PBF Energy Inc. (PBF) Q4 2021 Earnings Report, Transcript and Summary

Good day, everyone, and welcome to the PBF Energy Fourth Quarter 2021 Earnings Conference Call and Webcast. At this time, all participants have been placed in a listen-only mode, and the floor will be opened for your questions following management's prepared remarks. [Operator Instructions] Please note this conference is being recorded. It is now my pleasure to turn the floor over to Colin Murray of Investor Relations. Sir, you may now begin.

Thank you, [Vikram] [Ph]. Good morning, and welcome to today's call. With me today are Tom Nimbley, our CEO; Matt Lucey, our President; Erik Young, our CFO; and several other members of our management team. A copy of today's earnings release, including supplemental information, is available on our Web site. Before getting started, I'd like to direct your attention to the Safe Harbor statement contained in today's press release. Statements in our press release and those made on this call that express the company's or management's expectations or predictions of the future, are forward-looking statements intended to be covered by the Safe Harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we describe in our filings with the SEC. For information, our PBF Energy and PBF Logistics 10-K report should be available in a week's time. Consistent with our prior periods, we will discuss results today excluding special items. In today's press release, we describe the non-cash special items included in our fourth quarter 2021 results. The cumulative impact of the special items increased net income by an after-tax benefit of $9.8 million, or $0.08 per share. Included in that number are the effects of the re-measurement of deferred tax assets, which resulted in a tax benefit for the quarter. There are a number of other notable items included in our results that Erik will highlight in his remarks. For reconciliations of any non-GAAP measures mentioned on today's call, please refer to the supplemental tables provided in today's press release. I'll now turn the call over to Tom Nimbley.

Thanks, Colin. Good morning everyone, and thank you for joining our call. Today, we reported fourth quarter earnings of $1.28 per share, and adjusted net income of $157 million. Before commenting on the macro environment, I would like to thank all of our PBF employees and all those who worked alongside us inside and outside of our refinery and terminal gates, for their dedication and efforts that allowed us to strongly finish what started out as a very challenging year. Through the fourth quarter, we continued building on the positive momentum generated by strong demand for our products. Our high complexity refining system benefited from improving crude differentials as OPEC+ continued their measured supply increases over the course of 2021. We expect that trend to extend into 2022. We are seeing strong demand for light crude in certain regions, which is also contributing to favorable differentials for lower-quality feed stocks. Having said that, crude markets remain tight, and in part this has led to tight product markets. As we exited 2021, inventories were low across the board. Domestic gasoline, diesel, and jet stocks are all currently below 2019 levels, and trailing five-year average lows. Perhaps more importantly, from a demands perspective, gasoline, diesel, and jet inventories are all below 2019 levels in terms of days of forward cover. We view this as a very constructive setup for 2022. Product inventories are low, demand continues to strengthen, and low refinery capacity due to global capacity rationalization should all support favorable refining margins. Demand remains the key driver. We expect demand in 2022 will continue its strong recovery, and exceed 2021. With that, I will now turn the call over to Matt.

Thank you, Tom. As Tom mentioned, we finished the year on a high note, and are pleased with the current market conditions as they are certainly trending in the right direction. Overall, PBF had a good quarter. We operated well in the East Coast, while completing turnaround work on the crude and sulfur units. While we suffered through on planned downtime in Toledo, the repairs are now complete, and we are running as planned. Chalmette ran well in the Gulf Coast and our West Coast assets ran very well, including the completion of turnaround on the cat feed hydrotreater and sulfur plant, at Martinez. Looking ahead to the first quarter, our CapEx and throughput guidance is presented in today's press release. The first quarter represents approximately 30% of our turnaround work for the year, with ongoing work primarily on the West Coast and the East Coast. Over the past year, we have advanced our renewable diesel project in Chalmette. We believe we have a top-tier project with regards to capital cost, operating cost, geographic flexibility, feed and product optionality, and time to market. To date, we have completed the project engineering and design. We work closely with the state of Louisiana and local official to earn their support and secure property tax incentives as well as all of the necessary permits to begin construction, which began last quarter. We fully anticipate that we will be in production with full capabilities in the first-half of next year. The project is designed for 20,000 barrels a day of renewable fuels capacity, with full pre-treatment capability. We expect our total project cost to come in under $2.00 per gallon, and we believe this compares favorably with projects of similar size and scope. We are able to achieve this capital efficiency by leveraging existing idled equipment at the Chalmette refinery, including an idle hydrocracker. In addition to the capital cost advantages, we also expect to have a top-tier facility in terms of operating costs. The facility will directly benefit from being collocated with an operating refinery. Additionally, Chalmette's location, essentially at the intersection of the Mississippi River and the Gulf of Mexico, is ideal with direct access to the green belt and trade flows on the Mississippi, and with full optionality to deliver [RD] [Ph] products to the most attractive markets globally. With the combination of operating expense and logistics advantages, we believe we will be able to deliver the lowest cost RD barrels into all the key demand markets, including Europe, Canada, and California, where we will be further advantaged by utilizing our existing statewide footprint. In parallel with the project development, we are evaluating a number of different financing alternatives across the capital structure. We are working with financial advisors and are encouraged by the interest expressed by potential counterparties. We should be able to provide an update on these activities in the coming months. Before turning the call over to Erik, I must comment on the RFS, and as this is still one of the industry's strongest headwinds that is also driving costs higher at the pump for every consumer in the country. After months of delay, the EPA finally offered RVO proposal for not only ‘21 and ‘22 but also adjusted 2020. While the EPA’s 2020 and 2021 proposals appropriately reflect actual RIN generation, the EPA proposed an unachievable RVO for ethanol RINs in ‘22. As most markets are, the RIN market is forward looking. And as such increase in ‘22 creates a shortfall whereby the market will need to rely on the depleting RIN bank and then increased advanced RIN generation. To end it more simply, RIN scarcity will persist. If the EPA fails to lower the ‘22 RVO by 1.5 billion gallons to be more in line with EIA demand projections, the scenario in which the market runs out of RINs that we laid out on previous calls would easily materialize in ‘22. This would create significant problems for the market at large. Administration has been hearing from a lot of stakeholders on the problems with ‘22 conventional biofuel requirement. So, we are hopeful there will be a pathway to a more sensible and workable program with the final rule. There is a lot more news coming in this area. And like you, we can speculate but will have to wait until the rule is finalized. With that, I’ll turn it over to Erik.

Thank you, Matt. A positive fourth quarter financial results reflect an improving refining market based on strong product demand as the recovery from the pandemic continues. Today, we reported adjusted EBITDA of approximately $425 million. Most importantly, our free cash flow generation continued to improve in the second-half of 2021 following our pivot to profitability during the second quarter last year. Our adjusted EBITDA includes two notable non-cash income items. We recognized roughly $80 million related to Q4 cash settlement of our California AB32 cap and trade obligations and approximately $75 million for net adjustments to our outstanding RINs obligation. Consistent with our prior 2021 quarters, we wanted to provide incremental context around our crude environmental expenses. Our overall accrual has decreased since Q3 by approximately $350 million to a balance of approximately $950 million. Of this, roughly $400 million relates to our California obligation that will be settled over the next few years. Our accrued RIN obligation at yearend was approximately $550 million. We continue to carry a mark-to-market RIN position which was valued at $450 million year end with the remaining $100 million being fixed price purchase commitments that we expect to be satisfied during the first quarter of this year. Consolidated CapEx for the quarter was approximately $169 million which includes $167 million for refining and corporate CapEx and $2 million for PBF Logistics. For the full-year 2021, our consolidated capital expenditures totaled just under $400 million. While our planned refining capital expenditures in 2022 are increased over 2021, we continue to focus on capital disciple. Our historical annual maintenance, environmental, regulatory, and safety capital expenditures have been consistently in the $150 million to $200 million range. And we expect this to continue in 2022. Consistent with our approach during the pandemic, we believe it is prudent planning to address near-term turnaround requirements. We expect to incur turnaround related capital expenditures of approximately $200 million to $225 million in the first-half of this year. Our liquidity positions remains consistent with more than $2.4 billion of total liquidity including approximately $1.3 billion of cash and in excess of $1.1 billion of borrowing availability at the end of the quarter. Throughout the pandemic by necessity, we maintained a level of liquidity and cash on hand beyond our day-to-day operational needs. As business conditions improve, we expect to return to previous operating levels of liquidity. As we discussed during our third quarter call, the deleveraging process is underway. Our efforts in 2021 resulted in debt reduction of more than $335 million. As mobility statistics continue to strengthen, demand for our core products will result in continued profitability that should translate into an organic form of lower net leverage at PBF. In addition, one of our near-term priorities is to amend and extend the bank facilities at PBF Holding and PBF Logistics, and to address the 2023 unsecured note maturity at PBF Logistics. Similar to the successful refinancing and extension of our multi-year inventory intermediation facility, our goal will be to find the most attractive balance between cost of capital, flexibility of structure, and tenure. Successful execution of this step lays the groundwork for a longer-term deleveraging, and addressing our 2025 debt maturities. Our goals are achievable in this market if we continue to focus on operating safely and reliably, controlling costs, and generating cash. Operator, we've completed our opening remarks, and we'd be pleased to take any questions.

Thank you. In a moment, we will open the call for questions. [Operator Instructions] First question is from the line of Phil Gresh with JPMorgan. Please go ahead.

Hey, good morning. Erik, with respect to your comments in terms of the quarter, just to make sure I fully understand the moving pieces, you talked about the mark-to-market effects with [RINs in AB32] [Ph]. Was there also any impact with respect to the changing of the RVOs in the quarter, and some of the other refineries kind of had some catch-up effects with respect to that?

Yes, that is the, roughly, the $75 million mark-to-market, right. RIN prices didn't move materially quarter-over-quarter. So, the $75 million relates to, let's call it, the standard change that came out in Q4. So, another way to say it is, the $425 million of adjusted EBITDA included roughly $155 million worth of income-related items, read non-cash income-related items there, the $80 million-plus to $75 million.

Okay, that makes sense. That's perfect, thank you. And then just overall, as you look at 2022, I know you mentioned the turnaround spending in the first-half, but how do you think about overall spending for 2022? And with the comments Matt was making on Chalmette, I guess is it officially moving forward, and will there be some one-time spending this year for that project? Just any additional thoughts you could share there.

Sure. So, of the $400 million that we spent throughout the course of 2021, there is around $45 million of cash that was invested in the renewable diesel project, right, it's primarily engineering, a handful of other commitments that were made during the year. Fortunately, the bulk of the spend on the renewable diesel project is going to be backend weighted, right. So, what we have today is we have advanced the project. Matt mentioned tax incentives that we've received. The project is fully permitted. And at this point, using financial advisors, we believe that we will be in a position to fully fund the project throughout the course of this year. Again, I think at this point, right, we're talking about an extremely competitive project, top quartile project with respect to cost. And so, from our standpoint, we believe there will be incremental outside capital that will come in and essentially help us as we continue to incubate this project internally.

So, I guess just on the cost, the below $2.00 pre gallon in cost for the project, is that a next cost inclusive of the tax credits and other things that you would expect or just how do you think about the next cost of PBF if there is no partner and I guess you're saying you'd move forward even if you didn't have a partner? And I'll turn it over. Thank you.

Just in regards to the net cost, we expect all the capital for us just to manufacture 20,000 barrels a day of renewable diesel with full pre-treatment capability to come under $2.00 a barrel -- at $2.00 a gallon, excuse me. The property tax incentive, that helps in regards to our operating expenses once we're operating, because that's an ongoing forgiveness from -- with the state of Louisiana. But to address your question as head on as we can, the $2.00 encompasses all capital required to be fully in the business.

So, Phil, this is a $600 million all-in, for which PBF, let's just round up, let's say that $45 million is $50 million. We've invested $50 million to date, through the course of 2021. Over the next six quarters, the plan would be to continue to invest the remaining $550 million. We've received all of our permits. The project is significantly de-risked. We will, at PBF, continue to incubate the project. We have received countless in-bounds. We believe, with some assistance, helping administer basically a capital raising project. Over the next six months, we will be in a position to fully fund the project through the remainder of 2023, and start producing renewable diesel midway through fiscal year 2023.

Got it, thank you.

Thank you. We have the next question from the line of Roger Read with Wells Fargo. Please go ahead.

Yes, thank you, good morning.

Hi.

I guess could we do two things? One, a little more detail on the turnarounds that you're encountering, kind of what you see maybe even broader across the industry. And then hit also how you're seeing the demand side. Obviously, you talked about it improving. There was a story that you're going to bring some of the units from Paulsboro back online as a function of, say, a story here. You put a press release out, but that you were seeing better demand on the East Coast and better supply-demand situation. So, was just curious how all that was fitting together here.

Paul -- I mean, Roger, excuse me, let me address the last question, and then I'll hand it over to Tom in regards to Paulsboro. We actually didn't put out a press release, there were some press reports. What my comment would be, the press reports weren't entirely accurate. We're continuously looking to optimize our system, not only on the East Coast, where we have two refineries, but across our system. We do that every single day. In that effort there are some things we are planning to do on the East Coast with some secondary units that will improve our clean product yield, and will reduce logistics cost between our two plants. But none of the headlines have changed in regards to we're not starting up a cat cracker, [you know, a coker] [Ph]. There's no major CapEx or no major throughput changes. So, some press reports were a bit erroneous, but we're always optimizing our system. And, indeed, we are continuously doing that on the East Coast as well. So, we will be starting up some secondary units, specifically in Paulsboro.

Yes, and I'll just add on that. This is Tom, good morning. Roger. Part of the issue is the East Coast configuration worked. It really did work. But as we started to see demand recovery and growing up our utilization, particularly in Delaware to take advantage of the market opportunities, we found ourselves getting constipated, if you will, in Delaware because of the intermediates being transferred from Paulsboro to Delaware when we shut down the cat cracker, the [coker] [Ph], et cetera. So, what we're really doing now is we're starting up a couple of units, not the big ones as Matt said, that is basically going to reduce those transfers significantly, Paulsboro will turn them into finished products. Not a significant increase in clean products production, but some high-value products production and a better capture rate. Regarding turnarounds, I think some of our -- on prior calls, our peers have indicated that everybody hunker down as best as you could during the pandemic, and certainly we did. And as Erik reinforced, we would not cut routine maintenance or jeopardize the operations integrity of the units, but we did take steps, like take smaller turnarounds, squats, do things of that nature. And now, we're going to go and start the return to more of a normal [RINs] [Ph] cycle. For us specifically, most of this is in the first-half of the year. We have already done one in Martinez. We'll be taking a turnaround in Torrance in the second quarter; Delaware City will be taking a turnaround their reformer. And in Chalmette is actually in the process of wrapping up a turnaround and on their aromatics and reforming unit. So, we've seen an increase, we were going back to kind of a normal type of a run pattern. And I think that's happening throughout the industry. And if you look at what the rigs are saying in terms of what the scheduled turnarounds are, they are quite high and exactly coupled with some of the unscheduled downtimes and the rationalization that I mentioned. Certainly seems to lay the groundwork for pretty high utilizations in the industry in the U.S. and frankly, other parts of the world.

I appreciate the clarifications. Thanks, guys. Good quarter.

Thank you, Roger.

Thank you. We have next question from the line of Doug Leggate with Bank of America. Please go ahead.

Good morning everyone and I appreciate the clarity on the unit we started. That was actually one of the things on our mind as well. Erik, I wonder if I could kick off with RIN costs. You obviously walked us through what the EBITDA impact was, I just wonder if you could quantify to the extent you can what the cash avoidance was -- the cash cost avoidance in the quarter, we're trying to get a handle on what the underlying cash power of the business is, if you had fully funded your current RIN and cash cost obligation?

Well, we have a net RIN Expense roughly incurred every month of about 50 million RINs, right? We've outlined our gross RVO in a regular way throughput environment of roughly 900 million RINs. So, that equates to we blend roughly a third, we have a net obligation that hits the P&L of 600 million RINs. So, assume on average, and it will obviously depend on turnaround, so other things. We have -- if we incur 50 million RINs per month of an obligation. I think we were relatively straightforward in our third quarter call and even going back to the end of the summer that we were continuing to carry a short related to 2021. We have essentially right we invested $185 million this past quarter to fulfill all of the firm fixed price commitments for our RIN position. We are now looking at this RIN position as a 2020, 2021 overall consolidated RIN position. I think what I would say is to put it in context had we been purchasing RINs on a reasonable basis throughout the course of 2021 we would have had over $800 million of RIN expense. Our P&L year-to-date is $725 million, hence the $75 million of adjustment that was flushed through the P&L, so recognized as income. The key piece is that an $800 million dollar RIN expense is more than 35% above what we pay just shy of 4,000 employees every year. That's really the key message. I think if we're trying to figure out what's the cash that this business can generate. Our refining business generated over $200 million of EBITDA during the quarter regular way. Right once we adjust for these mark-to-markets, an AB32 and PBF Logistics generated $60 million of EBITDA, that's what -- that's the core earnings power of the business in the fourth quarter, really driven by right West Coast and Gulf Coast. Now, we probably left. Go ahead, Doug.

No, I was just going to say that. I understand that, but I'm trying to -- what we're trying to figure out is if you are unable to somehow get relief for the RIN obligation. Your cash flow would have been lower. I'm trying to understand how much lower and I guess I don't related follow-up of the $950 million that you have. I guess, cumulatively accrued at the end of the year. What do you expect the cash cadence of that to be in terms of cash outflow? We completely concur with the stupidity of the RFS on a company like yourselves, but nevertheless, we got to acknowledge that as a potential obligation, we're trying to understand what it would look like if you met our obligation on a current cost basis?

So today, right we are we have we exited 2021 for RIN related liabilities $550 million, a 100 of that is fixed. $450 million relates to our RIN short position. So, number of RINs times the weighted average RIN cost as of the last business day of 2021. So, if that price didn't change, and we were required to fulfill that obligation, we would be on the hook for $450 million. That's the floating rate exposure.

All right, okay. I wish you good luck with --

Hey, Doug, hang on [multiple speakers]…

Just so we are clear, though, I just want to make sure you understand whether we're procuring the RINs in the market or not. We're fully expensing RINs throughout the quarter for whatever the prevailing RIN price is.

Right. Yes, now I understand that. And I appreciate the clarification guys. Hopefully my second question is a bit more constructive. A bit of a kind of macro question, but what we're trying to quantify is whether international gas European particular becomes a structural situation going forward, maybe not at current levels. I just wonder if you could help kind of quantify how you might think about the relative margin uplift for your system, versus let's say the generic European system as a consequence of significantly higher gas prices both for energy and obviously hydrotreating. I don't know if you can quantify that on a per barrel basis, is it two bucks, is it three bucks. Well, how would you frame that reference?

We looked at it and obviously it's going to be a function of the absolute spreads. When gas prices in Europe that well, even now, if there are $25 a day and that's over $150 equivalent oil, the retired versus the prices we are paying in the U.S. that probably results or translates to the following advantages. It's going to change on individual refinery configurations, et cetera. And it'll change based on whether or not that some of the refineries in Europe have the capability to switch to oil and therefore and maybe be able to blend some of their gas exposure. But if you can't do that, and basically with these spreads, you're probably looking at a $3 to $5 a barrel operating costs in our view advantage for U.S. or at least our system, given the size and the complexity, and the costs that we incur, and then you hit clearly on the second point, which is a very significant, well it's three points you make, it is the operating costs because we obviously buy natural gas to fire up the engine inside a refinery. But then, we buy either natural gas and process it in our own plants or by third party hydrogen that is made from natural gas in order to hydrotreat and hydrocrack and do all those other things. And there's a significant, obviously, increasing costs of hydrogen production with these prices, which would be an advantage for our system, the U.S. system versus Europe or any other place that's faced with these costs and what we're seeing on that though, is obviously if the cost of hydrogen goes up precipitously, it gives you a rather significant economic advantage to switch cruise fleets, change of cruise fleets, back out to the highest offer cruise and go to Sweden cruise and that basically just adds a little bit more fuel to the widening light, heavy fleet hours. The first question or the first comment you made, I think you're spot on, is this going to be a permanent structural thing? I don't know for sure. But my own personal view is this has kind of emerged are a second example of going into an energy transition with a goal set of goals, but perhaps not a well thought out strategy and execution plan. And that's the fact, you shut down the nuclear plants, you shut down the coal plant and yet now you're starting to shut down the fossil fuel plants to rely on solar and wind and if that's not available, well, it becomes a problem. And my own view is we're going to see more examples of that as we go forward.

I appreciate the answer. So, thanks so much.

Thank you. We have next question from the line of Theresa Chen from Barclays. Please go ahead.

Good morning. I'd like to understand your strategic thoughts around the competitive advantages of the Chalmette facility. Matt, I understand that you will have full pretreatment capability. And I guess my question is, is the idea to run on 100% low CI feedstocks or on a run rate basis do you see like between low CI and high CI, and if the former or if even if the book is low CI, just given the tightness in the market and the trouble that even experienced players has in capturing strong margins given the feedstock constraints, how do you plan to compete in that space?

So, what we plan to run are the most economic rate available in the marketplace. And as a facility that has advantages in regards to the capital that was required to entry of the business, the capital that’s required to operate the business, and the geographic footprint we have, we believe we’ll be the most -- one of the most competitive for all bids for all feeds. But in regards to do we plan to run all CI advantaged feeds or less advantaged feeds, we’ll have full flexibility and optionality to run what’s most economic to run within the give market. We have the capability to stand up a commercial organization around Ag teams. We are in the process of doing that. It’s critically important to get into that business and understand it early. So, we are in the process of doing that. We have full faith that we will be able participate in that market as efficiently as everyone else in the marketplace. And again, it’s no different than the refining business. You don’t know exactly when sweet crudes are going to going to be more attractive or the heaving crudes or the heavy or the sour crudes. So, what’s really important is making sure you have the optionality to run whatever you want and that you are in a location that’s going to be advantageous.

Got it.

Hang on a moment. [Multiple Speakers]…

Also that just in terms of I think you got to look at the marketplace perhaps little bit differently going forward. Renewable diesel is a superior product to biodiesel. And there will be transfers of feeds that are going into that market today. That will be call it for into the better margin environment for going into the renewable business.

Thank you. And Erik, was there anything to call out on the moving pieces with working capital this quarter?

I think yes. We tried to highlight for folks that we are going to have $435 million of cash going out the door, right? So, that’s clearly hit working capital related to this accrued viability or accrued expense line. At the same time, we were able to offset that by hitting some year-end inventory targets that’s probably worth between $200 million and $225 million. And then, there is an incremental $150-ish million that ultimately we benefited from again this is just continuing to focus on managing the balance sheet at this point. So, when we think through sources and uses of cash through the quarter specific to the refining business, we had about $785 million of stuff that left the system. And that was offset by a combination of clearly EBITDA, this inventory as well the other working capital. And your net cash went down by about $135 million Q3 to Q4.

Thank you.

Thank you. You next question from the line of Manav Gupta with Credit Suisse. Please go ahead.

I have a first policy question. And I know these are little tricky. But, I am hoping you have more visibility than we do. So, going back in August there was somewhat of a leak from EPA to Reuters, which put the RVO at 14.1 billion gallon for 2022. Then something changed. Somewhere in November the final number came out, we went right back up to 15 billion gallons. Now what we are hearing is that EPA is again recognizing that 15 billion gallons is not possible, so they are looking to again retroactively cut the 15 billion obligation back to [indiscernible]. So, obviously the first question I had was like what do you think happens here? Do they again go back somewhere around October and November say, okay, 15 was never possible. And so, let’s lower it back to some 14 number whatever. And then the question then to Erik would be that like you recognized the $75 million RVO benefit in your fourth quarter like would this become a kind of a recurring item then where you start with the 15 billion gallon number every year with EPA. Somewhere down the line they make a correction. And most refiners end up with the fourth quarter number which is an adjustment because RVO was lowered retroactively somewhere down the year?

I’ll start. In regards to the [reports] [Ph] and what ended up happening, I mean I think you can sort of [indiscernible] program has been [battered] [Ph] around. And to some degree, I think they got unintended results. I don’t think it was the administration’s intention to put out a program that was actually going to increase RIN prices. They try to make adjustments previous years without realizing that they tinkering with ‘22 that would have the consequences it did. I think they recognized that now. I think we’ve been very vocal to tell them directly. And our counterparts that represented workforce, building new trades, all the affected parties in this regard have been speaking to them. I think they certainly understand it. So, what they end up doing, we will see. But I think they certainly recognize that they did not get their desired outcome. And obviously, there should be huge pressure on them to adjust the price of gasoline for everyone. And I would think maybe in the 15 years I would think it would be much easier to do adjusting RVOs and negotiating with the RIN, but we shall see. And if the prices do get -- if the problem gets fixed, RINs become less scares, prices will come down. It’s good for the consumers. And it’s good for the losers on the side of the RIN war that’s persisted over the last 15 years.

And at this point, Manav, I think consistent with what we’ve done previously, right? If we go back to 2020 and 2021 and every year prior to that, we fully accrue for whatever the most recent kind of public data is available to us. So, we’ve clearly adjusted -- and it hit in Q4 of 2021, we adjusted for the historical retroactive reductions as we look into 2022, if nothing changes between now and the end of Q1, we will be accruing to the overall RIN percentages as they are laid out in the most recent pronouncement. If they subsequent to Q1 are suddenly reduced for whatever reason or changed, we will then change our overall accrual methodology. And it may result in pluses or minuses that will flow through the income statement. And then ultimately reside in the accrued expense section in our balance sheet.

Perfect. A quick follow-up here on the design of Chalmette, so, we are seeing two kind of design changes being made. One which is basically you split your hydrogen. You split kind of the facility. So, you end up with an RD facility, but then you end up with the refinery with a slightly lower nameplate capacity. The second obviously is the RD facility is coming on at the refinery but completely independent unit. So, there is no change to the nameplate capacity. And I just wanted to understand since you have done the engineering work here when other projects comes on, does the nameplate capacity of Chalmette change as it relates to refining?

It’s the later. As you described it, it will have zero impact on the operations at Chalmette. It’ll benefit from having all the utilities and all the infrastructure in place, but it’ll have zero impact on the refinery. When we bought the refinery, there was idled equipment from back when there a failed marriage between Exxon and PDVSA. And so, we are able discreetly use the idled hydrocracker. And it’s not connected in any way to the refinery operations.

Thank you so much for taking my question.

Thank you. We have next question from the line of Carly Davenport with Goldman Sachs. Please go ahead.

Hey good morning. Thanks for taking the questions. I just wanted to start on the liquidity side. You are still above $2 billion as of yearend. So, how are you thinking about optimal liquidity levels in this type of microenvironment? And I guess just thinking about the strong equity performance this year, is there any appetite to tap the public markets the accelerate deleveraging or the renewable diesel investment?

I’ll take it in sequential order there. I think at this point given where current crude prices, hydrocarbon prices are if we go back historically and look at where we were and adjust for obviously have a bigger business today than in the last time when crude prices were at this level, we would probably operate this business between $750 and a billion dollars of liquidity. That loosely translates into cash ranging, right, from a day-to-day operational perspective anywhere from $250 million to $500 million. There will be swings, right? Daily swings, but I think over a long period of time assuming again kind of again significant lack of volatility. Those are reasonable numbers to assume. Our first priority in 2022 is on making sure not only that we continue to operate well but on essentially refinancing the bank facilities that we have in place. So, that's our goal over the next six months. Then I believe we will be able to start attacking. All right, how do we directionally get back to regular way liquidity? All of these assumptions are predicated upon the forward curve that we see today, or some derivative thereof, coming to fruition. Right now we're seeing huge tailwinds in our business. We expect those to continue, then, as we address in the latter half of this year and into next year, let's assume the refinancing goes as planned, then we will ultimately be continuing to execute on the renewable diesel project. We would then have a partner associated with that. We believe the combination of all of those things, along with the organic delivering that we should benefit from, right. Our business is trending significantly closer to a trial, a trailing 12 months EBITDA for a year of north of a billion dollars, versus where we were a year ago, right things have changed significantly since the middle part of Q2 2021. That's ultimately the strategy. There are lots of moving pieces with all of that, but that's everything that we have kind of laid out to achieve in 2022. I think it's difficult to really sit here and say that we're going to do anything in the capital markets on a go forward basis. We obviously pay attention to where the share price is. But ultimately, our focus right now is on continuing to execute, generating free cash flow, to have both the organic deleveraging strategy along with that is the biggest piece that will help us with this refinancing effort as we go forward.

Great, that's really helpful. Thank you. And then the follow-up was just on the West Coast, which had a really strong quarter. It seems like there may have been some downtime from other operators in 4Q, but just curious real time as we start the year here, what you're seeing in terms of supply demand balances in California.

Yes, there were some issues in the fourth quarter, particularly in the Pacific Northwest. And in fact, there was this severe weather event that hit the Bay Area. We fortunately, all folks rode through that and I'm very proud of them, but there was some issues. But as we sit here today, we have a very tight market on the west coast. It's clear, demand is recovered. It slowed down a little bit here as it normally does in the first quarter because it started rain out in California. But it's recovered, the cracks have recovered. They're very strong. The crew differentials are better been benefited by all the things we've already talked around about, including out in California. And spread between Brent and ANS et cetera code. Those fundamentals are there. And the other overriding factor is you folks have often said in the past that the West Coast or California has long refinery or refinery and a half. Well that's no longer the case, because obviously, the Avon refinery and Martinez was shut down at 160 a day. The day always shutdown some capacity as they converted to renewables. So, you've got less availability, good, strong demand. And the last piece I would say is auto refineries in California are certainly, if they're in the top five refineries on the West Coast, no question in terms of their efficiency, complexity and power.

I appreciate that color.

Thank you. We have next question from the line of Connor Lynagh with Morgan Stanley. Please go ahead.

Yes, thanks. I wanted to return to that question around equity and I guess the question is just in light of your desire to bring a partner on Chalmette. Are we to read from your comments that you're not considering equity at this time to suggest that the terms offered by the partners that you're discussing and discussions with our favorable to what you would see in the public markets. I guess, basically, I'm just curious, what types of structures you're contemplating and what type of economics you'd be looking on that side?

I think it's difficult to pin down an exact structure what we've seen right, if we go back in time, over 12 months ago, when this project really started to pick up steam internally. Clearly PBF was in a different financial position. The market had a significant amount of forward uncertainty on what was coming at us. And what we've seen over the past 12 months is not only has our project continued to be de-risked internally, but we've seen a variety of different structures. We've seen everything from feedstock joint ventures. More recently, we've seen one of our peers, who ultimately ended up capitalizing a project using a variety of call it project/structured finance. So, not to say there's a million different ways to structure these things. But I think we have some internal views on overall where things can go. We will ultimately do what we believe is the right thing in terms of optimizing the structure and making sure that the structure fits within not only where we are today, but where we expect to be over the next couple of years as well. It could involve some type of equity partner for Matt's comments. It could involve a strategic partner. Those two partners could be one in the same it could end up being simply a financial partner that comes in and helps us finance. At the same time, we do believe there are other avenues, whether there are federally funded programs. We do have PBF Logistics as well. There's a variety of different ways that this thing can be structured. I think that's why quite frankly, having the assistance of a financial advisor as we make this kind of final piece of the puzzle fit together. That's going to be the most important thing for us over the next six months.

Understood and you were alluding to the need to have feedstock flexibility there. Just confirming, are you in favor of some sort of feedstock partnership? Do you think that's going to be a necessary strategic pillar of the project returns?

No. I don't think it's a necessary step. We're looking to maximize our efficiency in acquiring the most economic feeds, that very well could come in with a partnership, but we certainly believe will have the capability to acquire the feed necessary. We have tangentially been around the market and more work over the next year to staff up our capabilities specifically on some of the specific feeds, but there's no requirement.

All right, I appreciate the context. I'll turn it back.

Thank you. We have next question from the line of Karl Blunden with Goldman Sachs. Please go ahead.

Hi, good morning. Thanks for the time and the color on the capital structure. With the improved performance, both of the bonds and company itself, they've some more options opening up to you on the cap stack. When you think about the mix you'd like between secured and unsecured bonds over time, is there something you can share on that the securities do come with some covenants that limit flexibility in some way. So, I'd just be interested in that especially with the -- those high coupon securities becoming callable later this year?

I think our message is relatively consistent with going back to May of 2020 when we raised the first billion-dollar tranche of secured notes that ultimately that was an insurance policy. We did oversize it on the front end and we saw an opportunity to raise another 250 in December of '20. In hindsight, that proved to be absolutely the right decision for PBF simply because the pandemic went on longer than we believe anyone originally expected. So, our view has not changed. This is an insurance policy and over time, what we have outlined to investors to rating agencies and to the market is our long-term goal is to get back inside of that 40% net debt to cap number. We understand that, that will take some time. Again, it's going to come not only just with re-maneuvering within the cap stack, but we're going to have an inherent deleveraging again as our business continues to improve. We've gone from losing money a year ago to now being in a position where we're covering all of our fixed costs plus sum. Again, we have an insurance policy that's sitting on the balance sheet we are carrying around an awful lot of cash, again that we don't need for day-to-day operations. Our goal longer term will be to get back to a fully unsecured GAAP structure. We believe that is the appropriate structure in a regular way environment for a publicly traded independent refining business.

That's all really helpful. Erik, in terms of Paulsboro we spoke a little bit about potentially some capacity coming back, but you're looking at the market, when you do -- if and when you do make a decision to bring that up and fully ramp back to pre-COVID levels, do you have a sense of how long that would take once you make that decision, and what the cost would be at this point?

And just so there's clarity. At the moment, that's not the thing we're considering. It would take a couple months. It would not be extraordinary in regards to capital. There would be some work done, but at the moment, we're sticking to what we have. And we can obviously reevaluate that we preserve the equipment. But I don't want anyone listening to this call to come away with the idea that we're in the process of starting the major equipment that was shut down.

Understood, thanks very much.

Thank you. We have the next question from the line of Jason Gabelman with Cowen. Please go ahead.

Yes, good morning. Thanks for taking my questions. I just wanted to first ask maybe about the cash outlays for the RFS program moving forward. My understanding based on the current timeline is there won't be another cash outlay due to the government until 2023, the 2021 RIN obligation and 2022, both due in '23. Could you just confirm that, and maybe elaborate on the timing of those two yearly payments? And then the follow-up is just back on the Chalmette renewable diesel project, you said you've been kind of progressing it over the past year. And it seems like, at least in the equity markets, the support around renewable diesel equities has weakened. And so, the question is, can you characterize how your conversations have been going with potential partners in the project? Over the past year, have you seen more interest or less; has that interest been more enthusiastic or less, any type of characterization would be helpful? Thanks.

I think Erik alluded to it a year ago, when we were talking about the renewable diesel project. Much of it was more theoretical and an idea. We've tremendous progress over the last year. And so, like he said, all the engineering is complete, all the permitting is done. We've started putting pilings into the ground. And so, it's becoming much more real. In terms of the marketplace, we view our position, as I mentioned before, and our advantages puts us in an advantageous position. And I, at the end of the day, believe, as does the company, that there is going to be a marketplace incentivised, and you're going to have to have government involvement incentivised to manufacture renewable diesel. And it's not only a preference of this country, but the rest of the world. And that can come in the form of the margin itself, but obviously you have [indiscernible] tax credits, you have RINs, you have LCFS program. And we're not projecting any one program or one aspect of it, but in general as the price have probably been going forward, we believe there is going to be a market incentive to manufacture renewable diesel. And we think we're going to be very well-positioned due to that considering all the strengths we bring to it. In regards to the RINs timing of payment, of course it's a political program that's broken, it doesn't live up to any of its stated requirements. So, when the payments are due is anyone's guess, because it'll depend on when the final rule comes out. You have to remember what came out previously was a -- the recommendation. And then they took comments on it. But the final rule has yet to come out, and that's where we think there is a reasonable chance that they may reconsider what they propose. But the timing of which will completely depend, the ultimate RVO deadlines will depend on when that final rule comes out. So, the 2020, it's possible it could be at the end of this year, but it's possible that could be pushed if the final rulemaking doesn't come out for some time. So, I think if they stuck to something this spring, the 20 is maybe December 1, but when do they actually put it out, if you find out let me know.

The other thing just to note too on renewable diesel that we should make note of here is, not only is Chalmette strategically located, it has the benefit of this idled equipment, we are able to essentially take advantage of extremely large industrial in situ infrastructure, with hydrogen, steam, et cetera. But we also have the other end with the only really true available domestic LCFS program; we are a very large operator in California. We're in the LCFS market every day. We control our own proprietary distribution system as well in California. So, we can not only bring product in, we can distribute through, again, assets that we control today. That's an important point when we think through the overall value chain supply chain of not only producing this stuff, which again, what do we need to do? We're good at capital projects, we're good at execution. Matt mentioned we are in the process of staffing up a team on the feedstock side of things. And, quite frankly, we already have the product disposition side of things from our perspective, based on where the market is today, is California. It looks as if New Mexico will be coming at some point. Canada will be coming. We believe there will be other markets. Europe is an available market as well. But when we think through what is one of the largest kind of consumers of renewable diesel today in the state of California, we believe we have an added advantage there as well.

Mr. Gabelman, do you have any further questions?

No, that was it from me. Thanks.

Thank you. We have a final question from the line of Matthew Blair with Tudor, Pickering, Holt. Please go ahead.

Hey, good morning, and thanks for taking my question. I'll just end with one here. So, I had a question on the California market. The Q3 LCFS data showed that about 33% of diesel consumed in the state was either biodiesel or renewable diesel. And so my question is, are Torrance and Martinez, are they still able to place 100% of their diesel production in the state or have you had to, I guess, look for new markets, export some of the diesel to Singapore or Canada or Mexico?

No, we're selling all of our diesel out of those two refineries on the West Coast.

Great, thank you.

Thank you. We have reached the end of the question-and-answer session. And now, I would like to turn the call over to Tom Nimbley for closing remarks. Over to you.

Thank you, and thank everybody for attending the call today. We look forward to our next call with you, where we hope to give you further clarity and updates on our key priorities, including deleveraging and the progress on the renewable diesel project. Everybody have a great day.

Thank you very much. This concludes today's conference. And you may now disconnect your lines at this time. Thank you for your participation.