CVR Energy, Inc. Aktie

Hello, everyone. Thank you for joining us, and welcome to CVR Energy's Third Quarter 2026 Earnings Call. [Operator Instructions]

I will now hand the conference over to Richard J. Roberts, Chief Financial Officer. Richard, please go ahead.

Thank you. Good morning, everyone. We very much appreciate you joining us this morning for our CVR Energy Third Quarter 2026 Earnings Call. With me today are Dane Neumann, our Chief Executive Officer; Mike Wright, our Chief Operating Officer; and other members of management.

Today, we announced our agreement to acquire 2 refineries from Marathon Petroleum, and we have posted a presentation on the Investor Relations section of our website. We will refer to that presentation during our prepared remarks.

Prior to discussing our 2026 third 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 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 2026 third quarter earnings release that we filed with the SEC and Form 10-Q for the period and will be discussed during the call.

In addition, our remarks today include forward-looking statements regarding the proposed acquisition, including its expected benefits, synergies, accretion, financing and timing to close. These statements are subject to risks and uncertainties, including the satisfaction of customary closing conditions and regulatory clearance, our ability to finance the transaction and to integrate the acquired assets and the other factors described in our press release and SEC filings.

With that said, I'll turn the call over to Dane.

Thank you, Richard. Good morning, everyone, and thank you for joining our earnings call. This is a historic day for CVR Energy as we announced the largest acquisition in the company's history, along with a record earnings quarter on both a consolidated basis and in the Refining segment. We are also pleased to announce a third quarter 2026 dividend of $0.10 per share. We believe current market conditions, along with the platform expansion opportunities afforded by this transaction, generate tailwinds for our business that should create tremendous value for our shareholders. Before Richard takes you through the quarter, I want to spend a few minutes on the news we announced this morning.

Starting on Slide 2 of the presentation, CVR Energy has entered into a definitive agreement to acquire Marathon's St. Paul Park, Minnesota and Mandan, North Dakota refineries, along with their associated marketing business and certain logistics assets for total consideration of approximately $4.2 billion, subject to certain customary closing adjustments. The 2 refineries have a combined nameplate crude capacity of approximately 177,000 barrels per day with St. Paul Park at 105,000 and Mandan at 72,000. Combined with Coffeyville and Wynnewood, our crude processing capacity would increase from approximately 207,000 to approximately 384,000 barrels per day.

This is a transformative acquisition for CVR Energy, nearly doubling our refining capacity, enhancing our geographic scope and diversifying our distribution footprint through a highly complementary marketing and logistics platform. The transaction implies an asset acquisition multiple of less than 3.5x management's estimate of 2026 EBITDA for the acquired business. For the 9 months ended September 30, 2026, on a pro forma basis, giving effect to the transaction, CVR's EBITDA increased from approximately $900 million on a stand-alone basis to approximately $2 billion and diluted earnings per share increased from $3.73 on a stand-alone basis to $7.67. Further, we expect the transaction to be greater than 50% accretive to CVR's earnings and free cash flow in the first full year after closing.

We intend to fund the transaction with a mix of common equity, cash and debt, and we plan to redeem our outstanding 2028 senior notes. The equity portion is intended to be funded by a large common equity investment from Trafigura, along with a $500 million equity commitment from IEP and approximately $650 million of cash from the CVI balance sheet. We have $2.5 billion of committed bridge financing from our banks, which we expect to replace with syndicated secured debt financing prior to closing, and we expect to draw $300 million on an upsized $1.1 billion ABL facility.

We also expect to equally and ratably secure our 2031 and 2034 senior notes upon the completion of the permanent financing. Pro forma for the transaction, we expect total debt, excluding CVR Partners of approximately $3.8 billion at closing, less than 2x our estimated 2026 consolidated pro forma EBITDA. We remain committed to a strong balance sheet, and we intend to capitalize on the above mid-cycle margin environment to further reduce leverage.

As the potential transaction is absorbed, we also see potential to substantially improve our corporate credit rating profile. The transaction has been unanimously approved by our Board of Directors and is expected to close by year-end 2026, subject to customary closing conditions and regulatory clearance, including expiration of the waiting period under the Hart-Scott-Rodino Act.

Turning to Slide 3. This is a unique opportunity for us to acquire high-quality geographically advantaged assets from an established operator at a compelling valuation. This transaction would expand our footprint to new geographic areas across the Upper Midwest and Northern Great Plains regions, broadening our exposure to regional transportation fuel demand and expanding our presence across the broader PADD II region.

From an operations perspective, these assets are similar to what we own and operate today, medium-sized inland refineries with advantaged crude access via Bakken and Canadian crude oil processing. They are also well-maintained assets, supported by strong historical investment by Marathon that drove average utilization levels over the past 5 years in the high 90s. The transaction would include Marathon's associated marketing business with up to 590 branded locations across the Upper Midwest and Northern Great Plains regions and long-standing relationships with strategic counterparties. It gives us a diversified distribution mix across gasoline, ultra-low sulfur diesel, jet fuel and asphalt in new geographies through a combination of local rack sales and wholesale channels and a platform for potential expansion into our existing footprint.

The business also has high blending capacity, which would increase our internal RIN generation capability and reduce some of our reliance on third-party RIN purchases, potentially further improving the overall RIN exposure of the company on a consolidated basis. I would also note that Mandan has received a small refinery exemption for 50% of their 2023, 2024 and 2025 obligations. Additionally, a larger, more diversified asset base would support more durable free cash flow through the cycle, enhanced balance sheet flexibility and more sustainable capital returns. This should also mitigate the volatility inherent in our smaller existing system. We expect to see approximately $70 million in cost and operational synergies on an annual run rate basis. Ultimately, we believe a larger platform improves our positioning for future growth, supported by a larger and more diversified shareholder base.

Turning to Slide 5. We believe this transaction comes at an attractive point in the cycle with a compelling forward margin environment. The ongoing conflicts in Russia, Ukraine and the Middle East continue to drive volatility across crude oil and refined product markets. Disrupted shipping through the Strait of Hormuz, combined with damage to refineries in the Middle East and Russia continues to constrain global refined product supply. Even if an effective reopening of the strait eases crude supply constraints, we believe refined product prices could stay elevated for longer as damaged refineries must be repaired and global inventories rebuilt. We think global supply dislocations and historically low inventory levels support a higher than mid-cycle margin environment for at least the next 12 to 24 months.

Looking at the U.S., the domestic refining fleet ran hard in the third quarter as companies deferred maintenance and maximize throughput volumes to keep product supply flowing to meet the needs of consumers. U.S. refinery utilization averaged 96% in the quarter, well above the 5-year average of 92% for the same time period. Despite the high utilization, refined product inventories have continued to decline due to resilient demand trends and increased refined product exports. Domestic gasoline inventories are currently 5% below the 5-year average and distillate inventories are 9% below the 5-year average. Exports of gasoline and diesel from the U.S. averaged 2.9 million barrels per day for the third quarter, an increase of nearly 20% from the third quarter of 2025.

Slide 6 shows how PADD II refining dynamics reflect similar trends with supply-demand fundamentals and widening light heavy differentials supporting margins in the region.

Before we speak to our third quarter results, I want to recognize the employees at St. Paul Park and Mandan, who have built a long record of safe and reliable operations, along with the team at CVR Energy that has worked tirelessly on this transaction. We look forward to welcoming these new employees to CVR Energy following our closing, and our focus between now and closing will be a seamless transaction for our new colleagues and customers.

Now let me turn the call over to Richard to discuss our third quarter results.

Thank you, Dane, and good morning, everyone. Turning to our third quarter results highlighted on Slide 10. For the third quarter of 2026, our consolidated net income was $563 million, earnings per share was $5.67 and EBITDA was $804 million. Our third quarter results include a favorable change in our RFS liability of $314 million, favorable inventory valuation impacts of $35 million and unrealized derivative losses of $127 million. Excluding the above-mentioned items, adjusted EBITDA for the quarter was $582 million and earnings per share was $4. Adjusted EBITDA in the Petroleum segment was $565 million for the third quarter compared to $120 million for the third quarter of 2025. Elevated Group 3 crack spreads and higher throughput volumes drove the majority of the increase from the prior year period, offset somewhat by higher RIN expenses and realized derivative losses.

Combined total throughput for the third quarter of 2026 was approximately 228,000 barrels per day. Crude utilization for the quarter was approximately 105% of nameplate capacity and light product yield was 93% on total throughput volumes. The Group 3 2-1-1 averaged $68.50 per barrel for the third quarter of 2026 compared to $25.94 per barrel in the third quarter of 2025.

Our third quarter realized margin adjusted for the change in RFS liability, inventory valuation and unrealized derivative losses was $34.97 per barrel, representing a 51% capture rate on the Group 3 2-1-1 benchmark. RIN price increased significantly from third quarter 2025 levels, up over 125% to average over $14 per barrel for the third quarter of 2026. Net RIN expense for the quarter, excluding the change in RFS liability, was $235 million or $11.20 per barrel, which negatively impacted our capture rate for the quarter by approximately 16%.

The estimated accrued RFS obligation on the balance sheet was $230 million at September 30, representing 113 million RINs mark-to-market at an average price of $2.04. We were pleased with the EPA's decision in August to grant Wynnewood Refining Company a full SRE for its 2025 obligation, which reduced the RFS liability on the balance sheet by $253 million. We appreciate EPA's recognition that Wynnewood Refining Company is disproportionately economically harmed by the RFS and deserves full relief. However, the exorbitant cost of RINs continues to disproportionately harm small and merchant refineries like ours, along with American consumers as RINs currently represent roughly $0.28 of every gallon that hits the pump. If the President wants to lower the price of fuel today, he should pull the only lever he can that doesn't need an act of Congress, exercise of the EPA administrator's existing RFS waiver authority.

Our third quarter 2026 results include derivative losses totaling $259 million, comprised of a $133 million realized loss and a $127 million unrealized loss. For the fourth quarter of 2026, we have approximately 2.3 million barrels of diesel hedged with a total notional value of approximately $93 million. For 2027, we have approximately 3.2 million barrels of diesel hedged fairly ratably across the year.

Direct operating expenses in the Petroleum segment were $6.15 per barrel for the third quarter compared to $5.69 per barrel in the third quarter of 2025. The increase in direct operating expenses per barrel was primarily due to increased personnel expense, largely due to share-based compensation.

Adjusted EBITDA in the Fertilizer segment was $20 million for the third quarter compared to $71 million for the prior year period. Ammonia utilization rate was 80%, which was impacted by the planned turnaround at East Dubuque during the quarter. The Board of Directors of CVR Partners General Partner declared a distribution of $1.79 per common unit for the third quarter of 2026. 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 third quarter of 2026 was $655 million and free cash flow was $593 million. Significant uses of cash in the quarter included $61 million of capital spending, $46 million of cash interest, $41 million paid for the noncontrolling interest portion of the CVR Partners' second quarter 2026 distribution and $10 million for dividends. Total consolidated capital spending on an accrual basis was $58 million, which included $22 million in the Petroleum segment and $35 million in the Fertilizer segment. For the full year 2026, we estimate total consolidated capital spending to be approximately $220 million to $240 million.

Turning to the balance sheet. We ended the quarter with a consolidated cash balance of $1.3 billion, which includes $158 million of cash in the Fertilizer segment. Total liquidity as of September 30, excluding CVR Partners, was approximately $1.7 billion, which was comprised primarily of $1.1 billion of cash and availability under the ABL facility of $530 million.

Looking ahead to the fourth quarter of 2026 and excluding the acquired Marathon assets for our Petroleum segment, we estimate total throughput to be approximately 210,000 to 225,000 barrels per day, direct operating expenses to range between $115 million and $125 million and total capital spending to be between $45 million and $55 million. For the Fertilizer segment, we estimate our ammonia utilization rate to be between 88% and 93%, which will be impacted by the completion of the East Dubuque turnaround in October. We estimate direct operating expenses, excluding inventory and turnaround impacts, to be between $58 million and $63 million, turnaround expenses to be between $4 million and $6 million and total capital spending to be between $26 million and $34 million.

With that, Dane, I'll turn it back to you.

Thank you, Richard. In summary, we delivered a great quarter in refining, and we remain constructive on the outlook for both segments. I would like to thank our employees for all their hard work during the quarter, delivering crude utilization of 105% and completing the East Dubuque turnaround on the revised schedule. Our third quarter results show the benefits of focusing on safe and reliable operations. We continue to believe this up cycle in refining could persist through 2027, and today's announcement is a clear example of our focus on pursuing accretive growth opportunities intended to add value for our shareholders.

We have approached the Marathon acquisition with discipline. We underwrote it on historical mid-cycle earnings rather than today's elevated margins and at less than 3.5x our estimates of 2026 EBITDA that includes both Refining and Marketing, we consider the transaction to be extremely compelling for CVR Energy through the cycle with the current environment as upside. Subject to closing, we look forward to welcoming the St. Paul Park and Mandan employees to CVR Energy.

With that, operator, we are ready for questions.

[Operator Instructions] Your first question comes from the line of Matthew Blair with TPH.

Congrats on the strong quarter. I think you mentioned at the end that this transaction was predicated on mid-cycle economics. Maybe you could talk a little bit about what your assumptions are for mid-cycle. If we look back, it looks like the Mid-Con segment for MPC made about $5 to $6 a barrel in 2024 and 2025, which I think, if I'm doing the math correctly, would put the EBITDA around $400 million. Does that seem reasonable for a mid-cycle environment? Or are you projecting something higher?

Matthew, yes, the idea of mid-cycle and refining is something that we talk about every quarter. I would say from a historical basis, not taking into account any of the changes in refining fundamentals recently, looking back over a 10-year period, that's typically the way we view mid-cycle. We look at a 10-year period of cracks, adjust that for the RIN component since the RVO has been so volatile and then gross that up with the current RIN price on a go-forward basis, we get to a number probably close to double that, that you threw out for a historical mid-cycle basis on these assets.

I think our view is that given all the changes in the global refining supply-demand picture recently, that the go-forward mid-cycle is probably higher than the historical mid-cycle. But I would point out, too, that the negotiations on these assets started before the Ukraine war kicked off. So all of the upside that we've seen in the market here recently and that we're looking forward to for the next couple of years most likely, really wasn't factored into the valuation that we had here.

Okay. Sounds good. And then could you talk a little bit about the crude slate and then the product exposure for the acquired refineries. I think I remember the St. Paul Park refinery running about 1/3 WCS. And so I guess that would put the total crude slate for the package at maybe roughly 20% WCS, 80% Bakken. Is that reasonable?

And then on the product exposure, I thought that these refineries also sold into the Mid-Con Group 3 product market like your existing system. So what is a good approximation for the split between Mid-Con and Midwest exposure for the acquired assets on the product line?

Yes, Matt, this is Dane. So total crude throughput for the acquired assets, call it, around 175,000 barrels a day. Bakken is about 126,000 of that, just approximately. And then total Canadian just under 50,000 barrels and half of that Canadian would be WCS or heavy. So -- and then on the, call it, the product side, these assets actually, with their wholesale marketing and strong, call it, presence of distribution in the, call it, the northern part of the Mid-Con -- there's really historically about 15% of their product that ends up, kind of, in that bulk market, so substantially lower than ours, and they have significantly more advantaged product placement.

North Dakota, obviously, the only -- sorry, Mandan is the only refinery in North Dakota and can place the majority of its product in relatively local areas. And then St. Paul Park has a really attractive metropolitan area that allows it to place the majority of its product over the rack. So from a marketing perspective, substantially different than what we have in our existing business today and don't really see a significant amount of overlap or bulk market volumes.

[Operator Instructions] Your next question comes from the line of Neil Mehta with Goldman Sachs.

Congrats on the transaction. I had a couple and I might queue back in here, which is -- the first is just around Mandan. Historically, this has been eligible for a small refinery exemption. Can you remind us that, I believe, has been more partial versus full, but help us size what that's been in terms of a cash flow tailwind? And how does that feed into the way that you thought about valuing these assets?

Yes. Thanks, Neil. Yes. So Mandan has received 50% waivers for the '23, '24, '25 period. In terms of our valuation, we actually did not apply any waivers into the go-forward business and any waiver received would be upside from our transaction valuation.

That's helpful. And just the follow-up is how do you weigh this relative to the path that you were on around deleveraging? Because you had gotten the balance sheet back into a good place at the precipice of reinstating the dividend. So how do you think about this relative to return of capital?

Yes. So Neil, for us, I think that we've all talked a long time that CVI, just kind of as a stand-alone business, always suffered from lack of geography, lack of scale and lack of really controlling the barrel downstream of this. So as this opportunity came up, and again, as Richard pointed out, we believe in an elevated period of time of cracks here for the next year or so or further, taking a little excess leverage and then using the incremental tailwinds we have from the market to get us back to a more normalized level across the entire fleet became the more accretive option for us. So while there is a little bit of excess leverage, if you think about a mid-cycle level on a, call it, LTM or on a '26 estimate or what we believe the '27 environment look like, it seems like a decent leverage target, but we want to continue to work that down over time.

[Operator Instructions] Your next question comes from the line of Neil Mehta with Goldman Sachs.

Can you spend a little bit more time talking about the retail side of the business and the marketing side of the business? A lot of us covered Northern Tier back in the day, and I know that was a business they were looking to grow. But just give us a mark-to-market on that -- on those assets and how we should be thinking about that?

Yes, Neil. So just to clarify, it's not a retail business and that we don't own the retail stores. It's more...

As a marketing...

Marketing [indiscernible]. So for one, that's a business we don't have today in our existing assets in the Southern Mid-Con and Group 3. So there is some margin that we're giving up between where we're selling in the bulk market and where that product ends up to the ultimate retailer. So by controlling that piece of the value chain, there's some incremental margin that we get to capture there. In addition to that or as part of that, which is actually a pretty meaningful piece, is the RIN generation that comes along with controlling that piece of the business, along with the significant rack sales relative to what we have today.

So I think we mentioned in the prepared remarks, but on a go-forward basis, even not giving credit to the SREs that we've gotten at Wynnewood and that Mandan has received, our consolidated RIN obligation would go down quite a bit just from the additional blending. And as you layer in those potential additional SRE benefits that it goes even lower. So incremental margin there just on controlling more of the barrel and where it goes on top of the additional RIN generation.

Your next question comes from the line of Matthew Blair with TPH.

I guess just to clarify on the RIN exposure, are you saying that you can overblend on these assets that you actually are, I guess, net long RINs on the acquired assets? Or maybe I'm misinterpreting here.

Yes. No, Matt. It wouldn't be a net long position. The relative blending capacity of the acquired assets is significantly higher than the relative blending capacity of the CVR assets, predominantly the St. Paul Park with that local rack supplying a substantial portion of their volumes. What the RIN exposure comment is, as it relates to the weighted average across the 2 facilities, our percentage will come down in terms of open exposure pretty dramatically.

Okay. And then are you expecting any notable capital investments with this acquisition? Just thinking that the St. Paul Park runs a fair amount of WCS, but I believe it still does not have a coker. Would you consider putting in a coker or any other notable capital investments?

Thanks, Matt. I'll take that one. Yes, we would consider it. I think that there's -- really that's a pretty heavy lift in terms of capital dollars and really where would that -- how much more of the value would we capture in that mode. Coffeyville, we do have the benefit of having a gasifier fertilizer business right next door and can get a decent netback and that's a good synergy, and we probably don't have that as much. It's a pretty big transportation that they get from St. Paul down. There is capital that is planned, and we put all of the capital that was currently planned with Marathon into our future forecast, and we expect to complete those. Not -- they've done a really good job of maintaining those assets and don't see really a lot of makeup capital like you see in some other assets that go on the market. So excited about these assets the way they are well maintained and reliable. So look forward to working with them. And really, it's more about a successful integration than it is trying to re-kit that right away.

Sounds good. And then finally, is there any sort of earn-out on the transaction?

No, sir.

We have reached the end of the Q&A session. I will now turn the call back to Dane for closing remarks.

All right. Again, I would like to thank you all for your interest in CVR Energy and our employees for their hard work and commitment towards safe, reliable and environmentally responsible operations. And we look forward to reviewing our fourth quarter 2026 results during our next call in a couple of months. Have a safe day.

This concludes today's call. Thank you for attending. You may now disconnect.

Thank you for standing by, and welcome to the CVR Energy, Inc. Second Quarter 2026 Earnings Conference Call. [Operator Instructions]

I would now like to turn the call over to Richard Roberts, Interim Chief Financial Officer and Vice President of FP&A and Investor Relations. Sir, please go ahead.

Thank you. Good afternoon, everyone. We very much appreciate you joining us this afternoon for our CVR Energy Second Quarter 2026 Earnings Call. With me today are Dan Neumann, our Chief Executive Officer; Mike Wright, our Chief Operating Officer; and other members of management. Prior to discussing our 2026 second 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 the 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 for 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 2026 second quarter earnings release that we filed with the SEC and Form 10-Q for the period and will be discussed during the call.

With that said, I'll turn the call over to Dan.

Thank you, Richard. Good afternoon, everyone, and thank you for joining our earnings call. We posted another quarter of strong operating results, with crude utilization of 98% and ammonia plant utilization of 99%. The ongoing global conflicts have created tightness across energy and fertilizer markets, which directly benefited our asset base during the second quarter. We are pleased to announce the second quarter 2026 dividend of $0.10 per share, and we believe current market conditions could present opportunities to reduce leverage and add value for our shareholders.

Now let me turn the call over to Richard to discuss our financial highlights.

Thank you, Dan, and good afternoon, everyone. For the second quarter of 2026, our consolidated net income was $46 million, losses per share were $0.03 and EBITDA was $151 million. Our second quarter results include an unfavorable change in our RFS liability of $73 million, favorable inventory valuation impacts of $19 million and unrealized relative gains of $6 million.

Excluding the above-mentioned items, adjusted EBITDA for the quarter was $209 million and adjusted earnings per share was $0.34. Adjusted EBITDA in the Petroleum segment was $106 million for the second quarter compared to $38 million for the second quarter of 2025. Elevated group recrack spreads and higher throughput volumes drove the majority of the increase from the prior year period, offset somewhat by higher rent expenses, significant backwardation in WTI and realized relative losses.

Combined total output for the second quarter of 2026 was approximately 213,000 barrels per day. Crude utilization for the quarter was approximately 98% of nameplate capacity and light product yield was 92% on total throughput volumes. Benchmark crack for the second quarter of 2026 increased from the prior year period with the Group 3211 averaging $44.91 per barrel compared to $24.2 per barrel in the second quarter of 2025.

Our second quarter realized margin, adjusted for the change in RFS liability, inventory valuation and unrealized derivative gains was $12.43 per barrel, representing a 28% capture rate on the Group 3211 benchmark. Ran price increased significantly from second quarter 2025 levels, up over 125% to average nearly $14 per barrel for the second quarter of 2026. Net rent expense for the quarter, excluding the change in RFS liability, was $216 million or $11.16 per barrel, which negatively impacted our capture rate for the quarter by approximately 25%.

The estimated accrued RFS obligation on the balance sheet was $408 million at June 30, representing 169 million RINs mark-to-market at an average price of $2.41. EPA has still not ruled in our pending 2025 petition, and as such, we will continue to recognize 100% of Winnie finding companies rent allegation in our financials, which for the second quarter of 2026, was approximately $77 million. Headwind Wider finding Company received the 100% SRE we believe it is entitled to, our consolidated capture rate for the quarter would have been improved by approximately 9%.

EPA is now 9 months delinquent and rolling on winning wider finding companies 2025 SRE petition. The current compliance date for 2025 is approximately 1 month away, and we still do not know what our compliance obligation will be. RIN prices have gotten completely out of hand due to the blending obligations, EPA established in SET 2, effectively creating a short market that will require imported biofuels in order to potentially meet the required obligations. the complete opposite of the stated intent of the RFS.

Meanwhile, RIN prices are adding nearly $0.40 a gallon to the price of gasoline in the U.S. and RFS compliance costs are more than twice all the other combined operating costs from any refineries. As we have stated numerous times, if the administration is serious about lowering fuel prices, it should start with the RFS.

Our second quarter 2026 results included derivative losses totaling $75 million comprised of an $81 million realized loss and a $6 million unrealized gain. The realized loss for the quarter was related to the crack spread swaps that we discussed on the first quarter call. We settled approximately 4.4 million barrels of crack spread spot positions during the second quarter, leaving open positions totaling approximately 8.2 million barrels. For the remainder of 2026, there were approximately 4.6 million barrels of diesel hedged and 400,000 barrels of gasoline hedge, with the diesel exposure fairly split between the third and fourth quarters and all of the gasoline exposure in the third quarter.

The total notional value of the open crack spread swaps for the third quarter is approximately $102 million. For 2027, we have approximately 3.2 million barrels of diesel hedged fairly ratably across the year. We continue to actively monitor these positions and plan to be opportunistic in managing our exposure going forward, which could include closing out these positions or adding other positions depending on market conditions.

Direct operating expenses in the Petroleum segment were $5.93 per barrel for the second quarter compared to $6.45 per barrel in the second quarter of 2025. The decrease in direct operating expenses per barrel was primarily due to increased throughput volumes as the coal refinery was coming out of turnaround in the second quarter of 2025. Adjusted EBITDA in the Fertilizer segment was $107 million for the second quarter compared to $67 million for the prior year period. Ammonia utilization rate was 99%, with both plants running well and experiencing minimal downtime during the quarter.

The Board of Directors of CVR Partners' general partner declared a distribution of $6.08 per common unit for the second quarter of 2026. As CVR Energy owns approximately 37% of CVR Partners common units, we will receive a proportionate cash distribution of approximately $24 million.

Cash flow from operations for the second quarter of 2026 was $307 million and free cash flow was $264 million. Significant uses of cash in the quarter included $43 million of capital spending, $27 million paid for the noncontrolling interest portion of the CVR Partners' first quarter 2026 distribution, $20 million for cash interest and $10 million for dividends. Total consolidated capital spending on an accrual basis was $46 million, which included $29 million in the Petroleum segment and $17 million in the Fertilizer segment.

For the full year 2026, we estimate total consolidated capital spending to be approximately $215 million to $240 million. Turning to the balance sheet. We ended the quarter with a consolidated cash balance of $737 million, which includes $137 million of cash in the Fertilizer segment. Total liquidity as of June 30, excluding CVR Partners, was approximately $1.1 billion, which was comprised primarily of $600 million of cash and availability under the ADL facility of $540 million. We remain committed to our deleveraging goal and plan to continue working towards a gross leverage target of $1 billion, excluding debt at CVR Partners.

Looking ahead to the third quarter of 2026. For our Petroleum segment, we estimate total throughput to be approximately 205,000 to 220,000 barrels per day, direct operating expenses to range between $110 million and $120 million and total capital spending to be between $41 million and $50 million. For the Fertilizer segment, we estimate our ammonia utilization rate to be between 75% and 80% which will be impacted by the upcoming planned turnaround at the East -- but facility. We estimate direct operating expenses, excluding inventory and turnaround impacts to be between $57 million and $62 million, turnaround expenses to be between $30 million and $35 million and total capital spending to be between $40 million and $49 million.

With that, Dan, I'll turn it back over to you.

Thank you, Richard. In summary, we had another good quarter of operations in our refining and fertilizer businesses. We are optimistic about the near-term outlook for both segments and believe we could remain above mid-cycle conditions well into 2027. The ongoing geopolitical conflicts across the globe continue to create volatility. However, the U.S. has remained fairly insulated and able to benefit from these conditions with its relatively abundant supplies of available crude oil, natural gas and critical refining infrastructure.

Starting with the refining segment. The ongoing conflicts in the Middle East have so far been more impactful for refined products and crude oil. In addition to reduced flows of crude oil from the closure of the straight of our Hormus, a number of refineries in the Middle East have been damaged and the status of those repairs and time lines on potential restarts remains unknown. Outside of the Middle East, Ukraine has stepped up its attacks on Russian refineries over the past few months. with reports estimating 1/3 to nearly half of Russia's refining capacity could be offline.

As a result, refined product exports from Russia have been effectively shut off, while China has also halted refined product exports for several months. Looking at the U.S., the tightness in global refined product supply has created opportunities for increased refined product exports. Due to the exports of gasoline, diesel and jet fuel have increased 16% compared to the same period last year to over 2.6 million barrels per day on average. Meanwhile, U.S. demand for refined products has remained resilient, driving gasoline and diesel inventories near or below 5-year lows on a days of supply basis.

In the Mid-Con, where we operate, we are seeing similar trends with days of supply hovering near 5-year lows for the past several months. While cracks were strong in the second quarter, quarter-to-date cracks have increased further, and we should see some improvements to capture as crude oil backwardation narrows in the third quarter.

In the Fertilizer segment, the spring planting season went well, and demand for nitrogen was strong overall. Grain prices have increased some recently with expectations for lower carryout inventories driven by a combination of hot and dry conditions across the Western corn belt, increased export demand and a smaller-than-expected corn crop in Argentina. Summer fill and fall prepay for ammonia occurred in late June and UAN fill was completed in early July.

Overall, we saw a strong demand for both products, and we were able to secure a solid book of business for the second half of 2026 at attractive pricing. We expect to start the planned turnaround at Esubuque in late August, during which we intend to complete the brownfield capacity expansion, which we believe should increase its ammonia production capacity by approximately 5%. We also expect to finalize a detailed design and construction plan this year intended to allow the plant to utilize natural gas as an alternative feedstock to third-party pet coke.

Looking at quarter-to-date pricing metrics for the third quarter of 2026, Group 3211 cracks have averaged $58.70 per barrel with the Brent WTI spread at $4.82 per barrel and the WCS differential at $14.04 per barrel under WTI. Prompt fertilizer prices are $650 to $700 per ton for ammonia and $325 to $350 per ton for UAN. After 8 years of the company, I have seen the benefits of focusing on safety, reliability, cost management and prudent capital allocation. We have a strong team in place, and I look forward to continue executing on the strategy we laid out earlier this year.

In addition to our constant focus on safe and reliable operations, we remain committed to working to improve margin capture in our base business, and we are laser focused on pursuing accretive growth opportunities that would add value for our shareholders.

With that, operator, we are ready for questions.

[Operator Instructions] Your first question comes from the line of Manav Gupta with UBS.

Congratulations on a very strong quarter. You provided some outlook on macro and which was pretty constructive. And I'm just trying to understand, based on everything you said, you could be building a lot of cash. And again, coming back to your vision of expanding your refining footprint. So I'm just trying to go back and understand, is that still a goal for you to have higher refining capacity and if that is the case, how will you plan to fund it, including the surplus cash that probably you will accumulate because margins are well above mid-cycle?

Yes. Thanks, Manav. Yes. So our strategy is, obviously, we still believe that CVI needs to grow in barrels and diversify from its core region of the Southern Mid-Con. As it relates to the growing cash balances, Obviously, we want to continue to focus on reducing the debt levels at CBI to our base business. And also, as we continue to look at commercial opportunities, we're mindful that we may come across a couple of smaller, call it, immaterial opportunities to advance our logistics footprint. I don't really consider the cash at this time as potentially being a meaningful impact to any M&A, if there's an opportunity out there, we do believe the capital markets are open. Obviously, I think the world has learned a very valuable lesson on the value of the U.S. refining complex.

And frankly, we're going backwards in capacity when we should be going forward. So I kind of consider them separate topics and would look to fund alternatively other than using cash on the balance sheet.

And a quick 1 again on your hedging strategy. This is somewhat unique. Most of your peers don't hedge as much or don't admit to hedging that much. So can you walk us through some of the hedging strategy that you have in place for the next few quarters and the next year?

Yes, sure. So Manav, historically, we'd get Board authorization to target around 30% of our production and usually for around a calendar year. I would say, historically, when opportunities have presented themselves, we would layer into the market, and we'd often miss the timing of it and kind of not get the hedges on that we wanted. Unfortunately, this time around, we learned from the past went really, really fast. and the conflict, obviously is still ongoing. So a great example of past performance, not indicative of future results.

As we look forward, I think for our book for the rest of the year, we're satisfied with where the levels are at. 2027 is a much smaller amount. If we did look at any closures, it'd be looking at the 2027 area, obviously, nothing that -- with no action that we've taken and just discussing it. Going forward, I think that we will probably look to lower what type of authorizations we get, 30%, maybe a little high on a go-forward basis and just continue to assess as we go forward. and then be a little more cautious as we layer in.

Your next question comes from the line of Matthew Blair with TPH.

Maybe just stick on the hedging side. So -- if I heard correctly, it sounded like the realized hedge loss in the quarter was $81 million, which I think shapes out about $4.20 a barrel as a headwind. Is that how you look at it as well? And do you have an estimate on what like the mark-to-market hedging impacts would to like in Q3? Would that be something around $100 million to $120 million.

Matthew, it's Richard. And you're right on the 2Q impact, so it was $81 million of a realized loss, which was about $4.16 a barrel, and that was about a 9% hit to capture. We did say in the prepared remarks. So 2Q was the largest volume exposure that we had of all the hedges that we had in place. So that's behind us now, which is nice. We stepped down in 3Q, we stepped down again in 4Q. and then the '27, it's a lot smaller. For 3Q, total exposure is about 2.7 million barrels and the notional value of that position right now is $102 million as I mentioned earlier.

So if you want to try to back into it, I think we talked about it last quarter, we put these hedges on pretty early when the Iran conflict started, call it, late February, early March. So if you wanted to look at where we're 3Q, 4Q NYMEX diesel cracks trading around that time. You can probably get a sense of where we would have locked in to try to get order of magnitude of where we are versus where we enter into.

Okay. That's helpful. And then do you have any concerns on 2026 RIN compliance? Any concerns that there simply might not be enough RINs in the market and if so, are you adjusting your room purchase strategy? Or are you buying any extra wins now to avoid a potential shortage later in the year?

That's a great question, Matt. Yes. I think just in general, I have concerns about the 2026 RVO, and I'll avoid the soapbox. But just in brief, we've mismanaged the program. We are not helping farmers. We are harming consumers. and we are just not giving any clarity on how to plan businesses as it relates to EPA and their waivers, deadlines, et cetera.

So I don't know how the EPA could let the RIN bank go short. Like, they're forcing us to comply with something, they will have to take some level of action. It's just untenable that they could do what they've done or let it get worse. As it relates to RInbuying, our plan is always ratable. I think in 2Q here, when the prices really started to get out of control, we slowed down a little bit just because we think the EPA has to take some action here. That strategy has paid off a little bit as we've seen some softness in RINs for the last few days, and we'll continue to focus on ratable buying and with a little bit of catch-up here in the third quarter.

Okay. And can I just clarify for Wynnewood, are you currently buying 50% of your expected 2026 obligation?

Yes. So we are intending on buying 50% of the obligation for Wynnewood, although we still intend and have proven out using the DOE scoring methodology that we deserve a 100% waiver when you would.

Your next question comes from the line of Alexa Bruno with Goldman Sachs.

First of all, congratulations, Dane and Richard, on your new role is well deserved. Can you guys talk about what you're focused on in these new seats? And then how is the leadership transition going?

Yes. Thank you. The leadership transition has been a great. We have a really strong team in place. Obviously, I've been at the company a long time and as have a number of other senior leaders. The team I had in the CFO organization is very, very strong. And then obviously, bringing Richard up to help us out here has been, I think, a great move.

So I don't really feel like we missed a beat. the team I have is capable of wearing many hats has very broad experience and frankly, have made it relatively easy to manage through.

Strategically, I don't think anything really changes. We do want to focus on the core commercial business, improving capture and then just accretive opportunities to shareholders. So we're marching forward on that. And hopefully, we have some information to share soon.

Appreciate that. And then as a follow-up, just wanted to ask on capital allocation. Can you talk a little bit more about how you guys are thinking about balancing a dividend with debt reduction? And then as you look at the potential to scale up refining, what does the M&A landscape look like right now?

So for capital allocation, consistent with what we previously said, we really want to get back to that base level of $1 billion of debt, excluding CVR Partners. So that remains a priority. I would say similar to the past, we always said that we didn't have to get that balance gone before we return to dividend and we delivered on that in the first quarter. If we can make meaningful progress, which we have a line of sight to doing on the remaining balance of that debt, there's certainly opportunity to discuss some incremental increase in the dividend with the market conditions the way they are.

I don't see us returning to the high historical levels but something that is sustainable and regular throughout the cycle. So we'll continue to provide updates on that front. M&A perspective, I think this, to me, almost feels like somewhat of an ideal time for folks to take action, looking to rebalance portfolios. Now more than ever, I think the ability for refining refineries to trade at a mid-cycle level, which over a long term is where people should transact presents an opportunity. Historically, bid as have been very, very wide, but this gives you a scenario where value can be achieved in risk/reward can be balanced as well.

That concludes our question-and-answer session. I will now turn the call back over to Dan Neuman for closing remarks.

Again, I would like to thank you all for your interest in CVR Energy and our employees for their hard work and commitment towards safe, reliable and environmentally responsible operations. And we look forward to reviewing our third quarter 2026 results during our next earnings call. Have a safe day.

Ladies and gentlemen, this concludes today's call. Thank you all for joining. You may now disconnect.

Hello, and thank you for standing by. My name is Regina, and I will be your conference operator today. At this time, I'd like to welcome everyone to the First Quarter 2026 CVR Energy, Inc. Earnings Conference Call. [Operator Instructions] I'd now like to turn the conference over to Richard Roberts, Vice President of FP&A and Investor Relations. Please go ahead.

Good afternoon, everyone. We very much appreciate you joining us this afternoon for our CVR Energy First Quarter 2026 Earnings Call. With me today are Mark Pytosh, our Chief Executive Officer; Dane Neumann, our Chief Financial Officer; Mike Wright, our Chief Operating Officer; Travis Capps, our Chief Commercial Officer; and other members of management. Prior to discussing our 2026 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 2026 first quarter earnings release that we filed with the SEC and Form 10-Q for the period and will be discussed during the call. With that said, I'll turn the call over to Mark.

Thank you, Richard. Good afternoon, everyone, and thank you for joining our earnings call. In the first quarter, our operations performed well with crude utilization of 97% and ammonia plant utilization of 103%. Major geopolitical events drove volatility in energy and fertilizer markets, which have set up attractive market opportunities for the balance of 2026. Given the disruptions in global supply chains with loss of production and lack of product movement for refined products and fertilizer, CVR Energy is well positioned to improve our margin capture for the balance of the year.

We are pleased to announce a first quarter 2026 dividend of $0.10 per share, and we believe our prospects should allow for a balanced debt reduction and capital returns to shareholders as we move forward. Now let me turn the call over to Dane to discuss our financial highlights.

Thank you, Mark, and good afternoon, everyone. For the first quarter of 2026, our consolidated net loss was $160 million, losses per share were $1.91 and EBITDA was a loss of $52 million. Our first quarter results include unrealized derivative losses of $158 million, which primarily relate to NYMEX gasoline and diesel crack spread swaps entered into during the quarter against expected future production at a crack spread value of $447 million through 2027, which I will discuss further in our Petroleum segment results.

In addition, our results also include an unfavorable change in our RFS liability of $51 million and favorable inventory valuation impacts of $120 million. Excluding the above-mentioned items, adjusted EBITDA for the quarter was $37 million and adjusted losses per share were $1.24. Adjusted EBITDA in the Petroleum segment was a loss of $50 million for the first quarter compared to a loss of $30 million for the first quarter of 2025. Increased RIN expenses, higher operating costs and realized derivative losses drove the majority of the decrease from the prior year period.

Combined total throughput for the first quarter of 2026 was approximately 214,000 barrels per day. Crude utilization for the quarter was approximately 97% of nameplate capacity and light product yield was 93% on total throughput volumes. Benchmark cracks for the first quarter of 2026 increased from the prior year period with the Group 3 2-1-1 averaging $21.58 per barrel compared to $17.65 per barrel in the first quarter of 2025. Our first quarter realized margin adjusted for unrealized derivative losses, the change in RFS liability and inventory valuation was $4.72 per barrel, representing a 22% capture rate on the Group 3 2-1-1 benchmark.

RIN prices increased significantly from the first quarter 2025 levels, more than doubling to almost $9.50 per barrel for the first quarter of 2026. Net RINs expense for the quarter, excluding the change in RFS liability, was $143 million or $7.37 per barrel, which negatively impacted our capture rate for the quarter by approximately 34%. EPA has repeatedly stated that the cost of RINs is ultimately passed through to consumers at the pump. The decision to establish the highest RVO in history through the recent set 2 rule has driven RIN prices significantly higher, which has in turn raised the price of gasoline.

This is in direct conflict with the administration's stated goal of lowering fuel costs for American consumers. RIN prices have increased more than 75% since the beginning of the year, in addition to the 18% increase in the RVO, currently adding $0.25 to $0.30 to every gallon of fuel purchased in America. If the administration is serious about lowering fuel prices, it should start with the RFS. The estimated accrued RFS obligation on the balance sheet was $204 million at March 31, representing 113 million RINs mark-to-market at an average price of $1.80. As EPA has not yet ruled on our pending 2025 petition, we will continue to recognize 100% of Wynnewood Refining Company's RIN obligation in our financials, which for the first quarter of 2026 was approximately $52 million.

Had Wynnewood Refining Company received the 100% SRE we believe it is entitled to, our consolidated capture rate for the quarter would have improved by approximately 12%. Once again, EPA has missed a deadline on ruling on Wynnewood Refining Company's 2025 SRE petition. Will the EPA ever meet a deadline? Our first quarter 2026 results included derivative losses totaling $182 million. As previously discussed, $158 million of this loss was the unrealized mark-to-market change in all of our open crack spread swap positions as of March 31, and our physical positions intended to offset are expected to be sold as the swap contracts expire through 2027.

Given this disconnect, we do not view the impact of the unrealized loss as a detriment to the current period and as we have done in the past, adjust the amount out for our adjusted EBITDA figures. As we progress through the year, if these positions remain negative, we would anticipate these derivative losses to be more than offset by any gains on physical production as we realize increased crack spreads on the remainder of our unhedged production. As of March 31, our total open crack swap positions included 9.9 million barrels of diesel and 2.4 million barrels of gasoline. Of this total, approximately 2.9 million barrels of diesel swaps are in 2027 with the remainder in 2026.

This represents roughly 15% of our expected gasoline and diesel production volumes for 2026 and 4% for 2027. Since the end of the quarter, NYMEX crack spreads have declined, and we have seen Group 3 strengthen relative to the onset of the war. We will continue to actively monitor these positions and plan to be opportunistic in managing our exposure going forward, which could include closing out these positions or adding other positions depending on market conditions. Direct operating expenses in the Petroleum segment were $6.10 per barrel for the first quarter compared to $8.58 per barrel in the first quarter of 2025.

The decrease in direct operating expenses per barrel was primarily due to increased throughput volumes as the Coffeyville refinery was undergoing a turnaround in the first quarter of 2025. Adjusted EBITDA in the Fertilizer segment was $78 million for the first quarter compared to $53 million for the prior year period. Ammonia utilization rate was 103% with both plants running well and experiencing minimal downtime during the quarter. The Board of Directors of CVR Partners' general partner declared a distribution of $4 per common unit for the first quarter of 2026.

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 first quarter of 2026 was $64 million and free cash flow was $21 million, of which approximately $63 million was generated by the Fertilizer segment. Significant uses of cash in the quarter included $47 million of capital spending, $40 million of cash interest, $15 million for the costs associated with the debt refinancing and $3 million paid for the noncontrolling interest portion of the CVR Partners' fourth quarter 2025 distribution.

Total consolidated capital spending on an accrual basis was $44 million, which included $29 million in the Petroleum segment and $14 million in the Fertilizer segment. For the full year 2026, we estimate total consolidated capital spending to be approximately $200 million to $240 million. Turning to the balance sheet. We ended the quarter with a consolidated cash balance of $512 million, which includes $128 million of cash in the Fertilizer segment. Total liquidity as of March 31, excluding CVR Partners, was approximately $923 million, which was comprised primarily of $384 million of cash and availability under the ABL facility of $539 million.

We remain committed to our deleveraging goal and plan to continue working towards a gross leverage target of $1 billion, excluding debt at CVR Partners. Looking ahead to the second quarter of 2026 for our Petroleum segment, we estimate total throughputs to be approximately 200,000 to 215,000 barrels per day, direct operating expenses to range between $110 million and $120 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 95% and 100%, direct operating expenses, excluding inventory and turnaround impacts, to be between $57 million and $62 million and total capital spending to be between $28 million and $32 million. With that, Mark, I will turn it back over to you.

Thank you, Dane. In summary, despite a slow start to the year in the Refining segment, market fundamentals have changed quickly over the past few months, and we believe the outlook is constructive for both of our businesses. Two areas of the economy that are among the most impacted by the ongoing conflicts in the Middle East are energy and fertilizers. Starting with the refining segment, global inventories of crude oil and refined products have tightened considerably over the past few months with the effective closure of the Strait of Hormuz.

While the extent of the damage to refining capacity is still unclear at this point, the larger impact to global refined product markets has been availability of crude oil supplies and the need to curtail refinery runs as a result. Fortunately, the U.S. refining fleet has largely been unimpacted so far, although refined product inventories in the U.S. have also been declining partly due to increased product exports. Gasoline and diesel inventories in the Mid-Continent were elevated at the beginning of the year, driven by higher-than-average refinery utilization levels that weighed on crack spreads, particularly gasoline cracks.

This has changed significantly over the past month with gasoline inventories declining by 17% and diesel inventories declining 20% compared to the beginning of the year. Demand trends have improved as well for both gasoline and distillate in the Mid-Con. On a days of supply basis, gasoline supply is sitting at the low end of the 5-year range, while distillate supply is below the 5-year average. This improvement in Mid-Con supply and demand fundamentals over the first quarter has tightened refined product basis in the Mid-Con relative to other regions of the country.

Accessing higher demand regions outside the Mid-Continent also remains one of our key strategic initiatives as we work to improve margin capture in the refining segment. We have stepped up these efforts and recently began utilizing the rail loading facility at Wynnewood that was repurposed after the reversion of the renewable diesel unit. We remain optimistic that basis has room to improve further over the intermediate term with the new product pipeline from Kansas and Denver scheduled to come online later this year. Other pipelines under development over the next few years, including the Western Gateway pipeline should offer additional outlets from the Mid-Con and the Gulf Coast as well.

In the Fertilizer segment, the spring planting season is underway and has gone well so far this year. The USDA is currently estimating approximately 95 million acres of corn will be planted in 2026. While this is a decline from the record levels of 2025, 95 million acres is well above the average level of corn plantings over the last 5 years. Nitrogen fertilizer inventory levels at the beginning of the year were tight across the industry after the large planting seasons in the U.S. and Brazil in 2025 and the ongoing conflicts in Russia and Ukraine. The recent events in the Middle East have caused fertilizer markets to tighten even further.

Roughly 30% of nitrogen fertilizer production typically transits through the Strait of Hormuz and multiple nitrogen fertilizer production facilities across the Middle East have been damaged or curtailed production over the past few months due to limited natural gas supplies. While it remains unclear how long these issues in the Middle East will persist, we will continue to focus on safely and reliably running our plants at high utilization levels to meet the needs of our customers during the challenging time in our industry.

Looking at quarter-to-date pricing metrics for the second quarter of 2026, Group 2-1-1 cracks have averaged $38.36 per barrel with the Brent WTI spread of $3.81 per barrel and the WCS differential at $15.46 per barrel under WTI. Prompt fertilizer prices are $950 per ton for ammonia and $525 per ton for UAN. In closing, I would like to thank our employees for their excellent execution, safely achieving 97% crude utilization and 103% ammonia utilization for the first quarter.

Strong operating performance, along with the improvements in crack spreads and the progress we have made so far in reducing debt having enabled us to announce a dividend of $0.10 per share for the first quarter of 2026. We intend to continue our deleveraging strategy as we look to return to $1 billion of gross debt on the balance sheet. In addition, we will continue to work to improve margin capture in our base business while we seek opportunities to add scale and geographic diversity to our portfolio. With that, operator, we are ready to take questions.

[Operator Instructions] Our first question will come from the line of Matthew Blair with TPH.

I was hoping you could talk a little bit about your increasing exposure to WCS at Hardisty. I think your disclosures show roughly 8% yield -- or sorry, crude slate exposure to WCS in Q1 versus basically 0 in Q4. Why are you making that change? And what advantages does that offer to CVR here?

Matthew, it's Mark. When the actions were taken in Venezuela in early January, we saw almost an immediate change in the values for Western Canadian and that the differential backed up by about $3 a barrel. And when we looked at it and ran our models, we saw that have more value than our other alternatives. And so we've been running a lot more in Western Canadian, around 18,000 barrels a day. And so we'll continue to do that if the differentials hold in there. They've been good so far, and we're almost 4 months into it. So good value in that crude.

Sounds good. And then could I just confirm a few things on your derivative exposure. So for the first quarter, was the realized impact that rolled through your numbers approximately a headwind of about $37 million or about $2 a barrel? I'm getting that based on your total impact of $195 million plus the $158 million of unrealized. And then secondly, for the second quarter, if there was a mark-to-market today, do you have an approximate impact that these derivatives would have in Q2?

Yes, Matt, this is Dane. Just to summarize on the first quarter, yes, so we did -- as you saw in our 10-K, we did have some crack swap positions on. The realized loss on those was about $25 million, really due to positions that were put on lower losses Jan, Feb. And then with March, they got exacerbated. The remainder of that is the losses associated with really inventory hedging as the prices ran up on crude, particularly in the month of March.

As it relates to the second quarter, we won't give any specifics, but we did give out kind of the notional amounts of our hedges and also the -- effectively, the $447 representing the amount of volume at a strike price. You can kind of calculate an average from that. I'll remind you that we did put on those positions early at the outset of the conflict. And the market was pretty heavily backwardated at that time. So I wouldn't assume that average applies over the entire strip.

Our next question comes from the line of Manav Gupta with UBS.

I just wanted to understand if you could talk a little bit about the macro as -- in Mid-Con as to what you're seeing out there in terms of supply-demand cracks? And how long do you expect some of these cracks to remain elevated, even if the Strait of Hormuz opens because there are a few out there saying that it could take like 2 months for flows to normalize. But on top of that, there are many people who don't have crude globally. So cracks could remain well elevated. So from your perspective, where you're sitting, can you talk a little bit about the refining macro?

Sure. Thank you, Manav. So what we experienced is, and typical for the Mid-Con, there was a lag. So when the conflict broke out, the coastal markets adjusted faster than our market did. But over the course of March, we started to close the gap between the Mid-Con and the Gulf Coast, in particular, which is our closest market, but also the other Western markets. And yes, cracks -- our differentials or our basis has really, I'd say, gotten closer to normal there between where we are. So our cracks have elevated faster than the others.

And we've been able to move product into other markets and that's drawing -- the other markets are drawing out of the Mid-Con. We've had a big drop in inventories in the last 3 weeks. And so our market is, I'd say, adjusted now to the conflict. And so with -- if these markets, we agree with you. We tend to think this is going to go longer than maybe people expect a snapback. And -- but our market is already set up with the other markets, and I think we will benefit without the spread in basis, which we -- it took us 3 or 4 weeks for that to fall into place. So we're enjoying a lot better cracks in April and the markets have settled in, and we are -- the markets are drawing out of the Mid-Con at this point. And we expect that as long as this conflict is in place, it will continue.

Perfect. My quick follow-up here is, I think I know the answer, but I just want to make sure the dividend that has been reinstated, that's not a variable dividend, right? That's your path to a normal dividend, which will be there and maybe grow from here. Is that the right way to think about it?

That's correct. It's not a -- our fertilizer business is a variable. This is not meant to be a variable dividend, Manav.

[Operator Instructions] And our next question comes from the line of Alexa Petrick with Goldman Sachs.

We just wanted to ask a follow-up on the hedges announced during the quarter. Can you talk a little bit about what drove the decision to add those hedges? Is there any strategy there that we should expect to continue? Or any color on that would be helpful.

Yes. Thanks, Alexa. So historically, we've put hedges on when we've seen market levels above mid-cycle. We've done that over the past couple of years with some downside protection. As the war broke out and we saw things elevate quickly, we wanted to -- not knowing if the market was going to correct itself quickly or not, we wanted to get in the market and capture some of those higher values as we see, this is dragging out longer and a little slower might have been better, but we are where we are.

And as we said in the prepared remarks, look, I think we're going to continue to monitor. We don't like to hedge over roughly 30% of our production just to make sure that we're covered between our 2 refineries. And that's on gas or diesel independently. So we've got a pretty healthy book on right now that we'll continue to monitor. And then, if anything, look to try to lock in any basis positions as we see improvement from there.

Okay. That's helpful. And then our follow-up is just on capital allocation priorities. You've outlined that $1 billion gross leverage target. We've now got the dividend. Can you talk about how you're balancing the 2? And then you've also previously discussed potentially having interest for M&A. So any color on those different pieces would be helpful.

Sure. And I will separate the 2. On capital allocation, I think with the change in the market dynamics and opportunities there, we feel like we can continue on the path we've been on from a deleveraging, but also paying dividends going forward. And with our -- what we see for economics for the rest of the year, we feel like we can do both. And so that's why we were comfortable bringing the dividend back this quarter is that we just feel like we can achieve what we wanted to achieve and also return some capital to our shareholders.

On M&A, we continue to be -- that continues to be a priority for us. I would say the last couple of months have been one where maybe everybody is focused on all the volatility. So not -- that hasn't been our highest priority in the last 2 months. But as things settle down, we will be back and looking for opportunities and in discussions with folks. But the volatility is certainly -- that's our #1 priority right now is managing the base business and positioning the company to do well in a very volatile market, but with much more attractive economics than we had 2 months ago.

This concludes our question-and-answer session. I'll hand the call back over to Mark for closing comments.

Okay. Well, thanks, everybody. We appreciate you joining our call today, and we look forward to discussing our second quarter results in late July. Thank you very much, and have a good day.

That concludes our call today. Thank you all for joining. You may now disconnect.

Hello, and thank you for standing by. My name is Bella, and I will be your conference operator today. At this time, I would like to welcome everyone to Fourth Quarter 2025 CVR Energy, Inc. Earnings Conference Call. [Operator Instructions] I would now like to turn the conference over to Richard Roberts, Vice President, FP&A and Investor Relations. You may begin.

Thank you. Good afternoon, everyone. We very much appreciate you joining us this afternoon for our CVR Energy Fourth Quarter 2025 Earnings Call. With me today are Mark Pytosh, our Chief Executive Officer; Dane Neumann, our Chief Financial Officer; Mike Wright, our Chief Operating Officer; and other members of management.

Prior to discussing our 2025 fourth quarter and full year results, let me remind you that this conference call may contain forward-looking statements as estimate a 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 fourth quarter earnings release that we filed with the SEC and Form 10-K for the period and will be discussed during the call. With that said, I'll turn the call over to Mark.

Thank you, Richard. Good afternoon, everyone, and thank you for joining our earnings call. For the full year 2025, we reported consolidated net income of $90 million and EBITDA of $591 million. At the segment level, we generated EBITDA of $411 million in the Petroleum segment, $211 million in the Fertilizer segment and a loss of $22 million in the Renewable segment.

For the fourth quarter, consolidated net loss was $116 million and EBITDA was $51 million. Our fourth quarter results were impacted by the accelerated depreciation associated with the reversion of the renewable deal unit at Wynnewood back to hydrocarbon processing along with extended downtime at the Coffeyville fertilizer facility due to 3 weeks of start-up issues at the third-party air separation plant. We continue to believe the refining and fertilizer market fundamentals look constructive for the next several years, which I will discuss further in my closing remarks.

Now let me turn the call over to Dane to discuss our financial highlights.

Thank you, Mark, and good afternoon, everyone. For the fourth quarter of 2025, our net loss attributable to CVR shareholders was $110 million losses per share were $1.10, and EBITDA was $51 million. Our fourth quarter results included unfavorable inventory valuation impact of $39 million, a $9 million unfavorable change in our RFS liability and unrealized rate of gains of $10 million. Excluding the above-mentioned items, adjusted EBITDA for the quarter was $91 million and adjusted losses per share were $0.80.

Adjusted EBITDA in the Petroleum segment was $73 million for the fourth quarter of 2025 compared to $9 million for the fourth quarter of 2024. Higher crack spreads and increased throughput volumes drove the majority of the increase from the prior year period. Combined total throughput for the fourth quarter of 2025 was approximately 218,000 barrels per day. Crude utilization for the quarter was approximately 97% of nameplate capacity and life product yield was 92% on total throughput volumes.

Benchmark cracks for the fourth quarter softened from the third quarter levels as they typically do in the winter with the Group 311 averaging $22.70 per barrel. Cracks were unseasonably strong in October and November, which we believe led to higher than average U.S. refining utilization levels that partly drove the decline in crafts in December. Our fourth quarter realized margin adjusted for the change in RFS liability inventory valuation and unrealized derivative gains was $9.92 per barrel, representing a 44% capture rate on the Group 3 2-1-1 benchmark.

RIN prices declined approximately $0.18 per barrel from the third quarter 2025 levels, averaging $6.05 per barrel for the fourth quarter. Net RINs expense for the quarter, excluding the change in RFS liability, was $90 million or $4.49 per barrel, which negatively impacted our tax rate for the quarter by approximately 20%. The estimated accrued RFS obligation on the balance sheet was $72 million at December 31, representing 59 million RINs mark-to-market at an average price of $1.21. As a reminder, we will continue to recognize 100% of Wynnewood Refining Company's RIN obligation in our financials as EPA has not yet ruled on our pending petition, which for the fourth quarter of 2025 was approximately $34 million.

Direct operating expenses in the Petroleum segment were $5.40 per barrel for the fourth quarter compared to $5.13 per barrel in the fourth quarter of 2024. The increase in direct operating expenses per barrel was primarily due to increased personnel and utilities costs.

Adjusted EBITDA in the Renewable segment was breakeven for the fourth quarter, a decline from fourth quarter of 2024 adjusted EBITDA of $9 million. The decline in adjusted EBITDA was driven by a combination of the loss of the blenders tax credit, a decline in the HOBO spread and reduced throughput volumes. We ceased operations of the renewable diesel unit at the end of November and the reversion of the unit to hydrocarbon processing was completed in December.

Adjusted EBITDA in the Fertilizer segment was $20 million for the fourth quarter of 2025 compared to $50 million for the prior year period. ammonia utilization rate was 64% for the quarter, which was impacted by the planned turnaround and subsequent delayed start-up at the Coffeyville facility.

While the turnaround was completed in early November as scheduled, we experienced additional downtime following approximately 3 weeks of start-up issues at the third-party air separation plant. The Board of Directors of CVR Partners' general partner declared a distribution of $0.37 per common unit for the fourth quarter of 2025. As CVR Energy owns approximately 37% of CVR Partners common units we will receive a proportionate cash distribution of approximately $1 million.

Cash flow from operations for the fourth quarter of 2025 was breakeven and free cash flow was a use of $55 million. Significant uses of cash in the quarter included a $75 million payment on the term loan, $68 million of RIN purchases related to Wynnewood Refining Company's 2024 and 2025 obligations, $55 million of capital spending for the noncontrolling interest portion of the CVR Partners third quarter distribution and $26 million of cash interest.

Total consolidated capital spending for the full year 2025 was $197 million, which included $135 million in the Petroleum segment, $57 million in the Fertilizer segment and $4 million in the Renewable segment. Turnaround spending in the petroleum segment was approximately $190 million in 2025.

For the full year 2026, we estimate total consolidated capital spending to be approximately $200 million to $240 million and turnaround spending in the petroleum segment to be approximately $15 million to $20 million. Growth capital spending of $75 million to $90 million in 2026 is expected to be slightly elevated relative to the past few years as we hit the peak spending year for the alkylation project at Wynnewood along with a host of reliability and debottlenecking projects in the Fertilizer segment. As a reminder, the growth capital spending in the Fertilizer segment will be funded from cash reserves taken at CVR Partners over the past few years.

Turning to the balance sheet. We ended the quarter with a consolidated cash balance of $511 million, which includes $69 million of cash in the fertilizer segment. Subsequent to year-end, we completed a $1 billion senior notes offering with maturities in 2031 and 2034. The proceeds of the offering were used to repay the remaining balance of the term loan redeem all of the outstanding 8.5 senior notes due in 2029 and redeemed $217 million of the 5.75% senior notes due in 2028. With these transactions, we are able to significantly extend our debt maturity profile while retaining the ability to pay down the remainder of the outstanding 2028 notes as we work to get back to our current target of $1 billion of gross leverage.

Total liquidity as of December 31, excluding CVR Partners, was approximately $690 million, which was comprised primarily of $442 million of cash and availability under the ABL facility of $248 million. Subsequent to year-end, we also completed an upsize and extension of our asset-based lending facility, increasing the commitments from $345 million to $550 million and extending the maturity to 2031.

While we have not historically drawn on the ABL, we believe the increased liquidity is a benefit and provides additional financial flexibility if needed.

Looking ahead to the first quarter of 2026 for our Petroleum segment, we estimate total throughput to be approximately 200,000 to 215,000 barrels per day. We estimate direct operating expenses to range between $110 million and $120 million and total capital spending to be between $30 million and $35 million.

For the Fertilizer segment, we estimate our first quarter 2026 ammonia utilization rate to be between 95% and 100%. We estimate direct operating expenses to be approximately $57 million to $62 million, excluding inventory impacts, and total capital spending to be between $25 million and $30 million.

With that, Mark, I will turn it back over to you.

Thank you, Dane. As this is my first earnings call as the CEO of CVR Energy, I wanted to take a few minutes to highlight some of the strategic priorities that we will be focused on over the next few years.

First and foremost, our primary focus will continue to be the safe and reliable operations of our facilities. Reliability is key in this industry as we need to make sure the facilities are running well to be able to capture whenever margin opportunities present themselves.

Second, we are reevaluating our commercial optimization opportunities to drive margin capture improvement in the petroleum segment. While we are still at the beginning phases of this analysis, we believe there are opportunities in our existing asset base to capture more of the crack than we have been over the past few years. These include the reversion of the RDU back to hydrocarbon processing, which should expand the crude slate flexibility at Wynnewood and allow us to repurpose rail assets for additional feedstock security and product shipment optionality. At Coffeyville, we have started ramping up our WCS processing and believe we may be able to get throughput up to 20,000 barrels per day compared to less than 1,000 barrels per day in 2025.

I would also like to take this opportunity to introduce our new Chief Commercial Officer, Travis Capps. Travis brings over 30 years of leadership experience in the refining and petrochemical industries. Most recently having served as Chief Commercial Officer at Motiva. We're excited to have Travis leading our commercial team as we look to better optimize our refining portfolio.

Third, we plan to take a more proactive approach in pursuing opportunities to expand our asset footprint. Our portfolio would benefit greatly from additional geographic diversity and increased scale, and we plan to be more active in the marketplace and trying to identify these opportunities.

And finally, we will maintain a disciplined approach to capital allocation. We've made significant progress on our deleveraging efforts, reducing debt on the balance sheet by over $165 million in 2025. Making progress on deleveraging, along with maintaining a cash balance of $400 million to $500 million excluding CVR Partners and generating free cash flow in the current environment are some of the key metrics the Board evaluates each quarter regarding a potential return of the dividend.

Looking ahead, we believe fundamentals in the refining sector continue to look constructive over the next few years. Global refining capacity additions are set to slow down in 2026 and 2027 and compared to the past few years, while refined product demand growth is expected to remain steady, particularly for diesel.

Within the Mid-Con where we operate several new refined product pipelines are under construction or development that should offer additional outlets from the Mid-Con and the Gulf Coast to the Denver area, the Southwest and potentially on to California.

On the crude oil side of the equation, recent developments in Venezuela could lead to additional heavy barrels coming to the Gulf Coast, which in turn may pressure Canadian crude oil differentials. Wider Canadian crude debts would be a benefit to our system as we increase our WCS processing at Coffeyville, which was part of the facility's upgrades over a plus turnaround cycle.

Although RINs continue to weigh on our margin capture in refining, we remain cautiously optimistic after the actions taken by EPA last year to clear the backlog of outstanding SRE petitions. We believe Wynnewood refining company should continue to receive full or partial SRE grants as it has for the 2017 through 2024 period. And we will continue to fight for the right 21 refining companies entitled to.

Far from being the windfall that large integrated refiners and the RFA claim, there is no doubt that Wynnewood Refining company suffers disproportionate economic harm as a result of complying with the RFS. Any attempt to force the shutdown of small refineries is nothing more than a maneuver to increase the market share of large integrated refiners to align their own pockets at the expense of the American driving public.

In Fertilizer segment, despite a record crop year for corn in 2025 and preliminary estimates are calling for up to 95 million acres of corn to be planted in 2026, which should drive continued strong demand for nitrogen fertilizers through the spring. In addition, global inventories of nitrogen fertilizers appear to still be tight and pricing has been robust so far to start the year. We are continuing to invest in plant infrastructure for reliability in addition to increasing our DEF production and load-out capacity. We are also progressing the feedstock diversification and ammonia expansion project at the Coffeyville facility and the brownfield expansion at East Dubuque.

Although we experienced some unplanned downtime in the fourth quarter due to the third-party owned air separation plant at Coffeyville. Both facilities are running well today. And as Dane noted in our guidance, we are currently expecting a long utilization rates back above 95% for the first quarter.

Looking at quarter-to-date pricing metrics for the first quarter, [ Group 3 2-1-1 ] cracks have averaged $17.09 per barrel with the Brent WTI spread at $4.57 per barrel. And the WCS differential at $14.84 per barrel under WTI.

Prompt fertilizer prices are $700 per tonne for ammonia and $350 a tonne for UAN. With that, operator, we are ready for questions.

[Operator Instructions] Your first question comes from the line of Manav Gupta with UBS.

I wanted to first start on a little bit on what you mentioned in the opening comments, looks like more pragmatic M&A, but more persuasive approach to M&A than the prior management team. Can you talk a little bit about that, your expansion plan? What kind of assets are you looking? Which fats would you be interested in? Is it only refining? Anything on those lines would really be helpful.

Thanks for the question, Manav. So our focus is when we say proactive means that try to engage with other players to discuss kind of where things are headed strategically and looking for places where people are thinking of doing something different going forward looking at a portfolio evaluation and really just trying to engage in discussions and see what may be out there and trying to see if there are opportunities to do bilateral acquisitions as opposed to participating in the auction process. So we're really just more trying to engage in being in the dialogue.

We're looking at both sides of the business, so both our refining business and our fertilizer business. So we are looking at opportunities to grow in both areas. And what I want to say is while we're going to be more proactive, we're not going to lose our discipline. So it's not that we feel pressure that we have to do something, but we think there's going to be opportunities. We think the industry is sort of at an inflection point where there's going to be changes in portfolios out there, and we would like to see if there's opportunities to participate in that and -- but we're going to be disciplined.

And I would give you kind of two thoughts on metrics or guideposts. One is we won't stretch the balance sheet. So we're not going to try to leverage up to do anything in either business. And the other is that any deal that we would consider has to be accretive to our shareholders or our unitholders. So we are going to try to see if opportunities present themselves, but we are going to be disciplined in our approach.

Perfect. That's very reasonable. My quick follow-up, sir, is, you said you were going to pay down term loan and you have paid a portion of it, should we expect that you will first pay down the full amount of it? Or can we expect that as you are paying it down, you could institute like a small, modest dividend, refining shareholders always appreciate some kind of cash returns. I'll turn it over.

Yes. Thanks, Manav. This is Dane. As we've said in our prepared remarks, cash -- free cash flow, minimum cash balances and progress deleveraging have been our priorities. We don't believe that we have to be back to our base $1 billion target before a dividend can return, and we've obviously made a lot of progress on the deleveraging.

So again, we don't think we have to be at 0. We want to see a clear path to paying it down further before we consider returning to a modest level of dividend.

Yes. And just to add to that, Manav, because we do get that question quite a bit as when we return with the dividend, we want a dividend that's going to be sustainable in any part of the cycle. So we want to be -- have -- be able to do that and not yoyo the dividend. And so we -- one of our major goals is to bring the dividend back. We understand that the shareholders would like us to be paying a dividend. But we want also something that's sustainable. So we'll pick that spot. The sweet spot Dane's described where we can be sustainable in paying it again, in good crack markets and bad.

Your next question comes from the line of Matthew Blair with TPH.

Great. you talk a little bit more about ramping up the WCS runs at your Coffeyville refinery. I think previously, you were shipping those WCS barrels and then reselling them in Cushing. So you're still getting some economic benefit. But I think on -- earlier, you mentioned that you're looking to ramp up rents at 20,000 barrels a day versus just the one that you did in 2025. So -- can you talk about like why -- like what's spurring this change? Is there anything different going forward in your kit? Why are you doing this?

So Matt, we were -- we had sort of gotten prepared for this day. The last two turnarounds, we had upgraded our metallurgy there and so we were prepared for this day. And quite frankly, when Maduro was removed in Venezuela, that started changing the dynamics in the Western Canadian market. And we saw dips widen out. And the biggest bang for our buck in the portfolio was to run those barrels as opposed to there were some -- the sales price was the most attractive. So the most attractive option was to be able to run the barrels, and we moved very quickly.

So I was very happy with quickly our team acted on that, and we've been ramping up in January and into February. So we're taking advantage of that market opportunity. And -- but the best economic value of the barrel was to run it at Coffeyville rather than shipping it all down to the Gulf Coast.

Okay. It sounds good. And then could you talk about the steep rise in RIN prices since the start of the year and basically, how are you dealing with it? Are you looking to blend more of your own barrels? Or are you in the market purchasing those RINs? And as part of the M&A effort, would you think about acquiring more blending capacity or potentially retail to offset some of your RIN exposure?

Sure. There's a few questions in there, so I'll try to parse that. But rent prices have increased quite a bit in the first 6 weeks of the year. I think we believe that the -- it's not finalized, of course, we're in already in '26, so we don't even have to finalize '26 RVO. So apart from the course there. But there has been a proposal made. It's supposed to be finalized any day now, back in September, and we think that it's a much higher RVO than we've had historically, and we think that, that's lifted the rent market.

Just to give you a fact there, the RIN obligation at Wynnewood is our financial obligation is 2 to 3x what we pay everybody who works at the facility. So just to level set how what a steep cost it is to us it is 2 to 3x when we pay all the employees at the facility today. And yes, we are trying to blend more, we're trying to take steps to reduce our overall exposure. And in the acquisition world or develop world, we're going to be looking for ways to either get more blending capacity or moving fuel around or all of the above and try to minimize the impact on us. But there's no doubt that we can't hide from the full effect of the RVO. We're going to have some exposure there, but we're going to try to do everything we can to minimize the cost to the company.

Your last question comes from the line of [ Alexa Petrick ] with Goldman Sachs.

I wanted to start maybe back on Coffeyville. Would love your perspective, there's been more initiatives there on improving capture rates, and you've also talked about increasing jet fuel production. Any thoughts on how we can think about kind of the capture rate uplift and some of the moving pieces there going forward?

Sure. And we have a similar number of initiatives going on in winning wood. So I don't -- we did talk about Coffeyville a lot today, but we're pursuing it on -- at both facilities. And we're not -- we're pretty early and not ready to get targets. We're going to continue to be talking about all of our capture opportunities that we've either done or pursuing over the coming quarters. So we'll be communicating the way we are thinking about it is rather than putting a fixed number out there and saying that's what our -- it's really, from my perspective, a cultural shift where we are constantly looking for those margin capture opportunities.

Because they come in different forms in January, the two forms that were -- that appeared that were not on the radar screen or the winter storm and the Venezuelan situation. And we're working together to being able to respond to changes in the market and take advantage. And the issue is the window is open and close, and they're generally open for short periods of time. And so you have to be fast and you have to respond. And we are working to speed it up and respond to opportunities across the whole platform to be able to take advantage of it.

So we're not putting a target out there at this point, but we will be communicating with you as to our progress on improving our margin capture, and we wanted to show up in the results. Obviously.

Okay. That's helpful. And then maybe one follow-up. It's been a few months in some of these product pipeline projects were announced, bringing products from the Mid-Con to the West Coast. Any updated thoughts on how this could change the operating environment dynamic in the Mid-Con and how you guys are thinking about the next few years there?

Yes. Sure. We're -- I would just say I'm very optimistic about the Mid-Continent for the next several years because I think with the pipelines that are being developed to go to the West and then the Denver I feel like our -- the Group 3, the Southern and the Southern Plains, well, it's going to begin to look more like the other parts of the geographies and refining in other parts of the country where you have other outlets.

The biggest issue in the Mid-Con is seasonally, we have a wide basis. And if we had more outlets for what we're producing, I think that basis would not be as wide. And so I look out as the infrastructure is being developed as the Mid-Con being a pretty attractive place to be and give us opportunities to be moving fuel to other regions. And especially in times of the year where seasonally it's softer in the Mid-Con.

So I'm very optimistic about it. It's going to take some time for all the infrastructure to be put in place. But I think the upside for our company in the Mid-Con is very good. And I think the Mid-Con as a market is going to be a lot more attractive in the coming years. So very optimistic about what's ahead there.

There are no questions at this time. I will now turn the call back over to Mark Pytosh for closing remarks.

Again, I'd like to thank all of you for your interest in CVR Energy. Additionally, I wanted to thank our employees for their hard work and commitment delivering safe, reliable and environmentally responsible operations, and we look forward to reviewing our first quarter results in a couple of months. Thank you.

Ladies and gentlemen, that does conclude our conference call for today. Thank you all for joining, and you may now disconnect. Everyone, have a great day.

Greetings, and welcome to the CVR Energy Third Quarter 2025 Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Richard Roberts, Vice President of FP&A and Investor Relations. Thank you, sir. You may begin.

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; Dave Newman, our Chief Financial Officer; and other members of management. Prior to discussing our [indiscernible] 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 3rd quarter earnings release that we filed with the SEC on Form 10-Q for the period and will be discussed during the call.

That said, I'll turn the call over to Dave.

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 [indiscernible] 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%. And 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 '25 or '26 and we currently expect the next planned turnaround to be at Wynnewood Refinery in 2027. Group III benchmark cracks averaged $25.97 per barrel for the third quarter of '25 compared to $19.40 per barrel last year. Average RIN prices for the third quarter were approximately $6.33 a barrel, nearly 25% of the Group 3 2-1-1 craft. Regarding RFS, after years of fighting for the rights of the Wynnewood refinery -- at the rights at the Wynnewood refinery company is entitled to, EPA in August finally ruled on a backlog of $175 million outstanding SRE petitions covering the past compliance period that have been pending before it for years.

In addition to affirming its prior grants the wine would Refining Company's 2027 and '28 petitions, EPA granted full waivers for 2019 and '21 and 50% waivers for 2020 and '22 and '24. 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 for vegetable oil feedstock at our renewable diesel unit at Winningwood.

Gross margin was negative by approximately $0.01 per gallon for the third quarter compared to positive $1.9 per gallon for the previous year. The loss of the blenders tax credit and a significant increase in soybean prices this year continue to weigh on the profitability of the renewables business. We did not recognize any of production tax credit benefits in the quarter as we continue to wait 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 UAN and ammonia compared to the third quarter of 2024. And fertilizers 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.

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 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 rent 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 30, representing 90 million RINs mark-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 rent 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 Renewables 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 Holo 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 of 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. Sebi 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 noncontrolling 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 million the $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 30, excluding CVR Partners, was approximately $830 million, which was comprised primarily of $514 million of cash and availability under the ABL 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 throughput to be approximately 200,000 to 215,000 barrels per day, direct operating expenses to range between $105 million and $115 million and total capital spending to be between $20 million 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 be between $58 million and $63 million and total capital spending to be between $30 million and $35 million.

Turnaround expense is expected to be between $15 million and $20 million. For the Renewables segment, we estimate fourth quarter 2020 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.

Thanks, Dan. Refining market conditions continued to improve during the third quarter with refined product demand remaining steady and inventories continue to trend near 5-year average levels. Increased geopolitical tensions have contributed to the strength in crack, particularly diesel cracks, following a string of Ukranian drone tax on the Russian refineries over the past few months. Within the Mid-Con, 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 or out of the 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 product supply from PADD 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 in 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 and with minimal new fuels refinery capacity projected to start up over the next few years. Meanwhile, refined product demand appears stable and we continue to believe any pro-growth initiatives from the Trump administration will -- 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, probably has been challenged this year after the loss of the BTC and the increase in soybean break. -- 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 it 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 RD service. We would also retain the option to switch back to renewable diesel service in the future of 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 RD unit back to hydrocarbon processing. We also wrote off approximately $3 million of capital investment associated with the potential renewables project at the 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 planning 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 plants 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 2-1-1 cracks have averaged $25.69 per barrel with a Bread TI spread of $3.80 per barrel and a WCS differential of $11.62 and 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 UAM. 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 SRE grants at the Wynnewood Refining Company received in August, our balance sheet has improved significantly to the reduction of the RFS obligation.

However, EPA has not ruled on SRE petition SRE petition we submitted in July. If the Wynnewood refinery company is great at 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 and to satisfy both our gatobligated subsidiaries for '24 and '25 obligations. Beyond the current cash needs for RINs, we intend to continue to prioritize paying down the term loan with excess cash flow we were able to generate. Reducing the balance on the term loan is 1 of the several criteria in the Board's decision around a potential return to the quarterly dividend, and that decision is evaluated every quarter.

If cracks remain elevated, we would likely be able to reduce debt faster and accelerate conversations with the Board around the dividend. As always, we -- as always, we always look to ways to improve capture reduce costs 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. They have cross passed with a ton of people over the years, all of whom I've learned something from and contributed to my success.

With that, I am grateful. With that, operator, we're ready for questions.

[Operator Instructions] Our first question comes from the line of Matthew Blair with TPH.

Dave, wishing you the best in retirement. It's really been a pleasure working with you over these past, I guess, several years. So yes, we wishing you the best. I wanted to follow up on your commentary on the new product pipeline that would take barrels West. It seems like this could be a potential positive for MidCon refineries like CVI. But could you talk about whether you would plan to to make maintenance shipping commitments on any of these types? And if so, like is there a proposal that looks more favorable in your view?

Well, we haven't really studied that too much yet because a lot of the details on these lines is still coming out. But I think you're right, Matt, that it will be very constructive for the Mid-Con. As I've said many times, the Mid-Con has been long on product. with the high utilizations we've seen in the northern tier of the pad to and any relief of where to move those barrels will be a positive to the group 2 and then probably a positive to Group IV or PAD 4 and PADD 5.

Obviously, 1 of the projects goes all the way to California, the other does not. And I will remind you that the Denver pipeline is out there also, which moves barrels to PADD IV also. So 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.

Sounds good. And then I guess 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?

Well, in the short term, it definitely be shut down, and that's why we took the accelerated depreciation -- it's probably -- if you look at the current spreads of -- basis of soybean oil and other feedstocks, they're pretty tight and it doesn't give a lot of incentive for [indiscernible]. But 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. .

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

Just want to extend my congratulations on your retirement. And thank you for all the help throughout the years. We appreciate on the renewable diesel. So what does it take? Is it just the change of the catalysts or that there's other changes that you need to make in order for you to convert back into winning hydrocarbon. And also that do you have an estimate of the cost to keep the PTC to sustain in a reasonable shape so that in the future, you decided that to restore it.

Yes, Paul, I think it's a pretty easy conversion for us because we considered this when we built the unit -- so it's mostly a catalyst change. There's 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 just -- 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 breakeven. 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 couldn't really handle any of the real low CIs just because of metallurgy. And even with the low CI, what's happening in most cases as the Hobo goes up and down, and the RINs change is just going into the feedstock cost. So we just didn't see much of a chance to really -- for anything to change in that space that is going to make it a good deal.

So even with the PTC or facility, we're never able to handle the OCI stuff.?

Well, any of very low stuff, like used cooking oil, we're not designed to metallurgical wise. With land use that helped, but the PTC does not -- even with that doesn't make up for the BTC.

I see. And when you're saying that you're going to move forward the PTC and that, is there any -- that the cost is so minimum that to maintain it going forward, that is just the job in the bucket. So really just pocket change or that's a reasonable cost associated on a going-forward basis?

Once we mothball it, Paul, it's really pretty low cost. There'll be some costs that we started, but there won't be a lot .

I see. And then a final question. I mean with the -- all the proposed new pipeline getting the barrel out from the [indiscernible] does in any shape or form that change the way how you're looking at your configuration and how you're going to run those facilities? Or that doesn't really matter?

Well, depending on which those 2 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. So -- and 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. .

But certainly, we'll have the other 2 grades that we can do. And then 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 you have to make to do that. I'll remind you that we have this case at project that is going to make more all at Wynnewood we're going to be alkylating all our C3s that today we sell. And so that's going to increase our outlet production, which helps us in some of these clean-burning gasoline...

Yes. So we're trying to make gasoline for the 1 market. I should say, it's just a matter of the warning and how much is 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 case? And what is it to be on?

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

Your next question comes from the line of Alex Patrick with Goldman Sachs.

I wanted to ask on the $100 million rent obligation you guys talked about outstanding. How are you guys kind of thinking about the strategy of meeting that reobligation when we also keep in mind that we're still waiting on some incremental SRE updates specifically '24 and '25?

Yes. Thanks, Alexa. So right now, we're just thinking about the December deadline for '24 and the March deadline for 2025. the $100 million encompasses covering Coffeyville and winning wood at 50% through 2025 and also went through 2024. Again, as you mentioned, we're particularly monitoring for the 2025 waiver outcome -- and winning what historical the last few years have gotten 50%.

We expect that to be a worst-case scenario. We still believe it should be 100% in the event that we do get 100% I think is the rents that we purchased for that could be used for Copel compliance going forward. So it feels like a conservative thing to do to plan to buy the $100 million wins between now and March 31.

Okay. That's very helpful. And then maybe just some early thoughts on 26, how we should be thinking about capital spend? And then any considerations there related to the RDU conversion?

Yes. We don't -- we usually give that guidance in the fourth quarter, Alexa. So I think we'll wait until that time to fill you in on that.

Your next question comes from the line of Manav Gupta with UBS.

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 1.5 or 2 years, This is the most bullish I've heard you on an earnings call. So it's good that you also feel that this is a much stronger refining environment that we are in. And so 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 because that's the #1 question we get is CVI is doing much better. When can we see some form of payout for the shareholders?

Well, that's a difficult prediction to make, Manav. I do -- 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. And 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 start-up phase. There are just as 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.

And Demand is still growing, even though it's slower. No doubt, EV penetration is hit. But a matter of fact is there's -- the refining is going to -- to me, it's going to be short in the future. and it's a great space to be in. And 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 our -- what the market cap of what these companies are today. and that just bodes well to me for the future on what cracks will look like.

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.

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 towards safe, reliable and environmentally responsible operations. .

With that, we'll talk to you next quarter. Thank you.

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.