Greetings. And welcome to the CVR Energy, Inc. Third Quarter 2023 Conference Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. [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 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 third 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 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 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 except 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 third 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 income of $354 million and earnings per share of $3.51. EBITDA for the quarter was $530 million. Our solid results for the quarter were driven by continued strength in gas and diesel crack spreads, along with significant decline in the price of RINs at the quarter end. We are pleased to announce the Board of Directors has authorized a special dividend of $1.50 per share. This is in addition to the regular dividend, third quarter dividend of $0.50 per share, both of which will be paid on November 20th to shareholders of record at the close of market on November 13th. Our year-to-date declared regular and special dividends total $4 per share, for a total cash return to shareholders of approximately 13%. In our Petroleum segment, combined total throughput for the third quarter of 2023 was approximately 212,000 barrels per day and light product yield was 98% on crude oil processed. Overall, our refineries operated well during the quarter with minimal unplanned downtime. We also completed the repairs to the gasoline hydrotreater at Wynnewood, which was impacted by a fire in the second quarter. Benchmark crack spreads remained elevated during the third quarter with Group 3 2-1-1 averaging $39.10 per barrel. The third quarter average RIN price declined from the second quarter, but remained stubbornly high at over $7 per barrel. As we discussed in previous calls, we have filed lawsuits and received a stay in the Fifth Circuit Court of Appeals related to the denial of Wynnewood small refinery exemptions for 2020 and 2021, and we have recently received a stay for 2022 as well. In early October, we were pleased to have our day in court as…

Thank you, Dave, and good afternoon, everyone. For the third quarter of 2023, our consolidated net income was $354 million, earnings per share was $3.51 and EBITDA was $530 million. Our third quarter results include a reduction to quarterly RINs expense due to a mark-to-market impact on our estimated outstanding RFS obligation of $174 million, a favorable inventory valuation impact of $91 million and unrealized derivative losses of $48 million. Excluding the above-mentioned items, adjusted EBITDA for the quarter was $313 million and adjusted earnings per share was $1.89. Adjusted EBITDA on the Petroleum segment was $281 million for the third quarter, driven by strong product cracks in the Mid-Con. Our third quarter realized margin, adjusted for inventory valuation, unrealized derivative losses and RIN mark-to-market impacts was $20.73 per barrel, representing a 53% capture rate on the Group 3 2-1-1 benchmark. Realized derivative losses of $44 million or $2.28 per barrel, reduced our capture rate by approximately 6%. RINs expense for the quarter, excluding the mark-to-market impact was $90 million or $4.64 per barrel, which negatively impacted our capture rate for the quarter by approximately 12%. The estimated accrued RFS obligation on the balance sheet was $413 million at September 30th, representing $367 million RINs mark-to-market at an average price of $1.12. As a reminder, our estimated outstanding RIN obligation excludes the impact of any small refinery exemptions. Direct operating expenses in the Petroleum segment were $5.39 per barrel for the third quarter, compared to $5.53 per barrel in the third quarter of 2022. The decrease in direct operating expenses was primarily due to lower natural gas and electricity prices and higher throughput volumes, somewhat offset by increased personnel costs, partially related to stock-based compensation expense. Adjusted EBITDA on the Fertilizer segment was $32 million for the third quarter, with…

Thanks, Dane. In summary, we had another solid quarter driven by strong results in our Refining segment, along with a positive contribution from the Fertilizer segment, as well as the Renewable Diesel business. As we look ahead to the fourth quarter and 2024, we are cautious about the near-term outlook given the significant geopolitical risk currently facing the market. Starting with Refining, crack spreads remained elevated in the third quarter of 2023 with gas and diesel cracks both increasing relative to the second quarter. Although U.S. Refining product demand is down in general, gasoline inventories are roughly in line with five-year averages and distillate inventories are over 12% below the five-year average. Reduced Refining capacity in the United States, ongoing turnaround activity and a string of unplanned outages during 2023 have all helped keep refined product inventories in check. Exports of gasoline and diesel have also continued to be strong, consistently averaging over 2 million barrels per day so far in 2023. Gas cracks have recently declined, which is typical for this time of year as demand slows after the summer and supply increases with the RVP change. Distillate cracks sold off early in the third -- in the fourth quarter but rebounded quickly as winter approaches. Container shipments have increased recently for the first time this year, although rail and truck shipments remain lower. The potential for a cold winter in Europe and an increase in natural gas prices continue to present an upside for diesel cracks in the near-term in addition to the significant geopolitical risks we are currently experiencing. As we have discussed in previous earnings calls, we continue to watch the start-up of new Refining capacity around the world, although many of these projects are delayed. Turning to crude oil, shale oil production continues to increase…

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

Hi, guys. My first question is more on the RIN side. Right now, the way you are positioned, what EPA has done is actually benefiting you. We’ve seen that in the RFS revaluation, D4 is dragging D6 down. So, in a way, you are very well positioned for what EPA has done in the near-term. If you look and try and expand your renewable diesel capacity meaningfully from these levels, then, in a way, you are countering what EPA has done for you in terms of the RFS obligations. So, I’m just trying to understand these two balancing forces where a lower RIN is actually good for you, but you do want to grow your Renewable Diesel franchise, in which scenario, you would like to see a higher value of the RIN for a higher margin. So, if you can help us understand those dynamics?

Well, Manav, we’ve always said that, it was important for EPA to disconnect D6s from D4s. And if you really look at, if you’re really attempting to do something about climate change, the Renewable Diesel is the molecule that makes a difference. The ethanol blend of gasoline does really little to do anything to reduce carbon emissions. So, it’s still our position that EPA should have disconnected these two and there’s several legislation moves that are in the works to try to make that happen. But they also should have increased the D4 to more in line with what the industry is building and is planning to come online. So, I think it’s just a misguided program still and something has to break to fix it.

So, in an ideal world, Dave, you would like a D4 obligation to be set like 8 billion or 9 billion versus -- and a D6 to be set at 13 billion, 13.5 billion. That would be the ideal scenario, which you are hoping for, right?

That’s correct.

And SRE is allowed.

Right. And frankly, E15 should be allowed too. So, you can argue whether it’s 13.2 billion on the D6 or it’s something higher like 14 billion, but it certainly isn’t 15 billion, which is above the blend wall. And the demand of gasoline is up in question going forward and EPA has to be flexible with that.

Perfect. My quick follow-up is, you mentioned this in the comment that the gasoline is down seasonally and RV has -- and RVP has increased. So, I’m just trying to understand, in your system, sir, have you seen any real signs of concern of weaker gasoline demand, which could have an impact going ahead or you believe what we are seeing right now is just basically seasonal and some overproduction and should correct itself as we move along next three months or four months?

Well, in our markets, Manav, it’s -- our demand is really and I’ve said this since about three months into the pandemic, our demand really didn’t move much and it still hasn’t. If you look at the seasonal liftings out of the Magellan system, they’re almost right on spot to where they’ve always been, even pre-pandemic. So, I don’t -- I attribute a lot of that to the growth in Oklahoma. Oklahoma City, if you’ve been there recently, is really a growing place. So is Kansas City to some degree. And those are the main markets we serve, Tulsa also. And our liftings at our racks are actually up compared to pre-pandemic. And when I’m talking about U.S. demand, I’m really talking about the whole U.S. and that’s where we’re seeing the main part of the decline.

Thank you so much, sir.

You’re welcome.

Thank you. Our next question comes from the line of Matthew Blair with Tudor, Pickering & Holt. Please proceed with your question.

Hey. Good morning, Dave. On WCS, what do you think is widening out at differentials to that $26.20 (six) [$26.02] that you mentioned? And what’s your outlook next year with the Trans Mountain expansion? What kind of impact do you think that’ll have on this?

Sure. Well, I think seasonally WCS usually softens in the winter a bit. You get more diluent injected into it. But a lot of it was just built -- inventory that built in hardesty and backed up the system to some degree. What’s interesting is Trans Mountain has been delayed, but the cost of that thing and what the tariff’s going to be, it looks like to me that the tariff to go to the Gulf Coast is going to be the same as going to the West Coast and -- or something very close to that. So I don’t know that it’ll have a huge impact other than it does increase the takeaway capacity and does open the spigot for some more projects up there if somebody would invest in them. The second part of your question was?

Oh! I think you touched on it. My follow-up is on the product crack hedges. If I caught that right, I think it was a 6 percentage point headwind to capture in Q3. Should we expect, just kind of based on where the future scriptures are now, should we expect that that impact would probably be less in the fourth quarter just with lower gasoline cracks rolling through?

Yeah. So our open positions are around 15% for the fourth quarter and then about 15% throughout 2024. But it would be a fair assumption if the market holds where it has, that the bulk of the impact is behind us.

Sounds good. Thanks so much.

You’re welcome.

Thank you. Our next question comes on the line of John Royall with JPMorgan. Please proceed with your question.

Hi. Good afternoon. Thanks for taking my questions. So, Dave, you gave an update on the court situation for the Wynnewood SREs, which was very helpful. Do you have a timeline in mind for when you think you could have a final answer there and if you get to the point where you feel like it’s -- you can’t really fight it anymore, do you then start to close out your RIN short?

Well, it’s difficult to always predict what a court will do and this case is no exemption from that. There’s two parts to the case. First is the venue that the court has to decide, which whether it stay in the Fifth Circuit or go to the D.C. Circuit. We think we’re optimistic that they’ll keep it, but you never can be sure. The second part of the case is the merits of the EPA’s argument on denying all small refinery waivers and we feel very good about that piece. The question is how long will it take them to rule and then how will they rule? A lot of times in these cases, they just rule to remand it back to EPA to fix. We really are going to fight to try to get more definition on that, should we win, that limits what EPA can do, because if you look at history, they just kind of invent something new to deny it again and we’re back in court. So it’s very difficult to predict timing, but hopefully before the end of the second quarter next year, we should have a ruling one way or the other at the latest. So then the second part of your question was, would we liquidate? Whatever we do here is going to be a structured settlement, because none of those RINs from the past years are available anymore or will be by that time and somehow it will have to be negotiated what it would be, should we lose. I’m pretty optimistic that we won’t. So that case may never come to be.

Understood. That’s very helpful. Thanks, Dave. And then you got a question on WCS diffs. I just had another differential question. This one’s on Brent WTI, which I think you addressed a little bit last quarter. Specifically, cushioning inventories are meaningfully lower today and I think below five-year ranges. But we haven’t really seen a significant narrowing of Brent WTI. So any color on why you think Brent WTI is where it is and how you think about that going forward would be helpful.

Yeah. I think, I’ve always said that, continued growth in shale oil is important for the Brent TI to maintain its position in this range bound between $3 and $4.50 that we mentioned and it’s really to force the barrel offshore. It requires that kind of differential to make up for shipping and wherever the destination point is to be competitive in the world market. That’s what’s driving it to us. So as shale oil matures and continues to slowly grow, which is probably the best scenario, there’s still plenty of takeaway capacity. We think that bodes well for the Brent TI.

Great. Thank you.

You’re welcome.

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

Again, we’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 towards safe, reliable and environmentally responsible operations. We look forward to reviewing our fourth quarter 2023 results during our next earnings call. Thank you.

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