CVR Energy - Q1 2023

Transcript

Operator (participant)

Greetings, welcome to the CVR Energy, Inc. Q1 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. If anyone should require operator assistance during the conference, please press * 0 on your telephone keypad. 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 in Investor Relations. Thank you, sir. You may begin.

Richard Roberts (VP of Financial Planning and Analysis in Investor Relations)

Thank you, Christine. Good afternoon, everyone. We very much appreciate you joining us this afternoon for our CVR Energy Q1 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 Q1 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 Q1 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.

Dave Lamp (CEO)

Thank you, Richard. Good afternoon, everyone, and thank you for joining our earnings call. Yesterday, we reported Q1 consolidated net income of $259 million and an earnings of per share of $1.94. EBITDA for the quarter was $401 million. Our strong 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 Q1 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 Q1 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 Q1, with Group Three 2-1-1 averaging $34.16 per barrel. The distillate crack remained above gas crack in the Q1, 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%-10% if economics dictate.

RIN prices declined slightly from the Q4, but remained stubbornly high at $8 per barrel. On our last earning 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 law. Small refineries across the country have filed similar lawsuits, with compliance stays being granted so far for certain small refineries in the Fifth, Eleventh, and D.C. 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. We will continue to fight for our rights that we believe Wynnewood is entitled to. We continue 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 Q4. The combination of higher throughput volumes and improved HOBO spread drove improved results for the Q1 of 2023 relative to the Q4 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 Q1. However, we posted another quarter of strong results since we sold more than half of our Q1 production in the Q4 of 2022 before prices began to decline. We continue to expect healthy demand for fertilizer in the planning season due to strong grain prices and farmer economics. Let me turn the call over to Dane to discuss our financial highlights.

Dane Neumann (CFO)

Thank you, Dave, and good afternoon, everyone. For the Q1 of 2023, our consolidated net income was $259 million. Earnings per share was $1.94, and EBITDA was $401 million. Our Q1 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 on the petroleum segment was $210 million for the Q1, driven by strong product cracks in the Mid-Con.

Our Q1 realized margin, adjusted for inventory valuation, unrealized derivative gains, and a RIN mark-to-market impacts was $18.99 per barrel, representing a 56% capture rate on the Group Three 2-1-1 benchmark. RINs 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 on March 31st, 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 Q1, compared to $5.57 per barrel in the Q1 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 on the fertilizer segment was $124 million for the Q1, with strong production for the quarter offsetting the decline in nitrogen fertilizer prices relative to the Q1 of 2022. The partnership declared a distribution of $10.43 per common unit for the Q1 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 Q1 of 2023 was $247 million. 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' Q4 distribution and $50 million paid for the CVI Q4 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 Q1 was $40 million.

For the full year of 2023, we estimate total consolidated capital spending to be approximately $200 - $226 million, and turnaround spending to be approximately $60 - $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 Q2 of 2023, for our petroleum segment, we estimate total throughput to be approximately 195,000-210,000 barrels per day.

Direct operating expenses to range between $90 - $100 million, total capital spending to be between $35 - $45 million. For the fertilizer segment, we estimate our Q2 2023 ammonia utilization rate to be between 95%-100%. Direct operating expenses to be approximately $50 - $55 million, excluding inventory impacts, total capital spending to be between $7 - $12 million. For renewables, we estimate Q2 2023 total throughput to be approximately 15 - 22 million gallons for the quarter due to a planned catalyst change. Direct operating expenses for the Q2 are expected to be between $6 - $8 million. With that, Dave, I will turn it back over to you.

Dave Lamp (CEO)

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 Q1 average crack spreads in recent history. While high diesel cracks drove much of the strength in the Q1, diesel has softened somewhat, but this has been somewhat offset by increased gas cracks. Turnaround activities across the industry were high in the Q1, leading to inventories of refined products in the U.S. to fall below 5-year average levels.

In the Mid-Con, inventories for gas and diesel are low for this time of year, product liftings have been strong, particularly for diesel or agricultural demand pulling hard during the planning season. Which allows us to blend additional biofuels and increase our internal RIN generation. Refined product volumes across our racks are up approximately 5% compared to the Q1 of 2022. Premium gasoline margins averaged $0.36 a gallon in the Q1, which helps our capture rates as approximately 15% 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, 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 was partially reflected in our unrealized dividend derivatives gain for the Q1. On the crude oil side of the equation, inventory has increased closer to 5-year averages levels, which can also be partially attributed to elevated turnaround activity in 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, 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 WTI differential has narrowed some recently, exports of WTI Midland are continuing at record levels, which we believe should be supportive of the sustained Brent WTI spread. Turning to fertilizer segment, nitrogen fertilizer prices declined in the Q1, 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, this should bode well for nitrogen fertilizer demand in spring. Since the turnarounds completed at both of our facilities in the Q3 of 2022, the plants ran well with high utilization in the Q1.

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, 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 for the Q1. We are completing our second planned catalyst change, we are expecting to see significant improvements in renewable diesel yield with the new catalyst install. Construction of the PTU is progressing, we are currently expecting an in-service date to mid to late Q3 of 2023.

With the addition of the PTU, we expect to see renewable diesel margin capture improve by approximately 30%. Looking at the Q2 of 2023, quarter to date metrics are as follows: Group Three 2-1-1 cracks have averaged $32.32 per barrel, with the Brent/WTI spread at $3.96 per barrel and WTI Midland 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 Three 2-1-1 cracks were $25.96.

Brent WTI was $3.65, and WCS was $15.09 under WTI. RINs were approximately $1.50, or 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 (participant)

Thank you. We will now be conducting a question and answer session. If you would like to ask a question, please press * 1 on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press * 2 if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the * keys. One moment, please, while we poll for questions. Thank you. Our first question comes from the line of Manav Gupta with UBS. Please proceed with your question. Manav Gupta, your line is live.

Manav Gupta (Executive Director)

Hi, 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?

Dave Lamp (CEO)

I think that's right, Manav. you know, the you don't know what our strike price was or what we bought them at, but, leave it to say that, you know, we're at, you know, it's going to affect our results materially in the Q2 and probably the Q3 and Q4.

Manav Gupta (Executive Director)

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 Q4 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. Should we assume your renewable diesel results get a lot more competitive with the benchmarks out there once you are done with the catalyst change as well as the PTU coming online late 3Q?

Dave Lamp (CEO)

Yeah, I think that's a good assumption. you know, you know, 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'll bring us up to 50. The catalyst change itself has two elements to it. Run length, we're predicting to be, probably two or three times better than what we've been getting so far, and it also improves the distillate yield substantially. That will move capture up also.

Manav Gupta (Executive Director)

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

Dave Lamp (CEO)

Thank you.

Operator (participant)

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

Neil Mehta (Managing Director and Head of Americas Natural Resources Equity Research)

Thanks so much. 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?

Dave Lamp (CEO)

Neil, it's, you know, I think if you look at the MidCon, 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. You look back five years, we're at very low on inventory on gas, which is extremely unusual this time of year. It tells me demand has been good. 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, you know, again, distillate has been extremely strong. You know, 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 Q1 from our competitors and other refiners in the system. Even though we had a turnaround, Even though it was a fairly small turnaround, it's just a coker, we still were cut back on rates and still had a very good quarter. You know, I think in general, you know, 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.

That's the main reason we employed some of the hedges we did, just because we saw that coming. You know, there's 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 startups and shutdowns. It's the rest of the world that's where the incremental capacity is gonna come from, and a lot of those are export refiners. It's even though our demand is strong, you know, I think the world's seeing a bit of a slow.

Neil Mehta (Managing Director and Head of Americas Natural Resources Equity Research)

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

Dave Lamp (CEO)

Well, I think, you know, 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 'cause that's just the effect of doing the spin-off. You know, we're a cash machine. That's what we're here for. We give out either via a regular or special. We don't do many stock buybacks 'cause we just don't think that's really necessarily in the best interest of our shareholders. We're gonna give it back as dividends or specials.

Neil Mehta (Managing Director and Head of Americas Natural Resources Equity Research)

Okay.

Operator (participant)

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

John Royall (Executive Director)

Hi. Good afternoon. Thanks for taking my question. Maybe just to 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 Q1, including the UAN tax payment, and you've locked in some hedges in the future. Any updated thoughts on the propensity to pay out some of that with the special going forward?

Dave Lamp (CEO)

Well, I think, you know, the specials, as I mentioned before, was really, around, a unique set of market conditions. I'd, 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. That's why we did specials. You know, they, you know, we didn't, think about raising the regular, up to that 'cause we didn't think it was sustainable. I think the same situation is here is, you know, we're gonna take it quarter by quarter and the board looks at it very closely. You know, we're managing cash to levels we think we need to avoid, using our revolver unless we absolutely have to.

That's just the point of view we have. So specials will come and go if the market's remarkable, and we have the cash on the balance sheet to dividend out, we will.

John Royall (Executive Director)

Great. That's, that's helpful. Then, on the monetization of the tax credits at UAN, how do those work in general? How do they impact future cash flows at UAN in terms of what you're giving up? Then, following the $19 million payment in Q1, how should we think about the potential for future payments and timing there?

Dane Neumann (CFO)

Yeah, I'll take this one. Really what we had in place previously was an existing CO2 sales contract with a counterparty. We ended up contributing that sales contract to a JV with the same counterparty. In a result, it allowed the tax equity investor to claim those credits that we're receiving for the sequestration activity. 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 a string of payments we expect to receive associated with the JV. 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 one and a half million each quarter. 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. Obviously from the CVR Partners' perspective, they'll take that into consideration, when they are looking at their cash available.

John Royall (Executive Director)

Thank you.

Dane Neumann (CFO)

You're welcome.

Operator (participant)

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

Matthew Blair (Managing Director of Refiners, Chemicals, and Renewable Fuels Research)

Hey. Good morning, Dave. You mentioned the benefits on premium gasoline rolling through your system.

Dave Lamp (CEO)

Yes.

Matthew Blair (Managing Director of Refiners, Chemicals, and Renewable Fuels Research)

Could you talk about the drivers for these wide octane spreads? Do you think that's sustainable for the rest of the year?

Dave Lamp (CEO)

Well, the group 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 very short in the Q1. You know, what usually cures it is a big shipment coming up from the Gulf, via Explorer into the back, into Tulsa, into the back of our markets. That just didn't happen very much this year. Either they had better export markets or something off the Gulf, and even though the arb was pretty wide, the shipments just didn't come. It kind of played into our hand. We have the ability to make quite a bit of premium if the margin's there.

You know, we use our CCR reformers to make that material. 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 Q1.

Matthew Blair (Managing Director of Refiners, Chemicals, and Renewable Fuels Research)

Okay. 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?

Dave Lamp (CEO)

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

Matthew Blair (Managing Director of Refiners, Chemicals, and Renewable Fuels Research)

Okay. Sounds good. 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?

Dave Lamp (CEO)

It's gonna make some more D6s, I think for sure. You gotta remember that only 5% of the convenience stores even offer E15, so it's limited in its in its reach into the market. You know, I don't know who buys it for what reason, but, you know, the typical discount's $0.02-$0.03. It's not like it's a barn burner. If you include the mileage deduction you get with it's probably a loser for most people. I don't expect it to do a whole lot.

Matthew Blair (Managing Director of Refiners, Chemicals, and Renewable Fuels Research)

Great. Thanks for the commentary.

Dave Lamp (CEO)

You're welcome.

Operator (participant)

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

Paul Chang (Managing Director and Senior Equity Analyst)

Hey, guys. Good afternoon. Dave, I know you're not going to tell us, too much detail on the hedging. Can you tell us that if the gas -both of them being hedged 25% of your future output or that one is being hedged more than the other?

Dave Lamp (CEO)

Well, I think we did a combination of all. We did 2 on 1s. We did some distillate, we did some gas. It's a wide variety, just depending on what our strike price was at the time. I really am not gonna get into all the details of exact volumes.

Paul Chang (Managing Director and Senior Equity Analyst)

Okay. I just want to clarify that when Dane was talking about $95 million on the RIN, on the RIN costs for the quarter, does that include the RIN you generate from the RD or that's excluding the RIN you're generating in the RD?

Dane Neumann (CFO)

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, like an open market transaction. They still have to be costed for that.

Paul Chang (Managing Director and Senior Equity Analyst)

I see. Also that just clarify that. I mean, in the past, I think, you have the shipping history to get about 30,000 barrel per day of the WCS and, you just sold most of them at Cushing and run a little bit in the cost of it. Are you still doing that and getting about 30,000 barrel per day and which is included in your result?

Dave Lamp (CEO)

Yes. Typically, you know, we'll get 25 on the Keystone side and 5 on the Spearhead side. We're contracted for 10 on the Spearhead side. We run it opportunistically. If it's in the money, we'll run it. Of course, we had a coker turnaround in the Q1, so we minimized the runs during that period of time. 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. We're not running any now. Don't plan on running for the next month as long as the spread stays where it is.

Paul Chang (Managing Director and Senior Equity Analyst)

Right. A final one for me. What's the sustaining CapEX for the corporation now going forward? That also on the renewable, maybe I missed it. Did you tell us that, what is the growth margin and the net, and the pre-tax income for that operation in the, in the Q1?

Dave Lamp (CEO)

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.

Paul Chang (Managing Director and Senior Equity Analyst)

Okay. how about sustaining CapEX?

Dane Neumann (CFO)

Yeah, sustaining CapEX for the corporation, we just say it's $80 - $100 million, Paul.

Paul Chang (Managing Director and Senior Equity Analyst)

Okay. Will do. Thank you.

Dane Neumann (CFO)

You're welcome. Thank you.

Operator (participant)

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.

Dave Lamp (CEO)

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 Q2 2023 results during our next earnings call. Have a great day.

Operator (participant)

Ladies and gentlemen, this does conclude today's teleconference. You may disconnect your lines at this time. Thank you for your participation, and have a wonderful day.