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Greetings, and welcome to the CVR Energy, Inc. First Quarter 2023 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 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 first 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 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 2023 first quarter earnings release that we filed with the SEC and 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. Good afternoon, everyone, and thank you for joining our earnings call. Yesterday, we reported first quarter consolidated net income of $259 million and earnings per share of $1.94. EBITDA for the quarter $401 million. Our strong quarter results for the quarter were driven by high gas and diesel cracks in the Refining segment, and record high production volumes in the Fertilizer segment. We are pleased to announce that the Board of Directors has authorized the first quarter dividend of $0.50 per share, which will be paid on May 22nd to shareholders of record on the close of the market on May 15th. Our annualized dividend yield of approximately 7%, based on yesterday’s closing price remains best in class among independent refiners. In our Petroleum segment, combined total throughput for the first quarter of 2023 was approximately 196,000 barrels per day, and light product yield was 100% on crude oil processed. We began the planned coker turnaround at Coffeyville at the end of February, and work was completed in early April. Benchmark cracks remained elevated during the first quarter, with Group 3 2-1-1 averaging $34.16 per barrel. The distillate crack remained above gas crack in the first quarter, although gas cracks have improved significantly recently. While the incentive in the group is still to operate refineries in max distillate mode, we have the ability to swing production from distillate to gasoline by approximately 5% to 10%, if economics dictate. RIN prices declined slightly in the fourth quarter -- from the fourth quarter, but remained stubbornly high at $8 per barrel. On our last earnings call, I highlighted that we filed petitions with the Fifth Circuit seeking judicial review of EPA’s ridiculous and misguided denial of Wynnewood’s small refinery exemptions for 2017 through 2021. I am pleased to announce that the Fifth Circuit recently ruled to stay Wynnewood’s compliance obligation after noting EPA’s June 2022 small refinery exemption denial was likely contrary to the law. Small refineries across the country have filed similar lawsuits with compliance days being granted so far for certain small refineries in the Fifth, Eleventh and DC circuits. As we have stated many times in the past, the RFS regulation was written to protect small refineries like Wynnewood from disproportionate economic harm caused by absurdly high RIN prices, and we will continue to fight for our rights that we believe Wynnewood is entitled to. We continued to increase throughput rates at our Wynnewood renewable diesel unit in the quarter, processing approximately 22 million gallons of vegetable oil feedstock. The HOBO spread improved by approximately $0.30 per gallon from the fourth quarter and the combination of higher throughput volumes and improved HOBO spread drove improved results for the first quarter of 2023 relative to the fourth quarter of 2022. 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 record consolidated ammonia utilization of 105%. Fertilizer prices declined during the first quarter. However, we posted another quarter of strong results since we sold more than half of our first quarter production in the fourth quarter of 2022 before prices began to decline. We continue to expect healthy demand for fertilizer in the planting season due to strong grain prices and farmer economics. Now, let me turn the call over to Dane to discuss our financial highlights.

Thank you, Dave, and good afternoon, everyone. For the first quarter of 2023, our consolidated net income was $259 million, earnings per share was $1.94, and EBITDA was $401 million. Our first quarter results include an unfavorable inventory valuation impact of $20 million, a positive mark-to-market on our estimated outstanding RIN obligation of $56 million, and unrealized derivative gains of $31 million. Excluding the above-mentioned items, adjusted EBITDA for the quarter was $334 million and adjusted earnings per share was $1.44. Adjusted EBITDA in the Petroleum segment was $210 million for the first quarter, driven by strong product cracks in the Mid-Con. Our first quarter realized margin adjusted for inventory valuation, unrealized derivative gains and RIN mark-to-market impacts was $18.99 per barrel, representing a 56% capture rate on the Group 3 2-1-1 benchmark. RIN’s expense for the quarter, excluding the mark-to-market impact was $95 million or $5.36 per barrel, which negatively impacted our capture rate for the quarter by approximately 16%. The estimated accrued RFS obligation on the balance sheet was $582 million at March 31, representing 363 million RINs mark-to-market at an average price of $1.60. As a reminder, our estimated outstanding RIN obligation excludes the impact of any small refinery exemptions. Direct operating expenses in the Petroleum segment were $5.90 per barrel for the first quarter compared to $5.57 per barrel in the first quarter of 2022. The increase in direct operating expenses was primarily due to higher repair and maintenance expenses related to the coker turnaround at Coffeyville, offset somewhat by lower natural gas costs. Adjusted EBITDA in the Fertilizer segment was $124 million for the first quarter, with strong production for the quarter offsetting the decline in nitrogen fertilizer prices relative to the first quarter of 2022. The partnership declared a distribution of $10.43 per common unit for the first quarter of 2023. As CVR Energy owns approximately 37% of CVR Partners common units, we will receive a proportionate cash distribution of approximately $41 million. Cash provided by operations for the first quarter of 2023 was $247 million, and free cash flow was $213 million. Significant uses of cash in the quarter included $98 million of net RIN purchases, $53 million of capital and turnaround spending and $29 million of cash interest, in addition to $70 million paid for the non-controlling interest portion of the CVR Partners’ fourth quarter distribution and $50 million paid for the CVI fourth quarter dividend. Total consolidated capital spending was $59 million, which included $42 million in the Petroleum segment, $4 million in the Fertilizer segment and $12 million on the pretreatment unit for the RDU. Turnaround spending in the first quarter was $40 million. For the full year 2023, we estimate total consolidated capital spending to be approximately $200 million to $226 million and turnaround spending to be approximately $60 million to $65 million. Turning to the balance sheet. We ended the quarter with a consolidated cash balance of $601 million, which includes $121 million of cash in the Fertilizer segment. Total liquidity as of March 31st, excluding CVR Partners, was approximately $734 million, which was comprised primarily of $479 million of cash and availability under the ABL facility of $255 million. Looking ahead to the second quarter of 2023, for our Petroleum segment, we estimate total throughput to be approximately 195,000 to 210,000 barrels per day, direct operating expenses to range between $90 million and $100 million, and total capital spending to be between $35 million and $45 million. For the Fertilizer segment, we estimate our second 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 $7 million and $12 million. For renewables, we estimate second quarter 2023 total throughput to be approximately 15 million to 22 million gallons for the quarter due to planned catalyst change. Direct operating expenses for the second quarter are expected to be between $6 million and $8 million. With that, Dave, I will turn it back over to you.

Thank you, Dane. In summary, we had another strong quarter driven by solid contributions from both, Refining and Fertilizer segments, and we saw improved results in our renewable diesel business as well. As we look at the underlying fundamentals driving our business, we remain cautiously optimistic about the near-term outlook. Starting with Refining, 2023 got off to a strong start, with the highest first quarter average crack spreads in recent history. While high diesel cracks drove much of the strength in the first quarter, diesel has softened somewhat, but this has been somewhat offset by increased gas cracks. Turnaround activities across the industry were high in the first quarter, leading to inventories of refined products in the U.S. to fall below five-year average levels. In the Mid-Con, inventories for gas and diesel are low for this time of year and product liftings have been strong, particularly for diesel with agricultural demand pulling hard during the planting season. Refined products volumes across our racks are up approximately 5% compared to the first quarter of 2022, which allows us to blend additional biofuels and increase our internal RIN generation. Premium gasoline margins averaged $0.36 a gallon in the first quarter, which helps our capture rates as approximately 50% of our gasoline production is premium. Given the elevated crack environment early in the year, the Board authorized a hedging program, allowing us to enter into crack spread swaps for up to 30% of our expected gasoline and diesel production for Q2 through Q4 of 2023 and all of 2024. We began putting these hedges on in early January, and we currently have crack spread swaps locked in for approximately 25% of our 2023 expected production and approximately 7% of our 2024 expected production. We currently are in the money on those hedges, which are partially -- or which was partially reflected in our unrealized dividend -- derivatives gain for the first quarter. On the crude oil side of the equation, inventories increased closer to five-year averages levels, which can also be partially attributed to elevated turnaround activity so far in 2023. Heavy crude spreads are narrowing, which, along with the decline in diesel cracks, have been hurting coker economics recently. Shale oil production in the United States continues to grow slowly, and we have seen our volumes in our gathering systems increase to nearly 140,000 barrels per day in March due to increased drilling activity. Although the Brent-TI differential has narrowed some recently, exports of Midland WTI are continuing at record levels, which we believe should be supportive of the sustained Brent-TI spread. Turning to Fertilizer segment. Nitrogen fertilizer prices declined in the first quarter, in part due to a significant decline in natural gas prices in Europe, Asia and the U.S. Grain prices remain strong and farmer economics are attractive, and this should bode well for nitrogen fertilizer demand in spring. Since the turnarounds completed at both of our facilities in the third quarter of 2022, the plants ran well with high utilization in the first quarter. Over the next two years, we plan to invest some additional capital in the fertilizer plants, intended to further improve their reliability, lower their carbon footprint and prepare for potential capacity expansions in one or both facilities. We are also continuing to evaluate the potential transaction to spin off our GP and LP interests in CVR Partners, and I look forward to providing you additional details at the appropriate time. Finally, in renewables, we continue to ramp up production on the renewable diesel unit at Wynnewood processing over 22 million gallons of feedstock in the first quarter. We are completing our second planned catalyst change, and we are expecting to see significant improvements in renewable diesel yield with this new -- the new catalyst installed. Construction of the PTU is progressing, and we are currently expecting an in-service date to late -- mid to late third quarter of 2023. With the addition of the PTU, we expect to see renewable diesel margin capture improved by approximately 30%. Looking at the second quarter of 2023, quarter-to-date metrics are as follows: Group 3 2-1-1 cracks have averaged $32.32 per barrel, with the Brent-TI spread at $3.96 per barrel and Midland WTI differential at $0.66 per barrel over WTI. The WTL differential has averaged $0.04 per barrel under WTI and the WCS differential has averaged $15.31 under WTI. Prompt fertilizer prices are approximately $500 for ammonia and $300 per ton for UAN. As of yesterday, Group 3 2-1-1 cracks were $25.96, Brent-TI was $3.65 and WCS was $15.09 under WTI. RINs were approximately $1.50 -- excuse me, per barrel were $7.81 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 renewable business. We will continue to focus on maximizing free cash flow, which underpins our peer-leading dividend yield. With that, operator, we’re ready for questions.

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

Congrats on the hedging strategy. Very smart move on your part. Again, would this mean that going ahead for the rest of the year, we would find it difficult to model your capture rate because the hedges you have put in would definitely be in the money and giving you propping up margins as we go along? Would that be the right way to think about it?

I think that’s right, Manav. You don’t know what our strike price was or what we bought them at, but leave it to say that we’re at -- it’s going to affect our results materially in the second quarter and probably the third and fourth.

Perfect. My quick follow-up, Dave, here would be, once your PTU is up and running, and you have this catalyst change also done, should we assume that by the fourth quarter of this year, we see a competitive margin capture out of you -- your system, I don’t know, maybe $0.75 or $1, but whatever that number is. But should we assume your renewable diesel results get lot more competitive with the benchmarks out there once you are done with the catalyst change as well as the PTU coming on line late 3Q?

Yes, I think that’s a good assumption. The PTU should add, as I mentioned, about 30% on our capture rate. Today, we’re running in the low-20s on capture. And we think that will bring us up to 50. The catalyst change itself has two elements to it. Run length, we’re predicting to be probably 2 or 3 times better than what we’ve been getting so far, and it also improves the distillate yield substantially. So, that will move capture up also.

Perfect. Congrats on a good quarter and congrats on the very smart hedging strategy.

Thank you.

Our next question comes from the line of Neil Mehta with Goldman Sachs.

Dave, you’ve got a unique perspective on what’s going on in the industrial economy just given where your assets sit and your higher distillate leverage. I’d just love your perspective on the individual end markets of demand, and where do you see some of the stuff trending?

Well, Neil, I think if you look at the Mid-Con, it’s kind of a little bit different than what the rest of the United States looks like. I mean, we’re at low levels. If you look back five years, we’re very low on inventory on gas, which is extremely unusual this time of the year. So, it tells me demand has been good. And in fact, if you look at it, liftings in the Magellan system are very similar to what they’ve always been, even pre-COVID, post-COVID, all the way through. On distillate, again, distillate has been extremely strong. The basis has been in the teens over the NYMEX for most of the quarter. Sometimes it hit as high as $0.35, which tells me that there was a lot of turnarounds going on and a lot of interruptions in the first quarter from our competitors and other refiners in the system. Even though we had a turnaround that it was -- even though it was a fairly small turnaround, it’s just the coker, we still were cut back on rates and still had a very, very good quarter. I think, in general, trucking volumes are down. I think all the data shows that. From an industrial standpoint, it’s not real strong. I mean,, all the indicators are there that the market is somewhat down on distillate. And that’s the main reason we employed some of the hedges we did just because we saw that coming. And still there’s 2 million barrels of refining capacity around the world that’s about to come on. The U.S. looks to me to be about flat with new start-ups and shutdowns, but it’s the rest of the world that’s -- where the incremental capacity is going to come from. And a lot of those are export refineries. So, it’s -- even though our demand is strong, I think the world is seeing a bit of a slow.

Helpful perspective. The follow-up is, just on the dividend, Dave, it’s been a couple of quarters now where it’s been $0.50 a share, and the implied dividend yield on the stock is now close to 8%. You haven’t been afraid to move that up and down. But just from where you sit, do you feel like the $0.50 dividend a quarter is something that you can sustain in the current market environment?

Well, I think -- I don’t think that will change unless we restructure corporation a little bit. If we do the spin-off, I think we’ll have to look at the dividend again because that’s just the effect of doing the spin-off. But we’re a cash machine. That’s what we’re here for. And we give out either be a regular or special. We don’t do many stock buybacks because we just don’t think that’s really necessarily in the best interest of our shareholders. And we’re going to give it back as dividends or specials.

Our next question comes from the line of John Royall with JPMorgan.

So, maybe just a follow-up on that last discussion on dividends. Maybe you could just give us some updated thoughts on the potential for specials. I think Dave referred to the specials from last year as kind of one-offs on the prior conference call, and correct me if I’m mischaracterizing that. But you did have over $200 million of free cash in 1Q, including the UAN tax payment, and you’ve locked in some hedges in the future. And so any updated thoughts on the propensity to pay out some of that with the special going forward?

Well, I think the specials, as I mentioned before, was really around a unique set of market conditions. I’ve been in this business a long time, and I’ve never seen cracks where they were for a pretty sustained period of time in 2022. And that’s why we did specials. We didn’t think about raising the regular up to that because we didn’t think it was sustainable. And I think the same situation is here. As you know, we’re going to take it quarter by quarter and the Board looks at it very closely. We’re managing cash to levels we think we need to avoid using our revolver unless we absolutely have to. And that’s just the point of view we have. So, specials will come and go there -- if the market is remarkable, and we have the cash on the balance sheet to dividend out, we will.

Great. That’s helpful. And then on the monetization of the tax credits at UAN, how do those work in general? And how do you -- how do they impact future cash flows at UAN in terms of what you’re giving up? And then, following the $19 million payment in 1Q, how should we think about the potential for future payments and timing there?

Yes. I’ll take this one. So really, what we had in place previously was an existing CO2 sales contract with a counterparty. And we ended up contributing that sales contract to a JV with the same counterparty. And as a result, it allows the tax equity investor to claim those credits that we’re receiving for the sequestration activity. So what occurred is the contract was deemed a value of $46 million. We put that as deferred revenue on our balance sheet and recognized an equity method investment of $46 million. The cash receipt of $19 million, it was $18 million net of fees, was really just the first payment in the string of payments we expect to receive associated with the JV. And that payment drew down some of the equity method investment. On a go-forward basis, we will recognize that deferred revenue off our balance sheet into other income for our Fertilizer segment, call it $1 million, $1.5 million each quarter. And there will be periodic payments each quarter as well as opportunity for milestone payments annually. There will be a difference between what’s going through income and what we receive in cash. But obviously, from the CVR Partners’ perspective, they’ll take that into consideration when they are looking at their cash available.

Our next question comes from the line of Matthew Blair with Tudor, Pickering, Holt.

Hey. Good morning. Dave. You mentioned the benefits on premium gasoline rolling through your system. Could you talk about the drivers for these wide octane spreads? And do you think that’s sustainable for the rest of the year?

Well, the group is kind of -- is a little bit unique in terms of premium. It sort of gets real long or gets real short. It’s just happened to be -- been very short in the first quarter. And what usually cures it is a big shipment coming up from the Gulf via Explorer into the back -- into Tulsa in the back of our markets. And that just didn’t happen very much this year. Either they had better export markets or something off the Gulf. And even though they are, but it’s pretty wide that the shipments just didn’t come. So it kind of played into our hand. We have the ability to make quite a bit of premium if the margin is there. And we use our CCR reformers to make that material and it just happened to be available at the time. It could go anywhere from -- I’ve seen as low as $0.07 to all the way to $0.55. In fact, we saw some $0.50 spreads in the first quarter.

Okay. And as a follow-up on that, are you fully compliant on the Tier 3 low sulfur gasoline specs, or are you in the market having to buy those credits?

No, we’re fully compliant. We actually sell some credits occasionally.

Okay. Sounds good. And then, what are your thoughts on this E15 blend waiver for the summer? Do you think that will have a material impact on either gasoline demand or D6 RIN production?

Well, it’s going to make some more D6s, I think, for sure. But you got to remember that only 5% of the convenience stores even offer E15. So, it’s limited in its reach into the market. And I don’t know who buys it for what reason, but the typical discount is $0.02, $0.03. It’s not like it’s a bar burden. And if you include the mileage deduction you get with it, it’s probably a loser for most people. But I don’t expect it to do a whole lot.

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

Dave, I know you’re not going to tell us too much detail on the hedging. But can you tell us that if the gasoline and distillate, both of them being hedged 25% of your future output or that one is being hedged more than the other?

Well, I think we did a combination of all. We did 2-1-1s, we did some distillate, we did some gas. So, it’s a wide variety, just depending on what our strike price was at the time. And I’m really not going to get into all the details of exact volumes.

Okay. And when -- I just want to clarify that when Dane was talking about $95 million of the RIN -- on the RIN cost for the quarter, if that will include the RIN you generate from the RD or that’s excluding the RIN you generate in the RD?

So, Paul, the $95 million is the refinery’s obligation, excluding the RIN from the RD. That’s assuming they’re just buying the RIN from the RD on a like an open market transaction. They still have to be costed for that.

I see. And also that, just clarify that, I mean, in the past, I think you have the shipping history to get about 30,000 barrels per day of the WCS and you just sold most of them at Cushing and one a little bit in the [indiscernible]. Are you still doing that and getting about 30,000 barrels per day, which is included in your results?

Yes. Typically, we’ll get 25 on the Keystone side and 5 on the Spearhead side. But -- and we are -- we’re contracted for 10 on the Spearhead side. But we run it opportunistically. If it’s in the money, we will run it. And of course, we had a coker turnaround in the first quarter. So, we minimized the runs during that period of time. And now it’s basically a push on whether you run it or not just where the spreads are and what we can sell it for in Cushing. So, we’re not running any now. We don’t plan on running through the next month as long as the spread stays where it is.

Right. Final one for me. What’s the sustaining CapEx for the corporation now going forward? And that also, on the renewable, maybe I missed it. Did you tell us that what is the gross margin and the net -- and the pretax income for that operation in the first quarter?

We haven’t been disclosing that until we break it out as a segment, which we plan to do probably at the end of the year or start of next year.

Okay. And how about sustaining CapEx?

Yes. Sustaining CapEx for the corporation, we’d just say, it’s $80 million to $100 million, Paul.

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

Again, 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 towards safety -- safe, reliable and environmentally responsible operations. We look forward to reviewing our second quarter 2023 results during our next earnings call. Have a great day.