CVR Energy Inc.

Greetings and welcome to the CVR Energy, Inc. fourth 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 of Financial Planning and Analysis 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 Fourth Quarter 2020 Earnings Call. With me today are Dave Lamp, our Chief Executive Officer, Tracy Jackson, our Chief Financial Officer, and other members of management. Prior to discussing our 2020 Fourth Quarter results, Let me remind you that this conference call may contain forward-looking statements, as that term is defined under federal securities laws. For this purpose, any statements made during this call that are not statements of historical facts may be deemed to be forward-looking statements. You are cautioned that these statements may be affected by important factors set forth in our filings with the Securities and Exchange Commission and in our latest earnings release. As a result, actual operations or results may differ materially from the results discussed in the forward-looking statements. We undertake no obligation to publicly update any forward-looking statements, whether as a result of new information, future events, or otherwise, except to the extent required by law. Let me also remind you that CVR Partners completed a 1 for 10 reverse split of its common units on November 23, 2020. Any per-unit references made on this call are on a split-adjusted basis. This call also includes various non-GAAP financial measures. The disclosures related to such non-GAAP measures, including reconciliation to the most directly comparable GAAP financial measures, are included in our 2020 fourth quarter earnings release that we filed with the SEC in Form 10-K 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. I'd like to begin today's call with a brief discussion of our accomplishments in 2020, then discuss our operating performance for the quarter as well as for the year. 2020 was a challenging year for the United States, our industry, and our company. As the pandemic shut down the country and reduced demand for refined products, we were forced to adjust our strategy and adapt to the conditions we were presented. Despite these challenges of the year, we have a number of accomplishments worth highlighting. We maintained safe, reliable operations and back office functions during the COVID crisis. We successfully completed a billion-dollar notes offering in January of 2020, which provided us with additional cash and liquidity at attractive rates. We completed a major planned turnaround at our Coffeyville refinery during the beginning of the COVID crisis and deferred turnarounds at Winnie Wood and bulk fertilizer plants. We completed an ERP modernization project on time and on budget. We realigned our business strategy with a focus towards sustainability. With the board-approved renewable diesel project at Winneywood, we plan to reduce refining capacity and retool for renewable diesel production, while also transitioning to a lighter-gravity gathered crude at our refinery. While we intend to maintain our current capabilities in refining, we are focusing new investments towards growing our renewable diesel business and reducing our carbon footprint. We achieved significant reductions in SG&A operating costs, capital expenditures company-wide, exceeding our goal of $50 million annual reduction in SG&A and operating expenses. We announced the acquisition of Blue Knight Energies crude oil pipeline assets in Oklahoma, which closed in early February and expands our crude gathering reach at the wellhead. We evaluated multiple acquisitions in Pad 4, but maintained our capital discipline and refused to overpay for assets when we felt the bid-ask spread was still too wide. In our trucking business, we began hauling LPGs to our plants to reduce costs. We appealed the misguided Tenth Circuit court ruling to the Supreme Court, which has agreed to review the case. Earlier today, CVR Partners CEO Mark Pythos announced the following accomplishments for a fertilizer segment in 2020. Record ammonia production of 852,000 tons between the two plants, posting a combined utilization of 95% for the year. Certification of CVR Partners' first-ever carbon offset credits as a result of nitrous oxide abatement efforts. And our long-term air separation contract with Messer was renewed with favorable conditions, including the addition of a new oxygen surge tank which will further improve reliability of our gas supplier at Coffinville. Yesterday, we reported CBR Energy's full year and fourth quarter results. For the full year of 2020, we reported a net loss of $320 million and a loss of $2.54 per share. For the fourth quarter, we reported a net loss of $78 million and a loss per share of 67 cents. EBITDA for the year was a negative 7 million, and for the quarter was a positive million. Weaker crack spreads as a result of demand destruction from the pandemic, and dramatically higher RIN prices weighed heavy on our results for the full year and the quarter. The market remains volatile and uncertain. particularly in regard to RIN prices, which currently consume a significant portion of the refining margin available in the market. As a result, the Board of Directors did not approve a dividend for the fourth quarter of 2020. On the last few earning calls, I have discussed our focus on preserving our balance sheet and liquidity position in light of the ongoing pandemic, as well as potential acquisition opportunities that we were evaluating. Although we got far down the path on the number of acquisitions that we viewed as attractive, ultimately the bid-ask spread proved to be too wide. At this time, there are no active discussions on these potential transactions. We have also made it clear that we do not currently have any interest in acquiring Delit. although as its largest shareholder, we continue to see the stock as undervalued and have some suggested actions DELIC should take to improve its business. We also notified DELIC of our intent to nominate three directors for election to DELIC's board at its upcoming annual meeting. As we get more visibility into the sustained rebound of the refining market, We continue our discussions with the board around the appropriate level of cash return to shareholders and in what form. At current trading levels, there could be more value in buying back our own shares. For the petroleum segment, the combined total throughput for the fourth quarter of 2020 was approximately 219,000 barrels per day as compared to 213,000 barrels per day for the fourth quarter of 2019. Both the facilities ran well during the quarter, although the total throughput remained constrained by light naphtha processing capabilities as narrow crude differentials continued to favor running very light crude slate. Across the board, benchmark cracks and crude differentials deteriorated significantly from the year ago. Group 3 2-1-1 crack spreads averaged $8.44 per barrel in the fourth quarter of 2020. However, RINs consumed 40% of that at approximately $3.50 per barrel. The Group 3-211 averaged $16.65 per barrel in the fourth quarter of 2019, when RINs were only $1.15 per barrel. The Brent TI differential averaged $2.49 per barrel in the fourth quarter compared to $5.55 in the prior year period. The Midland to Cushing differential was $0.37 over WTI in the quarter compared to $0.94 over WTI in the fourth quarter of 2019. And the WCS to WTI crude differential was $11.44 per barrel compared to $18.89 per barrel in the same period last year. White product yield for the quarter was 103% on crude oil processed. Our distillate yield as a percentage of total crude oil throughputs was 44% in the fourth quarter of 2020, consistent with the prior year period. In total, we gathered approximately 117,000 barrels per day during the fourth quarter of 2020, as compared to 148,000 barrels per day for the same period last year. Our current gathering volumes are approximately 130,000 barrels per day, the volumes on the pipelines we have recently acquired from Blue Knight. In the fertilizer segment, we had a strong ammonia utilization at both of our facilities during the quarter, at 99% at Coffeyville and 103% at East Dubuque. Although fertilizer prices remained soft in the fourth quarter, year-over-year production and sales volumes were higher for both UAN and ammonia. With the rally in crop prices over the past few months, farmer economics have improved considerably, and this has driven higher demand for crop inputs. As a result, UAN and ammonia prices have increased significantly since the beginning of the year, and the outlook for spring planting currently looks favorable. Now let me turn the call over to Tracy to discuss our financial highlights.

Thank you, Dave, and good afternoon, everyone. Our consolidated fourth quarter net loss of $78 million and loss per diluted share of $0.67 includes a mark-to-market gain of $54 million related to our DELIC investment and favorable inventory valuation impacts of $15 million. Excluding these impacts, our fourth quarter 2020 loss per diluted share would have been approximately $1.18. The effective tax rate for the fourth quarter of 2020 was 23% compared to 40% for the prior year period. As a result of our net loss for the full year 2020 and in accordance with the NOL carryback provisions of the CARES Act, we currently anticipate an income tax refund of $35 to $40 million. The petroleum segment's EBITDA for the fourth quarter of 2020 was a negative $66 million compared to a positive $135 million in the same period in 2019. The year-over-year EBITDA decline was driven by significantly narrower crack spreads and elevated RENs prices. Excluding inventory valuation impacts of $15 million, our petroleum segment EBITDA would have been a negative $81 million. In the fourth quarter of 2020, our petroleum segment's refining margin, excluding inventory valuation impacts, was $0.56 per total throughput barrel compared to $11.86 in the same period in 2019. The increase in crude oil and refined product prices through the quarter generated a positive inventory valuation impact of $0.76 per barrel during the fourth quarter of 2020. This compares to a $0.61 per barrel positive impact during the same period last year. Excluding inventory valuation impact and unrealized derivative losses, the capture rate for the fourth quarter of 2020 was approximately 20%, compared to 79% in the prior year period. The most significant item impacting our capture rate for the quarter was elevated rent prices, which reduced margin capture by approximately 71%. Derivative losses for the fourth quarter of 2020 total $15 million, including unrealized losses of $23 million associated with Canadian crude oil and crack spread derivatives. In the fourth quarter of 2019, we had derivative losses of $19 million, which included unrealized losses of $24 million. RIN's expense in the fourth quarter of 2020 was $120 million, or $5.97 per barrel of total throughput, compared to $13 million for the same period last year. Our fourth quarter RINs expense was impacted by $64 million from this mark-to-market impact on our accrued RFS obligation, which was mark-to-market at an average RIN price of $0.89 at year-end and other market activities. The full-year 2020 RINs expense was $190 million as compared to $43 million in 2019. For 2021, we forecast a net obligation from refining operations of approximately 280 million RINs, adjusted for our expected internal blending volumes. We also expect to generate approximately 90 million D4 RENs from renewable diesel in the second half of the year, bringing our net REN obligation for 2021 to approximately 190 million RENs. RENs expense for 2021 is expected to be comprised of the cost of this anticipated 190 million REN obligation, as well as any necessary mark to market on any remaining accrued RFS obligation. Subsequent to year end, we have reduced our 2020 REN by approximately 8%. The petroleum segment's direct operating expenses were $3.99 per barrel of total throughput in the fourth quarter of 2020 as compared to $4.63 per barrel in the fourth quarter of 2019. For the full year 2020, we reduced operating expenses and SG&A costs in the petroleum segment by approximately $62 million compared to the full year 2019. The reduction in full year operating expenses and SG&A costs were a direct result of our cost savings initiatives, most of which we believe should be sustainable going forward. For the fourth quarter of 2020, the fertilizer segment reported operating loss of $1 million and a net loss of $17 million, or $1.53 per common unit, an EBITDA of $18 million. This is compared to a fourth quarter 2019 operating loss of $9 million, a net loss of $25 million, or $2.20 per common unit, an EBITDA of $11 million. The year-over-year EBITDA improvement was primarily due to higher sales volume and lower operating and turnaround expenses, offset somewhat by lower prices for UAN and ammonia. For the full year 2020, we reduced operating expenses and SG&A costs in the fertilizer segment by over $23 million compared to the full year 2019. During the quarter, CVR Partners completed a 1 for 10 reverse split and repurchased nearly 394,000 of its common units for approximately $5 million. In total, CVR Partners repurchased over 623,000 of its common units for $7 million in 2020, and the Board of Directors of CVR Partners General Partner has approved an additional $10 million unit repurchase authorization. Total units outstanding at the end of 2020 were $10.7 million, of which CVR Energy owns approximately 36%. The partnership did not declare distribution for the fourth quarter of 2020. The total consolidated capital spending for the full year 2020 was $121 million, which included $90 million from the petroleum segment, $16 million from the fertilizer segment, and $12 million for the renewable diesel project at Winneywood. Of this total, environmental and maintenance capital spending comprised $92 million, including $77 million in the petroleum segment and $12 million in the fertilizer segment. Actual spending for the year came in at the low end of our expected range, as a result of canceling or shifting certain projects into the future. We estimate the total consolidated capital spending for 2021 to be $215 to $230 million, of which $115 to $125 million is expected to be environmental and maintenance capital, and $95 to $100 million is related to the renewable diesel project. Our consolidated capital spending plan excludes planned turnaround spending which we estimate will be approximately $11 million for the year in preparation of the planned turnaround at Winnie-Winnie Coffeeville in 2022. Cash provided by operations for the fourth quarter of 2020 was $28 million, and free cash flow in the quarter was $4 million. Working capital was a source of approximately $105 million in the quarter, due primarily to an increase in our accrued RFS obligation. For the year, cash from operations was $90 million, and free cash flow was a use of $193 million. In addition, in January 2020, we refinanced and upsized our notes, which generated a net $489 million of cash. Turning to the balance sheet, we ended the year with approximately $667 million of cash, a slight increase from the prior year. Our consolidated cash balance includes $31 million in the fertilizer segment. As of December 31st, excluding CVR partners, we had approximately $929 million of liquidity which was comprised of approximately $637 million of cash, securities available for sale of $173 million, and availability under the ABL of approximately $365 million, less cash included in the borrowing base of $246 million. Looking ahead to the first quarter of 2021, for our petroleum segment, we estimate total throughput to be approximately 185, excuse me, to 190,000 barrels per day. Due to the extreme winter weather and natural gas and power curtailments over the past two weeks, our Coffeyville and Winniewood refineries both ran at reduced rates. We currently anticipate resuming normal operations at both facilities by the end of the month. We expect total direct operating expenses for the first quarter to be 95 to 105 million and total capital spending to range between 65 and 75 million. For the fertilizer segment, despite reducing operating rates at East Dubuque last week due to the extreme weather conditions and natural gas pricing, we estimate our ammonia utilization rate to be greater than 90% for the quarter. We expect direct operating expenses to be $35 to $40 million, excluding inventory impacts, and total capital spending to be between $4 and $7 million. With that, Dave, I will turn it back to you.

Thank you, Tracy. In summary... 2020 was a very challenging year, but we were able to navigate through this difficult environment. We believe we are well positioned to capitalize on any eventual upswing in the market. Our mission remains to be a top-tier North American refining and fertilizer company as measured by safe, reliable operations, superior financial performance, and profitable growth. Looking at 2021, Cracks have improved to start the year, although most of the increase is being consumed by out-of-control prices for RENs. While vaccines are encouraging, so far we've not seen any meaningful increase in demand for refined products. Domestic inventories are generally balanced, but utilization is still low and is starting to increase without a corresponding pickup in demand. In the near term, our outlook remains cautiously optimistic based on market fundamentals that we see. Starting with crude oil, we've drawn down about 50% of the excess crude oil inventories worldwide. Shale oil production is still declining, but drilling is starting to increase. Crude differentials are still narrow, but the Brent TI spread has widened some. And backwardation is firmly in place, supported by declines in inventories and the action taken by the Saudis. Moving on to refined products, gasoline demand is down approximately a million barrels per day, and vehicle miles traveled are showing declines. Jet demand remains low, mainly due to little international travel. Domestic demand is approaching five-year averages. U.S. inventories are near five-year averages, but still high. overall, while inventories and demand in the Magellan system are near normal. Exports are weak and imports are high. RINs are ridiculous, approaching $5 per barrel, putting RINs cost above operating costs. Looking at cracks, cracks have been trending up but barely keeping up with RINs. Diesel cracks are in contango and the domestic refining utilization is still still low at 83%. We believe cracks will remain relatively weak until demand supports utilization in the 90% plus level. The question is, what happens to RINs going forward? Right now, the industry is not generating sufficient free cash flow from refinery operations at these conditions, considering sustaining capital requirements and turnaround spending. Crack spreads and RIN prices are unsustainable at these levels over the long term. We believe we need to see more rationalization of capacity in order to see sustained move higher in cracks. To date, we have seen approximately 5 million barrels per day announced between permanent shutdowns, temporary idling, and potential closures worldwide, with 1.1 million of that in the United States. While we remain cautiously optimistic on the market in the near term, we continue to focus on what we can control to put us in the best position to take advantage of any improvements in the market. Safe, reliable operations remains a key focus for us as a company. We'll continue to work to minimize capital spending on our refining system other than what we consider critical to safe, reliable operations and remain compliant with applicable regulations. We are in the process of integrating our crude oil pipeline assets we acquired from Blue Knight and working to maximize their value to our system by reducing our purchases of Cushing Common. We are executing on our renewable diesel strategy. Our primary focus now is on getting phase one mechanically complete. We are currently in construction. We have everything ordered. We remain generally on schedule, although it is tight. As we move through Construction, we will focus on completing soybean oil procurement and renewable diesel marketing agreements. Next, we will begin development of phase two, which would involve adding pretreatment. We are currently evaluating different technologies and considering where we could build the unit and what capacity. We could potentially have a pretreatment unit installed by the end of 2022 or sooner if we go through a third party subject to board and other approvals. We will also begin planning for the potential phase three at Coffeyville. We will most likely wait until the first wave of large renewable diesel projects are completed to see where the market goes before making the final decision on phase three. We continue to believe that renewable diesel will become a commodity over time and that there is a clear advantage for being an early mover. For the fertilizer segment, we were more optimistic on the near-term outlook. Corn prices have rallied over 50% since October, significantly improving farmer economics and driving demand for crop inputs higher. We believe prices for nitrogen Fertilizers likely bottomed in 2022, and we currently expect demand for UAN and ammonia to be strong in 2021. The NOLA urea price has continued to increase as LNG and natural gas prices overseas have surged. As the business has improved and its credit markets have strengthened, we intend to focus on potential refinancing of CBR Partners' senior notes at much lower costs. Looking at the first quarter of 2021, quarter-to-date metrics are as follows. Group 3-2-1, Group 3-2-1-1 cracks have averaged $12.77 per barrel with a Brent TI spread of $3.11 per barrel and a Midland Cushing differential of $1.05 over WTI. WTL differential has averaged $0.71 per barrel over WTI. And the WCS differential has averaged $12.60 per barrel under WCI. Corn and soybean prices have increased significantly, and fertilizer prices have responded. Ammonia prices have increased to over $400 a ton, while UAN prices are $250 per ton. Renewable diesel margins have averaged $1.31 per gallon, quarter to date, based on soybean oil with a carbon intensity of 60. and includes RINs, lender's tax credits, and low-carbon fuel standard credits. As of yesterday, Group 3 211 cracks were $17.77 per barrel. Brent TI was $3.67, and WCS was $12.85 under WTI. Although benchmark cracks have improved, as I mentioned earlier, most of this move is associated with increased RIN prices. According to date, ethanol RINs have averaged $0.94 and biodiesel RINs have averaged $1.05. In January of 2020, ethanol RINs averaged $0.16 and biodiesel RINs averaged $0.40. A nearly six-fold increase in the price of ethanol RINs in one year should be clear evidence that the RFS program is broken. EPA's refusal to rule on outstanding small refinery waivers for 2019 and 20, while failing to issue a renewable volume obligation for 2021, despite their legal obligations, are significant factors in driving what we've seen over the past year in the RINS market. We are encouraged that the Supreme Court decided to hear the appeal of the misguided Tenth Circuit ruling and we do not believe they would have taken the case if they did not have serious questions about the ruling. The original intent of the RFS regulation was that small refinery waiver could be applied for at any time. We had an accrued RFS obligation at the end of 2020, which approximates our 2019 and 2020 obligations at Wynnewood for which waivers have been applied. Without the mark-to-market effect of this position, our capture rate would have been higher by 38% for the quarter. 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 2 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 Prashant Rao with Citigroup. Please proceed with your question.

Hi, good afternoon. Thanks for taking the question. First one, Dave, you know, RIN prices are high, as you've elaborated quite in detail, and we've been getting Indications from the Biden EPA press release yesterday that they're going to change course on SREs versus the Trump administration. So it looks like, first, we could be in a higher end price situation structurally for the near term. I wanted to ask, though, with respect to your renewable diesel expansion, are these prices or these price levels we're seeing, is this exceeding your expectations when you thought about the economics of those projects, that is, Do they have more economic value in your current view of what the RINs market will look like over the next year or two years? Or is this sort of within the range that you thought?

Well, I think they're higher than what we originally approved the project under. And, you know, I think most of us in this business don't understand in any way how a high RIN price benefits anybody. including the Renewable Fuels Association and all their members. And really, if you look at past history, when they've gotten this high, they tend to be knocked back down by some other change of approach, just because eventually it's going to affect the consumer, and the consumer is not going to like it. So I think it's exceeding our expectations now, but my thoughts are it will come down at some point.

But given the short, I mean, it seems like when you would have given the low cost is a fairly short payback period project even under your original expectation. So I guess my next question is if in the short term in that time, you know, RINs remain elevated as the project comes online, there could be some excess cash generation. You know, my question would be with that excess cash, what would be the priority specifically putting it more towards, you know, the pretreatment? It sounds like that's early 2022, but you know, maybe to get more aggressive there, or would you be looking at, you know, starting to pay down debt first or address a little bit on the balance sheet? How would you take, you know, access, I guess, savings or cash generation from the Wynnewood project in the back half of this year if the current environment persists?

Well, I think, you know, I mentioned in the prepared remarks that the board looks at this every quarter. and help continue to do so. And, you know, they're evaluating right now whether we should be buying back shares or doing something else with the cash, including buying down debt, if that made sense. So they consider everything every quarter and, you know, decided to do nothing this quarter, but that doesn't guarantee that that will remain for the next quarter. If you look at our, you know, I think I would say that we have too much cash on the balance sheet. It's not optimum, and we think our minimum cash requirements are around $250 million. So you can see we have excess cash, but we also have a lot of uncertainty in the marketplace. So we think cash is king in this environment to some degree.

Makes sense. Last question for me. The pretreatment facility, could you remind us I think you've given us very clear numbers on how much the Winningwood Project reduces your RVO, and we can do the math on sort of the savings on that based upon our rent price assumption. But how much more does the pretreatment add to that? How should we be thinking about that in terms of cost reduction or just total net cash flows? If there's anything incremental you could offer, that would be helpful.

Yeah, well, the big advantage for a pretreater is getting the CI down of the feedstock. If you look at all the feedstocks to renewable diesel right now, they're all up, including the waste oils. Every single parameter is up. But the CI is the real prize. And that's what the pre-treater will do for us. And, you know, typically we're still penciling in about $50 million to do that project. And that's probably getting a clean train and a dirty train. So we have a lot of optionality. If you really look at it, the really holy grail here is to create oils out of biomass of some sort. Really, the values in that is really getting at the low carbon fuel standard credits and even a cheaper feedstock to some degree.

Just one quick follow-up. How much of a CI score improvement would the pre-treater add? versus what Winniewood will be when it first starts up? Is there a ballpark range you could give us?

Yeah. I think we'll probably end up with washed and bleached soybean oil being around a 58. And if you go to corn, just use corn oil as an example, that's about a 28. So a substantial improvement.

Okay. Thanks very much for taking the questions. I'll turn it over. Sure.

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

Hey, Dave. I wanted to ask you about a letter you sent to Dalek on January 14th. We have gone through the letter all of us. I just want to understand from you the perspective of the letter, what is the aim here, how you think these suggestions would actually help out Dellick, and of course you, because you own such a large portion of Dellick. So if you could walk us a little bit through your letter and what's the aim of the letter here.

Well, I think we took on the Dellick investment as an investment, and we thought they were undervalued at the time, and we still feel they are. But there has to be some cleanup, so to speak, of their activities and what they're doing. You know, the two refineries that we've suggested are marginal are, you know, the Proud Springs and El Dorado. And I think if my math is right, they're probably going to present negative gross margins. And you really, you know, that in mind is a big piece. And as far as what the bottom line is, what we're trying to shift them from is a model of growth to a model of free cash flow, which I think is what CVI represents, is mainly free cash flow generation is our main strategy. And that bodes well in a market that's not necessarily growing but shrinking. As far as what the letter says, it says what it says, and I think you can read it just as well as I can.

That's a fair point. Can you talk a little bit about the board members you have recommended and why you think those will be the right fit for Dalek?

Well, the board members we have suggested are extremely experienced in this industry all around in their entire careers have been basically in value creation and free cash flow generation. And we think the refresh of the board will help a lot.

Okay. My last question here is, David, you talked about building a Phase II pre-treatment unit. And Phase I kind of cuts your RVO a lot, but there is still some obligation left there. And I was just wondering, is there any flexibility here where phase three can start a little before phase two? That actually gets you long rents. So CVI, which has always been short rents, becomes long rents and then can benefit from higher rent prices. And I'm just trying to understand if there's some flexibility here where the company could prioritize phase three over phase two to get actually long rents.

You know, nothing makes me more upset than having to capitulate with the government on rent. But it kind of forced you into it. There's really no other option other than to grin and bear it. So, you know, I think the way I'd answer the question on phase three is that if I do the math correctly, I see, you know, announced almost 300,000 barrels a day of renewable diesel has been announced. How much of it gets built, I don't know. But probably, you know, if I go down the list, it looks like 80% of it will probably happen to me. And, you know, some of it's already in construction. Some of it will not get permits. Some of it will have other problems that won't happen. But $300,000 is a whole lot of RENs, number one, but it's also a whole lot of low-carbon fuel standard credits. And that market has to move. Everything has to move with it. Of course, not to mention feedstock tightness is already occurring and probably will get even tighter. So I think our view, or at least mine, and I think our board sees it the same way, is that we want to get in here early and get Winnie Wood up. Then we want to watch the market for a little while. It will take us some time to develop the project anyway, so I don't think we're delaying it a lot by doing that, but we're going to, in another year, another two years, we're going to know a whole lot more about renewable diesel.

Thank you. That all makes perfect sense. Thank you so much.

Our next question comes from the line of Phil Gresh with J.P. Morgan. Please proceed with your question.

Hi, this is Nick on for Phil. First question would just be around feedstock availability for RD. I guess where you're standing at right now trying to secure the supply for SBO, for Woody Wood, how are things looking? And then going forward, how do you see the feedstock market really developing?

Yeah, well, I think this is an area of concern without a doubt for future projects coming on, but Right now, you know, there's still exports of bean oil going offshore. So, you know, I think we really don't have a problem securing it in the short term. We have to get after it, though. I mean, we're very close to agreements on how we're going to do that. So I don't think we have a problem securing it in the short term. Longer term, as we move to more of the more favorable CIs, I think that's really a question. The availability is there. It's just a question of... of being able to get it in there timely and get it procured correctly and the right quality. But longer term, I think this is, as I mentioned, there's really, there's a Gen 3 coming. That's probably where the industry has to get to is this biomass. There's a lot of biomass out there. It's just how to convert it. There's ways to do it. It needs more research. But it's the holy grail in this area. It's really... taking biomass and converting it to liquid fuel that has basically a negative CI. And, you know, that will be the holy grail, so to speak.

Thanks. And a second question. I know it was mentioned the Biden admin came out yesterday with the SRE opinion. Do you think there's any possibility of further rent market reform coming under the admin, maybe limiting rent market participants or I guess, XRINs, is there any chance of a national LCFS standard that you've been hearing about?

Well, you know, I think anything's possible with the current administration. And the shift in strategy is pretty dramatic, just by the evidence of that letter you mentioned. You know, normally EPA has to go through rulemaking on all these things, and And this is a 10-year history of doing waivers and interpreting the law the way they have. And now they suddenly come out and say, well, we're going to reinterpret it and say the Tenth Circuit was right. Well, that takes years of rulemaking to really get through the process. So I'm not sure what in the world they're thinking. But it's obviously confusing. And I think that's half the reason the Supreme Court took the case. because it's just blatantly wrong. If you read the law, it's pretty darn clear. There's two sections of it that talk about waivers. One's an extension of the exemption. The other is at any time you can apply for a waiver. I'll give you a for instance. Just look at what we're doing at Winningwood. We can probably run more barrels there. We choose to keep it below the level that's required for a small refinery waiver. Well, with renewable diesel, we're going to cut the rate by another 20,000 barrels. We're going to be in around under 60,000 barrels per day. That's why that was put in there. You could choose to become a small refiner in the future for multiple reasons, and climate change could be one of them. And the law was written to be flexible enough to allow you to do that. So it's just really what RFS has turned into as a political football, And, you know, Donald Trump did a great job for the first two years and then fell apart in the last two years on RFS. And Obama for many years was the same, no waivers. So, you know, it's all political. It's just that's no way to run a railroad, particularly a refining business.

Appreciate taking the questions.

Our next question comes from the line of Neil Meadow at Goldman Sachs. Please repeat your question.

Thank you. I appreciate the time this afternoon, guys. The first question is just around capital returns. Dave, you alluded to it on the call in your script, but how do you think about the reinstatement of the dividend? Is that dependent on getting clarity on demand and RINs? what are the milestones that we should be looking for around capital return, especially as you alluded to, you got cash on the balance sheet. And then how do you weigh buyback versus dividend? Just kind of walk us through the framework as we think about it.

Well, I think, you know, I think our overriding principle, Neil, is just as you say, is pre-cash flow. It's what we're all about. So, you know, I think our shareholders are interested in cash. back either through dividend or, if the price is right, stock buybacks. And furthermore, they'd be more interested in diversifying our business and coming up with an acquisition that, at the right price, would diversify our EBITDA, which we think would reflect in our stock price also. So the priority is, I'll tell you what it was last year, was to do an acquisition that made sense. And then as it evolved through the year, it kind of became renewable diesel. And again, we were kind of backed into a corner with higher rent prices to do something. I call it capitulation with the government, but others would probably call it something else. But I think it kind of tells a lot. If we can't do any of those others, then it becomes excess cash and it either goes back as the latter two. But whether it's a buyback or it's an actual dividend itself.

Yeah, the follow-up is around M&A. You kind of gave us the hint at it, but it sounds like you went down the path of Pad 4 acquisitions, and then the bid ask wasn't there. Can you just sort of unpack what you can say in terms of your acquisition strategy, what transpired, and how do you think about going forward? Is there a scenario where you come back and do a deal, or is that just off the table for the foreseeable future?

Well, you never can predict the future, Neil. Some of these deals may come back. Who knows? You know, we were up there as a lead candidate for a while, and we fell off the page. So you never know. It could come back at some time. Just unpredictable.

Yeah, and I think sneak one more in there, if I could, is just, you know, always value your view on the macro. Talk about how you think the path is. looks for distillate and margin in particular, where you have disproportionate exposure, and then Brent WTI looking out over the next year?

Well, I think I'd tell you on the distillate side is, you know, I mentioned that the diesel crack is in contango with crude and backwardation. And you see the distillate price continuing on the futures going up and crude to be falling. I think that bodes well. I think that says a lot to the industry about rebalancing, and I think we may actually be seeing some of the IMO 2020 coming into effect, where if bunker fuel ever recovered, it would demand more distillate. If you look at inventories and demands right now, it's pretty good on distillate worldwide. I think that's recovered. At least it's been rebalanced, let's put it that way. As far as the Brent TI goes, I'm a firm believer that if shale oil reemerges, I think the Brent TI reemerges also. Even with the pipeline capacity we have, to drive more and more barrels offshore requires Brent TI to be higher and higher. If you look at WTI price, Midland WTI in Houston, it's a premium to to Cushing, and it needs to remain that way because it is a higher value crude than Brent. But that differential is driven by shale oil production.

Thanks, Dave. Appreciate it. Sure.

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

Hey, good morning, everyone. I had a question on the outstanding RIN liability, which sounds like it's from Winnie Wood here. So I believe it was $86 million at the end of Q3. Where did that stand at the end of Q4? And then do you also have a number on where that stands today? I think, Tracy, you mentioned you had cut that down by about 8%. That is accurate.

That is what I said. What's The K that will be filed tonight will have detail that outlines the accrued obligation specific line item.

Is it fair to say that, you know, I think rent prices are up about 20% since the start of the year. So if you've cut it back by 8%, is it fair to say that today's obligation is higher than where you ended at the end of the year?

Yes. Because we also would have had another obligation that built.

Right, right. OK. And then I wanted to follow up on the pretreatment cost. Was that $50 million? And would that cover both the 100 million gallon Winnie Wood plant as well as the 150 million gallon Coffeyville conversion?

Well, that's one of the dilemmas we have, Matt, is really what do we do? build one common plant or build two pre-treaters. And we haven't made that decision yet. But the $50 million is really just to handle the Winnie Wood project.

Got it. And then last question. I think your share of regional crude fell to 45% of your total throughputs, which was the lowest in more than a year. And your share of WTI moved up to 36%. Was that just kind of like a temporary one-time dynamic? It seems like in general you've been moving more to the regional crude. So what explains the uptick in more pushing source barrels in Q4?

Mainly the pandemic. Our gathering rates went way, way down in March, April, May. And they've been slowly recovering for a period of time, and now they're starting to drop again as depletion occurs. Without any drilling, the shale oil barrels are the ones that fall off the quickest. You'll see a slight uptick now with the Blue Knight pipeline system added. That 600 miles, we think, can get us up to 25,000 barrels a day, maybe even a little bit more. once we get it up and fully running and, and all our crude procurement, uh, lined up and going. Um, but you know, it's still, it's still dependent on, you know, at the current crude prices, I think drilling will start again. Although the EMPs are much, as you, you all know, is EMPs are much more focused on free cashflow than they are, um, while drilling, uh, uh, campaigns. So how much, uh, crude will decline in the United States is anybody's guess at this point, I think.

Sounds good. Thank you very much.

You're welcome.

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 our employees, contractors, and the communities we operate in for their hard work and their commitment towards safe, reliable, environmental, and responsible operations. We look forward to reviewing our first quarter results, 21, during the next earnings call. Thank you.

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.