VAALCO Energy, Inc.

Good morning and welcome to the Valco Energy, Inc. Third Quarter 2020 Earnings Conference Call. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. Please note this event is being recorded. I would now like to turn the conference over to Al Petrie, Investor Relations Coordinator. Please go ahead.

Thank you, Alyssa. Good morning, everyone, and welcome to Valco Energy's third quarter 2020 conference call. After I cover the forward-looking statements, Kerry Bounds, our Chief Executive Officer, will review key highlights along with operational results. Liz Prochnow, our Chief Financial Officer, will then provide a more in-depth financial Kerry will then return for some closing comments before we take your questions. During our Q&A session, we asked you to limit your questions to one and a follow-up. You can always reenter the queue with additional questions. I'd like to point out that we posted an updated investor deck on our website this morning that has additional financial analysis, comparisons, and guidance that should be helpful. With that, let me proceed with our forward-looking statement comments. During the course of this conference call, the company will be making forward-looking statements. Investors are cautioned that forward-looking statements are not guarantees of future performance and that those actual results or developments may differ materially from those projected in the forward-looking statements. Valco disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise. Accordingly, you should not place undue reliance on forward-looking statements. These and other risks are described in yesterday's press release, the presentation posted on our website this morning, and in the reports we filed with the SEC, including the Form 10-Q that was filed yesterday. Please note that this conference call is being recorded. Let me turn the call over to Kerry.

Thank you, Al. Good morning, everyone, and welcome to our third quarter 2020 earnings conference call. This year has been difficult for the energy industry as we have faced many extraordinary challenges. From COVID-19 to supply and demand imbalances to low commodity prices, Valco has responded well to all of these challenges. Thus far, Valco's operations have not been materially impacted by the global COVID-19 pandemic which is a testament to our dedicated workforce, given that we have operated our platforms under the precautionary measures for approximately eight months now. We have managed through the logistical challenges that we have faced since the outbreak occurred and continue to put the safety of our employees, contractors, and local stakeholders first. We are minimizing high-risk activities and using on-site medical supervision to screen test, and monitor employees and contractors while in quarantine before going offshore. We have contingency plans in place in the event we are directly impacted by the pandemic. We continue to work with our vendors and suppliers to implement cost-cutting measures and partner with other operators to reduce costs by sharing services and equipment such as support vessels and helicopters. As we've said before, approximately 90% of our costs are fixed and we can add production and improve our margins with minimal increasing costs. Our strong production and lower costs have helped us to continue to generate solid cash flow and adjusted EBITDAX. We remain focused on operational excellence, which will lead to cash flow generation, allowing us to prepare for future drilling campaigns at a time. In the third quarter, we produced an average of 4,405 net barrel point of our guidance range. Our third quarter 2020 production was up 43% from the same quarter in 2019 as a result of the three new wells that came online as part of our successful 2019-2020 drilling program. However, our third quarter 2020 production was below our second quarter average of 5,410 net barrels of ore per day due to the planned full field maintenance shutdown in September and the production curtailment in Gabon due to an OPEC Plus mandate. As we discussed in our last conference call, we were asked to assist Gabon in meeting its OPEC Plus production quota by temporarily curtailing production at its top. In September, we performed our planned five-day full-field turnaround to perform maintenance on the Natipa FPSO and all four production platforms. The turnaround was performed on time, on budget, and most importantly, with no safety or environmental incidents. Looking ahead, we expect to produce somewhere between 4,600 and 5,000 barrels of oil per day net tobacco in the fourth quarter, which is up 200 to 600 barrels of oil per day versus the third quarter. You will note that we have increased the lower end of the range for for the fourth quarter in our new guidance of 4,600 to 5,000 barrels of oil per day from the 4,300 to 5,000 barrels of oil per day net fourth quarter estimate we gave during our last call. We continue to see strong production uplift from better than expected performance from the three new development wells drilled and brought online as part of the 2019-2020 drilling campaign. In the third quarter, despite continued low realized crude oil prices, and production curtailments, we reported an adjusted EBITDAX of $7 million, which brings our year-to-date adjusted EBITDAX to $23.1 million. And we have only spent about $10 million in CapEx thus far this year, thereby confirming our ability to generate free cash flow even in this difficult environment. In addition to managing our capital spending, we have also reduced our operating and G&A expenses, Liz will give more detail on this, but driving down our costs maximizes our ability to generate free cash flow. In September, we announced that we are acquiring and processing new proprietary 3D seismic data over the entire ATOM license. We believe the seismic data will help improve capital efficiency at ATOM by allowing us to select drilling locations that maximize oil recovery and it will also allow us to identify new locations to add to our portfolio of drilling prospects. We expect to complete the seismic acquisition in the fourth quarter of this year with full processing completed by this time next year. When acquisition and processing are complete, this will be the first continuous 3D seismic survey to cover the entire ATOM license, which will allow for a more robust subsurface interpretation than ever before. We are proud of the highly successful and transformational drilling program that we completed earlier this year, and we believe that a new 3D seismic survey will build on that success as we plan for future drilling programs at ATOM. Now, I'd like to give you a quick update on our activity in Equatorial Guinea. In the first quarter of 2020, BALPA required additional working interest from Atlas Petroleum thereby increasing our working interest from 31% to 43%. The cost for acquiring the additional Block P working interest is a future payment of $3.1 million that will only be made if there is commercial production from Block P. In August, an amendment to our production sharing contract of Mines and Hydrocarbons. We're excited about the future at Block P, and we are having ongoing farm-out discussions with Levine Hydrocarbon. Under the farm-out terms, Levine will potentially cover all, or substantially all, about those costs to drill an exploratory well in Block P. We are optimistic that we will finalize the agreements with Levine and prepare for a drilling campaign that will commence in the next couple of years with minimal financial exposure to Valco. This is a challenging time in the energy industry, but we believe that we are well positioned with a strong debt-free balance sheet, $42 million in cash, and a stable production base that is free cash flow positive at current prices. Going forward, we will maintain our focus on free cash flow and operational excellence to deliver both near-term and long-term performance With that, I will turn the call over to Liz.

Thank you, Kerry, and good morning, everyone. In the third quarter of 2020, we reported strong net income of $7.6 million, or 13 cents per diluted share. This is despite the impact of low crude prices and temporarily lower production expense because of the maintenance shutdown and OPEC Plus curtailment. In the third quarter of 2019, we reported a net loss of $3.9 million, or $0.07 per diluted share. Lower realized crude oil prices in this year's third quarter were more than offset by higher sales volumes year over year as a result of the additional production associated with the three successful wells from the 2019-2020 drilling program. Third quarter 2020 net income additionally benefited from lower operating costs and expenses compared with the same period last year. Third quarter 2020 earnings included a tax benefit of $2.8 million, while the same period a year ago had income tax expense of $7.7 million. In the second quarter of 2020, net income was $0.6 million, or penny per share, deluded share, which reflected the impact of significantly lower prices that were partially offset by higher sales volumes, as well as a loss on derivatives of 0.8 million and a tax benefit of 2.2 million. Adjusted net income in the third quarter of 2020 increased to 2.3 million, or 4 cents, for deluded share from an adjusted net loss in the third quarter of 2019 of 0.6 million, or a penny per share, primarily as a result of 2.6 million decrease in G&A expense. Third quarter 2020 adjusted net income was lower than 5.3 million in the second quarter of this year, primarily because of realized gains of 6.5 million in the second quarter from our derivative contracts. Adjusted EVA DACs totaled $7 million in the third quarter of 2020, compared with $4.5 million in the same period of 2019. In the second quarter of 2020, adjusted EVA DACs was $10.1 million. Adjusted EVA DACs for this year's third quarter was higher than the same period last year, primarily due to increased sales volumes associated with the new production from the three wells completed as part of the drilling program. and lower operating costs and expenses. This was partially offset by lower realized prices. Adjusted EBITDA for the third quarter of 2020 was lower than the second quarter, primarily due to the realized gain on derivatives of 6.5 million mentioned earlier. Production for the third quarter of 4405 death barrels of oil per day increased 43% from the third quarter of 2019 due to the new wells which came online, but was down 19% in the second quarter of 2020 due to the planned full field maintenance shutdown and the OPEC Plus curtailments. Sales volumes in the third quarter of 2020 were up 48% from the same period in 2019 because of the new wells, but was down 35% from the same quarter of 2020, primarily due to the combination of lower production as well as having three listings in the third quarter versus four in the second quarter of this year. Our crude oil price realizations fell 29% to 43.63 per barrel in the third quarter of 2020 versus 61.26 per barrel in the same period in 2019. It was up 54% compared to the 28.31 per barrel in this year's second quarter. At this time, we don't have any derivative contracts in place, but we will continue to assess our needs to mitigate price risk and protect cash flow in the future. According to expenses, production expense excluding workovers for the third quarter of 2020 was $9.1 million, or $22.21 per net barrel of oil, which was within our guidance ranges. This expense was lower than $9.5 million in the same period of 2019, primarily due to proactive cost reductions. And this was in spite of $0.4 million in additional costs related to proactive employee-related measures taken in response to the pandemic. Production expense for the third quarter of 2020 was lower than the $12.2 million in the second quarter of 2020 as a result of less sales volumes. The per unit production expense, excluding workovers, decreased significantly in the third quarter of 2020 as compared to the third quarter of 2019 as a result of higher sales volumes. For the full year 2020, we are looking to reduce the top end of the guidance range for our production expense, excluding workovers, to $38 million versus the $39 million previously reported and tightening the production expense per barrel of crude oil sales to 2050 to 2150. Production expense for the fourth quarter of 2020 is projected to be between $9 and $10 million, or $19 to $23 per barrel of crude oil sales. While low crude oil prices have certainly had an impact on our financial results, From an operational standpoint, we have not been materially impacted by the worldwide COVID-19 pandemic. Our guidance excludes any potential future impacts not currently being experienced. DD&A for the third quarter 2020 was $2.2 million, or $5.37 per net barrel of oil sales, which was above our per barrel guidance range. DDNA per barrel was substantially unchanged from the same period in 2019. The per unit DDNA rate in the third quarter of 2020 was higher than the rate in the second quarter of 2020 due to the higher volumes attributable to fields with higher deployable costs, which resulted in DDNA per barrel being above our guidance range. We expect our DDNA for the fourth quarter of this year to be between $5 and $6 per net barrel of sales. General administrative expense for the third quarter of 2020, excluding non-cash stock compensation expense, was $2.4 million. G&A was lower than the $3.6 million in the third quarter of 2019 as a result of lower professional fees, legal expenses, and accounting and audit fees, but was similar to G&A expense in the second quarter of 2020. The third quarter of 2019 included one-time G&A costs associated with our dual listing on the London Stock Exchange. We are forecasting that the lower cash G&A run rate due to proactive reductions implemented in April will also occur in the fourth quarter of 2020. As a result, for the full year 2020, we have lowered our forecast of cash G&A to be between $10 and $11 million. Non-cash stock-based compensation expense with a benefit of 0.2 million during the three months ended September 30th, 2020, reflecting the reduction in the SARS liability as a result of the decrease in the company's stock price during the quarter. For the third quarter of 2019 and the second quarter of 2020, our stock price increased, which resulted in charges to increase the SARS liability during those periods. Turning now to taxes. Due to evaluation allowances on deferred tax assets recognized this year, in combination with an overall negative effective tax rate, comparisons between quarters are challenging. For the three months ended September 30th, 2020, the company had an overall income tax benefit of $2.8 million. This was comprised of $5.3 million deferred tax benefit and current tax expense of 2.5 million. Foreign income taxes are attributable to Gabon and are settled by the government taking their crude oil in-kind. As detailed on slide 27 in the presentation deck posted this morning on our website, we currently estimate that Valco's operational break-even in 2020 is now approximately $26 per net barrel of oil sales. and our free cash flow breakeven price is approximately $33 per net barrel of oil sales. Keep in mind that our realized prices are benchmarked to Brent crude oil prices. These breakeven prices have gone down this year due to higher production levels as well as lower costs in general. In general terms, we estimate that each $5 increase in the realized oil price increases our annual adjusted EBITDA by approximately $9 million. This clearly shows our strong leverage to higher oil prices. At September 30, 2020, we had an unrestricted cash balance of $42 million, which included $6 million of cash attributable to non-operating joint venture under advances. Despite the challenges of low prices, adjusted working capital of September 30, 2020 increased to $29.3 million, compared with $24.1 million as of June 30, 2020. In the third quarter of 2020, we had essentially minimal net capital expenditures on an accrual basis, reflecting the efforts to manage expenditures in the current low oil price environment. As Kerry discussed, we recently agreed to acquire new 3D seismic data in the fourth quarter of 2020. We estimate the gross cost of the acquisition and processing of the seismic survey to be between $12 million and $15 million or $4 million to $5 million net to Valco. We plan to invest $3 million to $3.5 million net to Valco in the fourth quarter of 2020. and the balance in 2021, all of which we expect to fund with cash on hand and took cash from operations. As has been the case since the second quarter of 2018, we are carrying no debt. With this, I'll now turn the call back over to Kerry.

Thanks, Liz. While the current pricing environment remains volatile, we continue to react decisively to drive down our costs and improve our margins. Over the past several years, we have worked diligently to build a solid foundation for the future. We have taken actions to strengthen Valco operationally and financially, including eliminating all debt and growing our production base, which will allow us to better navigate cyclical energy markets and leave us uniquely placed to consider growth opportunities. We remain focused on continuing to generate positive cash flow as we prepare for future drilling campaigns on the ATOM license. Valco has a strong producing asset in Gabon with significant upside. We hope to repeat the success of the 2019-2020 drilling program and continue adding reserves and production through the life of our ATOM license in Gabon. We recently initiated a new 3D seismic acquisition campaign at ATOM that will conclude in the fourth quarter of 2020 with processing fully completed by the fourth quarter of 2021. This full field 3D survey will optimize future drilling locations, provide better imaging of existing satellite and infill locations, as well as identify additional prospects to add to our drilling portfolio. We are very excited to acquire, process, and analyze the data and then incorporate it with our 20-plus years of knowledge as operator of the field. With a debt-free balance sheet, approximately $42 million in cash on hand at September 30, and a strong asset base at its home that continues to generate free cash flow, we have positioned Valco to weather near-term uncertainties. Additionally, we continue to evaluate opportunities that are consistent with our inorganic growth strategy, and we believe that we are well positioned to deliver long-term growth in line with our strategic objectives. Thank you, and with that, operator, we are ready to take questions.

We will now begin the question and answer session. To ask a question, you may press star then one on your touchtone phone. If you are using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star then two At this time, we will pause momentarily to assemble the roster. The first question today comes from Charlie Sharp of Canaccord. Please go ahead.

Thank you very much, and thank you, Carrie and Liz, for a comprehensive update. Much appreciated. If I may just ask a question around the seismic and the prospectivity that you see. You highlighted the success of the 2019-20 drilling program. And I'm not looking for specific details, but perhaps you could paint a picture of the number of well locations, future well locations that you might see based upon the current interpretation of data. And also then perhaps you could just explain a little bit about the dovetailing perhaps of interpretation with fast track processing of certain areas of the new 3D seismic. In other words, do you have to wait until all of that seismic is fully processed or is there a way of kind of accelerating that interpretation process? Thank you.

Right. Okay. Well, Charlie, good to hear from you and I'm happy to share what our strategy is with the seismic. And in our investor deck on slide 18, you'll see a list of prospects and a list of wells. And what I would focus you in on, and to answer your question on where we would accelerate processing, it would be in the areas where we have what we call our satellite prospects. And so these are prospects that were identified on the existing 3D. where the new 3D will give us better imaging of those prospects and hybrid those is what our intention is. And so I think, you know, the idea would be to accelerate processing where we see these satellite prospects that have, on average, reserves, or I'm sorry, resource potential of 5 million barrels, but of course that's the middle of the range. It could be much more than that. So that's That's one of the primary objectives of the seismic acquisition campaign is to better define our satellite prospects and then also to better define our well locations, our infill well locations, in and around southeast of Tom, for example. So that's our objective. Then we will start processing immediately, and like you mentioned, accelerate processing around our satellite process. prospects and have final processing or fully processed data towards the end of next year.

Okay, thank you.

The next question comes from Bill DeZellum of Titan Capital. Please go ahead.

Great, thank you. I'll follow on to that last question. When you've begun the survey or as you're thinking about the survey, what are you speculating that you're going to determine? Are you thinking that there is a lot more oil out in those satellite prospects or are you really doing this more to identify precise locations for infill wells? What's your gut feeling of what you're going to find and ultimate purpose?

Hi Bill, good to hear from you as well and great question. The primary objective I would say is to define the satellite prospects and understand, have a better understanding of what the oil potential is so that we can prioritize our capital spending in the future. We would drill the prospect with the most confidence and the most oil. That's the primary objective. I think secondary maybe to that is better defining where to place But also what I would also mention is when the government granted our license extension back in 2018, we actually picked up additional acreage. And so there's areas that we really haven't studied before and what I'm hoping is that we find in these new areas that we find additional prospects. And so those are the objectives, Bill.

That's very helpful. Your gut feeling from what you know is relative to these satellite prospects, what are you thinking or hoping that the issue will confirm?

What I'm thinking and hoping that we can confirm is that the probability of success is 75 percent or greater. We have several prospects that are the probability of success is 75 percent and so first of all The seismic will tell us where we have the most confidence and where we have the most potential resources.

Great. That's appreciated. I just used up my question in my follow-up. Would you like me to go back in queue or shall I continue?

Go ahead and continue, Bill. That's fine.

Great. Thank you. Cut me off any time. The GNA that you referenced in the press release being 800 pardon me, $400,000 higher as a result of COVID and the proactive things that you're doing, is that going to go away anytime soon? Or basically, should we count that as an ongoing part of your expense structure as long as COVID is an issue?

You would count it as part of our ongoing cost structure as long as COVID is an issue. Because what we're doing is we're we're mitigating the impact of an outbreak on any of our facilities, which would be devastating. I look at that cost as minimal because it has enabled us to continue producing with no real impact on operations. But yes, we'll continue to see that cost as long as the epidemic is still running.

And also, this is Liz, I'd like to just clarify, those costs are primarily in our production expense rather than G&A.

Yes, thank you. As I was asking the question, I confused it with my next one, so that's a great clarification, Liz, which is that G&A did decline $800,000 sequentially. What allowed that to happen? Great job, but how did you do that?

Okay, and you're talking about overall G&A, right?

That's right, overall G&A down in Q3 versus Q2.

Yeah, most of what's going on there has to do with the SARS liability. So we have to mark that to market at the end of the period. So whatever the stock price is on the last day of the quarter, that's going to drive the valuation for that liability. And so when you end up with an increase in the stock price, then we have to record additional expense, and when you have a decrease, you record a reversal of that expense. So that's, to a large degree, what's going on. I would say beyond that, it's pretty stable between the quarters.

The only benefit one could think of is a lower stock price.

Yeah, I have to say I agree with you. I like client charges for that.

I understand. One other accounting question, if I may. The reduction in your tax valuation allowance, with all of the uncertainty that the pandemic is causing, what gave you the confidence to reduce that valuation allowance?

I have to say, and this is just confusing, but it's part of the mechanics of the US GAAP rules on interim period tax allocation. So there's some odd rules that you have to apply, and you end up with a, in our situation, we've got income in some quarters, and we've got losses in other quarters, and because we ended up with an overall negative effective tax rate, you end up allocating the taxes oddly versus what you would expect. I know that's probably not the most helpful answer, but it's really the best I can give for something that you almost have to be a tax expert to really make sense of it. Candidly, if it were me, I would change the way the rules work because I just don't think it's helpful for the investors to see the allocations the way they are, but This is what we're stuck with. By the end of the year, I think overall it'll make sense, but on a quarterly basis, it's difficult to understand.

Maybe I should take this offline, but I'm going to take one more stab at it, and then I'll move on. Yes. Is this an indication that you would expect greater profitability than what you were previously expecting? And as a result, that's mechanically why this needs to be done. And again, that'll be more obvious in the fourth quarter. Or is it something entirely less logical?

It's something entirely less logical. So basically, this is kind of how to look at it. We forecasted what we thought the full year was going to be in terms of taxable income. And then we had to take a portion of the valuation allowance and allocated in the first quarter when we had losses using a negative rate. And so that ended up putting on a bigger valuation allowance in the first quarter than what we were projecting for the whole year. And so it reverses out over the subsequent quarters. It is a very odd result, but you kind of got a hint of that in the first quarter, when we had this very large deferred tax liability, which doesn't make a lot of sense if you're writing down all your deferred tax assets, but that deferred tax liability amortizes off to zero by the end of the year. So it's a particularly hyper-technical explanation, but that is it.

Great. No, I appreciate it, Liz. Thank you. And then last one for me. is the production decline in the third quarter versus the second quarter. How much of that was due to the FPSO maintenance versus how much was the OPEC component? We recognize the wells themselves could produce better than what you did.

Right. And the way to think about that, Bill, is the the turnaround for maintenance on the FPSO and the platforms was a five-day turnaround. And so you can take the average production for the quarter and multiply by five, and that was the impact of the turnaround. And so the rest of the reduction was related to the OPEC curtailment so that Gabon could meet their quarters. Great. Thank you both. Okay. Thank you.

Next question comes from Jamie Weiland of Weiland Management. Please go ahead.

Good morning. I've been reading about your partner in the town is looking to sell their minority interest. And there seems to be lots of buyers circling around Korea Energy, BW Energy, and maybe others. And could you tell me the status of that? Do we have right of first refusal? Are we in their bidding? Do we wait until the end? And what does that say about what we think a part of this partnership is worth?

Right, Jamie. I can't comment on SASL's divestiture process and who's participating and what the status is. That is really for SASL to comment on. And what I can say is, yes, there is in our joint operating agreement at Atom, there is an opportunity for not only Valco, but the other partners to preempt the sales process. Again, I can't comment on those details because that is SASL's process to notify the joint venture partners. So under our JOA, though, there would be an opportunity for Valco and the other partners to preempt. And other than that, all I can say is we've We've said repeatedly we're very happy with the Atom asset, and for the right price, we would increase our stake, whether it's Sasol, Addicts, or Petro Energy, but I cannot comment on the process other than that.

Did Sasol put out any deadline dates for when they wanted bids to be invited?

Jamie, again, I can't comment on their process. Okay.

the 2018 extension from Gabon, that they gave you new areas. What did they give you? I didn't recall reading about that.

Okay. Yeah. If you refer to, again, slide 18, I don't know if you have access to our investor deck, but on slide 18, there's an outline of the license today. And if you go back in time prior to the extension, we had three separate what they call AEEs, and they were production areas, basically. There was one to the to the southeast it was a buma, there was one towards the middle that was a tom, and southeast a tom, and then there was one further to the north that was a buri. And they were not continuous. And so the acreage we picked up is the acreage in the center of the field in between, say, a buri and a tom, and then in between a tom and a buma, if that makes sense.

Excellent. Good. When you put out your forecast for a fourth quarter and looking forward, how do you factor in what you may have to do to meet Gibran's requirements for OPEC? And could you also, what percentage did you cut back? Did they force you to cut back because of the OPEC restrictions?

Right, right. Let me take your second question first. The percentage we cut back was a negotiation between Valco and the government. And For that reason, I really cannot give you any of the details other than we worked with the government on a target production rate for Valco based on Valco's long-term commitment to Gabon, the wells we recently drilled. Each operator really independently negotiated an allocation. I can't comment other than that. We did make it clear to the Gabonese government that we've invested heavily in Gabon recently and we have a long-term commitment and we need rates that allow us to recover our investments. But your first question on the fourth quarter, what you'll see in our guidance range is, has the OPEC production curtailment requirement built into it? And so the range that we put out, And, again, that range is – the low end of that range is up compared to the prior four-quarter forecast. So the OPEC curtailment is already – if there is one, is already built in.

Okay. And lastly, with the next drilling program, is it going to wait until the 3D seismic is complete? Is this a 2022 item or a function of oil prices, or where do you look at that?

Well, you know, there's a couple of, let me make a couple of points here. We don't really, of course, we have to wait until the seismic acquisition is complete. And then, as we talked about earlier with Charlie Shark, we will accelerate processing in certain areas where we see, you know, today we see the most prospectivity. So, you know, we don't necessarily have to wait until all of the processing is We'll start processing early next year, have the survey interpreted again all throughout next year. In terms of the next drilling program, let me say the seismic survey will not slow down the timing of the next drilling program. We've always talked about 18 to 24 months in between drilling programs. That's still our ambition and our schedule. Kind of think about 18 to 24 months from when we concluded the drilling program last April. That's when we would target picking up again. So that would be late next year into early 2022, something like that. Great. Thanks, Gary. Appreciate your time. Okay. Thank you, Jamie. Good to hear from you.

As a reminder, if you do have a question, please press star then one. No further questions. This concludes our question and answer session. I would like to turn the conference back over to Kerry Bonds for any closing remarks.

Yes, I wanted to thank everybody for participating and we look forward to speaking with you again next quarter.

The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.