Orcadian Energy (LSE:ORCA) — Investor Presentation

0:02 Good afternoon, ladies and gentlemen, and welcome to the ORCADIAN ENERGY Investor Presentation. Throughout this presentation, investors will be on listen only mode. Questions are encouraged and can be submitted at any time using the Q and A tab situated on the right hand corner of your screen. Please just simply type in the question and press send. The company may not be in a position to answer every question received during the meeting itself. However, the company review all questions submitted today and publish responses where it's appropriate to do so. These will be available via your Investor Meet company dashboard, and we'll send you an e mail to notify you when they're ready for your review. I'd also like to remind you that this presentation is being recorded.

0:38 I'd now like to hand over, if I may, to Stephen Brown, CEO from ORCADIAN ENERGY. Good morning to you. Good afternoon. Good afternoon, everyone, and welcome to ORCADIAN ENERGY's debut on the investor meet company platform. We're really delighted to be able to have this chance to talk directly to investors and potential investors. I suggest you read the disclaimer another time, and I'll get straight into the story of ORCADIAN. So we started this business in 2014. And when we did that, we set out to get our hands on big discovered oil fields at the lowest cost possible. And the way you do that in The UKCS is by making applications and licensing rounds.

1:27 So we now have four licenses. We've got one on the Outer Moray Firth, with our partners, Parkmeat, but our core area lies in an area known as Western Platform. So it's West of the Central Graben, but it's a 150 kilometers due East of Aberdeen. And we have three licenses in that area. And in our core license, we have the pilot field. And the pilot field has 79,000,000 barrels of two p reserves, which is actually a really significant volume of two p. And, you know, when you're doing offshore oil developments, there's one thing that really matters and it's scale. And with 79,000,000 barrels of two p, we've got sufficient scale to have a really profitable project.

2:18 So it's worth about $8 a barrel, NPV 10 at $60 a barrel oil prices. That's $640,000,000 of NPV 10. And we've actually got great opportunities to build on that scale. So firstly, in existing discoveries and the other licenses in that area, we've got three discoveries, Blakeney, Norville, and Elkie. And there's 78,000,000 barrels of two c contingent resources in those discoveries. And we've also got some fantastic exploration and appraisal opportunities. So not actually mentioned on this slide, we've got about 60,000,000 barrels of two two u prospective resources sitting around Elkie. But also sitting just north of Pilot is the Bowhead prospect.

3:07 And that's our favorite prospect in the area. It's a pilot lookalike with a really good chance of success and 43,000,000 barrels of two u prospective resources in that in that prospect. But Pilot's the core of our base, and it's actually where most of our effort, and where most of the value lies. We are actually quite far advanced in the process of progressing the pilot field to a final investment decision. We submitted a a concept select report originally to the OGA in September 2020. And on the July 1, we submitted an update to that. We mentioned it on our second press release when we listed on Thursday, and we've proposed a modification to our selected concept, which is all designed to reduce emissions per barrel to the lowest possible level.

4:11 And the OGA, I have to say, are very supportive of what we're doing, and they really like the approach we've taken to reducing c o two emissions. I said the company's been around a long time. We really got going in 2019 whenever the Shell traders loaned us a million dollars, and that enabled us to put together the concept select report. And the Shell traders only loaned us that money after a pretty thorough due diligence exercise. So the most important work for us to do is to get this pilot project financed, and that's a big part of the reason why we listed last week. So that's a quick intro to our assets. Let me introduce the team. So we have an excellent team of nonexecutive directors.

4:58 Joe Darby, who's the former Lasmo CEO, is our chairman, and he's a really experienced nonexecutive and a lovely bloke as well, actually. Just gotta say that. Christian Wilms is technically really strong. He's the senior vice president of subsurface and reservoir development at Moel, and he joined Moel fairly recently having spent over twenty years with Shell. And Tim Feather recently joined us. He knows the capital markets really well, having been a qualified executive in the past. So with me today is actually Greg Harding, who's our technical director. He's on the line, and he'll be answering some of your questions later, I'm sure. And he's got a a great subsurface background, and I've actually worked with Greg for years.

5:46 Morris Bumford and Dave Puckett make up the rest of our subsurface team. Morris used to be exploration manager at Talisman and, EnQuest. Dave has been a specialist in EOR for many, many years working with BP and the Oil and Gas Authority. And also with us today is Alan Hume, who's our CFO. There's Alan. He's waving at you. He's, got a background working, with, big contractors, Halliburton, Brown and Root, Rockwater, EMC. But he's also had experience with listed companies on the end market, so it's a great combination. A little bit about myself. So, I started my career in BP. Actually, back in the midst of time, I ran production operations on forties bravo. That's a picture of forties bravo there in the sunset.

6:37 But probably the most relevant activity I did when I was at BP was that I led the pre project team for the Harding development. And that's the team that essentially put the development plan together for the Harding field. And Harding was BP's first viscous oil development in the North Sea. It's actually one of the first viscous oil fields developed in the North Sea after Griffin, and it's been a tremendously successful project. It's produced over 300,000,000 barrels. Harding Central has a 74% recovery factor. And I have to say I'm quite proud of the work I did there. So when you look at the whole team, we've got a lot of experience of North Sea developments. We've got a lot of experience of viscous oil. So I think we've got a great team to take our company forward.

7:25 But we take the company forward in the context of the oil price. And I have the slide up here to show you what how an oil field developer thinks about oil prices. And the first thing you do if you're an oil field developer is you don't well, you do. You do look at the oil price every day, but you shouldn't look at the oil price every day. It's actually the long run oil price and what's happening in the trends in oil price that actually matters. And this this is a chart I've put together just showing how, you know, the oil price and the oil market goes from abundance to scarcity to abundance to scarcity and back again. And, actually, when you look at it, it's often politics that creates scarcity.

8:11 So in the seventies, it was the Arab oil embargo and what followed after that with OPEC, that created a period of scarcity. And in the early two thousands, it was China's entry into GAP and the opening up of the Chinese economy that created a massive growth in oil demand that also created scarcity. But as night follows day, whenever there's scarcity, the oil price goes up. And when the oil price goes up, engineers like me work out how to develop more difficult oil fields. So in the seventies, that was offshore in Alaska. So forties in Prudhoe Bay, to put it in a BP context. In the early two thousands, it was all about shale oil.

8:58 And the cure for, high oil prices is high oil prices. That drives new developments and creates a new period of abundance. But look at the price in those the average price in those periods of abundance. It goes from $25 in the sixties to $35 in the nineties. And since the oil price crash, on 01/01/2015 to now, the oil price has averaged $58 a barrel. So you we think a $60 oil price is a pretty sensible price to plan on. And we actually think we might be in the cusp of another period of scarcity. And this time, we think it's maybe climate politics that will starve capital from the upstream industry that will drive the next period of scarcity.

9:52 So that's our perspective on oil prices. Let me move now to the formal statement of what our licenses have and what the CPR says our licenses have. And, actually, I just want you to focus on one number in this table, which is the 78,800,000 barrels of two p reserves in pilot. You know, we could add up all the other numbers, you know, the two c resources that the commercial two c resources and the technical two c resources and the perspective barrels and some barrels that we didn't get audited, and we could get to a really big number, like 400,000,000 barrels. It's a bit like adding up different currencies. You know? Adding up sterling and dollars and yen, it doesn't make sense. Just focus on the two p. That's where the heart of the value is.

10:45 And what I'm gonna do now is talk you through where we get that 78,800,000 barrels of two p reserves from. So let's start with some geophysics and a bit of geology. Now the pilot field is a deep marine turbidite sand. It's a fantastic quality sand. I'll give you some numbers on that in a moment. And it shows up really brightly on the seismic. So that that seismic in the top right hand side of that panel is a colored inversion display. And where it's bright and blue, that's where the oil is. As it moves into the water, that's gray. And, where it's a that bright cyan color, super bright cyan color, that's gas.

11:31 So, you know, we can see in the seismic where the gas is in the field. We can see in this the seismic where the oil is in the field, and we can see where the water is. So that helps us define the size of the reservoir envelope in pilot really well. And there are a lot of wells drilled on pilot. So it was discovered by FINA in 1989. There's actually been seven reservoir penetrations, five wells with two sidetracks. There's five of those wells cored. Couple of them were tested including actually, in the right on the north of the field, that short horizontal well in the north of the field, that was tested at 1,800 barrels a day. And, you know, that proves that you can get commercial rates out of what turns out to be the most viscous part of the fields.

12:18 The rocks on Pilot are fantastic. They're really excellent reservoir properties. You know, we're talking, 34, 35% porosity, 95% plus net to gross, permeabilities, two to eight Darcys. These are fantastic reservoir rocks. The only thing that ever stopped Pilot from being developed straight after it was discovered was that the oil is a bit viscous. So you have to know how to develop a field that's a bit viscous. But the viscosities aren't terrible. So in the field, in the far south of the field, the viscosity is about a 160 centipoise. That's kind of like olive oil. In the north of the field, it's 600 to maybe 1,200 centipoise. That's kind of like engine oil.

13:04 And we know that engine oil flows at 1,800 barrels a day out of that that part of the reservoir. So we're confident we've got commercial rates here. And Sproul, who are reserve auditors, and I'd I'd say a premier league reserve auditor, have, ascribed 79,000,000 barrels of proven and probable reserves to Pilot. We've got some technical two c resources as well and some perspective resources around pilot, but focus on the 79,000,000 barrels. I talked about, the viscosity of the oil. The solution to the viscosity is polymer flooding. And polymer flooding is a really well proven technique for recovering more oil from viscous reservoirs and it's been around for about forty odd years.

13:53 And you might say, well, why didn't, FINA, when they found out and Total bought FINA, when they've had this field, when Venture had this field, why didn't they think of doing a polymer flood? Well, it used to be that the limit on polymer flooding was considered to be about a 150 centipoise. So if you go back to papers written in the 1998 and specifically, they say that's the limit on which you can polymer flood. But CNRL and other companies, many other companies in in Alberta have been polymer flooding at much, much higher viscosities, five, ten thousand centipoise fields and having great success. So if you read the more recent papers, you know, twenty twenty fifteen or thereabouts, the limit on, polymer flooding is now 5,000 centipoise.

14:42 And that's miles more viscous than the oil we have. So it's actually a fairly recent development in terms of the industry, thinking that polymer flooding would be suitable for pilot. And we've been lucky enough to be the ones holding this license when that development's come along. And it's not just proven in Alberta. It's proven offshore as well. It's actually proven offshore in the North Sea. So, in in '20 2009, Chevron did a trial on the Captain field, and I'll talk about that on the next slide. And they wrote that up and published the paper about how successful that trial on Captain had been in 2018 at the same time as they approved an investment in a polymer flood of the Captain Field. That's gone really well. And earlier this year, Ithaca, who now operate Captain, approved a further £400,000,000 of investment in polymer flooding, another part of the Captain Field.

15:48 So you might be wondering, how does polymer flooding work? How does it improve recovery from a viscous oil field? So I need you to look at these top two pictures. So what what these pictures show is are the oil saturation in a slab of core, which started off with a 100% oil in it, 2,000 centipoise oil. And in the lab, they pumped water into that slab of core. The oil is red. The water's blue. And what you can see is that the water fingers through the oil. And this is after 2.7 pour volumes have been pumped around the slab of core, and there's still loads of oil left behind in the core.

16:42 What they then did is they started to add some polymerized water. So that's water that you've added just a quarter of a percent of polymer to the water, and that thickens the water. It makes it about 25 centipoise. And what happens is that the flood front stabilizes and you get a piston like displacement of the oil out of that out of that core. And if they carried on pumping polymerized water into that core, it would have swept all the oil out of that core. So what polymer does for you, if you inject right from the beginning, which is actually our plan, is it gets you much more oil in much less time. So your field life is much shorter and without you having to handle anything like the level of fluids that you typically have to handle with a a viscous oil field that's developed with water flooding.

17:41 So it's absolutely fantastic for us that Chevron and Ithaca have progressed the polymer flood of the Captain Field because they've cracked the code on how to implement a polymer flood in the offshore setting. They've worked out the logistics, the operational approach, and we can copy all of that. And we can copy virtually everything they do, but there's one thing we're gonna do differently. So on Kapton, they started the polymer flood after twenty odd years of water flooding. Twenty years, you can probably put about three poor volumes around the Kapton Field. And whenever they started polymer flooding, they got a fantastic uplift in their recovery. We can start the polymer flood right from the beginning.

18:29 And CNRL actually have on their website this chart that's in the bottom right hand side of the slide. And what it shows in the blue is the amount of oil that you would get out from a conventional water flood. The yellow is a slab of extra oil you get by polymer flooding. And in the green, it's the incremental recovery if instead of water flooding then polymer flooding, you polymer flood from the start. So we're expecting that polymer flooding pilot from the start will give us a great result. But let me also show you, how that, trial went on the captain field. So this picture here,

19:09 it looks complicated. It's not actually that complicated. On the y on the x axis, it's time. So they started this process in October 2009. And on the, y axis, that's the cumulative amount of oil produced from a well pair. So that's a producer and an injector in the Southern Upper Captain sand. And these were long horizontal wells about a 125 meters apart. So for the first eighteen months or so, they treated it like a water flood. They injected water into the injector. They produced from the producer. And after eighteen months, they'd produced about one and a half million barrels from this, well pattern.

19:54 And Chevron really understand CAPS and they know what the field will behave like. And at that point, they made a forecast, which is this dotted line, about how a water flood would have carried on in the Captain Field.

20:09 But they didn't carry on. What they started to do was to inject polymerized water. And what happened was that the the oil that they expected to produce over the next six or seven years, they produced in one year. And they carried on polymer flooding, and they recovered another roughly one and a half million barrels extra, about 16% extra on the recovery factor, and that's what that green amount is. So they got a significantly increased recovery in a much, much shorter time.

20:48 So what does our development plan look like?

20:51 Well, we've looked at what Chevron did on the Captain fields, and we recognized that one of the key things we had to get right early on was the well spacing. And we've spent a lot of time trying to work out what's the optimum well spacing for pilot. And it turns out the answer is, roughly speaking, about a 150 meters apart in the south of the fields. And in the north of the fields where it's a bit more viscous, about a 100 meters apart. That makes for actually a 32 well development program. That's a lot of wells. But we're in the Central North Sea. We're in 80 meters of water. And, you know, one thing you wouldn't wanna do is have 32 subsea wells. That would be crazy expensive. What you want to do instead is put a little wellhead platform in, about three and a half thousand tons, and you can have 20 slots on that wellhead platform. You can reach all 20 slots from your jackup, and you can knock 20 wells down into that wellhead platform. We plan to have a second wellhead platform in the North as well.

21:58 And all the processing and treatment of the produced fluids and preparation of the injected fluids will happen on an FPSO. That's a floating production storage and offloading vessel. So the bulk of their process equipment sits on the FPSO. All the wells are on the wellhead platforms, and we're also planning to include in our development scheme a floating wind turbine. And I'll come on to, in a moment, why we think that's a really good addition to our development plan. The reason we're adding the floating wind term is all about emissions, and this has become a really important issue for the oil and gas authority. They used to have just one central objective, which was to maximize economic recovery from the North Sea. Today, and it's enshrined in law, they have two central objectives.

22:52 One is, once again, maximizing economic recovery from the North Sea, and the other is to minimize the c o two emissions involved in producing that oil. So they've really set us a challenge to minimize emissions from our development scheme. And, you know, people think that viscous oil is much more difficult to produce and has much higher emissions than light oil. And if you go about it in a conventional way, that's possibly correct. A typical viscous oil emits about 30 kilograms of c o two per barrel of produced oil. And, that figure we're showing as a benchmark is actually based on analyzing environmental statements from a couple of recent viscous oil developments.

23:39 The North Sea average is around about 21. When we looked at a water flood of Pilot, we were coming up with a figure of around about 25. But because we've adopted polymer, we've shortened the field life, we've reduced the fluid handling, that massively reduces the amount of energy we use to produce the field. That reduces our emissions to about 14 and a half kilograms per barrel. But we wanted to do better. So alongside our process engineers, who sit at Crondle Energy, we've torn up our process design. We've torn up our power generation systems. And what we've realized if we we really aggressively manage the process heat, and by that, I mean, rather than just having heat exchangers in our process, we've got heat pumps in our process. You know, not the ones you put in your garden.

24:31 These are big heat pumps, $5,000,000 heat pumps. And, we've switched from a conventional simple cycle gas turbine to gas reciprocating engines, and that changes the efficiency of our power generation system from around about 30% to 49%. Those two things together roughly have our emissions. So we're done at 5.9 kilograms per barrel. And then we found we could do even better because, our whole development scheme was a bit energy deficient. So what do I mean by that? We have some associated gas with our oil, but not that much. And over the life of field, we expected to have to import some gas to power all our systems. So that involved putting in a $50,000,000 gas pipeline and buying a load of gas from the full more gas system.

25:26 Perfectly good plan. What we find by installing a floating wind turbine, we could drop that gas import pipeline, not have to buy gas. And, actually, we've been able to reduce our emissions to 2.6 kilograms of c o two per barrel with no bloody green premium here. We've actually slightly reduced our CapEx, slightly increased our OpEx, but the NPV difference is damsel. So we've done a great job of reducing our emissions, and we've done it without having to pay and throw money away. So where does that put us in a global context? So you've maybe seen press releases recently where other companies are benchmarking against standards and so on and so forth.

26:18 Turns those standards are actually based on this dataset. So this is a Stanford University dataset put together using the OPG EE tool, and we've used that tool alongside Krondal Energy's tool to to work out exactly where our emissions would sit on a global basis. And, typically, emissions run from roughly two grams of c o two equivalent per megajoule. Notice I've just changed units there, up to, well, over 50 grams of c o two per megajoule for some of the worst, schemes where there's lots of flaring of gas or, really high intensity development schemes. We're right at the top or the bottom, whichever way. We've got the lowest emissions. They're in the lowest 5% of global oil production.

27:11 You can't actually produce oil, with a better performance than this. And as I said, we're doing this without it hurting the economics at all. You know, the pilot field's a tremendously profitable project. Its cash breakeven is around about $32 a barrel. In NPV 10 terms, it's around about $39 a barrel. Just for context, since 01/01/2015, the oil price has been more than $39 a barrel, 94% of the time. You know? So if your breakeven's $39 a barrel, you've got a project. At $60 a barrel, Pilot, which are all those green blocks, makes 640,000,000 at 70, which is pretty close to the today's price despite the little coming off yesterday.

28:00 It's it's knocking on the door of $900,000,000 of value. All those additional discoveries, you know, push those numbers up to roughly a billion dollars and $1,400,000,000 of value at sick 60 and $70 respectively, and that's factoring in Spruill's chance of development. So our next step is actually, to secure development partners, and the key development partner we want to bring on board is the FPSO contractor. Because, the structure of your FPSO contract fundamentally defines the equity you need to find to develop the field. So if you can find an FPSO contractor who's willing to share some risk and share some reward, then that significantly reduces the amount of capital you need to find for the development.

28:53 And what we're planning to do is to use Crondle Energy. I mentioned them earlier. They're probably the best FPSO advisers in the world. They know FPSOs better than anyone, and they're going to work with us to first put together a basis of design for the FPSO and a functional specification for the FPSO, and then to approach the FPSO market and see which contractors want to work with us on that project. And that's the first thing we'll do. In parallel with that, we'll look at possibilities for oil companies to farm in, but we'll also look at opportunities for other contractors to participate in the development. You know, we're gonna drill 32 wells on this development, and we're only gonna start with four or five of them.

29:42 So in terms of getting the project off the ground, if we can turn to the likes of Schlumberger Halliburton or Baker Hughes and a drilling contractor and say, you know, help us with the financing of the first tranche of wells, and you're locked in as a contractor for the other, 28 or so, then that'll be an interesting conversation for us to have with them. And, you know, equity can come from two sources. It can come from the industry through a farm out or it can come through a fundraising. And what we'll do is we'll choose the approach that maximizes value for shareholders. And you can count on that because the management team in ORCADIAN own about two thirds of the shares in this company. So we're averse to dilution. We don't we dilute very reluctantly.

30:30 And we'll look at dilution at the asset level and dilution at shareholder level as almost identical. So we'll be certain to get the best deal possible for shareholders. So that's a story on, the value of Pilot and a bit of a history. What does the production profile look like? So after a year or so, we expect to be producing about 30,000 barrels a day. Those initial batch of wells will be

31:00 able to come on stream at about 20,000 barrels a day, but they decline pretty quickly. So you gotta keep drilling all the way through. We'll have a drilling program that runs for roughly four years or so, and that keeps us on plateau. And then, actually, with polymer flooding, the field life's pretty short. It's all over after eleven years.

31:20 That leaves space for the Elke, Norwell, and Blakeney projects to come in. But if we were successful in drilling up, the Bowhead prospect, and I'm gonna tell you a bit more about that now, we'd probably aim to increase the capacity of the FPSO to about 50,000 barrels a day that we could maximize the value of that discovery. So let me tell you a little bit more about Bowhead. So Bowhead's a pilot look alike that sits just on the northern side of a salt swell

31:51 from pilot. It shows up really brightly on the top reservoir far stack amplitudes. That's the display on the left hand side. It does not show up so brightly on the near, far stack near stack amplitudes. And what's interesting by comparing those two displays, it's the difference between those displays that's telling you something about the fluid contact fluid content. So if you look at pilot, it hardly shows up on the nears except for the gas cap. There's a little gas cap here. That shows up quite brightly. And Phew, that has a gas cap. That shows up really brightly. And Bowhead looks for all the world a duplicate of Pilot on the nears.

32:38 And when you go to the forest, both Bowhead and Pilot shine really brightly. Phew shows up even more brightly. But suddenly, out of nowhere, it's not in the nears at all, blatantly shows up. And that's an one of our discoveries. So that's a clue about how the seismic can tell you something about fluid fill. So we've got a new dataset of seismic. We got it just last week. We're about to start work next week interpreting that, and that new seismic is newly relatively newly shot, but really recently, newly reprocessed. No one's ever interpreted it across Pilot, Blakeney, or Bowhead, and we have that seismic now.

33:24 We're going to work on that. And in two or three months time, we hope to be able to take a drilling decision on the Bowhead prospect. It's 49% chance of success, based on the current seismic and 43,000,000 barrels of prospective resources. And our funding strategy is flexible. We're very happy to farm out the industry. And as long as our share price is at the right place, we'd be happy to raise money, to drill, that well. And it's not a terribly expensive well. Petrofac estimated the well cost is about 8,000,000. So let me just start to summarize our story. What's our strategy going forward? Well, it's to deliver a high return for investors. Remember, we own two thirds of this company. It's all about delivering a high return for the investors, and we'll do that when we fully finance the polymer flood project for Pilot.

34:20 We'll look for all companies as farm and partners. We'll look to structure our contractor alliance. We'll look at multiple options to develop this field, and we look to add value to that by drilling up great exploration prospects like Bowhead and by maturing the development plans for our contingent resources in Blakeney, Elkie, and Narwhal. And that's what we think will deliver a return. So just looking forward, what's the near term news flow? Well, I said we submitted a con concept select addendum to the OGA in the July 1. You know, government moves slowly and in mysterious ways, but we expect to see in due course, I won't be any more specific than that, a letter of no objection to our selected concept.

35:09 And with that, we'll be able to approach the market. We'll be able to go out to the FPSO market, and the oil companies looking at the farming potential, the FPSO contractors looking at the development potential will know that the OGA supports our plans. We'll work up, the seismic and bowhead. We'll make a commitment to drill a bowhead exploration well, and then we'll see how we finance that. We won't be getting into all the work that you do to fully finance the, fully document the field development plan. You know, there's an absolute alphabet soup of documents you gotta put together for that, but there's no point doing that until you know who the operator is. If we formed out to another company, it's for them to pull together their supply chain action plan, their project execution plan, so on and so forth.

36:05 So we're very cautious about spending money. Actually, you know, putting together our concept select report, we spent a total of eight thousand one hundred man hours to do that, both the concept select report and the addendum. So we're very parsimonious. That's our style. And, I'm gonna finish on a couple of slides. One is just to try and put us in context with some other listed companies. So I'm just gonna give you some facts here, and then it's kinda up to you to make up your mind about what those facts imply. What I've done here is I've looked at companies that I think are comparable. So first of all, that means they're nonproducing companies. You know? You can't compare two p reserves from a producing company with two p reserves where you haven't even started spending money on the development project. That's disingenuous to do that. You need to look at companies that are nonproducing, and you need ones that have reasonably clear statements about what their resource base is. So the companies I've looked at are Longboat, Advanced, Imperium, Delta, Saphir, Chariot, Jersey, Rockhopper, Boliv, and Providence.

37:15 And each of those has some sort of statement about what their resource base is. And the numbers I've added up, and I recognize these are really actually different currencies, but so what are their two p? And funny enough, you'll see that pretty much we're the only company with a significant volume of two p, but whatever. The two c, even though that's contingent in some way. And then I haven't ignored the prospects. What I've done for the prospects, I've said, well, you need to look at the risk volume, and you can only really count the prospects for the exploration wells being funded. So that's why we've got, some resources in for longboat and Delta. Anyway, when I do that, I come up with a number, which is their resource, and I divide that into their market cap.

38:06 Maybe I should do enterprise value. Well, you know, it's been my experience. The oil companies raise cash and then they spend it. So let's just look at the market cap. And all those red dots show you the range of values per barrel, the London markets putting on resources. And it's kind of up to the market to decide where we sit. But I'll tell you this. I wouldn't swap a barrel of pilot oil for a barrel of anyone else's resources. So why and create ORCADIAN? Here's the reason to invest in ORCADIAN. We've got a really substantial reserve base with significant e and a upside. That's, and a project that's really well advanced. Number two, we've got a clear plan of how we're gonna get the project financed, and there's multiple ways of achieving that goal.

38:56 Number three, you're backing a management team that's got a very big stake in the success of this business. And finally, we're swimming with the tide on the emissions question. We've absolutely transformed our project into an example of how best to minimize emissions while maximizing economic resources. So I hope you find this interesting, and now I'll hand back to Mark. That's great, Steven. Thank you very much indeed for updating investors this afternoon. Actually, just before I go, I didn't submit the poll earlier. So please, if I may, if I could just submit that poll and if you would be so kind as to give you that give that your kind attention, I'm sure the company would be most grateful. Ladies and gentlemen, please do continue to submit your questions using the Q and A tab situated on the right hand corner of your screen. I just want the company to take a few moments to review questions submitted already.

39:45 I'd like to remind you that the recording of this presentation, along with a copy of the slides and the published Q and A, will be accessible via your Investor Meet company dashboard. I'd also like to remind you that your feedback is important to the company. And immediately after the presentation has ended, you'll be redirected for the opportunity to provide feedback in order that the company can better understand your views and expectations. Stephen, obviously, had the ability to submit presubmit questions, and there's some questions that are coming in the live event. So perhaps I can hand back to you now. If I could just ask you to read out the questions and give a response where it's appropriate to do so, that'd be great. Yeah. Let me just stop sharing, and perhaps Alan and Greg could turn on their cameras, and you can maybe see a few more of the management team.

40:33 I'm gonna do is I'll I'll start with the presubmitted questions because I kind of worked out who's gonna answer them. And the first question was regarding that funding from Shell Trading. So the question was funding from Shell Trading, what form did this take, and does it create a liability? Alan, could I ask you to answer that? Yeah. Sure. So we we borrowed a million dollars from Shell trading in 2019 at LIBOR plus a modest interest a modest percentage above that four year term, and shall get trading marketing rights, sorry, on some of the first barrels produced from pilot. Very good. And the interest rolls up. Yeah.

41:19 The second question is about oil viscosity. As how does this compare to Harding, Alba, Griffin, Kraken, Mariner, and Captain? A 159 centipoise to 900 centipoise, so that was almost an old slide of ours. Does this create any issue? Greg? So the the list there of the viscous oil fields that they're already producing or under development in the North Sea, and their viscosities ranged from sort of five to 10 centipoise for the first three in that list, the oldest field, up to around 500 centipoise for the top part of the in one of the two reservoirs in in Mariner. Our most reliable sample is about 400 centipoise, and our range is is you know, what you've got there is for around a 160 to to 1,200.

42:11 So we don't see an issue here. Much of the field is within the range of viscosities already being developed and the full range of our viscosities is is within the scope of successful polymer developments onshore in Canada as Steve mentioned earlier. And to give us extra confidence our reserves ordered to Sproul as a Canadian company. They're very familiar with the success of these polymer projects in in Canada. So, you know, their audit of our reserves, I think, is is valuable. Very good. Okay.

42:56 The next question is about sulfur content and also c o two. So it says sulfur and c o two is the field high low sulfur and high low c o two. Would this secure a Brent premium? So let me separate that those two. Really, we talk quite a bit about the c o two emissions in in the presentation, so I won't go over that again. We've managed to make those emissions really, really low. If the if the question was about c o two content, there's no c o two in our associated gas, so that's that's not actually an issue. Let me move on to sulfur. So sulfur content and you may have seen a a little release we did this morning, because we realized that some of the questions we were gonna answer, we hadn't made publicly available the answer to the to those questions.

43:45 Sulfur content's point 7%. That's identical to Kraken. So, in fact, our oil is very, very similar to Kraken. It's roughly the same town number, same API gravity, same same sulfur content. And if you follow EnQuest's news releases, they they've been saying they've actually been able to secure a premium to Brent for cracking cargoes. In our CPR, we just assume we're selling at Brent prices, but low it's not strictly speaking low sulfur because low the transition is at point 5%, but it's a pretty low sulfur crude. And pretty low sulfur heavy crude has been getting very good prices. The next question is about wells.

44:33 So the question is what's the basis of the well costs? What sort of rig are you gonna use? How many days is it gonna take to drill? Has Petrofac got a turnkey contract and how far along are rig spread contract negotiations? And is there a provisional spud debt? One of the things I've noticed is people go in for a lot of bonus questions here in these pre submitted questions. So I think I've got five to answer. So drilled and completed, our well cost is actually $212,800,000, roughly 13,000,000. That's based on a a harsh environment jackup. Typical specification would be a CJ 50. Merce drilling happens to a lot of those just in passing. And if you go to the Basso offshore, analytics search section, they say premium harsh environment rigs are getting $90,000 a day, and vintage harsh environment rigs are getting $75,000 today. Our 13,000,000 well cost is based on $85,000 a day. It only takes forty five and a half days to drill and complete one of these wells. So, you know, you're saying that's not much. It isn't much, but the reservoir's only 2,700 feet deep.

45:47 And and and exploration well drilled on our block, 2127 B 7, that was drilled in eighteen point four days. So you can knock these wells down pretty quickly. We haven't specifically gone out to secure a rig, But as in parallel with our FPSO negotiations, we're intending to approach rig contractors and, you know, the, the likes of Schlumberger, Halliburton, Baker Hughes to see if they want to participate in a Wells Alliance for Pilot. So the next question is, what recovery factor be expected from a polymer flood from day one? Would it be more than 28%? So I'll ask Greg to answer that. Okay. So as you know from the presentation, our plan is to implement Polymer from day one. And, yes, we would expect to see a better recovery factor than 28%.

46:42 I think the 28% comes from that chart from Pelican Lake in in Canada, and and that relates to an oil with a viscosity in order of magnitude or more large greater than pivert. So after review of our technical work, Spruell settled on a recovery factor of 40% for 2P reserves in the our developed area, which I think is a comparable basis to the 28%. Very good. Thanks, Greg. The next question is what's the impact on OpEx of polymer flooding? What sort of volumes are required, and what does this add to OpEx? Is it similar to water injection volumes, or is it a direct displacement of oil? So let me try and try and answer that.

47:32 Our regular field OpEx is about eight pounds per barrel, and the cost of polymer adds between two and a half, three pounds per barrel to that. And the way it works is you add roughly between well, if the water is low salinity, you add about 900 parts per million of polymer to the water, and we're planning to have a 63,000 barrel a day low salinity water plant. And the reason for that is because, it saves us so much money on polymer. Because if the water has a high salt content, you have to add about 2,500 parts per million of polymer.

48:18 So we're gonna start off injecting low salinity water, but all the produced water is going to be reinjected back into the reservoir. And, actually, that's a really good point there. We plan to reinject every drop of water that comes out of the field. And one of the reasons for that is to make sure that none of the polymer gets into the sea. Now the polymer isn't actually considered to be terribly environmentally damaging. It's used in water treatment plants and so on, but it's much better to be careful with things like that. So we'll have we'll start with low salinity water, our total water injection capacity is around about a 169,000 barrels a day. And I think that's answered the question. So the next question is, will you batch drill?

49:04 Are there any plans here for early production, production from Drill Center 1, Drill Center 2, or is it all 30 wells then into production? Well, it's not that. It's we'll start with four or five wells from the first drill center, then we'll complete all the drilling at that drill center, then we'll install the second wellhead platform and move the jackup rig to that, and then add the rest of the wells. And that actually does give us an element of early production from our scheme because we can start the development with the FPSO, the infield flow lines, and the mooring on a well one wellhead platform and four or five wells. And then we have cash flow that funds the rest of the wells and the second wellhead platform.

49:50 The next question is, does the polymer require heating prior to injection? Is it injected raw or with water? And I'll ask Greg to answer that. Okay. So there's no heating required, the polymer is a dilute dilute solution in the injection water. I mean, Steve's mentioned it's it's up to sort of 2,000 PPM, not not a great quantity. So you can really consider this as an additive to conventional water flood. Yeah. Great. So the next question is one of these multi question questions. So what I'll do with this one is I'll actually step through them one at a time. So development partners with cognizance of fully financed with the minimum dilution, what terms would you consider?

50:39 The best terms. Those are the ones we'd consider. I'm not gonna say exactly which terms we'd consider. We want to have a competitive process. We wanna get the best offer from the industry. I don't think it's appropriate for me to say what terms we'd consider. Would you offer a share in the fields to contractors? Yeah. Definitely. Absolutely. If it if it that's what it took to get the FPSO, provider to fully finance the FPSO, we definitely offer a share in the field to the to the contractor. Would we consider a free carry for ORCADIAN in return for a bigger share to another large operator? Absolutely. That's a good way to do a deal. You know, that's a classic development forming approach where the big company comes in, funds all the upfront capital, and the smaller company keeps an interest, but they don't have to find the capital.

51:39 Would early let me ask this question just as it's written. Early stage production funding to allow for self funding to an extent? Yes. I mean, that's sort of what we're doing already by deferring the second wellhead platform and the bulk of the wells. We think we found the sweet spot for the development with that arrangement. The next question, is bond financing a consideration? Definitely. Independent Oil and Gas did that very successfully for their Southern North Sea development, placing a bond in the is the Nordic bonds, the classic market for oil companies to go to. We think that could be a really good option. And the next question, I mean, thank god you've asked it.

52:25 Dilution of early shareholders is always a concern for private investors and is one of many reasons why there is skepticism of small cap oilies. How would you aim to preserve shareholder value in the pursuit of financing? This is a great question. I am so averse to dilution. You would not believe it. You would not believe it. I'll do anything to avoid dilution. So but sometimes you have to dilute to take the next step, and it's all about making sure you minimize that dilution and what you're doing is adding value. Let's take the bullhead well as an example. So today, our market caps $2,526,000,000 quid. If we're trying to finance an £8,000,000, well, maybe we'd have to do a £10,000,000 raise. Would we do a £10,000,000 raise to drill a fantastic, brilliant, bowhead prospect on a market cap of 26,000,000?

53:23 Would we insert your preferred expletive at that point? We wouldn't. We'll only dilute to do something that adds value to shareholders. Sorry. I'm got a bit passionate there. So next question, Tim. The power generation solution, would you ever install your own turbines? The largest are around about 10 megawatts. Well, actually, what we plan to do, is we've been talking to a a floating wind company called Floating, Power Plant. And they have a really great solution where they have a semi sub, foundation, and built into that foundation is a couple of megawatts of wave power.

54:09 You may as well put it in once you've got the platform there, and they're planning to put a 12 megawatt wind turbine on that. The largest certified at the minute is 13 megawatts by 2022. We think maybe a 15 megawatt one would be certified. And the key with offshore wind is actually to go for the biggest turbine you can. So, floating power plants have made a proposal to us, an outline proposal. We haven't got into contractual terms yet, but to lease us that wind turbine for the field life. And we think that's the best commercial structure. The next part of the question is, can the proposed reciprocating gas engines deliver a 100% of par in event of turbine failure or adverse weather? Well, of course, actually, you know, that's the thing about wind. The wind doesn't always blow. Today, it's completely still here in Serbenton.

55:03 I think it's probably completely still in the Central North Sea. And on a day like today, you'd get nothing from your wind part. But we're really lucky on pilot because we have a small gas cap in the east of the field, and we can use that as a place to put our associated gas when the wind blows. And we can draw down on that when the wind's not blowing and we need to generate power using our reciprocating gas engines. And they'll be sized for a 100 or maybe a 150% of our, power requirements. What is the CapEx of a wind turbine? You'll note that in the press release this morning. Fifty to fifty five million pounds was the the number that FPP were happy for me to say in response to that question.

55:51 Can you strike a deal with the wind farm operator for exclusive access to power required? That's exactly what we do. We'd actually make this an integral part of our development, and it would come under the OGA's regime rather than having to include Scott Wind and Crown Estate and all those other bodies. Is the heating process energy intensive? I've added a word to the question to try and make sense of it. The the way we're going to add process heat is either with waste heat from the the reciprocating gas engines or with a heat pump, and it does add a fair bit to our energy demand. And the last part of this question is how much power does the FPSO and the well hub platforms need? 30 to 40 megawatts. Well, actually, the answer is 18 megawatts.

56:38 So, we worked that through. Next question, does do the NPV calculations assume both in wind power? What price are you using per megawatt hour? The NPV calculations assume that we're leasing the wind turbine. If you divide the amount of electricity versus the cost of the lease, it's coming out around about £80 per megawatt hour, roughly speaking. Question 12, what's the development timeline? Well, the key thing for us is to get the project financed, and I'm not gonna speculate about how long that takes. This is something that could come together very quickly, or it could take quite some time to put together the complex deals that you need. So let's say that takes as long as a piece of string.

57:24 Once we've reached the end of that piece of string and we got the project financed, it's, you know, a two to three year project. In the CPR, we assume a thirty month project. And then the final question from the pre submitted questions is how far have FPSO talks progressed? Well, we have actually had some preliminary conversations with FPSO operators, but we're now about to go into a huddle with Crondle, work up, the basis of design, this functional specification so we can actually approach the FPSO market formally with a pretty clear request about what what we require from the market. And, actually, to include some of these key things around heat pumps and gas reciprocating engines for power generation, we have to specify that. Otherwise, the market won't come back to us with those proposals.

58:17 So what I'm about to do now is get to the questions that have been asked here. So the first bit's a compliment. That's great. I like compliments. That's so great presentation. How well funded are you for your development plan? And what do you feel is the greatest risk to your plan? Well, we didn't raise very much money at the, at the IPO. We raised £3,000,000. That doesn't take you terribly far, but it takes us as far as we intend to go in this phase. It lets us interpret that bowhead seismic. It lets us put together the FPSO package. And, really, the development plan is not funded. That's the job that we're gonna work on for the next few months.

59:04 And to be perfectly honest, what's the greatest risk to our plan? It's securing that finance. This is a great project. It's great reservoir. The Polymers, approach is well proven. We're not in deep water. We're not in a complicated development scheme. This is actually all pretty simple stuff, but pulling the finance together is actually number one on our list of risks. And that that question was from Simon c. And I've, another one of these multi question questions from so that you first one is, my understanding is, the pilot field is heavy oil, 12 to 16 API. That's correct.

59:50 Are there any resemblances or correlation to the Bentley field, excite energy? So Bentley is around about 1,500 centipoise. It's it's actually, more viscous than even our most viscous oil. But what's the biggest and most significant difference between Pilot and Bentley is that the Bentley oil sits as a pretty thin oil column, not that thin, actually, but a reasonably thin oil column on top of a massive aquifer. And when you put the wells into Bentley, that aquifer comes up into the the production wells. On pilot, our our field is a is a kind of a wedge shape, and then there's only about half of the field that's underlaying by any water.

1:00:37 And most of the field has only about, has a small aquifer in beneath it. That makes a tremendous difference to how you go about implementing a polymer flood. So our field has exactly the right reservoir geometry for a polymer flood. Second, how much capital is ORCADIAN looking for for the field development? Well, roughly speaking, it takes about a billion dollars to get to first oil, but 600,000,000 of that is the FPSO. And if we can strike the right deal with the FPSO provider such that they're the ones bringing the capital to create that FPSO, then that massively reduces the amount of capital we have to find. Then there's opportunities to reduce some of that capital. That's split into roughly three three blocks.

1:01:27 There's about a third of that, which is, the first batch of wells. There's a third of it, which is that's not quite true. It's a smaller number. But the there's another chunk which is, the, mooring and the infield flow lines, and the other chunk is the wellhead platform. So, actually, you can shrink the amount of capital we need to find. In terms of finding that capital, we have proven reserves on pilot. Now that's the first part of the two p. So the two p is 78.8, and the proven, I think, is 56.8. Greg, correct me if I'm wrong, but, so if you could double check that. But, that's a pretty substantial volume of proven reserves, and that's the reserves that the bankers look like look look at. And on Spruill's forecast oil prices, which is $53.54 dollars a barrel, that makes a 16 and a half percent pretax return. So that's a robust project from a banker's perspective.

1:02:31 So we'll be able to get some lending against that. And then the balance is the equity you need to find. So and the equity can either come from the market or it can come from an oil company. We're kind of neutral on that. Was I far off, Greg? Sorry. You're muted. Sorry. I'm muted. 584. Sorry. 584. I I understated it. Thank you. Thanks for looking that up. Question three from Sadat. As mentioned in the slide, that field was first discovered in 1989 followed by seven appraisal wells. Which company drilled that well, and why didn't they develop the field? So the original company that discovered Pilot and drilled most of the wells was FINA, which used to be the Belgian state oil company, Petrofina.

1:03:18 They were taken over by Total. And not long after they'd done the the horizontal well test on pilot, Totalfina looked at this asset, and as often the case, they looked at the kind of peripheral assets from, the company they've taken over and they sold it. So they sold that comp, field to Venture. You remember Venture Production? And Venture Production, well, god bless them, they were optimists. So they had a really elegant geochemical model of pilot, and that predicted that in the middle of the field, they'd find 100 centipoise oil. So they had a they actually put together a fully fledged development plan. They had a letter of intent for an FPSO, and they thought they'd just better go and check their geochemical model.

1:04:09 The plan they'd put together was not well intensive. So they planned four wells in total. We're planning 32. And they were gonna be subsea wells tied back to an FPSO. That sort of plan just won't work with much more viscous oil. They went and tested their geochemical model and found 400 centipoise oil, and their development plan didn't work. At that point, they relinquished it. EnQuest then picked it up, and they looked at it as a carbon copy of the Kraken development, so as an FPSO and subsea wells. And if you go with subsea wells, what happens when you're optimizing your well spacing is that spacing gets wider and wider Because subsea wells cost twice as much of platform wells.

1:04:55 And they widened the well spacing and to the point where they weren't predicting a good enough recovery, and they, decided that they wouldn't go ahead with that, relinquished it, which was fantastic because that meant Pilot was an open acreage, and we could apply for it. And we were lucky enough to have the field when all this news about how polymer flooding can actually be applied to much more viscous oils, up to 5,000 centipoise, 10,000 centipoise was coming into the market when Chevron were publishing the results of their polymer flood, and we were able to bring that together and come up with what is actually, I'll say it myself, a brilliant development plan for Pilot. Question four from Sadat. Since the company is moving towards alternative energy sources, which may suggest demand of oil might drop in the future, how risky is this for ORCADIAN in terms of oil prices or to entrap potential investors and partners?

1:05:56 Well, I don't think there's any inconsistency between us trying to develop pilot in the most environmentally friendly way possible and minimizing use of fossil fuels in our development scheme and needing to continue to supply oil to the global oil market. And that's a global oil market we're talking about here. You know, the IEA forecast that we don't need to do any more, oil and gas projects in their net zero, forecast. The Saudi petroleum minister described that as a sequel to La La Land. It's just not the case that oil and gas demand is going to drop precipitously.

1:06:43 The world needs low cost, reliable energy, and that's how you lift people out of poverty. So we don't think there's a big risk to that. If anything, all these climate politics are going to result in, decline in supply against this continuing demand. And I think, the upside for oil prices is huge, and the risk of downside is pretty low. And then a final question from Simon c. Thank you, Simon. Do you think the free float's an issue? Park Mead has a similar problem with Tom Cross being a large holder, and often the share price is affected by very small trades, meaning the share price remains always undervalued.

1:07:30 It's true we won't have a big free float. That's just a characteristic of the management team owning a big chunk of the business. That's the two go together. I think, maybe the issue is how communicative you are with the market and how much you promote the company in the market. It's absolutely their intention to be out there talking to people on a regular basis and building up retail interest in the stock that is available to trade. You know? The free float can work two ways. You know? One way might be that there aren't very many trades and that the share prices remains undervalued.

1:08:16 The other could be that there's not a lot of stock out there, and it gets pretty hard to buy it whenever you're looking to buy some. So it can work both ways. I think what matters is actually talking to the investors as much as possible and making sure that you're there's a good news flow and that there's a good engagement to retail investors. And then, Simon, thank you very much for that. Very knowledgeable. Great update. Thank you. Stephen, I might just jump in because you've been incredibly generous with your time, and you've addressed every question that's come in both ahead of the event and during the event. So thank you very much indeed to all the investors that have taken time to submit the questions today.

1:09:01 Stephen, just perhaps before I divert investors to provide you feedback, which I know is important to the company, perhaps I could just ask you for a few closing comments, and then I'll redirect them. My closing comments? Sorry. I'm exhausted. So let me go back to my previous closing comments. So the key thing is we have 79,000,000 barrels of 2P. You won't find that anywhere else on the EM market. You won't find this volume of two p. We've got a really well advanced project. There's a lot of value in it. In time, the market will recognize that value. I'm confident. And you're backing a management team that's got a big stake in the business.

1:09:49 We're gonna try and maximize the value to us and to you. Thank you very much for listening. I'm sorry for going over time. Don't don't be so silly. Greg, Alan, Steven, thank you so much for updating investors this afternoon. Could I please ask investors not to close this session as you'll now be automatically redirected for the opportunity to provide your feedback in order that the management team can really better understand your views and expectations. This will only take a few moments to complete, but I'm sure will be greatly valued by the company. On behalf of the management team of ORCADIAN ENERGY, I'd like to thank you for attending this afternoon's presentation. That now concludes today's session, and good afternoon to you all.