CVR Energy - Earnings Call - Q3 2025

Executive Summary

• Q3 2025 was dominated by the EPA’s small refinery exemption decision, driving a GAAP net income of $401M, $3.72 EPS and EBITDA of $625M; adjusted EPS was $0.40 and adjusted EBITDA $180M as management stripped the $488M RFS liability benefit and valuation/derivative items.
• Revenue of $1.944B beat S&P Global consensus of $1.875B*; adjusted EPS $0.40 beat $0.229*; reported EBITDA $625M versus $156M*, with the EBITDA “beat” largely due to the nonrecurring RFS liability adjustment; underlying petroleum adjusted refining margin was $12.87/bbl with crude utilization ~97%.
• Guidance: Q4 2025 outlook introduced—Petroleum throughput 200–215kbpd; Renewables throughput 10–15MM gal as the Wynnewood RDU reverts to hydrocarbons in December; Fertilizer ammonia utilization 80–85% (turnaround impact); no CVI dividend for Q3.
• Strategic pivot: Management will revert the Wynnewood renewable diesel unit back to hydrocarbon service due to unfavorable economics and subsidy uncertainty—retaining optionality to switch back if incentives improve.
• Potential stock catalysts: clarity on 2025 SRE outcome and RIN purchases (~$100M worst-case), crack spread strength, jet fuel ramp at Coffeyville, debt paydown path informing potential dividend reinstatement discussions.

What Went Well and What Went Wrong

• What Went Well

  • EPA SRE decision removed ~424M RINs and recognized a $488M gain, materially reducing RFS obligations and boosting GAAP earnings and EBITDA.
  • Operational execution: combined throughput ~216kbpd, crude utilization 96.6–97%, improved capture rate; adjusted refining margin $12.87/bbl vs $8.23 last year.
  • Fertilizer strength: UAN and ammonia realized prices rose 52% and 33% YoY; Nitrogen Fertilizer EBITDA $71M and Q3 distribution $4.02/unit; CEO: “CVR Partners achieved strong results... with a combined ammonia production rate of 95 percent”.

• What Went Wrong

  • Renewables underperformance: Q3 renewables margin ~($0.01)/gal, adjusted renewables margin $0.37/gal; depreciation accelerated $31M; decision to mothball pretreatment and revert RDU highlights challenged economics (loss of BTC, higher soybean oil).
  • Non-GAAP adjustments mask core profitability: $471M favorable change in RFS liability, $18M unfavorable inventory valuation, and $8M unrealized derivative losses—necessitating adjusted views (EBITDA $180M; EPS $0.40).
  • RIN burden persists: net RINs expense (ex-SRE impact) $88M (~$4.45/bbl) hit capture; pending 2025 waiver creates cash planning risk (estimated ~$100M RIN purchases by March 2026 worst-case).

Transcript

Speaker 2

Greetings and welcome to the CVR Energy Third Quarter 2025 conference call. At this time, all participants are in listen-only mode. A brief question-and-answer session will follow the formal presentation. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Richard Roberts, Vice President of FP&A and Investor Relations. Thank you, sir. You may begin.

Speaker 5

Thank you, Eric. Good afternoon, everyone. We very much appreciate you joining us this afternoon for our CVR Energy Third 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 third quarter results, let me remind you that this 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 third quarter earnings release that we filed with the SEC in Form 10-Q for the period and will be discussed during the call. That said, I'll turn the call over to Dave.

Speaker 3

Thank you, Richard. Yesterday, we reported third quarter consolidated net income of $401 million and earnings per share of $3.72. EBITDA was $625 million. These results include a $488 million benefit associated with the full and partial small refinery exemptions granted to the Wynnewood Refining Company for the 2019 through 2024 compliance years, in addition to solid operations and improved market conditions in both our petroleum and fertilizer business. In our petroleum segment, combined total throughput for the third quarter of 2025 was approximately 216,000 barrels per day for crude processing utilization of 97%. Light product yield was 97% on crude oil processed. After working off intermediate inventories built during the Coffeyville turnaround earlier this year, we ran at full rates at both refineries in the third quarter with no significant lost opportunities.

We do not currently have any additional turnarounds planned in the refining section for the duration of 2025 or 2026, and we currently expect the next planned turnaround to be at Wynnewood Refinery in 2027. Group 3 benchmark cracks averaged $25.97 per barrel for the third quarter of 2025, compared to $19.40 per barrel last year. Average RIN prices for the third quarter were approximately $6.33 per barrel, nearly 25% of the Group 3 2-1-1 crack. Regarding RFS, after years of fighting for the rights that the Wynnewood Refining Company is entitled to, EPA in August finally ruled on a backlog of 175 outstanding SRE petitions covering the past compliance period that had been pending before it for years.

In addition to affirming its prior grants of the Wynnewood Refining Company's 2027 and 2028 petitions, EPA granted full waivers for 2019 and 2021 and 50% waivers for 2020, 2022, and 2024. Based on these decisions, we were able to reduce our outstanding RFS obligation on our balance sheet by over 80%. While we continue to believe Wynnewood Refinery deserves 100% waivers for every year, we are pleased to have these lingering issues resolved and a large obligation on our balance sheet significantly reduced. For the third quarter of 2025, we processed approximately 19 million gallons of vegetable oil feedstock at our renewable diesel unit at Wynnewood. Gross margin was negative by approximately $0.01 per gallon for the third quarter compared to a positive $1.09 per gallon for the previous year.

The loss of the blenders’ tax credit and a significant increase in soybean prices this year continued to weigh on the profitability of the renewables business. We did not recognize any production tax credit benefits in the quarter as we continue to await final regulations from the IRS, but we estimate the unbooked production tax credit value would have been approximately $4 million for the third quarter and $9 million year to date. As a reminder, we believe that we would have the ability to retroactively claim these credits once regulations are finalized. In the fertilizer segment, the ammonia utilization rate was 95% for the quarter compared to 97% for the third quarter of 2024. Nitrogen fertilizer prices for the third quarter of 2025 were higher for both urea ammonium nitrate (UAN) and ammonia compared to the third quarter of 2024.

Fertilizer supplies remain tight around the world, which has been supportive of pricing. Now let me turn the call over to Dane to discuss our financial highlights.

Speaker 5

Thank you, Dave, and good afternoon, everyone. For the third quarter of 2025, our consolidated net income was $401 million. Earnings per share was $3.72, and EBITDA was $625 million. Our third quarter results include a positive change in our RFS liability of $471 million, an unfavorable inventory valuation impact of $18 million, and unrealized derivative losses of $8 million. Excluding the above-mentioned items, adjusted EBITDA for the quarter was $180 million, and adjusted earnings per share was $0.40. Adjusted EBITDA in the petroleum segment was $120 million for the third quarter, with the increase from the prior year period driven by a combination of increased Group 3 benchmark cracks, higher throughput volumes, and improved capture rates. Our third quarter realized margin adjusted for RFS liability impacts, inventory valuation, and unrealized derivative losses was $12.87 per barrel, representing a 50% capture rate on the Group 3 2-1-1 benchmark.

Net RINs expense for the quarter, excluding the RFS liability impact, was $88 million or $4.45 per barrel, which negatively impacted our capture rate for the quarter by approximately 17%. The estimated accrued RFS obligation on the balance sheet was $93 million at September 30th, representing 90 million RINs marked to market at an average price of $1.03. As a reminder, our estimated outstanding RIN obligation excludes the impact of any future small refinery exemptions. Going forward, we intend to continue to recognize 100% of Wynnewood Refining Company's current period RINs expense in our financials until EPA rules on our pending petitions. For modeling purposes, Wynnewood Refining Company's annual RIN obligation based on the 2025 RVO is approximately 120 million RINs.

For the third quarter of 2025, we estimate adjusted EBITDA in the petroleum segment would have been approximately $34 million higher, with the benefit of a 100% small refinery exemption for 2025, or $17 million higher, with a 50% small refinery exemption. Adjusted refining margin per barrel would have been approximately $1.68 per barrel higher, with a full SRE for 2025 or $0.84 higher, with a 50% SRE. Direct operating expenses in the petroleum segment were $5.69 per barrel for the third quarter compared to $5.72 per barrel in the third quarter of 2024. The decrease in direct operating expense per barrel was primarily due to higher throughput volumes. Adjusted EBITDA in the renewable segment was a loss of $7 million for the third quarter, a decline from the third quarter of 2024 adjusted EBITDA of $8 million.

The decrease in adjusted EBITDA was driven by a combination of a decline in the HOBO spread due to higher soybean oil prices, along with the loss of the blenders’ tax credit and nothing booked for the production tax credit. Adjusted EBITDA in the fertilizer segment was $71 million for the third quarter, with higher UAN and ammonia sales pricing driving the increase relative to the prior year period. The partnership declared a distribution of $4.02 per common unit for the third quarter of 2025. As CVR Energy owns approximately 37% of CVR Partners’ common units, we will receive a proportionate cash distribution of approximately $16 million. Cash flow from operations for the third quarter of 2025 was $163 million, and free cash flow was $121 million, of which approximately $83 million was generated by the fertilizer segment.

Significant uses of cash in the quarter included $43 million of capital and turnaround spending, $43 million for cash interest, $26 million paid for the non-controlling interest portion of the CVR Partners’ second quarter 2025 distribution, and a $20 million repayment on the term loan. Total consolidated capital spending on an accrual basis was $40 million, which included $25 million in the petroleum segment, $14 million in the fertilizer segment, and $1 million in the renewable segment. For the full year 2025, we estimate total consolidated capital spending to be approximately $180 to $200 million, and capitalized turnaround spending to be approximately $190 million. Turning to the balance sheet, we ended the quarter with a consolidated cash balance of $670 million, which includes $156 million of cash in the fertilizer segment.

Total liquidity as of September 30th, excluding CVR Partners, was approximately $830 million, which was comprised primarily of $514 million of cash and availability under the AVL facility of $316 million. During the quarter, we paid down $20 million on the term loan, leaving the current principal balance at approximately $235 million. Looking ahead to the fourth quarter of 2025 for our petroleum segment, we estimate total throughputs to be approximately 200,000 to 215,000 per day, direct operating expenses to range between $105 and $115 million, and total capital spending to be between $20 and $25 million. For the fertilizer segment, we estimate our ammonia utilization rate to be between 80% and 85%, which will be impacted by the planned turnaround currently underway at the Coffeyville facility.

We expect direct operating expenses, excluding inventory and turnaround impacts, to be between $58 million and $63 million, and total capital spending to be between $30 million and $35 million. The turnaround expense is expected to be between $15 million and $20 million. For the renewable segment, we estimate fourth quarter 2025 total throughput to be approximately 10 million to 15 million gallons, with a catalyst change expected in December. We expect direct operating expenses to range between $8 million and $10 million, and total capital spending to be between $1 million and $3 million. With that, Dave, I'll turn it back over to you.

Speaker 3

Thanks, Dane. Refining market conditions continued to improve during the third quarter, with refined product demand remaining steady and inventories continuing to trend near five-year average levels. Increased geopolitical tensions have contributed to the strength in crack, particularly diesel cracks, following a string of Ukrainian drone attacks on the Russian refineries over the past few months. Within the Mid-Continent region, where we operate, we continue to see positive supply-demand trends, with gasoline and diesel inventories at or below recent historical averages and demand improving. During the quarter, we began producing jet out of Coffeyville, and we expect to see production and sales volume of jet fuel ramp up over the next few quarters as we continue to make commercial progress.

Looking out over the next few years, multiple pipeline projects have been announced that would connect refined products supplied from Pad 2 into Pads 4 and 5, which could provide a constructive solution to meet consumer demand across all regions. Overall, we remain cautiously optimistic about the near and medium-term outlook for the refining sector. As I mentioned, supply and demand balances remain favorable. Even with the trend of high fleet utilization continuing, there are still several refineries in the U.S. and Europe that are scheduled to shut down over the next few quarters, representing a total capacity of around 400,000 to 500,000 barrels per day.

With minimal new fuels refinery capacity projected to start up over the next few years, refined product demand appears stable, and we continue to believe any pro-growth initiatives from the Trump administration should be positive for GDP growth and demand for transportation fuels in the U.S. This dynamic of stable and improving demand with limited new refining capacity could help cracks remain healthy. In the renewable segment, the profitability has been challenged this year after the loss of the blenders’ tax credit and the increase in soybean oil prices following EPA's announcement of increasing RVOs and limits on credit generation from an imported feedstock. As we've talked many times over the past few years, while we want to participate in the renewable space, we will only do so if profitable.

Unfortunately, the renewable business relies heavily on government mandates and subsidies to be profitable, and the government does not currently seem to be interested in supporting the renewable business it created. Given the losses that we have faced this year in our renewable business, and that we have seen little government support that return us to profitability in the near term, we have made the decision to revert the renewable diesel unit at Wynnewood back to hydrocarbon processing during the next scheduled turnaround in December. We believe that we have more opportunities to create value in the full hydrocarbon processing mode, and we look forward to working on some of the alternative uses for the logistical assets built for renewable diesel service. We would also retain the option to switch back to renewable diesel service in the future if incentivized to do so.

In the third quarter, we recognized $31 million of accelerated depreciation associated with the pretreatment unit as a result of our decision to revert the renewable diesel unit back to hydrocarbon processing. We also wrote off approximately $3 million of capital investment associated with the potential renewables project at Coffeyville. We anticipate additional accelerated depreciation impacts of approximately $62 million in the fourth quarter as well. Finally, in the fertilizer segment, we saw continued strong pricing through the summer due to tight supplies, trade, and geopolitical issues. The harvest is currently on schedule and nearing completion. Current USDA estimates on corn planting and yields would imply carryout levels at or below 10-year average, although grain prices have remained low on the expectation of a large crop production in Brazil and North America.

Domestic and global inventories of nitrogen fertilizers remain tight, which we believe should continue to support prices into the spring of 2026. We have a number of projects in flight to support capacity increases at both plant and infrastructure projects to target improved reliability for max utilization to capture this market into the future. Looking at the fourth quarter of 2025, quarter-to-date metrics are as follows. Group 3 2-1-1 cracks have averaged $25.69 per barrel, with a Brent-TI spread of $3.80 per barrel and a WCS differential of $11.62 under WTI. As of yesterday, Group 3 2-1-1 cracks were $30.10 per barrel, and RINs were approximately $5.91 per barrel. Prompt fertilizer prices are approximately $700 per ton for ammonia and $360 per ton for urea ammonium nitrate.

As we stated in our last earnings call, returning the balance sheet to targeted leverage is a key focus for us in the near term. With the small refinery exemptions that the Wynnewood Refining Company received in August, our balance sheet has improved significantly due to the reduction of the Renewable Fuel Standard obligation. However, the EPA has not ruled on the small refinery exemption petition we submitted in July. If the Wynnewood Refining Company is granted a 50% waiver for 2025, we currently estimate that we would have to purchase approximately $100 million worth of RINs by the end of March 2026 to satisfy both our obligated subsidiaries for 2024 and 2025 obligations. Beyond the current cash needs for RINs, we intend to continue to prioritize paying down the term loan with excess cash flow we are able to generate.

Reducing the balance on the term loan is one of several criteria in the board's decision around a potential return to the quarterly dividend, and that decision is evaluated every quarter. If Group 3 benchmark cracks remain elevated, we would likely be able to reduce debt faster and accelerate conversations with the board around the dividend. As always, we always look to ways to improve capture, reduce cost, and ultimately grow our business profitably. As this will be my last earnings call before retirement, I'd like to say it's been a pleasure to work for the last 45 years in an industry that makes modern life possible. I have crossed paths with a ton of people over the years, all of whom I've learned something from and contributed to my success. For that, I am grateful. With that, Operator, we're ready for questions.

Speaker 2

Thank you. We will now be conducting a question-and-answer session. To ask a question, please press star, followed by the number one on your telephone keypad. Our first question comes from the line of Matthew Blair with Tudor Pickering. Please go ahead.

Speaker 0

Hey, Dave. Wishing you the best in retirement. It's really been a pleasure working with you over these past, I guess, several years. Wishing you the best. I wanted to follow up on your commentary on the new product pipelines that would take barrels west. It seems like this could be a potential positive for Mid-Continent refiners like CVR Energy. Could you talk about whether you would plan to make shipping commitments on any of these pipes? If so, is there a proposal that looks more favorable in your view?

Speaker 3

I think you're right, Matt, that it'll be very constructive for the Mid-Continent region. As I've said many times, the Mid-Continent region has been long on product with the high utilizations we've seen in the northern tier of Pad 2. Any relief of where to move those barrels will be a positive to Group 2, and probably a positive to Group 4 or Pad 4 and Pad 5. Obviously, one of the projects goes all the way to California, the other does not. I'll remind you that the Denver pipeline is out there also, which moves barrels to Pad 4 also. We think it's helpful. Whether we take line space on any of them, we haven't decided yet, and more to come on that in the future.

Speaker 0

Sounds good. In regards to the decision on the renewable diesel plant, is there any opportunity to still utilize the pretreatment plant, or would that be just completely shut down as well?

Speaker 3

In the short term, it would definitely be shut down, and that's why we took the accelerated depreciation. It's probably, if you look at the current spreads on the basis of soybean oil and other feedstocks, they're pretty tight, and it doesn't give a lot of incentive for the PTU. We will look for all those opportunities we can find. We know we have use for the rest of the logistical assets, so just look for us to find new ways to use that in the future.

Speaker 0

Sounds good. Thanks for your comments.

Speaker 3

Thank you.

Speaker 2

Your next question comes from the line of Paul Cheng with Scotiabank. Please go ahead.

Speaker 1

Hi. Thank you. Hi, Dave. Good afternoon or good morning. Just want to extend my congratulations on your retirement, and thank you for all the help throughout the years. Really appreciate it.

Speaker 3

Wonderful.

Speaker 1

On the renewable diesel, what does it take? Is it just the change of the catalyst, or are there other changes that you need to make in order for you to convert back into one-link hydrocarbon? Also, do you have an estimate of the cost to keep the PTC in to sustain in a reasonable shape so that in the future you decide to restart it?

Speaker 3

Yeah, Paul, I think it's a pretty easy conversion for us because we considered this when we built the unit. It's mostly a catalyst change. There are a few other pieces of pipe we need to do, but in the general case, it's just really a piping change. As far as the PTU goes, I think we'll mothball it in a way that we can bring it back in short order should something change in the renewable space. The renewable space is, I guess the decision was largely made just because we just don't see any catalyst that can really change the projection of that thing. RINs were designed to make the marginal producer break even. Some people are predicting a big increase in RINs, but our unit was limited to mainly soybean oil and a little bit of corn oil.

It couldn't really handle any of the real low CIs just because of metallurgy. Even with the low CIs, what's happening in most cases is the HOBO goes up and down, and the RINs change. It's just going into the feedstock cost. We just didn't see much of a chance for anything to change in that space that was going to make it a good deal.

Speaker 1

Dave, even with the production tax credit or facility, we're never able to handle the low CI stuff?

Speaker 3

Any of the very low stuff, like used cooking oil, we're not designed to handle it metallurgical-wise. With land use, that helped, but the production tax credit does not, even with that, doesn't make up for the blenders’ tax credit.

Speaker 1

I see. When you say that you're going to move forward the production tax credit and that, is there any, or that the cost is so minimum to maintain it going forward that it's just a drop in the bucket, so it's really just pocket change, or that there's a reasonable cost associated on a going-forward basis?

Speaker 3

Once we mothball it, Paul, it's really pretty low cost. There'll be some cost to restart it, but it won't be a lot.

Speaker 1

I see. The final question, I mean, with all the proposed new pipeline getting the barrel out from the Mid-Continent region, does it in any shape or form change the way that how you're looking at your configuration and how you're going to run those facilities, or that doesn't really matter?

Speaker 3

Depending on which of those two options really happen, I think we can make a reformulated gasoline. We can probably make some Arizona clean burning gasoline, but CARB would be challenging for us. I don't know that we'd ever want to make an investment for CARB. Eventually, I think that formulation may melt away or go away at some point when California wakes up to the high cost of fuel out there and what it costs to make that reformulated special blend for them. I certainly will have the other two grades that we can do. It's just a question of volume. If we do elect to take that business, how much volume would it be and what changes would we have to make to do that? I'll remind you that we have this CASAT project that is going to make more alkylate at Wynnewood.

We're going to be alkylating all our C3s that today we sell, and so that's going to increase our alkylate production, which helps us in some of these clean burning gasoline.

Speaker 1

Yeah. If you're trying to make gasoline for the Arizona mountain, as you say, it's just a matter of the volume and how much it's going to cost. Can you give us some idea that if you want to make, say, 20,000 barrels per day, how much is that cost and what needs to be done?

Speaker 3

We haven't looked at that yet, Paul. I can't give you any guidance on that.

Speaker 1

Okay, we do. Thank you.

Speaker 2

Your next question comes from the line of Alexa Patrick with Goldman Sachs. Please go ahead.

Speaker 4

Hey, good afternoon, Dave and team. I wanted to ask on the $100 million RIN obligation you guys talked about outstanding. How are you guys kind of thinking about the strategy of meeting that RIN obligation when we also keep in mind that we're still waiting on some incremental small refinery exemptions updates for specifically 2024 and 2025? Thanks.

Speaker 0

Yeah. Thanks, Alexa. Right now, we're just thinking about the December deadline for 2024 and the March deadline for 2025. The $100 million encompasses covering Coffeyville and Wynnewood at 50% through 2025 and also Wynnewood through 2024. Again, as you mentioned, we're particularly monitoring for the 2025 waiver outcome. Wynnewood historically the last few years has gotten 50%. We expect that to be worst-case scenario. We still believe it should be 100%. In the event that we do get 100%, the nice thing is the RINs that we purchased for that could be used for Coffeyville compliance going forward. It feels like a conservative thing to do to plan to buy the $100 million RINs between now and March 31.

Speaker 4

Okay. That's very helpful. Maybe just some early thoughts on 2026, how we should be thinking about capital spend, and any considerations there related to the RDU conversion?

Speaker 3

Yeah, we usually give that guidance in the fourth quarter, Alexa. I think we'll wait until that time to fill you in on that.

Speaker 4

Okay. Sounds good. I'll turn it back. Thank you.

Speaker 3

Thank you. Eric?

Speaker 2

Yes. Your next question comes from the line of Manav Gupta with UBS. Please go ahead.

Speaker 1

Hey, Dave, thank you for all the years that you provided us insights into the refining market. I do have to say that if you look at the last one and a half or two years, this is the most bullish I have heard you on an earnings call. It's good that you also feel that this is a much stronger refining environment that we are in. The question that comes back to is, by when do you think you would be at the right debt levels to restart some form of dividend? That's the number one question we get is CVR Energy is doing much better. When can we see some form of payout for the shareholders?

Speaker 3

It's a difficult prediction to make, Manav. I will tell you that I've been in the business a long, long time, and I've watched these markets for a long, long period of time. This setup that I see coming is probably the best I've seen in a long time. Just look at the number of refineries that are shutting down and the supply of new ones. We came through a big wave of new refineries coming on, some of which are still in the startup phase. There just are very few fuels refineries that are going to be starting, even in conception right now, that are going to make a difference in this balance. Demand is still growing, even though it's slower. No doubt EV penetration's hit. The matter of fact is, refining is going to, to me, it's going to be short in the future.

It's a great space to be in. If you consider what it takes to build a refinery these days, I don't care where you do it in the world, it's just really expensive. It's almost 4x what the market cap of what these companies are today. That just bodes well to me for the future on what cracks will look like.

Speaker 2

Thank you, sir. I'll turn it over.

Speaker 3

Thank you.

Speaker 2

Thank you. We have reached the end of the question and answer session. I'd now like to turn the floor back over to management for closing comments.

Speaker 3

Thank you. Again, I'd like to thank you all for your interest in CVR Energy. Additionally, we'd like to thank our employees for their hard work, commitment toward safe, reliable, and environmentally responsible operations. With that, we'll talk to you next quarter. Thank you.

Speaker 2

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