CVR Energy Inc (CVI) 2022 Q3 法說會逐字稿

Greetings, and welcome to the CVR Energy, Inc. Third Quarter 2021 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.

Thank you, Camilla. Good afternoon, everyone. Thank very much for you joining us this afternoon for our CVR Energy Third 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 third quarter results, let me remind you that this conference call may contain forward-looking statements as that term is defined under federal securities laws. For this purpose, any statements made during this call that are not statements of historical facts may be deemed to be forward-looking statements. You are cautioned that these statements may be affected by important factors set forth in our filings with the Securities and Exchange Commission and in our latest earnings release.

As a result, actual operations or results may differ materially from the results discussed in the forward-looking statements. We undertake no obligation to publicly update any forward-looking statements whether as a result of new information, future events or otherwise, except to the extent required by law. Let me all remind you that CVR Partners completed a 1 for 10 reverse split of 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 third quarter earnings release that we filed with the SEC on Form 10-Q for the period and will be discussed during the call.

With that said, I'll turn the call over to Dave.

Thank you, Richard. Good afternoon, everyone, and thank you for joining our earnings call. Yesterday, we reported third quarter consolidated net income of $80 million and earnings per share of $0.92. EBITDA for the quarter was $181 million. Our strong results for the quarter were driven primarily by the refining segment due to high distillate cracks and our best-in-class distillate yield, somewhat offset by turnarounds at both fertilizer plants during the quarter.

We are pleased to announce the Board of Directors has authorized a third quarter regular dividend of $0.40 per share and a special dividend of $1 per share both of which will be paid on November 21 to shareholders of record at the close of market on November 14. Year-to-date, the Board has authorized regular and special dividends totaling $4.80 per share, representing a yield of over 12% based on yesterday's close price.

In our Petroleum segment, combined total throughput for the third quarter of 2022 was approximately 202,000 barrels per day and life product yield was 97% on crude oil processed. Benchmark crack spreads remained elevated during the quarter with Group 3 2-1-1 averaging $43.94 per barrel. The distillate crack remained significantly above the gas crack in the quarter, and we continue to operate our refineries in max distillate mode.

RIN prices also remained stubbornly high at $8 per barrel, thereby adding approximately $0.30 per gallon to fuel costs at the pump due to EPA's continued mismanagement of the RFS regulation. We have filed petitions in the Fifth Circuit seeking judicial review of our EPA's ridiculous and misguided denial of Wynnewood small refinery exemptions for the years 2017 through 2021.

We will continue to fight for the rights we believe Wynnewood is entitled to as intended by Congress, when they -- when the RFS regulation was passed and became the law of the land. We expect to file for an exemption for 2022 soon. We continue to increase throughput rates at the Wynnewood renewable diesel unit in the quarter, processing approximately 18 million gallons of vegetable oil feedstock.

The HOBO spread averaged a negative $1.48 per gallon for the third quarter, an improvement of approximately $0.50 per gallon from the second quarter. For the third quarter, our financial results also improved for renewable diesel business, which we are currently include -- which currently include -- is included in our corporate and other segment.

In the Fertilizer segment, we completed planned turnarounds at both facilities in the third quarter. We currently (inaudible) any other planned turnaround scheduled for Fertilizer until fall of '24. Fertilizer markets remain tight, and we have seen a steady increase in prices over the past few months, which is carried through to the fall and into -- we expect to carry through the fall and into 2023.

Now let me turn the call over to Dane to discuss our financial highlights.

Thank you, Dave, and good afternoon, everyone. For the third quarter of 2022, our consolidated net income was $80 million, earnings per share was $0.92 and EBITDA was $181 million. Our third quarter results include an unfavorable inventory valuation impact of $114 million, a negative mark-to-market on our estimated outstanding rate obligation of $38 million and unrealized derivative gains of $20 million.

Excluding the above mentioned items, adjusted EBITDA for the quarter was $313 million and adjusted earnings per share of $1.90. Adjusted EBITDA in the Petroleum segment was $306 million for the third quarter, driven by high utilization rates at our refineries and strong product cracks in the Mid-Con.

Our third quarter realized margin adjusted for inventory valuation, unrealized derivative gains and RIN mark-to-market impacts was $23.05 per barrel, representing a 52% capture rate on the Group 3 2-1-1 benchmark. RINs expense for the quarter, excluding the mark-to-market impact was $98 million, or $5.28 per barrel, which negatively impacted our capture rate for the quarter by approximately 12%.

Note, this excludes the approximately $50 million worth of RINs generated by the renewable diesel unit in the third quarter. The estimated accrued RFS obligation on the balance sheet was $715 million at September 30 and was mark-to-market at an average RIN price of $1.69. As a reminder, our estimated outstanding RIN obligation excludes the impact of any small refinery exemptions.

Direct operating expenses in the Petroleum segment were $5.53 per barrel for the third quarter compared to $4.52 per barrel in the third quarter of 2021. The increase in direct operating expenses was primarily due to higher repair and maintenance expenses and increased natural gas and electricity costs. Adjusted EBITDA in the Fertilizer segment was $10 million for the third quarter, with results impacted by lower production volumes and elevated operating expenses as a result of the 2 planned turnarounds completed in the quarter, as well as approximately 11 days of downtime at the Coffeyville facility due to outages at the third-party air separation plant.

The partnership declared a distribution of $1.77 per common unit for the third quarter of 2022. As CVR Energy owns approximately 37% of CVR Partners common units, we will receive a proportionate cash distribution of approximately $7 million. Cash provided by operations for the third quarter of 2022 is $156 million, and free cash flow was $93 million.

Total consolidated capital spending was $68 million which included $23 million in the Petroleum segment, $25 million in the Fertilizer segment and $16 million on the pretreatment unit for the RDU. For the full year 2022, we have made total consolidated capital spending be approximately $204 million to $234 million and turnaround spending to be approximately $80 million to $85 million.

Turning to the balance sheet. We ended the quarter with a consolidated cash balance of $618 million which includes $119 million of cash in the Fertilizer segment. Total liquidity as of September 30, excluding CVR Partners, was approximately $746 million which was comprised of primarily a $499 million of cash and availability -- availability under the ABL facility of $247 million.

Looking ahead to the fourth quarter of 2022 for our Petroleum segment, we estimate total throughput to be approximately 200,000 to 220,000 barrels per day, direct operating expenses to range between $100 million and $110 million and total capital spending to be between $30 million and $35 million. For the Fertilizer segment, we estimate our fourth quarter 2022 ammonia utilization rate to be between 93% and 98%, direct operating expenses to be approximately $60 million to $70 million, excluding inventory impacts, and total capital spending to be between $5 million and $10 million.

For renewables, we estimate fourth quarter 2022 total throughput to be approximately 14 million to 17 million gallons for the quarter due to a catalyst change. Direct operating expenses for the fourth quarter are expected to be between $5 million and $7 million. With that, Dave, I will turn it back over to you.

Thanks, Dane. In summary, we had another strong quarter driven by the refining segment. We were pleased to returning another $1.40 per share of dividends to our shareholders. Market conditions are currently very strong across all our businesses, and we believe we are well positioned the benefit from the structural changes we see taking place.

Starting with refining, the strength in the cracks of this year has largely been driven by tight supply conditions driven by refined product driving -- refined product inventories well below 5-year average levels. Between lost production capacity, as a result of refinery closures and significantly increased operating costs for many refineries outside the United States. We are currently seeing record exports of gasoline and diesel out of the U.S. while imports have mostly stayed flat.

In addition, planned and unplanned downtime at refineries across the U.S. has caused refined product supplies to tighten further and cracks to move higher. Despite the declines we are experiencing in gasoline and diesel demand, forward distillate cracks are heavily backward dated but are currently over $45 per barrel for all of 2023.

On the crude side of the equation, inventories are also low -- on the low end of the 5-year averages and continued releases from the strategic petroleum reserves are impacting differentials.

Shale oil production volumes are up and we believe most incremental barrels are going to exports, which is supportive of a wider Brent-TI differential. We are seeing volumes on our gathering system stabilized at around 125,000 barrels per day and new projects have been announced in our gathering areas that could offer additional upside potential.

Turning to the Fertilizer segment, nitrogen fertilizer production in Europe has been significantly reduced as a result of an increase in natural gas and energy prices over the past year, and this has created an opportunity for U.S. producers to export fertilizers to Europe. As a result, domestic fertilizer supply is tighter, and we've seen a steady increase in the prices since summer.

We have sold product through the end of the year and into the first part of '23 and believe prices for the spring of '23 could be similar to the highs that we saw in the spring of 2022. We currently believe strong fundamentals in the fertilizer market could persist for several years with turnarounds now complete, we are looking at the potential brownfield capacity expansion that both our plants which we think could be done at much lower cost than greenfield capacity.

Finally, in our renewable business, we continue to ramp production -- ramp up production on renewable diesel unit and have reached design capacity of 315,000 gallons per stream day of feed in early October before taking the unit down for catalyst change. Yields have recently been above 90% for renewable diesel production as a percentage of vegetable feedstock. With the catalyst change currently in process, we expect to add additional isomerization catalysts which should increase catalyst life by a few months.

Construction on the PTU is progressing, and we are currently expecting an in-service date early to mid-third quarter of 2013. With the addition of the PTU, we expect to see between $0.50 and $1 per gallon increase in our renewable diesel margins.

Looking at the fourth quarter of 2022, quarter-to-date metrics are as follows: Group 2-1-1 cracks have averaged $52.54 per barrel with a Brent-TI spread at $5.33 per barrel and the Midland differential at $1.90 over WTI. WTL differential has averaged $1.21 over TI and the WCS differential has averaged $25.77 per barrel under WTI.

Fertilizer prices remained strong as well with ammonia prices over $1,100 per ton and UAN prices over $5.50 per ton. As of yesterday, group 3, 2-1-1 cracks were $46.71 per barrel. The Brent-TI spread was $7.87 per barrel. WCS was $29.15 under WTI and RINs were approximately $8.60 per barrel.

As I mentioned, we believe many factors driving the strong market conditions in our Refining and Fertilizer business are structural, and we are optimistic about the output for the rest of the year and 2023. Our focus remains unchanged. We strive to operate our plants in a safe, reliable and environmentally responsible manner and control and continue to focus on growing our renewables business.

Our transformation to segregate the renewables business remains on track, and we expect completion in the first half of 2023. We also continue to explore opportunities to invest in projects where we believe we can earn an attractive return, both in renewables and in our refining business.

We have identified some diesel recovery projects that we believe could increase our industry-leading distillate yield to close to 50% on crude processed. I look forward to providing additional details on these projects as they develop.

With that, operator, we're ready to -- for questions.

(Operator Instructions) Our first question is with Matthew Blair from TPH.

Congrats on the strong capital returns to shareholders. I had a question on your WCS share at Coffeyville, it looks like it stayed fairly low. I think just around 6% of your total feedstock slate despite some attractive WCS discounts. So is that going to be the case going forward that even if WCS spreads widen out, the refinery will process some, but then you'll resell some WCS at Cushing?

Well, I think this quarter, we'll be maximizing the amount of WCS we run because, as you mentioned, the spreads did widen out. In the first part of the quarter, it was actually fairly narrow where we were better off to sell it. So that's -- we have adjusted and then we had some work we had to do on the coker in that sulfur plant that took some of the WCS out of the slate for a while.

We do have a turnaround next year on the coker that will affect our WCS runs, but I expect us to run up to the maximum we can within sulfur and TAN limits of our process equipment.

Sounds good. And then, Dave, do you have any expectations for this upcoming RVO from the EPA? There's a thought that things actually might look pretty different going forward. The EPA might issue a 2023 to 2025 RVO, and there's also some talk about how this $15 billion ethanol blending rate requirement is going away and EPA might have more flexibility to reduce the ethanol requirements. Do you have any thoughts on that?

Well, I do, Matt. None of them are any good. Most of the time, my view is that EPA has completely mismanaged the entire RFS program, starting with this ridiculous denial of all small refinery waivers.

It gives me no confidence that they'll do anything that they say. And I don't know how in the world you can issue an RVO for the next 3 years when you don't even know what gasoline demand is or distillate demand is. And a lot of factors can change those, as you well know.

I don't know, I'm sure you've noticed, but RIN prices have drifted up ever since the RVO has been -- was announced for '21, '22 and it's done nothing but go up and just reflected in the fact that they've maintained this $15 billion of ethanol and the market basically can't blend that much.

Now the economics for blending ethanol are very strong right now, particularly with $1.71 RIN D6 RIN. But my confidence level on them to do anything that makes any sense -- they are worried about the price of gasoline and yet have $0.30 now, probably $0.35, frankly, of cost built in for blending ethanol and it doesn't really need a subsidy. It's profitable to do on its own.

Our next question is from John Royall with JPMorgan.

If you could potentially get into the potential brownfield expansions in Fertilizer? Any further detail there, what size we're talking about anything on potential cost or return expectations?

Well, we're in the early throes of -- we just completed 2 turnarounds, big turnarounds for both plants. So after we get all lined out from all that, which we're pretty close to, we'll start the feasibility studies on these. But I think you're looking at a modest increase somewhere between less than 15%.

I don't know the exact numbers yet because we just really haven't done the work yet. But I think I would estimate that there are less than $100 million in each expansion, something like that or we probably won't do them if they're any more expensive than that.

But 15% is a good walking number, capacity on East Dubuque is around 1,100 tons a day. and Coffeyville is about 1,350 or so tons per day. So that gives you some numbers to work with.

Yes. That's really helpful. And then just thinking about the special dividend and kind of how it ties into the balance sheet, how do you feel about your net leverage right now? I think it's just under $1 billion of net debt. Do you think that's kind of the right level for this business? Or could you actually draw down some cash with the special dividend in excess of cash flows and lever up a little?

Well, we think about -- with the current EBITDA, it's probably -- we probably could afford some more debt. But a little bit of concern of what the interest rates are going to be going forward. We do have 1 tranche of our bonds that are due '25.

So we'll be looking at refinancing somewhere in '24 on those. And we're always keeping the option open to buy down some of that if the interest rates are too high. It's too early to know what they will be at this point, but we always had the opinion that -- and that we're a cash machine, and we pay -- if we earn it, we're going to pay it out to shareholders. And I think we've shown that in the last 2 quarters that, that is truly what we march to.

Our next question is from Carly Davenport with Goldman Sachs.

I wanted to just start on the capital return side. Can you talk a little bit about kind of where you view the optimal regular dividend level over time? Is there a potential to grow that in the near to medium term? Or is there more of a preference to continue to kind of utilize the special dividend as a flywheel in this robust margin environment?

Well, Carly, I think the interesting fact is that I think this is the first time in history we've had both businesses hitting on full stride. We're finding at the same time as Fertilizer and Fertilizer at the same time as Refining. And that is a little bit of the logic for a special because the Fertilizer cycle will turn at some point, and I don't know on refining. I think it's structurally short for quite a long time.

But I think we used to have a dividend -- a regular dividend of around $0.80, and we would love to get back to that number, and the Board looks at it every quarter to see if it makes sense to increase the regular and decrease the specials. But right now, with both the hidden at the same time, history would tell us that doesn't last forever. So we remain cautious on that.

Got it. That makes sense. And then the follow-up is just on renewable diesel. I recognize that the process to kind of build that out and eventually break the business out is ongoing. But can you talk a little bit about what you're seeing from a unit margin perspective at that business as you think about how 3Q tracked and then thinking about where 4Q has been tracking?

Sure. Q3, I think probably September was a good month for us with HOBO, as I mentioned, was off $0.50 and some of the bases had come in to some degree. I always thought refining was a wild business, but I'll tell you, renewables wilder than any of it. There's so many variables in it to go up and down with low-carbon fuel standards at $60 where they start -- when we started the unit were almost $200.

That's largely been offset by RIN increases, but we're still optimistic. And I think September, we printed a positive number, and we still don't have the pathway completed on the final pathway for the LCFS. So we're on the provisional still. As we get towards getting that certified, then we'll pick up another tranche. And then as I mentioned, we've got the capacity. We've demonstrated full capacity. We still have some challenges around that to work out in the refinery, but I think we'll be successful at that.

And we should have a pretty good run in '23, assuming we can lengthen the catalyst life a little bit by adding some more catalyst to the mix. So we're very positive on it. And with the PTU, PTU is going to be between $0.50 and $1 uptick and that just adds right to the bottom line.

Our next question is from Paul Cheng from Scotiabank.

Dave and Dane, can you talk a little bit about the projects you mentioned of the distillate yield improvement, what is the capacity, the yield, the timing? And also which facility and what is the CapEx spending may look like?

Paul, we're in the early phases of looking at this, but we're pretty confident there's at least 6,000 barrels available pick up over the top of what we do today. And we typically yield about 44% on crude. We're trying to push that number towards 50%. And the molecules are there. It's just we need to debottleneck the -- all 3 of our distillate hydrotreaters and put some hardware on some of our vacuum towers to recover this distillate.

But I'm pretty confident it's there. It's just a matter of what is the cost to get that done. And we're still in the engineering studies to figure that out.

And Dave, what is the earliest that the project will get sanctioned or will get complete? Any kind of time line that you can share?

Well, it's going to take us another 6 months to fully define it, I think. Then it's a question of, do we need downtime to make the changes? And then those will have to consign with the turnarounds or if we deem it or opportunities come up to do it.

But most likely, it's going to take a turnaround to do these because we have to make modifications to the vacuum towers to do it. So I'm going to guess 2 years minimum, maybe 3. But I'll tell you, Paul, we still think distillate is short for a long, long time. It just structurally is going to be around for a long time. It appears to us with IMO 2020 than some of the other factors that have happened on nat gas and the balance around the world.

Right. And David, for the renewable diesel, you're saying that you're going to have a catalyst change in the fourth quarter. That's only 6 months since you start off the project seems to be a very short duration, has that come as a surprise?

No. That was our design, basis was 6 months at full rate. I think we -- the first load may have gone a little quicker just because of start-up. But we've got a good handle on it now. And like I said, I think we'll stretch that out. I'm pretty confident we'll get another 2 months at least. So hopefully, we'll only have 1 catalyst change next year. We're budgeting for 2, but hopefully, we'll only have 1.

And how expensive it is when you change the catalyst each time?

Catalyst cost about $2 million, and the -- to change it out is about $3 million, so $5 million in total.

Okay. And final question that any preliminary estimate for 2023 CapEx and turnaround expense? I think that you do have 1 turnaround in cost of (inaudible) next year? And then also that, what is RVO currently on the balance sheet liability?

We don't disclose typically. We all will provide us guidance for the next quarter, Paul, on what we plan to do in '23. As far as the RVO -- as far as the RIN short, Dane, do you want to cover that?

Yes. So the short as of the end of the month or the end of the quarter, Paul, was $422 million RINs, just under $423 million RINs, and it was $715 million.

And that has come down, Paul, since the second quarter because we are buying feverishly for the Coffeyville and to close out the Coffeyville refinery RVO.

And out of the $423 million, what's the component related to Wynnewood?

Yes, of the $423 million, around $295 million RINs of Wynnewood are just under $0.5 billion, Paul.

There are no further questions at this time. I would like to turn the floor back over to management for closing comments.

Again, we'd like to thank you all for your interest in CVR Energy. Additionally, I'd like to thank our employees for their hard work and commitment towards safe, reliable and environmentally responsible operations. We're proud of the work we do, and we're proud of providing the American public with the fuels they need to enjoy modern life and we look forward to reviewing our fourth quarter results in the next earnings call. Thank you.

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