Cvr Energy Inc Q3 FY2020 Earnings Call

Greetings, and welcome to the CVR Energy’s Third Quarter 2020 Conference Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Richard Roberts, Senior Manager, FP&A and Investor Relations. Thank you, sir. You may begin.

Thank you, Kristine. Good afternoon, everyone. We very much appreciate you joining us this afternoon for our CVR Energy third quarter 2020 earnings call. With me today are Dave Lamp, our Chief Executive Officer; Tracy Jackson, our Chief Financial Officer; Dave Landreth, our Chief Commercial Officer, and other members of management. Prior to discussing our 2020 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 that are made during this call that are not statements of historical facts may be deemed to be forward-looking statements. You are cautioned that these statements may be affected by important factors set forth in our filings with the Securities and Exchange Commission and in our latest earnings release. As a result, actual operations or results may differ materially from the results discussed in the forward-looking statements. We undertake no obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise, except to the extent required by law. This call also includes various non-GAAP financial measures. For disclosures related to such non-GAAP measures, including reconciliation to the most directly comparable GAAP financial measures, are included in our 2020 third quarter earnings release that we filed with the SEC and Form 10-Q for the period, and will be discussed during the call. With that said, I'll turn the call over to Dave.

Thank you, Richard. Good afternoon, everyone, and thank you for joining our earnings call. Yesterday, we reported the third quarter consolidated net loss of $108 million and a loss per share of $0.96. EBITDA for the quarter was negative $39 million. Narrower crack spreads, elevated RIN prices and a decline in our investment in Delek all impacted our results for the quarter. In light of the ongoing challenges to our business presented by the pandemic, preserving the balance sheet remains a key focus. As a result, the Board of Directors did not approve a dividend for the third quarter of 2020. The board thinks the Wynnewood renewable diesel project that I will discuss shortly and potential acquisition opportunities could offer better returns to shareholders. For our petroleum segment, the combined total throughput for the third quarter was approximately 201,000 barrels per day as compared to 222,000 barrels per day in the third quarter of '19. We experienced some weather-related power outages at both facilities in August that modestly impacted our throughput rates for the quarter. Total throughput was also constrained by naphtha capabilities as tight crude differentials have favored running a very light crude slate. Across the board, benchmark crack spreads and crude differentials deteriorated significantly from a year ago. Group 3 2-1-1 crack averaged $8.34 per barrel in the third quarter as compared to $18.30 per barrel in the third quarter of '19, a decline of nearly $10 per barrel. The Brent TI differential averaged $2.42 in the third quarter compared to $5.59 per barrel in the prior year period. The Midland Cushing differential was $0.13 per barrel over WTI in the quarter compared to $0.26 per barrel under TI in the third quarter of '19. And the WCS to WTI differential was $9.82 per barrel compared to $12.59 per barrel for the same period last year. Our light product yield for the quarter was 99% on crude oil processed. Our distillate yield as a percentage of total crude oil throughputs was 43% in the quarter compared to 45% in the prior year period. In total, we gathered approximately 124,000 barrels per day of crude oil during the third quarter of 2020 as compared to approximately 127,000 barrels per day for the same period last year. Our production volumes in our gathering regions fell significantly in the second quarter with the drop in crude prices. Those volumes quickly came back as prices recovered to around $40 a barrel. Our current gathering volumes are over 120,000 barrels per day. In the fertilizer segment, we had strong ammonia utilization at both facilities of 97% at Coffeyville and 99% at East Dubuque. Although fertilizer prices remained soft, year-over-year sales volumes were higher for both ammonia and UAN, and we've made additional progress in our cost savings initiatives. Weather conditions have been favorable. And with the harvest largely complete, we expect solid demand for the ammonia fall run. I would also like to highlight some of the environmental achievements announced by CVR Partners recently. The Coffeyville fertilizer facility recently certified its first carbon offset credits for reducing nitrous oxide emissions at one of its acid plants. The East Dubuque facility has already abated the majority of its nitric oxide emissions over the past five years. Between the two plants, CVR Partners is now able to reduce its carbon dioxide equivalent emissions by over a million metric tons per year. Now, let me turn the call over to Tracy to discuss additional financial highlights.

Thank you, Dave, and good afternoon everyone. Our consolidated net loss of $108 million and loss per diluted share of $0.96 includes a mark-to-market loss of $68 million related to our investment in Delek and a favorable inventory valuation impact of $16 million. Excluding these impacts, our third quarter 2020 loss per diluted share would have been approximately $0.57. The effective tax rate for the third quarter of 2020 was 22% compared to 25% for the prior year period. The petroleum segment's EBITDA for the third quarter of 2020 was $15 million compared to $228 million in the same period in ‘19. The year-over-year EBITDA decline was driven by significantly narrower crack spreads, elevated RIN prices and lower throughput volumes. Excluding inventory valuation impacts of $16 million, our petroleum segment EBITDA would have been negative $1 million. In the third quarter of 2020, our petroleum segment’s refining margin, excluding inventory impact, was $4.61 per total throughput barrel compared to $16.37 in the same quarter of ‘19, a 72% decline. The increase in crude oil and refined product prices through the quarter generated a positive inventory valuation impact of $0.86 per barrel. This compares to a $0.03 per barrel negative impact during the same period last year. The cash rate, excluding inventory valuation impacts, was 55% in the third quarter of 2020 as compared to 89% in the third quarter of 2019. The most significant item impacting our cash rate for the quarter was elevated RIN prices, which reduced margins captured by approximately 23%. Derivative gains for the third quarter of 2020 totaled $5 million, which includes unrealized gains of $1 million associated with Canadian crude oil derivatives. In the third quarter of 2019, we had total derivative gains of $18 million, which included $14 million of unrealized gains. RIN expense in the third quarter of 2020 was $36 million compared to a $2 million benefit in the same period last year. The year-over-year increase in RIN expense was due to an increase in RIN prices during the third quarter of 2020 and a reduction of our renewable volume obligation in the prior year period. Based upon recent market prices at RINs and current production plans, we now estimate that our RIN expense will be approximately $110 to $115 million for 2020. Despite lower throughput, the petroleum segment’s direct operating expenses declined to $4.17 per barrel in the third quarter of 2020 as compared to $4.46 per barrel in the prior year period. Total consolidated operating and SG&A expenses for the third quarter of 2020 declined by approximately $25 million from the prior year period due to our continued efforts to lower costs. For the third quarter of 2020, the fertilizer segment reported an operating loss of $3 million, a net loss of $19 million or $0.17 per common unit and EBITDA of $15 million. This is compared to the third quarter of 2019 operating losses of $8 million, a net loss of $23 million or $0.20 per common unit and EBITDA of $11 million. The year-over-year EBITDA improvement was primarily due to higher sales volumes and lower operating and turnaround expenses, offset somewhat by lower prices for ammonia and UAN. During the quarter, CVR Partners repurchased just over 1.4 million of its common units for $1.3 million. The partnership did not declare a distribution for the third quarter of 2020. Total consolidated capital spending for the third quarter of 2020 was $23 million, which includes $17 million from the petroleum segment and $5 million from the fertilizer segment. Of this total, environmental and maintenance capital spending comprise $16 million, including $12 million in the petroleum segment and $3 million in the fertilizer segment. We estimate total consolidated capital spending for 2020 to be approximately $125 million to $135 million, of which approximately $90 million to $95 million is environmental and maintenance capital and $15 to $20 million is related to the renewable diesel project at Wynnewood. Total capital spending excludes capitalized turnaround expenditures year-to-date of $154 million. We do not currently expect significant planned turnaround expenditures for the remainder of 2020 and turnaround spending in 2021 is expected to be less than $15 million in preparation for the turnaround planned in 2022. Cash provided by operations for the third quarter of 2020 was $111 million and free cash flow in the quarter was positive $76 million. Working capital was a source of approximately $93 million in the quarter due in part to an increase in lease crude payables and an increase in accrued liability. Turning to the balance sheet. At September 30, we ended the quarter with a strong cash balance of approximately $672 million on a consolidated basis, which includes $48 million in the fertilizer segment. On a trailing 12 month basis, our net debt to EBITDA at the CVI level was approximately 4.4 times, excluding CVR Partners standalone debt and EBITDA. As of September 30th, excluding CVR Partners, we had approximately $858 million of liquidity, which was comprised of approximately $624 million of cash, securities available for sale of $118 million and availability under the ADL of approximately $393 million less cash included in the barn base of $277 million. Looking ahead to the fourth quarter of 2020, for our petroleum segment, we estimate total throughput to be approximately 200,000 to 220,000 barrels per day. We expect total direct operating expenses to range between $75 million and $85 million and total capital spending to be between $6 million and $12 million. For the fertilizer segment, we estimate our ammonia utilization rate to be between 95% and 100%. We expect direct operating expenses to be approximately $37 million to $42 million, excluding inventory impact, and total capital spending should be between $5 million and $8 million. Corporate and other capital spending, which includes investments in the Wynnewood renewable diesel project, is expected to range between $12 million and $15 million. With that, Dave, I will turn the call back to you.

Thank you, Tracy. The reduction in refined product demand due to the ongoing pandemic continued to weigh heavily on crude oil and refined products in the third quarter of 2020. We continue to do everything we can to manage the business through this difficult environment. Our focus remains on operating in a safe, reliable manner, controlling our costs, and maintaining a strong balance sheet and liquidity position. In the near-term, our outlook remains cautious as we see strong market fundamentals. Crude oil differentials have tightened considerably with the decline in crude prices and domestic shale oil production. We expect differentials to remain weak until shale oil production recovers. The inventory of drilled but uncompleted wells are expected to decline as well, with depletion likely at WTI prices under $40 per barrel. Crude oil prices will need to rise further to incentivize new wells to stem production declines. US refined product inventories have benefited from product exports returning to pre-COVID levels. Gasoline inventories are now within a five-year average while distillate inventories remain elevated, mainly due to weak jet fuel demand. The loss of jet fuel demand is more than half of the total demand destruction for transportation fuels. We need jet fuel demand to recover for oil to recover. Commercial air travel made up primarily of business and leisure travel accounts for 75% of the total jet fuel demand and remains depressed. Ultimately, we will likely need to see additional run cuts and/or permanent refinery shutdowns for crack and crude differentials to improve. As we work to maximize the profitability at our plants under these conditions, CVI is running a maximum light crude slate, maximizing premium production, maximizing RIN generation, and selling 100% of our WCS in Cushing while continuing to reduce operating and corporate costs. We continue to explore opportunities to diversify our business. We have received Board approval to complete detailed engineering work and have ordered long lead equipment for the renewable diesel project at the Wynnewood refinery. We are currently evaluating a multi-phase approach to our renewable diesel strategy, with Phase 1 being the conversion of the existing hydrocracker at Wynnewood to allow for the production of renewable diesel. With Phase 1, we will also retool the refinery for maximum condensate processing. We have submitted applications for all environmental permits to the State of Oklahoma for final approval. Pending state approval, state agency and final Board approval, we could receive feedstock as early as May of 2021 and have the unit online by July 1 of '21. This would allow us to receive 18 months of the dollar per gallon Blenders Tax Credit that is currently authorized through the end of year '22. We view Phase 1 as providing us with optionality. Between the Blenders Tax Credit, Low Carbon Fuel Standard credits, and RINs generated by renewable diesel production, we believe we can recoup a significant portion of our initial investment in 18 months. If market conditions change materially, then we would have the option to return the unit to hydrocarbon service fairly easily at minimal cost. On the other hand, if Group 3 cracks remain low and these government incentives continue to be supportive, we have an attractive mix of projects to grow our renewable diesel business in two additional phases. Phase 2 would involve the installation of a pretreatment unit at Wynnewood that would allow us to process lower carbon intensity feedstocks, like inedible corn oil, animal fats, and used cooking oil. Finally, in Phase 3, if approved, we would pursue a similar renewable diesel project at the Coffeyville refinery. We currently have excess hydrogen capacity and an existing high-pressure hydrotreater at the Coffeyville refinery that we could repurpose for renewable diesel production similar to the project at Wynnewood. In addition to expanding into the renewable fuels market, we have stated many times that we believe further consolidation in the refining space is needed, and we would like to be a part of that process. While we don't have anything new to report at this time, we remain interested in several potential opportunities, including our nearly 15% stake in Delek and potential assets in PADD IV. Looking at the fourth quarter of 2020, quarter-to-date metrics are as follows: Group 3 2-1-1 cracks have averaged $6.97 per barrel with the Brent-TI spread of $1.98 per barrel and a Midland Cushing differential of $0.07 over WTI; the WTI differential has averaged $0.22 under Cushing WTI and the WCS differential has averaged $9.69 per barrel under WTI. Corn and soybean prices have also increased by 30% since July and we believe fertilizer prices will follow. Ammonia prices have increased to $250 to $325 per ton, while UAN prices remain at $140 to $160 per ton. As of yesterday, Group 3 2-1-1 cracks were $7.04 per barrel, the Brent TI was $2.16 per barrel and the WCS was $9.48 under WTI. In this environment, refineries are all competing on the cost curve where we remain competitively positioned versus many of our peers. Quarter-to-date ethanol RINs have averaged $0.53 and biodiesel RINs have averaged $0.80. While refined product prices have been compressed with market volatility, RINs remain significantly overpriced and now represent one of the single largest costs for the refineries aside from crude oil. We were disappointed by the EPA's recent blanket denial of GAAP petitions with little basis. And as I have said before, we believe the 10th Circuit got it all wrong when it ruled to vacate three small refinery exemptions earlier this year. We have sought to review this misguided 10th Circuit RFS ruling by the US Supreme Court, and we believe this ruling conflicts with other rulings and sets national policy which exceeds the 10th Circuit authority. When the RFS regulation was passed, Congress clearly intended that small refinery waiver provisions would protect small refineries from financial devices as a result of the RFS regulation, especially refineries serving rural areas without redistribution of the waived RVO. With that, operator, we're ready for questions.

Our first question comes from Phil Gresh with JPMorgan.

First question, I just want to follow up on the RIN discussion. Obviously, it sounds like headwinds here into the third quarter.

You're cutting out, Phil.

With RINs prices having gone up here in the fourth quarter, how are you viewing the potential headwind into 2021 relative to the 2020 guidance that you provided?

Well, a couple of factors. One is an election that, depending on those results, I think RINs could go multiple directions. I think the other thing I'd say on the longer-term is the number of announced renewable diesel projects is an astounding number of new RINs to the market. I'm not sure anybody has really analyzed this very much, but there's over about 1 million gallons of renewable diesel been announced in '20 and '21, with several of them in the process of starting up now, but that represents about 1 billion new RINs to the market. So I think longer-term, and you're starting to see that even in the forward RINs that are selling now for 2021 on the renewable diesel side that are lower-priced in the future than they are today. But I think even further than that, that volume of RINs hitting the market will bring parity between ethanol RINs and renewable RINs, and all of them will trend down.

The only thing that I would add to that is that we anticipate with the RDU coming online midyear, we'll have a portion of RINs that we generate ourselves in addition to what we already generate, that will offset that obligation also.

And I guess for my second question, just to clarify, when you backed out the 23 percentage point capture rate impact, kind of mid-70s capture. Is that what you would view as kind of a fair capture rate in an environment where Brent-WTI spreads are in this $2 range?

It's not far off from that, Phil. I think we were also hit with the premium; the spread narrowed quite a bit, almost $0.10 a gallon. And now we're heading into the season where Y-grade comes in, that's the number one ultra-low sulfur diesel, which usually carries $0.20 to $0.30 premium. So all those factors will bring up, I think, would bring it back to the normal levels, assuming RINs moderate.

Second question, it may be a bit hypothetical, but if we encounter a situation with the Biden administration, people are concerned about the shutdown risks with DAPL. I believe you have access to barrels on Pony Express and White Cliffs to some extent. I was wondering if, in a challenging situation in the Bakken, you have the capacity to potentially capture those barrels and benefit from any widening of the spread?

Well, we are Cushing-based. So I think we're somewhat immune to that situation should it occur, although it would dry out barrels in Cushing to some degree. But we get very little barrels off of White Cliffs, and most of our light crude comes from the Oklahoma gathering systems that we have and the Kansas gathering systems we have. So I think I would tell you, we're pretty immune to that impact.

Our next question comes from the line of Manav Gupta with Credit Suisse.

I just want to kind of get a clarification. You mentioned that with your first phase of the renewable diesel project, you'll probably end up making 100 million gallons of renewable diesel. And I think you get 1.7 times credit for the D4 RIN. So I'm just trying to understand where your current RIN obligation is in terms of gallons, and what that 100 million gallons of renewable RINs does to that RIN obligation once the plant actually comes online. How much short RINs would you be once that plant is up and running?

The renewable diesel at 100 million a gallon throughput would generate about 170 million RINs. Our obligation today is around 310, 320, somewhere in that neighborhood, and we generate internally about 21%, 22%. So you can pretty much do the math from there. I will tell you that we kind of view renewable diesel as a separate segment. So refining will have to pay for its full amount of RIN obligations and it will show up as a credit to the renewable diesel as another form of credit. So keep that in mind. We put all the incentive on the renewable diesel that it earns.

So I get the accounting. So basically, what you're saying is 66% of your RIN obligation gets mitigated with this 100 million gallons of D4 RINs coming in by mid-July of next year. Is that the right way to think about it?

Yes. I think we're going from approximately 250 down to 135, somewhere in that range of net across the whole company.

On to something which dragged down your earnings, $65 million or $68 million in marketing security losses associated with Delek. I'm just trying to figure out how you're thinking about the company at this point with all the investment opportunities you highlighted in renewable diesel Phase I, Phase II, Phase III and versus spending capital in getting additional interest in Delek, which is kind of pulling you back a little at this point of time, definitely pull back your 3Q earnings. So trying to understand how you're viewing the opportunity in renewable diesel expansion versus putting the same capital towards getting more interest in Delek?

Well, as I mentioned that we're interested. We believe that the industry needs to consolidate more just to drive out fixed costs. Typically, in a commodity business, the fixed cost is the enemy of everyone. And separate private public companies have significant costs associated with maintaining that scenario. So the more consolidation that happens, the more efficient the fleet is. And we'd like to participate in that and that's what it really made our investment in Delek to start. And we still think it's a pretty interesting proposition, getting even more interesting every day with the current stock prices. That said, we don't have any plans to do anything at this point. And then we continue to watch the market and look at the other alternatives we have in PADD IV, and we'll make a decision at the appropriate time.

One last question. The pretreatment unit is a part of Phase 2 of renewable diesel expansion that doesn't change the total capacity. It still remains at 100 million, but what you're basically going to do is use more animal fat, used cooking oil, and maybe some other feedstocks versus soybean oil. Is that the plan for the Phase 2 expansion?

Yes. I think we'd probably focus mostly on inedible corn oil because a lot of the used cooking oils are spoken for today. But I think this will end up being transportation driven, and we'll be able to gather some of it, but that's yet to be seen. And what is available is inedible corn oil and we're really after a lower CI material, carbon intensity material, and that just makes you earn more credits in California. The other thing I did mention in the prepared remarks is if we do this at Coffeyville, we will need a substantially larger-sized pretreater. And we may consider even whether we build it, the pretreater at Coffeyville, or at Wynnewood or some other location. And we're rallying at in any way and trying to do whatever is most efficient from a permitting standpoint, as well as a cost standpoint of where we actually do that pretreatment.

David, the Phase 2 and Phase 3 sound very exciting, and we look forward to more details on those two future phases of the renewable diesel project, as well as you hitting that July mark of getting the first phase on. Thank you.

Our next question comes from the line of Prashant Rao with Citigroup.

I wanted to discuss the industry consolidation strategy from a perspective outside of Delek, Dave. Let’s consider the PADD IV opportunities, particularly regarding your long WCS barrels in the current tight WCS environment. There are some variables at play with Alberta’s production quotas being lifted, but the economic cuts were actually below the quotas. Therefore, the impact is somewhat uncertain. I would like to hear your thoughts on your WCS position and how it relates to the potential bid-ask spread for a PADD IV asset, especially in comparison to other investment opportunities in your portfolio. Additionally, I have a follow-up question about Wynnewood. Thank you.

I believe there are opportunities for profit in consolidation. Our primary focus in PADD IV is to diversify our EBITDA in a market that possesses some niche characteristics similar to our current environment. We believe PADD IV achieves this in various ways. Many of these opportunities come with marketing assets that enable you to earn a RIN or a part of the RINs generated. Most of them are linked to WCS due to their proximity to Hardisty and Western Canada. This positions us competitively since delivery costs range from $3 to $4 per barrel compared to $6 to Cushing. All these factors integrate well into our portfolio. So far, we have been successful in recovering our pipeline tariff on the 35,000 rate we've secured in Keystone and elsewhere. Regarding Canada, I previously calculated that approximately 4.2 million barrels per day of pipeline capacity exists. Canada has not been producing significant amounts of WCS recently. With the removal of curtailments, we anticipate production to increase even at current prices, given that cash costs for incremental WCS in Canada are quite low, assuming diluent is available. This situation may influence pricing to align more with rail costs rather than pipeline tariffs, which will be impactful. WCS competes directly with mine on the Gulf Coast, and we are currently selling it at about $3.30 below WTI in Cushing, landing in the Gulf Coast at around $2. It remains competitively priced against mine and is likely to stay that way for the immediate future.

And then on Wynnewood on the renewable diesel project, one specific aspect that I wanted to get a little bit more color on. If the market dynamics dictate, you mentioned the ability to switch between by or renewable production and traditional fossil fuel based production. Could you maybe elaborate a bit more on what that would take to make that switch back? What's the time window, and is that something that gets done within a short turnaround? Just sort of, I guess, it's a bit more of a mechanical question. But for a mechanica... non-engineering audience, if you could give us a bit more color, that would be helpful. Thanks.

The primary distinction is that even with some enhancements to the metallurgy in the hydrocracker unit, the unit remains fundamentally the same. It's merely an upgraded metallurgy. The catalyst used is slightly different. To revert to hydrocarbon service, you only need to change the catalyst, which takes about 20 days. This process can be done quite swiftly. The important factors at play include whether more states adopt the low carbon fuel standard, the fluctuation of RIN prices, and the impact of the blender's credit. There are scenarios where these elements could move in an unfavorable direction. However, we see this as an opportunity, allowing us to quickly pivot between options to maximize profitability for CVI while considering all variables. Essentially, within about a month, we can seamlessly switch between the two services.

And would you be thinking about some similar sort of optionality with Coffeyville as well if you go forward with that?

It's actually the exact same scenario. And I've mentioned that Coffeyville is probably even a higher capacity than this 100 million; it's probably more in the 150 million range because it's a much bigger unit and much bigger hydrogen plant.

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

The first question I have for you, David, is historically, and I think the market has historically viewed the business as one of having one of the stronger balance sheets in the refining sector, and I think it might be a function of a lot of technical dynamics too. But we have seen the credit sell off pretty hard here over the last couple of weeks. And I just want to give you an opportunity to kind of talk about the way that you see the balance sheet playing out, liquidity, cash flow burn. And how you guys are comfortable about managing through this tougher period?

Well, I think the primary focus we have is to run safe, reliable operations and to reduce our costs and capital spending to levels that frankly, we probably have never seen. That's what it takes to survive in this environment. Protecting the balance sheet is very important to us and maintaining our cash for what we consider some great opportunities. And frankly, when the market is on its rear end, it's the time to consider buying assets, and we want to be in that position as much as possible. So we actually generated a little cash this quarter. I don't know that we'll repeat that in the fourth quarter, but those are the kind of activities we're doing. The amount of cost-cutting we've done to date, I think Tracy mentioned $25 million quarter-over-quarter, and you do that on a run-rate basis, you can see we're quickly approaching $4 or less a barrel operating cost. And we've equally cut a significant amount of money out of the SG&A side too. So I don't think those go away. They stay around for a while. We're trying to make sure we don't defer any maintenance that's needed for safe, reliable operations in any way or things that we're obligated to do by the government or whatever they be. But we are really improving the competitiveness of our facilities, which are frankly, pretty competitive anyway, considering our configuration and the kind of crudes we can run and process. So I'm not sure I got to what you were looking for, Neil, but.

No, it's directionally very helpful. So to just put some numbers around it, as you think about 2021 capital spending, I know it's still early. But any thoughts on where you can flex it down to, if needed, and maintain that safe and reliable level? And then just as you think about cash flow neutrality, do you think as you look at the forward curve for both Brent-WTI and refining margins, recognizing that I think there are a lot of us who were skeptical that the forward curve is right. But do you still think that you can minimize cash flow burn in that environment?

Yes. I believe we will implement some hedging strategies around forward cracks that seem beneficial. We will focus on purchasing crude oil and selecting the best discounted crudes with the highest value, leveraging our position directly linked to the field which gives us more flexibility than others. We are aiming to keep our sustaining capital below $80 million, excluding the R&D project. At this budget level, we do not have any immediate turnaround plans for the coming year. As Tracy pointed out, we believe we can manage until the end of 2021 without issues. After that, we will start evaluating other options. The forward curve is slightly in contango, but not to my satisfaction. Ultimately, everything depends on the virus situation and its impact on jet fuel demand, as well as the number of impaired operations and refinery shutdowns. Many of these adjustments are still necessary in this environment, and I am confident they will occur. If my calculations are correct, we are already looking at about 1.7 million barrels per day that are currently out of commission in some form. This includes us downgrading Wynnewood for R&D, which is leading us to reduce crude processing. Coffeyville is making similar adjustments. Moreover, we are reconfiguring both facilities for a different crude slate that will further cut costs. There's still much more to explore and many options we have yet to utilize.

Our next question comes from the line of Paul Cheng with Scotia Howard Weil.

Dave, can you remind me what is the preliminary CapEx for the Phase 1 of the renewable plan?

We are targeting $100 million for Phase 1.

And $100 million for 100 million gallons. And the feedstock you will decide, you said it's going to be soybean oil?

Yes. It's washed, refined, and bleached soybean oil.

And I think you have said that. But can you just remind me how much is the Wynnewood throughput will be reduced by, and how that product yield is going to change?

We have adjusted the refinery for increased condensate processing, which allows us to maintain the reformer fully supplied along with the associated equipment. By removing the hydrocracker from the fuels processing, our CAC cracker rate is expected to increase, although we will have similar yield types, likely resulting in slightly less diesel and a bit more gasoline, but not significantly due to this change.

And what is the total throughput will be changed by?

Total throughput today is about a little under 75,000 barrels a day, and that will go to about 59,000 barrels a day, between 55,000 and 59,000.

So it will drop by somewhere between 15 to 20 million barrels, or 20,000 barrels per day.

That's right, when we're in R&D mode.

And maybe I get this wrong on the math. I think you're saying that assume the Phase 1 is on stream, your net win exposure will drop from 310, 320, down to about 135 going in?

No. Yes, you're close, but you forgot our internally produced RINs, which is about 20%, 21%, 22% of our RVO. So those are 65 million.

I thought that would be about 60, 70 because your RIN obligation is 310 to 320, right? So 20% will be 60% to 70%, and the renewable diesel plan will be 170…

Right.

And so should we be down to 80 only on your net exposure?

That's pretty close. Let's see. Something less than 100 million.

Yes, because I thought I heard you saying that as a higher number. So I'm not sure that I thought I did…

I think I said 135. But the RVO goes down with the crude rate cut too, remember. So you've got to adjust both numbers, the top number and the bottom number.

In theory, your obligation has only decreased by about 10%, as your overall throughput for the company will also decrease by about 10% at 20,000 barrels per day. Therefore, we should be discussing around 270. This means your obligation should actually be less than 80, more likely around 60.

Yes, I arrived at 70 to 77, but I believe you have the correct figures.

I'm a bit confused about the figure of 135. Dave, I'm interested to know how we should view CVR Partner in light of its price being under $1 per share, especially regarding consolidation and the benefits of M&A. You also have the option to purchase it at this price or something close to it. Does it make sense to consider eliminating that MLP structure, considering its future outlook? How low do you see the equity value, or do you think there are better opportunities elsewhere? On one hand, CVR Partner is involved in stock buybacks, suggesting that the Board finds the valuation appealing. If that’s true, why not eliminate it and simplify things to save on regulatory costs, avoiding the need to report it as a separate unit?

You made a solid argument, Paul. We are constantly assessing that. While it may not be the right moment now, it is something we regularly consider and remains an option for us. With the debt maturing in 2021, we want to determine our course of action for 2023, assuming that's when we will make a decision. This is definitely a possibility. As for the fertilizer segment of our business, it has performed remarkably well this year and highlights the benefits of having a diversified portfolio. However, a possible factor that could shift this perspective is if taxes increase significantly, which could make MLPs desirable again. We are always evaluating our options, and this is a worthwhile idea.

And just curious that if there's a good asset or asset that fit you with the right asset, what is the maximum leverage you're willing to go to?

We are constantly evaluating that. If we were to pursue a major acquisition, it would likely be assessed on a pro forma basis, which would slightly alter the numbers. However, I don't believe we would consider anything above a leverage of two. Currently, that aligns with our EBITDA situation.

So is that net debt-to-EBITDA maximum 2 times?

I don't think anybody in this space goes much above that. On purpose, I mean. They don't go much above it on purpose.

A final question for me, maybe it's for Tracy that how much is the tax refund you expect next year from the CARES Act? Do you expect in the second quarter or third quarter to receive it? And also whether the third quarter unique cost a good baseline to be used for the future forecast, or that's an adjustment or one-off item that we need to take into consideration?

So the first question, I would just use our 21% corporate average. I would anticipate that you should look at what we expect our full year production to look like with the curves and get a full year loss number or gain number, whatever you're predicting, and apply a corporate percentage rate to it, and that is going to be a good proxy for what our cash return from the net loss carryback that we're expecting. Can you restate your second part of your question, please?

For the third quarter, your unit cost was very low. Is that a reasonable level that we can use as a baseline to forecast into the future, or are there one-off items that we need to take into consideration and adjustments?

I think you can look to our current operating cost run rate to be a new normal for us for the short term. And certainly, we will look to hold cost at that level should we see an economic return. We do have projects that are not related to safe and reliable operations that we're deferring that we will bring back at some point. But right now, we don't need to be painting tanks.

So Tracy, when you say that, are you talking about on a per unit basis or on an absolute nominal? Are we talking about $4.20 per barrel? Is it reasonable baseline or $77 million; is that reasonable baseline?

$4.20 a barrel is a reasonable baseline.

I think we're going to drift, Paul, more towards $4, and we do have some more, like I said, more ammo in our belt that we can fire should we need to from a cost-saving standpoint. So we don't really want to go there because we've already had a reduction in force and done quite a few things to conserve cash. But I really think the $4 level is doable.

And Dave, is there any reason we should expect your throughput in the fourth quarter to be much different than the third quarter, given the market conditions?

No. We're running basically 94% of capacity on a light slate, which is about all we can do. And we're not having trouble moving any product or any other constraints. So we plan to stay at the same rates.

Our next question comes from the line of Matthew Blair with Tudor Pickering Holt.

Dave, you mentioned the crude slate reconfiguration. It looks like you're already making some changes here. Condensate up to 10% of your slate, WTL up to 5%. Could you talk a little bit more about that? Is it possible to quantify the benefit in Q3? And do you expect to run a pretty light slate into Q4?

Well, the condensate spread was approximately $0.50 in Cushing under WTI. So when you look at our gathering system, that's actually wider than that. So you can kind of tell what we're after there. And the yield on condensates, with our configuration, is a high percentage of gasoline but still makes significant diesel and really has a great volume yield. So it's just win-win for us all the way around.

And then I also wanted to ask about the BTC. So obviously, something pretty hard to forecast. But in your internal modeling, what are you assuming for BTC into 2023 and 2024? There's some talk that it might get phased down or it might go away completely. So what are you assuming? And do you think the election results would make a difference in that?

If you look at the history of the Blenders Tax Credit, it has always been there at the $1 level. It's been delayed for as long as two years but retroactive back to those two years. I don't see that changing much. I do think the state of the deficit and other things is going to put pressure on it to reduce it some way, but to eliminate it. I mean what happened with RFS is that created an industry; it created actually two industries. One on ethanol and ethanol production and one on biodiesel, now renewable diesel on top of it. And when Congress creates industries, they just can't abandon them. And this is a bipartisan issue for a large part. So I think you see it kind of gravitating towards the renewable diesel more than the biodiesel, and that should naturally happen, I think. The market forces will force that. But I think they're going to have to support it somehow, some way because they created an industry around it.

Your next question comes from the line of Matt Vittorioso with Jefferies.

Most of it's been asked. Maybe just quickly on fourth quarter cash flow. You mentioned in the third quarter, you got a big boost from working capital. Some of that was payables and accrued expenses. Do you expect that to reverse in the fourth quarter or any big movements in working capital for the fourth quarter?

We do expect working capital in the fourth quarter to continue to be a source of cash for us. And I don't really want to comment on the net cash position for the fourth quarter. But specifically, working capital will likely be a provision of cash.

It all depends on cracks to some degree, and we don't know. We won't know those until it's over.

I'm not sure how much you can share, but could you discuss the benchmark differentials and industry markers early in the fourth quarter? How should we view the generic refining margin? You achieved $4.60 in the third quarter. Based on what you're observing in the market today, are we at a similar level in the fourth quarter or are there any significant changes?

We haven't seen much change. However, I must point out that the current numbers are not sustainable for the industry, particularly regarding crude prices and cracks. You find yourself competing on the cost curve, and many, including myself, agree that significant decisions like a turnaround really highlight the situation. At these numbers, it's clear you're not recouping your turnaround costs, which is unfeasible. Therefore, something will have to change, either in demand or production. The balance of supply and demand will return because it’s an economic reality that you either need to increase margins or reduce runtimes; there are no other options.

We have reached the end of the question-and-answer session. I would now like to turn the floor back over to management for closing comments.

Again, I'd like to thank you all for your interest in CVR Energy. Additionally, I'd like to thank all our employees for their hard work and commitment towards safe, reliable, environmentally responsible operations. They have been under extra strain with the virus and done a really good job of keeping our operations running and successful. We look forward to reviewing our fourth quarter results at our next earnings call, and good day, everyone.

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