Good day, everyone, and welcome to the PBF Energy Q4 2021 earnings conference call and webcast. At this time, all participants have been placed in a listen-only mode, and the floor will be open for your questions following management's prepared remarks. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. 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 begin. Thank you, Vikram. 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 website. 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 our 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 remeasurement 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 improved 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 feedstocks. 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 demand 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 also 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 on the East Coast while completing turnaround work on the crude and sulfur units. While we suffered through unplanned downtime in Toledo, the repairs are now complete and we are running as planned. Chalmette ran well on the Gulf Coast, and our West Coast assets ran very well, including the completion of turnarounds 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 East Coasts. Over the past year, we've advanced our renewable diesel project in Chalmette. We believe we have a top-tier project with regards to capital costs, operating costs, 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 officials 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 pretreatment capability. We expect our total project cost to come in under $2 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 idled 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 co-located 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 Grain Belt and trade flows on the Mississippi and with full optionality to deliver RD 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 their RVO proposal for not only 2021 and 2022, 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 2022. As most markets are, the RIN market is forward-looking, and as such, the increase in 2022 creates a shortfall whereby the market will need to rely on the depleting RIN bank and an increased advanced RIN generation. Stated more simply, RIN scarcity will persist. If the EPA fails to lower the 2022 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 could easily materialize in 2022. This would create significant problems for the market at large. The administration has been hearing from a lot of stakeholders on the problems with 2022 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 to come in this area, and like you, we can speculate, but we'll have to wait until the rule is finalized. With that, I'll turn it over to Erik. Thank you, Matt. Our 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 the Q4 cash settlement of our California AB 32 cap-and-trade obligations and approximately $75 million from net adjustments to our outstanding RINs obligation. Consistent with our prior 2021 quarters, we wanted to provide incremental context around our accrued 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 obligations that will be settled over the next few years. Our accrued RIN obligation at year-end was approximately $550 million. We continue to carry a mark-to-market RIN position, which was valued at $450 million at 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 discipline. Our historical annual maintenance, environmental, regulatory, and safety capital expenditures have been consistently in the $150 million-$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-$225 million in the first half of this year. Our liquidity position 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 tenor. Successful execution of this step lays the groundwork for 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. The company requests that all callers limit each turn to one question and one follow-up. You may rejoin the queue with additional questions. If you'd like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star two if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. One moment, please, while we poll for questions. First question is from the line of Phil Gresh with J.P. Morgan. 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 and AB 32. Was there also any impact with respect to the changing of the RVOs in the quarter and some of the other refiners kind of had some catch-up effects with respect to that? Yeah. That is 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. Another way to say it is the 425 of adjusted EBITDA included roughly $155 million worth of income-related items, right? Non-cash income-related items there, the 80 plus the 75. 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? 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. 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 back-end weighted, right? 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. 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. I guess just on the cost, the below $2 per gallon cost to the project. Is that a net cost, inclusive of the tax credits and other things that you would expect? Or just how do you think about the net cost to PBF if there is no partner, and I guess you're saying you'd move forward even if you didn't have a partner. I'll turn it over. Thank you. Just in regards to the net cost, we expect all the capital required to manufacture 20,000 barrels a day of renewable diesel with full pretreatment capability to come under $2 a barrel. I mean, $2 a gallon, excuse me. The property tax incentive that helps in regards to our operating expenses once we're operating, because that's forgiveness with the state of Louisiana. But to address your question as head-on as we can, the $2 encompasses all capital required to be fully in the business. Phil, this is a $600 million project all in, for which PBF, let's just round up, let's say that 45 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 inbounds. 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 next question from the line of Roger Read with Wells Fargo. Please go ahead. Yeah, thank you. Good morning. 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. Then, hit also how you're seeing the demand side. Obviously, you talked about it improving. There was a story that you're gonna bring some of the units from Paulsboro back online as a function of. I say a story. You put the press release out that you were seeing better demand on the East Coast and better supply-demand situation. I was just curious how all that was fitting together here. 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, so there were some press reports. 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. It'll reduce logistics costs between our two plants. None of the headlines have changed in regards to we're not starting up a cat cracker or the coker. There's no major CapEx, or no major throughput changes. Some press reports were a bit erroneous, but we're always optimizing our system. Indeed, we are continuously doing that on the East Coast as well. We will be starting up some secondary units, specifically in Paulsboro. Yeah, I'll just add on that. It's Tom. Good morning, Roger. Part of the issue is the East Coast configuration worked. It really did work. As we started to see demand recovery and bring 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, et cetera. What we're really doing now is we're starting up a couple units, not the big ones, as Matt said. That is basically gonna 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 on prior calls our peers have indicated that everybody hunkered down as best they could during the pandemic, and certainly we did. As Erik reinforced, we would not cut routine maintenance or jeopardize the operational integrity of the units, but we did take steps like take smaller turnaround scopes, do things of that nature. Now we're going to go and start to return to more of a normal run-length 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 on their reformer. Chalmette is actually in the process of wrapping up a turnaround and on their aromatics and reforming units. We've seen an increase. We're going back to kind of a normal type of a run pattern, and I think that's happening throughout the industry. If you look at what the rags are saying in terms of what the scheduled turnarounds are, they are quite high. That 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. 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. Thanks. Good morning, everyone, and I appreciate the clarity on the unit restart. 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 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 throughput environment of roughly 900 million RINs. That equates to we blend roughly a third. We have a net obligation that hits the P&L of 600 million RINs. Assume on average, and it will obviously depend on turnarounds, other things, 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 ratable 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 RIN expense is more than 35% above what we pay just shy of 4,000 employees every year. Mm-hmm. 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 and AB 32, 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. We prob- I- We probably left. Go ahead, Doug. Go on. No, I was just gonna 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. I guess as a 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've got to acknowledge that there's a potential obligation. We're trying to understand what it would look like if you met that obligation on a current cost basis. Today, right, we exited 2021 for RIN-related liabilities, $550 million. $100 of that is fixed. $450 million relates to our RIN short position, number of RINs times the weighted average RIN cost as of the last business day of 2021. 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. Right. Okay. Well, wish you good luck with. Just, just- Hey, Doug? Hang on a minute, Doug. Doug, just so we're clear, though, I just wanna 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. Yeah, no, I understand that, and I appreciate the clarification, guys. Hopefully, my second question is a bit more constructive. It's a bit of a kinda macro question, but what we're trying to quantify is whether international gas, Europe in particular, becomes a structural situation going forward, maybe not at current levels. I just wonder if you could help kinda 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 $2? Is it $3? How would you frame that reference? We've looked at it, and obviously it's gonna be a function of the absolute spreads. When gas prices in Europe, well, even now if they're at $25 a million, that's over $150 equivalent oil. You use that versus the prices we're paying in the U.S. That probably results or translates to the following advantages. It's gonna change on individual refinery configurations, et cetera. It'll change based on whether or not some of the refineries in Europe have the capability to switch to oil, and therefore maybe be able to blunt some of their gas exposure. If you can't do that, then basically, with these spreads, you're probably looking at a $3-$5 a barrel operating cost, in our view, advantage for U.S. or at least our system, given the size and the complexity, and the cost that we incur. You hit clearly on the second point. Well, there's 3 points you made. There's the operating cost because we obviously buy natural gas to fire up the engine inside a refinery. We buy either natural gas and process it in our own plants or buy third-party hydrogen that is made from natural gas in order to hydrotreat and hydrocrack and do all those other things. There's a significant, obviously, increase in cost 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 set to face these costs. 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 crude slates, change your crude slates- Right. back out the higher sulfur crudes and go to sweeter crudes, and that basically just adds a little bit more fuel to the widening light heavies or sweet sours. Right. Yep. Right. Yep. The first question or the first comment you made, I think is just spot on. Is this gonna be a permanent structural thing? I don't know for sure, but my own personal view is this is kind of maybe the first or 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. That's the fact. You shut down the nuclear plants, you shut down the coal plants, and now you're starting to shut down the fossil fuel plants to rely on solar and wind. If that's not available, well, it becomes a problem. My own view is we're gonna see more examples of that as we go forward. Appreciate the answers, fellas. Thanks so much. Thank you. We have next question from the line of Theresa Chen from Barclays. Please go ahead. Morning. I'd love 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 the idea to run on 100% low CI feedstocks? Or on a run rate basis, do you see a split between low CI and high CI? If the former or if even if the bulk is low CI, just given the tightness in the market and the trouble that even experienced players have in capturing strong margins, given the feedstock constraints, how do you plan to compete in that space? What we plan to run are the most economic grades available in the marketplace. As a facility that has advantages in regards to the capital that was required to enter the business, the capital that's required to operate the business, and the geographic footprint we have, we believe we'll be one of the most competitive bids for all feeds. In regards to do we plan to run all CI advantage feeds or less advantage feeds, we'll have full flexibility and optionality to run what's most economic to run at any given market. We have the capability to acquire, you know, stand up a commercial organization around ag feeds. We're in the process of doing that. It's critically important to get into that business and understand it as early. We're in the process of doing that. We have full faith that we'll be able to participate in that market as efficiently as everyone else in the marketplace. Again, it's no different than the refining business. You don't know exactly when the sweet crudes are gonna be more attractive or the heavy crudes or the sour crudes. What's really important is making sure you have the optionality to run whatever you want and that you're in a location that's going to be advantageous. Got it. Can I add something also to that? Sorry, hang on one second. Just in terms of I think you got to look at the marketplace perhaps a 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 called for into the better margin environment that are going into renewable diesel. Thank you. Erik, was there any, I think, to call out on the moving pieces with working capital this quarter? I think, yes. We did. You know, we tried to highlight for folks that we were gonna have $435 million of cash going out the door, right? That clearly hit working capital related to this accrued liability 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. Then there's 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. 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 as the other working capital, and your net cash went down by about $135 million, Q3 to Q4. Thank you. Thank you. We have next question from the line of Manav Gupta with Credit Suisse. Please go ahead. Hi. I have a first policy question, and I know these are a little tricky, but I'm hoping you have more visibility than we do. Going back in August, there was somewhat of a leak from EPA to Reuters, which put the RVO at 14.1 billion gallons 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 a certain number. Obviously, the first question I had was, 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 or whatever." 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 a 15 billion gallon number every year with EPA, somewhere down the line they make a correction, and so most refiners end up with a fourth quarter number, which is an adjustment because, RVO was lowered retroactively somewhere down the year. I'll start in regards to the reports and what ended up happening. I mean, I think you can sort of lay it at the feet of the politicians. Look, this program's been batted 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 tried to make adjustments to previous years without realizing that if they tinker with 2022, that would have the consequences it did. I think they recognize that now. I think we've been very vocal to tell them directly. Our counterparts with the represented workforce, the building and trades, all the affected parties on this in this regard have been speaking to them, and I think they certainly understand it. What they end up doing we will see, but I think they've certainly recognized that they did not get their desired outcome. Obviously, there should be huge pressure on them to adjust the price of gasoline for everyone. I would think, although maybe not over the last 15 years, I would think it would be much easier to do adjusting RVOs than negotiating with Iran. You know, we shall see. If the prices do get or if the problem gets fixed, RINs become less scarce, 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. 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. 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 is on the design of Chalmette. 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 a refinery, which is 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. I just wanted to understand, since you have done the engineering work here, when the project comes on, does the nameplate capacity of Chalmette change as it relates to refining? It's the latter, 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 some idled equipment from back when there was a failed marriage between Exxon and PDVSA, and so we're able to 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're still above $2 billion as of year-end. How are you thinking about optimal liquidity levels in this type of macro environment? And I guess just thinking about the strong equity performance this year, is there any appetite to tap the public markets to 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 having a bigger business today than the last time when crude prices were at this level, we would probably operate this business with between $750 million and $1 billion 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 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. That's our goal over the next six months. 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. 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 de-levering that we should benefit from, right? Our business is trending significantly closer to a trailing 12 month EBITDA figure of north of $1 billion 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. [audio distortion] Yeah. I think it's difficult to really sit here and say that we're gonna do anything in the capital markets on a go-forward basis. We obviously pay attention to where the share price is. 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. 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 and demand balances in California. Yeah. There were some issues in the fourth quarter, particularly in the Pacific Northwest. In fact, there was this severe weather event that hit the Bay Area. Fortunately, our folks rode through that, and I'm very proud of them. There was some issues. 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 to rain out in California. It's recovered. The cracks have recovered. They're very strong. The crude differentials are being benefited by all the things we've already talked about, including out in California, the spread between Brent and ANS, et cetera. Those fundamentals are there. The other overriding factor is, you folks have often said in the past that the West Coast or California's long of a refinery or a refinery and a half. Well, that's no longer the case because obviously the Avon Refinery in Martinez was shut down. That's 160 a day. The day always shut down some capacity as they converted to renewables. You've got the less availability, good strong demand, and the last piece I would say is our two 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. Appreciate that color. Thank you. We have next question from the line of Connor Lynagh with Morgan Stanley. Please go ahead. Yeah, thanks. I wanted to return to that question around equity. I guess the question is just in light of your desire to bring a partner on at 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 in discussions with are 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 at 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. 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. 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 years as well. It could involve some type of equity partner, per Matt's comments. It could involve a strategic partner. Those two partners could be one and 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. 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 we'll have the capability to acquire the feed necessary. We have tangentially been around the market, and we'll work over the next year to staff up our capabilities, specifically on some of the specific feeds, but there's no requirement. All right. 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 all the time and the color on the capital structure. W ith the improved performance, both of the bonds and the company itself, you have 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 secured notes do come with some covenants that, you know, limit flexibility in some way? I'd just be interested in that, especially with those high coupon secured notes becoming callable later this year. I think our message is relatively consistent with going back to May of 2020 when we raised the first, you know, $1 billion tranche of secured notes, that ultimately was an insurance policy. We did oversize it on the front end, and we saw an opportunity to raise another $250 million in December of 2020. 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. 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 will take some time. Again, it's gonna come not only just with re-maneuvering within the cap stack, but we're going to have an inherent de-levering, 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 some. 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 cap structure. We believe that is the appropriate structure in a regular way environment for a publicly traded independent refining business. That's, I think that's all really helpful, Erik. In terms of Paulsboro, we spoke a little bit about potentially some capacity coming back, but, you know, you're looking at the market. 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? Just so there's, you know, clarity. At the moment, that's not something 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've preserved 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 restarting the major equipment that was shut down. Understood. Thanks very much. Thank you. We have next question from the line of Jason Gabelman with Cowen. Please go ahead. Yeah, morning. Thanks for taking my question. 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 RVO obligation and 2022 both due in 2023. Can you just confirm that and maybe elaborate on the timing of t hose two yearly payments. 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. 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, 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 made tremendous progress over the last year. Like you 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. I at the end of the day believe, as does the company, that there's going to be a marketplace incentivized, and you're going to have to have government involvement incentivized to manufacture renewable diesel. It's not only a preference of this country, but the rest of the world. That can come in the form of the margin itself, but obviously, you have Blenders Tax Credits, you have RINs, you have LCFS programs. We're not projecting any one program or one aspect of it. In general, the price of carbon going forward, we believe there's going to be a market incentive to manufacture renewable diesel. We think we're gonna be very well positioned to do that considering all the strengths we bring to it. In regards to the RINs timing of payments, of course, it's a political program that's broken, that doesn't live up to any of its stated requirements. 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 the recommendation, and then they took comments on it. The final rule has yet to come out, and that's where we think there's a reasonable chance that they may reconsider what they propose. The timing of which will completely depend, you know, the ultimate RVO deadlines will depend on when that final rule comes out. 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. I think if they stuck to something this spring, the 2020 is maybe December 1. You know, 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. 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. 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. 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 potentially be coming at some point. Canada will be coming. We believe there will be other markets. Europe is an available market as well. 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 for 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. 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. My question is: Are Torrance and Martinez still able to place 100% of their diesel production in the state? Or have you had to, I guess, look for new markets, you know, 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 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 de-leveraging and the progress on the renewable diesel project. Everybody have a great day. Thank you very much. This concludes today's conference. You may now disconnect your lines at this time. Thank you for your participation.