CVR Energy Inc.

Greetings, and welcome to the CVR Energy 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. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. 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, Christine. Good afternoon, everyone. We very much appreciate you joining us this afternoon for our CBR 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 made during this call that are not statements of historical facts may be deemed to be forward-looking statements. Your caution that these statements may be affected by important factors set forth in our filings with the Securities and Exchange Commission and in our latest earnings release. As a result, actual operations or results may differ materially from the results discussed in the forward-looking statements. We undertake no obligation to publicly update any forward-looking statements, whether as a result of new information, future events, or otherwise, except to the extent required by law. This call also includes various non-GAAP financial measures. The disposures 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 96 cents. EBITDA for the quarter was a negative 39 million. Narrower crack spreads, elevated RIN prices, and a decline in our investment in DELIC 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 Winnie Wood 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 a day, as compared to 222,000 barrels per day in the third quarter of 2019. 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 NAPTA processing 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. The 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 2019, a decline of nearly $10 a 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 2019. 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. While 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 remain 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 ammonia 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 nitric 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 Delix. and favorable inventory valuation impacts 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 segments EBITDA for the third quarter of 2020 was $15 million compared to $228 million in the same period in 2019. The year-over-year EBITDA decline was driven by significantly narrower crack spreads, elevated RENs 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 impacts, was $4.61 per total throughput barrel, compared to $16.37 in the same quarter of 2019. a 72% decline. The increase in crude oil and refined product prices through the quarter generated a positive inventory evaluation impact of 86 cents per barrel. This compares to a 3 cent per barrel negative impact during the same period last year. The capture rate excluding inventory evaluation 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 capture rate for the quarter was elevated in RENZ prices which reduced margin capture 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. REN's 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 RENs expense was due to an increase in RENs 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 of RENs and current production plans, we now estimate that our RENs 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 third quarter 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 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 comprised 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 to 135 million of which approximately 90 to 95 million is environmental and maintenance capital, and 15 to 20 million is related to the renewable diesel project at Winnewood. 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 turnarounds planned in 2022. Cash provided by operations for the third quarter of 2020 was $111 million, and free cash flow in the quarter was a 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 liabilities. 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 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 ABL 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 and $85 million and total capital spending to be between $6 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 to $42 million, excluding inventory impacts, and total capital spending to be between $5 and $8 million. Corporate and other capital spending, which includes investments in the Winniewood Renewable Diesel Project, is expected to range between $12 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 production 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 continues to be 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 on market fundamentals that we see. 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. Inventory of drilled but uncompleted wells are expected to decline as well, with depletion likely at WTI prices under $40 a barrel. Crude oil prices will need to rise further to incentivize new wells to stem production declines. U.S. 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 in order 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 Winningwood 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 Winningwood 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 blender's tax credit that is currently authorized through the end of year 22. We view phase one as providing us with optionality. Between the blender's tax credit, low carbon fuel, standards credit, and RENs 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 minimum 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 two would involve the installation of a pretreatment unit at Winniewood that would allow us to process lower carbon intensity feedstocks like inedible corn oil, animal fats, and used cooking oil. Finally, in phase three, 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 hydro-treater at the Coffeyville refinery that we could repurpose for renewable diesel production similar to the project at Winnewood. In addition to an 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 a number of potential opportunities, including our nearly 15% stake in DELIC, in potential assets in Pad 4. 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 WTL differential has averaged $0.22 under Cushing, WTI, and the WCS differential is average $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 53 cents, and biodiesel RINs have averaged 80 cents. 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 EPA's recent blanket denial of gap petitions with little basis. And as I have said before, we believe the Tenth Circuit got it all wrong when it ruled to vacate three small refinery exemptions earlier this year. We have sought to review this misguided Tenth Circuit RFS ruling by the US Supreme Court, and we believe this ruling conflicts with other rulings and sets national policy which exceeds the Tenth Circuit authority. When the RFS regulation was passed, Congress clearly intended that small refinery waiver provision would protect small refineries from financial demise as a result of the RFS regulation, especially refinery serving rural areas without redistribution of the waived RVO. With that, operator, we're ready for questions.

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

Hey, good afternoon. First question, I just want to follow up on the RIN discussion. Obviously, it sounds like it's a huge headwind here in the quarter.

You're cutting out, Phil.

I apologize. Can you hear me?

Yeah, now I can.

Okay, sorry about that. With RIN's 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 in the longer term is the number of announced renewable diesel projects is an astounding number of new RENs to the market. I'm not sure anybody's really analyzed this very much, but there's over about a 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 a billion new RENs 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 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 mid-year, we'll have a portion of RENs that we generate ourselves in addition to what we already generate that will offset that obligation also.

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

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

Okay. Uh, second question, but I guess it's a little bit hypothetical, but, um, if, if we move into a situation, uh, here with the Biden administration, I think people are focused on the shutdown risks with DAPL. And, um, I think you guys get barrels on a pony express and white cliffs to some extent. So I was just curious if there's any, if we get into a, a difficult situation in the Bakken, how much ability do you have to potentially capture those barrels and benefit from any spread widening?

Well, we are Cushing-based, so I think we're somewhat immune to that situation should it occur, although it would dry up 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 we have and the Kansas gathering systems we have. So I think I would tell you we're pretty immune to that impact.

Okay.

All right. Thank you.

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

Hi, guys. I just want to kind of get a clarification. You mentioned that with your first phase of 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? Like, how much short rinse would you be once that plant is up and running?

Yeah, the renewable diesel at 100 million a gallon throughput would be about 170 million rinse. 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 we will account, refining will have to pay for its full amount of rent obligations, and it'll 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 again, 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 or by mid of next year. Is that the right way to think about it?

Yeah, I think we're going from nominally about 250 down to 135, somewhere in that neighborhood. of net across the whole company.

Okay, perfect. So that's good news. On to something which dragged down your earnings, $65 million or $68 million in marketing security losses associated with Delic. 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 1, Phase 2, Phase 3 versus spending capital in Delic. getting additional interest in Delic, which is kind of pulling you back a little at this point of time, definitely pulled 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 Delic.

Well, as I mentioned, 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, you know, separate public companies have significant costs associated with maintaining that scenario. So the more consolidation that happens, the more efficient the fleet is. And, you know, we like to participate in that, and that's what really made our investment in DELIC 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 we continue to watch the market and look at the other alternatives we have in Pad 4 and we'll make a decision at the appropriate time.

Okay, one last question. The pretreatment unit is a part of Phase 2 of the 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, use cooking oil, and maybe some other feedstocks versus soybean oil. Is that the plan for the Phase 2 expansion?

Yes. You know, I think we'd probably focus mostly on an edible corn oil as part because a lot of the used cooking oils are spoken for today. But I think this will end up being, transportation will drive a lot of it, and we'll be able to gather some of it. But that's yet to be seen. What is available is an edible corn oil. And we're really after a lower CI material, carbon intensity materials. And that just makes you earn more credits in California. The other thing I did mention in prepared remarks is, you know, if we do this at Coffeyville, we will need a substantially larger size pretreater. And, you know, we may consider even whether we build the pretreater at Coffeyville or at Winniewood or some other location. And we're railing it 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.

Now, David, the phase two and phase three 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. You're welcome.

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

Hi, good afternoon. Thanks for taking the question. I wanted to talk about industry consolidation approach from a non-delic angle, Dave. Maybe if we could talk about the PADD4 opportunities and specifically thinking about your long WCS barrels and we're in a tight WCS diff environment. There's some moving parts there with, you know, Alberta production quotas being lifted. However, economic cuts were below what the quotas were anyway. So it's arguable as to what that impact might be. So I wanted to get your view on how you're thinking about that WCS position that you have and how that maybe relates to where a potential pad for asset, you know, the bid-ask spread is, you know, how those two play with each other versus the other opportunities you have, um, in the portfolio in terms of capital investment. And then I have a follow-up on Winnie Wood. Thanks. Sure.

Um, you know, I think, um, again, um, you know, there's, there's money to be had in the consolidation play. You know, you know, our, our main drive in pad four is really around diversification of EBITDA in, uh, in a, in a, what I'll call a similar market to what we, we have today where there's a little bit of a niche, um, status to it. And we think PAD4 does that in a lot of ways. A lot of these come with marketing assets, which allows you to earn a RIN or a portion of your RINs that you generate. And they are, most of them are associated with some form or fashion with WCS because of proximity to Hardesty and Western Canada. and your somewhat competitive advantage because the delivery cost is only $3 to $4 a barrel compared to $6 to get to Cushing. So all those kind of play into our portfolio quite well. We've been successful to date really recouping our pipeline tariff on the $35,000 rate that we have secured in Keystone and Spearhead. And, you know, as far as what's happening in Canada, you know, there's, I think, last time I added it up, it was about 4.2 million barrels a day of pipeline capacity out of Canada. We haven't, Canada has not been producing that much WCS to date. With the curtailment being removed, the thought is that we should, it should result in production going up, even at these prices. because the cash cost is so low in Canada for incremental WCS, assuming there's deluent available. But that fact should go back to the price-setting mechanism being more related to rail than to pipeline tariffs. And that will make a big difference. WCS really competes against mine on the Gulf Coast. And we're selling it today at a about $3.30 under WTI in Cushing. And it's landing in the Gulf Coast at about $2. So it's still very competitive with Mayan, and it will probably be that way for the next year or two.

Thanks. Appreciate that. And then on Woody Wood, on the renewable diesel project, one specific aspect that I wanted to get a little more color on. If the market dynamics dictate, you mentioned the ability to switch between biorenewable 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? I guess it's a bit more of a mechanical question, but for mechanical question for non-injuring dummies and analysts. If you could give us a bit more color, that would be helpful. Thanks.

Sure. Yeah. The basic difference between, even though you upgrade some metallurgy in the hydrocracker unit, the unit is basically the same. It's just metallurgy metalled up, so to speak. And then catalyst is a bit different. So To really switch it back to hydrocarbon service, you just basically change the catalyst, which is a 20-day outage period. So it's rather rapid that you can do it in. The real conditions that matters here is do more states opt in to the low-carbon fuel standard game? What are RIN prices? And what happens with the blender's credit? You can paint scenarios where all those can go the wrong way. And we we would just view this as an option we can we can jump back and forth fairly quickly and harvest whatever whatever is the best whatever makes the most money for CVI and considering all factors So, you know, that's why I say it's an option. That's what it really is within You know, let's say 30 days one month. You can switch it back and forth between the two services. I

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

It's actually the exact same scenario. And I mentioned that Coffeeville is probably going to have a higher capacity than this $100 million. It's probably more in the $150 million range because it's a much bigger unit and a much bigger hydrogen plant.

Okay, excellent. Thanks for the time this afternoon. Sure.

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

Good morning, guys, or good afternoon. The first question I have for you, David, is historically, and I think the market has historically viewed the business as 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 Just wanted 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 to levels that, frankly, we've probably 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, you know, frankly, when the market's 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 You know, we actually generated a little cash this quarter. I don't know that we'll repeat that in the fourth quarter, but, you know, those are the kind of activities we're doing. The amount of cost-cutting we've done to date, I think Tressie 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 it may 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't run and process. So I'm not sure I got to what you were looking for, Neil, but that's my answer.

Yeah, 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 – 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 are skeptical that the forward curve is right, but do you still think that you can minimize cash flow burn in that environment?

Yeah, well, I think, you know, we'll do some hedging around forward cracks that we think are advantageous. We'll do all we can on crude buying and buying the best discounted crudes we can with the highest value, which we, since we're direct coupled to the field, we do have a lot of optionality there that others don't have. And, you know, really to... You know, we're trying to drive our – we don't have our budget done for 21 yet, but we're trying to drive below $80 million on sustaining capital. That doesn't include the RD project, but at those kind of levels, you know, and we don't have any turnarounds planned immediately in this next year, as Tracy mentioned. You know, we think we can ride until easily the end of 21 without any problems. And at that point, then we start making some other decisions. But, you know, the forward curve is somewhat and a little bit in contango, but not enough for my liking. And as I mentioned earlier, really, it's all hinges on the virus and what happens with the jet fuel demand to see and the number of impaired operations or other refineries or actual shutdowns. There's still a lot of those that need to happen in this environment, and I think they will. If I did the math right, we're already at about 1.7 million barrels a day. That's been mothballed in some form. Even that includes us, which we're downrating Winnie Wood when we do RD. We're actually cutting crude. Coffeeville would be the same way. and we're reconfiguring for a different crude slate that actually reduces costs even more at both facilities. So there's a lot to come and a lot of knobs we still have to turn.

Thanks, Dave.

Our next question comes from the line of Paul Chang with Scotia Howard Wheel. Pleased to see with your question.

Hi, thank you. Good afternoon. Hi, 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.

$100 million for a 100-million gallon. And that fifth stock you will decide, is it 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 full put will be reduced by and how that product yield is going to change?

Well, we've retooled the refinery for more condensate processing, Paul, and what that really means is we keep our reformer full and equipment around that, and it basically puts Taking the hydrocracker out of the fuels processing means our catcracker rate directionally goes up, but we make similar type yields, probably a little less diesel, more gasoline, but not a lot, just on that shift.

And what is the total throughput we've been changed by?

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

Okay, so it will drop by somewhere between 15 to 20 million barrels, about 20,000 barrels per day. That's right.

That's right.

When we're in RD mode. Okay. And maybe that I get it wrong on the map. I think you're saying that assume the phase one is on stream, your net wind exposure will drop from 310, 320 down to about 135.

Yeah, you're close, but you forgot our internally produced RINs, which is about 21, 22% of our RVO. So that's roughly 65 million. I thought that would be about 60, 70, because

Your wind obligation is 310 to 320, right? So 20% will be 60 to 70. And the renewable diesel plan will be 170 on the wind. So should we be down to 80 only on your net exposure?

That's pretty close. Let's see. Was it equal to 77, 80 range? Something less than $100 million?

Right. Yeah, because I thought I heard you saying that it's a higher number, so I'm not sure that I thought I did something wrong.

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.

Okay, understand. But, I mean, in theory, that if you're running at – because it's only dropped by about 10% on the – on your obligation, given that your full put for the total company will only drop by about 10%, not about $20,000 per day. So we talked about $270,000. So that should still be, actually, if anything, that it should be even less in terms of your obligation. It should be less than $80,000. It should be more like in the $60,000.

Yeah, I came up with $70,000. $77,000, I think, Paul, with the I think you're on the right numbers.

Yeah, I just get confused that when you say $135. And Dave, I'm just curious that when you're talking about consolidation and the benefit of the M&A, how should we look at the CVR partner given there's less than $1 per share or per unit on the price, and you also have the option that you can essentially buy or at least that that is a possibility that you can buy it at the current price or that close to that. Does it make sense that for you to eliminate that MLP structure, given the whole look for the MLP structure going forward, and how low is the equity value anyway already? Or that you think that's a better value somewhere else and it's still not? Because on one hand, that CVR, partner is actually, as you indicate, that you are buying back some stock. So I would imagine that the board believes the valuation is attractive. And so if that's the case, why not just take it out, privatize it, and that you can have some saving on the regulatory fund so that you don't have to report it as a separate unit.

Well, you laid out a pretty good case there, Paul. But we continue to look at that at all times. You know, we don't know that the time's right right now, but it's something we evaluate all the time. And it is an option for us to do. You know, I think with the debt level that's expiring in 21, that, you know, we want to kind of see what we end up doing in that in 23. I guess it's debt in 23. So, you know, that's on the table. And, you know, the way we view the fertilizer side of the business, it's kind of a, It's been a great performer for us this year, frankly, and it shows the value of the diversified portfolio that can make sense. Now, the thing I'd say may offset that a bit, depending on who gets elected, if taxes go up a lot, the MLPs may come back in favor again, too. Who knows? We evaluate it all the time, though, and it's a good idea.

Okay. 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?

Well, you know, we're always looking at that. And if you did do a major acquisition like that, I think you would do it on a performable basis. which would change the numbers a bit. But I don't know that anything above a two is anything we're interested in, in terms of leverage. And that we're kind of there right now on our EBITDA basis, so.

So net, is that net set to EBITDA maximum two times?

Yeah, I don't think anybody in this space goes much above that.

Okay. On purpose. And, yep, sorry.

On purpose, I meant. They don't go much above it on purpose.

A final question for me maybe is for Tracy. How much is the tax refund you expect next year from the CARE Act? Do you expect in the second quarter or third quarter to receive it? And also whether the third quarter unit calls a good baseline to be used for the future forecast or that there'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 of 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 is very low. Is that a reasonable level that we can use as a baseline to forecast into the future, or that that's one of items whether plus or minuses that we need to take into consideration and adjustment.

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 costs 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, Chase, when you say that, are you talking about on a per-unit basis or on an absolute nominal? Like, are we talking about 420 per barrel as a reasonable baseline or 77 million as a reasonable baseline?

420 a barrel is a reasonable baseline.

I think we're going to drift, Paul, more towards four.

Four, yes.

But 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 a $4 level is doable.

And Dave, is there any reason we should expect your full put in the fourth quarter will 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.

OK. Thank you very much. You're welcome.

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

Hey, good morning, everyone. 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 50 cents in Cushing under WTI. So when you look at our gathering system, it'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.

Sounds good. 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 like 2023 and 2024? You know, there's some talk that, you know, 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 Blender's tax credit, it has always been there at a dollar 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 the 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 it 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 naturally will 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. Sounds good. Thanks. Sure.

Our next question comes from the line of Matt Vittorioso with Jefferies. Please proceed with your question.

Yeah, thanks for taking my question. Most of it's been asked. Maybe just quickly on fourth quarter cash flow, you mentioned in the third quarter you know, you got a big boost from working capital, some of that with 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.

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

And then, you know, I don't know how much you can say here, but maybe just you've gone through where some of the benchmark differentials and industry markers are here early in the fourth quarter. How should we think about just generic refining margin? You did $4.60 in the third quarter. Based on sort of what you're seeing in the market today, are we kind of at that same level in the fourth quarter or any big movements there?

Yeah, we haven't seen much change. I will say that these numbers where they're at are just not sustainable for the world, frankly, both on crude price and cracks. You're sitting here, you know, competing on the cost curve. And, you know, that, you know, again, most people will say, and I tend to say too, is when you have to make a big decision like a turnaround is when you really, the rubber hits the road. Because, again, we're not, you know, basically at these numbers, you're not recouping your turnaround accrued costs. There's just no way at these numbers. So something's going to have to give, you know, either on demand or on production. Supply demand will come back because it's just an economic fact that you either have to increase margins or cut rums. There's just no other way around it. All right.

Thank you. Okay.

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 that our next earnings recall. A 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.