CVR Energy Inc
NYSE:CVI
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CVR Energy Inc
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Greetings, and welcome to the CVR Energy Third Quarter 2024 Conference Call. [Operator Instructions] As a reminder, this conference is being recorded.
It is now my pleasure to introduce your host, Richard Roberts, Financial Planning and Analysis and Investor Relations. Thank you, sir. You may begin.
Thank you, Christine. Good afternoon everyone. We very much appreciate you joining us this afternoon for our CVR Energy Third Quarter 2024 Earnings Call. With me today are Dave Lamp, our Chief Executive Officer; Dane Neumann, our Chief Financial Officer; and other members of management.
Prior to discussing our 2024 3rd 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 of the most directly comparable GAAP financial measures are included in our 2024 3rd quarter earnings release that we filed with the SEC and Form 10-Q for the period and will be discussed during the call.
With that said, I'll turn the call over to Dave.
Thank you, Richard. Good afternoon, everyone, and thank you for joining our earnings call. Yesterday, we reported third quarter consolidated net loss of $122 million and a loss per share of $1.24. EBITDA was a loss of $35 million. Our results were impacted by unplanned downtime at both facilities during the quarter, partially due to external power supply outages, along with an unfavorable mark-to-market impact on our outstanding RFS obligation and negative inventory readout validation impacts due to the declining crude oil price.
With the upcoming major turnaround planned at Coffeyville next year, maintaining adequate liquidity and a strong balance sheet is a primary focus as we navigate the currently challenging refining market. In light of this, the Board of Directors has elected to suspend the quarterly dividend as we look to preserve cash on the balance sheet. While this was a difficult decision, we believe it is an appropriate course of action given our near-term cash needs and the current forward strip for crack spreads into 2025.
In our Petroleum segment, combined total throughput for the third quarter of 2024 was approximately 189,000 barrels per day and light product yield was 99% on crude oil processed. We had a very difficult operational quarter with multiple plant interruptions, some of which were related to or were the result of external power supply outages. Crude oil utilization for the quarter was 85% compared to our third quarter crude utilization rate of 95% over the past 5 years.
We estimate lost profit opportunity was approximately $23 million in the third quarter, of which approximately $13 million was related to external power issues. Year-to-date, total lost profit opportunity was approximately $73 million. Group 3 2-1-1 benchmark cracks averaged $19.40 per barrel for the third quarter of 2024 compared to $39.10 per barrel for the third quarter of last year. Average RIN prices for the third quarter of 2024 also declined from the prior year period and ended the quarter at approximately $0.74 on an RVO weighted basis. Although this was a 7% increase from last quarter.
Regarding the RFS, the situation remains incomprehensible. No less than 3 federal courts, including the United States Supreme Court have told EPA in no uncertain terms that small refinery hardship exemptions exist to protect small refiners who suffer disproportionate economic harm. Both the Fifth Circuit and the DC circuit called EPA's denial of the most hardship petitions arbitrary and capricious, vacating those denials and reminding them back to EPA.
Incredibly, despite this expressed statutory obligation to rule on hardship petitions within 90 days, EPA has done nothing, even though almost a year has passed since the Fifth Circuit loss. EPA's ingregious conduct has level pending petitioners hanging in limbo for years and the financial impact of their actions threaten the very existence of small refineries like ours.
That a U.S. federal agency can be allowed to flagrantly and repeatedly violate the law without recourse shakes the very foundation of our government. No one is above the law, including EPA. So I call you out Administrator Regan. EPA has broken the RFS, violated the law, persistently ignores very clear direction from the courts. This must stop now. For our part, we continue to seek relief in court, not only through to secure small refinery exemptions that Wynnewood deserves, but to force EPA to remedy the root cause of small refinery harm. EPA's decision to violate the RFS law allowing non-obligated parties to produce, buy, sell, trade and hoard RINs, resulting in manipulation of the RIN market.
For the third quarter of 2024, we processed approximately 20 million gallons of vegetable oil feedstocks through the renewable diesel unit at Wynnewood. The HOBO spread weakened slightly from the second quarter of 2024 with lower diesel prices, although this was offset by higher prices for D4 RINs and LCFS credits, which helped drive a positive result for the quarter. As a reminder, our renewable diesel business is currently reported in our corporate and other segments.
In the fertilizer segment, both facilities ran well during the quarter with a consolidated ammonia utilization of 97%. Nitrogen fertilizer prices for the third quarter of 2024 increased relative to the third quarter of 2023, and we saw a strong demand for ammonia and UAN over the summer.
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 2024, our consolidated net loss was $122 million, losses per share were $1.24 and EBITDA was a loss of $35 million. Our third quarter results include a negative mark-to-market impact on our outstanding RFS obligation of $59 million and unfavorable inventory valuation impact of $30 million and unrealized derivative losses of $9 million.
Excluding the above-mentioned items, adjusted EBITDA for the quarter was $63 million and adjusted loss per share was $0.50. Adjusted EBITDA in the Petroleum segment was $24 million for the third quarter with the decline from the prior year period primarily driven by lower product cracks in Group 3 and reduced throughput volumes due to the downtime at both facilities.
Our third quarter realized margin adjusted for RIN mark-to-market impacts, inventory valuation and unrealized derivative gains was $8.23 per barrel, representing a 42% capture rate on the Group 3 2-1-1 benchmark. We estimate the unplanned downtime in the quarter negatively impacted our capture rate by approximately 7% related to the resale of gathered crude oil and the purchase of refined products, while the backwardation in the market drove an additional 6% unfavorable capture impact.
RINs expense for the quarter, excluding the mark-to-market impact was $46 million or $2.62 per barrel, which negatively impacted our capture rate for the quarter by approximately 14%. The estimated accrued RFS obligation on the balance sheet was $374 million at September 30, representing [ $467 million ] RINs mark-to-market at an average price of $0.80. As a reminder, our estimated outstanding RIN obligation excludes the impact of any small refinery exemptions.
Direct operating expenses in the Petroleum segment were $5.72 per barrel for the third quarter compared to $5.39 per barrel in the third quarter of 2023. The increase in direct operating expense per barrel was primarily driven by lower throughput volumes, partially offset by lower repair and maintenance expenses and natural gas and electricity costs.
Adjusted EBITDA in the Fertilizer segment was $36 million for the third quarter, with higher market prices for ammonia and UAN and lower feedstock and operating expenses, driving the increase relative to the prior year period. The partnership declared a distribution of $1.19 per common unit for the third quarter of 2024. The CVR Energy owns approximately 37% of CVR Partners common units. We will receive a proportionate cash distribution of approximately $5 million.
Cash provided by operations for the third quarter of 2024 was $48 million, primarily driven by $87 million of cash flow from the fertilizer segment. Free cash flow for the quarter was $13 million, also attributable primarily to the Fertilizer segment. Significant uses of cash in the quarter included $50 million for the CVI second quarter 2024 dividend, $39 million for cash interest, $36 million of capital and turnaround spending and $13 million paid for the non-controlling interest portion of the CVR Partners' second quarter 2024 distribution.
Total consolidated capital spending on an accrual basis was $39 million, which included $28 million in the Petroleum segment, $10 million in the Fertilizer segment and less than $1 million for the RDU. Turnaround spending in the third quarter was approximately $3 million. For the full year 2024, we estimate total consolidated capital spending to be approximately $170 million to $195 million which represents a reduction of approximately $25 million from our previous estimates. Turnaround spending is expected to be approximately $50 million to $60 million.
Turning to the balance sheet. We ended the quarter with a consolidated cash balance of $534 million, which includes $111 million of cash in the fertilizer segment. Total liquidity as of September 30, excluding CVR Partners, was approximately $713 million, which was comprised primarily of $423 million of cash and availability under the ABL facility of $290 million.
Looking ahead to the fourth quarter of 2024. 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 $100 million and $110 million. And total capital spending to be between $38 million and $42 million.
For the Fertilizer segment, we estimate our fourth quarter 2024 ammonia utilization rate to be between 92% and 97% with some potential downtime at the third-party air separation unit at Coffeyville expected in the quarter. We estimate direct operating expenses to be approximately $60 million to $70 million, excluding inventory impacts and total capital spending to be between $19 million and $23 million.
With that, Dave, I will turn it back over to you.
Thanks, Dane. Although we saw a slight improvement in the Group 3 crack spreads from the second quarter levels, Overall, refining markets remain challenging. While the Board's decision to suspend the dividend was difficult, we believe the key to surviving these downturns in the refinery is maintaining adequate liquidity and protecting the balance sheet, while we focus on areas we control, safe, reliable operations while reducing costs and capital spend. .
We are currently exploring the potential increase in our liquidity through possible access to capital markets, between these efforts, cash on hand, availability on our undrawn revolver, we are confident in our ability to navigate this challenging environment and be well prepared post-turnaround for any improvements in refining margins.
Line demand fundamentals for refined products have improved in the second half of 2024 with gasoline and diesel inventories both currently below 5-year averages. Gasoline and diesel demand are essentially in line with 5-year averages, while refined product exports have remained above 2 million barrels per day. One of the key issues for the U.S. refining in 2024 has been utilization levels that have averaged more than 2 percentage points higher than the 5-year average over the course of the year.
So far in the fourth quarter, we've seen utilization rates for the U.S. refining fleet decline from the low to mid-90s down to the mid-80s during the fall turnaround season. While this is encouraging, ultimately, we believe we need to see additional refining capacity rationalization in both the U.S. and globally in order to -- for crack spreads to make a sustained move higher.
In the fertilizer segment, we believe we are currently in a more of a mid-cycle type environment after the peaks we saw over the past few years, and we are encouraged to see ammonia and UAN prices for the third quarter increased relative to the third quarter of last year. The fall harvest is ahead of schedule, nearing completion and conditions look favorable for the fall ammonia application. Nitrogen fertilizer prices for the fourth quarter are up approximately $50 per ton for ammonia and $10 per ton for UAN compared fourth quarter of 2023.
Finally, in renewables, we are pleased with the third quarter results from the Wynnewood renewable diesel unit, with this being the first full quarter of operations with the RD unit with a pretreater. Our discussions with interested party -- counter-parties related to the potential conversion of the Wynnewood renewable diesel unit to 100% SAF are ongoing. As we said before, we would not expect to move forward with the conversion without developing an offtake structure for SAF that would provide us downside protection and minimize our reliance on government credits.
Looking at the fourth quarter of 2024. Quarter-to-date metrics are as follows: Group 3 2-1-1 cracks have averaged $18 per barrel, with the Brent-TI spread at $3.79 per barrel and the WCS differential at $12.93 per barrel under WTI. Prompt fertilizer prices are approximately $550 per ton for ammonia and $250 per ton for UAN. As of yesterday, Group 3 2-1-1 cracks were $15.83 per barrel. Brent TI was approximately $4.27 and WCS was $12.50 per barrel under WTI. RINs were at $4.29 per barrel.
The crack at these levels is well below mid-cycle and may remain this way through the next year. This creates an opportunity for us to focus on positioning our business for the long term. So we are best equipped to take advantage of favorable market conditions when they return, as I believe they will.
So here is our plan.
One, strengthen our balance sheet to improve our ability to navigate these market conditions. This includes internal cost-cutting initiatives and reduced hiring. Focus also includes focusing our capital spend on projects that are in flight and those critical to safe, reliable operations. And finally, we are exploring access to capital markets, which could include non-core asset sales. Suspending the dividend is also part of this, but our Board will continue to look at it each and every quarter. What we think this shows is we can make the tough decisions when necessary to support the company's future and our goal of increasing value to our stockholders.
Two, focusing on executing our upcoming turnaround safely on time and on budget. Given market conditions, our turnaround timing is it looks to be very, very well planned. Our track record for exceptional project execution things for itself. Although we've had some hiccups this year, we are a great operator to have demonstrated our ability to successfully execute turnarounds in the past. Three, continue exploring ways to optimize our business. We will not ignore accretive opportunities before us and liquidity measures we announced yesterday should help with this.
And four, as always, continue to focus on safe, reliable operations in an environmentally responsible manner. This should result in lower operating costs, better capture rates and ultimately, superior financial performance for our shareholders and stakeholders.
In summary, despite the weakness in the current refining market, we continue to believe the U.S. fleet is the most advantage in the world given its high complexity access to low-cost crude oil and natural gas. Our refineries are very competitive among this fleet. We have tremendous confidence in the future, and we see the actions we announced in our intended path forward as best positioning CVR to take advantage of it.
With that, operator, we're ready for questions.
[Operator Instructions] Our first question comes from the line of Neil Mehta with Goldman Sachs.
I guess Dave, maybe the first question just around how you're thinking about the dividend. You have always had a little bit more of a variable approach to the distribution raising it in strong times and suspending it previously in some of the weaker times. So just how should we think about the go forward for the dividend? And if we get on the back end of the turnaround and margin environment normalizing, how do you think about resuming it? And then just your framework would be helpful.
Yes, Neil, I think we've said many times that our structure, as such, really lends ourselves to our preferred method of returning cash to shareholders is via dividend. And I don't think anything's changed on that. Yes, we're a little bit more variable now. And if you look at our past record of returning cash to shareholders via the dividend, it's pretty strong.
We don't really want to take this action, but I think it's necessary in light of -- if you look at the forward curve from -- in '25, we're printing in the '17 type numbers. And with the inflation and everything that's been happening in the marketplace, we view mid-cycle has increased to at least $1 a barrel, if not $2. So we're just being cautious. If you look at the turnaround, we have coming up, it's our largest turnaround of the sequence. Every 5 years, it's around $180 million, is about half of our budget, a little less than half of our budget for turnarounds in that cycle. And we're just taking it very cautiously.
And then -- that's helpful. And then just your perspective on non-core asset sales and the opportunity set because as you talked about accessing the capital markets, you mentioned that you brought up UAN in the past as an area of potential monetization. But just curious on what in the portfolio do you think has -- could be on the table and any sense of how deep into conversations you might be? .
Well, we have really started anything in earnest, Jeff. But non-core assets, as you know, we have about $80 million worth of EBITDA associated with midstream assets, including pipelines, trucking and tankage and others. Some of that would be considered for sure. As far as UAN goes, we really have no new news in that area. And as you know, we own 37% of the units and have 100% ownership of the non-economic GP but nothing really new to report there yet.
Our next question comes from the line of Matthew Blair with Tudor, Pickering.
Is there a potential to file any insurance claims on the downtime in an effort to recover any of that lost profit opportunity?
Yes. We have recovered some money from it. I anticipate that our cost from a [ PP&I ] basis was somewhere in the neighborhood of $25 million. So we have a deductible, it comes off of that. But we don't have an answer for it yet exactly how much we'll get out of that. .
Sounds good. And then circling back to the question on the potential access to capital markets, should we interpret that to mean that you're considering a potential equity raise? And then also on the non-core asset sales, you mentioned some of the midstream assets. What about the gathering system? Would that be core or non-core for CVR Energy?
Well, I'll take the second part of that. The gathering system is integral to our system, but it could be monetized if we absolutely needed to. I don't think that would be our first choice. We have joint ventures and pipelines that feed our refineries that would probably go first. .
On the liquidity, Dane?
Yes. And Matt, as far as capital markets guy, I'd say it's pretty premature to discuss exactly what path we're thinking is we're assessing all options, both magnitude and path to the market. So we'll be sure to update you guys more when we have more of a plan.
Our next question comes from the line of John Royall with JPMorgan. .
I was just hoping for your updated thoughts on acquisitions. You've been pretty vocal about looking at acquisitions. One of the big assets that we knew publicly was out there was Citgo, which is now sold to another party. So how do you view the opportunity set today with that asset now off the market? And does the need to preserve liquidity today, but any inorganic growth ambitions on hold for now? .
Well, as I mentioned in the prepared remarks, we're not going to turn down any accretive deals that come up. Right now, we don't really have any in the pipeline with the Citgo situation. But we continue to look at the market for any opportunities that can improve our portfolio as such to diversify it. You can tell when we have 2 refineries, we have problems at both, it really hits the quarter hard. And that's really our strategy is try to diversify around that. But I don't know that our current situation precludes us from looking at anything in the future, and we'll continue to look at that. .
Okay. And then my next question is maybe just a little housekeeping on the hedge program. What should we expect in 4Q in terms of hedging, any positive or negative impact as it looks today? .
Yes. So in terms of our crack swap hedging, if you recall, we predominantly closed that out in the second quarter, recognized a realized gain. Those will roll off through the fourth quarter and through 2025, and you'll see the flip between realized and unrealized. But other than that, no significant plan to do any other material hedging at this time. .
Our next question comes from the line of Manav Gupta with UBS.
I just wanted to focus a little bit on the refining macro. You kind of made a number of comments, you did say we will need more refining capacity closures. You also said the margins could be below mid-cycle in 2025. So I'm just trying to figure out like how does this recovery eventually, as you also said, will happen, happen, like, I mean, much capacity do you think globally needs to come in, some in U.S. and maybe some outside, do you think some Mid-Con capacity needs to shutdown? But I'm just trying to understand the path to back to mid-cycle margins, what will it take to get there?
Well, I think I'd characterize the market right now, Manav, is oversupplied. It's not a demand problem as such. At least demand in the Mid-Con is as strong as it's ever been, even after COVID, it was -- it hasn't really moved much. As far as the United States go, as in general, demand is back fairly normal to a 5-year level, almost. Diesel may be a little bit behind, but not much.
So I don't think it's a demand question. It's really a supply question, and there's just some of the refining capacity that shut down during COVID, has been added back. Lyondell is supposedly shutting down at the end of this year, but we'll see if that happens. It hasn't happened yet. And you look at an announced project in California, the shutdown of LA refinery.
But I think in general, we've almost added back as much as we shut down during COVID. And frankly, there's penetration of EVs as it continues to accelerate. The efficiency of the overall fleet, therefore, is improving. So even though vehicle models traveled are up, it still looks like efficiency is keeping demand at about at the same level.
So I think there are still some topping units that are running as evidenced by the diesel crack where it is today. And that probably -- those are probably European assets as such. And then there's just new capacity additions that have come in and a couple of new announced Chinese refineries that are going to be built in 3 or 4 years that will further impact the market.
The good news is there's still growth in the market worldwide. I don't know how that will divide up among the various regions, but I would guess that the U.S. will continue to see continued pressure from EVs and substitution in the LNG phase because if you look at the gap between crude oil and LNG, it's huge. And there's plenty of incentive to convert engines to LNG and other things on the industrial fleet. So it's going to take either grow our way out of it or additional shutdowns to occur.
Our next question comes from the line of Paul Cheng with Scotiabank. .
Dane, maybe I missed it, did you mentioned what is the 2025 CapEx? If not, could you give us a rough estimate? And I think that will be included in cost of view on the major turnaround. How many days is the turnaround going to be and whether it's all going to be in the first quarter, in the current plan or that is going to spill in the second quarter? That's the first question. .
Paul, it will cross over both quarters slightly. We'll start in late February, and it's approximately 45 days of oil-to-oil. But it will cross over into first and second quarter, just slightly.
Okay. And what's the CapEx for next year currently that you have in mind given the market condition? .
Yes, Paul, we typically don't disclose that until later in the year. We are going through our budgeting process and taking a real hard look at the capital in light of Dave's comments about focusing on spend in flight and focusing only on growth projects or projects critical to the operations of the refinery in a safe and reliable manner. So we are undergoing that exercise now and we will share the guidance when we have it prepared. .
Then can I ask that what is the minimum you need to spend? I'm not saying that you would just spend the minimum. Just curious, what is the minimum given the major turnaround that you expected for next year?
What is the minimum. I don't know that we've prepared something like that. We have a lot of projects that are in flight that take multiple years to complete. We are not proposing to stop those just because it costs more to stop them then restart them. But that number, I don't have it. Dane, do you?
No.
I don't have it accessible to me. So we can probably look it up, Paul, and we'll get back to you with it. .
That would be great. A second question. I think, Dave, in the past, you have thrown the idea that you could even convert the [indiscernible] plant in Wynnewood back into processing crude oil. One of your peers that down in Alabama that they have just done that. If you do not find a partner to allow you to convert that into FAF, what's the thought process and the time line for you to make a decision whether you want to go the other way? .
Well, I think, Paul, it goes back to the discussion of whether how short we are on rent. And even with a small refinery waiver for Wynnewood, we're still substantially short on rents. What the hydrocracker does in renewable diesel services provide us with a relatively low-cost RINs on the margin since the capital sunk. And I think that's a strategy we're going to continue to play out.
This quarter, we did make money in renewable diesel, and I think with the setup we have and with the pretreater now, we're experiencing good yields. Our biggest issue really is catalyst life, and we continue to explore that. We'll probably take us another year or two to really understand that in full throw. But right now, we're repricing margins are we actually make more money in R&D on a per barrel basis than what we do in refining. So we'll probably stay on that service. .
We have no further questions at this time. I'd like to turn the floor back over to management for closing comments. .
Thank you all for joining our earnings call and your interest in CVR. Additionally, we'd like to thank our employees for their hard work and commitment towards safe, reliable and environmentally responsible operations. And we look forward to reviewing our fourth quarter results with you on the next earnings call.
Thank you, and have a great day.
Ladies and gentlemen, this does conclude today's teleconference. You may disconnect your lines at this time. Thank you for your participation, and have a wonderful day.