Panoro Energy ASA

OSE:PEN

Earnings Call Transcript 2019-Q4

[Operator]

Hello, and welcome to the Panoro Energy Fourth Quarter 2019 Results Call. My name is Courtney, and I'll be your coordinator for today's event. Please note that this call is being recorded. [Operator Instructions] And I will now hand you over to your host, John Hamilton, to begin today's conference. Thank you.

[John Andrew Hamilton, Chief Executive Officer]

Thank you, Courtney, and good morning, everyone. Thank you for participating in our 2019 Annual Results Conference Call. This is John Hamilton, Chief Executive Officer of Panoro Energy. For your reference, our results announcement was released this morning, and the full report is available, together with the presentation that we're giving today, on our website at www.panoroenergy.com. We're going to take you through some slides now. And if I'd like -- if I could, I'd ask you to turn now to Slide 3, which is called Presenting Team on the Webcast. I would like to introduce the participants today. We have Qazi Qadeer, our Chief Financial Officer. We have Richard Morton, our Technical Director; and Nigel McKim, our Projects Director, each of whom will be contributing to the presentation today. As a reminder, today's conference call contains certain statements that are or may be deemed to be forward-looking statements, which include all statements other than statements of historical fact. Forward-looking statements involve making certain assumptions based on the company's experience and perception of historical trends, current conditions, expected future development and other factors that we believe are appropriate under the circumstances. Although we believe that the expectations reflected in these forward-looking statements are reasonable, actual events or results may differ materially from those projected or implied in such forward-looking statements due to known or unknown risks, uncertainties and other factors. I would now like to go to the next slide entitled Corporate Highlights, Slide #4, where we have an overview of some of the things we're going to be talking about in a little bit more detail. On the financial side, we recorded full year revenue -- record full year revenue and record EBITDA since 2013. So the company is in good health financially. We closed out the year with a cash position of about $30 million, including the deposit we've held for the Salloum drilling, and gross debt of $25 million. On the operational front, we produced approximately 2,400 barrels of oil per day. It's important to note that the financials that we've just discussed do not include the contribution from Aje, our Nigerian operations. Those have been held as now a discontinued operation. So they've been withheld from the headline financial statements. It doesn't impact the overall conclusions, but it can affect some of the metrics that you see. I need to point that out upfront. We are poised in Gabon and Tunisia for 2020 production growth. We also, during the course of the year, had the transformational discovery at Hibiscus in Gabon. On the strategy side, we have, today, announced also our dividend strategy, articulated that a little bit more clearly. We also have the PetroNor dividend, which we'll talk a little bit more about coming up. And we have also stated our strategy being to balance a growth business together with shareholder distributions. On the outlook, we're anticipating a big production growth during the course of the year. Our guidance is somewhere around 50% higher than it was in 2019. We have as many as 5 exploration wells to be drilled during the course of the year. So we have lots of exploration excitement as well, we believe. And we also have some new ventures that we're looking at, including the transaction that we announced yesterday in South Africa, which we'll tell you a little bit more about. Next slide, please, Slide #5, shareholder distributions. We'd like to talk about 2 things here. The first is being that it is our intention to distribute the PetroNor shares that we received as part of the sale of Aje, which has been well disclosed. For those of you who follow us, we will receive PetroNor shares upon completion of this transaction, which should be sometime perhaps in the third quarter of this year. And as a special dividend, we intend to distribute that to our shareholders. In the second column on the right, we are articulating now a shareholder return strategy, which is that we intend to distribute up to 50% of net profit in the form of dividend payments or share buybacks or perhaps a combination once Ruche Phase 1 production is online. That is scheduled to come online at the end of 2021. And at that point, the company will be generating huge amounts of post-tax operating cash flow, and it is our intention to take into account, obviously, macro circumstances at actual financial and operational performance. But based on what we see now, we have the full intention to distribute up to 50% of net profits to our shareholders in the form of a dividend or share buybacks. If you could please turn now to Slide #6, which is a quick little update on our farm-in to Block 2B South Africa. Richard will take you into a little bit more detail about the asset. But yesterday, we announced an entry into South Africa on the exploration front, where we signed a farm-out agreement with Africa Energy Corp., which is part of the Lundin Group of Companies, for Panoro to take a 12.5% interest in Block 2B, which is located in the Orange Basin, offshore the west coast of South Africa. This is a very exciting oil play. Richard, again, will tell you a little bit more about it, but there is an existing discovery on the block. And since that discovery was drilled more than 30 years ago, modern 3D seismic has been acquired on the block, which shows that if we come up-dip from that discovery, we have a good chance of finding material oil resources. That well is going to be targeting up to 350 million barrels of oil on a gross unrisked prospective resource basis. Again, we'll tell you a little bit more about that. That deal should close, hopefully, in something like 6 months. It's subject to the consent of the minister in South Africa and the other farm-in agreement that they've signed with Azinam Limited also becoming effective. What I'd like to do now is turn to Slide #7 and turn it over to Qazi Qadeer, who will briefly take you through some of the 2019 financial results. Qazi, can I turn over to you on Slide 7 now, please?

[Qazi Qadeer, Chief Financial Officer]

Thank you very much, John, and good morning, everyone. On Slide 7, we have a summary of headline results for 2019 and the fourth quarter. It is customary to note here that the results presented here and discussed on this call are unaudited. Before I go into the details of the numbers, it is again important to note here that we have made some presentational changes this quarter in order to comply with the reporting standards where we have isolated operations from Aje, related transactions in the P&L as a separate line item, which is discontinued operations. And equally, in the balance sheet, we have classified Aje-related assets and liabilities as held for sale. Details of what these items can be found on Note 5 in our quarterly report, which we have published this morning. The result of isolating Aje operations in the discontinued line has resulted in restatement and rearrangement of comparative information as well in order to have a like-for-like comparison. So you would see that you wouldn't recognize necessarily the numbers we have published in the third quarter in the P&L. There is no underlying change in numbers on a net basis. It's just a presentational situation, which arises from applying the standard. So just to give you a bit of more detail now on the numbers. To start with the revenue for the year was $48 million compared to $3.5 million for 2018. This is largely driven by full year of operations on both Dussafu and our production in Tunisia. Note that the numbers here are from continuing activities. The composition of barrels sold between third and fourth quarter is 154,000 barrels roughly, net loss for the third quarter; and 210,000 barrels for the fourth quarter, which are higher because of 4 international lifting, which is in line with our guidance. Average realized prices for the fourth quarter were at $65 per barrel, in comparison to third quarter at $57 per barrel. As a result, the full year EBITDA is about $26 million compared to $5.2 million in the fourth quarter. EBITDA is affected slightly by overlift position, which inflates OpEx in the period. This is expected to reverse out with production from the next quarter. Key noncash items, again, included in the P&L for the fourth quarter are unrealized loss on commodity assets, which is $2.2 million. And in the discontinued operations line before classifying assets as held for sale, we have reversed about $8 million of impairment that was previously recognized in -- several years ago. That basically leaves us with a cash position of a healthy $30 million and a gross debt of $25.4 million at the end of the year. If I can invite you to go to the next slide, please, Slide #8. We have also tried to give the guidance for the coming year 2020, which is 2,600 barrels of oil per day production to 3,100 barrels of oil per day, and these volumes exclude Aje. The guidance is based on operators' range for Dussafu plus a range in Tunisia, which, at the lower end, is the current production, and at the higher end reflecting our aspirations for the growth during the year. This guidance range may be updated as we progress through the course of the year. We also wanted to give you a little bit of background on our pattern of liftings and sales, whereby we are expecting 2 international liftings in the first and second quarter of the year. And then in the latter part of the year, we are expecting about 7 liftings from our Dussafu and Aje -- sorry, Dussafu and Tunisia operations combined. Typical parcel size in Dussafu is about 650,000 barrels, of which we have 7.5%. And in Tunisia, the parcel size is 150,000 barrels, of which we get about 90,000 barrels net. There are some small domestic liftings as well in Tunisia, which vary between 6 to 8 liftings a calendar year. Again, there is no Nigerian information here. We have not included any Aje volumes in this guidance. Now moving on to the guidance for capital expenditure. We have a very exciting investment program for the year 2020 with Dussafu at $21 million, which will be spent on both exploration and development activities. And on -- in Tunisia, we have a capital expenditure plan of around $11 million, which includes the Salloum well, which is also anticipated later in the year. This concludes my review of the numbers, and I will give the call now to Richard to take us through his bit of operations. Next slide, please.

[Richard Morton, Technical Director]

Thank you, Qazi. So we're now on Slide #9 entitled Gabon Highlights. Before I describe the Q4 activities at Dussafu, some background information on our Gabon project. As a reminder, we've been active in Gabon for the past 13 years, and we enjoy an exceptional track record in terms of exploration and now development and production activities. Our project at Dussafu is the largest exploitation area in Gabon, and the fiscal regime in Gabon encourages significant drilling activity. Any cost for exploration appraisal or development wells are immediately captured in the cost pool, so it can be later recovered through cost of oil. For this reason, we're able to execute multiple well drilling campaigns. And as a consequence, you should expect to see a significant number of wells and news flow in the next 2 years. Finally, we've demonstrated with the rapid approval of the Ruche and Hibiscus development as Ruche Phase 1 that we can bring any discoveries into production very rapidly. Moving on to the next slide, #10. This slide shows a graphic depicting the drilling activity we foresee in 2020 and beyond. We're currently concluding the Tortue Phase 2 drilling, where the DTM-4H and DTM-5H horizontal oil development wells were successfully drilled and completed. Both wells were drilled in the Gamba reservoir on the field and encountered long horizontal sections of good quality, oil-saturated Gamba sands. Of the remaining 2 -- Phase 2 development wells, DTM-6H, the Dentale well is underway, after which the final Tortue Phase 2 well, DTM-7H, will be drilled and completed in the Gamba reservoir. Following the development drilling at Tortue, a further exploration well is planned in 2020. The JV partners are completing a reprocessing project on the 3D seismic data covering the block, and we plan to use this new data to help select the prospect location for that well. Additional exploration drilling may be carried out in 2020 depending on the results of the reprocessing and the current drilling campaign. In 2021, we are planning the initial Ruche Phase 1 development drilling, and you can expect to see up to 2 exploration wells drilled when we bring the rig for Ruche Phase 1 into the area. Going forward into 2020 and -- 2022 and beyond, should the prospectivity warrant it, we have an aspiration to drill additional 2 exploration wells per year in the block. It's expected that Tortue Phase 1, DTM-4H and 5H wells will start production in Q1, with the DTM-6H and 7H wells coming online in Q2 2020. Once all 6 wells are producing at Tortue, the production is expected to peak at around 25,000 barrels of oil per day. So move on to the next slide, please. This is entitled 4Q Production at Tortue. Here, we're showing a graphic of the Phase 1 wells in Tortue and the monthly production from start-up in September 2018 to date. So far, we've produced gross 5.5 million barrels from the field. Production from the field continued from the DTM-2H and 3H wells during the quarter at an average gross rate of around 10,800 barrels of oil per day for the quarter and 11,779 barrels of oil per day year-to-date. The 2020 production guidance is between the yearly gross average of around 17,000 and 21,000 barrels of oil per day, assuming the 4 Phase 2 well start as planned. Move on to the next slide, please, Slide #12. Just a word on our most recent discovery on the block. We drilled the Hibiscus exploration well in September and its sidetrack in October. Analysis of the well data acquired has resulted in a gross 2P estimate of 45.4 million barrels for the field. In order to bring this oil into production quickly, we revised the plans for the next phase of development at Dussafu and have made a final investment decision on the project, which is now known as Ruche Phase 1. We move on to the next slide, slide #13. The detailed planning for Ruche Phase 1 continued in the quarter, and a final investment decision on the project was taken at the end of 2020, as I just described. Ruche Phase 1 consists of 4 production wells at the Hibiscus field and 2 production wells at the Ruche field, all to be drilled in the Gamba formation. A platform is to be located between the 2 fields with a 19-kilometer pipeline tied back to the Adolo FPSO, which is stationed at Tortue. First oil from the Ruche Phase 1 is expected at the end of 2021. And once all 6 wells are online, the total Dussafu production is forecast to exceed 40,000 barrels of oil per day. Ruche Phase 2 development will target additional discovered resources through up to 7 production wells, with the objective to maintain the production plateau. The CapEx for the revised Ruche Phase 1 incorporating the Hibiscus development is now expected to be approximately $445 million gross. Total field operating costs, including Ruche Phase 1, are expected to be around $10 per barrel, excluding royalties and taxes at the current FPSO capacity. Moving on to the final slide now on the one where we discuss the prospect inventory and exploration plans. The Slide #14 shows we're in the process of updating our prospect inventory on the block. The map on the left shows the location of the existing fields in green and the outlines of the main prospects in -- and leads in orange, yellow and brown colors. As you can see, we have plenty of potential on the block. The operator has defined 13 prospects with a total P50 gross prospective resource of 281 million barrels of oil. NSAI, the reserves auditor for the project, has attributed a geological chance of success to the prospects of between 36% and 90%. We're finalizing reprocessing project to improve the definition across the entire license area, and we intend to use the results of this work to modify the portfolio and identify new prospects. With that, I'll conclude the update on Gabon and hand over to my colleague, Nigel McKim, to take you through the activities in Tunisia. Nigel?

[Nigel Bruce McKim, Projects Director]

Thank you, Richard, and good morning, everybody. We're on Slide 15 now, the Tunisia introductory slide. As an introduction to our ongoing activities in Tunisia, we have provided a few overview slides on the country and the establishment of our second core area of business. This slide describes the drivers that Panoro had in choosing to invest in Tunisia: broadening of the asset base; the opportunity to pick up significant assets as majors divested their interest in this part of the world; and an asset target having both production enhancement characteristics together with additional exploration potential. Next slide, please. On Slide 16, we highlight some of Panoro's particular reasons for investing in Tunisia. The stable, well-established political and oil industry environment is very attractive to us. Coupled with this, we saw an opportunity to pick up a set of contiguous assets where we could leverage existing infrastructure whilst enhancing the evident potential resources available. The TPS assets currently provide over 10% of total domestic oil production, and we see the significance increasing as we take steps to further enhance the production. Next slide, please. On Slide 17, we demonstrate the contiguous nature of the 2 assets acquired by Panoro. The TPS assets are located onshore around the city of Sfax, with a further field offshore north of the Cercina Islands. The Sfax offshore exploration permit located adjacent to these concessions provides exploration opportunity, which, in the success case, could be tied back to TPS infrastructure. We have an active operational program in progress on the TPS assets, where a number of well workover operations are underway. Whilst on the Sfax offshore exploration permit, we are in the final stages of detailed planning for the drilling of the Salloum West well. I will go on to describe these activities in a little more detail using the next few slides. Next slide, please. We're on Slide 18, Enhancing TPS Production Levels. This slide shows the historical production from the TPS assets since start-up in 1981. We display here the production from each of the 6 fields on the 5 producing concessions. After a ramp-up of production through the 1980s and '90s, the impact of relatively low oil prices at the end of the '90s can be seen to have constrained further development in the early 2000s. Later in that decade, production in excess of 6,000 barrels of oil per day was established from this group of fields. But in recent years, production has fallen significantly below these levels as a result of a period of relative underinvestment. We believe that this situation can be turned around, and I'll touch on some of the initiatives that we are currently pursuing to deliver this objective. The average gross daily production for 2019 was 3,696 barrels of oil per day. Whilst with a number of wells undergoing workover operations, the fourth quarter average production was 3,473 barrels of oil per day. We are currently producing at just over 4,000 barrels of oil per day, and our near-term objective is to raise production to our target of 5,000 barrels of oil per day gross. On the right-hand side of the slide, we have identified the ongoing activities that are expected to underpin the current future production. Enhanced production shown in orange is expected to be achieved by 6 well activities. The drilling of a new production well at the Guebiba field, 3 wells currently undergoing workover coming back onstream, the completion of -- or drilling to a new reservoir interval in a further well, and the hookup of the Salloum West exploration well and the success case. Note that there are parallel ongoing activities required to maintain the existing production base shown in blue. The most significant of which is to replace failed electrical submersible pumps, or ESPs, as and when they occur. It is worth remembering that the economic life of this group of assets extends well into the 2030s and that there'll be plenty of activity over the coming years. But for the purposes of this presentation, I focus only on the near-term activities. Next slide, please, Slide 19, TPS Well Activities. This slide shows the specific recent ongoing and planned activities for the coming months. GUE-03 was worked over in October to replace a failed ESP pump. The Rhemoura-01 workover comprised of stimulation and ESP replacement. The stimulation was very successful, leading to a fourfold productivity increase in this well. This has encouraged us to identify further the targets for stimulation across the other fields. Some of the highest impact near-term opportunities line with resumption of production at the El Ain field. We currently have an ongoing operation at the EL AIN-01 well, where we are completing well with an ESP for the first time. We will also bring the EL AIN-03 well back online after the stimulation. Also on Guebiba-05, we are attempting the perforation of the Douleb reservoir. This is a newly completed reservoir in this well. These activities alone will, we envisage, enable our target production of 5,000 barrels of oil per day gross to be reached. Looking forward, we plan a series of additional well workover operations. On Guebiba-04, we hope to recover a failed downhole completion and to also complete this well on the Douleb reservoir. We are in the final stages of planning the drilling of the sidetrack on the Guebiba-10 well and have taken the opportunity of a delay in approvals of the Salloum West well to schedule this activity with the CTF Rig 06 ahead of the Salloum West well. Next slide, please, Slide 20, Guebiba-10 Drilling. Approval has now been granted by both ETAP and Panoro for TPS drilling of a production well on the Guebiba field. This will be the first activity of this type since 2015. As I stated, we have taken the opportunity of the delay to the Salloum West well approval to drill this well using the CTF Rig 06. The operations will utilize an existing top hole section and will target a new production interval on the Bireno formation at 3,600 meters in a known fault block compartment. Following the Guebiba-10 well operations, the CTF Rig 06 will move to Salloum West to drill the exploration well. I will now hand back to John for the next slide, Slide 21.

[John Andrew Hamilton, Chief Executive Officer]

Thank you, Nigel. I just want to touch briefly on our exploration. So we're on Slide #21 called New Exploration Assets. As we've articulated for the past 6 months or so, we have been quite interested to add some additional exploration to the portfolio we have within our Tunisian and our Japanese assets, obviously a lot of exploration potential, but we felt we wanted to broaden out and provide for some future activity on exploration drilling outside of those 2 areas. And so we've been spending a lot of time on it. And again, our strategy is to take smaller stakes to start with at least. We don't want to become an exploration company per se, but we want to make sure that we continue to prime the pump with bringing new assets and new production opportunities into the business. So we're always targeting in these exploration deals things that are not something you can bring into production 10 years from now but things you can bring into production reasonably quickly, new existing infrastructure, the first such opportunity we've announced yesterday, which is Block 2B in South Africa, and we are still evaluating some other opportunities. We're, again, taking modest stakes, partnering with reputable oil companies, again, in the African region. What I'd like to do now is to encourage you to go to Slide #22, South Africa Block 2B. I'll let Richard briefly take you through the opportunity. Just as an intro to Richard, this is a block that Panoro has actually been looking at for the past 4 years, and we're very, very pleased to have found a way into the block. It's something we identified many, many years ago, and we're absolutely thrilled to be working together with Africa Energy on this one. Richard, do you want to take us through the 2 or 3 slides on Block 2B, please?

[Richard Morton, Technical Director]

Yes. Thanks, John. We're on Slide 22. So Block 2B is an exploration license located in the Orange Basin in the Atlantic margin of South Africa. The block's gotten existing oil discovery and has got recent 3D seismic data to be farmed in for 12.5% of this. And we intend to drill an exploration well called Gazania-1, and that well will be drilled as early as Q4 this year. We're targeting an estimated above 300 million barrels prospect updip of the discovery well. So we think it's pretty low-risk exploration opportunity. We move to the next slide, Slide 23. This slide shows a cross-section through the discovery well, which is called AJ-1, after the proposed new well Gazania-1. So the new well will hit 2 prospects. It's -- the first prospect is Namaqualand; the second, Gazania. And we expect good reservoir properties and a good chance of finding significant oil accumulation with the well, above 300 million barrels between the 2 prospects. We've also got significant running room on the block, and additional targets on the block could have an upside of up to 1 billion barrels in total. We move to the next slide. This shows how that 1 billion barrel prospective resources is built up, Slide 24. We've got 37 million barrels already confirmed as contingent resources from the discovery, which was drilled back in 1988, the AJ-1 well. The Gazania well may add significantly to those resources in what we call the Axial Delta Play, initially Gazania, but also the Pelargonium and Ursinia prospects. The well will also test Namaqualand above Gazania, which is estimated at 186 million barrels. Further prospects have been identified on the eastern side of A-J Graben. And there's also a separate Northern Graben in the north of the block, which would require some 3D seismic before drilling. But initially, we think that could contain prospects up to 400 million barrels. So in summary, we saw this as a great opportunity to expand the portfolio and add an exciting well into 2020 activities. In the event of its success, we could bring this oil to production relatively rapidly. That's it for Block 2B. Back to John for concluding remarks.

[John Andrew Hamilton, Chief Executive Officer]

Thanks, Richard. So Slide 25, Outlook 2020. We have multiple things going on in the company. In the exploration side, we've talked about the Salloum West well, which Nigel touched on; we have a firm exploration well at Dussafu; we have up to 2 additional optional wells in Gabon; and we have Block 2B in South Africa, which could spud as early as the end of this year. So we have a very, very busy -- up to 5 exploration wells to be drilled this year. So we hope that we will be drilling the majority of those during the course of this calendar year. On the production side, we've got -- in Dussafu, we have 4 new wells coming onstream. We're going to see a big production growth in Gabon. In Tunisia, we've got unprecedented activity going on in these assets, having taken it over just about a year ago. As Nigel described to you, we're targeting initially a production up-ramp to 5,000 barrels a day, but we're very, very busy. And we have additional activities underway, which may be able to take these numbers even higher. So in summary, our production as a group should materially increase during the course of the year. And on the corporate side, we're looking at further smaller exploration opportunities at the moment. We're looking forward to completing the Aje sale during perhaps the third quarter and dividend-ing those shares to our shareholders. So we think we have a particularly busy year in 2020. And I will now encourage you to turn to the final slide, which is Slide 26, our ESG slide. I won't go through much on this only to say that our annual report this year, we'll be having additional focus on ESG. It's something that we're all spending a lot more time on. And in terms of our disclosures, in terms of our strategy around this, you'll see a lot more dialogue on this coming up through our annual report, which will be out at the end of April. So with that, we conclude, and I'd like to open up for any questions we might have.

[Operator]

[Operator Instructions] We currently have no questions coming through via the audio lines. [Operator Instructions] We do have a question coming through from the line of Jørgen Torstensen calling from Fearnley Securities.

[Jørgen Torstensen, Analyst]

Can you hear me?

[John Andrew Hamilton, Chief Executive Officer]

Yes. Yes. We can now.

[Jørgen Torstensen, Analyst]

Okay. That's good. So just to follow up on your comments on sort of further M&A, do you have any specific regions you're looking at or any indications whatsoever, what could be sort of relevant for you to consider?

[John Andrew Hamilton, Chief Executive Officer]

Yes. Sure, Jørgen. At the moment, we're really concentrating on, obviously, our existing asset set, which is going through a high level of activity. On the M&A front, we're really just, at the moment, concentrating on some of these smaller exploration stakes that we're looking to take in sort of material areas like Block 2B, some things that can be real game changers, where we take a small stake, which is not going to expose ourselves too much to turn into an exploration company but nonetheless where we can provide for some growth for the future. So we're not, at the moment, entirely focused on large-scale M&A, more adding strategic bits to the portfolio.

[Jørgen Torstensen, Analyst]

Okay. That makes sense. And if you don't mind me asking another one at this issue specifically on exploration, the sort of order of operations in terms of which wells you're next up and some additional details on that, if you can.

[John Andrew Hamilton, Chief Executive Officer]

Sure. So the very first exploration well will be spud in June on current schedules in Gabon. We have 2 optional slots on the rig. The joint venture has not made a decision yet on whether to exercise those options. We, of course, at Panoro, hope that we take all the options. But that decision has not been taken by the JV yet. But should we elect to take 1 or 2 of those options as we follow immediately from June, so you'd probably see a well, one in July and one in August roughly. So you'd have 3 back to back there. Salloum is currently slated as a third quarter event. So that one will slot in there. And then Block 2B, we hope to be able to drill that perhaps -- or spud that by the end of the year. That depends on, first of all, getting approval from the South African government; secondly, making sure we secured a rig. So on that one, we've said as early as Q4, that could easily slip into next year if there are any delays to finding a decent rig. But it's sort of in that time period. We've separately, Jørgen, also had a question on CapEx on Block 2B come in via the webcast. And just to answer your question while we're talking about 2B is there's a question about whether Block 2B is not included in our CapEx guidance. And that's mostly -- there is a bullet point on the slide about that. It's because we're not actually sure that the CapEx will fall in 2020. If it does, then obviously, there'll be a little bit of CapEx for Block 2B in 2020 as well. So our expectation that even if we spud in Q4, most of the CapEx will probably fall into Q1 of 2021. So hopefully, that answers one of the questions that have come through on the webcast as well. We have another question that's come in through the webcast. Are we targeting oil on Block 2B? Or is it also a condensate in gas? And given the discovery, what would be the most likely development concept? Richard, can I turn that over to you, please?

[Richard Morton, Technical Director]

Yes. So the discovery well tested oil, and we hope to find oil updip of that. In terms of the development plan, we're looking at a concept of a platform with a FSO with a drilling center, drilling deviated wells from that drilling center. So we do have conceptual developments already in mind for the project.

[John Andrew Hamilton, Chief Executive Officer]

Great.

[Operator]

We currently have no further questions coming through via the audio lines.

[John Andrew Hamilton, Chief Executive Officer]

Okay. Well, I'd like to conclude then and thank everybody for joining us. Obviously, if there are additional questions that you would like to pose to us, you can reach out to us by e-mail, of course. And thank you very much for attending the conference. Thank you very much.

[Operator]

Thank you for joining today's call. You may now disconnect your handsets. Hosts, please stay connected and await further instruction.