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Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Greetings and welcome to the CVR Energy, Inc. Fourth Quarter 2020 Conference Call. [Operator Instructions] 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 CVR 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 maybe deemed to be forward-looking statements. You are cautioned that these statements maybe 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 and Form 10-K for the period and will be discussed during the call.
With that said, I will turn the call over to Dave.
Thank you, Richard. Good afternoon, everyone and thank you for joining our earnings call. I would 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 shutdown 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 $1 billion 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 Wynnewood in both 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 the Wynnewood, we plan to reduce refining capacity and retool for renewable diesel production, while also transitioning to a lighter gravity gathered crudes 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 Blueknight Energy’s 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 PADD IV, 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 Pytosh, announced the following accomplishments for our 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 search tank, which will further improve reliability of our gasifier at Coffeyville.
Yesterday, we reported – for CVR 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 $0.67. EBITDA for the year was a negative $7 million and for the quarter was a positive $1 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 a number of acquisitions that we viewed as attractive, ultimately, the bid/ask spread proved to be too wide. At this time, there are really – 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 Delek. Although as its largest shareholder, we continue to see the stock as undervalued and have some suggested actions Delek should take to improve its business. We also notified Delek of our intent to nominate three directors for election to Delek’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 returned 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 the light naphtha processing capabilities as narrow crude differentials continue to favor running very light crude slate.
Across the Board, benchmark cracks and crude differentials deteriorated significantly from a 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 2-1-1 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.
Light 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 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, including the volumes on the pipelines we have recently acquired from Blueknight.
In the Fertilizer segment, we had 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 planning 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 Delek investment and favorable inventory valuation impact 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 carry-back provisions of the CARES Act, we currently anticipate an income tax refund of $35 million 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 RINs 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 RINs prices, which reduced margin capture by approximately 71%.
Derivative losses for the fourth quarter of 2020 totaled $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. RINs 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 the 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 RINs from renewable diesel in the second half of the year, bringing our net RIN obligation for 2021 to approximately 190 million RINs. RINs expense for 2021 is expected to be comprised of the cost of this anticipated 190 million RIN obligation as well as any necessary mark-to-market on any remaining accrued RFS obligation. Subsequent to year end, we have reduced our 2020 RIN obligation 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 and 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 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 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 Wynnewood. 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 million to $230 million, of which $115 million to $125 million is expected to be environmental and maintenance capital and $95 million 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 turnarounds at Wynnewood and Coffeyville 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 31, 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 185,000 to 190,000 barrels per day. Due to the extreme winter weather and natural gas and power curtailments over the past 2 weeks, our Coffeyville and Wynnewood 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 million to $105 million and total capital spending to range between $65 million 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 million to $40 million, excluding inventory impacts, and total capital spending to be between $4 million 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 and 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 RINs. While vaccines are encouraging, so far we have 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 have 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 1 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 5-year averages. U.S. inventories are near 5-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 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 improvement in the market. Safe, reliable operations remains a key focus for us as a company. We will 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 Blueknight and working to maximize our 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 1 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 the development of Phase 2, 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 3 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 3. 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 are 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 as credit markets have strengthened, we intend to focus on potential refinancing those CVR Partners’ senior notes at much lower cost.
Looking at the first quarter of 2021, quarter-to-date metrics are as follows. Group 3 2-1-1 have averaged $12.77 per barrel with a Brent-TI spread of $3.11 per barrel and the Midland Cushing differential was $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 WTI. 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 6 and includes RINs, lenders tax credits and low-carbon fuel standard credit. As of yesterday, Group 3 2-1-1 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.
Quarter-to-date ethanol RINs, have averaged $0.94 and bio-diesel RINs have averaged $1.05. In January 2020, ethanol RINs averaged $0.16 and bio-diesel RINs averaged $0.40. A nearly six-fold increase in the price of ethanol RINs in 1 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 have 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 anytime. 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 are ready for questions.
Thank you. [Operator Instructions] 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, RIN prices are high, as you have elaborated quite in detail and we have been getting indications from the Biden EPA press release yesterday that they are 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 2 years? Or is this sort of within the range that you thought?
Well, I think they are higher than what we originally approved the project under. And I think most of us don’t – in this business don’t fathom and don’t understand in any way how a higher RIN price benefits anybody, including the Renewable Fuels Association and all their members. And really, if you look at past history, when they have 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 Wynnewood 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, Brent remain elevated as the project comes online, there could be some excess cash generation. My question would be, with that excess cash, what would be the priority, specifically, putting it more towards the pretreatment? It sounds like that’s early 2022, but maybe to get more aggressive there? Or would you be looking at starting to pay down debt first or address a little bit on the balance sheet? How would you take excess, 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 I’ve mentioned in the prepared remarks that the Board looks at this every month, every quarter and they will continue to do so. And they are 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 we decided to do nothing this quarter, but that doesn’t guarantee that, that will remain for the next quarters. If you look at our – I think I would say that we have too much cash on the balance sheet. It’s not optimum, and it’s – our – 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 pre-treatment facility, could you remind us – I think you’ve given us very clear numbers on how much the Wynnewood project reduces your RVO, and we can do the math on sort of the savings on that based upon our RIN 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 is anything incremental you could offer that would be helpful?
Yes. Well, the big advantage for a pre-treater is getting the CI down of the feedstock. If you look at all the feedstocks to renewable diesel right now, they are all up, including the waste oils, all up. Every single parameter is up, but the CI is the real prize. And that’s what the pre-treater will do for us. And typically, we’re still penciling in about $50 million to do that project, and that’s probably getting clean train and a dirty train. So we have a lot of optionality. And really – but if you really look at it, the really holy grail here is to get – to create oils out of biomass of some sort. And really the values in that is really getting at the low carbon fuel standard credits and even a cheaper feedstock to some degree.
How much of a – just one quick follow-up, how much of a CI score improvement would a pre-treater add versus what Wynnewood will be when it first starts up? Is there a ballpark range you could give us?
Yes. I think we will probably end up with washed and bleached soybean oil being around 58. And if you go to corn, I’ll just use corn oil as an example, that’s about 28, so a substantial improvement.
Okay. Thanks very much for taking the questions. I will 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 Delek on January 14. 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 how Delek and of course you because you own such a large portion of Delek. 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 Delek 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 are doing. The two refineries that we’ve suggested are marginal, our – the Crop Springs and El Dorado, and I think if my math is right, they are probably going to present negative gross margins. And really, 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. And as far as what the letter says, it says what it says, and I think you could read it just as well as I can.
That’s a fair one. Can you talk a little bit about the Board members you have recommended and why you think those will be the right fit for Delek?
Well, the Board members we have suggested are extremely experienced in this industry and are 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 2 pre-treatment unit. And Phase 1 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 3 can start a little before Phase 2 that actually gets you long RINs, so CVI, which has always been short RINs, becomes long RINs and then can benefit from higher RIN prices? And I’m just trying to understand, is there some flexibility here where the company could prioritize Phase 3 over Phase 2 to get actually long RINs?
Nothing makes me more upset than having to capitulate with the government on RIN, but they kind of force you into it. There is really no other option other than to grin and bear it. So I think the way I’d answer the question on Phase 3 is that if I do the math correctly, I see announced – almost 300,000 barrels a day of renewable diesel has been announced. How much of it gets built? I don’t know. But if I go down the list, it looks like 80% of it will probably happen to me. And some of it’s already in construction. Some of it will not get permit. Some of it will have other problems that won’t happen. But 300,000 is a whole lot of RINs, 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 of the – and I think our Board sees it the same way is that we want to get in here early and get the Wynnewood up, then we’ll 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, in another 2 years, we’re going to know a whole lot more about the renewable diesel.
Thank you. That all makes perfect sense. Thank you so much, Dave.
Our next question comes from the line of Phil Gresh with JPMorgan. 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 Wynnewood, how are things looking? And then going forward, how do you see the feedstock market really developing?
Yes. Well, I think this is an area of concern without a doubt for future projects coming on, but right now, there is still exports of bean oil going out offshore. So 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 with 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 that – the availability is there, it’s just a question of being able to get it in there timely and get it secured correctly in the right quality. But longer term, I think this is – as I mentioned, there is really – there is a Gen 3 coming that’s probably where the industry has to get to is this biomass. There is a lot of biomass out there. It’s just how to convert it. There is ways to do it. It’s – 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 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 is any possibility of further RIN market reform coming under the admin, maybe limiting RIN market participants or I guess, ex-RINs, is there any chance of a national LCFS standard that you’ve been hearing about?
Well, I think anything is possible with the current administration. And the shift in strategy is pretty dramatic and just by the evidence of that letter you mentioned. Normally, EPA has to go through rulemaking on all these things. 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 are 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. And what – if you read the law, it’s pretty darn clear. There is two sections of it that talk about waivers. One is an extension of the exemption. The other is, at any time, you can apply for a waiver. I will give you, for instance, like – just look at what we’re doing at Wynnewood. 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 that – 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 Donald Trump did a great job for the first 2 years and then fell apart in the last 2 years on RFS. And then Obama for many years was the same, no waivers. So it’s all political. It’s just – that’s no way to run a railroad and particularly a refining business.
Appreciate taking the questions.
Our next question comes from the line of Neil Mehta with Goldman Sachs. Please proceed with your question.
Thank you. 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 our overriding principle, Neil, is just – is free cash flow is what we’re all about. So I think our shareholders are interested in cash coming back, either through dividend or if the price is right, stock buybacks. And furthermore, they would 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 will tell you what it was last year, it was to do an acquisition that makes 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 RIN 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 then it either goes back as the latter two, but whether it’s a buyback or it’s an actual dividend itself.
Yes. That’s – 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 PADD IV 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. 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, unpredictable.
Yes. And I’ll sneak one more in there, if I could, is just I always value your view on the macro. Just talk about how you think the path looks for distillate 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, as I mentioned that the diesel crack is in contango and with crude in backwardation. And you see the distillate price continuing – on the future is going up and crude to be falling, and 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. And so I’m kind of – if you look at inventories and demands right now, it’s pretty good on distillate worldwide. So I think that’s recovered or 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 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 the WTI price, Midland WTI and Houston, it’s a premium to Cushing, and it needs to remain that way to – because it is a higher-value crude than Brent, but that differential is driven by shale oil production.
Thanks. 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. I had a question on the outstanding RIN liability, which sounds like it’s from Wynnewood 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? Yes. The K that will be filed tonight will have detail that outlines the accrued obligation specific line item.
Is it fair to say that – I think RIN prices are up about 20% since the start of the year. So if you have 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 an abnormal obligation that built.
Right, right, okay. And then the – I wanted to follow-up on the pre-treatment costs, was that $50 million and would that cover both the 100 million-gallon Wynnewood plant as well as the 150 million-gallon Coffeyville conversion?
Well, that’s one of the [indiscernible] we have, Matt, is really what do we do? Do we 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 Wynnewood project.
Got it. And then last question. I think your share of regional crude fell to a 45% of your total throughput, 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 onetime dynamic? It seems like, in general, you’ve been moving more to the regional crudes. So what explained the uptick in more Cushing-sourced barrels in Q4?
Mainly the pandemic as our gathering rates went way, way down in March, April, May, and they have been slowly recovering for a period of time, and now they are 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 Blueknight pipeline system added. That’s 600 miles, we think that 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 all crude procurement lined up and going. But it’s still dependent on – at the current crude prices, I think drilling will start again, although the E&Ps are much – as you all know is the E&Ps are much more focused on free cash flow than they are while drilling campaign. So how much crude will decline in the United States as anybody’s guess at this point, I think.
Sounds good. Thank you very much.
You are 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 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.