Good day and thank you for standing by. Welcome to the Berry Corporation's First Quarter 2022 Earnings Call. At this time, all participants are in a listen-only mode. After the speaker presentation, there will be a question-and-answer session. [Operator Instructions] Please be advised that today's conference is being recorded. [Operator Instructions] I would now like to hand the conference over to your speaker today, Mr. Todd Crabtree, Investor Relations. Please go ahead sir.

Thank you, Ren and welcome to everyone. Thank you for joining us for Berry's first quarter 2022 earnings teleconference. Earlier today, Berry issued an earnings release highlighting first quarter results. Speaking this morning will be Trem Smith, Board Chair and CEO; Fernando Araujo, Chief Operating Officer and Executive Vice President; and Cary Baetz, Chief Financial Officer and Executive Vice President. Before we begin, I want to call your attention to the safe harbor language found in our earnings release. The release and today's discussion contain certain projections and other forward-looking statements within the meaning of federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements. These include risks and other factors outlined in our filings with the SEC. Our website bry.com has a link to the earnings release and our most recent investor presentation. Any information, including forward-looking statements made on this call or contained in the earnings release and that presentation reflect our analysis as of the date made. We have no plans or duty to update them, except as required by law. Please refer to the tables in our earnings release and on our website for a reconciliation between all adjusted measures mentioned in today's call and the related GAAP measures. We will file our 10-Q later today. We will also post a replay link of this call and the transcript on our website. I will now turn the call over to Trem Smith.

Welcome everyone and thank you for joining us this morning. We are pleased with our performance in the first quarter of 2022, and we are well-positioned for a good year. As our results, once again, demonstrated we're a cash-generating machine. With our new shareholder return model in place and current oil and stock prices, we are excited to report that we are on track to deliver top-tier returns just as we promised when we announced our new shareholder return model. With our new variable dividend, that started with the first quarter 2022 results plus our regular fixed dividend, we are delivering record returns totaling $0.19 per share or three times prior quarter returns, positioning us as one of the highest returners of capital amongst our peers. For 2022, we anticipate we will deliver a cash return equaling 120% to 150% of the approximately $100 million of dividends we have returned to our shareholders since our IPO in July of 2018. This translates to approximately $1.60 to $1.90 per share and a return in the mid to high teens. Our new return model is predictable, transparent and simple just like our business model. It allocates 60% of our discretionary free cash flow, primarily in the form of cash variable dividends. The remaining 40% is for discretionary capital to be used opportunistically, including in the form of share repurchases. Last week, the Board increased the share repurchase authorization to $150 million in aggregate. Furthermore, we are executing the operations side of our business with excellence. We are hitting our production target, which, as a reminder, is to maintain production flat year-on-year. I'll explain how we do this. The foundation of our business model is our base production, which is the production that comes from our existing producing wells and on average, accounts for 90% of our total production year in and year out before we ever have to drill a new well. It is predictable and does not require new permits. This is why our business can be modeled like a manufacturing or industrial business. We plan to fill the 10% gap to keep our production flat from year-to-year by drilling new wells for 6% of that production gap and completing workovers in the existing wells for the remaining 4%. In other words, 90% of our cash flows comes from production out of existing producing wells. Fernando will share more details about our production activities, including the better than expected performance that we are seeing out of our Utah assets. We have steadily reduced our carbon footprint and we are continuing to do so. As a reminder, through the end of 2021 and in early 2022, we reduced our carbon footprint by 13%, which is more than 205,000 metric tons, and reduced our operating costs by $14 million, mainly due to our focus on operational efficiencies and A&D activity, as well as ESG initiatives. We are continuing to [technical difficulty] on energy operating costs. Gas costs continue to rise due to various market factors. To address this situation, we recently improved our 2022 gas purchase hedging positions. And as we have mentioned previously, our access to the Kern River gas line from the Rockies to California increased on May 1 this past Sunday to provide up to 80% of our daily gas needs, further enhancing our ability to obtain gas from markets that have historically been cheaper and more reliable than California. Additionally, our oil production accounts for 91% of our current total production. Our oil production is well hedged, giving us visibility of our levered free cash flow over the next two-plus years. C&J Well Services, our recent acquisition that provides standard well services to the industry in California and accelerates the reduction of fugitive emissions by plugging idle and orphan wells, has been fully integrated into the company. It is on track to plug approximately 2,000 third-party idle wells in California in 2022. Plugging wells reduces actual and potential methane emissions as well as other potential health and environmental hazards. According to the United Nation's Environment Program and the Climate and Clean Air Coalition, methane is a powerful greenhouse gas. And over a 20-year period, it is 80 times more potent at warming than carbon dioxide. It also reports that methane has accounted for about 30% of global warming since pre-industrial times and is proliferating faster than at any other time since recordkeeping began in the 1980s. With C&J Well Services, we have the capability to address this urgent environmental issue today with technology that exists today. I will come back to highlight other ESG activities and initiatives as well as give an update on legislative activities in my concluding remarks. Now, I will turn it over to Fernando, who will highlight the operational results of the quarter.

Thank you, Trem. I want to begin my comments by reaffirming our commitment to the safety of our employees and contractors, protection of the environment and regulatory compliance. In Q1, we continued to achieve solid safety results, including that happened on lost time incidents since 2019. This is best-in-class performance. In terms of operational performance in Q1, you can refer to the earnings release and 10-Q for details. I do want to highlight a few key achievements from Q1. As Trem mentioned, on average, our base production accounts for approximately 90% of our total production this year. Our goal is to keep production flat by filling this gap with workover and new drilling activity. In Q1, net of divestment and acquisition activity, our quarterly production was slightly higher than our production plan. In Q1, we operated on average with 1.5 rigs, drilling a total of 26 wells, 22 wells in California and four wells in Utah. In California, we continued with our successful development campaign, drilling horizontal wells in the Midway-Sunset field and vertical wells in our Hill property. In addition to drilling new wells, we accelerated workover activities, both in California and Utah, completing 76 jobs, with a rate of return greater than 100% for the program. As mentioned in the past, workover activity is our most efficient use of capital. In Antelope Creek, our Q1 bolt-on acquisition in Utah, we doubled production in the two months that Berry has been operating in this property. There is another example of outstanding work from our Uinta Basin team. We have significant upside potential for additional workovers, operational improvements and new drilling inventory, which is what an ideal bolt-on acquisition should look like. In Q1, non-energy OpEx remained essentially flat compared to last year, effectively mitigating market pressures. We continue to focus on operational efficiencies. And unlike other oil and gas producing regions in the country, our inflationary pressures are going as we planned in California. We are a purchaser of fuel gas and the market dictates prices, higher than expected gas prices increased our energy OpEx in Q1. This is mainly driven by current geopolitical pressures. As you may remember, our energy OpEx includes fuel gas purchases, which are partially offset by electricity sales from our core generation plants in California. We recently added new gas hedges, which effectively protects two-thirds of our gas demand at $4 an MMBtu. And as Trem mentioned, as of May 1, we have additional physical line capacity in the Kern River line, which covers up to 80% of our total demand. Both of these initiatives will help us mitigate the volatility in gas markets. Also, increase in oil prices outpaced the cost of energy, resulting in an overall increase in our operating margin for Q1. To summarize Q1, net of divestments and acquisitions, our production went according to plan. We have done an excellent job in accelerating and executing our workover campaign, which has delivered great results, and our capital expenditures and production guidance are within plan. Now, I'll turn it over to Cary.

I'll keep my comments brief as Trem and Fernando have covered most of the important items. My first comment is that we expect our second quarter variable dividend to be much greater than the first quarter as the first quarter is seasonally our largest working capital consuming quarter. In Q1, working capital use was higher than we anticipated due to the rise in oil prices in the second half of the quarter, which caused a temporary increase in our quarter ending accounts receivable balance. We have added a slide to our IR deck, slide 12, where you can see the historical quarterly changes in working capital. Again, we are well-positioned to have a strong payout under our shareholder return model for 2022 and over the next few years. Turning to oil hedges. We are limited on our hedge volume by our credit agreement. For 2022, roughly 60% of our planned production is swapped at about $77 a barrel Brent. This provides certainty around our free cash flow and leaves upside for a significant portion of our production as we anticipate continued strong pricing throughout the rest of the year and beyond. Before turning it back to Trem, I want to highlight that the Board did approve an increase to $150 million of share repurchases in aggregate. We recently amended our credit agreement to allow us greater flexibility around share repurchases. Speaking of the credit agreement, we don't see in our -- we don't see a change in our elected commitment of $200 million. Although, the borrowing base supports a higher amount, there is no reason to pay for liquidity we don't need. In closing, we aren't a resource play. Due to our attractive low decline curves and low capital intensity needs, our development and production business provides investors with strong predictability and visibility into our cash flows. This gives us the confidence to plan for and deliver significant cash returns and to provide additional value to shareholders, including through share repurchases. Back to you, Trem.

Thanks Cary. We had a good quarter and are well positioned for the rest of the year. Now, I want to touch briefly on a few of our environmental, social and governance initiatives, or ESG. First, one of our strategic focuses for our well plugging business is to work with the state to plug orphaned wells in highly populated often distressed neighborhoods, such as in parts of Los Angeles County. Many of these wells were drilled years ago, some even decades. C&J Services is highly skilled at dealing with these old and often complex wells. This is a critical component in achieving the state's goal to safely reduce emissions near at-risk populations. In addition, as carbon capture and sequestration projects [technical difficulty], it will be imperative to ensure that historic wells in the carbon dioxide sequestration [technical difficulty] are appropriately shut in and plugged to ensure the reservoir is completely sealed. The technical confidence [technical difficulty] plugs these very sensitive wells will be in high demand. C&J Well Services, working with CalGEM, other state government agencies and other operators, is uniquely positioned to do this work. In conjunction with our environmental efforts, we continue to monitor the developments at the state level or CCS opportunities. On the legislative front, California seems poised to take action this year to embrace CCS as a necessary tactic to transition to a lower carbon economy. There are a handful of measures that have been introduced and currently making their way through the legislative process that deal with CCS, including three bills to lay the foundation and framework to make CCS [technical difficulty] California. One bill addresses the poor space ownership issue necessary to achieve widespread deployment of CCS. A second bill streamlines the permitting process for these projects, and the third bill directs agencies to adopt regulations and safety guidelines for CO2 pipelines. We continue to be very committed to being part of the energy [technical difficulty]. We are working with the state to make sure we can continue to provide California's with safely produced, affordable, equitable and reliable energy. Now, I'll open it up for questions.

[Operator Instructions] Our first question comes from the line of Leo Mariani with KeyBanc.

Hey, guys. I wanted to see if you can provide a little bit more detail on the regulatory side. Really just curious if you all have been getting kind of regular way, oil drilling permits from the state over the last couple of months. And I guess, if so, do you have what you need for the 2022 program at this point or you still a little short?

Leo, this is Trem. I'll handle this one. The question is that the -- that we are getting permits that are handled under CEQA already. The issue is CalGEM is now the lead CEQA agency. CEQA stands for California Environmental Quality Act, which is a requirement in all activities, not just oil and gas in California. While Kern County goes through its legal issues, we expect by the end of maybe the second or third quarter of this year, Kern County will become the lead agency. So, the answer is, yes, we are getting permits. We will be -- currently have permits to take us through the end of June. And we expect to get another group of permits here shortly that will take us well into the year. But we don't have permits in hand yet, as we normally don't. Okay. Leo, I just want to make that clear. At this time, we don't have all the permits in hand for the entire year's activity, but we're moving forward and working with the agencies as necessary to get those permits.

Okay. But has there been, I guess, movement in the last couple of months where they have been issuing them?

Yes. That's what I was just trying to say, Leo. Yes, we have been getting permits. Yes.

Okay. And then, I guess, any kind of specific update on any of the CO2 sequestration pilots you've talked about? Obviously, you went through the legislation. It certainly sounds like a positive that's moving through the legislature there. But anything kind of specific to barrier that you're working on?

As we mentioned in the previous call, the fourth quarter call, we have an LOI with a company that is investigating, taking our CO2. Our largest generators of emissions are our cogens, and taking the CO2 and emissions from those cogens into a project they have going on in another basin. That is moving forward. And then we regularly touch base with CRC. Elk Hills is a very good place to store CO2 and we will be a participant as a source of CO2 for them as they progress. So, those are the two activities for Berry at the moment.

Okay. And then just maybe you could touch base on the oilfield service business here. [Indiscernible] right, it looks like you all did just over $3 million of EBITDA there in the first quarter. I think you all had talked about annual guidance of $27 million on EBITDA this year. So, it sounds like maybe it's off to a bit of a slow start. Can you maybe just give us a little bit of color in terms of how you're feeling about hitting that guide and explain a little bit on the recent shortfall?

So, this is Cary, and good talking to you. The guide -- we still feel very comfortable in the guide. First quarter is kind of the slowest quarter for C&J. Revenue-wise, Berry was very strong. There was a couple of inflationary pressures that they got it with. One was adjusting all field level wages up by $2. So that was a little higher than it was expected. And then, also fuel got them a little bit as well. So, a bit comfortable with the revenue. Revenue is actually moving better than we thought. Finding the personnel still is a challenge out there. A staff the other day that we heard is Del Taco now in California pays $21 an hour for new employees. So think about that, and the Taco have to move. So you do have to make sure that you're offering a very good competitive wage in order to get out there and work in. But Jack is doing a great job with that, and we still feel comfortable with the guide.

Okay. Thanks guys.

Thanks Leo.

Thanks Leo.

Thank you. Our next question is from the line of Charles Meade with Johnson Rice. Your line is now open.

Good morning, Charles.

Good morning Trem, Cary, Fernando. Trem, I want to go back to the C&J Well plugging. So, I get that -- I think a great point that you're going to have to plug more wells to make these fields really a good place for CCS. I guess, my question is, has the character or the size of this opportunity changed versus last year when you bought this business? It seems like it's gotten better. And if that is the case, is this something we should be thinking about for -- is there at least 2023? Or is this more kind of a back end of the decade kind of thing where it's gotten bigger and better?

Well, there's two components to your question, so let me explain. First off, the state has the liability for thousands -- tens of thousands of orphaned wells. Many of those wells -- there are several markets here. Many of those wells occur in highly populated areas, and C&J is uniquely positioned to take care of those wells. The other [technical difficulty] going to develop over time is the plugging around wells that are in the CO2 sequestration realm. And that should happen in several projects and probably will be a growing business, okay? Right now, it's not a big piece, as you observe, but that will be growing over time. And there'll be several aspects of it, Charles. And this is just me talking, which is one is preparation of those reservoirs for sequestration, okay? Wells -- old wells will need to be plugged. And then as the reservoirs become utilized for sequestration, additional wells will need to be plugged. The other component that has changed, which is also positive, is the state is becoming more proactive in offering tenders for big packages of wells to be plugged. We didn't talk much about that today, and I'm hoping we'll talk more about it in future quarters as we win some of these tenders, which are currently in progress. The state is [technical difficulty] at tendering and understanding the complexities with plugging a number of orphan wells in certain area. That is a change that's evolved over the last three to six months in my experience. So, plugging business, when we bought C&J, the plugging business was about 20% of their entire business. That may continue to grow, and we continue to position. So, we're delighted with the way it looks for the plugging business in that acquisition. Does that help?

Yeah. No, that helps a lot of it. That's great insight into -- not just your thinking, but how the markets evolved. And that's exactly what I was looking for, Trem. And then, Cary, if I could have a follow-up for you. And I apologize ahead of time but this is a little down in the weeds, but I think it's an important thing to pull up. And it's about really your variable dividend. So, one of the ways that Berry is different that you guys are calculating different from other companies to put these variable dividend frameworks in place. You guys are doing it post working capital adjustments, which makes sense. That's really where you were -- that's closer to real free cash flow, but it's not something that other people in the space are doing. So, to drill in on the point that you made earlier about your working capital expansion or drain in 1Q, I get the part about your receivables going up as the oil price goes up. But what other things happen in 1Q that makes that kind of a working capital draw?

Yeah. So, that's a good question, Charles. And we were doing fine until March. But for good reason, prices went up and our AR went up about $25 million in March, which is one of the biggest drivers. But there's two other things that happen once twice a year. So, in the first quarter and in the third quarter, we pay our annual interest expense, our semiannual interest expense on the bonds. So that's a little bit of a working capital use. But the other big item that's in Q1 that doesn't stand in any other quarter is our -- what we call our Formax lease, which is our annual royalty payment to Exxon for Formax, which on average gets into -- and it gets into about a $15 million number give or take a little bit on an annual basis. And then the last item that we do also in Q1 will be -- it's not as big a number, but you also pay your annual bonuses in Q1. So, those are kind of the three biggest outliers versus the other three quarters. You've got interest, royalty payment and bonuses.

Got it. And as those kind of roll-off or don't repeat in 2Q, that working capital adjustment not only will go to zero, but can flip the other way?

Yeah. That's right. [Technical difficulty] continued at the end of the quarter on oil prices. And again, it's a seven-day lag from the end of the quarter to when we get paid. So, we feel a little frustrated at times. There's give and take with that as well. But those are the three big items in the first quarter, and that's the reason when you look at the other three quarters in the [technical difficulty], you'll see they're relatively flat. If you look at price, prices impact a little bit on the AR, but other that, they're fairly flat.

Got it. Thank you. Thank you for the slide you prepared on that and for indulging that question, Cary.

Yeah. No problem. Thanks Charles.

Thank you. Our next question is from the line of Steve Busch with Everglades Resources. Your line is now open.

Good morning, Steve.

Thank you for taking my call. I'm just kind of new to the stock, so I'm just trying to wrap my head around the oil and gas derivatives number and why it's in revenues and it's a pretty big number? If you could just kind of fill me in a little bit.

Yeah. I think from an overall point of view, the reason it's in there is so we actually get the realized price for our commodities. So, it is adjusted to -- so everybody sees the actual price that we receive on the products that are sold.

Okay. So, like this was $161 million derivative loss for the quarter. Is that just purchasing forward contracts? Or is that actual mark-to-market? Is it a cash?

That is a mark-to-market for the hedge book for that quarter -- during that quarter.

Okay. So, it's not cash. That's what I thought.

Yeah. If prices stay flat from here on, you won't see that mark-to-market. It's when you have big wide changes that you see that, Steve. And as you know, in the first quarter, we saw a substantial run-up in oil prices, and that's where you get that big number jumps out.

I understand. Okay. And so -- and just kind of an odd question. Are we having any trouble with water or droughts or needs for any kind of that water uses in California?

Steve, this is Trem. We do not have a problem sourcing water. Most of the water we use in our operations, we actually produce and recycle, okay? [Technical difficulty] water is disposing of water that we don't end up using that we have produced, okay? And we have various disposal methods, including the best one is disposal wells, okay?

Okay. I think you guys are doing a great job.

Steve, hold on -- are you still there, Steve?

Yeah. Go ahead.

Okay. You opened up the water thing. So, let me -- we do -- we are working very -- we have one field in particular on the east side of the San Joaquin that has very pure water that we produce. And we are very close in -- we're in negotiations on selling that water to one of the water districts that provides water to the farming industry in California. So, I'm hoping we'll talk about that. But that -- your point is [technical difficulty] with the drought conditions in that way.

Okay. Appreciate it. Thank you.

Thanks Steve. Welcome to the stock.

Thank you.

Thank you. Our next question is from the line of Nicholas Pope with Seaport Research. Please go ahead.

Morning everybody.

Hi, Nick.

Just hoping you could talk a little bit about the operating costs kind of where it's running? I mean, obviously, energy has run-up on the energy component of the operating expense. But just looking at the -- or the non-energy operating expense and kind of where that's running relative to kind of the full year guide? I see a very active quarter for workovers. And I was kind of curious how that kind of was situated relative to kind of where the plan was and where operating costs kind of are trending over the course of the year relative to that kind of very active first quarter for workovers?

Yeah. Hi, Nick. This is Fernando. In terms of non-energy OpEx, as you know, that's basically our standard LOE. Just historically, we've been able to reduce our non-energy OpEx by about $2 a BOE since 2019. And this has proven to be very sustainable in 2021 and into 2022 as seen by the results that we have. Obviously, we've been able to realize significant improvements in operational efficiencies in all aspects of the operation, and these efficiencies are continuing into 2022. Now, we budgeted a slight increase in non-energy OpEx due to inflation. But for now, we are working within that number. So, our actual Q1 dollar per BOE number is actually below what we plan for. And we don't expect energy OpEx to be an issue beyond what we plan for. So, we're staying within that above 5% increase compared to last year.

Yeah. Nick, this is Cary. I'll jump in. I think overall, nonenergy OpEx, we're still comfortable with the range. I think we are -- the energy OpEx side of things is where we're focusing on. Again, getting about two-thirds of our daily demand or use at $4, I think, helps us get that back down. Getting access to the current line as of last Sunday, the full access of that is going to give us some ability to move some lesser expensive Rockies gas maybe to our areas as well. But I think non-energy OpEx good, energy OpEx on the higher side. But right now, we're still comfortable overall with our guidance.

Got it. And the non-energy OpEx, I think it was $6.25 to $7.50 or something like that. Is that right on a unit basis?

No, I think it's -- yes, energy, energy, yeah. But we'll be on [technical difficulty] I think we need to get through the second quarter before we refresh on the energy side of things. But I think non-energy OpEx, we're still comfortable within guidance.

That makes sense. Thank you. And I was hoping you could expand a little bit on kind of the CO2 capture pilot that you're talking about on the cogen facilities. It sounds like that's like a small-scale project. Is this something that like realistically you could see CO2 capture from your electric generation facilities? I mean, is that realistic at this point in their life to see CO2 capture? Or is this more of kind of a test case to see if it could be viable? I mean, are these facilities actually capable of capturing CO2?

Actually, the capturing of CO2 is not the issue. The issue is getting the permits by the group we have the LOI with, we'll be taking that -- the technology exists to capture the CO2. So, we are able to do that. There are various methods that cost different things, and so we'd all run the economics as well. But that's been around for a long time, and we can do that. The issue with those projects is that is taking them from -- when they've been captured to the location they're going to be injected into the subsurface. One of the pieces of legislation that I mentioned in the CO2 pipelines, that is a much -- that's an area that's never been addressed lately or regulatory-wise in California. So that's where the risk associated with. If you think about it, for us, the CO2 emitters are going to be our steam generators and our cogens. In California, the biggest CO2 generators are going to be industry, of which there's some, but not as much -- cement factories, utilities, things like that. And that's where the capture of larger volumes is going to occur, and that will contribute as a source of CO2. But for Berry, we -- as our invests -- our ESG deck supports, we produce about 1.4 million metric tons a year, okay? So, we actually don't produce that much. But as a company, we are measured by how much we reduce and that's why reducing so far, in the first quarter, we completed the reduction of 205,000 metric tons, which is a big deal for us. So, no, it's more than just a pilot testing things. This is [technical difficulty] beneficial to Berry. And it's doable.

And is the idea that the CO2 that you're intending to capture, I mean is it purely for sequestration? Or is there -- I would assume it would have to be a more peer source of CO2 for use in CO2 flood? Is it pure sequestration that we're talking about?

Well, yes, it is pure sequestration, right? And Berry has no plans to do a CO2 plug to generate additional hydrocarbon production.

Got it.

If that's what you mean by CO2?

Yeah. That's yes. Exactly. Thank you.

No. No. This is pure sequestration.

I appreciate the time guys.

Thank you. Our next question is from the line of Joseph McKay with Wells Fargo. Your line is now open.

Thank you.

Good morning, Joseph.

Thanks for taking my question. I was just wondering if you guys could maybe dive into kind of that 40% side of the discretionary capital. And just kind of how you're thinking about these levels with you have the increase to the share repurchase plan and kind of $100 oil. How are you balancing kind of the repurchases versus organic inventory growth and some of the other options embedded in there?

I would say it's a calculus model. But I think in California will be limited by permitting and the ability to get the permitting to be able to grow. So, I think, we're comfortable with our current guidance based upon permitting and where we're at from permitting. As Fernando pointed out, we've had some very good success in the Antelope Creek bolt-on. So, to increase there, but it won't be substantial enough to really take over that 40%. We are [technical difficulty] some additional bolt-ons that would take part of that as well. But I think also we're keenly focused on total shareholder [technical difficulty] the right opportunity comes around to be able to repurchase some shares. I think we will take advantage of that as well. So, I would say it's fluid. It's not tightly defined. But again, the right bolt-ons will come out of that. And then, I think the rest of it will be focused much more on the share repurchase side as well.

Okay. Thank you. That helps. And then, maybe just a quick follow-up on Charles' question about the variable dividend. Obviously, the working capital was kind of a headwind to this quarter. I guess moving forward, if there was working capital change that went in the other direction. Would the variable dividend be kind of based on the inflow coming in? Or would you kind of maybe pocket that change for future quarters when it reverses and use it to kind of even things out a little more?

No, I think it's -- from our point of view, to keep the math simple, keep -- let the math just work like math. Some quarters will be a little higher [technical difficulty] less, but overall, I think we're still comfortable. As Trem pointed out that $1.60 to $1.90 range for that dividend return. And so, I think with that being said, it blends out over time.

Gotcha. All right. That’s all for me.

Yeah. The long-term investor will continue to reap the benefits of the cyclicality of the working capital. But again, we don't see as much cyclicality in Q2, Q3 and Q4. It's really the first quarter, and you kind of -- the next three quarters should be fairly steady if historical working capital stays in place -- trying to stay in place.

Gotcha. Make sense. Thank you very much.

You bet. Thanks. A - Trem Smith: Thank you. I really want to thank everybody today for the time, and we're looking [technical difficulty] good second quarter. Thank you.

Thank you. This concludes today's conference call. Thank you for participating. You may now disconnect.