CVR Energy, Inc. (NYSE:CVI) Q2 2023 Earnings Call Transcript

CVR Energy, Inc. (NYSE:CVI) Q2 2023 Earnings Call Transcript August 1, 2023

Operator: Greetings, and welcome to the CVR Energy, Inc. Second 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 FP&A and IR. Thank you, Mr. Roberts, you may begin.

Richard Roberts: 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.

Dave Lamp: 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 process. We completed the planned coker turnaround at Coffeyville in early April, and we are 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 cracks. 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, EPA continued down their ridiculous and misguided path once again, denied petitions for small refinery waivers — small refinery exemptions, including Wynnewood’s petition for 2022. We’ve already followed lawsuits and received a stay from the Fifth Circuit related to the denial of the Wynnewood’s small refinery exemption for 2017 through 2021, and we expect to challenge this most recent denial and court very soon. As we have continually 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 our 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.

Dane Neumann : 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 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 $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 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 noncontrolling 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, $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 losses 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.

Dave Lamp : 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 above 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 headed, 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 continue to — continued crude exports at this level supports 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 — our alky 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 years 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 the 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 three months — 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 take — explore — look for — as we look 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 safe, reliable, and environmental, 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.

Q&A Session

Operator: [Operator Instructions]. Our first question is from Matthew Blair with Tudor, Pickering, Holt & Company. Please proceed with your question.

Matthew Blair : 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.

Dave Lamp : Well, the $11 million is correct. That is the 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 [ph] and it’s the front months that are really hitting us pretty hard.

Matthew Blair : 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 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?

Dave Lamp : Sure. Well, I think you’ve heard us talk about the conversion of — and kind of doing what we did at Wynnewood in the past at Coffeyville. We’ve looked at that pretty hard and it really doesn’t pay out. The best option is to build more — I wouldn’t call it greenfield, I call it more brownfield, it would be in proximity to the refinery, there would be some synergies with the refinery. But in any case, all this — the economics are always better when you get scale, as you get bigger. So, we’re looking at not only upsizing it, but building what’s largely practical to ship into Coffeyville itself. is that’s usually limited by rail access, which is vessels no bigger than 14 feet in diameter or something like that. So, I think we’re looking at something much larger than what’s in Wynnewood and the type of partners we’re really looking for are all of the above.

This is a fairly pricey project should we decide to do it. The first levels of activity are really around doing the design, doing a full cost estimate by having the land to put it on, and getting the permit submitted. So, until we have that, we don’t really — we’re pretty wide open on who partners might be. But we have, as we mentioned, have had a lot of conversations with people that are interested in investing in this space and we’ll look to try to monetize our position at Wynnewood with the construction of this joint venture. However, we might structure it.

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

Manav Gupta : 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?

Dave Lamp : Well, as you know, that where the fire occurred was in a gasoline hydrotreater, which basically takes gasoline and treats down the sulfur to meet Tier 3 specs. We’ve been running that unit for quite a long time and at both Coffeyville and Wynnewood wouldn’t have generated significant credits. We monetize some of those credits during this time. And those — all those credits are on our balance sheet at zero value. So, you didn’t see much impact on the financials. We are hurt a little bit because we — those are credits we could have sold, which right now are selling around $2,500 per credit, and we could have sold those in the future. So, it did impact us in some ways. However, even though the fire did cause a disruption for a short period of time, we were pretty well able to catch that back up.

I will remind you, too, that we finished up the coker turnaround at Coffeyville towards the beginning of the first quarter, but it did impact our rates as we had high inventories that we had to run off until we got those inventories back in control, we weren’t at full crude rate at Coffeyville either.

Manav Gupta : 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?

Dave Lamp : Well, as you know, we restructured our company to break out renewables as a separate company ultimately with the idea that we could spend that if we build the scale that we think we can do. So, I think what we’re looking really at is some type of partnership with probably multiple parties because of the size of this company would be probably 600 million, 700 million, gallons a year of renewable diesel and probably half of that, SAF. So, it’s a sizable venture and a decent market cap. So, we think it — it has the potential to be a stand-alone company. And this is precisely why we did the restructuring. This will allow us to pursue this type of activity. So, I think we want strategic, we want financial. We want all types.

We’d love somebody to come in and has the ability to sort of help us source feed, advantage speed. We think Coffeyville is a really good location to build something like this because it’s right in the ag belt and its close proximity to a lot of ethanol plants, which as you know, corn oil is a fairly low CI material that would allow us to capture BTC on any kind of SAF we might make, enhanced BTC, I’ll say. So, we’re — it’s still really early, but it’s wide open, and we’ll just be exploring what all the alternatives are.

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

John Royall : 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 100% payout type policy?

Dave Lamp : Well, I think we’ve told you our whole drive here is to maintain attractive investment profile by focusing on free cash flow generation and cash returns to our shareholders. That is — that’s every day in our DNA. And we really are targeting above-average cash returns to shareholders and unitholders, and we look at repurchasing stock units, buying down debt, all the options every quarter. And we only do those when they’re value-added and where our stock price where it is today, stock buybacks don’t make any sense to us. And the debt buyback is — we don’t have anything pressing us immediately, but that will be on our equation going forward. As far as the cracks go, I would tell you, if you look back five years back to 2018, which was a pretty good year for refining.

The gas crack was around $14 on a RIN-adjusted basis, it was around $12. Today, we’re looking at $27 on an unadjusted basis, and $19 on an adjusted basis. Diesel back in ’18 on an unadjusted RIN basis was almost $23, today, it’s $37. Adjusted on for RINs is $21, and $29, almost $30. So, they’re fairly remarkable. They’re not quite as — diesel is a little less than what it was in ’22 but gasoline is very much stronger than what ’22 was. So I would still tell you, they’re pretty remarkable, at least in my experience of 40 years in this business. So, when we have the cash, we’re going to — every quarter, the Board looks at all the options, and decide where to put. If we don’t have good investments or something that is a high return, it’s going to go back to shareholders.

And that’s exactly what we did this time.

John Royall : 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?

Dane Neumann : 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.

John Royall : Thank you.

Dane Neumann : Good.

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

Neil Mehta: 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.

Dave Lamp : Sure. Well, I think we had the very — if you look at demand on the Magellan system, it basically hasn’t changed much at all. Even though when I mentioned the U.S. is down a bit on diesel. You can’t see it at all in the Mid-Con. And actually, we had the basis blew out a little bit into a negative point in the quarter, but that has since come back to positive numbers versus the New York Harbor. And what happens then is typically the ARB opens between Gulf Coast and Mid-Con, and barrels come up the pipeline to meet us. They’ve been hesitant to do that a little bit just because of the backwardation in the market. Products have been severely backwardated, and that adds a lot of risks when you have seven days of shipping time.

So, that’s been limited. So, the margins have been very good in the group. And the premium has been even better than that. Numbers somewhere, I think we averaged in the second quarter, let me see it, about $0.41 premium to regular. So, really no trouble moving barrels, no trouble at all making as much premium as we can. And really, it’s been a very open market for any kind of production increases we could make. Sorry, I forgot the rest of your question.

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

Dave Lamp : Yes. On Brent-TI, I think we’re — we’ve always said that shale oil, what makes drives that number. And in our area, actual shale production is up several of the E&P companies have hit pretty big-sized wells, and did some farming activities that they’re still coming on and – so, you can see it in our pipeline rate, we’re up to 145,000 barrels which we were — during COVID, I think we bottomed it right at 105 somewhere in there. So, it’s still happening. And with $4 million of exports that seem to be hanging in there pretty tight, $4 Brent-TI is necessary to force that of the market off the shore. So, — we still have that point of view that as long as shale oil production is maintaining where it is since the Gulf Coast is mainly heavier crude refiners that all this light crude has to go offshore.

Neil Mehta : And then, Dave, I don’t want to get you animated here, but I do have to ask every quarter about your perspectives on the RINs markets and on RFS. Just sort of your thoughts on how ethanol and biodiesel RINs can evolve here? And what are the next things that we as an investment community should be looking forward to as we kind of see — try to figure out what this means for the refining sector?

Dave Lamp : Well, this does get me fired up, Neil, as you well know. I just feel that the EPA has totally mismanaged this — the whole system for many, many years. And they did it again with the new RVOs that came out, keeping the ethanol mandate above the blend wall, and actually putting pretty small numbers, frankly, for the D4s or the advanced bios. It just seems like a complete mistake to me. What are you trying to encourage here? You’re just trying to keep RIN prices high to make the consumer pay another $0.30 a gallon or what? Frankly, D6 should be cheap, and D4 should be expensive. And if the BTC goes away, I think you’ll see D4s even have to go a lot higher to continue to encourage production of renewable diesel and SAF.

So, it just seems to me it’s — they talk out of both sides of their mouth. Climate change is huge, and we’re going to do everything to do it. But yet, we can’t put an RVO out that encourages more — probably the lowest carbon liquid fuel out there. So, as far as the future, I think — we’ve seen a big surge in our rack volumes, which helps us blend more ethanol and biodiesel, which just means we have less to buy in the open market, and we’re pretty much long D4s with the Wynnewood situation. So, I don’t think our position is bad. If we did something like a big RD plant at Coffeyville, we’d be very long RIN. So, our strategy hasn’t changed. We’re still investing in renewables and minimizing what we invest other than maintain our assets and any value of projects that improve our feedstock supply, improve our capture, or our product placement in the refining side.

Neil Mehta : Yes. It’s definitely less of an issue than it was before for you guys, but understood. Thank you so much.

Dave Lamp : Thanks.

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

Paul Cheng : Thank you. Dave, I have to apologize, first, I came in late so you may already address 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?

Dave Lamp : Well, we haven’t published any numbers on R&D profitability, but we did mention that the second quarter was better than the first quarter, and the first quarter was profitable. So, we continue to ramp up and went through our second catalyst change. PTU comes on in the fourth quarter, and we’re anticipating that will add $0.30, $0.40, and $0.50 to the per-gallon margin. And our long-term view of soybean oil is in the current market, it’s somewhere around $1.50 to $1.70, maybe $1 to $1.70 — actual margin, and that looks to be still true to us.

Paul Cheng : Thank I think — are you currently running this all soybean oil or that you are running some lower CRP stock?

Dave Lamp : 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.

Paul Cheng : All right. And I’m just curious, I mean, a number of years ago that you guys have — pretty active trying to sell the company or looking for a merger partner. Since then that — I think there’s a number of companies, the management has changed in terms of your peers, have you revisit whether that it’s worth so that you can get a better economy of scale in the refining business?

Dave Lamp : Well, you know, I think we looked at all sides of the equation, Paul, as you know, we’ve looked at selling our assets to buying more assets in refining. And we’ve kind of gotten to the point where I don’t think we’re a consolidator. We’re — but we could be a consolidate — but anything future-wise, we’re really focused on renewables in some form or fashion. And any other thing that could be a carbon reduction in the field. I’ll tell you that’s a pretty tough growing. There just aren’t a lot of really great opportunities out there even with the IRA. The problem with it is it’s — at last 10 years, 12 years, and then what you’re left with uncompetitive assets compared to fossil fuels. So, it’s difficult to make that kind of investment when you’ve got that short horizon. And it takes you three to four years to build anything.

Paul Cheng : Earlier that I’m trying to make sure I heard you say that at today’s share price buyback doesn’t make sense to you? So, when you — when the Board and you and the management decide whether you want to go for buyback or special dividend? And maybe then on the buyback, what kind of metrics that you guys are using to determine whether you should go for a buyback or special dividend?

Dave Lamp : Well, I think it’s not that complicated, Paul. It’s really if the share price is cheap, buybacks make a lot of sense. But at $35 where we’re at today, we’re maybe a little higher than that now, but that’s more difficult for us to see how that’s accretive in the long haul. And I just — share buybacks to reduce the number of shares, but that’s about.

Paul Cheng : Okay. A final one for me. Do you have excess cash and 1 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 how 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.

Dane Neumann : 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.

Paul Cheng : All right, thank you.

Dane Neumann : Thank you.

Operator: 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.

Dave Lamp : 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.

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