Welcome to the BW Energy Q2 for the report of 2023. For the first part of this call, all participants are in a listen-only mode. Afterwards, there'll be a question and answer session. To ask a question, please press five star on your telephone keypad. I'll now hand it over to the speakers. Please begin.
A warm welcome to the Q2 presentation for BW Energy. This presentation will be hosted by, as usual, by our CFO, Knut Sætre, our COO, Lin Espey, and myself, Carl K. Arnet. Please note our disclaimer. Highlights for the Q2 . 3 producing wells at Hibiscus has been completed and has been handed over to operations, and we are on a very good track to complete the fourth well and expect to have that handed over to operations shortly as well. We have managed to start the second gas lift compressor after some initial commissioning issues, and it's now supporting the production from the Tortue field, and that will be covered a bit more lately as well. Golfinho closing is imminent, and address that later.
We had a EBITDA in the Q2 of $39.3 million, with a net profit of $5.3 million. There was one lifting in the quarter to BW Energy for 950,000 barrels, with a between lifting price of $75 per barrel. We had $100 million RBL accordion completed and drawn, and cash available to the company is about $233 million. We had, unfortunately, a lost time incident in the Q2 , which was caused one of our third-party support vessels, which was there for the drilling operation. Otherwise, we have all other activities has been incident-free. We also had no environmental incidents in so far in 2023, and have had none since we started operations.
I will go on to cover in a bit more detail the Dussafu asset. Production update. We had a gross production in the quarter, Q2 , of 1.4 million barrels, equal to about 15,200 barrels per day. The production was positively impacted by first oil from the two Hibiscus wells. We did, however, struggle a bit with the with the completions of these wells, and they were a bit delayed in coming on production, which is, of course, then reflected in the number of barrels that we produced. The OpEx declined in line with the production increase to about $35 per barrel. We had one lifting, as I previously told you.
We commenced the third Hibiscus well in mid-July, that has been handed over, and we are now drilling the fourth Hibiscus well. The gas lift compressor was lifted and installed and commissioned. We had some commissioning issues, and it was a bit delayed in coming on stream, as you know, compared to our initial plans, but it's now in operation and is performing well. We have a current well capacity of approximately 30,000 barrels as we speak, and we are producing close to that, but we do have some ESP electrical issues related to one of the Hibiscus wells, and we may have to do an intervention that is currently being evaluated by our team. The Hibiscus Ruche drilling program is continuing, and we are pleased with the operation today.
We are drilling the fourth Hibiscus well as we speak, the DHIBM-6H. We, as I said, expect to hand that over to operations early September. The campaign is targeting a further 2 Ruche Gamba wells, and we have now 6 firm and 2 options. Company is still evaluating further exploration and production drilling targets for the 2 remaining options. The current production outlook as we speak, we produce about 27,500 barrels per day. We expect the next lifting to BW Energy of 950,000 barrels in October. There will be 2 partner liftings in the meantime. We expect production in the range of 7-8. Slight reduction compared to previous estimates, and we expect them to have an annualized average OpEx of $25-$28.
That is just related to, of course, the number of barrels that we expect to produce. You can see here from the captions, the quarterly lifting schedule in the bottom left-hand corner of the slide, also the gross production profile. On to the Maromba assets. We have decided to step through the development plan and optimize it with respect to the ongoing inflation that we see in the market. There are some significant shifts in the cost of input, inputs to a project like the Maromba development. We, first of all, want to step through it to see, is the plan the most sensible plan we can have in the current pricing environment? Of course, we are still the, the, the overall development is still awaiting the project financing to conclude.
We feel we have time to step through and ensure ourselves that we have the right development plan in the current environment. We still expect the peak annual production in the 30,000-40,000 barrels per day range. We have also deferred the payment of the FPSO purchase in line with the revised project plan. We are very optimistic with the respect to our ongoing efforts, so we, we expect to have a good revised plan for Maromba development fairly shortly. Of course, we will inform you soon as we have the conclusions on the investment and the project financing. On to Kudu. We have acquired a 3-D seismic survey, and that was completed in May.
The new dataset will enhance both our model and de-risk potential upside in the targets, or the drilling targets, I should say, in our block. This is a very significant large block. We have already seen a very high improvement in data quality. Our geoscientists are now analyzing the new data, the new data cube that we have acquired. We have some early indications which of course tells us that there is a lot of promise in the Kudu block as well. The new results from Orange Basin is of course also underpinning and assisting in this analysis. We are still executing a concept or working on executing a concept for a planned Gas-to-Power project.
We are in a dialogue with the government, in and or government bodies, I should say, in Namibia, about this. We are extremely optimistic with respect to the future of our Kudu asset. I think that is the conclusion today. As we said earlier, we expect to have the final analysis done approximately one year after we completed the survey, so that will be more Q2 next year. On to Golfinho. We are extremely pleased with the smoothness of the startup of Golfinho. As we have related to you earlier, this field has been shut in for a significant revision to the facilities. It was recently restarted by Petrobras. The restart went extremely well, and the production has proven to be very stable.
We expect closing imminently. We are waiting some formal certificate, certificates of approval. As you understand, these certificates or issuing these certificates is outside of our control. We are working with the authorities, and we expect, as I said, imminently to be able to close this. The expected production from Golfinho is around 9,000 barrels per day. Again, we have a nice proven recoverable resource of 38 million barrels oil equivalents, and also some gas potential. I will hand over to Knut, who will cover the financials and sum up this presentation.
Welcome, everyone, to, to the financial part of this presentation. Just to be clear, I'm going to comment on the quarterly figures. We have this morning also issued a more formal first half report of 2023, which is then covering the half year figures and commenting accordingly. Now I'm focusing on the quarterly figures. To the income statement, we had operating revenues of $87.6 million, an increase from the Q1 . We also sold more barrels in, in the quarter. We had a lifting in, in May, which gave us a good, good revenue. We also had a few gains on the, on the derivatives from, from the commodity hedging. Operating expenses were lower compared to previous quarter.
We also significantly lowered the OpEx per, per barrel, giving us an EBITDA of $39.3 million in the quarter. Just to highlight again, we have some additional costs in the quarter related to the Golfinho acquisition. We have been ready for some time to take over operations from Petrobras on the Golfinho field, and in the quarter, we had about $11 million that were related to the Golfinho operations that we currently are undertaking. On the depreciations, it's somewhat higher. We've started depreciation from, from the Hibiscus Ruche development, so they will also increase going forward, bringing the operating profit to $21.4 million in the quarter. On the financial items, nothing significant to focus on.
Net financials was $5.6 expense, then giving us $15.8 million profit before tax. The income tax expense that comes with higher production, $10.5 million, giving us a net profit for the period of $5.3 million. Over to the balance sheet, it's more or less the same comments as, as usually we're, we are investing a lot in, in our Ruche Hibiscus development, which you can see here under the E&P tangible assets, $47.6 million increase in the quarter. Also in the intangible assets, we, we have costs or CapEx related to the Kudu seismic.
On the liability side of the balance sheet, you can see we had a drawdown of the RBL accordion. The RBL is now fully, fully drawn. You can see on trade payables, we have a very high activity and thereby also increased trade payables in the period. The balance sheet is growing, but still giving us a robust and good balance sheet. For the cash situation, we started off with $166 million in cash at the start of the period. Had operating cash flow, mainly then related to the May lifting of $57.9, and as mentioned, quite high investments in both the Dussafu license and also in the Kudu license of $75.6.
We have the net financing activities, which is the net of the RBL drawdown and financial liabilities related to the Adolo Release, giving us a net of $85 million and a cash position of $233.5 towards the end of the quarter. Still giving us a good cash and liquidity situation to continue our investment activities both in Gabon and elsewhere. I go over to the summary of this presentation. We have a step change in production. In Q2, we had a doubling of production. Right now, we are up to more than 3 times of what we had in the Q1 , at least.
As you can see from the right-hand graph, if everything goes as planned on Tortue, Hibiscus and Golfinho, then we will get up to approximately 50,000 barrels of oil towards the year-end. Just to summing it up, on the production and exploration, we're optimizing Dussafu output. New gas lift is finally there to support the Tortue wells. We have some work to do on the one well, the way we lost the ESP connectivity, but we're doing our utmost to get that rectified. Then we'll also continue to assess the Kudu potential from the seismic. On the development side, we will continue to drill in Dussafu, also having some interesting exploration targets to look at.
We will also then finalize Maromba development plan and work on, on the financing, and progress the Kudu Gas-to-Power project. On the corporate side, a good cash position, as mentioned. Complete the Golfinho acquisition, that is very important for us. The field has started up and is producing as, as predicted. Hopefully, in a very short time period, we can get the final certificates that is needed to close this transaction. In the meantime, we are working on also new potential financings. We have the RBL, as mentioned. We are also working on a possible Golfinho oil prepayment facility that we hope to close in the quarter.
Most importantly, the operational cash flow is imminent for us to fund new projects and future returns. That concludes my part of the presentation. We are over to the Q&A session, I leave the word back to you, operator.
Thank you. If you do wish to ask a question, please press 5 star on your telephone keypad. To withdraw your question, you may do so by pressing 5 star again. There will be a brief pause while questions are being registered. The first question will be from the line of Teodor Sveen-Nilsen from SB1 Markets. Please go ahead. Your line now will be unmuted.
How is that incorporated in your updated production guidance? My second question is on Golfinho. Should we expect any revenue recognition at all in Q3 from Golfinho? My third question, that is on Namibia and Kudu, of course, exciting times in Namibia with all the discoveries there. Could you please discuss potential exit groups for the gas and potential pricing for the Kudu gas in the future? Thanks.
Thank you, Theodore. We lost your first question. We couldn't hear you. Can you please repeat that?
Yeah, sure. No problem. The first question that was regarding the ESP and the well intervention you're talking about, I just wondered, how is the potential well intervention, incorporated into your new, or your updated production guidance?
Thank you. I guess I could quickly answer the second question, revenue in Q3 for Golfinho. We will record revenues for Golfinho as soon as we take over, which is expected imminently, and we can elaborate a little bit more on that. If just as an example, if the closing is first September, then we will recognize revenues from first September. But of course, it's associated with liftings, so that's when it really hits the books. That's it on Golfinho revenues.
Yeah, I think that that, sorry for interrupting, but I think that was the question. Do you expect any, any liftings from Golfinho in, in the Q3 ?
No, we do not.
I understand that there will be some production.
That, there will not, not be any liftings as far as I know. Petrobras did a lifting now in July, and they also did another one, in August. When, when closed, we have to come back to you with some guidance on, on Golfinho liftings for us.
Okay, thank you.
The first question, Lin, can you please say something more about?
Sure
on, on Dussafu?
Sure. Regarding the production, does the forecast incorporate the issue with the downhole ESP in 4H? That incident happened relatively recently, we have endeavored to account for the loss of production in our forecast going forward. I believe it forecasts an intervention to remedy the issue. There's gonna be downtime loss production until we do that intervention, which is scheduled in a couple of months.
Good. Then the third question that was related to Kudu and gas pricing, that was the way I should understand it, Theodore?
Yeah, well, yeah, it's, it's Kudu, potential exit route for gas and also potential pricing mechanism for the gas.
Okay, I can, I can try that. There are several, there are several possible exit routes for the gas. We have looked at before a route to Lüderitz, but there's also other possibilities. I think the, the, the, the current plan is to land the gas in Namibia. Then, again, of course, we are looking at several possibilities here. The location is, of Kudu is, very good for, let's say, any gas, other gas as well, associated gas, that could be produced in the Orange Basin. We expect there to be some work also with potential partners on establishing a gas-gathering network. It's early days, and, you know, we are speculating a bit at this stage.
We have a concept, of course, for taking our gas for the Gas-to-Power project to the beach. Of course, as we have a potential for more and more gas, we may have to revisit what we where we land the gas. The current plan is to take the gas to a power station, the gas price will be a negotiation based on a Gas-to-Power agreement and a power sales. The gas price will then be a result of the development cost and the achieved price on the electricity sold. That's also a bit early days, as we are as you can understand looking at various possibilities for the amount of gas that we need to take to or to land in Namibia.
I know it's a bit of a, let's say, neither here nor there answer to your question, but, but, the Orange Basin is super exciting, and there's a wide range of outcomes that are being. I'm sure you, you read in the press the same as we do, and there is a lot of speculation also from, Namibian parties going on as to the size of the, resources in Orange Basin. I'm sure you also appreciate that this will affect both where we land, eventually, and, and also the technical solutions that we will use. I think we have the right tools and the right location to become a gas hub in that part of the world, and then we will have to see what that becomes.
Okay, thank you.
Thank you, Theodor. The next question will be from the line of Tom Erik from Pareto. Please go ahead. Your line will now be unmuted.
Hey, thank you for taking my question, questions. I have a couple here. On CapEx related this year, how will that develop compared to the fourth, to the, to the Q2 ? Should we expect kind of a stable investment level, or, or will that come down or, or up with activity you have planned now? On capacity on the FPSO as well now that the business is ramping up, should we think about that as 40,000 barrels per day, or should we think about that as a somewhat higher figure, with, with some upside, at least given the bottlenecking potential that has been mentioned a bit earlier, I think?
Lastly, is there a timeline for when we can expect some kind of Maromba update now that all the things in Brazil is, is looking to move forward? Thank you.
Thank you, Tom Erik. I can take the first question to the CapEx. We have a very high activity, as mentioned in the presentation. We have invested more than $150 million in the first year. It's mainly Dussafu with all the drilling, and also in the Q1 , also with the MaBoMo installation and startup. In Brazil, we have more concept work, ongoing studies. That is out of the 150, that is about 15, that relates to Maromba.
Going forward on Maromba, it will still be study work for the new concept, but it will also then be the first of 2 payments to BWO of $30 million in October, and then later $20 million in April next year. That's the new agreed timing of the payments for the FPSO Polvo. For Kudu, we spent about $30 million in the first half of this year. That was mainly related to the seismic. Let's say, at least 25 of those were related to the seismic, and the rest also for concept work and commercial preparations.
Going forward on Kudu, there's a little bit left for for the seismic, about five-ish, and then so another 7, 8 for for the rest of the year, I suppose. The rest is for Dussafu with the, with the continued the drilling. Let's say it's $70 million-$80 million left for for the remainder of this year, and also something for for next year, depending on on targets and and what to utilize on on the options. If that is clear to you, then we can go over to the next question on Dussafu production.
Yeah.
Yeah, thanks.
I can take that. I can take that, Knut. Our production guidance of 40,000 barrels a day from Dussafu operator barrels holds. We're not changing that yet. Very pleased with the performance of the first three wells that we put online. They're coming in as expected or a little bit better. We are working with BWO, the FPSO operator, to see about expanding that capacity, but we're not quite yet there to propose any changes to our current forecast, but we're working on it.
Good. Just to add to, back to the, the CapEx question, of course, Golfinho is something that we expect to come as well. I, I didn't elaborate on that, but I would prefer to come back to that, that at closing. At closing, we would obviously then issue a, a press release and say something and more about, about the payments to Petrobras and Citibank, which would then come in addition to what I mentioned. The third question was, Moromba-
Maromba updates. Maybe I can take that. As I said, we are stepping through our development plan. We have done some updates. We do expect to see a slight improvement. Even though it is an inflationary market, we do expect to see a bit of improvement in our overall CapEx. This is being detailed as we speak. The real issue though, is that we are working hard to put together the financing package for the project. Let's say some of our previous trusted banks have pulled back from financing E&P investments. We are looking at other sources.
We are currently working on a package for the infrastructure and looking at various ways to either get infrastructure financing or lease financing for parts of this infrastructure. Nothing is landed yet, and that is driving the schedule. We will have our new development plan technically vetted by the end of this year, November timeframe. Then, of course, we hope then to trigger the project as soon as we can, when we have the financing package in place, or packages, I should say. There are several sources.
Tom Erik, does that answer your question?
Yes, thanks. Much appreciated.
Thank you.
Thank you, Tom. As there are no more questions in this call for now, I'll hand it back to the speakers for any written questions.
Thank you, operator. We have a lot of questions to answer. I tried to structure them a little bit. Let's go for, for Dussafu first. Link, if you could elaborate a little bit more on, on the, let's say, go- ongoing plans for, for Dussafu and, and the current well that we're drilling, the, the 6H, when that will be up and, and producing, and maybe also say something about about what we're going to do after the 6H.
Okay. We are drilling the 4th well in the program, it's the 4th well from the Hibiscus field, drilling is going well. We're actually have started the completion phase of it, I think it's anticipated the well's gonna be handed over in 2-3 weeks. We'll bring that well on, that'll be the 4th well. As a reminder, Ruche Phase 1 was sanctioned as a total of 6 wells. This week, we're just about to complete the 4th well, then we have 2 remaining wells, these 2 wells will target the Ruche field, which is the adjacent field to Hibiscus. They're all these wells being drilled from the MaBoMo platform, we'll bring those on.
As Carl mentioned, we are considering drilling, doing some additional activity, whether more development wells or a little bit of appraisal, exploration appraisal. We're evaluating that and to see whether we want to extend this drilling program, but no official announcement on that yet.
Okay. Then there is a follow-up question from Nick in certain place. If you had to do an intervention to fix the electrical issue on the Hibiscus well, what would that involve, and what might it cost? Would you need a rig to do this?
Okay. The, as a reminder, this type of downhole electrical submersible pump system is actually wireline retrievable. In theory, or not in theory, in practice, you can pull the pump and motor out using wireline and not necessarily you have to have the rig. We're, we're still trying to identify what the, the issue is, and we haven't made a determination which type of intervention we're gonna do, whether it's a wireline retrieval or use the rig that's on location to pull the entire completion out. I do... The cost for, if we do a work rig, workover, where we pull the entire tubing and completion out, the cost of that is gross, $8 million-$10 million.
As a follow-up to that, again, from Nick: Can you just confirm the amount of expected CapEx remaining for Hibiscus-Ruche Phase One end of June? Can you give some more color on, on why the CapEx estimate has gone up, given drilling performance seems to have now improved?
I can, I can answer the increase in the CapEx and, the remaining CapEx, I think, you may have already answered that.
Yeah
The, the, the uptick in the CapEx that we've announced is primarily reflects the issues that we had in 2Q, which related to the completion installation problems with 3H, the 3H well. Running the completion, we had a number of issues that we had to work through. In 4H, we had the stuck casing that we had to sidetrack. Those were 2 significant events that, that we've had to account for now in the CapEx.
Good. Then there is a question about liftings. We had lifting now in, in July. There will be another lifting for partners in August and another for partners in September. If everything goes as planned with taking on the new well, we will then have liftings on a monthly basis. For the Q4 , there will then be three liftings for BW Energy. Going forward, there will be monthly liftings. I think we have covered most of the Dussafu questions on this. If we then move on to there are lots of Golfinho questions. You say that Golfinho is producing and in accordance with expectations. According to marine traffic, lifting has commenced. Yes, I mentioned that.
How much has been lifted, and who is entitled to the sale of the oil up until closing? That is Petrobras, and there has been 2 liftings to Petrobras, in 1 in July and 1 in August. It is producing according to expectation. They started up early June, production, bringing up in total 6 wells. The first 2 wells came up as expected. Those are on ESPs, and the 4 remaining took some time. There are 2 gas lift compressors on the Victoria FPSO, and it took some time to get those up to operational uptime, so to say. It was a little bit up and down, but when they came up, the average production was of 10,000 barrels in July. It's producing as expected.
I don't know if you have anything to add, Lin or Carl?
No, I think that's, sums it up.
Yeah.
Yeah. No, fair.
Then you have guided on 2 infill wells to be drilled. How many months after close do you expect to commence the drilling campaign, and when will this be completed?
I can touch on that. Once we've acquired the asset, then, I think nominally we have... There's two infilled wells that we've identified, a gas well and an oil infilled well, that we like, and those are identified as the first two capital projects. We would work that up. I think the forecast, it's, it's a little over, little over two-year process before we would be able to get those two wells online.
Okay, next question: You will maintain a robust balance sheet and liquidity supported by RBL and possible Golfinho oil prepayment facility. Is this a new RBL, including Golfinho? The possible Golfinho oil prepayment facility, is that related to offtake? Please elaborate. The RBL accordion, that is the $100 million that we drew down in Q2. That is related to Dussafu and has nothing to do with Golfinho. What we said in this presentation is that we are working on a trading facility, a prepayment facility, that we hope to get closed in this quarter. That is also then related to a marketing agreement with an offtaker.
There is a question: closing of the Golfinho deal is expected imminently, and you are awaiting formal certificates of approval. Is that only for IBAMA? What other formal certificates do you need? It's an IBAMA, or it is what we're waiting for, a certificate, and we hope to see that coming out rather soon, then we can go into the closing procedure, get everything-
Just a quick... We first have to have the IBAMA, then there's about 48 hours, and then we should have the final ANP approval, and then it, it's the importation of the unit, as soon as we close with Saipem. These are the, the outstanding bits, and the first that we are waiting for is IBAMA.
Yep. Taker of the FPSO Cidade de Vitoria will be when the current short-term lease and operate contract for the FPSO expires. Who is paying for the FPSO now and until close of the deal? That is Petrobras, and we will then take over, or after closing, then the, the cost goes to BW Energy, and the plan is then to take over the FPSO after some handover time in, in the Q4 . The final question that I see here on Golfinho is, how do you see the production after restart of the field? You say something, Carl?
Well, the field has been shut in for a while, and we did expect to see some, let's say, increased level of production due to well recovery, and that has appeared more or less as we expected in, in line with our, let's say, theoretical model of the reservoir. We do expect to see some downtime on the unit, as we, we have seen a very smooth startup, but I think it's prudent to expect there to be some equipment malfunction after a longer period of non-operation. We, we expect about 9,000 barrels, as we said in our presentation earlier. That is, It's not super conservative, but it's not super optimistic either. It's, I think we, we, we, we, we try to strike a kind of middle ground in us, that estimate.
Okay, I think that was all for Golfinho. If I continue down on the list, there is a question from a Norwegian investor that have seen that we have registered a company in Norway, BW Energy Norway Management. Why was that done? That is a pure management company. We have utilized BW Offshore for some supporting functions. Now, we have moved some of the employees in Norway, over to a separate management company. There's nothing, nothing big news around, around that registration. It's just a practical thing. I think we have answered some of these. Let me see if there's anything.
Regarding cash flow for H2, considering the payment of $30 million for the FPSO Polvo and ongoing CapEx in Gabon, potentially Brazil, are there any sources beside the existing cash on hand and operational revenue? What's the situation regarding the submersible drilling rig, Leo, that was acquired for Kudu? I think we have answered the first part of the question related to financing. We are exploring a trading facility for Golfinho in the shorter term, and then on the longer term, obviously, it's the Maromba financing that is being worked on. Situation on the Leo, maybe shortly, Carl?
Yeah, well, Leo is in cold layout. We are extremely pleased that we managed to acquire this unit at a very trough of the market. We are warehousing a very large, very new build unit that is very, very well adapted to the use we envisage as a gas hub in the Orange Basin. Yeah, it's under cold layout and waits when we formally launch a project that will use it. We are very, very certain we will use it, as we are getting more and more confident that there will be plenty of gas coming out of the Orange Basin.
Good. Then there is a question on hedging: "Can you give us some more details of your oil hedge pricing?" We have obligations in the RBL to hedge 40% of the year one production and 25% of the year two production. Right now, that's only related to the Tortue production. As soon as we get completion of Hibiscus Ruche, then that production will be added. We will do some, some more hedging going forward. Right now, we have hedged about 1.5 million barrels with use of zero-cost collars, where we have puts between $50 and $60, and the calls are close to $100.
That's, that's where we're at right now, and we will then continue with hedging activity in the Q4 . Considering also using the same instruments, zero-cost collars or also, also swaps. There is a question on dividends: "Why is dividend payment conditional upon full operation for Maromba? Does it mean first oil? Is it a covenant in the RBL or just an internal decision?" There's nothing in the RBL stopping us from paying dividends, so that's up to the BW Energy board. What we have said in the past is that we would have to see or have a clear vision of the outcome of Maromba before paying dividends to shareholders. There is a question about the...
There is some news out there from the Ministry of Mines and Energy in Namibia, that said in August, that the Kudu gas reserves are expected to increase to 10 TCF. Is that the case?
We think it's a bit early days to declare that, normally you would have to have a seismic interpreted. I think we would also need an exploration well to prove up that amount of resources. It is true that we do see a lot of potential in a lot of, we have a much clearer picture of the subsurface in the current data set. We can see that already, but as I've said before today, the full interpretation of the current data is expected in May. We will have an interim report in October, where we will be able to, let's say, progress on our thinking.
May next year, and potentially an exploration well, and then we can declare with triumph and say 10, 10 TCF. That's a bit of maybe yet.
Good. I think that concludes the list of questions that we see on the web. I leave the word up back to you, Carl, for closing.
Well, I thank you for the interest and lots of interesting questions. Again, very much thank you to everybody for attending our presentation. Thank you.
Thank you.