Welcome to the BW Energy Q3 2021 presentation. Throughout the call, all participants will be in listen-only mode, and afterwards there will be a question and answer session. Today, I am pleased to present Carl Arnet, CEO. Please begin your meeting.
A warm welcome to this BW Energy Q3 2021 presentation. The presentation will be hosted by Lin Espey, our COO, our CFO, Knut Sæthre , and myself, Carl Arnet. I will take you through the initial slides on the operational status as usual, and Knut will take you through the financial status. We'll all be available for any questions after the presentation. Please note our disclaimer. On to highlights for the quarter. We will comment on them in more detail later in the presentation on the successful completion of the last two Tortue Phase 2 wells in October, which also concluded the Tortue Phase 2 development.
We are pleased to announce that this came in $45 million below budget, and we consider that a very good result, given the significant hiatus we had in the project caused by the pandemic. We will also comment on the provisional award of operatorship for two blocks in Gabon's 12th offshore licensing round, Block G and H. More on that will follow. Of course, we maintain a strong balance sheet with no debt and cash position of $170 million. Managing the impact of COVID-19 pandemic on operations is key to us, and we are still in a pandemic state that cycles around the world and this has implications for a lot of the things we do.
The Q3 EBITDA came in at $8.3 million, with a loss of around $10 million, caused by no liftings to the company in the quarter. We did produce about 0.8 million barrels in the third quarter gross. We are planning liftings in fourth quarter. We have already completed one in November, and there's a further lifting for company planned for December. The Hibiscus/Ruche development activities are on track, and we will comment on that in more detail. We have acquired the semi-submersible rig, Leo, that will be a key to unlock the Kudu gas to power development in Namibia, and more on that will also follow in the presentation. Our HSE efforts were awarded with no LTIs in the quarter.
We had one incident that we recorded on BW Adolo with a minor spill to the environment, where 15 liters of oily water was released. Further, the security risk at Dussafu remains low, and there's been no security incidents in our region. The COVID-19 is still affecting, in particular, the FPSO operations and our ability to do modification work. As I'm sure everybody's noticing, it's also affecting the general supply chain and availability of a number of products today. The production outlook, we have reduced our expectation for 2021 and 2022 on production from Tortue, and that is reflected in the gross production estimate, seen in the left caption and, of course, likewise, the net production estimate in the right caption. We will comment further on that later in the presentation. On to Dussafu.
Production at Dussafu was 0.8 million barrels equal to about 9,000 barrels per day. The production was affected by plant shutdowns and the limited capacity, gas lift capacity that we are suffering from. The gas lift limitations will continue to defer production until capacity can be increased in the fourth quarter of 2022. We are planning to install an additional machine for implementing higher gas lift capacity. Due to the restrictions we have on offshore work and also the problems with the supply chain, we will not be able to do this until the fourth quarter, and that will affect our production from Tortue. The Q3 OpEx was $36 per barrel. That's including the COVID costs in this quarter as well.
While we expect a revised full year now with the new production figures to be around $30 per barrel. The Tortue Phase 2 was successfully completed, and with the tie-in of DTM-6H and DTM-7H, the two wells were both on stream in October. First DTM-7H and then later, a bit later, a week later, the DTM-6H. Both performs according to our expectations with DTM-6H being a positive surprise in terms of its capacity. We are pleased with the wells, but we are extremely pleased with, of course, the overall project result with the final cost estimate of $230 million, which meant we didn't use at all the project contingency we had set aside.
We also managed to reduce a bit further. That's extremely well considering the duration of the project. It's also showing that we managed to completely stop all activities and all costs during the hiatus we had, caused by the pandemic. The total project, just to remind everybody, that was a further four production wells, tied back to the FPSO and a new inlet manifold on the FPSO. The 2021 production forecast has been revised to 4.1 million. This is caused partly by the number of trips we've had in the operation on the FPSO, but mainly are caused by the lack of gas lift capacity.
With the wells we have now completed, we have a well capacity of 19,000 barrels, but we can only use part of that due to the gas lift capacity. We will not see an impact on the overall recovery from Tortue, but we will have deferred production and, as I'm sure you know, the barrel we don't produce today is one of the later barrels we will produce. When we have the production, the gas lift capacity increased, we will be able to increase production somewhat from today's level, as you can see from this caption on the top left-hand side. We will then also have, in the meantime, seen some decline in the reservoir, so the balance is not a large increase.
Overall, we will not see an effect to the recovery from Tortue, and we expect the number of barrels to be produced from Tortue to remain unchanged over the life of the field. The Hibiscus/Ruche field development project is progressing according to plan. Hibiscus Alpha, as you can see from the picture, was in the dry dock at Dubai Drydocks. The first phase of the conversion is completed with the demolition of drilling equipment and preparation for the unit to go to Lamprell, where we will do the topside work. We have purchased all major equipment packages.
We are seeing a well-functioning COVID-19 protocol in Dubai that allows us to get people, particularly, service people and people associated with the packages, in and out of country. It looks very promising. We are monitoring the situation very closely though, because of the general problems we see in the supply chain. At this point, all our major equipment packages are tracking to schedule. Of course, we have to stay alert to any mitigations if there are problems that we discover later on. The field work is also progressing according to plan. We have just tendered for the drilling program, which will be a firm +4 optional wells program.
The planning is also done to perform up to two exploration wells as part of this drilling program. We are very much on track for first oil in late Q4 2022 from Hibiscus/Ruche. In terms of budget, we are tracking very well to meet our improved budget where the repurposing of the jack-up as opposed to building a new platform will give us savings of $100 million, approximately $100 million. Hibiscus North post-drill implementation interpretation is shown in the caption on the right-hand side. We have discovered oil in Gamba and the Dentale formations as expected.
Basically, we found the reservoir a little bit deeper and the oil-water contact a little bit shallower than expected from the seismic interpretation, which gives somewhat lower volumes than the pre-drill expectations. We will of course now take this data to update the reservoir model and our interpretation. We will see a potential to add this reservoir as a future standalone subsea tie-in to Hibiscus Alpha. That will be later on when we have started production and are seeing decline from the main Hibiscus and Ruche reservoirs that will be targeted for the first phase of this development. The well cost came in as expected at about $20 million for this well.
We are currently in negotiations for operatorship of Block G12-13 and H12-13 in Gabon. We were provisionally awarded these concessions in the 12th offshore licensing round. We are now negotiating with governments on the details of the PSC for these two blocks. As you can see, these are very large concessions. Block G12-13 is around 3,000 sq km, and Block H12-13 is around 2,000 sq km surrounding the well-known Etame and Lucifer fields. We are planning if we can conclude these negotiations for an eight-year exploration period with a potential for two-year extension. The commitments is to drill exploration wells and do a 3-D seismic on both blocks. We represent a partnership where you see some well-known suspects.
It's Panoro Energy with 25%, Vaalco Energy with 37.5%, and BW Energy as operator and also with 37.5% ownership. On to Maromba. With the release of the Polvo FPSO from its current contract, it has become the lead candidate for the Maromba development. We are currently evaluating yards to carry out the upgrade, repair, and refurbishment that is required. We are now stepping through all long lead items to make sure that we have full control over those. Continuing work alongside this, of course, on the main approvals and the outstanding approval is the environmental approval from IBAMA, and we are carrying on with that work. As far...
While we are also, of course, optimizing the field CapEx and the OpEx and time to first oil. We are well on track to achieve a final investment decision in 2022, and we are very much on track to achieve the 15% IRR, which is our target for $40 per barrel oil price. We are quite optimistic on the further development of the Maromba at this point in time and we see the Polvo FPSO as a very much instrument in achieving this. Kudu.
With the acquisition of the semi-submersible drilling rig, Leo, for $14 million, we have, let's say, the key component in achieving a gas to power project for the Kudu development. It's a totally integrated gas to power project, where this Leo semi-submersible will be the floating production unit located on the field, producing gas through a pipeline to shore, where there will be a power barge with a total capacity of 420 MW, of which 250 will be base load and 170 will be available for peaking power in the local market.
This significant optimization of the project and timeline versus the previous development concept makes us able to meet a very attractive local power price for the base power, as well as, of course, the obvious environmental benefits of this project for Namibia, where if this project is done, they will replace import of coal-based electricity from South Africa with natural gas electricity. This will of course also make it possible for Namibia to, with a very high degree, use renewables in addition to this gas-powered power, as they can then use the flexibility of the gas power to fill in when the other forms of power, solar and wind, are not available in the grid due to either night or lack of wind.
This will create a lot of flexibility and will give a very sustainable project for Namibia. We are extremely pleased to, let's say, renew our efforts and, based on this key change and key possibility, where, of course, this acquisition gives a lot of flexibility in the production at a very aggressive price point. On to financials and, Knut, over to you.
Thank you, Carl. A few words to the financials. They're not that exciting in this quarter as we had no liftings, but let's take you through and go to the next slide, please. The income statement. The operating revenues in the third quarter relates to the state profit oil and our domestic market obligations. We had an EBITDA of $8.3 million, significant increase due to the fact that we didn't have any liftings. The depreciations are also lower. We only have a small portion which is related to the state profit oil. That depreciation is following sales mainly and then we also have the depreciation for right of use assets, which follows production.
Production was a little bit lower in the third quarter compared to the second quarter and ended up with $6.1 million, giving us an operating profit for the quarter of close to $1 million. We have the financial items, not a lot to mention. Previously, we have also highlighted that we have an interest rate swap that fluctuates on a mark to market. In the third quarter, we had a gain on that swap. That is a loss before taxes in the quarter was -$1.9 million, and then we had the taxes of $8.4 million, giving us a loss for the quarter of $10.3 million.
If we go to the next slide, which is the balance sheet. There, if we should pick something that is important to mention is an increase on the E&P tangible assets. That is the capitalization of the 7H well offset by depreciations. On the intangible assets, we capitalized the Hibiscus North well, and also we have, of course, the Hibiscus/Ruche development where we're incurring costs in our yard activities, mainly now at Lamprell and also the previous stint with the Dubai Drydocks World. We also had the Kudu farm-in in July, where we will come up with.
We have worked on a business case, and in the fourth quarter now, we hope to conclude on the business case, and we will then start to capitalize Kudu going forward and also reverse some of the past impairments that we had on the Kudu project. That will all happen now in the fourth quarter. On the inventories, there has been an increase that is then due, mainly due to the underlift position we had, as we had no liftings in the quarter. The trade receivables have reduced significantly, because of the receipts of the June lifting funds that we got in July. On the liability side, there's not a lot to highlight.
We have a very strong equity position, $530 million of equity, which gives about a 60% equity ratio. Just to remind you, there is still no external debt. The long-term lease liabilities for the BW Adolo is what we have shown here as our debt position. No external debt. We have the liabilities for Adolo. If we then move on to the next slide showing us the cash flow in the quarter. We started off with a very healthy cash position of $216.5. Good operating cash flow of $21.
Quite significant investments, as I mentioned, the drilling campaign, the Hibiscus/Ruche project, and also the payment for the farm-in in Kudu. In the fourth quarter, we still have significant CapEx spending on the Hibiscus/Ruche project, and we also will record the cash outlay for the purchase of Leo that was just mentioned. That will also come in the fourth quarter. The net financing activities, which relates to the bareboat of BW Adolo, giving us a cash position of $170.6 at year-end.
On the production and exploration side, we're working hard on optimizing the Dussafu output, to see how we can get an improved gas lift capacity and have an optimal production of the two latest wells together with the four, let's say, old wells. That is something that is ongoing. Hopefully we'll have that stabilized sooner than later. The permanent solution will not be ready until the fourth quarter next year, where we have another module installed. We will in the fourth quarter now complete the Hibiscus North oil in place assessment with our external reserve auditors and get out with those results for the annual reserve report that we will issue together with the annual report in February.
We're also in the planning for the next steps of the Dussafu exploration program. We have a significant drilling campaign coming up next year with the drilling of all the Hibiscus wells. There we also might have another go for another exploration well, but that has not been decided yet. On the development side, our number 1 and 2 and 3 target is to get the Hibiscus Ruche to first oil, which will give us a significant increase in production in late Q4 next year and continue into 2023, where we'll add on new wells, new production, and operating cash flow. Another imperative is to progress Maromba to FID in 2022.
We're currently in an assessment of the Polvo and are waiting for Polvo to be released from Brazil to enable us to get to a yard, get things going, and the plan is to get to first oil late 2024. Then, as Carl just mentioned, maturing the new concept of Kudu, get it right-sized with a lower CapEx and improved timeline. It's also something that is important for us and that will continue during next year and into 2023. On the corporate side, we have as an imperative to maintain a strong balance sheet, which we currently have. We have a good cash position. We have good operating cash flows that can fund new projects and future shareholder returns.
The intention is to pay a dividend of up to 50% of net profit once we're fully operational at Dussafu and Maromba. Finally, we have restarted our RBL financing initiative. We have reconvened our discussions with the banks and hope to see some progress and a conclusion towards the end of the first quarter in 2022. By that was our final slide before we move on to the Q&A session.
I leave it back to you, operator, to see if there is any questions online, or if not, then we will take the ones we have from the web.
Thank you. If you wish to ask a question, please dial zero one on your telephone keypad now to enter the queue. Once your name has been announced, you can ask your question. If you find your question is answered before it's your turn to speak, you can dial zero two to cancel. Our first question comes from the line of Teodor Sveen-Nilsen of SB1 Markets. Please go ahead, your line is open.
Good afternoon, and thanks for taking my questions. A couple of questions from me. First on the 2022 production expectations. You say that the current gas lift issues obviously will reduce 2021 production, where you have indicated precisely 13% lower production. I just wonder for 2022, how much will the gas lift issues impact 2022 production compared to your expectations a few months ago? The second question is on your investment level for 2022. Should we expect you to invest slightly more in 2022 compared to 2021? My last question is on Block G12-13 and Block H12-13 in Gabon. When should we expect the first activity there? Thank you.
Okay, maybe I should start then on the gas lift question or 2022 production. We have just started production from the two latest wells and that is, they are performing very well. We are currently optimizing with the gas lift capacity we have, and we're obviously trying everything to, let's say, augment the position while we're waiting for the last you know, the new and upgraded gas lift compressor that we have ordered. It is a bit early days to say exactly or to have a very firm figure for you on the production. Currently, we're producing around 15,000 barrels per day. That's a reasonable result given the lack of gas lift.
I don't know if you have anything to add to that, Lin.
No, other than the once we install the additional gas lift capacity, we will end up tripling our current capacity. It is quite a increase from where we stand today. No, Carl, it was a good summary.
Yeah. For the investment, Knut, I suppose you take that.
Yes, I do. On the CapEx guidance, we have been very active over the second quarter and most of the invoices came in the third quarter. We had a good progress on Hibiscus/Ruche and also the finalization of Tortue Phase 2. For the total year of this year, I think our previous guidance was around $160 million. As you have seen, we have acquired a semi-submersible drilling rig. That will increase by that amount plus a little bit extra. I think it's more in the $180 million plus that we will end up with.
It's of course always hard to see which side of the 31st December you will receive or pay invoices, but around there. For 2022 we have of course continuous high activity in Dussafu with the Hibiscus/Ruche project, where we'll also later on start with the drilling campaign and also these gas lift initiatives. We have a CapEx of around $230-ish related to Dussafu as we stand now. Then we have Maromba, which is around $7.5 a month, about around $30. A little bit of Kudu, a little bit extra. I would say roughly $275 million in total for 2022 as a CapEx guidance.
The final question was to Block-
And-
Just directly-
Yeah. Lin will probably take that.
Sure. Initially, the first step is the partnership. We've been invited to negotiate the PSC, production sharing contract, with the government. So that'll be the next steps. We anticipate to start those detailed negotiations here in this quarter. But there's uncertainty in when exactly that'll be concluded. That's uncertain. That could be as within the first quarter of next year or perhaps, you know.
Quite a bit longer as well. Once that happens, the first step is to do geologic studies on it, including evaluating whether we wanna shoot new seismic on that prospect. I don't think we anticipate to start drilling on it for a number of years from now. Did that answer the question?
Yes, absolutely. Thank you. Just a follow-up on the current production. You said that current production rate is 15,000 barrels gross. Is that a fair estimate for the total production in the Q4 as a whole?
No, I think the additional wells didn't really come on until the end of October, so beginning of November. We've also been experiencing a bit of operational difficulty, ups and downs, and we're trying to get all that lined out. I think we're gonna be. We're not gonna average 15,000 for the quarter. I think we're gonna be with the operational.
I think we have given a guidance there, Lin. Sorry for the interruption, of $11-$50 for the-
For the full year.
For the full year.
Okay.
Okay, understood. That's fair.
Okay. Great.
Okay, that's all for me. Thank you.
Okay, thank you.
Thank you. Once again, if there are any further questions on the phones, please dial zero one on your telephone keypads now. Okay, there seems to be no further questions from the phone line, so I'll hand back to our speakers for the questions on the web.
Thank you. Yes, there are a lot of questions on the web, and a lot of them are related to this gas lift discussion that we just had. I'm just trying to see if there's anything in addition. Well, it says something here about, given your compressor issues, what's the production ability currently, and what do you expect for the next quarters? I think that has been mentioned. What risk of not getting the new compressor installed by 2022, what are the risks to that timeline, equipment, crew, et cetera? Does the compressor issues impact your Hibiscus/Ruche plan at all? What impact will Hibiscus/Ruche have if the compressor installation is delayed beyond 4Q 2022?
Okay, very quickly, this compressor, additional compressor for Tortue does not affect the Hibiscus/Ruche at all. We do not expect to see any spillover. There is a general concern about the supply chain these days, as we know from, let's say the general walk of life, that there is difficulty with lots of deliveries, cars, what have you. It is a general issue, and we believe we have a conservative estimate when we say Q4 2022, and we definitely believe today that this is our best estimate and very conservative estimate. It only affects Tortue production, not Hibiscus/Ruche production. That is self-contained in the Hibiscus/Ruche development that we're currently undertaking and will.
All of these things will be dealt with on the platform that we will install on the Hibiscus/Ruche.
We have another question on guidance on the short-term Q4 results. What we've said there is that we have two liftings. Actually, we've done one of those liftings, and the second one is planned for December. Given that that lifting will take place as planned, we will have a very good quarter. We have also guided on $30 per barrel OpEx. Whatever comes out of that in terms of oil price for lifting that we did now in November, the month in terms of oil price started really well. Now it's a little bit down, but we're still above the $80 barrel average. We have a question: Does the $230 million Tortue development include the new ordered compressor to increase gas lift capacity?
No, the Tortue development has now been finalized and closed, and the newly ordered compressor is part of the CapEx guidance that I just gave to Teodor. We have a question on Maromba and more on the timing of the FID for Maromba. You say in the presentation that is for 2022. Can you say something about what are the triggers for getting to that FID?
Yes. There is. First of all, we are, let's say, awaiting BW Offshore to demobilize the unit from the field. We believe that will happen very shortly, and then they will take the unit to a suitable location, Middle East most probably. And that is where we will then take over and get access to the vessel for the final inspections and the assessment of the condition of the vessel. We expect to be able to make a decision on the FID in the course of the first half of the year, probably towards the very end. That is our internal target, to have the FID within the first half of 2022.
Good. We have another question related to more M&A activity. There is a question here that the media in Brazil have pointed to BWE as a potential bidder for the Golfinho oil field cluster offshore Brazil. Is this an ongoing process, and may it lead to a possible deal with Petrobras? Well, I refer to, let's say, more general statement that we also issued in, back in October that we note the press speculations regarding the possibility of BW Energy making an acquisition for the Golfinho. But specifically, we've had no formal decisions to acquire any of the assets currently being marketed by Petrobras. But maybe you could elaborate a little bit more, Carl, because there are more questions related to the same, what we are looking at.
Are we looking to buy brownfield, greenfield? Maybe something about geographical areas that we are involved in.
Well, it is correct that we for quite some time have been defining brownfield acquisitions as part of our strategy. Yes, we are looking in the very areas where we currently have assets. Brazil is obviously an area where we are keenly looking at the possibility of acquiring brownfield opportunities. That is yes, definitely within our strategy, and yes, definitely within our geography. We are very interested in pursuing these opportunities, and we see that as beneficial to the company and the shareholders, and also would spread some of our production risk, which is good.
We do, we don't comment on specific questions like whether we are into Golfinho or not, because that's something we will announce to the market as and when we have something concrete to announce to the market.
Good. Over to Kudu. There are several questions related to Kudu. One of them is, you have acquired a semi drilling rig. Does that mean that you would substitute the FPSO that was in the previous plan? If I merge that with another question as well, what are the next milestones, and when can we expect first gas from Kudu?
Well, first of all, on the suitability of the semi-submersible, we obviously it's a question of price. With the current close to scrap price we achieved on Leo, we consider this to be an extremely well-suited asset for what we need on Kudu. Kudu is quite harsh environment. An FPSO could have worked as well. We're not saying that it isn't a viable solution technically. It's just that a semi-submersible is much cheaper for this particular job where we do not need any storage. The condensate production on Kudu will be extremely low, and we do not need to have the tanks of an FPSO available for condensate. The gas is dry. A semi-submersible is ideal for this type of environment.
It's quite hard, harsh conditions. Leo is a very well-suited unit. It will need to be converted to permanent mooring, but that's not a huge conversion. Of course, we will benefit from sale of a lot of the quite new drilling equipment that is on board. We will have very ample deck space to do the processing required for the gas to meet pipeline specification. The other thing to note with Kudu is that it's now an integrated gas-to-power project where everything, including the power barge is in the project scope. It's field development, plus pipeline, plus power barge.
This gives a much better guarantee structure, and we're looking forward now to discuss this new solution with the government in Namibia as a very viable solution for them. We also have the possibility, of course, to divert the gas to South Africa, and the current need in Africa is in South Africa is there. There's been a number of LNG to power projects already being launched and that are bid, but there's still a lot of replacement of coal-fired power that will take place in the years to come. Namibia is our first port of call. If we do not get the traction we're looking for for this project there, we will look at South Africa as well.
We are very optimistic, but of course, we need to find a power contract. We need to sell the power, and that is the trigger for the project.
Good. I think we are down to the bottom of the list. There are a few questions left, and they are related to the share price, and it seems like we have someone that is not that happy about the current share price. There is one question I guess goes to you, Carl, because you have bought a lot of shares recently. Could you please tell us why you believe in the company?
Yeah. That's an interesting question. Well, I have a lot of confidence in what we're doing, and I think our future looks extremely good. All our projects are tracking well. Yes, we do have some issues with the current production, but it's mainly deferral of production. It's not really not giving us the barrel. The end game is still the same. So I think the company is extremely viable, and it's going to have a great future. All our investment projects are coming in well below our estimates and our budgets, which is good, and I'm sure the shrewd investors will know that that's key in this market, that you control your costs.
We will manage to solve these temporary operational issues with respect to the, let's say, irregularity of the FPSO and the gas lift that we have suffered from lately. That's work in hand, and I'm still very optimistic about solving these issues in the not too distant future.
Very good. That concludes the questions from the web. It's for you to close, Carl.
Okay. Well, thanks to everybody for attending.
Thank you.
Wish you all a very good day.
Thank you.
Thank you.