million of EBITDA for the full year of 2024. For the fourth quarter, consolidated net income was $40 million and EBITDA was $122 million. In the petroleum segment, combined total throughput for the fourth quarter of 2024 was approximately 214,000 barrels per day. Crude utilization for the quarter was approximately 94% of nameplate capacity despite planned run cuts in December. And light product yield was 103% on crude oil processed. Benchmark cracks softened during the fourth quarter with Group 3-2-1-1 averaging $14.32 per barrel. The bulk of the decrease came from the third quarter came from a decline in gasoline crack, which is somewhat typical for the fourth quarter as demand slows seasonally and supply increases with the addition of butane blending. In addition, the U.S. refining fleet continued to run hard through the fourth quarter averaging 91% utilization compared to a five-year average of 87%. RIN prices increased $0.17 per barrel from the third quarter of 2024 levels averaging approximately $4.06 per barrel for the quarter. In early January, EPA denied Wynnewood's 2023 small refinery exemption petition, once again coming up with new reasons for the denial that we consider ludicrous and illegal, forcing us once again to seek protection of the Fifth Circuit through a stay. Our 2024 application for small refiner exemption is already filed and EPA again missed the 90-day deadline to rule on it. We are pleased to report that EPA does not oppose the stay Wynnewood requested. Last week, EPA advised the Fifth Circuit. While the Fifth Circuit has not yet ruled on our now unopposed motion to stay, we expect them to do so soon. While we continue to aggressively pursue the small refinery exemptions Wynnewood deserves, we are hopeful that EPA's Fifth Circuit filings last week signal a return to common sense to the agency. We welcome Administrator

For the fourth quarter of 2024, our net income attributable to CVR shareholders was $28 million. Earnings per share was $0.28 and EBITDA was $122 million. Our fourth quarter results include a reduction to quarterly RINs expense due to a mark-to-market impact on our estimated outstanding RFS obligation of $57 million, a gain on the sale of our interest in the Midway pipeline of $24 million, an unfavorable inventory valuation impact of $20 million, and unrealized derivative losses of $6 million. Excluding the above-mentioned items, adjusted EBITDA for the quarter was $67 million and adjusted losses per share were $0.13. Adjusted EBITDA in the Petroleum segment was $9 million for the fourth quarter, with lower frac spreads driving the majority of the decline from the prior year period. Our fourth quarter realized margin adjusted for RIN mark-to-market impacts, inventory valuation, and unrealized derivative losses was $6.45 per barrel, representing a 45% capture rate on the Group 3-2-1-1 benchmark. Net RINs expense for the quarter, excluding the mark-to-market impact, was $56 million or $2.86 per barrel, which negatively impacted our capture rate for the quarter by approximately 20%. The estimated accrued RFS obligation on the balance sheet was $323 million at December 31st, representing 487 million RINs mark-to-market at an average price. This is down slightly from the RFS obligation on the balance sheet at the end of 2023 of $329 million, comprised of 362 million RINs marked at an average price of $0.91. As a reminder, our estimated outstanding RIN obligation primarily related to Wynnewood's RIN obligations is 2024, and excludes the impact of any small refinery exemptions. Direct operating expenses in the petroleum segment were $5.10 per barrel for the fourth quarter, compared to $4.69 per barrel in the fourth quarter of 2023. The increase in direct operating expenses per barrel was primarily due to increased repair and maintenance expenses, in addition to lower throughput volumes compared to the prior year period. Adjusted EBITDA in the Renewables segment was $9 million for the fourth quarter, a significant improvement from our fourth quarter 2023 adjusted EBITDA of negative $17 million. The increase in adjusted EBITDA was driven by a combination of an improved HOBO spread and reduced feedstock basis due in part to the addition of the pretreatment unit in 2024 enabling the processing of cheaper untreated feedstocks. Adjusted EBITDA in the fertilizer segment was $50 million for the fourth quarter, with increased ammonia sales prices, lower pet coke feedstock costs, and lower direct operating expenses driving the improvement relative to the prior year period. The board of directors of CVR Partners' general partner declared a distribution of $1.75 per common unit for the fourth 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 flow from operations for the fourth quarter of 2024 was $98 million and free cash flow was $40 million. Our fourth quarter cash flow from operations includes a working capital of approximately $80 million excluding RIN obligation changes, and the gain on the sale of our interest in the Midway pipeline. The working capital benefit was primarily attributed to increased accrued payables. Significant uses of cash in the quarter included $62 million of capital and turnaround spending, $18 million of cash interest, and $7 million for the non-controlling interest portion of the CVR Partners third quarter distribution. Total consolidated capital spending for the full year 2024, which included $128 million in the petroleum segment, $7 million in the fertilizer segment, and $11 million in the renewable segment. Turnaround spending was approximately $58 million in 2024. For the full year 2025, we estimate total consolidated capital spending to be approximately $165 to $205 million and turnaround spend to be approximately $170 to $185 million. Turning to the balance sheet, we ended the quarter with a consolidated cash balance of $987 million, which includes $91 million of cash in the fertilizer segment. During the quarter, we completed two transactions that significantly increased our liquidity, generating $318 million of net proceeds from the term loan issuance and $90 million of gross proceeds from the sale of our 50% interest in the Midway pipeline. So liquidity as of December 31st, excluding CVR Partners, was approximately $1.1 billion, comprised primarily of $896 million of cash, and availability under the EBL facility of $238 million. With the actions taken during the fourth quarter to increase our liquidity position, we feel confident in our ability to manage through the large turnaround underway at Coffeyville and the potential for continued near-term weakness in the refining market. We do not anticipate the term loan remaining a part of our long-term leverage profile and we would anticipate working to return to our leverage target of approximately two to two and a half times mid-cycle EBITDA on a gross basis as market conditions permit. Looking into the first quarter of 2025, for our petroleum segment, we estimate total throughput to be approximately 120,000 to 135,000 barrels per day, which will be impacted by the planned turnaround of Coffeyville in the quarter. We estimate direct operating expenses to range between $95 and $105 million, total capital spending to be between $30 and $40 million, and turnaround spending to be between $150 and $165 million. Again, in the fertilizer segment, we estimate our first quarter 2025 ammonia utilization rate to be between 95% and 100%. We estimate direct operating expenses to be approximately $55 to $65 million excluding inventory impacts, total capital spending to be between $12 and $16 million. In the Renewables segment, we estimate first quarter 2025 total throughput to be approximately 13 million to 16 million gallons, which will be impacted by a catalyst change completed in January. We estimate direct operating expenses to be between $8 million and $10 million, total capital spending to be between $2 and $5 million. With that, Dave, I will turn it back over to you.

Thanks, Dane. Refining market conditions remained challenging in the fourth quarter largely due to the market being oversupplied as a result of both average utilization levels in the United States as well as the addition of new refined capacity globally. As we look to 2025, however, we are cautiously optimistic that the refining market conditions will improve relative to 2024 for a number of reasons. Looking at the U.S. supply and demand balance, we are starting 2025 in a better position than we were a year ago. To date, average gasoline and diesel demand are at or above five-year averages, and inventories of gasoline and diesel are at or below five-year averages. Spring maintenance season is currently underway and planned turnaround activity is expected to be fairly heavy, particularly for FCC and Alky units. In addition, announced planned closures could result in nearly 800,000 barrels of refining capacity in the U.S. and Europe being shut down this year. Between these announced closures, increased diesel demand resulting from cold winter weather in the U.S. and Europe, and any potential increases in refined product demand as a result of business-friendly pro-growth policies, we see the potential for a tightening supply and demand balance this year, which should be supportive of increased crack spreads. The planned turnaround at Coffeyville is currently underway after we elected to accelerate the timing following an incident at Coffeyville's methan hydrotreater during freezing weather conditions in January. We currently anticipate the duration of the turnaround to be extended by 10 to 15 days from the original plan, and the cost to increase by $10 to $15 million. Although these figures could change depending on several factors, including weather, we currently expect the turnaround to be complete by the end of March, which should position us well heading into the summer driving season. During the turnaround, we intend to complete tie-ins for the initial phase of the diesel recovery project at Coffeyville, which should give us the ability to increase distillate yield by approximately 1,500 barrels per day. We believe we could further increase Coffeyville's distillate yield by another 2,500 barrels per day over the next few years if we elect to invest additional capital. We also plan to install some piping and revamp some of our tankage at Coffeyville, which should enable us to begin making up to 9,000 barrels per day of jet fuel, with the potential to increase that capacity with further additional investment. While it will take time to develop a significant book of business for the jet fuel, by shifting up to 9,000 barrels of distillate production to jet, we could potentially reduce Coffeyville's annual RFS obligation by up to 18 million RINs. Based on 2024 average jet to diesel spreads and average RIN prices, we estimate the potential margin uplift of approximately $5 to $7 a barrel on any new jet fuel sales. We currently expect to have the piping and tankage work associated with the jet fuel production complete by the end of the third quarter. In the Renewable segment, we completed a catalyst change in January and we are currently running the unit at 5,000 barrels per day in an effort to optimize yield and catalyst life. We currently intend to run the unit until we get clarity on the blender's tax credit and/or see the final rules on production tax credit. Without the $1 per gallon blender tax credit, we believe RIN prices and/or low carbon fuel standard credits must increase significantly to compensate. If not, a significant amount of biodiesel and renewable diesel production would likely be out of the money and would have to shut in. Given these headwinds as the renewable space moves forward, it is difficult to ignore that we have invested approximately $290 million in our renewable business over the last several years to participate in carbon emission reduction, generate RINs, and optimize our assets. In doing so, we have been reminded that reliance on government credits is not a sustainable business, and we already have enough exposure to politically mismanaged regulations like RFS. As a result, we are left with an investment with uncertain returns in a business that today is breakeven at best. We have completed the design of the SAFRD project near our Coffeyville facilities and have a firm understanding of our capability to convert our Wynnewood renewable diesel unit to SAF production with additional capital. We do believe there is potential for these opportunities in the future, but it is critical to get clarity on the availability and durability of government subsidies before we continue investing additional capital or time into such ventures. We remain willing to participate further in this space but are pausing our intentions to actively pursue the market for partners and investors. We remain open to the opportunity if someone approaches us that is willing to accept the subsidy risk. If an appropriate environment develops, we will resume an active approach to offering our value proposition to the market. In the fertilizer segment, recent USDA estimates for ending corn and soybean inventories have tightened, which is supportive of grain prices recently. The outlook for fertilizer demand for the spring is good, and we have seen prices increase to start the new year. We are continuing to invest in plant infrastructure for reliability, including the installation of two new boilers at Coffeyville in the fourth quarter, and planned projects in 2025 that focus on water and electricity reliability and quality at both plants. We are also looking at the potential to expand our capacity to make DEF and we continue to evaluate the potential natural gas feedstock optionality project at the Coffeyville facility. Looking at the first quarter of 2025, quarter-to-date metrics are as follows. Group 2-3-1-1 and Group 3-2-1-1 cracks have averaged $15.03 per barrel with a Brent-TI spread of $3.33 per barrel and a WCF differential of $13.19. As of yesterday, Group 3-2-1-1 cracks were $18.68 per barrel, Brent-TI was $3.99 per barrel, and WCS was $13.70 under WTI. RINs were approximately $5.32 per barrel. Prompt fertilizer prices are $600 per ton for ammonia and $315 per ton for UAN. Although 2024 was a challenging year for us both operationally and from a broader market perspective, we feel we are well-positioned to capitalize on any improvements in crack spreads this year as a result of supply rationalization. We are confident the liquidity-enhancing measures we took in the fourth quarter should provide ample cash for the Coffeyville turnaround and weather any near-term weakness in cracks. I want to reiterate something Dan mentioned in his prepared remarks that one of our primary focuses after the completion of the turnaround will be to start reducing debt and restoring our balance sheet to target levels as soon as we can, subject to market conditions and other conditions. As always, we continue to focus on safe, reliable operations of our facilities and continue to look for ways to properly grow our business. Operator, we are ready for questions.

Thank you. We will now be conducting a question and answer session. One moment please while we poll for questions.

Thank you. Our first question comes from the line of Manav Gupta with UBS. Please proceed with your question.

Morning, Dave and team. You did generate about $40 million in free cash flow in the fourth quarter. Obviously, in the first quarter, you are doing this big turnaround, but in line with the comments you made, it looks like by the second quarter, things would be even in a better position. And so if you do continue to generate free cash post your Coffeyville turnaround, just trying to understand what would be a better use in your mind, just to pay down debt or is at some point you could rethink about instituting a dividend here?

Payment off. Yeah. As we said in our prepared remarks, one of the key focuses we do want to work on is the delevering. Comfortable with the original billion, we want to work off the term loan. I do not think it should be a scenario where we should expect to see the term loan fully gone before a dividend were potentially to return. But we would want to see some sustained strength in the market as well. So look to take a balanced approach and see how things develop as we go forward.

As you know, Manav, the dividend is something the board looks at every quarter. And as cracks improve, I would think the likelihood goes up that the board acts on that.

Perfect. My quick follow-up here is you mentioned that you are looking at some projects which could give you a higher jet yield. Just trying to understand what could be the CapEx required to pull off those projects and what kind of timeline are we looking at? Could you, if you do decide to move ahead, could you bring those on within the next twelve or fifteen months by making some tweaks? So help us understand what could give you a higher jet yield going ahead.

Well, I think right now, Manav, our constraint is really building a book of business for jet. A lot of the airlines, major airlines are on three-year contract terms. It is going to take a little time to build it, but in essence, it is just a jumper or two and some pipe that we have to install and rearrange our tankage at Coffeyville to add additional volume of jet. As you know, we already produce jet at the Wynnewood refinery and are mainly sales constrained on that also with the loss of our military contract last year. So it is not going to take us long as I have said in my prepared remarks. We should be ready at the end of the third quarter to produce jet at Coffeyville.

Thank you so much. I'll turn it over.

Our next question comes from the line of Adam Wojeo with JPMorgan. Please proceed with your question.

Yeah. Good afternoon, team, and thank you for taking my questions. First one is just on how you guys think about the operating footprint of the company. I know probably more of a near-term focus on the big turnaround going on right now and then the balance sheet. But in the past, you've talked about looking to potentially diversify the company's refining operating footprint from the Mid-Con into other regions. Just wanted to get your latest views here. If you think there are any regions of focus we should be mindful of, and then anything on a potential timeline there. Thanks.

Well, Adam, I think we've mentioned many times, we look at everything that comes on the market. Bid-ask has been too wide for us to even consider a lot of these deals that have come up. But we'll continue to look for everything. Our biggest weakness as a company is really our concentration in the Group 3 market in the Mid-Con PAD 2. And, you know, anything that can diversify us from that is a benefit. That said, you know, our focus is more inland and going west than it is going south or east. Might consider going north if the right deal ever came up, but you know, again, we want to diversify out of PAD 2 as much as possible.

Got it. Very clear. And just a follow-up for me on the Renewables segment. Saw that you guys broke the segment earnings profile out this quarter. And when we think about the path to run rate positive EBITDA contribution going forward, aside from improving margins more broadly, operationally, is there anything you think we should be focused on? And can you tie that into how you guys think about potential opportunities within renewables, specifically in SAF, kind of what's needed from a supply-demand standpoint or an incentive standpoint, to further make a call there. Thanks.

Sure, Adam. I mean, as I mentioned in the prepared remarks, the problem with renewables is the uncertainty of government subsidies. And they will swing wildly, I guess, I'd say it. And when I say that, it's politically driven RFS regulation that, you know, seems to be there's nobody driving the ship. And I'll just use the example of the fact that the mandate is 22 billion and 15, 16 of that is ethanol. Ethanol does little for the environment, whereas renewable diesel does. And lo and behold, you've got D6s coupled with D4s that started to break a little bit. But even so, you would think the government would drive towards lower carbon material rather than just doing a mandate on ethanol, which is really not necessary at all. Because ethanol is a part of the fuel blend. It's a cheap blend stock for octane, and it would be blended no matter what. So, you know, until we get clarity on some of these regulations and somebody, an adult in the room controlling them, it would be difficult to see how we make some investments. Just to give you an idea on SAF, you know, the subsidies, and you know, that today, the people are reporting that that's selling for about a dollar to two dollar premium over RD. You know, if you take all the subsidies and add them all up, you'd need more, like, four bucks to really to even have that kind of sales price. So to us, it's we've had all we can stand of exposure to government subsidies and it just it's going to take a shift change for us to really invest in it. We do have projects that look attractive on a capital per barrel capital basis, for both SAF and Renewables. But, again, these subsidies are just scary.

Got it. Very clear. 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 one is on asset sales. And maybe a two-parter if I can. First, can you tell us the tax implications of the $90 million Midway pipeline sale and have the taxes been paid out yet? And then secondly, how should we think about asset sales from here and if other assets could potentially shake loose, does a better environment in refining maybe change your thinking on raising cash via asset sales?

Good afternoon, John. Yeah. So on the Midway sale, $90 million proceeds, there will be a tax impact. Say our tax basis in that joint venture was call it $15 million, so the remaining would be exposed to tax. Has not been paid, but anticipate paying that as we move through the beginning of 2025 here.

As far as other logistics assets, we have we used to advertise $80 million, which was kind of an aggressive EBITDA content that included, if we were to spin off our logistics as a separate MLP. We think that revised number is more realistic around $20 million. That's post the sale of Midway. So there's a few out there, but not near as much as we originally advertised, John. So hopefully, that answers your question.

It does. Thank you. And then the next question is on renewable diesel. I think you mentioned in the opener that you have some limitations on the side that are impacting your capacity. I think you took it down about 20% if I heard it right. Can you just give us a little more detail on what those constraints are?

Well, you know, this was a revamp. So we took an existing reactor and unit and converted it to what we thought was 7,500 barrels of capacity per day of vegetable oil and corn oil. Well, as it turns out, we're willfully short of catalyst. You know, our run lengths are between six and eight months at best. And it's just the yield is just so affected by the high space velocity at the higher rates that we just think we have to downgrade the unit to really do it. With the addition of another catalyst bed, we'd be right back to that 7,500, possibly even more. So and if you look at the SAF project, that's largely how we would accomplish it. We'd add a reactor and that would take care of the pretreatment to remove the oxygen, and then the existing reactor would be adequate for isomerization. So that's kind of the ultimate plan. The problem is, as I mentioned earlier, subsidies are scary.

Thank you.

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

Thank you, and good morning. The refining capture improved quarter over quarter, which seems pretty good in the context of a higher RVO and perhaps some other challenges. Can you talk about the tailwinds to capture in the fourth quarter and then also discuss any major moving parts on capture we should be thinking about for the first quarter?

Hey, Matt. Yeah. So tailwinds to capture, I would say, two things. Not massive contributors, but with the run cuts we did enact in December, that kind of drove our margin to a higher per barrel number on the cracks earlier in the period relative to the average across the quarter when they fell off in December. There's some small inventory benefits, you know, call it $0.30 to $0.50 a barrel also in there. Not a big number, but on a depressed crack, it does give you a little bit of a benefit. Other than that, not a lot of unusual things to report. And then as we look to the first quarter, again, I think it's going to be more a function of just getting back to normal operations and having a lower percentage of the crack being taken up by fixed cost if the crack stays elevated here.

Sounds good. And then I had two questions in regards to the RD feedstock mix. First, in the reporting, there's an other feedstock and blends box line item that it's fairly large. It's about one-third of the total throughput. Could you talk about what goes into that line item? And then second, with the 45

Well, Matt, I think on your first question, the other is just refinery gas streams that are processed with the RD unit when it was previously in hydrocracker service. Then there's also, I think, others that include hydrogen as a part of it. So that's probably the bigger piece. On your second question, which I already forgot, can you repeat it again, please?

Is anything changing on your RD feedstock mix going forward in light of the 45

Well, we'd yeah. We would desire to run more corn oil if we could, which is a low CI material. And, you know, the problem again is comes back to catalyst. And our ability to do that is limited by our ability to process more corn oil without a yield penalty. We continue to explore that, though, and look at other ways to do it. And, you know, the

Great. Thanks for your insights.

You're welcome.

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.