CVR Energy, Inc., (NYSE:CVI) Q2 2022 Results Conference Call August 2, 2022 1:00 PM ET
Company Participants
Richard Roberts – Vice President of FP&A and IR
Dave Lamp – President, CEO & Director
Dane Neumann – EVP, CFO, Treasurer & Assistant Secretary
Conference Call Participants
Carly Davenport – Goldman Sachs
Manav Gupta – Credit Suisse
John Royall – JPMorgan
Matthew Blair – Tudor, Pickering and Holt
Paul Cheng – Scotiabank
Operator
Greetings, and welcome to the CVR Energy, Inc., Second Quarter 2022 Conference Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. [Operator Instructions] As a reminder, this conference is being recorded.
I would now like to turn the conference over to your host, Mr. Richard Roberts, Vice President of FP&A and IR for CVR Energy, Inc. Thank you. You may begin.
Richard Roberts
Thank you, Melissa. Good afternoon, everyone. We very much appreciate you joining us this afternoon for our CVR Energy second quarter 2022 earnings call. With me today are Dave Lamp, our Chief Executive Officer; Dane Neumann, our Chief Financial Officer; and other members of management.
Prior to discussing our 2022 second quarter results, let me remind you that this conference call may contain forward-looking statements as that term is defined under federal securities laws. For this purpose, any statements made during this call that are not statements of historical facts, may be deemed to be forward-looking statements. You are cautioned that these statements may be affected by important factors set forth in our filings with the Securities and Exchange Commission and in our latest earnings release.
As a result, actual operations or results may differ materially from the results discussed in the forward-looking statements. We undertake no obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise except to the extent required by law.
Let me also remind you that the CVR Partners completed a 1-for-10 reverse split of its common units on November 23, 2020. Any per unit references made on this call are on a split-adjusted basis. This call also includes various non-GAAP financial measures. The disclosures related to such non-GAAP measures, including reconciliation to the most directly comparable GAAP financial measures are included in our 2022 second quarter earnings release that we filed with the SEC and Form 10-Q for the period and will be discussed during the call.
With that said, I’ll turn the call over to Dave.
Dave Lamp
Thank you, Richard. Good afternoon. Thank you for joining our earnings call. Yesterday, we reported our second quarter consolidated net income of $239 million and earnings per share of $1.64. EBITDA for the quarter was $401 million. Fundamentals in Refining and Fertilizer segment continued to improve during the second quarter. And once again, we posted improved results in both segments on a year-over-year basis, though this was offset by a legal accrual in our corporate segment.
We are pleased to announce, in addition to the second quarter regular dividend of $0.40 per share, the Board has also authorized a special dividend of $2.60 per share, both of which will be paid on August 22 to shareholders of record at the close of the market on August 12. At yesterday’s closing price, the combined annual dividend of $1.60 per share and the special dividend of $2.60 per share represents a dividend yield of nearly 13%, which is currently the most — almost 4x the average dividend yield among independent refiners.
For our Petroleum segment, the combined total throughput for the second quarter of 2022 was approximately 201,000 barrels per day with Wynnewood completing its planned turnaround on time and on budget in early April. This compares to 217,000 barrels per day in the second quarter of 2021. With the hydrocracker conversion at Wynnewood to renewable diesel service, we expect crude throughput at Wynnewood to be reduced by approximately 5,000 barrels per day going forward.
Benchmark cracks increased throughout the quarter. The group 2-1-1 crack spread averaged $48.50 per barrel in the second quarter as compared to $19.15 in the second quarter of 2021. Based on 2021 and 2022 RVO levels that were finalized in June, RIN prices averaged approximately $7.58 per barrel in the second quarter, a decrease of 7% from the second quarter of 2021. The Brent-TI differential averaged $3.38 per barrel in the second quarter compared to $2.91 per barrel in the prior year period.
Light product yield for the quarter was 98% on crude oil processed. Our distillate yield as a percentage of total crude oil throughput was 43%. Despite the conversion of the hydrocracker at Wynnewood to renewable diesel service, we have widened our crude slate at Wynnewood, and we have not seen a material decline in our distillate yield. We continue to operate our refineries in max distillate mode.
In total, we gathered approximately 126,000 barrels of crude oil during the second quarter of 2022 compared to 118,000 barrels per day for the same period last year. Our crude oil gathering rates have increased on both a quarter-over-quarter and a year-over-year basis, and we are encouraged to see producers start to ramp activity in the Anadarko basin.
The renewable diesel unit at Wynnewood began operations in mid-April and is processed — and processed approximately 3,100 barrels per day of vegetable oil feedstocks during the quarter. We have been gradually increasing the rate over the past few months. The HOBO spread averaged a negative $1.95 per gallon for the second quarter but increased to a negative $1.33 per gallon in June. With the increases in diesel prices and the improvement in the HOBO spread, recently, we’re assuming positive economics from the renewable diesel unit.
In the Fertilizer segment, we faced some unplanned downtime at both plants during the quarter, with consolidated ammonia utilization coming in at approximately 89%. Sales volume for the second quarters were impacted — second quarter of ’22 were impacted by a late start to the spring planning, along with some demand destruction as a result of higher fertilizer price environment. Lower sales volumes were more than offset, however, by increased price realizations, which drove strong results for the quarter. Global supply of nitrogen fertilizers remains tight. And with continued upward pressure on energy prices in Europe, we believe high fertilizer price environment could continue into 2023.
Now, let me turn the call over to Dane to discuss additional financial highlights.
Dane Neumann
Thank you, Dave, and good afternoon, everyone. For the second quarter of 2022, our consolidated net income was $29 million, earnings per share was $1.64, and EBITDA was $401 million. Our second quarter results include a legal accrual of $79 million, a negative mark-to-market impact on our estimated outstanding RIN obligation of $51 million, unrealized derivative losses of $21 million and favorable inventory valuation impacts of $41 million. Our estimated outstanding RIN obligation is based on the 2020, 2021 and 2022 RVOs that were recently finalized in June and excludes the impacts of any waivers or exemptions.
Excluding the above-mentioned items, adjusted EBITDA for the quarter was $511 million and adjusted earnings per share was $2.45. The Petroleum segment’s adjusted EBITDA for the second quarter of 2022 was $383 million compared to $18 million for the second quarter of 2021. The year-over-year increase in adjusted EBITDA was driven primarily by increased product cracks and over average RINs prices, offset somewhat by lower throughput volume and realized derivative losses.
In the second quarter of 2022, our Petroleum segment’s reported refining margin was $26.10 per barrel. Excluding the mark-to-market impact of our estimated outstanding rent obligation of $2.79 per barrel, favorable inventory impacts of $2.02 per barrel and unrealized derivative losses of $1.20 per barrel, our refining margin would have been approximately $28.06 per barrel. On this basis, capture rate for the second quarter of 2022 was 58% compared to 31% in the second quarter of 2021.
RINs expense, excluding mark-to-market impacts, reduced our second quarter capture rate by approximately 11% compared to a 31% reduction in the prior period. RINs expense for the second quarter of 2022 was $153 million or $8.34 per barrel of total throughput compared to an expense of $173 million or $8.77 per barrel for the same period last year. As a reminder, our reported RINs expense does not include the impact of any waivers or exemptions.
Our second quarter RINs expense includes a $51 million mark-to-market impact on our estimated accrued RFS obligation which includes a $55 million benefit from the lower RVOs that were finalized in June. The estimated accrued RFS application on the balance sheet was mark-to-market at an average RIN price of $1.61 at quarter end compared to $1.37 at the end of March.
For the full year 2022, we forecast an obligation of approximately $150 million RINs, which includes approximately $85 million RINs expected from renewable diesel production but does not include the impact of any waivers or exemptions.
Derivative losses in the Petroleum segment totaled $61 million for the second quarter of 2022, which includes unrealized losses of $22 million, primarily associated with crack spread derivatives. In the second quarter of 2021, we had total derivative losses of $2 million, which included unrealized losses of $37 million, primarily associated with the crack spread hedges that were closed at the end of the third quarter of 2021.
The Petroleum segment’s direct operating expenses were $6.12 per barrel in the second quarter of 2022 as compared to $4.23 per barrel in the prior year period. The increases in direct operating expenses were primarily due to higher personnel costs, in part due to share base compensation due to the increased stock price as well as increased natural gas prices and repair and maintenance costs.
For the second quarter of 2022, the Fertilizer segment reported operating income of $126 million, net income of $118 million or $11.12 per common unit and EBITDA of $147 million. This compared to second quarter 2021 operating income of $30 million, net income of $7 million or $0.66 per common unit and EBITDA of $51 million. There were no adjustments to EBITDA in either period.
The year-over-year increase in EBITDA was primarily driven by higher UAN and ammonia sales prices, offset somewhat by lower sales volumes. The partnership declared a distribution of $10.05 per common unit for the second quarter of 2022. As CVR Energy owns approximately 37% of CVR Partners common units, we will receive a proportionate cash distribution of approximately $39 million.
Total consolidated capital spending for the second quarter of 2022 was $41 million, which included $19 million from the Petroleum segment, $9 million from the Fertilizer segment and $12 million on the Renewable Diesel unit. Environmental and maintenance capital spending comprised $28 million, including $19 million in the Petroleum segment and $8 million in the Fertilizer segment.
We estimate total consolidated capital spending for 2022 to be approximately $195 million to $224 million, of which approximately $134 million to $148 million is expected to be environmental and maintenance capital. Our consolidated capital spending plan excludes planned turnaround spending, which we estimate will be approximately $80 million to $85 million for the year for the recently completed planned turnaround at Wynnewood and in preparation for the planned turnaround at Coffeyville in 2023.
Cash provided by operations for the second quarter of 2022 was $390 million and free cash flow was $275 million. Significant cash uses in the quarter included $115 million for CapEx and turnaround spending, $59 million for income tax, $40 million of dividends, $19 million of interest and $15 million for the non-controlling interest portion of the CVR Partners’ first quarter distribution.
Turning to the balance sheet at June 30. We ended the quarter with approximately $893 million of cash. Our consolidated cash balance includes $156 million in the Fertilizer segment. As of June 30, excluding CVR Partners, we had approximately $983 million of liquidity, which was primarily comprised of approximately $737 million of cash and availability under the ABL of approximately $246 million. In June, we completed the amendment of the ABL agreement, rightsizing the facility to $275 million, extending the maturity five years, removing cash from the borrowing base and potentially adding renewables inventory.
Looking ahead to the third quarter of 2022, for our Petroleum segment, we estimate total throughput to be approximately 190,000 to 205,000 barrels per day. We expect total direct operating expenses to range between $90 million and $100 million and total capital spending to be between $30 million and $35 million.
For the Fertilizer segment, we estimate our third quarter 2020 utilization rate to be between 60% and 65% as a result of the two plant turnaround for the summer. We expect direct operating expenses to be approximately $60 million to $65 million, excluding inventory and turnaround impacts and total capital spending to be between $22 million and $27 million. Turnaround spending is expected to be $30 million to $35 million of expense. For renewables, we estimate third quarter 2022 total throughput to be approximately 4,500 to 6,000 barrels per day and direct operating expenses to be between $2 million and $4 million.
With that, Dave, I will turn it back over to you.
Dave Lamp
Thank you, Dane. In summary, we are proud of our strong results for the second quarter of 2022 and pleased to be returning $3 per share in dividends to our shareholders. Tight supply and demand fundamentals in both Refining and Fertilizer businesses contributed to the strength in our consolidated results, and we believe the outlook for the near term continues to be favorable for both businesses.
Starting with Refining. Domestic and global inventories of crude and refined products remain below five-year average levels, driven by a combination of demand returning to pre-COVID levels and global refining capacity being reduced by approximately 5 million barrels per day. We’re starting to see some demand destruction as a result of increased prices, particularly for gasoline, with U.S. vehicle miles traveled travel turned negative in April and May compared to the same periods in ’19. More specifically to the Mid-Con, we have seen some tapering in gasoline and distillate demand but both are still comfortably within the five-year average levels.
Looking at crude oil, inventories are still on the low side and have been distorted to some degree by the sales from the strategic petroleum reserve. The SBR sales have also distorted inland crude differentials, and we have seen a widening of WCS differentials despite little or no production growth in that area. With crude oil prices comfortably in the $100 barrel per barrel range, we’re starting to see more activity in our backyard as evidenced by our increased crude oil gathering rates in the second quarter.
We believe at these crude oil prices, we could see further acceleration in drilling activity, although E&P companies continue to gravel with investor calls for capital discipline, along with limited available availability of manpower well services, steel and continuing with general cost inflation. Underinvestment in upstream activities over the past seven years is evident worldwide, and is part of the reasons we are seeing the prices where they are today. The main concern, however, continues to be the potential and the severity of a global recession that could impact demand.
Turning to refined products. crude spreads in the second quarter reached levels that are typically only seen during a hurricane or some other major disruption and even then, only for a short period of time. It is possible that cracks peaked in the second quarter. As I’ve said many times, the best cure for high prices is high prices, and we are seeing the effects of high prices on demand in the market today.
Utilization across the U.S. refining fleet has been very high at 95%, and there is still quite a bit of maintenance scheduled for the second half of the year. Despite the decline in the peaks of the second quarter, crack spreads are still incredibly strong today, particularly for diesel, where cracks are significantly better than gasoline. The forward curve for the Group 3 distillate crack is nearly $43 per barrel for calendar year ’23 and over $37 per barrel for calendar year ’24.
Although it has not been discussed much recently, we believe IMO 2020 is having a meaningful impact on the price of diesel with nearly 1 million barrels of diesel headed to bunker fuel markets in order to meet sulfur specs. We also see a material impact on the price of gasoline for the renewable fuel standard, which is adding approximately $0.30 per gallon to the retail prices and is incentivizing refiners to export as much fuel as possible. If the government were serious about doing everything in its power to bring down the price of gasoline, fixing RFS and bringing down our RIN prices would be a very quick and easy solution.
In the Fertilizer segment, we had a strong second quarter results despite cold and wet weather across the Mid-Continent significantly delayed the planting season. We also believe there’s some demand destruction as a result of the high fertilizer pricing environment. Once again, high prices are the best cure for high prices. Looking ahead, we believe the world remains tight on nitrogen fertilizer supply. And with a persistent high natural gas price in Europe, the floor for natural gas pricing is significantly higher than it’s been in the past few years. The summer fill program for ammonia and UAN were both recently completed at favorable pricing, and we expect prices to continue to increase in the fall.
We have turnaround scheduled at both fertilizer plants for the third — in the third quarter with Coffeyville nearly complete and East Dubuque starting in a couple of weeks. Following the completion of these turnarounds, we do not have any planned activity for the Fertilizer segment until ’24 at the earliest.
Finally, in the Renewable Diesel business, we are seeing improved fundamentals with the HOBO spread averaging less than $1 per gallon, a negative in the past month. Offsetting this somewhat is continued weakness in the low carbon fuel standard credits in California, which have fallen to around $80 to $90 — $90 to $95 per ton. When taking into account the expected credit values from our blended soybean oil and corn oil, we see an advantage see an advantage to sending the product out to California at these levels.
Total throughput volumes in July were approximately 3,600 barrels per day, and we continue to ramp up the full production. In October, we’re planning our first catalyst change, which will take the renewable diesel down for about 20 days. We are also continuing to work on the pretreatment unit, which is expected to be complete and online in the second half of ’23. With the addition of the PTU unit, we believe we could see margin improvement in the renewable diesel of approximately $1 per gallon.
As we discussed over the past few quarters, we continue to make progress on the reorganization of the Company to segregate the renewables business. We have created 17 new entities internally and in early July, completed the distribution of certain refining real estate assets into the appropriate entities. We anticipate completing the reorganization in the first half of ’23 and intend to begin reporting separate renewable segments when appropriate.
Looking at the third quarter of ’22, quarter-to-date metrics are as follows: Group 2-1-1 cracks have averaged $45.58 per barrel with a Brent-TI of $5.32 per barrel and a Midland differential of $1.67 over WTI. The WTL differential has averaged $0.49 over WTI and the WCS differential has averaged $19.70 per barrel under WTI. Fertilizer prices remained strong as well with ammonia prices over $950 per ton and UAN prices over $450 per ton.
As of yesterday, Group 3 2-1-1 cracks were $33.85 per barrel, Brent-TI was $7.64 per barrel and WCS was at $20.75 under WTI. RINs were approximately $7.90 per barrel. Ammonia prices were about $1,000 a ton and UAN prices are about $450 per ton.
In June, with the EPA finally announced the ’21 and ’22 RVOs along with an adjustment to the 2020 RVO, at the same time, it denied all small refinery waiver requests. These announcements only cause RIN prices to move higher as the blending mandates were once again set at levels that are unachievable, particularly for small and merchant refiners. As we have continuously stated, we believe Wynnewood’s obligation should be exempt under RFS as intended by Congress.
We have challenged EPA’s unlawful denial of our small refinery exemptions for 2018 through 2021, and will vigorously pursue this in court. We continue to fight for the rights we believe Wynnewood is entitled to and will continue to carry an obligation on our balance sheet related to Wynnewood’s outstanding rent obligation.
Although the misguided actions by EPA are troublesome and ultimately hurting the American consumer at the pump, we are pleased with our strong results for the second quarter and are optimistic about the near-term outlook. We will continue to focus on safe, reliable operations of our assets in an environmentally responsible manner to ensure we are ready to capture any market opportunities that they develop.
With that, operator, we’re ready for questions.
Question-and-Answer Session
Operator
[Operator Instructions] Our first question comes from the line of Carly Davenport with Goldman Sachs. Please proceed with your question.
Carly Davenport
I wanted to just start on the capital return side. As you think about the current macro, can you talk about your priorities from a capital allocation perspective? Is there a preference to continue to look at incremental special dividends from here? Or is there a potential for further growth in the regular dividend or around buybacks?
Dave Lamp
Sure, Carly. As we’ve said many times, we’re a company that returns cash to the shareholders as soon as we have no better use for it. And I don’t think we’ll see any change in that strategy as evidenced by our special this time. And I don’t know that the Board will continue to select special dividend as the mechanism or increase the regular, but it will be revisited every quarter and decisions will be made around that as we go forward. But bottom line is our commitment is to return cash to shareholders.
Carly Davenport
Great. And then the follow-up was just around Wynnewood renewable diesel. Can you just give us some color in terms of how the asset has been performing from an operational perspective? What you’ve learned from starting that up? And then perhaps how the potential extension of the blenders tax credit could impact your future views on incremental renewable fuels plans going forward?
Dave Lamp
Sure. Well, we’ve really had no problems making this conversion to renewable diesel from an operating standpoint. Logistics have been more of a challenge for us. Just getting the railroad in tune with our needs to deliver soybean oil and corn oil on a timely basis as well as remove product on a timely basis has been some of our bigger challenges, but we continue to work through those, and they’re all coming to be.
I think some of the things that have developed in the business ourselves is we have begun to look at sourcing some pretreated feed. That looks very attractive to us. Not only that will happen before our pre-treater is online or potentially before our pre-treaters online. But even with the pre-treater sourcing feedstock doesn’t appear to be any concern. We can easily do it. And really, our challenge going forward is really around sourcing more of the lower CI materials and we continue to work that strategy as we go. But overall, it’s been a pretty straightforward easy conversion.
Operator
Thank you. Our next question comes from the line of Manav Gupta with Credit Suisse. Please proceed with your question.
Manav Gupta
Congrats on a very good quarter. I just wanted to follow up a little bit on the PTU side. I might be wrong, but I think we were modeling it a little sooner, I think, somewhere around second quarter. So I would like to understand why is it moving? Or if it’s moving back a little? And also when we think about this as a reportable segment, should we basically assume that you will report it once the PTU starts then it kind of can become its own reportable segment, if you could just talk about those two things?
Dave Lamp
Sure. I think we’ve mentioned our strategy going forward is to maintain our refining assets going forward, but very little investment, except for sustaining capital turnarounds and keeping them a good working order. The reason for breaking out renewables as a business is that’s where our future dollars are going should the markets develop. So our plan is to report as a separate segment when appropriate.
I don’t know that it will be triggered off of the PTU or not. It’s more around the restructuring and getting our systems built — the financial systems built to be able to accomplish that. And that would, at best, would be probably the second quarter of next year, maybe later.
As far as the PTU moving back a bit, yes, I think it’s just engineering, just some of the supply problems have caught us a bit and moved us to back of the quarter on that. We originally thought we’d be in it in the second quarter. I think it’s more likely that it will be in the second half some time — maybe and towards the end of the second quarter — the third quarter, somewhere in that time frame that we have — actually have it up and running.
Manav Gupta
Perfect. And a quick follow-up here is if you could help us understand your outlook on the brand WTI spread? Is it only a function of SPI releases and other things? Or is it also a function of actual inland volumes starting to grow? If you could just give us a medium- to near-term cycle outlook on the Brent-WTI side?
Dave Lamp
Sure. Well, I’ve always said that Brent-TI is very dependent on shale oil production. And Permian is growing nicely. The rest of them are kind of anemic. We are starting to see a little bit in the basin. But if you look at the Bakken, it’s pretty flat. The Eagle Ford is fairly flat. Niobrara is fairly flat. DJ is fairly flat. So I think we’re in the early throes of that starting to happen.
But until rig count continues to grow, I think the strategic petroleum reserve releases are probably influencing the Brent-TI as much as anything. But we’re optimistic that as shale all grows that — and there’s still plenty of takeaway capacity that the Brent-TI will widen to force barrel’s offshore because once again, the ability of the U.S. fleet to run light Midland type crudes is very limited and basically full.
Operator
Thank you. Our next question comes from the line of John Royall with JPMorgan. Please proceed with your question.
John Royall
So could you give a little more color on the near-term fundamentals in the Fertilizer business? I know it was a difficult planting season this year and there’s also been this decision by the ITC to waive certain tariffs. So just looking for an update on how you think about the back half shaping up, and I know you’ll be impacted by turnarounds there, but just more on the fundamental picture over the near term?
Dave Lamp
Well, I think the prices are still very, very strong even at levels they’re at today. I don’t think there’s anything that’s going to — that I can see is going to change that. The tariff situation was a disappointment. But frankly, it’s not the driver of the market right now. It’s all natural gas in Europe and pricing there. A good number of the plants there are shut down because of high natural gas prices.
They’re actually importing ammonia to run their upgraders, and that’s really about all they’re doing. And I don’t see that situation changing. In fact, we just had another big uptick in natural gas prices approaching $60 a million BTUs. That puts ammonia at $1,800, almost $2,000 a ton. So those fundamentals are very, very strong and probably are not going to change in the short term unless there’s a resolution to the Ukraine or and Russia stops its activities with maintenance and other things designed to start Europe from natural gas. So, we’re very bullish on fertilizer prices and demand.
John Royall
Great. That’s really helpful. And then just switching over to the side, you spoke a little bit on the fundamentals there. But is there any update you can provide on how you’re thinking about the potential conversion of the hydro treater at Coffeyville? I think last quarter you were sort of characterizing it as somewhat of a wait and see. There has been some kind of new slow since then. We have the national LCFS program in Canada is starting next year, potential for renewal of the BTC. So just any update on kind of how you’re thinking about that project?
Dave Lamp
Yes. I think we’re still — this is probably a $650 million project. So it’s a big one for us, and it’s — we really need to see some other states opt into renewables in a carbon fuel standard or frankly, a pivot of the RFS, which — with the reset coming up, that could happen and RFS pivot towards a low carbon fuel standard. And those would move it.
As far as the BTC goes, all we get is extensions, two years, two years, one year. That’s hard to plan a business around when you have that level of uncertainty. All that said, I think our desire is we have a project that’s scoped and ready, and we’ll be able to pull the trigger when that — when we feel that timing is right. I don’t think it’s there yet.
Operator
Our next question comes from the line of Matthew Blair with Tudor, Pickering and Holt. Please proceed with your question.
Matthew Robert
The reporting showed, I believe, 6,000 barrel WCS runs in the second quarter at your refinery. But are you still piping down extra WCS barrels and reselling them at Cushing and getting the economics there? And if so, could you remind us on the volume?
Dave Lamp
Sure. We have pipelines based on paper of 35,000 barrels per day, were usually restricted or have been in the past to about 30,000 of delivery. So, when that arb is open, we’ll not only meet our own needs and we’re limited to about 12,000 barrels a day at our Coffeyville refinery on runs, but we’ll sell the rest in Cushing.
And frankly, we’re looking at other alternatives to sell it on the Gulf Coast also. But generally, we sell in Cushing today. And that is typically whatever is left from what we don’t run at our Coffeyville refinery. And that market is pretty liquid and we pretty much are always in the money on it. Our cost to deliver from Canada is about $6 — a little over $6. And typically, we’re making money on those sales.
Operator
Our next question comes from the line of Paul Cheng with Scotiabank. Please proceed with your question.
Paul Cheng
Maybe that I missed it. Dane, can you just remind us that how much is the — on the balance sheet for the obligation that you need to settle for this year and next year?
Dane Neumann
Yes, Paul, the total obligation on our balance sheet as of the end of the quarter was $708 million, and that’s for all 2020, 2021 and 2022 open positions.
Paul Cheng
And so those of next year, right, — this year, that has nothing to set up?
Dave Lamp
Yes.
Paul Cheng
No, I’m saying that that entire amount, it is 2020 — 2021 and ’22. So Dane, the deadline for the settlement is next year between the first quarter and the third quarter. So this year, you’re not going to have any cash settlement on the balance sheet — related to the balance sheet obligation?
Dave Lamp
Yes.
Paul Cheng
And then when you say $708 million or 708 million RIN?
Dave Lamp
That is dollars.
Paul Cheng
Okay. And that just curious that, Dave, with the diesel crack way we are, is it the battle for you that to run the going to run the conventional oil? Or that — I mean that why that you were still wondering for the out even though it may be a positive contribution at this point, but I would imagine it’s going to be far more positive contribution if you run the conventional oils? How quickly you can?
Dave Lamp
Well, Paul, I think as we’ve said, we get the choice to make the decision every time we do a catalyst change. And we made the decision to convert the RD. And I think it’s been a good one even with the cracks where they are, I can argue the opportunity cost was pre-hiring that period of time. But the incentive to run RD has not been bad either with the HOBO spread being where it’s been.
We’ll look at when we do this catalyst change, but I think we’ll probably stay in RD because you can’t — the practicality is you can jump in now a little bit, but it takes railcars, it takes a lot of set up logistics to get it going. And unless we just see a train wreck, I don’t think you’ll see us convert that.
Paul Cheng
I see. And typically, how long is the change on the catalyst, that be 18 months to two years or is longer?
Dave Lamp
No. On RD, it’s at full capacity, we’re estimating between six months of the year like — so we got every six months, basically.
Paul Cheng
And that two really quick questions. On the dividend, is there a formula approach or that is really purely on the discretionary? But when you determine, say, $2.60, I mean how exactly is the fourth process, that’s the right number?
Dave Lamp
Well, Paul, it’s somewhat subjective to the Board makes that decision every time. We’re going to cover our — maintaining our assets, sustaining capital. We’re going to recover our turnaround costs. We’re going to cover our interest charges on any debt we have. And then, we’re going to — we have to buy crude on a monthly basis, and we’re going to cover those expenses.
So that’s how the Board generally looks at it, and our also another consideration. But that — it’s just an every quarter look where we sit on cash, and the volatility of the cracks drives those numbers up and down like, as you might imagine.
Paul Cheng
Right. Okay. And final one with the rising fear of recession, the impact your balance sheet management in terms of like how much cash balance that you want to keep? And what is the cash return? I mean how that factor is being built in into your thought process?
Dave Lamp
Well, I mean, the price of crude matters is that crude settlement they it grows with the higher prices. So — and then we also have to be careful of the inventory we hold that gets revolved and that’s cash out the door, should that have — should crude drop in half, for instance. So, we consider all those factors. And typically, our cash — minimum cash balance is between $250 million at low crude prices and $500 million at high crude prices.
Operator
Thank you. Ladies and gentlemen, that concludes our question-and-answer session. I’ll turn the floor back to management for any final comments.
Dave Lamp
Again, I’d like to thank you all for your interest in CVR Energy. Additionally, I’d like to thank our employees for their hard work and commitment towards safe, reliable, and environmentally responsible operations. We look forward to reviewing our third quarter ’22 results in our next earnings call.
Thank you.
Operator
Thank you. This concludes today’s conference. You may disconnect your lines at this time. Thank you for your participation.
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