Buru Energy Limited (BRNGF) Investor Webinar Transcript

2025-09-04 06:12:20 ET

Buru Energy Limited (BRNGF) Investor Webinar

Company Participants

Thomas Nador - Chief Executive Officer

Presentation

Thomas Nador
Chief Executive Officer

Okay. Once again, greetings, and welcome to the investor webinar for Buru Energy. My name is Thomas Nador, and I'm very pleased to be speaking with you depending on your time zone, whether it's in a.m. or p.m., but I've been looking forward to sharing an update with you on the progress of our Rafael Gas project and provide some added detail and definition around the recent ASX releases we've made to the market relating to the project itself.

We do have a disclaimer, a standard disclaimer. I encourage you to read that at your own leisure. In particular, it refers to 3 quite pertinent ASX releases we've made to the market in 2024, 2025 that relates to the statements we are making today regarding resources.

I would like to start by sharing with you some key messages. So there is absolute clarity on the call as to what we are trying to get off the ground here at Buru Energy and why I firmly believe that Buru Energy is a very good investment proposition.

We do have a discovery called Rafael. For those of you that are new to Buru, Rafael Gas was discovered in 2023. And we are busily going about commercializing that gas and condensate discovery. It has the potential to transform the company.

Secondly, it has been independently certified as a contingent resource. And we have, since then, done some internal work as well that gives us confidence that the resource is there between 85 and 523 Bcf of gas and between 1.8 million and 10.8 million barrels of liquids.

There is a market that's available to us up in the Kimberley region of Western Australia, but also in the north of the Pilbara and some sections of the Northern Territory.

We have made a transformational deal with Clean Energy Fuels Australia. They will bring about 80% of the capital required to develop the project. They've got access to market and obviously, expertise in LNG to build, own and operate a facility on the Rafael 1 wellsite.

The cash flow is projected to come on about 2 years following final investment decision. And that cash flow, through our economic screening and analysis work, shows that it is greater on an annual basis than our current market capitalization.

And there's a very important point I would like to make to our listeners. All of the project assumptions we are using to make decisions on, and it will be fundamental for making a final investment decision, are based on a high confidence P90 inputs. What that really means is when we look at CapEx, when we look at pricing, when we are looking at schedules, everything is based on the high confidence numbers. When you're an explorer, you tend to focus the mind of the market on your best estimate or your high case. You can't develop projects on hope. This needs to work, and we have demonstrated that based on P90 assumptions, this project will work. And then anything above that P90 is upside.

I recognized we've got callers on this morning that have not been with Buru for a while and they don't know the company. So welcome, especially those in the U.K. and the U.S. The company has been around since 2008. At one stage, we were the most prolific onshore explorer in the state of Western Australia, which is fantastic. But so far, we have not been able to commercialize and develop any of that exploration success until now. We are now focusing on the commercialization of that Rafael conventional gas and condensate discovery, which we own at 100%. Why? Because those enduring cash flows will give us the right to grow. Those enduring cash flows will effectively rerate the company, and it will give us optionality that we currently don't have today.

We also are separately working on farming out, again, the Mars 1 well, which is an unrelated structure to the Rafael Gas project. And that well, if successfully farmed out, will underpin a potential restart of the Ungani production facility for oil exports.

So what's the problem we are solving? The problem we are solving is that for the last couple of decades, every molecule of thermal energy into the Kimberley has either been trucked or shipped from a long way away. So in the case of gas, the gas-fired power stations that exist around the main demand centers of Derby, Broome, Looma/Camballin, Fitzroy and Halls Creek, they rely on this long-haul trucking arrangement. And then it's costly, and it's also insecure. So that LNG gets trucked from North West Shelf, it makes its way up to Broome. And by the time that truck gets to Halls Creek, that truck has traveled 1,400 kilometers. To make it a little bit more challenging, every time there is a weather system that shuts down the Great Northern Highway, the only route up there, [indiscernible]. And some of the developers who are up their mines, they have to shut in operations because they've got no security of supply.

Now Horizon Power is a government-owned entity, and they're responsible for generating, procuring and distributing and selling electricity into that region. And also, they are now responsible for 100 remote communities that rely primarily on diesel for their power generation needs. A little bit more on that later.

Now this project, the Rafael Gas project, yes, we are looking at this as a potential offtake. And yes, we are making good headway with the WA state, but we can't just rely on this as the offtaker. And for that reason, a capture zone has to take into account, and our final investment decision will have to take into account, volumes over and above what we believe will be taken by the state, either as a primary source or as a firming source of thermal generation to complement whatever scheme the state will invest in to start shifting the region towards renewables.

The 100-or-so remote communities that rely on diesel today, once again, their diesel gets trucked or shipped. One of the benefits of the Rafael discovery is that it has a very high condensate gas ratio. And what that means is we've got condensate that is potentially suitable as a diesel replacement. And based on the basis of design, we could be looking at between 20,000 and 40,000 liters of this commodity, which, if this was in the Perth Basin, it would be treated as a bit of a problem, not up in the north.

There is robust demand for power outside of that immediate capture zone. So we are in discussions with proponents who have stated very clearly as part of their basis of design that they will rely on gas-fired power generation to actually get that project up. So that's the problem we are solving.

And Rafael is not the solution, but it's certainly part of that solution. It's uniquely positioned. It has no competition. This is a conventional resource. It has no competition. And when you put this particular slide in front of decision-makers, by virtue of the distances involved in this part of the world, it's a no-brainer, whether it's on proximity to market, whether it's the actual cost of delivery, whether it's the environmental footprint of long-haul trucking versus short-haul trucking, the opportunities for regional development, especially around Derby, where this project is at, new market opportunities and also new proponents coming on board who have been waiting because there is very expensive and very insecure supply of energy up there and also synergy with renewables.

Gas is more than a bridge fuel. Yes, we keep hearing about it as a transition fuel, but until such time as there's solid capacity building around transmission, around generation, there are very few alternatives available.

Now you will notice on the left-hand side of this picture, there's a map of Western Australia. And you also would see that there is no pipeline network up in the Kimberley. So there's no alternate option but to truck. But by virtue of the proximity to the market and once again, the capture zone does extend into the north of the Pilbara and into the west of the Northern Territory, there is -- it just adds up on so many levels.

The other point I would make on this one, and remember this number, regional gas generators are fueled by that LNG that comes from Karratha by truck, and it's been costed independently at $22 a gigajoule, $22 a gigajoule. Now, mom and dads don't pay $22 a gigajoule. They can't. The taxpayer is paying $22 a gigajoule, is making up the difference up to a tune of $170 million a year to make that arrangement effectively wash its face.

As you will see later on in the economic screening, this alternative provides a win for the government, it provides a win for developers, it provides a win for energy security and energy affordability in a region that very rarely makes the newspapers. But I personally have been up in Derby when there was new LNG trucks coming up from Karratha. And I'll tell you, it got pretty hot.

As I mentioned, those of you that have been on this journey and kudos to you, you want these projects developed in the time frames that we come out and make projections on because cash flow is king. A lot of our peers don't have cash flow. Some of them that have cash flow are still suffering. But coming back to Rafael, we actually have this 100%. The discovery is solid. It has actually been flow tested, but it needs an extended flow test for it to support independent reserve certification. It is a significant structure, but we are not talking about the upside here. But if we wanted to talk about the upside, this is what it looks like.

So based on the Rafael 1 penetration and based on the only zone that we tested, the primary reservoir interval, this produced 7.6 million scfs a day over the flow test duration. Based on that and based on the analysis, that gives us a range of between 85 and 523 Bcf of gas and between that 1.8 and 10.6 barrels of condensate.

There are 2 other targets of interest. There's a secondary reservoir interval, which can provide a potential upside in the Upper T30 Laurel Dolomite, which we carry as prospective resources, not contingent resources like the primary reservoir interval, but also on the back of the 3D seismic survey that we have shot, interpreted and done all the inversion work, et cetera, we now have the Deeper Nullara target, which is approximately 470 meters below the original Rafael T20 Ungani Dolomite.

So are we basing a project on a 2C or 3C? No, we're basing it on the 1C. We're basing it on that high probability case. If we wanted to, we could have started designing facilities on -- for a 2C, 3C, and the Flying Fox that would actually be, I think, too large for the Kimberley.

One of the attractions of this particular project is its size. It's actually the maximum impact, smallest footprint project that we could come up with. And we've had GHD and others actually work on that basis of design to inform our decision, to take and select this option going forward.

We do have Flying Fox. Yes, there is an opportunity to deepen the hall at Rafael B at a small incremental cost to actually give us a potential effectively third well for the development. Our reservoir engineering work shows that this is a base case 2-well development with potentially 3 -- a third well required down the line. This could be a very cost-effective way of ensuring flow in years 8, 9, 10, 11, down the line. And if you look at the size of the prospective resources, it is approximately the same size as the Rafael T20. We do have a high chance of success and the seismic -- the 3D seismic is -- the quality is second to none. Remember, the Rafael 1 well was drilled on 2D, not 3D. We now know a lot more about this structure than we ever did before.

Coming back to the project design. I must admit this is one of the smallest projects I've been involved in my 30 years, but it has potentially the largest impact, local impact, positive impact. As I mentioned, it is based on that high confidence 1C, but it is a very small footprint. And to visualize that, for those of you that remember the pictures we've had of Rafael 1 during the drilling campaign, this will fit on that footprint, which means there's no pipelines required, no material additional clearing required, and it's based on a proven design, a proven design effectively a cookie cutter of an existing plant that exists in Western Australia today, more on that later.

There are many of these global plants in operations. When I was working for other companies, especially 10, 15, 20 years ago, this was an emerging piece of technology. Today, they're run of the mill, and they are designed perfectly for remote applications. There are plenty of them around in Australia, and there's many, many of them around the world.

Our partner, who is a very experienced downstream partner, Clean Energy Fuels Australia, they want to build the biggest plant they can that fits on that well pad because it makes it easier for approvals, it makes it a lot easier with agreement-making with traditional owners. It makes it a lot easier because of the limited clearing that's required and the environmental footprint of the facility. These are very, very simple design plant.

The current plan is that we will be drilling 2 wells in 2026. The first well or the first new well in some time, which we call Rafael B, that will most likely become the primary well for the development. So we will actually drill that well this time with a short horizontal, like a 400-meter horizontal, to really improve the access into the reservoir. We will then go back into the original well, Rafael 1 well, and recomplete that well so that it will be a producer. We will also do a horizontal section on that well. So we will have upwards of 800 meters of exposure into that conventional reservoir. The project itself has a design life of 20 years, and the economics is currently based on 20 years.

Can we do this alone? No, we can't. And so we have spent a lot of time to attract the right partner. Deals take time. Anyone can do a deal, but if you're not spending the right commercial work, you build those right relationships, you get take into the cleaners. And this is a project that has no competition, so we have to make sure that we do a good deal. And that's why we got I Squared or CEFA, Clean Energy Fuels Australia, and we've been working with them for quite some time.

Now a little bit about them. So Clean Energy Fuels Australia is part of the Octa portfolio company. They're a local company. They're not an overnight success. They have spent a lot of time behind the scenes realizing a business opportunity there to provide effectively a virtual pipeline network in the state to provide LNG to remote areas of Australia.

They were acquired by I Squared Capital, which is the world's fifth -- I think, fifth or sixth largest infrastructure fund U.S.-based. And very quietly, have been building an amazing business. Earlier this year, in February this year, they've also acquired EVOL LNG, which is Wesfarmers' LNG distribution arm. So basically, they now have access to the largest fleet of LNG tankers in Australia. They've also have, as part of the Octa portfolio, access to technology and commercial arrangements to build out hybrid solutions that marry gas with renewables or marry thermal with renewables. So they are the perfect partner, and we have a strategic development agreement with them.

And part of that strategic development agreement, we need to do a bunch of things as Buru, and CEFA will do a bunch of things in their own right. Why? Because once we meet some conditions precedent, more on that later, CEFA will bring capital -- will effectively bring 80% of the total installed cost in terms of capital to build, own and operate the downstream facility. And they're already doing that today in other parts of Australia. They're doing that today in a place called Mt Magnet, a bit closer to Perth. And this will effectively be a very similar plant using similar supply chains, so there's a high fidelity of understanding of the CapEx associated with that, the logistics of getting it done, et cetera. But there's up to -- and it's not capped, it will cost what it will cost, but based on our understanding and benchmarks, it could be $150 million investment by a party that wants to build out that virtual pipeline network.

For this agreement with CEFA to become binding, Buru needs to do the upstream work. And what that really means is we need to fund the appraisal of the resource. I Squared is not going to come up with $150 million on the back of a single well and a short flow test. They need certainty of outcome, just like we do. So the key number one condition precedent that we are solving for as a company is that we need upwards of $40 million to drill that second well, Rafael B, to recomplete Rafael 1 to be a producer, and to flow test the structure over an extended period to underpin independent reserve certification. That is the number one challenge that we are solving for.

We are working collaboratively with CEFA on joint marketing. So we will have an arrangement that will allow us I Squared and CEFA to get their return on investment whilst not undermining our ability to share on any upside over certain volume threshold.

So how do you solve for that problem? How do you solve for that problem? If we were a $200 million company, it would have been probably the same problem that we are solving for in this day and age. We are in the Kimberley. We are in oil and gas. We are a micro-cap company sitting on an asset that is in multiples of their internal valuation. But this path has precedent, this path is reasonably well trodden.

Will we have a traditional farming partner? I very much doubt it. The process that we have kicked off some time back, which has attracted some parties and they're still actively engaged in data room activities, demonstrated to us that the best partner, and it will be up to us to work through the options, which will take time, the best option for us is most likely a strategic partnership for the upstream.

Now I'm sure many of you on the call would say, "Well, why wouldn't you just go back and speak with CEFA, see if they would underwrite that check." That's not their business. They don't take upstream risk. We are in the business of upstream. This is a low-risk development drilling program next year from an existing structure that is -- that has flowed, that is well imaged, but that's not the cup of tea for I Squared. So the strategic partnership piece is the number one condition precedent to unlock the funding pathway for us to support final investment decision. Now I will talk a little bit more about that when I get to the schedule as to how that will come together.

I think it's fair to say that the deal with CEFA is very valuable. They are very valuable commercially, but they're very valuable also because they have access to an existing market, they have access to existing molecules from the Dampier to Bunbury Natural Gas Pipeline. They've got a good contact list. So for the first time, perhaps in a long time, Buru's not farming out an exploration play. We're not farming out upstream risk per se. What we are farming out, we're looking for a partner to actually participate in a business. That is very different to where we've been before. And we've done deals left, right and center, some good, some not that good. But they usually take 4 to 6 months. And for that reason, we have issued the placement or we kicked off the placement, launched the placement and that's the reason why we are doing the SPP.

If I look at the schedule, and for those of you that have seen this and are cynical about it, I get it, but you don't live and breathe this every day, right? For us, I can categorically say that, that black bar, which is really a key activity on approvals, is well and truly underway. It's been underway for a long time, but you can't put milestones on as to when you are going to have an agreement with the traditional owners. If we had that, then we just can't create that certainty. It is active, and it has been active for quite some time.

Same with the environmental approvals. We are engaged very actively with regulators. And provided we can demonstrate the low-impact nature of this development. We don't foresee any additional challenges around that.

For us to be able to drill in the operating season in 2026, we really need to be landing that upstream partner between now and Christmas. Why? Because we need some additional materials to support the drilling campaign. We are now doing horizontals that hasn't been contemplated in the past, but that's on the back of some really good reservoir engineering work that supports -- that's the best way to building that certainty of outcome for the [ flue ]. And we need also to secure a rig, and there are a lot more rigs around than there used to be 2, 3 years ago. I'll tell you that now.

As far as the final investment decision is concerned, it will be a joint activity between ourselves, a new upstream partner and our established downstream partner, and we are targeting the second half of 2026.

We are carrying a first gas window based on an assumption that to procure or to final detailed design to procure, to construct and to install a facility, more or less a like-for-like facility to the facility that's at Mt Magnet now will take longer than what it has been delivered. We've actually allowed months in the schedule to allow for the Kimberley factor.

In any case, 2028 is the target, which is coming around very, very quickly. We need funding to maintain that project momentum, and we need funding to maintain the condition precedent with CEFA under their strategic development agreement.

The economics of the project. Look, it's somewhat unusual for a gas-focused company to put out detailed economics on a project. Why? Because remember, this is at the same time as us negotiating with CEFA on the processing tariff. This is at the same time as us speaking with potential offtakers for gas and condensate. This is at the same time as us negotiating agreements with the rightful owners of the country on which we will be developing this project. So we put screening economics in there.

Now remember that number, the $22 a gigajoule, based on a 1C contingent resource, not the 2 or 3C or Flying Fox, based on the 1C contingent resource, based on the flow rate of 14 terajoules a day, which supports a 250 tonne per day of LNG and about 40,000 barrels of condensate a day over a 20-year life, we've taken the mid case of $15. So that $15 for gas and that $1.50 for condensate represents that gross -- on gross terms, $70 million a year cash flow per annum, pretax operating cash flow.

Now of course, you will have to take off whatever the tariff is, the gas processing tariff is that we are currently negotiating with CEFA. But look around the market to get some benchmarks as to what it might be. Of course, you will need to take off a benchmark number to distribute that gas and store that gas, but that's information that we're also flexing.

Of course, there's a cost of bringing a molecule up to the surface. That is the pure upstream lifting cost that we, through these 2 wells, will need to be incurring. But I can tell you now that by the time you start subtracting those numbers from that $70 million, it still leaves quite a bit of a gap between that and what the market is currently paying for. And of course, depending on the deal we make with an upstream partner, there will be further dilution. But there's dilution everywhere in project development whether it's dilution at the shareholder level, whether it's dilution on the asset level, there's no other way of doing it.

Now we do have, as a company, some significant tax losses that we've incurred, which we'll be applying against future profits. So look, our market cap is around -- I haven't checked today, but let's say, round figures, $21 million post the placement and the SPP. So for us and for the new interested investors looking at us quite closely, this is the business that they're investing in, not the business of possibly the 5 bagger that you may or may not realize on the back of a drilling result. We are building certainty of outcome and we're building an annuity stream, which will then earn us the right to grow. It's a very different business to perhaps what we were in 5, 10, 15 years ago.

So what does the value staircase look like? I've just selected some of the main ones, just to give those that haven't been on the journey with us today a bit of an insight. A major derisking event, obviously, once we had an independent review through ERC confirmed that we've got a sizable contingent resource. Yes, we've done some engineering. Yes, we've done some 3D seismic. Yes, we have done some pots and pans pre-FEED work that all helped us select the best concept that will deliver that long-term cash flow at the minimum CapEx. The strategic development agreement, I expected the market to ascribe more value to that than it has.

It takes a lot of shoe leather to get the message out, and that's what we are doing right now. But that was a significant uplift certainly in project value. And it's a current shame, it hasn't been recognized by the market, and we are working very hard to get that rerated.

Clearly, the Flying Fox prospect does give us a higher-for-longer optionality, but we are not prioritizing Flying Fox, we are prioritizing the prudent delivery of the project. If it becomes a no-brainer that deepening that well at Rafael B is the way to go, then that's exactly what we will do, but it won't be just our decision, it will also be the decision of our upstream partner.

Securing that upstream development partner is a rerate. It is a rerate. And it's not without precedent. I don't like to fly other companies' flags. But if you need to see an analog, have a look at [ Invictus ] that happened last week. That's the sort of thing we are working on. I cannot give a market update on how many people we are speaking with, where they're from, what the deal structure is like, I will not do that. But we do have competitive tension that will allow us to build -- secure that partner and to build this project and unlock that project.

The major rerate will, of course, come at final investment decision by which time we will have publicized gas and condensate offtake partners, we would have publicized the final CapEx and schedule associated with the development and would have publicized basically all of the things you would expect a developer or co-develop publicized at the time of making an investment decision.

Our exposure is $40 million. Someone else's exposure is $150 million plus. We are working together with that party to make sure we have good scenario planning to make sure that the respective rates of return are achieved.

The data room we are running, it's a very different type of data room. Traditionally, we would just have rocks. We're not actually talking about the rocks. No one actually cares about the rocks. They care about the business. They care about the market. They care about the economics. It's fundamentally different. This is a commercial data room. And I don't think we've had that, certainly not in the last 3 years I've been here. Usually, you've got all the rock doctors coming through, having a really deep look at the exploration play to see if they want to roll the dice on it. There's no dice on this one. But there's a problem and a challenge that we have to solve for, and we are opening up all of our collective networks to make sure we do not a deal, but a good deal, a good deal.

It is -- there's no better time to do this. If -- Rafael will be developed. My job and the job of the Board is to make sure: a, shareholders get rewarded from that development; b, to make sure that there's a Buru flag somewhere on the mast of one of the cryogenic tanks on site to make sure that we maintain good standing in the community and they understand the value that this small development will do.

The system is outdated. There's no doubt about that. It relies on something that has worked in the past. It's not going to work in the future. And it is changing. Publicly, it's changing. The government has aspirations. There's a lot of politics involved in all of this. Whether we are going to end up as a primary source for some time while the government figures out how to actually increase renewable penetration up there, or whether become firming our economics assumed scenarios. And in those scenarios, we cannot see a future without some thermal generation up in the region.

The time line aligns with the government aspirations. And they did say by the first quarter 2028, we needed solution. Rafael is the solution. We are strongly believing that. Rafael condensate is value accretive in a region where other places, it will be a problem for us. We are very fortunate that there is a market for it. And we will also be able to unlock, hopefully, opportunities for developers who are waiting for an affordable, secure source of reliable thermal power to meet their needs for their minds up there.

Are we doing this alone? No, we can't. As I said it before, we have partnered with CEFA. That has derisked 80% of the CapEx of the project. That has opened us up to a market that is beyond -- it is beyond horizon. There's this misinformation out there that we rely on that contract alone. No, no, it would be lovely to be part of it. But you can't take a final investment decision on the government time line. You'd be silly. We are building out that book, and it has to work without it, right? So we have unlocked CEFA, but we do need to deliver our part of the bargain which is to prove to a very large infrastructure fund and to CEFA and to offtakers, not that the molecules are there, we know it's there, but it will flow the rights we need. Based on Rafael 1, we feel confident that we will -- and that the well design, we feel much more confident that it will be there, and we will be able to support the development of this project.

So I invite you to support the journey. I'm acutely aware of the history. Change has a lot of friction with it. We are a very different company to the one I joined, very, very different. When I came on board, we didn't really have a really good balance sheet. And we were terribly, horribly misled by [ Sabre ]. We've done the due diligence. Our third-party advisers did their due diligence. We were terribly misled by Sabre. That has taken us back. As it did when Origin left for their own strategic reasons.

Since -- especially over the last 1.5 years, we have taken a lot of cost out of the system. When I joined, we had 42 people in this company. Today, we are just over 10. We reduced our footprint in the Canning Basin to focus on Rafael and Rafael lookalikes for potential backfill and market-creation opportunities. Up to 60% of that has been handed back to the government. We've also, with that, reduced the holding costs associated with thousands and thousands of square kilometers of land up there.

Ungani, I get a lot of questions about Ungani. Can you just turn the tap back on? No, I will not turn the tap back on because it is not economic. It is not economic on current terms. I need to renegotiate terms. And with our projected remaining resource of oil, it makes no sense. However, we are in the process of farming out Mars 1, which is about 9 kilometers to the north of Ungani, which could very well up on discovery and it's a high pause prospect. Upon discovery could well and truly underpin a restart. It would underpin financing for storage. It would change the business model of the whole operation.

So coming back to it. This is the journey we are going through. We are going from the top right to the bottom right in terms of the pictures. We are transforming. And it's hard yakka, it is hard yakka because there's an expectation out there that we will be drilling tomorrow, and we will be drilling in 2 weeks' time. And on the back of that, day traders will make a lot of money or lose a lot of money. We are moving into a different thematic. We have institutional investors who are actually saying, "Look, I'm patient because I know what this is potentially going to unlock." There is a clear pathway for that Kimberley-based foundation gas business, and it is a foundation business.

Talking about the opportunity, we did successfully launched a share placement. And that's raised to just over $2 million. That was our target. We could have targeted $5 million. We could have targeted more, but I'm acutely aware of the silent backlash that the company received when we couldn't offer and we couldn't launch an SPP last time. And we couldn't do it because it was illegal to actually launch it within a certain period.

So I spoke with the Board and the Board has resolved to actually change the mix and allow Buru shareholders to participate in that share plan for a larger tranche. The opportunity is there. I think the use of funds is very clear. It's a $5 million use of funds. It does show an issue price discount. I haven't checked today, but I know there's potentially some selling off maybe in protest. But what I think is very attractive in this particular case is for the first time, we are attaching options on a 1-for-2 basis with a $0.03 very realistic strike price and a 2-year expiry.

So that was offered to placement participants, and we are also making that available, of course, to eligible shareholders who subscribe to the SPP. It will be a tradable option. And obviously, the issuance of that option will be subject to your approval or shareholders' approval by an AGM that is being planned.

Now we talk about the use of funds. And I have to be very careful how I say this. There is an incorrect assumption that we keep doing these placements to pay ourselves. That's incorrect. If you look at what it takes to actually get a project FID ready, it takes external work. It needs to make sure that the technical work, the commercial work in assessing and moving this forward is done properly -- to done properly, good oilfield practice properly. This is a gas project. We can't just -- it's a very different proposition to an oil project on -- for spot markets.

There's a lot of work to be done in how we negotiate things. There's payments that we are making for key stakeholders. There's marketing effort that we are doing jointly with CEFA. There's some engineering work that needs to be funded to make sure that the condensate stripping pots and pans work well with the LNG facility. We need to be ready so that when the partner lands, the upstream partner lands, they've got a ready-made drilling plan -- drilling engineering plan that we can deploy. And there's, of course, a lot of commercial work behind the scenes on making sure that we attract the right partner to help fund our appraisal development well.

The working capital is working capital. So that is more what some commentators assigned as management fees and whatnot. Every company needs working capital. We've got 16 years longer of legacy assets that we have to also do something with, maintain. We've got regulatory compliance that we have to deal with. We've got -- being a publicly listed company, we've got a cost and effort associated with that, et cetera. So that's the $5 million that I was referring to, of which $2.1 million has been secured, and it has been secured from some of our top major shareholders -- existing shareholders, but also we were able to attract some professional investors and new blood onto the register who understand what this department could do for Buru in the longer term.

As part of the pack, I'm obliged to highlight the investment risks, and I'll let you read that in your leisure. The team is the team. By the end of this month, you will have seen Mr. Robert Willes would have left, but certainly, he is still an active director until the end of the month.

And this is the mass prospect, I think because it's part of the use of funds to farm it out. This is the range between 0.75 million barrels and 6 million barrels with a mean of -- or best estimate of 2.8 million barrels. Now that's more than what Ungani has produced inception to date, more than what it has produced inception to date if it's successful. And the geological chance of success is 40%. The commercial chance of success is very, very high because the facility, the Ungani facility is the only contemporary piece of oil and gas infrastructure in the Kimberley with some storage and equipment. So that's -- that will be more approaching 90% to 100%.

Now I'm conscious that I have been speaking for 50 minutes. I would just like to answer some questions. I've received some good questions. And I'm also hoping that after this webinar, you will go on to our investor hub and ask some questions on there, and we will respond to them.

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