Greetings, and welcome to the CVR Energy, Inc., Second Quarter 2022 Conference Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. [Operator Instructions] As a reminder, this conference is being recorded. I would now like to turn the conference over to your host, Mr. Richard Roberts, Vice President of FP&A and IR for CVR Energy, Inc. Thank you. You may begin.

Thank you, Melissa. Good afternoon, everyone. We very much appreciate you joining us this afternoon for our CVR Energy second quarter 2022 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 2022 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. Let me also remind you that the CVR Partners completed a 1-for-10 reverse split of its common units on November 23, 2020. Any per unit references made on this call are on a split-adjusted basis. 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 2022 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. Thank you for joining our earnings call. Yesterday, we reported our second quarter consolidated net income of $239 million and earnings per share of $1.64. EBITDA for the quarter was $401 million. Fundamentals in Refining and Fertilizer segment continued to improve during the second quarter. And once again, we posted improved results in both segments on a year-over-year basis, though this was offset by a legal accrual in our corporate segment. We are pleased to announce, in addition to the second quarter regular dividend of $0.40 per share, the Board has also authorized a special dividend of $2.60 per share, both of which will be paid on August 22 to shareholders of record at the close of the market on August 12. At yesterday's closing price, the combined annual dividend of $1.60 per share and the special dividend of $2.60 per share represents a dividend yield of nearly 13%, which is currently the most -- almost 4x the average dividend yield among independent refiners. For our Petroleum segment, the combined total throughput for the second quarter of 2022 was approximately 201,000 barrels per day with Wynnewood completing its planned turnaround on time and on budget in early April. This compares to 217,000 barrels per day in the second quarter of 2021. With the hydrocracker conversion at Wynnewood to renewable diesel service, we expect crude throughput at Wynnewood to be reduced by approximately 5,000 barrels per day going forward. Benchmark cracks increased throughout the quarter. The group 2-1-1 crack spread averaged $48.50 per barrel in the second quarter as compared to $19.15 in the second quarter of 2021. Based on 2021 and 2022 RVO levels that were finalized in June, RIN prices averaged approximately $7.58 per barrel in the second quarter, a decrease of 7% from…

Thank you, Dave, and good afternoon, everyone. For the second quarter of 2022, our consolidated net income was $29 million, earnings per share was $1.64, and EBITDA was $401 million. Our second quarter results include a legal accrual of $79 million, a negative mark-to-market impact on our estimated outstanding RIN obligation of $51 million, unrealized derivative losses of $21 million and favorable inventory valuation impacts of $41 million. Our estimated outstanding RIN obligation is based on the 2020, 2021 and 2022 RVOs that were recently finalized in June and excludes the impacts of any waivers or exemptions. Excluding the above-mentioned items, adjusted EBITDA for the quarter was $511 million and adjusted earnings per share was $2.45. The Petroleum segment's adjusted EBITDA for the second quarter of 2022 was $383 million compared to $18 million for the second quarter of 2021. The year-over-year increase in adjusted EBITDA was driven primarily by increased product cracks and over average RINs prices, offset somewhat by lower throughput volume and realized derivative losses. In the second quarter of 2022, our Petroleum segment's reported refining margin was $26.10 per barrel. Excluding the mark-to-market impact of our estimated outstanding rent obligation of $2.79 per barrel, favorable inventory impacts of $2.02 per barrel and unrealized derivative losses of $1.20 per barrel, our refining margin would have been approximately $28.06 per barrel. On this basis, capture rate for the second quarter of 2022 was 58% compared to 31% in the second quarter of 2021. RINs expense, excluding mark-to-market impacts, reduced our second quarter capture rate by approximately 11% compared to a 31% reduction in the prior period. RINs expense for the second quarter of 2022 was $153 million or $8.34 per barrel of total throughput compared to an expense of $173 million or $8.77 per barrel for the same…

Thank you, Dane. In summary, we are proud of our strong results for the second quarter of 2022 and pleased to be returning $3 per share in dividends to our shareholders. Tight supply and demand fundamentals in both Refining and Fertilizer businesses contributed to the strength in our consolidated results, and we believe the outlook for the near term continues to be favorable for both businesses. Starting with Refining. Domestic and global inventories of crude and refined products remain below five-year average levels, driven by a combination of demand returning to pre-COVID levels and global refining capacity being reduced by approximately 5 million barrels per day. We're starting to see some demand destruction as a result of increased prices, particularly for gasoline, with U.S. vehicle miles traveled travel turned negative in April and May compared to the same periods in '19. More specifically to the Mid-Con, we have seen some tapering in gasoline and distillate demand but both are still comfortably within the five-year average levels. Looking at crude oil, inventories are still on the low side and have been distorted to some degree by the sales from the strategic petroleum reserve. The SBR sales have also distorted inland crude differentials, and we have seen a widening of WCS differentials despite little or no production growth in that area. With crude oil prices comfortably in the $100 barrel per barrel range, we're starting to see more activity in our backyard as evidenced by our increased crude oil gathering rates in the second quarter. We believe at these crude oil prices, we could see further acceleration in drilling activity, although E&P companies continue to gravel with investor calls for capital discipline, along with limited available availability of manpower well services, steel and continuing with general cost inflation. Underinvestment in upstream activities…

[Operator Instructions] Our first question comes from the line of Carly Davenport with Goldman Sachs. Please proceed with your question.

I wanted to just start on the capital return side. As you think about the current macro, can you talk about your priorities from a capital allocation perspective? Is there a preference to continue to look at incremental special dividends from here? Or is there a potential for further growth in the regular dividend or around buybacks?

Sure, Carly. As we've said many times, we're a company that returns cash to the shareholders as soon as we have no better use for it. And I don't think we'll see any change in that strategy as evidenced by our special this time. And I don't know that the Board will continue to select special dividend as the mechanism or increase the regular, but it will be revisited every quarter and decisions will be made around that as we go forward. But bottom line is our commitment is to return cash to shareholders.

Great. And then the follow-up was just around Wynnewood renewable diesel. Can you just give us some color in terms of how the asset has been performing from an operational perspective? What you've learned from starting that up? And then perhaps how the potential extension of the blenders tax credit could impact your future views on incremental renewable fuels plans going forward?

Sure. Well, we've really had no problems making this conversion to renewable diesel from an operating standpoint. Logistics have been more of a challenge for us. Just getting the railroad in tune with our needs to deliver soybean oil and corn oil on a timely basis as well as remove product on a timely basis has been some of our bigger challenges, but we continue to work through those, and they're all coming to be. I think some of the things that have developed in the business ourselves is we have begun to look at sourcing some pretreated feed. That looks very attractive to us. Not only that will happen before our pre-treater is online or potentially before our pre-treaters online. But even with the pre-treater sourcing feedstock doesn't appear to be any concern. We can easily do it. And really, our challenge going forward is really around sourcing more of the lower CI materials and we continue to work that strategy as we go. But overall, it's been a pretty straightforward easy conversion.

Thank you. Our next question comes from the line of Manav Gupta with Credit Suisse. Please proceed with your question.

Congrats on a very good quarter. I just wanted to follow up a little bit on the PTU side. I might be wrong, but I think we were modeling it a little sooner, I think, somewhere around second quarter. So I would like to understand why is it moving? Or if it's moving back a little? And also when we think about this as a reportable segment, should we basically assume that you will report it once the PTU starts then it kind of can become its own reportable segment, if you could just talk about those two things?

Sure. I think we've mentioned our strategy going forward is to maintain our refining assets going forward, but very little investment, except for sustaining capital turnarounds and keeping them a good working order. The reason for breaking out renewables as a business is that's where our future dollars are going should the markets develop. So our plan is to report as a separate segment when appropriate. I don't know that it will be triggered off of the PTU or not. It's more around the restructuring and getting our systems built -- the financial systems built to be able to accomplish that. And that would, at best, would be probably the second quarter of next year, maybe later. As far as the PTU moving back a bit, yes, I think it's just engineering, just some of the supply problems have caught us a bit and moved us to back of the quarter on that. We originally thought we'd be in it in the second quarter. I think it's more likely that it will be in the second half some time -- maybe and towards the end of the second quarter -- the third quarter, somewhere in that time frame that we have -- actually have it up and running.

Perfect. And a quick follow-up here is if you could help us understand your outlook on the brand WTI spread? Is it only a function of SPI releases and other things? Or is it also a function of actual inland volumes starting to grow? If you could just give us a medium- to near-term cycle outlook on the Brent-WTI side?

Sure. Well, I've always said that Brent-TI is very dependent on shale oil production. And Permian is growing nicely. The rest of them are kind of anemic. We are starting to see a little bit in the basin. But if you look at the Bakken, it's pretty flat. The Eagle Ford is fairly flat. Niobrara is fairly flat. DJ is fairly flat. So I think we're in the early throes of that starting to happen. But until rig count continues to grow, I think the strategic petroleum reserve releases are probably influencing the Brent-TI as much as anything. But we're optimistic that as shale all grows that -- and there's still plenty of takeaway capacity that the Brent-TI will widen to force barrel's offshore because once again, the ability of the U.S. fleet to run light Midland type crudes is very limited and basically full.

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

So could you give a little more color on the near-term fundamentals in the Fertilizer business? I know it was a difficult planting season this year and there's also been this decision by the ITC to waive certain tariffs. So just looking for an update on how you think about the back half shaping up, and I know you'll be impacted by turnarounds there, but just more on the fundamental picture over the near term?

Well, I think the prices are still very, very strong even at levels they're at today. I don't think there's anything that's going to -- that I can see is going to change that. The tariff situation was a disappointment. But frankly, it's not the driver of the market right now. It's all natural gas in Europe and pricing there. A good number of the plants there are shut down because of high natural gas prices. They're actually importing ammonia to run their upgraders, and that's really about all they're doing. And I don't see that situation changing. In fact, we just had another big uptick in natural gas prices approaching $60 a million BTUs. That puts ammonia at $1,800, almost $2,000 a ton. So those fundamentals are very, very strong and probably are not going to change in the short term unless there's a resolution to the Ukraine or and Russia stops its activities with maintenance and other things designed to start Europe from natural gas. So, we're very bullish on fertilizer prices and demand.

Great. That's really helpful. And then just switching over to the side, you spoke a little bit on the fundamentals there. But is there any update you can provide on how you're thinking about the potential conversion of the hydro treater at Coffeyville? I think last quarter you were sort of characterizing it as somewhat of a wait and see. There has been some kind of new slow since then. We have the national LCFS program in Canada is starting next year, potential for renewal of the BTC. So just any update on kind of how you're thinking about that project?

Yes. I think we're still -- this is probably a $650 million project. So it's a big one for us, and it's -- we really need to see some other states opt into renewables in a carbon fuel standard or frankly, a pivot of the RFS, which -- with the reset coming up, that could happen and RFS pivot towards a low carbon fuel standard. And those would move it. As far as the BTC goes, all we get is extensions, two years, two years, one year. That's hard to plan a business around when you have that level of uncertainty. All that said, I think our desire is we have a project that's scoped and ready, and we'll be able to pull the trigger when that -- when we feel that timing is right. I don't think it's there yet.

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

The reporting showed, I believe, 6,000 barrel WCS runs in the second quarter at your refinery. But are you still piping down extra WCS barrels and reselling them at Cushing and getting the economics there? And if so, could you remind us on the volume?

Sure. We have pipelines based on paper of 35,000 barrels per day, were usually restricted or have been in the past to about 30,000 of delivery. So, when that arb is open, we'll not only meet our own needs and we're limited to about 12,000 barrels a day at our Coffeyville refinery on runs, but we'll sell the rest in Cushing. And frankly, we're looking at other alternatives to sell it on the Gulf Coast also. But generally, we sell in Cushing today. And that is typically whatever is left from what we don't run at our Coffeyville refinery. And that market is pretty liquid and we pretty much are always in the money on it. Our cost to deliver from Canada is about $6 -- a little over $6. And typically, we're making money on those sales.

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

Maybe that I missed it. Dane, can you just remind us that how much is the -- on the balance sheet for the obligation that you need to settle for this year and next year?

Yes, Paul, the total obligation on our balance sheet as of the end of the quarter was $708 million, and that's for all 2020, 2021 and 2022 open positions.

And so those of next year, right, -- this year, that has nothing to set up?

Yes.

No, I'm saying that that entire amount, it is 2020 -- 2021 and '22. So Dane, the deadline for the settlement is next year between the first quarter and the third quarter. So this year, you're not going to have any cash settlement on the balance sheet -- related to the balance sheet obligation?

Yes.

And then when you say $708 million or 708 million RIN?

That is dollars.

Okay. And that just curious that, Dave, with the diesel crack way we are, is it the battle for you that to run the going to run the conventional oil? Or that -- I mean that why that you were still wondering for the out even though it may be a positive contribution at this point, but I would imagine it's going to be far more positive contribution if you run the conventional oils? How quickly you can?

Well, Paul, I think as we've said, we get the choice to make the decision every time we do a catalyst change. And we made the decision to convert the RD. And I think it's been a good one even with the cracks where they are, I can argue the opportunity cost was pre-hiring that period of time. But the incentive to run RD has not been bad either with the HOBO spread being where it's been. We'll look at when we do this catalyst change, but I think we'll probably stay in RD because you can't -- the practicality is you can jump in now a little bit, but it takes railcars, it takes a lot of set up logistics to get it going. And unless we just see a train wreck, I don't think you'll see us convert that.

I see. And typically, how long is the change on the catalyst, that be 18 months to two years or is longer?

No. On RD, it's at full capacity, we're estimating between six months of the year like -- so we got every six months, basically.

And that two really quick questions. On the dividend, is there a formula approach or that is really purely on the discretionary? But when you determine, say, $2.60, I mean how exactly is the fourth process, that's the right number?

Well, Paul, it's somewhat subjective to the Board makes that decision every time. We're going to cover our -- maintaining our assets, sustaining capital. We're going to recover our turnaround costs. We're going to cover our interest charges on any debt we have. And then, we're going to -- we have to buy crude on a monthly basis, and we're going to cover those expenses. So that's how the Board generally looks at it, and our also another consideration. But that -- it's just an every quarter look where we sit on cash, and the volatility of the cracks drives those numbers up and down like, as you might imagine.

Right. Okay. And final one with the rising fear of recession, the impact your balance sheet management in terms of like how much cash balance that you want to keep? And what is the cash return? I mean how that factor is being built in into your thought process?

Well, I mean, the price of crude matters is that crude settlement they it grows with the higher prices. So -- and then we also have to be careful of the inventory we hold that gets revolved and that's cash out the door, should that have -- should crude drop in half, for instance. So, we consider all those factors. And typically, our cash -- minimum cash balance is between $250 million at low crude prices and $500 million at high crude prices.

Thank you. Ladies and gentlemen, that concludes our question-and-answer session. I'll turn the floor back to management for any final 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 safe, reliable, and environmentally responsible operations. We look forward to reviewing our third quarter '22 results in our next earnings call. Thank you.

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