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

Thank you, Melissa. Good morning, and welcome to today's call. With me today are Tom Nimbley, our CEO; Matt Lucey, our President; Erik Young, our CFO; Tom O'Connor, our Senior Vice President of Commercial; 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. In summary, it outlines that statements contained in the press release, and on this call, which 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 described in our filings with the SEC. Consistent with our prior periods, we will discuss our results today, excluding special items. In today's press release, we provide a detailed list of the noncash special items included in our first quarter 2021 results. The cumulative impact of the special items increased net income by an aftertax benefit of $273.9 million or $2.27 per share. As noted in our press release, we'll be using certain non-GAAP measures while describing PBF's operating performance and financial results. For reconciliations of non-GAAP measures to the appropriate GAAP figure, please refer to the supplemental tables contained in today's press release. I'll now turn the call over to Tom.

Thanks, Colin. Good morning, everyone and thank you for joining our call today. While we're not out of the woods yet, our business saw a strong recovery during the first quarter. The vaccine rollouts have picked up and people are starting to come out from their respective COVID and winter hibernations. Market conditions are improving; lower utilization rates in 2020 kept refining product inventories within very reasonable ranges coming into 2021. Aside from the catastrophic personal impacts of Winter Storm Uri, the storm continued to clean-up and balancing of inventory levels. Crash responded as a result of the storm, but operational discipline meant that the impacts we're seeing in lower inventories rather than higher utilization. Product inventory levels are now or at or near their five-year average levels. Industry data shows that gasoline demand, domestic gasoline demand has recovered to approximately 95% of normal levels. Distillate demand has fully recovered and is even 5% or so above historic levels. While jet demand remains at about 75% of normal levels, but continues its slower recovery. Demand is the key driver. Increased demand will provide support for improved refining margins, which in turn will support incrementally higher utilization. Higher refining run should increase the coal on crews from produces, and this should have a positive impact on differentials. We're seeing a green shoots of this effect with discounts widening modestly for shallow crude oils as incremental barrels are coming from the Middle East. We expect this trend to continue as demand improves. To be clear, the industry is coming off a very low base, and many of the incremental data points are positive. We believe that a strong domestic recovery from the pandemic will continue to drive increased demand for our products. Internationally, the recovery has not been as consistent or smooth as we're experienced in the U.S. But those regions will recover as well. This should provide a backdrop where we see a more gradual but sustained growth in product demand. We're encouraged by what we have seen in the market. We expect utilization going forward will be pulled by demand rather than run ahead of it. We're expecting to run almost 25% more barrels to our system in the second quarter than we did in the fourth quarter of 2020. And this is a very big step in our recovery. Lastly, I'd like to thank all of our employees for following our pandemic protocols while continuing their tireless efforts in maintaining the safety and integrity of our operations. We look forward to the day when we will have all of our team members back to the office, which we will believe will occur by the end of the second quarter. With that, I'll turn the call over to Matt.

As Tom mentioned, markets are being driven in the right direction as demand is increasing. Our aggressive efforts to improve PBF's competitive position should help accelerate the company's recovery. We targeted cost reductions and operational excellence. We're cementing the savings achieved over the last 12 months and realizing the benefits of continued cost discipline. We believe our ongoing efforts will result in a permanent shift of our refining cost structure that will make us more competitive. We're expecting more than a $0.50 per barrel reduction in operating costs across our system versus historical levels. We're more than $250 million per year at full run rates. In the first quarter, we ran our refining system at just over 745,000 barrels per day in total, 10% higher than we ran in the fourth quarter. The midpoint of our second quarter throughput guidance is approximately 855,000 barrels per day or approximately 15% higher than Q1. We believe the demand recovery for our products is taking shape and our rate increases reflect a response to that demand. We're not going to run ahead of demand but we'll continue to be disciplined and responsive to the market. The challenges faced by our industry during the pandemic were met with discipline by operators, but also resulted in the difficult but necessary decision to rationalize capacity globally. As recently, as last week, we continue to see global capacity rationalization with the announced conversion of the South African Engine Refinery into a product terminal. This trend will likely continue outside the U.S. which was early to rationalize capacity. In addition to the pandemic, runaway compliance costs under the RFS program are creating another unsustainable burden on merchant refiners. The RFS program is a broken program, and if the problem is not addressed, it will likely result in a…

Thanks, Matt. As mentioned a moment ago, there were a number of significant one-time special items included in our GAAP results that are outlined on Page 6 of our press release. Today PBF reported an adjusted loss of $2.61 per share for the first quarter and an adjusted EBITDA loss of $190.9 million. Consolidated CapEx for the quarter was approximately $60 million, which includes $59 million for refining and corporate CapEx and $1 million for PBF logistics. As we have discussed on previous calls, our 2021 capital program was designed with intended flexibility. For the first half of 2021, we continue to expect roughly $150 million in refining CapEx. As a result of improving market conditions, we elected to advance some of the maintenance on the East Coast into the second quarter. And this is finishing up now. Please note that our Q2 throughput guidance is inclusive of this activity. Looking to the second half of the year, we expect capital expenditures to be roughly $250 million to $300 million, and we expect to perform turnarounds and related projects at Delaware City, Chalmette, and both West Coast plants. Our financial results, while not cash flow positive for the first quarter, continue to improve as the rebound from the pandemic progresses. We believe March was an inflection point as we generated positive adjusted operating margins and we still believe that the combination of an improving market backdrop and a more streamlined cost structure at PBF should result in a return to positive cash flow. Our liquidity position remains strong, with over $2.3 billion of total liquidity, including $1.5 billion of cash at the end of the first quarter. We continue to manage our balance sheet and financial resources to provide us with flexibility in the near-term. There are many factors that can change the trajectory of working capital flows, namely commodity prices, inventory levels, feedstock differentials, and the cost of renewable energy credits will be a factor over the remainder of 2021. We do however; expect to see approximately $550 million of working capital outflows through the remainder of the year. Operator, we've completed our opening remarks, and we'd be pleased to take any questions.

[Operator Instructions]. Our first question comes from the line of Theresa Chen with Barclays. Please proceed with your question.

Good morning, everyone. Tom and Matt, in your prepared remarks, you specifically spoke about the unsustainable headwind of elevated wind cost for the industry. And I wanted to delve into this a little bit more, just with the Supreme Court currently reviewing SRE case. Can you walk through the different scenarios of what you think can happen from here? And the loaded question of what are your expectations at this point for the blend mandate, and maybe the program going forward?

Yes, thanks for the question. There's so many unanswered questions as Supreme Court case was interesting from everyone that I've talked to and from what I listened to, people were encouraged by but obviously the government hasn't put out the RVO. They're overdue for this year. And so there's a lot of questions. But the biggest one is what it always is, is you have to have a direct voice into the administration, into the EPA, and into Congress, to explain to them the intended and unintended consequences of their actions. It is a broken program. Secretary Reagan is coming in, should be a relatively blank slate in terms of he's not a person that seems to have a vested interest in his history in this regard. We're working very closely with the representative workforce that is our colleagues and talking directly to the administration. The fact of the matter is, the RFS program is broken we keep using that term. If you look at it -- if you look at bio diesel, and bio diesel wins, that market sort of works. It's more of a pass-through. But when you get to gasoline, ethanol, D6 RINs, it's a completely inequitable program. And if it's not addressed, prices will continue to rise with soybeans. And it will make refining unprofitable, and that will have ramifications.

Let me just add a few things. To that, I mean, as question Matt spoke of it, obviously, the Supreme Court case was heard. Before that there was a hearing at the Circuit level on the E15, decision made by the EPA to allow year-round E15. Certainly, there was a motion to basically go back and dismiss that. So there's two places and the -- and course that could still unknown, that will weigh in on this. With the lobbying efforts that Matt spoke of, we've got governance petitions that have gone into the EPA that had not been responded to for request for economic farm waivers for merchant refiners in particular, the EPA will ultimately have to respond to that. And then the last piece of your question is if this thing just keeps going and going and going. Of course, this program sunsets. It sunsets at the end December 31 of 2022, at that point it would remand to the EPA. The EPA has already reached out and requested comments from all parties, including the agricultural lobby, and the refining industry, as to what things that could be done to make the program better if indeed, we go down that route. And one of the things that is being discussed is to go to more of a LCFS program, which, as you all know, I'm sure that is all passed through to the consumer 100%. There's no prioritization given to large retailers, large refiners, integrated refiners versus merchants. So a lot of activity, but we need action sooner than later on this.

Thank you for that thorough answer. I guess, turning to your assets in the West Coast, and it looks like you're looking for material step-up in throughput quarter-over-quarter, along with your other regions, maintenance aside. But specifically to this region, can you talk about what you're seeing there and what you're seeing in terms of demand across your footprint and is this step-up just primarily a function of things opening up, mobility increasing or are there other factors at play?

Well, it's primarily associated with mobility and the state opening up the -- obviously, the State of California has announced that effective June 15, the state is opened completely. But Paul Davis, our President of the West Coast region was out there last week, and the traffic on the highways, is pretty much back to what it was pre-pandemic. So demand is clearly up. We talked about the demand comparisons pre-pandemic to now across the region. But it's the same story. And in fact, a little bit more bullish on gasoline right now. And on PADD 5, where we're about 97% of pre-pandemic demand. So clearly, we've seen a utilization come up. But I would point out, and I think everybody is aware of this, we've mentioned in previous calls, what we watch closely, we're very confident, we already seen diesel eclipse our pre-pandemic levels. And that's being driven by the fact that we saw port of Long Beach, port of LA, cargo ships, container ships, in April, March and April that were unloaded. We're at a 40-year all-time high. So there's a ton of container ship traffic out there. Obviously, that means that there's diesel demand as you unload those containers, and they transport the material that was in and across the entire country, gasoline demand is coming back very strong. Jet is moving grudgingly. But jet is the one thing that we have to really pay attention to not only in PADD 5, but across the whole system. But it really is a little bit, for PBF it is a more of an issue on PADD 5 because of the amount of international travel that comes out of Seattle, San Francisco, and LA. And of course, it's the international travel that is recovering more slowly; we're actually seeing domestic travel start to come up pretty nicely. But overall, we're seeing good demand and utilization in California right now, at both refineries is about 85%.

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

Yes, hi, good morning. Maybe just starting with the cash flows in the quarter. I think in the fourth quarter call, your cash balances are around $1.25 billion. Now they're almost $300 million higher than that. So Erik, if you could give a little color about some of the moving pieces there. I appreciate the commentary about the working capital for the rest of the year. Maybe some of that was just a push out of that impact to the rest of year, but any additional color would be helpful.

Yes, I think we have discrete uses of cash that we expect to roll through Q2 through Q4 of roughly $550 million. We've tried to it's consistent with where we were, essentially in the February timeframe, when we walked everyone through the Q4 results. We did see a stronger benefit from working capital than we expected and quite frankly, a portion of that's probably going to be quasi permanent. What we don't know, we built some inventory, there are puts and takes across our working capital, ups and downs. We don't know where crude prices are going to go. We did build some inventory during the first quarter for example. Some of that was been offset by essentially deferral of payment on a variety of different topics and quite frankly, I think our team continues to do a very good job of managing cash, managing suppliers extending payment terms. And so combination of all those things on a normalized basis resulted in about $150 million of cash coming through the system. One thing that I think is important to note is our financial results do include roughly $130 million of a noncash mark-to-market on our environmental law obligations that shows up in the form of working capital as well. But this is essentially accounting treatment based on our overall net position of where we are for our environmental obligations. I think Tom and Matt give a pretty thorough overview on RINs. One of the key pieces here is, since our last call, one very important change is that the EPA has now allowed the 2020 obligation to essentially be fulfilled by the end of January 2022. And our 2021 obligation does not change our fulfillment date is still the end of March 2022. There is, however, the opportunity to extend that 2022 obligation for fulfillment period until March of 2023. And quite frankly, where we stand today, with the volatility and the current state of the RIN program, we're going to maintain as much financial flexibility as possible when it comes to managing our RIN and environmental credit position. So I think the key message is, while we were able to generate some incremental cash from working capital during the quarter, we do know that there are roughly $550 million of cash discrete uses that will again roll through our cash flow statement, hit the balance sheet, obviously reduce our cash balance through the remainder of the year. But we do believe that we have reached an inflection point here. So as we transition not only to generating positive operating margins, but most importantly, generating enough margin to cover all of our CapEx and interest that ultimately a portion of that $550 million will be offset by net cash from operations through the second half of the year.

Okay, guys, that's very helpful. I guess, just to clarify on your environmental liabilities commentary, and the push out to January of next year, does the $550 million of outflows include any prepayment, I guess of what would essentially be a 2022 obligation at this point. And order of magnitude, how much is that obligation today?

I don't think we're comfortable disclosing all of the nitty-gritty detail behind what we're doing from a credit standpoint, because quite frankly, while the cost of credits have increased, I think just looking at where the market has gone over the past three to five months, we've seen a significant run. So if commitments are made for example, to purchase credits three months ago, suddenly, those credits you may not have actually paid cash for the credits yet, they're left to settle, they could be worth 35% more today or this is just round numbers as an example. So I think overall, included in the $550 million is ample cash for us to ultimately fulfill our obligations for our 2020 timeframe.

Okay. Okay. And then just my second question on renewable diesel, do you have a rough sense of perhaps what a CI score target might be given that you have a pretreatment unit and any work you've done around feedstock or just color there? Thank you.

Yes, what we're -- in our design and our planning, we're planning to build a pretreatment unit, which will give us ultimate flexibility to run whatever feedstocks are available to run. And obviously, there's incentive to run as well as CI feedstock as you possibly can. So we'll have ultimate, we would have ultimate flexibility in being able to process any of those tellows or fabs that are used coking oil that that present the lowest CI scores.

Thank you. Our next question comes from the line of Doug Leggate with Bank of America. Please proceed with your question.

Thanks, fellas. Good morning. Thanks for taking my question. Guys, I know you spend a lot of time on RINs earlier this morning, but I wonder if you could help us with how you see the net cost in the quarter. So obviously, the RIN obligation is a cost of RINs but obviously some of that is reflected in the cost. So how would you characterize your net cost of the RFS in the first quarter?

So, Doug we expensed roughly $280 million of RINs during the first quarter and again $130 million of that had absolutely nothing to do with our day-to-day activity during the quarter. So our net RIN expense for what our six plants manufactured and ultimately sold is roughly $150 million for Q1.

Okay. Give an expectation for how that could play out in the balance of the year or what are you assuming for the balance of the year?

I think we're still very consistent with when we think through our, again, it would be nice to know what the actual RVOs for the year. So we're making some estimates here. But we assumed our net based on last year's RVO, gross then net of all of our blended RINs, we probably have over the course of the year between $550 million and $600 million net RIN gallons that we will be obligated to ultimately fulfill in either March of 2022, or March of 2023, depending on what we elect to do. And quite frankly, we're probably not going to be in a position to make that decision until the second half of this year.

Okay. Thank you for that. My follow-up just real quick on the cost reductions. I'm just curious if you could give any color on the breakdown on sustainability, I'm really looking for how much of the cost reductions are structural versus something you might have to get back as demand, and obviously markets and pricing recover?

Yes, we try to be as clear as possible. And when we cite the $0.50 a barrel, that is when we -- when we return to normal we compare our operations to 2019, we're $0.50 barrel better across our system. Obviously, you can get into a situation where you're comparing apples and oranges when volumes are down, and energy costs are down or up. But what we've tried to do is isolate on apples-to-apples basis and only really report to you, the sustainable shift in our cost structure. So our cost savings were actually a lot more than what we're reporting because our variable costs are down and all that stuff. But on a apples-to-apples basis, 2019 to post pandemic normal run rates, we've shifted our cost curve by $0.50 a barrel.

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

Hey guys. My question relates to the OPEC and South East indicating that they would actually raise their volumes. And so I wanted to know what your thoughts are on the heavy light spread. And if I may ask, additional part of that question is do you think the OPEC dynamics change if Iran is given a deal by President Biden?

That's a great question. Let me take the first part and -- first. We certainly believe that -- we believe going along that the path to recovery here for the refining industry and PBF, in particular starts with getting the pandemic under control. And that is clearly happening in the United States with the pandemic under control, the economies of this, the state economies in the country open up. And with the opening up of the economies, we see the demand growth, as we're sitting here; Matt indicated to me that the first quarter GDP numbers came out with a 6.4% GDP growth in the first quarter. So we're seeing that increase in recovery, and in demand, demand begets utilization, utilization begets improved cracks. And importantly, the coal on OPEC+ crude. And with that, the incremental barrel that's coming to market is obviously a medium, heavy, more sour barrel, which we believe will reward complexity will result in a widening of the light heavy spreads. We've actually seen the early indications of that, where Maya/Brent has moved out to where Maya is more than $6 on the Brent, that's a buck and a half more than it was as we came into the first part of 2021. So we're seeing that. We expect to continue to see that. The coal on crude over the course of the next seven months, through the end of the year is going to be somewhere around 6 million, 7 million barrels a day by a lot of forecasts. And as I say, that is going to be; maybe some of it's going to be WCS. But almost all of the rest of it is going to be OPEC, OPEC+. And in fact, we are and have seen indication that Iran is already supplying at least those reports that they're supplying somewhere around 900,000 barrels to 1 million barrels a day of crude to the Chinese through different audit avenues. But it certainly appears as though the Biden administration is very interested in getting back to a deal with Iran on the nuclear deal. And so we would not be surprised to see Iran pumping 2 million, 2.5 million barrels a day of crude by the end of the year, but we'll have to watch it closely.

Thank you. That's a very detailed answer. My quick follow-up there is, earlier in the year, we saw the Governor of California in fact trying to ban internal combustion engines now he wants to ban fracking, looks like he just basically wants to remove California from oil and gas completely. And you indicated you're working with the Federal government Biden administration. Are you also working with the Governor of California and trying to convince him that some of these plans are not exactly making sense?

Yes, yes, absolutely. And we're not doing it alone, obviously. And it's interesting in both the United States with the issues with RINs et cetera, but and now specifically to California, Manav we discussed the government has come out and said, okay, firstly, ban the internal combustion engine, by 2035 ban fracking by 2022. Fracking is not a huge component of the production. But then he also put in a cease and desist on all crude oil production by 2045. While I won't be around in 2045, so I'll assume that that may change in the intervening period. But the fact is, the Unions are very upset with the Governor of California, he's betting everything he's got on the Green movement. But the Unions are very, very annoyed at them. They are seeing these jobs being threatened and going away. We've already got one refinery that shuttered, we have another one that may in fact, convert to renewable diesels. So even the California Energy Commission is getting concerned about what's going on and we're working very closely individually, going to Sacramento and making a case. But the Western States Petroleum Association, which is basically the lobbying arm for the Western states, is all over this pushing mightily and trying to get support from a lot of people, not just the Unions, but basically people who are going to see their jobs threatened, or see their gas prices go up. I would not be surprised to see gas prices in California go past $5 a gallon here, maybe even around Memorial Day and sooner or later and gas prices in the U.S. are going to go up. Sooner or later, the U.S. population is going to say enough is enough. And frankly, I think there'll be a lot of pushback. But there's certainly a green agenda for Governor Newsom as he gets ready to fight his recall.

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

Good morning team. I just wanted to go back to the renewable diesel project. And you talked a little bit about the pre-treatment facility and how you're managing feedstock. But if you talk -- can you talk a little bit more about the conversations you're having with potential partners? What are you looking for them to bring to the table from a strategic or financial perspective to advance the project?

We've had robust discussions across the spectrum and we came into it with a whiteboard with. Sort of one critical aspect that was a guiding principle. Money is a commodity, and that can be priced. And clearly we're looking to offset some amount of capital by bringing in a partner. But we're not bringing in a partner simply to bring in a commodity and that we've been in active discussions with a number of parties that can bring strategic value and depending on who the partner is, it can be potentially could be on the feedstock side, it could be on the optic side, it could be any number of ways where, hey, the two parties together, not only can get the project to the finish line, but actually are accretive to each other and make the partnership stronger. So that's what we've been focused on. We've been very pleased with the discussions we've had. It's our hope and expectation over the next couple of months to cement the partner that we want to move forward with and see if we can get the project to the point where we'd like to go forward. I expect that by the time of our next call, I expect more news on that.

Okay. And that's the point of FID, Matt, how long would you think it would take for construction? We're just trying to think is that something that will come online in 2022 to capture the benefit of the BTC?

Look, when I take a step back as I answer your question more broadly, and we look at the competitive landscape and sort of the attributes that we potentially bring, we benefit from having refineries across the country. And we've evaluated this for years at all of our facilities. We strongly are connected, that the Gulf Coast is the best place to construct and have the operation. That is because it's sitting at our refineries, obviously, at the mouth of Mississippi, where you have access to a tremendous amount of a wide variety of feedstocks. Not only that, you're a point of distribution, you have the ability to deliver it into the State of California, if that's the highest netback adding much more competitive rate than the Eurail from the middle of the country. But then you also have the flexibility to deliver -- to whether it's to Europe, to Northwest Canada, wherever the market is demanding and you can get the highest netback. But maybe one of the single greatest attributes of what we have in Chalmette is idle hydrocracker. And to your point and I've had a number of discussions with partners, where they're saying their alternative discussions are talking about projects coming online in the second half of the decade, we believe, we will be operational, essentially in a year from our FID. So, if we get to a point over the next couple of months that we're able to move forward, we think while the project that is operating in a year's time.

Thanks, Matt. And the follow-up is just around integration on the East Coast. Obviously, tough margins in Q1, sounds like things are getting better. But you're bringing together two facilities. So just talk about how that's going, and what's left to be done?

Nothing's left to be done, has gone very well, we've achieved our sort of cost goals and integration. This was not a brand new initiative ever since we acquired both facilities, we had a -- we had the intent to optimize the two systems. Obviously, we took that to the next level and further tied two facilities. But in regards to how it's proceeding and what more needs to be done, the optimization effort is something that is always continual. But all the cost reductions have been put in place and we're moving feedstocks and finished products back and forth between the two facilities, as we've designed. So nothing's ever a completely finished product. But we're pleased with the efforts; the employees did an amazing job. And obviously, we need the market to be there to reward us. But we feel like our system is definitively stronger today than it was six months ago.

I'd just add, Neil. At the high-level 50,000 feet. The logic here was move the fuels operation phenomenally to Delaware City to shrink the fuels operation at Paulsboro. But importantly, retain the lubricant and asphalt operation in Paulsboro moves remains very strong. And with infrastructure, infrastructure plus perhaps we expect that we're going to have to my surprise to be honest, a strong asphalt market going forward. So we're pleased with how it's going so far.

Thank you. [Operator Instructions]. Our next question comes from the line of Karl Blunden with Goldman Sachs. Please proceed with your question.

Hi, good morning, guys. Thanks for the time. Just digging a little bit more on the working capital side of things. You mentioned discrete uses of cash of about $550 million. Could you break that out a little bit more in terms of your expectations around AB 32 and inventory and remediation if anything over there?

I think it's consistent with where we were back in February. We have roughly $250 million of discrete cash that we're going to need to ultimately use in the fourth quarter related to AB 32. And the remaining $300 million relates to environmental credits. And again, there's nothing that will roll through in all three quarters coming at us here. So there's nothing, nothing that we see that's a one-time bullet payment it will hit in 2Q, 3Q and 4Q.

That's it. Thanks, Erik. And then, in terms of free cash flow, in recent quarters you provided some guidance to how that might look as you go through the quarter sequentially by month, is there anything that you could offer for us in that front? Or is visibility quite limited at this point?

Well, I think obviously, we're getting closer. We started laying out kind of this nine month view and with every passing day, we're getting closer to the end of that nine month timeframe. I think we're still, we feel firmly consistent that we're going to be in that $50 million to $75 million a month number that that includes right, EBITDA or operating contribution, whatever metric you'd like to start with less CapEx, less interest. And it also takes into account all corporate expense, as well as working capital. We still believe we're in that range. What we have seen probably since February, and it's occurred really more over the course of the past month is that where our exit rate at least from an estimate standpoint, as we exit the second quarter, we still believe that we will be exiting at an EBITDA or positive operating contribution rates that will allow us to cover our monthly CapEx and interest. So we should be free cash flow positive as we exit the second quarter, margins have been pushed a bit to the right. But ultimately, the margin profile has increased. So the second half of the year, I think it's still a little too early to really walkthrough what's going to happen here, the pandemic response and the vaccination rates has been rocky in certain regions. But ultimately, I think our belief is that we will be, again, March was very much an inflection point for us. And I think, our first step was -- was to generate positive operating contribution on that activity, that occurs every day at the plant, we've done that. Now we need to generate enough money to cover all of our costs. And then from there, it will be generate as much money as we possibly can. And that will come off the back of incremental margin, higher capture rates, and ultimately lower operating costs as a result of permanent cost structure reductions that should be rippling through our system through the remainder of the year.

I'll just add on that last point that Erik made. Up till the time that we saw the increase in demand, obviously, we were running as everybody was at very low throughputs, which effectively meant that your fixed costs were being divided by a very low number and therefore elevated. As we come up in utilization, we now cover those fixed costs; there are almost three barrels on the fixed cost side and on the secondary cost side. So we look -- that's a big deal in terms of not only are we seeing the margin improvement from the fracks, but we're going to get out from under the burden of the low utilization, which is causing us to have high unit costs.

That's helpful. Thanks. And then just finally, on the renewable fuel project, I know you've touched on it quite a few times different ways to structure it. But should we assume that you'd look to prioritize the liquidity impact of that and limit the initial cash outflow as you complete that? Or is that just kind of one of the range of elements as you think about the economics of the project?

Yes, clearly a partner will be bringing in some amount of capital. And obviously, PBF is -- already has the infrastructure and facilities in place and all the things that can dramatically reduce time to market and capital costs, operating costs. So in terms of how that ultimately looks, that's something that we're working on, as we speak.

Thank you. Our final question comes from Manav Gupta with Credit Suisse. Please proceed with your question.

Thank you for letting me back in. Tom, I think you made a very interesting comment that at some point you think, or is it possible that RFS is replaced by LCFS and I'm wondering that would put a lot of emphasis on carbon intensity. Now there are a number of CCS projects which are coming up, and I think few of them are coming up right in your backyard in California. Would PBF be open at some point to kind of a partner who is willing to take your carbon dioxide sequester it for you, that lowers the carbon intensity of the fuels you're selling in California, and in turn, he is willing to share some of the 4052 credit with view, would PBF be open to such a partnership to lower the carbon intensity of the fuel that's selling?

Manav, its Matt. We've had some discussions on initiatives such as that. Yes to answer your question, we would we be open to it? Yes, obviously, it's not an insignificant project. And it comes with tremendous costs and risks that needs to be analyzed. But we certainly would not be opposed and have had and have had some discussions in that regard. My only comment on regards to LCFS and as it compares to RFS, putting aside whether it's good policy or bad policy, the big difference between LCFS and the RFS is no one complains about the LCFS equitable treatment of all the parties involved. And I think that was Tom's point he made where he said, the consumer is paying it's transparent. And there's not being games being played, where there are winners and losers, where they're definitively winners and losers with the D6 market for ethanol.

Thank you. Ladies and gentlemen, this concludes our question-and-answer session. I'll turn the floor back to Mr. Nimbley for any final comments.

Well, thank you, everybody for joining the call today. As you can tell, we’re encouraged about the recovery in the United States and that's good for the health of every citizen of the United States, and it's good for our company. We look forward to talking to you with the next quarter.

Thank you. Ladies and gentlemen, this concludes today's conference. You may disconnect your lines at this time. Thank you for your participation.