Greetings, and welcome to the CVR Energy, Inc. Second Quarter 2023 Conference Call. 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 IR. Thank you, Mr. Roberts, you may begin.

Thank you, Camilla. Good afternoon, everyone. We very much appreciate you joining us this afternoon for our CVR Energy Second Quarter 2023 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 2023 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 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 2023 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 Dave.

Thank you, Richard. Good afternoon, everyone, and thank you for joining our earnings call. Yesterday, we reported second quarter consolidated net income of $168 million and earnings per share of $1.29. EBITDA for the quarter was $300 million. Our solid results for the quarter were driven by continued strength in gasoline and diesel crack spreads. We are pleased to announce that the Board of Directors has authorized a special dividend of $1 per share. This is in addition to the regular second quarter dividend of $0.50 per share, both of which will be paid on August 21 to shareholders of record at the close of the market on August 14. Our annualized dividend yield, excluding special dividends, is approximately 5.5%, based on yesterday's closing price, and remains best-in-class among the independent refiners. In our Petroleum segment, combined total throughput for the second quarter of 2023 was approximately 201,000 barrels per day and light product yield was 100% on crude oil processed. We completed the planned coker turnaround at Coffeyville in early April, and we currently do not have any additional turnarounds planned for the remainder of the year. Although we experienced a fire at the gasoline hydrotreater at Wynnewood during the quarter, the impact to operations at the plant was minimal, and we were able to run the refinery without a hydrotreater in operation by consuming solver credits. We expect to have the hydrotreater repaired and back in service in the next week. Benchmark crack spreads remained elevated during the second quarter with Group 3 2-1-1 averaging $32.33 per barrel. RIN prices declined slightly from the first quarter but remained stubbornly high at over $7 per barrel. Last month, the EPA continued down their misguided path once again, denying petitions for small refinery waivers, including Wynnewood's petition for 2022. We've already filed lawsuits and received a stay from the Fifth Circuit related to the denial of Wynnewood's small refinery exemption for 2017 through 2021, and we expect to challenge this most recent denial in court very soon. As we have continuously stated, the RFS regulation was written specifically to protect small refineries like Wynnewood from disproportionate economic harm caused by the RFS regulation, and we will continue to fight for the rights that we believe Wynnewood is entitled to. We completed a second catalyst change at the Wynnewood renewable diesel unit in April, and we processed approximately 18 million gallons of vegetable oil feedstock in the second quarter. We also switched catalyst providers with the most recent change, and so far, we are seeing an increase in renewable diesel yields. The HOBO spread improved slightly from the first quarter, and despite the lower throughput volumes, we once again saw improved results relative to the previous quarter. As a reminder, our renewable diesel business is currently reported in our Corporate and Other segment. In the Fertilizer segment, both facilities ran well during the quarter with a consolidated ammonia utilization rate of 100%. Fertilizer prices continued to decline during the second quarter, although we sold more than 40% of our second quarter volume in the first quarter at higher prices. We recently completed both the summer fill and fall prepay ammonia ordering from customers. We have a good order book heading into the fall. Now let me turn the call over to Dane to discuss our financial highlights.

Thank you, Dave, and good afternoon, everyone. For the second quarter of 2023, our consolidated net income was $168 million, earnings per share was $1.29, and EBITDA was $300 million. Our second quarter results included an unfavorable inventory valuation impact of $26 million, unrealized derivative losses of $19 million, and a negative mark-to-market on our estimated outstanding RIN obligation of $2 million. Excluding the above-mentioned items, adjusted EBITDA for the quarter was $347 million, and adjusted earnings per share was $1.64. Adjusted EBITDA in the Petroleum segment was $258 million for the second quarter, driven by strong product cracks in the Mid-Con. Our second quarter realized margin adjusted for inventory valuation, unrealized derivative losses, and RIN mark-to-market impacts was $20.27 per barrel, representing a 63% capture rate on the Group 3 2-1-1 benchmark. RINs expense for the quarter, excluding the mark-to-market impact, was $88 million or $4.85 per barrel, which negatively impacted our capture rate for the quarter by approximately 15%. The estimated accrued RFS obligation on the balance sheet was $599 million at June 30, representing a $373 million RINs mark-to-market at an average price of $1.61. As a reminder, our estimated outstanding RIN obligation excludes the impact of any small refinery exemptions. Direct operating expenses in the Petroleum segment were $5.46 per barrel for the second quarter compared to $6.12 per barrel in the second quarter of 2022. The decrease in direct operating expenses was primarily due to lower natural gas and electricity prices, somewhat offset by higher repair and maintenance expenses. Adjusted EBITDA in the Fertilizer segment was $87 million for the second quarter with strong production for the quarter, somewhat offsetting the decline in nitrogen fertilizer prices relative to the second quarter of 2022. The partnership declared a distribution of $4.14 per common unit for the second quarter of 2023. CVR Energy owns approximately 37% of CVR Partners common units and will receive a proportionate cash distribution of approximately $16 million. Cash provided by operations for the second quarter of 2023 was $367 million, and free cash flow was $271 million. Significant uses of cash in the quarter included $97 million of capital and turnaround spending, $70 million paid for the non-controlling interest portion of the CVR Partners' first quarter distribution, $54 million paid for cash taxes and interest, and $50 million paid for the CVI first quarter dividend. Total consolidated capital spending was $48 million, which included $22 million in the Petroleum segment, $6 million in the Fertilizer segment, and $18 million on the pretreatment unit for the RDU. Turnaround spending in the second quarter was $11 million. For the full year 2023, we estimate total consolidated capital spending to be approximately $200 million to $225 million and turnaround spending to be approximately $55 million to $65 million. Turning to the balance sheet, we ended the quarter with a consolidated cash balance of $751 million, which includes $69 million of cash in the Fertilizer segment. Total liquidity as of June 30, excluding CVR Partners, was approximately $937 million, which was comprised primarily of $682 million of cash and availability under the ABL facility of $255 million. In light of our upcoming senior note maturity in 2025, we are currently intending to hold higher levels of cash on the balance sheet in order to offset the potential for a growing RIN liability as we await the outcome of the lawsuits related to Wynnewood's small refinery exemptions. Looking ahead to the third quarter of 2023, 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 $95 million and $105 million, and total capital spending to be between $45 million and $49 million. For the Fertilizer segment, we estimate our third quarter 2023 ammonia utilization rate to be between 95% and 100%, direct operating expenses to be approximately $50 million to $55 million, excluding inventory impacts, and total capital spending to be between $14 million and $16 million. For renewables, we estimate third quarter 2023 total throughput to be approximately 17 million to 22 million gallons, direct operating expenses to be between $6 million and $8 million, and total capital spending to be between $23 million and $25 million. With that, Dave, I'll turn the call back over to you.

Thanks, Dane. In summary, we had another strong quarter with solid contributions from both the Refining and Fertilizer segments. We saw another quarter of improved results with the renewable diesel business as well. As we look at the underlying fundamentals driving our business, we are optimistic about the near-term outlook, and we are pleased to be paying another special dividend to our shareholders. Starting with the Refining, crack spreads remained elevated in the second quarter of 2023, with the increase in gas cracks during the quarter nearly offsetting the decline in distillate cracks. Refined product inventories remain at or below five-year range at or below the low end of five-year ranges, demonstrating the impact of reduced refining capacity in the U.S. and the heavy turnaround activity of unplanned outages in the first half of the year. Product inventories have also benefited from continued strong exports of gasoline and diesel out of the United States, which have averaged over 2 million barrels per day in the first half of 2023. Gasoline demand in the U.S. has been trending above 2022 levels since March. Although diesel demand has been lower for most of the year by about 5% on average. Slowing diesel demand has been one of the primary areas of concern in the market with freight, rail, and truck movements all down this year. Although freight rates have started to increase recently. The other item we continue to watch is the start-up of new refining capacity around the world and the impact that may have on exports of refined products out of the U.S. On our last earnings call, I highlighted the hedging program that we entered into earlier this year, which generated a realized gain of over $11 million in the second quarter. For the second half of 2023, we have approximately 20% of our expected gasoline and diesel production volumes hedged, and for '24, we have approximately 15% hedged. On the crude side of the equation, commercial inventories have moved above the five-year average levels, which can also be partially attributed to elevated turnaround activity in the first half of '23. Heavy crude spreads remained narrow, and we've been running very little WCS at Coffeyville as a result. Shale oil production in the United States continues to grow slowly and our gathered volumes increased in the second quarter, averaging over 145,000 barrels per day. Crude oil exports out of the U.S. have been averaging around 4 million barrels per day, and we believe continued crude exports at this level support a sustained Brent-TI spread. We continue to make progress on some of the refining projects we have discussed in previous calls. We have received a permit for the project to replace HF acid with a solid catalyst in the Alky unit at the Wynnewood refinery, with an expected completion in 2026. This change will increase our alkylation capacity by 2,500 barrels per day as well. We are also continuing to progress our diesel yield improvement projects, which we believe could increase our distillate yield from the two refineries by approximately 6,000 barrels per day within two or three years. This would increase our total distillate yield from approximately 43% today to over 46%. Turning to the fertilizer segment, nitrogen fertilizer prices declined further in the second quarter in part due to the significant decline in natural gas prices in Europe, Asia, and the U.S. We believe customer inventories are now at the lowest levels in recent years, and we will need to be replenished over the coming months. In July, we completed both the summer UAN fill and the fall prepay ammonia ordering from customers. With the reset in prices, we saw a strong demand for our products and believe we have seen the recent bottom pricing in UAN and ammonia. In June, we announced that we concluded our evaluation of potential transaction to spin off our GP and LP interest in CVR Partners, and the Board decided not to pursue the transaction at this time. Ultimately, the Board concluded the complexity associated with the transaction may not deliver appropriate value under the current conditions. We will continue to explore ways to capitalize on unique assets of CVR Energy and CVR Partners. Finally, in renewables, construction on the PTU is progressing. However, delays in the equipment delivery of equipment have shifted the expected in-service date to the fourth quarter of 2023. Over the past few months, we have had preliminary discussions with various parties that may be potentially interested in partnering on a renewable diesel project with an option for SAF production at our Coffeyville location. We are currently contemplating a significantly larger facility at Coffeyville than we had at Wynnewood as we look for ways to explore the potential of taking advantage of the economies of scale. We would also like to be able to utilize some of the existing infrastructure at the refinery. Discussions are still in the preliminary phase at this point, but so far, we have received initial interest from a variety of partners. I look forward to providing additional details as we progress these discussions. Looking at the third quarter of 2023, quarter-to-date metrics are as follows: Group 2-1-1 cracks have averaged $34.51 per barrel, with the Brent-TI spread of $4.32 and a Midland differential at $1.50 over WTI. From fertilizer prices are approximately $450 per ton, and UAN is $250 per ton. As of yesterday, Group 3 2-1-1 cracks were $43.08 per barrel. Brent-TI was $3.76 per barrel. WCS was $15.65 under WTI, and RINs were approximately $7.84 per barrel. We continue to strive to operate our plants in a safe, reliable, and environmentally responsible manner and to explore opportunities to grow our renewables business. We continue to focus on maximizing free cash flow, which underpins our peer-leading dividend yield. With that, operator, we're ready for questions.

Our first question comes from Matthew Blair with Tudor, Pickering, Holt & Company. Please go ahead with your question.

Hi, Dave. Thanks for taking my question. Congrats on the strong results. I want to circle back to your comments on the product crack hedges. Did I hear you correctly that the realized gain was only $11 million in the quarter? We thought it was probably looking to be a little bit higher. And I guess if you mark that portfolio today, do you have a sense on whether Q3 would have a similar gain or maybe something a little bit higher? Thank you.

Well, the $11 million is correct. That is directly from our crack hedges. We had some other hedging activities that increased that number a bit, but around crude and other products. But right now, if you look at the portfolio we have, we're mostly underwater in the third quarter at this point. That has a way of shifting though. Some of the cracks we have in '24 are still above water. But in general, the market, as you know, is really heavily backwardated and it's the front months that are really hitting us pretty hard.

Okay. Makes sense. And then on the potential Coffeyville RD project, I appreciate that you're still in the early stages here. But I guess, do you have any more details you can share on the potential size of the project, both in terms of the capacity as well as CapEx? And to clarify, would this be a greenfield project? Or would it be a partial conversion of the refinery? And then if you could also maybe just talk about what type of partner you'd be looking for? Would this be more of like a financial partner or more of a feedstock partner?

Sure. I think you've heard us talk about the conversion and what we did at Wynnewood in the past at Coffeyville. We've examined that closely, and it really doesn't yield a good return. The best option is to expand, which I would refer to as brownfield rather than greenfield. It would be near the refinery, allowing for some synergies with it. Overall, the economics improve with scale as we grow. We're considering not only increasing the size but also creating something that can be efficiently transported to Coffeyville itself. This is generally limited by rail access, typically for vessels no larger than 14 feet in diameter. Therefore, we're contemplating something significantly larger than what's at Wynnewood, and the type of partners we are looking for encompasses a wide range. This is a costly project if we decide to pursue it. The initial steps will focus on design, full cost estimates, securing land, and submitting permits. Until those aspects are in place, we're open about potential partners. However, we've had numerous discussions with individuals interested in investing in this sector, and we aim to leverage our position at Wynnewood through this joint venture, in whatever structure we decide.

Our next question is from Manav Gupta with UBS. Please proceed with your question.

Good morning, guys. Very strong refining results. If one didn't know that there was an outage at the gasoline hydrotreater, there's no way the results would tell you that. So, help us understand because we do know there was some kind of outage how you manage so well around this outage? And if it had not happened, would the results — would have been actually even better than what we saw yesterday?

The fire occurred in a gasoline hydrotreater, which processes gasoline to reduce sulfur levels to meet Tier 3 specifications. We have operated that unit for a considerable time and at both Coffeyville and Wynnewood, it hasn't generated significant credits. We did monetize some of those credits during this period, but all credits are recorded on our balance sheet at zero value. Consequently, there wasn't much impact on the financials. We were slightly affected because we missed the opportunity to sell those credits, which are currently valued around $2,500 each and could have been sold in the future. So, while the fire caused a short-term disruption, we managed to recover fairly quickly. Additionally, we completed the coker turnaround at Coffeyville at the beginning of the first quarter, which impacted our rates as we had to reduce high inventories until they were back under control; we weren't operating at full crude rates at Coffeyville either.

Perfect. I just have a quick follow-up. As you mentioned, you're looking at various partner options, and I understand at this point you're limited in what you can say, but would you prefer a single partner who comes in for both the refining assets? Or are you actually looking for different partners for the two different assets that would potentially be RD units?

We have restructured our company to separate renewables into its own entity, with the vision of scaling up our operations. We are considering partnerships with multiple parties due to the size of this venture, which involves producing around 600 to 700 million gallons a year of renewable diesel and approximately half of that in sustainable aviation fuel. This represents a significant market opportunity, and we believe it could function as an independent company, which is why we made the restructuring move. We aim to attract strategic and financial partners who can assist us in sourcing feed and increasing our operational efficiency. The Coffeyville location is particularly advantageous because of its proximity to the agricultural sector and ethanol plants, making it easier to obtain low carbon intensity materials like corn oil, which would help us capture tax credits on any SAF produced. While we are still in the early stages, we are open to exploring all available options.

Our next question is from John Royall with JPMorgan. Please proceed with your question.

Hi, good afternoon. Thanks for taking my question. So just on the special dividend, I think I've asked on the past couple of calls, and Dave, you've talked about needing to see kind of a remarkable environment to do specials going forward. And perhaps we're in a remarkable environment right now, particularly with July gasoline cracks where they were. Is that still the bar only paying out in very strong environments? Or are you shifting policy more towards maybe something like a 100% payout type policy?

I believe our main focus is to maintain an attractive investment profile by prioritizing free cash flow generation and delivering cash returns to our shareholders. This approach is integral to our identity. We aim for above-average cash returns for both shareholders and unitholders and evaluate stock repurchases, debt repayment, and other options each quarter. We only pursue these options when they add value, and given our current stock price, stock buybacks do not make sense at this time. We don't have immediate debt buyback pressures, but that will be a consideration moving forward. Regarding the cracks, if we look back to 2018, a strong year for refining, the gasoline crack was around $14 on a RIN-adjusted basis and about $12 overall. Currently, we are seeing $27 on an unadjusted basis and $19 adjusted. For diesel, in '18 it was nearly $23 on an unadjusted RIN basis, and now it's $37. The adjusted figure is $21, approaching $30. These figures are quite remarkable. While diesel is slightly lower than in 2022, gasoline is significantly stronger than in that year. With 40 years of experience in this industry, I find these results impressive. When we have the cash, our Board reviews all investment options quarterly and decides where to allocate it. If no good investments with high returns are available, we will return cash to shareholders, which is what we did this time.

That's very helpful. Thanks, and then maybe along the same lines. Pro forma for the special, it looks like your cash balance is about $650 million or so. You talked about wanting to hold higher levels from here. Do you have a minimum cash balance that you're thinking of right now with that in mind? And is there any impact from the hedge program on additional cash that you have to hold there?

Yes. I'll grab this one. So, the minimum cash balance will fluctuate just based on commodity pricing levels, heavily focused on crude price. Today, we'd say our minimum cash balance is in the $400 million to $450 million range. And as we talk about holding a little excess cash, the primary driver there is to not allow our RIN short, particularly for Wynnewood to grow much more. So, when we talk excess cash, it's really just that balance that we'd want to cover on any growing short for the '23 position. And the rest after that would become available potential cash.

Thank you.

Good.

Thank you. Our next question is from Neil Mehta with Goldman Sachs. Please proceed with your question.

Yes, good morning, Dane Neumann. Congrats on a great quarter here. The first question is just your thoughts on the Mid-Con market. Obviously, we're seeing strong cracks everywhere, but Mid-Con sometimes can dislocate from Gulf Coast and East Coast. So, just your thoughts as we go through the back half of the year, different considerations, maybe you want to talk about the demand profile, maintenance, and, of course, the spreads between Brent and WTI.

Certainly. When observing demand on the Magellan system, it essentially remains stable. Despite a slight decrease in diesel demand in the U.S., this trend is not reflected in the Mid-Con region. We did experience a temporary dip in the basis, but it has since returned to positive figures compared to the New York Harbor. Typically, this situation leads to an opening of the arbitrage between the Gulf Coast and Mid-Con, allowing barrels to flow through the pipeline. However, there has been some reluctance to do so due to backwardation in the market, which poses risks because of the seven-day shipping time. Thus, this has limited activity. Despite this, the margins in the group have been strong, and the premium has been even better, averaging around $0.41 over regular fuel in the second quarter. There have been no issues with moving barrels or maximizing premiums, and the market remains open for any production increases we could initiate. I apologize for missing the rest of your question.

Just RIN WTI on the crude side as well, but that was great on the product.

Yes. Regarding Brent-TI, we've consistently stated that shale oil is the primary factor influencing that figure. In our area, actual shale production is on the rise. Several exploration and production companies have achieved significant well sizes and are engaged in farming activities that are still being developed. This is reflected in our pipeline rate, which has increased to 145,000 barrels; during COVID, we hit a low of around 105. So, progress is ongoing. With $4 million in exports remaining steady, $4 Brent-TI is essential to push that out into the market offshore. We maintain the perspective that as long as shale oil production continues at its current level, and since the Gulf Coast mainly has refineries for heavier crude, all this light crude will need to be exported.

Dave, I don't want to get you too excited, but I need to ask you once again about your views on the RINs markets and RFS. What are your thoughts on how ethanol and biodiesel RINs might develop? Also, what should the investment community be looking forward to as we try to understand the implications for the refining sector?

Well, this really gets me fired up, Neil, as you know. I believe the EPA has completely mismanaged the system for many years. They did it again with the new RVOs that were released, keeping the ethanol mandate above the blend wall, and setting quite low numbers for the D4s or the advanced bios. It just seems like a major error to me. What are they trying to promote here? Just keeping RIN prices high to make consumers pay an extra $0.30 a gallon? Honestly, D6 should be inexpensive, while D4 should be costly. If the BTC disappears, I think D4s will need to rise significantly to keep encouraging the production of renewable diesel and SAF. It seems to me they're talking inconsistently. Climate change is a significant issue, and we're committed to addressing it. But we can't release an RVO that promotes what is probably the lowest carbon liquid fuel available. Looking ahead, we've seen a substantial increase in our rack volumes, which allows us to blend more ethanol and biodiesel, meaning we have less to purchase in the open market, and we're pretty much well-positioned with D4s given the Wynnewood situation. So, I don't see our position as poor. If we were to undertake a significant RD plant at Coffeyville, we would be very well-positioned with RINs. Our strategy remains unchanged. We're still investing in renewables while minimizing investments elsewhere, aside from maintaining our assets and pursuing projects that enhance our feedstock supply and improve our product placement in refining.

Yes, it's definitely less of an issue than it was before for you guys, but understood. Thank you so much.

Thanks.

Thank you. Our next question is from Paul Cheng with Scotiabank.

Thank you, Dave. I have to apologize, first, I came in late so you may already addressed it; if it is the case, please let me know I will look at the transcript. Have you mentioned or that the is obviously, what is your LD second-quarter profitability, and then also that how you think that's going to trend over the next couple of quarters if we're going to assume the RD margin, say, the indicator is planned?

We haven't released any figures on R&D profitability, but we did note that the second quarter outperformed the first quarter, which was profitable. We are continuing to increase our efforts and have gone through our second catalyst change. The PTU is expected to be implemented in the fourth quarter, and we expect it will contribute $0.30, $0.40, and $0.50 to the per-gallon margin. In terms of soybean oil, we currently view the market to be around $1.50 to $1.70, possibly between $1 and $1.70 for the actual margin, and that assessment still holds true for us.

Thank you. Are you currently running this all soybean oil or that you are running some lower CRP stock?

We do run some corn oil, treated corn oil, but most of it is soybean oil today. We will be shifting to more corn oil as we bring the PTU on.

All right. I'm curious, several years ago you were quite active in exploring the sale of the company or seeking a merger partner. Since then, many of your peers have seen management changes. Have you re-evaluated if it would be beneficial to pursue a strategy that could improve economies of scale in the refining business?

We've examined various options, Paul. We've considered everything from selling our assets to acquiring more within refining. However, we don't see ourselves as consolidators. While future consolidation could be a possibility, our main focus is currently on renewables and initiatives aimed at carbon reduction. The challenge is that there aren't many strong opportunities available, even with the IRA in place. The downside is that investments typically take 10 to 12 years to pay off, leaving us with assets that may not compete well against fossil fuels. This makes it challenging to justify such investments, especially since it usually takes three to four years to develop any project.

Earlier, I wanted to clarify if you mentioned that a buyback doesn’t make sense at today’s share price. When does the Board, along with you and the management, decide between a buyback or a special dividend? Additionally, what metrics do you use to determine whether to pursue a buyback or a special dividend?

It's not overly complicated, Paul. If the share price is low, buybacks can be a wise decision. However, at $35, which is around our current price, it becomes harder to see how that's beneficial in the long term. Share buybacks primarily serve to decrease the number of shares outstanding, but that's the extent of it.

Okay. A final one for me. Do you have excess cash, and one of your peers, that when you have excess cash, they actually get out from the inventory offtake agreement because quite frankly that the inventory offtake agreement basically is just an off-balance sheet financing, and they charge you a fee, and that is pretty high? So, curious that when you're looking at that, you may just sign a new deal on here. Does it make sense for you to get out from that deal or that from that kind of view? Try to manage the inventory yourself, and then you probably will be able to save money. And if your balance sheet is actually strong enough there to be able to do it and have addressed cash.

Yes, Paul, I'll take this one. We actually did enjoy having the intermediation program in place, having just signed a new agreement. We don't find the cost to be overwhelming by any means, and they help us with a lot of credit management. So, there are other benefits that we enjoy outside of just having to manage our inventory. It is something we've looked at. And again, we'll look at it from time to time. But at this time, we are very happy about where we're headed on the remediation front.

All right, thank you.

Thank you.

We have reached the end of our question-and-answer session. I would like to turn the floor back over to management for closing comments.

I'd like to thank you all for your interest in CVR Energy. Additionally, I'd like to thank our employees for their hard work and commitment to safe, reliable, and environmentally responsible operations. We look forward to reviewing our third quarter 2023 results at our next earnings call. Thank you, and have a great day.

This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation.