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00:03 Greetings and welcome to the CVR Energy Inc. Fourth Quarter 2021 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.

00:22 I would now like to turn the conference over to your host, Richard Roberts, Vice President of FP&A and Investor Relations for CVR Energy. Thank you, sir. You may begin..

00:30 Thank you, Melissa. Good afternoon, everyone. We very much appreciate you joining us this afternoon for our CVR Energy fourth quarter 2021 earnings call. With me today are Dave Lamp, our Chief Executive Officer; Dane Neumann, our Chief Financial Officer; and other members of management.

00:45 Prior to discussing our 2021 fourth quarter and full year 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.

01:09 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 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. 01:34 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 2021 fourth quarter earnings release that we filed with the SEC and Form 10-K for the period and will be discussed during the call. 01:50 With that said, I'll turn the call over to Dave..

01:53 Thank you, Richard. Good afternoon, everyone and thank you for joining our earnings call. This morning, we reported CVR Energy's full-year and fourth quarter results for the full year of ’21. We reported a net income of $74 million inclusive of non-controlling interest or $25 million of attributable to CVI shareholders.

02:16 Earnings per diluted share were $0.25 for the full year of 2021. For the fourth quarter, we reported net income of $25 million inclusive of non-controlling interest and a net loss attributable to the CVI shareholders of $14 million. Loss per diluted share was $0.14 for the fourth quarter.

EBITDA for the year was $462 million and for the quarter it was $116 million. 02:46 While RIN prices remained stubbornly high and weighted on our refining results, fertilizer markets fundamentals continue to improve and drove another quarter of strong results for CVR’s fertilizer business.

Despite the challenges in the refining market in 2021, we continue to focus on safe, reliable operations. We continue to achieve significant year-over-year improvements in environmental health and safety metrics, including a 42% year-over-year reduction in environmental events.

03:21 We are providing more ESG disclosures and we published our first internal ESG report for 2020. Work is progressing on a 2021 report that we plan to release publicly later this year. We also returned capital to our shareholders through a significant special dividend in the second quarter totaling the equivalent of $492 million or $4.89 per share.

03:51 Turning to the fourth quarter results. For our Petroleum segment, the combined total throughput for the fourth quarter of 2021 was approximately 222,000 barrels per day as compared to 219,000 barrels per day for the fourth quarter of 2020.

Both facilities ran well during the quarter and we increased WCS processing at the Coffeyville refinery due to widening spreads of WCS at Cushing. 04:22 Benchmark cracks have improved significantly from a year ago.

The Group 3 2-1-1 crack averaged $17 per barrel in the fourth quarter of ’21, however, RINs consumed over 35% of that at approximately $6.19 per barrel. Group 3 2-1-1 averaged $8.44 per barrel in the fourth quarter of 2021 -- 2020, when RINs were $3.50 a barrel.

04:51 The Brent-TI differential averaged $2.71 per barrel in the fourth quarter as compared to $2.49 in the prior year period. The Midland Cushing differential was $0.63 per barrel over WTI in the quarter compared to $0.37 per barrel over WTI in the fourth quarter of 2020.

And the WCS to WTI differential was $16.60 per barrel compared to $11.44 per barrel in the same period last year. 05:25 Light product yield for the quarter was 103% based on crude oil processed. Our distillate yield as a percentage of total crude oil throughputs was 44% in the fourth quarter of 2021 consistent with prior period.

In total, we gathered approximately 113,000 barrels per day of crude during the fourth quarter of ‘21 compared to 117,000 barrels per day for the same period last year. We continue to see a slight decline in production across our system, due to limited drilling activities over the past year.

However, we would expect to see an additional wells being drilled with current prices firmly above $80 per barrel. 06:08 In the Fertilizer segment, consolidated ammonia utilization was 90% during the quarter, which was impacted by some unplanned downtime at both facilities.

In October, we completed the installation of an additional CO2 compressor and an ammonia pump at our Coffeyville facility, which should increase UAN production capacity by approximately 100 tons per day. Fertilizer prices continued to increase through the fourth quarter and prices currently look firm through the first half of the year.

06:42 Now let me turn the call over to Dave to discuss our financial highlights..

06:47 Thank you, Dave and good afternoon, everyone. Our consolidated fourth quarter net income of $25 million and loss per diluted share of $0.14, includes a negative mark-to-market impact on our estimated outstanding RFS obligation of $9 million and favorable inventory valuation impacts of $17 million.

Excluding these impacts, our fourth quarter 2021 adjusted EPS was a loss of $0.20 and adjusted EBITDA was $109 million. 07:14 The Petroleum segment's EBITDA for the fourth quarter of 2021 was $27 million compared to a negative $66 million in the same period in 2020.

The year-over-year EBITDA increase was driven by the significant increase in crack spreads, offset somewhat by elevated rent prices. Excluding the mark-to-market impact on our estimated outstanding RFS obligation of $9 million, and inventory valuation impacts of $17 million, our Petroleum segment adjusted EBITDA was $19 million.

07:44 In the fourth quarter of 2021, our Petroleum segment's reported refining margin was $7.13 per barrel. Excluding inventory valuation impacts, unrealized derivative losses and the mark-to-market impact of our estimated outstanding rent obligation, our refining margin would have been approximately $6.70 per barrel.

08:01 On this basis, capture rate for the fourth quarter of 2021 was approximately 39% compared to 59% in the fourth quarter of 2020. Our capture rate for the fourth quarter of 2021 was negatively impacted by elevated RINs prices and a less favorable crude differential mostly due to the steep [indiscernible] in the crude oil market.

08:24 RINs expense in the fourth quarter of 2021 was $100 million or $4.89 per barrel of total throughput, compared to $120 million for the same period last year. As a reminder, our reported RINs expense does not include the impact of any waivers or exemptions.

Our fourth quarter RINs expense includes a $9 million mark-to-market impact on our estimated accrued RFS obligation including a $2 million benefit from revising our 2021 obligation to the high end of the recently proposed 2021 renewable volume obligation.

08:58 Our estimated accrued RFS obligation was mark-to-market at an average RIN price of $1.34 at year-end compared to $1.31 at the end of the third quarter. The full-year 2021 RINs expense was $435 million as compared to $190 million in 2020.

Our estimated RFS obligation at the end of the year approximates Wynnewood’s obligations for 2019 through 2021 as we continue to believe Wynnewood’s obligation should be exempt under the RFS regulation.

09:29 For 2022, based on the high end of the EPA's proposed 2022 RVO, we forecast a net obligation from refining operations of approximately 250 million to 260 million RINs adjusted for our expected internal blending volumes.

We also expect to generate approximately 100 million to 110 million D4 RINs from renewable diesel, bringing our net RIN obligation for 2022 to approximately 150 million RINs. Our forecast does not include the impact of any waivers or exemptions.

10:00 Derivative gains for the fourth quarter of 2021 totaled $2 million, which were primarily realized gains associated with Canadian crude oil derivatives.

In the fourth quarter of 2020, we had derivative losses of $15 million, which included unrealized losses of $23 million, primarily associated with the crack spread swaps that were closed at the end of the third quarter of 2021.

10:23 The Petroleum segment's direct operating expenses were $4.84 per barrel of total throughput in the fourth quarter of 2021 as compared to $3.99 per barrel in the fourth quarter of 2020. The increase in direct operating expenses was primarily a result of higher personnel expense and increased natural gas prices.

10:43 For the fourth quarter of 2021, the Fertilizer segment reported operating income of $72 million, net income of $61 million, or $5.76 per common unit and EBITDA of $93 million. This is compared to the fourth quarter of 2020, operating loss of $1 million, a net loss of $17 million or $1.53 per common unit, and EBITDA of $18 million.

The year-over-year EBITDA improvement was driven primarily by higher prices for UAN and ammonia offset slightly by higher feedstock costs and operating expenses. 11:17 The partnership declared a distribution of $5.24 per common unit for the fourth quarter of 2021.

As CVR Energy owns approximately 36% of CVR Partners common units, we will receive a proportionate cash distribution of approximately $20 million.

Total consolidated capital spending for the full year 2021 was $226 million, which included $50 million from the Petroleum segment, $26 million from the Fertilizer segment, and $148 million for the renewable diesel project at Wynnewood.

Of this total, environmental and maintenance capital spending comprised $65 million, including $47 million in the Petroleum segment and $16 million in the Fertilizer segment.

12:00 We estimate the total consolidated capital spending for 2022 to be $222 million to $251 million of which $136 million to $150 million is expected to be environmental and maintenance capital, and $80 million to $90 million is related to the completion of the renewable diesel unit at Wynnewood, and the construction of the pretreater.

Our consolidated capital spending plan excludes planned turnaround spending which we estimate will be approximately $70 million to $80 million for the planned turnaround at Wynnewood this year and preparing for the turnaround of Coffeyville next year.

12:33 Cash provided by operations for the fourth quarter of 2021 was $14 million and free cash flow was a use of $24 million. During the quarter, we paid cash taxes of $37 million and interest of $22 million.

Other material uses of cash in the quarter included $15 million for the partial redemption of CVR Partners’ 2023 notes and $21 million for the non-controlling interest portion of the CVR Partners' third quarter distribution. 13:00 Turning to the balance sheet. We ended the year with approximately $510 million of cash.

Our consolidated cash balance includes $113 million in the Fertilizer segment. As of December 31, excluding CVR Partners, we had approximately $584 million of liquidity, which was comprised of approximately $398 million of cash and availability under the ABL of approximately $361 million, less cash included in the borrowing base of $175 million.

13:28 During the quarter, CVR Partners redeemed another $15 million of its 2023, 9.25% senior notes outstanding. Subsequent to year-end, CVR Partners redeemed the final $65 million of the 2023 Notes that were outstanding.

With the debt refinancing completed in June of 2021 and the full redemption of the remaining 2023 senior notes earlier today, CVR Partners' total debt on the balance sheet has been reduced by $95 million, and annual debt service costs will be reduced by approximately $26 million per year, a reduction of over 40%.

14:01 Looking ahead to the first quarter of 2022. For our Petroleum segment, we estimate total throughput to be approximately 185,000 to 200,000 barrels per day as Wynnewood will be running at reduced rates in March during the turnaround.

We expect total direct operating expenses to range between $90 million and $95 million, and total capital spending to be between $35 million to $45 million. 14:24 For the Fertilizer segment, we estimate our ammonia utilization rate to be between 92% and 97% for the quarter.

We expect direct operating expenses to be approximately $50 million to $55 million excluding inventory impacts and total capital spending to be between $4 million and $7 million. 14:40 With that, Dave, I'll turn it back over to you..

Group 3 2-1-1 cracks have averaged $18.09 per barrel; with a Brent-TI spread of $2.93 per barrel; and the Midland differential at $1.14 over WTI. The WTL differential has averaged $0.72 per barrel over WTI and the WCS differential has averaged $13.17 per barrel under WTI.

Fertilizer prices have held firm after increasing significantly in the fourth quarter, ammonia prices with ammonia prices over $1,200 per ton and UAN prices over $550 per ton.

21:22 As of yesterday Group 3 2-1-1 cracks were $17.47 per barrel, Brent-TI was $3.33 per barrel, and WCS was $12.50 under WTI, assuming the high end of the proposed 2022 RVO, RINs were approximately $7.24 per barrel. EPA's persistent failure to comply with its obligations under the RFS has led to current high RIN prices environment.

We're hopeful that EPA would capitalize on the opportunity to fix the situation in setting the 2021 and ‘22 RVOs. Unfortunately, they missed the mark again as RIN prices rose after EPA issued the proposed RVOs in December.

Comment periods end in early February for both the proposed RVO and EPA's proposed denial of outstanding small refinery exemption requests. 22:28 Depending on the final rule making by EPA, we are prepared to file suit if necessary to hold EPA accountable to the law.

In addition to pursuing small refinery exemptions, we believe Wynnewood is entitled to per -- the RFS that it – is entitled to per the RFS, we also may pursue lawsuits regarding EPA's unlawful activities including its failure to rule on small refinery exemption request within the mandated time period, failure to provide 16 month settlement window from the time the initial RVOs are proposed and for damages caused by it unlawful actions and an associated impacts to the market.

These issues are once -- until these issues are resolved, it is likely we will continue to carry a RIN obligation on our balance sheet related to Wynnewood’s RIN obligation as we believe they should be exempt under RFS.

We also believe RIN prices will likely moderate in the future, possibly due to pressure from high gasoline prices or from the resolution of the issues I just mentioned. 23:41 With that, operator, we're ready for questions..

23:46 Thank you. At this time, we'll be conducting a question-and-answer session. [Operator Instructions] Our first question comes from the line of Phil Gresh with JP Morgan. Please proceed with your question..

24:13 Hey. Good afternoon, Dave. Thanks for taking my question..

24:15 Hi, Phil.

24:17 So, just stepping back and kind of looking at the fourth quarter results, it seems that Gulf Coast refiners have put up much better margins quarter-over-quarter than the Mid-Con. You talked about some of the factors that could be influencing that.

Just curious if you think are those transitory factors in your view or structural factors like Brent-TI, backwardation et cetera. So just any thoughts you have there? Thanks..

24:46 Sure, Phil. Well, it's not uncommon for the Mid-Con to go long product during the winter season, so not only the effect of higher RVP, which is allowed under the law, but also just the fact that -- with the Brent-TI at the numbers, it's had, it's still has an incentive to -- everybody has an incentive to run wide open.

And demand typically falls, a little bit, although, not much, but the production of gasoline goes up dramatically, that and a little bit of the volatility in crude price you mentioned backwardation and the fact that there were no real significant refinery interruptions in our market, the base is just kind of blew out and reduced our profitability appropriately therefore.

25:39 So if you look at the Magellan inventories on gas, they're fairly high right now and that's seasonally typical. That's the reason we're doing our Wynnewood turnaround in the first quarter, which is usually the weakest season. I do expect it to recover once demand picks up in the area and the RVP starts to go back down.

As far as the Brent-TI goes it's really related directly to the production of shale oil, which is increasing, but not nearly as much as we would have expected at these kind of crude prices..

26:23 Got it. That's very thorough. Thank you. My follow-up is just around capital allocation. I'm just trying to get my arms around where CVI is headed here because you have the renewable objectives that could require more capital spending.

If you look at Coffeyville or other opportunities, we also -- are talking about maybe segregating that business? And then you think about kind of cash flow generation of the parent company, the RINs liability that's outstanding, so could you just kind of walk through how you're thinking about capital allocation.

Is there a scenario where you consider reinstating dividends or buybacks or do you feel like with these other things that you have on your plate that now is not the right time to look at that?.

27:10 Well, I think from a capital allocation, CVI has always been a cash machine and it's all about cash flow and is what we're all about. I think you've heard us mention that we spent 435 million complying with the -- or at least booked it on our balance sheet of rent expense.

And when you put that in the equation that it kind of just takes our cash flow to a level, we don't really like. So with some rectification to RINs has got to happen and we kind of outlined, a lot of the things that we think we're going to take steps on, but that 435 just kind of wipes out anything we can do.

Our balance sheet is still strong, however and I think we are not far from a position of thinking about dividends again and I know the board talks about it every quarter and that those conversations will continue.

28:12 As far as breaking out the renewables business, I think the thought here is and I think we're all starting to see it in this business anybody is in a fossil fuel businesses that raising money going forward is going to be difficult, and not to mention that renewables probably commands a little higher multiple.

Those two factors, I think are a lot behind our strategy here of breaking this -- change in our corporate structure and breaking it out, or we can raise money under decarbonization flag and have access to the capital markets where the -- a lot of them are being shut by ESG concerns and other things..

28:58 Okay. Great. Thanks for your thoughts..

29:00 You're welcome..

29:03 Thank you. Our next question comes from the line of Manav Gupta with Credit Suisse. Please proceed with your question..

29:08 Hey, Dave. Thanks for all the update on the renewables side. I have a question here.

Some of your peers and others, what they're doing is, that they're building the renewable diesel business, they are bringing in sometimes financial partners who are offering the CapEx and giving some preferred equity, other times they are bringing in a feedstock provider who probably is not offering a CapEx but offering you guaranteed supply of feedstock, and then taking some part of the profits.

And I'm just trying to understand as you build this business out, will it be more like it will be your -- do it yourself or are you open to bringing in financial partners or feedstock partners like how do you plan to build this business alone or with partners?.

29:54 Well, I think we're not real good at sharing but we probably could, in some of these cases and we're not shutting out of that optionality is going forward, particularly in the oil, in the area of bean oil supply or other feedstocks, I think it's having people with something a little more dollars in the skin in the game, if you want to say it that way is not a bad way to go and we're evaluating several deals, several crushers now that look very promising and not only that it's to help us break kind of the monopoly of bean oil where it's controlled by three big players, the ag players and will give us of a lot more optionality than more like you have with the refining business than you do with the vegetable -- vegetable business itself, so we're not opposed to it, but we haven't found those deals yet..

30:53 Okay. And the second question is, you talked about a little bit, help us understand some of the factors which are driving these fertilizer prices so high.

Is it the fact that Europe is struggling to make fertilizer with natural gas prices? What are the, some of the reasons why this high nitrogen or fertilizer price environment could last in 2022 or maybe even 2023?.

31:16 Well, I think you've got to start with the price of corn and soybeans, Manav, and then if you look at soybeans they’re approaching $16 a bushel corn over $6, farmers are pretty flush with incentives to farm and the RFS is broken and continues to put a big demand on corn and if you look worldwide, there is a drought in South America.

All factors are leading towards more demand for these two grains, which drive -- mainly drives fertilizer and even though the cost of fertilizer has gone up, most of our customers are more worried about getting allocated supply, than they are the price.

32:03 And the other reasons the price has gone up so much is what I mentioned in the prepared remarks is the natural gas in Europe has made -- for making fertilizer they’re unprofitable. So about 40% of the plants over there are shut down due to economics.

And you have China and Russia and Egypt, basically hording their what they’re usually exporters and they're hording their production for their own use. So all those factors together and not to mention the Winter Storm Uri and hurricanes that shut down a lot of the U.S. production.

32:40 And the other factor is, there was a trade case against Russia and Trinidad at -- that the U.S. won and there is going to be tariffs on those, those products which are probably going to limit imports for the next year or maybe even five years, just because those tariffs are fairly steep. So that's kind of the perfect storm I was referring to..

33:06 Perfect. And last, very quick one, I've asked you this before, looks like EPA is tilting towards declining all SREs, you have fought them before, you even taken them to Supreme Court and won.

So are you guys getting ready for around 2 for what you believe is rightfully yours?.

33:23 Yeah. I mean the comment period is up on their proposed denial of all small refinery waivers. And I think the responses were pretty, pretty dramatic.

If I know EPA, they'll basically ignore them all and just go like they want to and the next day we will -- as soon as they deny in the Federal Register all these small refinery waivers will be filing our lawsuit that minute..

33:52 Thank you so much..

33:53 You're welcome..

33:56 Thank you. Our next question comes from the line of Carly Davenport with Goldman Sachs. Please proceed with your question..

34:01 Hi. Good afternoon. Thanks for taking the questions. Just wanted to start on the decarbonization strategy, you mentioned in the prepared remarks. You’ve talked a lot about the renewable fuels piece, but wanted to get your thoughts on some of the other decarbonization efforts you're considering.

Is there anything to share on the CCS side or SAF that you think would be a good fit for your business?.

34:23 Well, it's early yet Carly, but what we are looking at is, and I think we're uniquely positioned to once again for this because of today, we do have -- in our Fertilizer business, we do sequester CO2 for enhanced oil recovery and we have a pipeline system. We're connected to a pipeline system is owned by a third-party.

But there isn't any reason we can extend that to both of our refineries and use RECOVER available CO2 that is as out there today.

So for example, I’ll give you a couple of examples, like the RD unit at Wynnewood that we're building requires the hydrogen plant to run, which makes a 35%, 40% concentrated CO2 stream which we can purify further and stick in either that pipeline or a new pipeline getting to it and sequester that recover 45Q credits.

Not only that monetize it in the low-carbon fuel standard credits through R&D and that's just one example. We also have a concentrated stream in our FCC stacks of CO2. We could recover those.

So there is a slew of stuff there, and there is also a real case to be considered on using hydrogen as fuel instead of natural gas itself within a refinery that it really hit Scope one and Scope 2. We would likely look at that in some detail and look at building a utility business around that to decarbonize the fuel refineries use.

So there's a lot of options here that that we think are exciting and we'll be pursuing over the next couple of years..

36:05 Great. Thanks for that color and the context. The follow-up is just around backwardation and you flagged some of the impacts on capture rates there during the quarter.

Is that something you're able to quantify what the impact was on capture in the quarter? Are there any kind of sensitivity you can provide as, we think about go forward captures given the current curve structure?.

36:27 Well, it's pretty much a one for one proposition that's comes right off of your crack. So what right now, we're about $1.20 -- between $1.20 and $1.50 of backwardation. I would just make the assumption that's that comes right off the crack..

36:47 Great. I appreciate that..

36:51 You’re welcome..

36:54 Thank you. Our next question comes from the line of Matthew Blair with Tudor, Pickering, Holt. Please proceed with your question..

37:00 Hey. Good morning. I was hoping you could help us think about fertilizer pricing realization for the first quarter here, it looks like in Q4 is only about 60% or so of the benchmarks and normally you're closer to 80%.

Just wondering, if we can pencil-in 80% for Q1 or if there are other -- some other moving parts we need to take into consideration?.

37:26 Well, we do have an industrial business, that's part of one of our plants, that's fairly large. So those, those are formula prices that take a while to ramp up. As far as the open book goes, as most of the stuff that we've booked in the spring and the early first half of the year, I should say are all at these higher prices.

So you'll see it factor in largely in the first quarter and second quarter. And then it's kind of a question where does the market go from there? It's not atypical for fertilizer to see a drop in price post the summer time side-dress and other activities at farmers do until the harvest occurs and then they start to apply ammonia again.

So we think it's pretty still pretty strong. But it's hard to say exactly what will happen in that second half, just because we have the order book is pretty much complete on a vast majority of the ammonia we're going to make in UAN, we're going to make in the first half..

38:31 Great. Okay. Sounds good. And then on the, on the R&D front, Dave, how would you assess the availability of RBDs soybean oil for your upcoming start up. We saw last year where the pricing really blew out relative to the crude soybean oil.

So, has there been a material improvement in overall supplier or you kind of, watching that kind of careful on what your start might do to that RBD market?.

39:05 Well, you remember Matt that we postponed, we could have started this up last year and we postponed because the basis for bean oil was so high, it’s over $0.30 a pound.

It's down in the $0.14 now and it's kind of maintained there, it took a while for all the trade flows to rebalance, but they have done that now and it's pretty steady at that, I'll call it $0.14 to $0.20 somewhere in that range. And at that point, we're profitable where we're at now and that's why we're doing the conversion now.

So I don't see a real big problem with the availability of it. We'll have to look for other feedstocks as we've always said. And with our pretreater it gives us that option.

But we've also got a pretty good source of corn oil that's that is suitable to run without a pretreater and it's -- it has a little higher basis than what bean oil has, but it's also a lower CI. So with that mix, we feel we can make money in the short-haul and offset a lot of revs..

40:19 So if that basis flows out again after you start up your plant, what do you, do you shut your plan in response to economics or do you just keep producing until your pretreater comes on?.

40:32 Well, we probably keep running, but I don't anticipate that happening. Our move is not huge. And some of the others coming on are claiming they're easing used oil and tallow and other things. And the fact of the matter is we have about a two months of feedstock and inventory. So we're not going to shock the market like it was seen last time..

40:58 Great. Thank you..

40:59 A lot of these are getting delayed to Matt. Some of them are coming on later and later. So that would just help rebalance trade flows..

41:08 Right. Good point. Thank you for all the color..

41:12 Thank you. Our next question comes from the line of Paul Cheng with Scotiabank. Please proceed with your question..

41:20 Hey, guys. Good afternoon..

41:23 Hey, Paul..

41:25 I think -- how do you, you're saying that you are going to reorganize and that partly done by early next year.

That means that from a financial reporting, you're going to way until then before you start reporting the RBD profit in your quarterly results or that anyway you would go ahead and start doing that before them? And also, you're talking about that become a different business.

Will you be looking at a merging the plan outside your refinery location and also that when you're looking at future, what comp payback period and IRR requirement for those investments?.

42:12 sure, Paul. The, probably the latter. first, as I think we would look at probably the same return, we look at in refining businesses. I don't view the -- I think the renewable business is going to be just as competitive as the refining, it's ultimately going to trade that way.

So there's really no difference in that from our approach standpoint of that. Your other question on what we were reporting as a separate segment, yes, as soon as appropriate. We'll have optionality with this restructuring. We don't have to spin it off as a separate company.

We couldn’t keep it under where we are, or we have the option to do that, if the market dictates that that should be done.

Again, the reason we're doing this is we think renewables commands a higher multiple as well as we're worried as much as anything about our financing going forward as more ESG takes, hard and we're already starting to see banks not want to participate in fossil fuel type businesses. So that's what we're planning for the future..

43:24 And Dave, when you looking at, even it is anticipation or RD plan.

I mean, the next one, obviously, you're looking at cost of you, and after that, are you guys looking how inside your refinery location as good would as [indiscernible] or that or are you going to look at for RD and then you would be looking at all basically other opportunities like what you say CSF and other things?.

43:51 Well, I think I think a lot of this decarbonization is going to turn into an opportunity of people that want to participate in that value chain as a -- as potentially installing us for other plants and taking an ownership it's no different than the hydrogen plants today are owned by third-parties typically, I can see decarbonization owned by third-parties just as a like and that helps us refiner decarbonize as well as monetizing that through a separate corporation.

We have a wide-open space..

44:30 Okay. And then I just wanted to go back, you're saying that you could -- we put them as a separate segment when it is appropriate.

That means that is -- this year that you're going to start up in the second quarter, should we assume by the second quarter, you will start doing it or that it’s going to take a number of quarters before you do that?.

44:52 Well, I think, that would be an appropriate time, just what I'd call it is to start reporting that as soon as we can get our ducks in a row and have that happen..

45:01 Okay.

And since that you're plan always on at least for Wynnewood is that once you have the plan and you will have the flexibility for them to switch depends on the market condition go back into the conventional refining versus out the mixing? How long is the lag effect -- how long it take in order for you to make that switch in terms of that –.

45:32 About 30 days to make the switch once you decide, but the practicality of it is, you're going to do it in some kind of cycle is the fact of matter is you're replacing catalyst on the RD of every, probably every year or less and that gives you a chance to look at it, each time that that happens.

Once you put -- back in hydrocracker service you probably want to have a good runway to run it. So you're not going to do that on without a lot of thought and a whole lot of thought around what the market forward is on refining..

46:09 So in practical matter is probably not more than once a year that and if you do make the switch you end up that has to be convinced for the subsequent 12 months that you will run in that particular form?.

46:23 Yeah, that's right..

46:26 And also that, can you tell us that once that you start up the RD, how we find the Wynnewood refinery.

I think you will reduce the capacity by 19,000 barrels per day, so how the throughput and also the product yield is going to change to?.

46:47 Yeah. And well, that 18,000 barrels is an old number. We've really come back to about – well around about 70 at Wynnewood with RD and we'll go to a like feedstock to accomplish that.

So what we're after there is naphtha to make hydrogen to make RD with and that we are uniquely positioned there, because we can gather those kinds of crudes in the field and bring them in with our proprietary pipelines..

47:16 Do you have an estimate, what is your gasoline and business view will look like after you make the switch?.

47:24 Yeah. Well distillate yield won't go down, and that's the main opportunity cost here is, because we will lose the hydrocracker which is a big distillate maker. So you're going to rely more on cat cracking post RD than you do today and you'll see switch you'll probably see loss of 15% of the diesel yield as a result..

47:47 Thank you..

47:48 You’re welcome, Paul..

47:51 Thank you. Ladies and gentlemen, that concludes our question-and-answer session. I will turn the floor back over to management for any final comments..

47:59 Again, I'd like to thank you for your interest in CVR Energy. Additionally, I'd like to thank all our employees for their hard work and their commitment towards safe, and reliable environmentally responsible operations. We look forward to reviewing our first quarter 2022 results during our next earnings call. Thank you..

48:20 Thank you. This concludes today's conference. You may disconnect your lines at this time. Thank you for your participation..