Good day. And welcome to the VAALCO Energy Fourth Quarter and Full Year 2020 Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions] After today’s presentation, there will be an opportunity to ask questions. [Operator Instructions] Please note today’s event is being recorded. I would now like to turn the conference over to Al Petrie, Investor Relations Coordinator. Please go ahead, sir.

Thank you, Rocco. Good morning, everyone. And welcome to VAALCO Energy’s fourth quarter and full year 2020 conference call. After I cover the forward-looking statements, Cary 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 review. Cary will then return for more closing comments before we take your questions. During our Q&A session, we ask that you limit your questions to one and a follow-up. You can always re-enter the queue with additional questions. I’d like to point out that we posted an investor deck this morning on our website 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 those actual results or developments may differ materially from those projected in the forward-looking statements. VAALCO 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 this morning on our website and in the reports we filed with the SEC, including the Form 10-K that was filed yesterday. Please note this conference call is being recorded. Let me turn the call over to Cary.

Thank you, Al. Good morning, everyone. And welcome to our fourth quarter and year end 2020 earnings conference call. Before I discuss our results, I would like to reflect on a number of significant accomplishments we have achieved all of which are building blocks towards long-term growth. In 2018, we negotiated a license extension of up to 20 years in Gabon that provided VAALCO the runway to maximize value by growing reserves and increasing production from our world-class Etame assets. Also in 2018, we paid off all our outstanding debt and began to rebuild our cash position. In 2019, we initiated trading on the London Stock Exchange, which complements our listing on the New York Stock Exchange by providing us the opportunity to diversify our shareholder base, attract additional research coverage and provide VAALCO with access to additional sources of capital to help fund our growth objectives. Just as critical, in September of 2019, we kicked off our 2019-2020 drilling campaign. That campaign had three successful development wells and two successful appraisal wellbores. Comparing our full year 2020 production of 4,853 net barrels of oil per day with our 2019 average of 3,476 net barrels of oil per day, we increase production 40% year-over-year as a result of our drilling success. In 2020, we saw oil prices adversely impacted by the global COVID-19 pandemic, as well as supply and demand imbalances. We had hedges in place that provided us good protection when oil prices fell and we were able to continue to generate meaningful free cash flow from our higher production volumes in 2020. Maintaining our strong balance sheet and financial flexibility gave us the ability to capture value through a very accretive acquisition opportunity that arose in 2020. We were able to overcome the challenges in 2020 and close…

Thank you, Cary, and good morning, everyone. We reported a net loss of $3.6 million or $0.06 per diluted share in the fourth quarter of 2020, which included the impact that $3.6 million in exploration expense related to the Etame seismic program during the quarter and $2.2 million of expenses related to stock-based compensation. As Cary mentioned, the liftings scheduled for December 2020 which delayed to January 2021, which reduced sales volume by approximately 155,000 barrels and revenues by approximately $7.8 million, while increasing inventory costs in the fourth quarter of 2020. For comparison purposes, in the fourth quarter 2019, we reported net income of $1 million or $0.02 per diluted share, which included the impact from a non-cash charge of $3.1 million for unrealized mark-to-market losses related to our crude oil swaps, expense for stock-based compensation of $0.7 million and a $1.8 million tax benefit related to a decrease in the valuation allowance on deferred tax assets. For the third quarter of 2020, we reported net income of $7.6 million or $0.13 per diluted share, which included an income tax benefit of $2.8 million, which reflected the impact of the decrease valuation allowances on deferred tax assets of $5.3 million. Our adjusted net loss in the fourth quarter of 2020 totaled $5.6 million or $0.10 per diluted share as compared to adjusted net income of $5.5 million or $0.09 per diluted share for the fourth quarter of 2019. The decrease in earnings between years is mainly due to the lower revenues as a result of lower oil prices and lower sales to the delay in the lifting scheduled for 2020, coupled with the $3.6 million of seismic related to the exploration expenses in the fourth quarter of 2020. In the third quarter of 2020, VAALCO reported $2.3 million in…

Thanks, Liz. Over the past several years, we have weathered a difficult macro environment. During that time, we worked diligently to build a solid foundation for the future by strengthening VAALCO operationally and financially. This included eliminating debt, growing our production base and consistently generating positive cash flow. As I looked at 2021 and beyond, I believe that this is a very exciting time for VAALCO. We are profitably growing VAALCO through a creative acquisitions and successful drilling campaigns at Etame. We are in and improving commodity price environment, which should meaningfully assist in our ability to generate significant free cash flow. The closing of the Sasol acquisition underscores our belief in Etame as a strong producing asset with significant upside. We’re also processing and interpreting our newly acquired 3D seismic and we’ll incorporate it with our 20-year -- our 20 plus years of knowledge as operator at Etame. The new seismic will help us to optimize and derisk future drilling locations and potentially identify new ones. Now I know that I’ve told this story before, but I think it is worth reminding everyone of the VAALCO track record of success at Etame. When we first began producing Etame in 2002, our third-party reserve auditors estimated there was 30 million barrels of gross recoverable oil. Over the years, we have drilled and expanded Etame such that we have produced over 120 million gross barrels of oil thus far. Looking to the future, we believe that the field still has over 100 million gross barrels of resource potential. We’re planning to drill up to four wells in the upcoming drilling campaign that we expect to initiate in the fourth quarter of this year. We have a strong asset base at Etame that is generating meaningful free cash flow in the current…

Thank you. [Operator Instructions] Today’s first question comes from Stephane Foucaud with Auctus Advisories. Please go ahead.

Hi, guys. Two questions to me. A bit detailed. The first one is around 2C contingent resources. In particularly, I saw that the extension based on economics sort of move from 13 million barrel to 18 million barrel. Even those are quite some low risk resources just about fixing the contract, I was wondering whether you could provide some color on why does have jammed up so much? And the second one is a simple one, we just a saw that there is an increase in the payables I think something that you call your account with JV partners, I think, its $5 million. And I was wondering how the cap -- the cash CapEx or the -- would move in Q1 and if whether it would be -- we need to incorporate these $5 million payments on top of the $2 million to $3 million, I think that you have forecasted in CapEx for Q1? Thank you.

Okay. Stephane, great to hear from you. I will answer your first question and then your second question, I’ll revert over to Liz. But your first question on contingent resources related to license extension beyond 2028 and the change from 30 million barrels to 18 million barrels of contingent resources. What happened is those -- that 30 million barrels was actually split into a combination of contingent and prospective resources. And so you’ll see that, that there’s another, I’m sorry, I’m sorry, that’s not correct, I’m sorry. The -- we have a management estimate of contingent -- of prospective resources that we haven’t included on the table. But those contingent resources that you see for the extension based on economics, those are Netherland, Sewell numbers. As we get our arms around the seismic and the interpretation of the seismic and we come up with new interpretations of the subsurface, we will revise our internal estimates and work with Netherland, Sewell next year to bring those volumes back into contingent. But again, those are barrels that would have been produced from 2028 to 2038. And in our view, their perspective and we will revisit those reserves as we continue to evaluate our seismic. Now on your second question.

Yeah. Stephane, on the second question, the joint venture is payables and receivables are really a function of when they’re paying their cash falls. So the -- we actually have a receivable as well that was fairly large at year end and so the net of those two was a $1.4 million payables. And so, yes, those do even out over time. So it -- if we were perfect at doing our cash falls and if the drilling owners didn’t pay early, that number would be zero. Well, it never is, because you’re never perfect at forecasting that stuff. But over time, it does tend towards zero. So, I would say, at year end, I mean, the 1.4 million, that’s not -- that’s a pretty small amount of impact on cash flow in the future.

Okay. Thank you.

Our next question today comes from Michael Sensilo with Enquira [ph]. Please go ahead.

Hi. Good morning. Thanks for taking my question. I have a couple of questions. One on costs and I’d like to focus on page 28 of your deck. Those cylinders and compare, I am not sure, if you have this available with page eight of your December deck, where the orange piece of the puzzle was $21.13 back in December and now it’s gone to $26. So just curious, I know you went over a bunch of numbers down on the cost side and I couldn’t really kind of say for them, but I would love to know what the reason for the $5 increase from your December numbers to the deck you put out today, which includes this one, I believe includes the Sasol acquisition?

Yes. That’s correct. So really what’s driving most of that increase is the lower production volumes. So about 90% of our OpEx is fixed and so when the production volumes go down the per barrel now is going to go up and vice versa and so we saw a really nice decline in 2020 due to the drilling program. Well, we had natural decline from the field, and so this year, because we aren’t doing another program and we won’t be bringing on new production and -- until very late in the year, maybe in the following year, you don’t see the benefit. That per barrel amount is going to go up. Now, on an absolute basis, our production expense is expected to be comparable between the two years and I think the midpoint of our guidance would point you to that. What we tried to do the other, I mean, part of this is challenging, because you’ve got the mixture of a portion of the year being with and without Sasol. So what we did in the press releases, we gave the growth numbers between the two years and we discussed those. And you’ll see that the midpoint of the guidance is -- was to what the gross number was last year.

Okay. The decline rate is 15% that would $21 to $26 is a lot more than a 15% increase on a per barrel basis. Is there something else going on, there’s a cost inflation in there as well?

About $4 of the decrease -- of the increase is the production rate and there is a little bit of increase, overall, in production expense, but not a significant amount. The other thing that you need to take into consideration is the prices that we’re using here. So you can -- there is a bit of a change at the -- at slightly higher oil prices you can end up with slightly higher production expenses as well. Because there is a -- there’s 10% of it that is variable.

Okay. The other pieces of a puzzle have also gone up -- the tax has gone up at $55 from December to today’s deck a little bit and then the G&A has going up as well and workovers has gone up. Everything has gone up, is there a reason for that?

Yeah. On the -- yes. On the -- if you’re talking about on a per barrel basis, the…

Yeah.

The tax is going to be a function of our revenues. So in general and this isn’t 100%. But in general, the cash tax that we pay is going to run about 10% of our revenue number. And the reason for that is that we’re getting 80% deductible as cost recovery. So that leaves you 20% and we pay about 50% of that is paid as a tax roughly. So when you’re looking at a $65 oil price, I think you’re going to end up with a higher tax number for barrel to that growth, because you got a higher oil price. In terms with the G&A, it’s actually down on a per barrel basis from last year. So last year, I think, we had $6.57 per barrel of G&A costs and here we’re forecasting about $4 per barrel of G&A costs and that…

But the December deck showed $3.44 after the, like, you have pre and post, before acquisition, after acquisition and so $3.44 after the acquisition and in today its $4, so that was a pretty significant percent of increase in the…

That…

…in that slice of the pie?

Yeah. And that’s going to be more a function of as the lower volumes in 2021.

Okay. Let me ask my next question, if I can, where do you think the stack looks after your 2021-’22 drilling program and where does your breakeven free cash flow go from and to?

We haven’t given any guidance on that. But one thing I can tell you is, so for example, last drilling program, we -- if you -- there’s a slide that shows the uplift and that was about 69 to minus 100 barrels a day gross, okay? And as Cary mentioned in his comments, and it’s also in the press release, from the next program, we’re expecting an uplift after the program is completed of somewhere between 7,000 and 8,000 barrels a day gross. So you can kind of use that as a guide to help you understand, okay, what would 2022 look like, as additional barrels. I mean, obviously, it’s going to have a significant impact on comparable to what we saw in 2020 -- the 2019-2020 drilling program. But we haven’t given, I mean, we haven’t given any guidance for 2022 yet. But that should help you at least directionally understand where the per barrel costs are going.

Okay. And then my final question will be just calculating free cash flow over the course of the year and putting that up against the VAALCO portion of the CapEx program, the drilling program ‘21-’22 that starts later this year. You got -- you have enough cash, I guess, between cash on hand and cash being generated, it looks like you’re going to be okay or do you plan on tapping a bank?

No. Based on current oil pricing, we expect to fund the next drilling campaign from cash on hand.

Okay. And the hedging will protect some of that as well you’re saying?

Yes. And that is exactly why we put the hedging in place, correct.

Are you layering in more hedges as we speak kind of thing or are we going to…

Not as we speak. I am sorry, I interrupted you. We’re not layering any hedges. Not right now layering on any new hedges? Not right now. But we are always considering new hedges.

Okay. All right. Great. Thanks. I’ll leave the floor.

Thank you.

Thank you.

Our next question comes from Bill Dezellem with Tieton Capital. Please go ahead.

Hi. Thank you. A couple of questions. First of all, can you discuss the December lifting and why it was delayed to January? And then secondarily, because oil prices did go up in January versus December, how much was the benefit to you?

Sure. Hi, Bill. Thanks for the questions. Okay. The delay in the lifting or the delay in the December sales to January was a function of a couple of things. First, it was a function of the COVID-19 protocols we have in place. There was a concern right before the lifting started that there was an infected person on the FPSO. As it turns out, the person was not infected, it was a false positive. But with all of our precautions that we have in place, it was more important to keep our employees safe and healthy and we decided to pause and delay the lifting until we were certain that the -- but again that our employees were safe and healthy. So that was the initial delay. And then secondarily, there were some operational issues, we have a crane that was not working on a support vessel, not a crane, but a winch, I’m sorry, winch that was not properly functioning on a support vessel that cost just a few days. But the -- really the delay it from December to January was primarily the COVID-19 protocols and our commitment to keep our employees safe.

And the…

Yeah.

… benefit?

And the benefit was $5 a barrel.

That’s right. So you had -- so the average price if we had done it in December, the average would have been around $50 and that’s kind of what we indicated with the $7.8 million and 155,000 barrels. In January prices ended up being around $55. So, I mean, roughly that’s 700,000 to 800,000 benefits for us.

Excellent. Congratulations, I guess, on not having the positive COVID and an extra $3.25 million in your pocket.

All right. Thank you, Bill.

Yeah.

And...

I apologize, Mr. Dezellem, please rejoined the queue. In the meantime, our next question today is from Charlie Sharp with Canaccord. Please go ahead.

Yes. Good morning. Thank you very much for a comprehensive update this morning. Really appreciate that. A couple of questions, if I may. One is I think exploring a little bit more an earlier question regarding the development program that you have coming up the drilling program at the end of this year and into next year, perhaps asking the same question as the earlier question, but in a slightly different way. What oil price do you think you need, given the outlook for production and the cost structure you have at the moment to be able to finance fully that program? That’s one question. And then secondly, with the FPSO contract expiring late next year, should we be concerned about potential uplift in cost structure associated with a replacement or an extension of that? Thank you.

Okay. On the drilling campaign, at the current oil prices that we see, I mean, we should be able to fund that easily with cash on hand and cash flows being generated between now and the time of the program. So I would -- while we haven’t disclosed kind of a breakeven oil price or anything like that, that’s -- I mean, we are happy with the current oil prices from a funding perspective. And then on the FPSO…

And on the FPSO, Charlie, good to hear from you and so you’re correct. Our FPSO contract is expiring next year in September. And so we’re looking at a couple of alternatives either, like, you mentioned, replacing the FPSO or extending the life of the existing FPSO, which is the Nautipa FPSO. And so I will say that both of those options require some upfront costs. Of course, if we replace the FPSO, there’s installation costs and things. And then if we keep enough people on station, there are life extension costs. And so we’re working through those cost estimates now and we have not made a decision. But as soon as we’ve made a decision on which path we will take, we will disclose those upfront costs. So there are upfront costs, but I’ll say that we do expect long-term costs to be less, whether -- and so there -- again, in a nutshell, the up -- there will be some upfront costs, but long-term we expect costs to be lower.

That’s great. Thank you.

Thank you.

And our next question today is from Bill Dezellem with Tieton Capital. Please go ahead again, sir.

Thank you. Circling back to the drilling program, I want to make sure that we’re getting this right that if we look at your forecasted production for 2021 and the forecast -- at the midpoint and your forecasted production from the drilling program at the midpoint, are we doing the math correctly? That’s approximately a 60% increase in production?

Yeah. I think mechanically that’s correct. However, the 7,000 to 8,000 is the production rate at the end of the program. So if you’re going to have to, I mean, you’re going to have to look at 2022 on a full year basis. But if you’re -- obviously, you’re not going to get the production that production for the entire year. You may get it at the end of the program. And one of the reasons, I mean, we didn’t get -- we didn’t try to get 2022 production, because at this point, we don’t have -- we’re forecasting we’re going to start the program in December, late in 2021. But there could be some things that could shift that forward or shift it back, depending on the rig contracts that we entered into and other things. So at this point, we really it would be very difficult to give you kind of full year production rates for 2022.

Understood. But mechanically that if the drilling program, if we were to just look at it in isolation relative to the 2021 production, it is that roughly 60% increase in the ‘22 production relative to ‘21 will simply be a function of the timing of when that program comes into play and natural decline rates?

Yes.

Exactly.

Yes. Don’t forget the natural decline, because that’s, I mean, the existing walls will continue to decline over time in ‘22.

That’s very helpful. And just as a reminder for us and I apologize for not knowing this off the top of my head, what was that equivalent mechanical calculation with your last drilling program? This seems larger to me and just really a big production benefit?

Yeah. There is a -- on slide 10 in the deck, that kind of gives you a good view that we -- for 2019, we had, on a gross basis, 12.8000 [ph] barrels a day. The Atlas was 6,900 luckily. We ended up with 1,800. That was a decline. So 1,800 is not quite 15% that -- it’s a little bit less than that. And then we ended up the overall average for the year was just below 18,000 a year a day.

Great. Thank you. I had not seen that slide. So just again, I did the math quickly. This is the prior program with slightly less, meaning that this new program is slightly more in terms of that mechanical calculation.

Yeah.

Excellent. And so then the follow on here, do you need to expand the capacity of the FPSO, whether it would be the one on site or a new one to accommodate this significant increase in production that is forthcoming?

Well, we are, of course, looking into the design of a replacement vessel and we would maximize the production capacity. There’s other alternative as well. But, yes, it is under consideration -- the capacity of the -- the production capacity of the FPSO is definitely under consideration. And not only the production capacity, but the storage capacity. We want plenty of storage if we’re producing at high rates. And so you’re right, well, all of those are under consideration right now and part of the analysis that’s ongoing.

Congratulations and thank you.

Okay. Thank you, Bill.

And our next question today comes from Garrett Finn with Susquehanna Capital. Please go ahead.

Hi, guys. Congratulations on the quarter, and again, on the deal, which looks like it was just an outstanding acquisition for you guys.

Thank you, Garrett.

One question I had is the 10-K states the cost recovery account, is it $51 million? Should we expect that to increase in conjunction with the closing of the Sasol deal?

All right. We would acquire Sasol share of that. Now, this is subject to certain adjustments and things. So we don’t have the precise number. But there should be an increase, yes.

And should it be like in the ballpark of 80% or…

There’s a lot of factors that go into candidly. I mean, just limitations on depending on what you pay for it and the value at the time. And I will keep it in mind that that’s an interest achievable so that when we make our disclosures in the first quarter we can -- we consider adding. But I mean, it should go up, but I can’t comment on whether it’s going to be an 80% increase or not.

Understood. Okay. And for the FPSO in the 10-K it states that it could process approximately 25,000 to 30,000 barrels of fluids per day. And so is the right way to think about it that the capacity for this vessel is 25,000 to 30,000 gross barrels of production per day.

Right. Right. The way to think about it is, it’s -- the capacity is 25,000 barrels of oil per day, plus we could send through another 5,000 barrels of water per day. So it’s 25,000 barrels of oil per day or 30,000 barrels of a combination of oil and water. But keep in mind that we have processing capacity on all four of our platforms. We removed the majority of the water on our platforms. And so the way to think about it is, there’s 25,000 barrels of oil per day production capacity on the FPSO.

Understood. Okay. And gross, the Etame has been running, I mean, in your slide, you have it kind of peeking out in the early part of 2020 at around 20,000 and then going up to maybe 22,000 and later in 2022. So it still seems like there is excess capacity on the vessel, which is provides a lot of leverage for you guys to the extent that you can increase production and fill it or potentially if you feel like that’s not realistic getting a smaller vessel, when the lease expires. Is that kind of how you’re thinking about it?

Well, the way we’re thinking about it is, you are right, we’ve managed over the past 20 years to drill and produce the field at 15,000 to 20,000 -- between 15,000 and 25,000 barrels a day, trying to utilize the full capacity. Now going forward, like you mentioned, September of next year, we will either replace or extend the Nautipa and our ambition is to increase capacity next September. And so that’s our ambition, but it has to come at the right price and so we have to look at, what is the cost of increasing the capacity versus the possibilities that we have to fill that capacity. So all of that is under consideration, but I would say, we would lean towards increasing the capacity as of next [Technical Difficulty].

Okay. And is this, I mean, it sounds like you said that you thought the total cost will decrease? Is there any reason to think the leases significantly above or below market or is it sort of reset to market rates with this recent extensions?

Well, I -- the overall market is not as active as it was 20 years ago when we installed the FPSO. And then, again, I think, it was 2012, when we amended the contract. And so, what we’re looking at, again, if we will have some upfront costs, but in this current market, we think we see the opportunity to reduce costs long-term.

Understood. And -- yeah, just looking at your slide on the deal, you guys paid $44 million, $4 million of that was a deposit and then -- that was the agreed price and then the cash that you’re paying is going to be $30 million. So the way I look at that is that this generated $10 million in cash in an eight-month period at $45 Brent.

Right.

And so that’s 3 times the cash you’re paying.

Right.

And Brent, obviously, is a lot higher now. So that just seems like an incredible deal.

Yeah. I think the other thing to keep in mind is that, is during that time period, we’ve had the seismic program and so that $10 million was bargaining to buy a quarter of seismic. So it’s actually -- if you excluded the seismic, you get -- and you’re looking more at a clear -- more clearly at operating costs -- ongoing operating costs then the number would have been higher.

Wow! Okay. All right. Well, I mean, that’s just a great deal and it’s a wonderful deal for shareholders. So we commend you guys. Thank you.

Thank you. We appreciate the feedback.

And our next question today is a follow up from Stephane Foucaud with Auctus Advisories. Please go ahead.

Yes. Hi, again, guys. And two further questions for me, can you say anything more on the plan for Block P. So the Memorandum of Understanding for this amount has expired, but that still remain very interesting assets, oil prices much higher, which probably means that even smaller resources are probably more commercial than they looked just six months ago. So how you are you seeing the sequence of events for the Block and what are your foot process? And secondly, another simple one, I was again looking at the aging program, the $53 barrel, that’s fixed price or that’s floor, if you can please remind me? Thank you.

Okay, Stephane. Thanks for the questions. On Block P, you’re correct, the Memorandum of Understanding we have with Levene has expired. And that was an agreement for Levene to come in and carry us on the cost of an exploration well. And so those discussions are still underway with Levene, but since the MoU has expired, we’ve broadened the discussions with other companies. And so, there’s a couple of different outcomes and so we’re -- one outcome that we’re still pursuing is to find a partner to carry us on an exploration well. We’re certainly still pursuing that option. And then you’re correct at these higher oil prices, another option that we have under evaluation is executing a standalone development of the Venus discovery on Block P. And so right now, we’re evaluating both of those options. We haven’t committed to either one yet. But they’re both very robust options. And like I’ve said in my earlier comments, the Venus discovery on Block P is 16 million barrels of gross resources and we’re looking at -- we’re looking for and evaluating cost effective development alternatives or opportunities, I should say, in the event, we don’t grow an exploration well. In the event, we can’t find a partner to fund this. So that is the state of play for Block P and Equatorial Guinea. And if you don’t mind, Stephane, could you repeat your second question for us?

That was around the aging program, it’s a detailed question, whether the -- if you could remind me whether the $50-ish per barrel is a fixed price or whether it’s just a floor that you can still benefit from the upside in the current oil price for the volume, that aren’t you?

That -- it’s a swap. So it’s a fixed price of $53.10.

Okay. Yeah. Thank you. And back on Block P. So Cary, is your feelings that Levene is still a serious counterparty and if it is not, do you get any sort of expression of interest for alternate parties or is there -- the risk of might stop again from scratch on the exploration somehow?

On the exploration side, I can’t really comment on the interest in other parties. Those -- we’re still negotiating and talking to other parties. So I really at this stage I can’t comment on the level of interest. I would say that, Levene, I can’t speak for what’s happening internally with Levene and their management and their strategy. But I can say that they chose not to extend the Memorandum of Understanding or memorandum -- MoU that we have with them to get to an agreement or to help us reach a format agreement. So, clearly their level of interest is changed. They have not extended the MoU, but we are still in discussions with Levene.

Thank you.

And ladies and gentlemen, this concludes the question-and-answer session. I’d like to turn the conference back over to the management team for any final remarks.

Sure. Thank you, Operator. I just want to say thank you for everyone’s interest and we look forward to your participation in our next earnings call. Good bye for now.

Thank you, sir. This concludes today’s conference call. You may all disconnect your lines and have a wonderful day.