Good afternoon, ladies and gentlemen. A warm welcome to our conference. Please let me first draw your attention to our legal disclaimer, which you can read in detail on slide to. I am here today with Alina Popa, our Chief Financial Officer, Cristian Hubati, our new Executive Board Member responsible for Exploration and Production, and Franck Neel, our Executive Board Member responsible for Gas and Power. Ladies and gentlemen, in December 2021, we launched our Strategy 2030, built on th pillars: transition to low and zero carbon, grow regional gas, and optimize traditional business. At the heart of the second pillar, Grow Regional Gas, stands Neptun Deep. This week, a year and a half into our strategy cycle, we have announced a major step forward in delivering on our Strategy 2030.
We reached the final investment decision for the development of Neptun Deep. Together with our partner, Romgaz, we approved the submission of a development plan to the regulator, the National Agency for Mineral Resources. Neptun Deep is crucial in securing our sustainable long-term growth by generating high profitability that will facilitate new investments and attractive shareholder returns. At the same time, by increasing the share of natural gas in our hydrocarbon production, this project is supporting our efforts to decarbonize, as we see natural gas as a key enabler for a successful energy transition. Ladies and gentlemen, this is an exciting and long-awaited moment for the investment community and many, many others. Before we look into the future, let us summarize the key milestones that contributed to this achievement.
Since 2008, the exploration activities in the Neptun Deep block have included two 3D seismic acquisition campaigns and two exploration drilling campaigns. A total of eight wells were drilled, with a success rate of around 80%, significantly higher than industry average. The first gas discovery well was Domino-1 in the Domino Field, which took place during the first drilling campaign in 2011-2012. After interpreting a second set of seismic data during the 2014-2015 drilling campaign, the Pelican South-1 well was drilled, leading to a discovery in the Pelican South field. Until now, total gross investment for the project has been around EUR 1.5 billion.
In August 2022, we became the operator in our new partnership with Romgaz. In December 2022, we marked another key milestone with the submission of a declaration of commercial discovery of the Domino and Pelican South fields to the regulator. Moreover, in March this year, we signed with Transgaz, the contract for the Tuzla pipeline shore capacity booking for the natural gas delivery from the Black Sea to the National Transport System. The field development plan that we have just approved in partnership with Romgaz is being submitted to the regulator for endorsement. For OMV Petrom, this project will be a transformational and plays a key role in our company growth story. It will completely reshape our hydrocarbon production portfolio and will significantly boost our earnings. In 2030, group EBIT is estimated to increase by 50% due to the Neptun Deep contribution.
This will support our investments in low and zero carbon projects, as well as our progressive dividend policy. Neptun Deep gas volumes represent a significant shift in our portfolio, as gas production is expected to double and reach 70% of our total hydrocarbon production. In addition, it will reduce the carbon intensity of our E&P portfolio by more than 70% compared to 2019. Neptun Deep is a strategic project, not only for us, but also for Romania. Together with Romgaz, we will invest up to EUR 4 billion in this project, which will contribute to Romania's long-term security of energy supply. Moreover, at Plateau, Neptun Deep Gas will double Romania's current gas production, and the country will become the largest gas producer in the EU, thus contributing to the EU's energy security.
Today, I am happy to present the key highlights of this project, which are broadly in line with the one shared in December 2021, when we launched our Strategy 2030. The development CapEx of the whole project is estimated between EUR 3.8 billion-4 billion, to be spent mostly during 2024-2026. Drilling activities are planned to start in 2024, with first production in 2027. Recoverable volumes are currently estimated at around 100 billion cubic meters, which are to be gradually recognized in our reserve base. It is expected that the plateau production will be reached within one year after first gas and will last for a total period of around 10 years at approximately 140,000 barrels of oil equivalent per day. After this period, the asset will enter into natural decline for a period of another eight years.
The production cost is estimated at an average of around $3 per barrel of oil equivalent for the entire life of field, which will significantly enhance the competitiveness of our entire E&P portfolio. The IRR for the life of the field is expected to exceed 12%. Let me share with you some technical details on the development concept of this project. The project includes the development of two natural gas fields, Domino and Pelican South. Domino, the main field, is located in water depths of 1,000 meters, while Pelican South is shallower, located at a 120 meter water depth. The two fields will function in parallel, being both connected to a shallow water platform. Domino field will be producing from six wells connected into a subsea production system. Pelican South will produce from four wells via one subsea production system.
The subsea production systems are connected via pipelines and umbilicals to the shallow water platform through flexible flow lines. These flow lines are continuously Direct Electrical Heating to a quite novel technology in the industry, ensuring reliability and reducing operating costs. The unmanned shallow water platform is where the gas processing will happen. The platform will generate its own energy and will operate at the highest standards of safety and environmental protection. The entire infrastructure will be operated remotely through a digital twin. This allows the optimization of processes and will contribute to the improvement of environmental performance by making energy consumption more efficient and reducing emissions. The natural gas discovered is a very high purity, dry biogenic gas with a composition of 99.5% methane, therefore it needs very little processing.
The gas will be dried or dehydrated to sales gas specification and then transported via a 160-kilometer pipeline to the shore, where it will pass through a metering station and enter into the national gas transmission network at Tuzla. The construction plan of this project takes into account any possible impact on the environment and the local communities. As part of the development, we will conduct environmental and marine life assessments, and where the case, we will put robust mitigation measures in place. The gas pipeline coming from the platform will be entirely buried, passing under the beach and continuing until it reaches the metering station in Tuzla. OMV Petrom has over four decades of experience as an offshore operator. Approximately 25% of our gas production today comes from our shallow water offshore assets.
During the exploration appraisal phase of this project, we partnered with ExxonMobil for more than a decade. We were the operator of the 3D seismic campaigns. For the execution of this project, we are leveraging our project management and logistics capability built during these 40 years of experience in developing and operating offshore assets. However, the deep water development is the first of its kind in the Romanian waters. We needed to complement our internal capabilities with new team members with international experience in deep water projects. A highly technical, capable, and diverse international team of approximately 300 people will be working on different stages of the construction and installation of the hardware. As an integrated company, we have experience in the entire gas value chain, including gas marketing.
We have been a major, reliable gas supplier to the Romanian market for more than two decades, and in the past years, we have become an important regional player by growing our portfolio beyond equity gas. Romania has been a net importer of gas for decades, and in the context of decreasing domestic gas production, without Neptun Deep, we estimate the imported gas as a percentage of total Romanian consumption would rise to approximately 50% by 2030. Domestic gas demand is expected to grow by 2030. This growth is driven mainly by new gas-fired power generation capabilities coming online, as well as the expected gradual increase in household demand, supported by governmental incentives for good connection extensions. The industrial demand is anticipated to decline gradually due to improved energy efficiency. Neptun Deep will turn Romania into the largest gas producer in the European Union and a net gas exporter.
The gas infrastructure developments in the past years ensure interconnection with Romania's neighbors, which are all net importers. The accumulated gas export capacity to Bulgaria, Hungary, and Moldova is currently around 8 BCM per year. Thus, Neptun Deep will provide an important stepping stone to both greater energy security and a lower carbon economy for Southeast Europe. Ladies and gentlemen, the final investment decision of Neptun Deep represents a fundamental step change in delivering on our Strategy 2030. This project will bring a significant shift in our hydrocarbon portfolio. By 2030, our gas production will more than double compared to the current levels, and gas will reach a 70% weight in the total hydrocarbon production. Importantly, the robust profitability of the project will support our investments in future low and zero carbon projects and will enable us to further deliver highly attractive shareholder returns.
Neptun Deep is also fundamental for our decarbonization journey. At plateau production, the carbon footprint is expected to be around 2.2 kg of CO2 per barrel of oil equivalent, significantly below the industry average. Neptune Deep will contribute to approximately half of our 70% reduction target of Scope 1 and 2 carbon intensity by 2030, also supporting our net zero operations commitment by 2050. The increase in domestic production will also support Romania's efforts to decarbonize, as gas can replace coal in power generation and enable integration with renewable capacities. At a country level, Neptune Deep will bring both increased security of supply and economic benefits. Based on an independent study on the economic impact of this project into the Romanian economy, Neptune Deep will bring around EUR 20 billion in revenues to the state budget and approximately EUR 40 billion economic value.
Moreover, almost 9,000 jobs will be created or maintained, thanks to the Neptun Deep project. Ladies and gentlemen, I now invite you to watch together a short video about this project. Afterwards, we will open for the Q&A session.
The Black Sea of Romania. Off this coastline is a natural resource that in a few years' time, will deliver new, cleaner energy. A resource that could turn Romania into the largest gas producer in the European Union. The first deepwater discovery in the Black Sea was made in 2012. The Domino-1 gas field is 170 km offshore and in water 1 km deep. Further exploration identified another field called Pelican South. 1 km beneath the surface, the pressure is 100 kg/cm². The latest technology will be used to install the subsea equipment. Over the Domino reservoir, there are two drill centers. Each wellhead is about the size of a small van. Both drill centers are connected to an offshore gas platform. The Pelican South Reservoir has one drill center, which is closer to the platform.
The offshore gas handling platform will be taller than six infinity columns stacked on top of one another. The platform is unstaffed and generates its own power, making it safer and reducing the project's environmental footprint. Routine maintenance visits will be made by a supply vessel to confirm safe and efficient operations. The natural gas requires only minor treatment before entering a new 160-kilometer pipeline to shore. Along its side, runs a fiber optic cable that allows the platform to be monitored and controlled remotely. As the pipeline approaches the shore, it will dive beneath the seafloor. Using the latest low-impact pipe tunneling technology, the pipeline will pass under the beach without disturbance to the environment. It will remain buried until it reaches a small metering station, just over a kilometer inland. The natural gas will now enter the Romanian transmission system.
Neptun Deep will bring new revenues and investments to the country's economy, and it will contribute to the building of a cleaner and more secure energy future for Romania.
Thank you for joining us today. Together with Lina, Christina, and Frank, we will be very happy to take any questions you have regarding the Neptun Deep project.
Good afternoon, also from my side. We are now opening the Q&A session. If you want to address a question, please use the raise hand function. When I mention your name, please unmute yourself so we can hear you. After you ask your question, please lower your hand and mute back your microphone. We kindly ask you to limit to three questions per participant. Once again, to ask a question, please raise your hand. We'll pause for a moment to assemble the queue. The first question comes from Jonathan Lamb. Please go ahead.
Good afternoon. Congratulations. It's a great day. I want to ask you about the availability of everything to make this thing happen on time. Do you already have the drilling rig booked, and all the engineering companies, contractors, ready to go in and start?
Jonathan, hi. Thank you for joining to us. Yes, we agree. It's a great moment today. With regards to the tendering process, Christina will take your question. Thank you, Jonathan.
Yeah, thank you. Thank you, Christina. Thank you for the question. We are just now in the process of tendering. In the final process of a tendering. We didn't award the final packages as we are waiting for the validation of the field development plan submitted to the regulator. We're ready.
Hello, Jonathan, also from my side, and very happy as well that we share with you this great moment for us. I would say, with regards to We do have options, we do have competitive process. We are very confident that we will be able to keep the timeline and have the first gas in 2027 based on what we have on the table right now. Thank you.
Next question. Sorry. Next question comes from Raphaël Dubois from Société Générale. Please go ahead. Raphaël-
Hello. Can you hear me?
Yes.
Yes, can you hear me now? Oh, great. First of all, let me congratulate you for, taking FID on Neptun. I have a few questions, please. The first one is: Is there a tax stability agreement that has been signed with Romania? We have seen a windfall taxation being imposed, so, it would be great to know if there is any stability that can be expected. Second question is, I understand the growing volumes, the lower OpEx per BOE, but in the end, can you address whether we should expect flat or better EBIT per BOE within your upstream division? Same question for the cash flow per BOE, that would be helpful. Lastly, have you signed any offtake agreements yet, or is this something that you will focus on now that the FID has been taken? Thank you.
Thank you, Raphael. For your kind words. For your first two questions on tax stability and sort of the improvement to the EBIT and the cash flow, Alina Popa will cover those. Then Franck Neel will talk about your question on offtake agreements. Thank you.
Hello from my side, Raphael, as well. Talking about the tax, we do have Offshore Law with some stability principles in the Offshore Law. There is a concession agreement with some stability there. As we mentioned with regards to Offshore Law, there are still some clarifications which are going on. In principle, with regards to tax, we do have stability there, and we will continue to advocate on how important stability and predictability is along the journey of this project. I think this is our job to do in order to make sure that this is maintained going forward. With regards to your second question around EBIT and cash flow predictability, we do have, of course, a lot of volatility around pricing.
With regards to volumes, we mentioned that after the first year, we will reach the plateau, which will be very stable production over the almost 10 years. Of course, we have the pricing element, which and price risk, which we are happy to take as an investor in this industry. Depends on how you see the pricing, you might have some volatility over the years. Thank you.
Good afternoon, Raphaël. Frank speaking. Thank you for your question. As you follow OMV Petrom since many months, many years, you know that the last years, the gas and power team has built the capability in term of marketing, in term of trading, in term of licensing, in of course, in Romania, but also in Southeast Europe. I'm very confident with my team in term of the possibility to market this gas. Of course, you know that due to the competition, no, and the fact our partner, Romgaz, is also our main competitor on the market, I cannot disclose commercial information, as you can imagine. What I can tell you in term of what we are looking at is, due to its proximity, Romania stands out as an attractive market.
We are also actively exploring our available option in within the European Union. We have an expectation that due to supply and demand, that the market will be long in Romania, so export will need to be available. What also we are very confident in the last four years is the development of the interconnection between Romania and the neighboring countries. I think the TSO, Transgaz, has done a great job there. We have available capacity in the different neighboring countries, which give us also the security that we will not be a, you know, a trap market or if there is an oversupply. I think that that's what was important for us to take also this idea. Thank you.
Thank you.
The next question comes from Iurie Coctan is from Millennium. Please go ahead.
Good afternoon. Can you hear me well? Sorry, because I had some technical problems. You do? Okay, great. First of all, thank you for your time, and congratulations on FID-ing the project finally after years of hesitation. One question I have, I have three questions, but the first question, it's a clarification. You said you took the FID as the company, as far as I understand, with Romgaz together, but the FID is not approved yet by the government. If you could just clarify what needs to be done and what do you expect from the government? Is it just a formality, or they still have to do and to approve some details, specificities about the project itself? That's question number one. Second question is on CapEx. You mentioned it's still EUR 4 billion.
However, you said that you haven't granted the contracts yet. I understand that big proportion of this CapEx is still not contracted, so this EUR 4 billion figure is a very old figure. How much confidence do you have that this is going to be EUR 4 billion and not more, especially in the high inflationary environment that we live? We hear from every oil and gas company in the world that the costs are going up by 20%-25% for the new developments. How can you be confident in this EUR 4 billion CapEx figure? The third question is on the security situation in the Black Sea.
You know, given the proximity of the project to the war zone in Ukraine and in the Black Sea, what extra steps do you need to take to ensure security of development and security of infrastructure, and how much will it cost you? Thank you.
Okay. Thank you. I will take the first question on sort of FID versus FDP. It's a very fair question to explain. Alina Popa is going to cover the CapEx with regards to the tendering, and Cristian Hubati will cover the question with regards to the Black Sea. So maybe I will clarify. So the final investment decision is a decision that obviously is taken by the company. Once the company has made that decision, it then has the ability to vote with the joint venture partner, and we voted with the joint venture partner that we were ready to submit the field development plan. So the field development plan has been submitted for endorsement, and we will wait for approval on that.
Clearly, we have been in dialogue with the regulator, we are looking for a speedy decision with that. From that, we will then be able to do the contract awards of that. The regulator has 90 days to do that, and we are hopeful that they will do it much shorter than that, given we've been having dialogue beforehand. Alina, next question to you.
Yes. Thank you, Yuri, for the question. With regards to CapEx, yes, we are indeed very happy, and we work hard to stay below the EUR 4 billion that we indicated when we launched our strategy. Right now, we have approximately 70%-80% of this CapEx either based on preliminary offers or best and final offers. We are quite confident that we will be able to stay below the EUR 4 billion. That's why we reconfirmed our indication of two years ago. Thank you.
Yeah, thank you for the question. As you know, we are operating as we are speaking in the Black Sea since more than 40 years. Of course, during offshore operation and during the project, we'll as a prudent operator, will take all the necessary measures as to perform safe operation. Of course, of course, for the moment, we're not seeing any operation interruption on the Black Sea due to the Russian-Ukrainian conflict. Of course, we are not seeing any risk of the development of the Neptun Deep due to this conflict.
Thank you.
I mean, I think, it's a very fair question, and we've obviously dialogued a lot with regards to this overall. The only other point I would say is, obviously, we're in dialogue with the Romanian authorities with regards to this. Obviously, a very important fact, obviously, that Romania is a NATO country of that, so. Thank you for your question, Yuri.
Thank you.
The next question comes from Daniela Mândru from Swiss Capital. Please go ahead.
Hello, everybody.
Daniela, can you hear us?
Can you hear me?
Yes, we can hear you very well. Please go ahead. Daniela, can you hear us?
Hello.
Daniela, please rejoin or follow the instructions that you will receive on the chat. Meanwhile, we'll take questions from Iuliana Ciopraga from Wood & Co. Please go ahead.
Hi, good afternoon. Congratulations for the FID. First, regarding the provisions on the Offshore Law where you wanted clarifications, can you let us know what is happening on this side? Second, the 12% IRR, what price is that based on? Third, my third question would be: How much does it cost you to export the gas? That's all. Thank you.
Okay, thanks. I'll take the first question, Elina, the second one, and Frank will take the third one of that. You're absolutely right. We have been working hard to get some clarifications with regards to the Offshore Law that came into effect in or was actually passed in May of 2022. We've been working this for over a year. We haven't actually got the necessary clarifications. To avoid any delay in the divestment, in the investment decision, we are applying a resolution mechanism that exists in the petroleum concession agreement to seek clarification for that. However, this is not in any way impacting the pace of the project, and as a company, we are confident that once matters are clarified, that this topic will also be settled for that. Alina, on the IRR?
Yes. Thank you, Iuliana, for the question on IRR. To mention first that we are talking about full cycle IRR. That's an important element, so you need to add to this future cost that we disclosed around EUR 4 billion, if we talk about 100% on all the past costs as well. That's the first clarification. With regards to prices, you know, we do not disclose our realized prices. Yeah, that's the practice we do for everything. In principle, what we see is that the prices are and what we expect for the time when Neptun will come on stream, is that prices will be more and more aligned with hub, European hub prices.
Our estimations for hub prices, which are for starting 2027, are somewhere between EUR 25-30 per MW, starting 2027. I think that's hub prices. You need to calculate the rest, but we do not disclose exactly the realized price. Thank you.
Hi, good afternoon, everyone. On your export question, I think it's a bit more complex than that. I think it depends on the spread between market, you know. Now if you refer to the interconnection costs or between market, it depends, you know, which market we are talking about. Usually it's between 1.5 EUR per megawatt hour, the interconnection cost to exit the country. Then you have variable costs as well, based on the gas.
Thank you so much.
Next in line is Tamas Pletser from Erste Group. Please go ahead.
Yes, thank you very much. Good afternoon. I got 2 questions. First of all, can you just tell us a little bit about the production profile of this project? I remember you mentioned during the presentation that you expect the plateau production around 140,000 barrels per day. When do you expect to reach that level? How do you expect later on the decline of this production going forward? That will be my first question. My second question would be about the kind of a production of this gas. Do you share this gas with Romgaz, or do you sell together this gas, what you produce from this project company? How can we imagine, you know, the sale process of the produced gas?
Okay. Cristian will take your questions with regards to the production profile, and obviously, when it comes to selling gas, Frank will cover this.
Yes, thank you, Tamas, for the question. You are right. Production profile is showing a plateau for 140,000 BOE per day. We're expecting to reach this 2028. Production profile plateau will stay 10 years, we'll have the plateau, and after that, will gradually decline for the next 8 years.
Thank you.
With our partner, Romgaz, the volume of gas will be shared based on our participation, so 50/50. We will all be responsible, each of the party, for the marketing of the gas.
So-
Okay.
Separately.
Separately.
Separately, okay.
Yeah.
Okay. That's clear. Thank you very much.
Thank you. Next question comes from Oleg Galbur from Raiffeisen Centrobank. Please go ahead.
Yes, good afternoon. I hope you can hear me well.
Yes, we can hear you very well.
Yes, thank you. I have three questions. The first one is based on the projected level of production, what level of royalties do you expect to pay on Neptun Deep output of production? Second question refers to CapEx. Could you please provide an approximately split, annual split of this EUR 4 billion? Thirdly, in order to be able to actually sell the gas produced at Neptun Deep, would it be necessary for any additional infrastructure to be developed by outside parties like Transgaz, for example? Thank you.
Great. Alina will cover the first two on royalties and CapEx, and then Frank will talk about any additional infrastructure needed for selling the gas.
Hello, Oleg. Also from my side, with regards to your first question on the projected level of production, based on the level of production, we will have an applicable rate of 13% for royalties. With regards to the second question, it's too early for us to have a CapEx split per years. We are really in the middle of the procurement process. There will be intensive discussions over the next few months. It's too early, and I'm not able to provide this to you today.
For your question, Frank speaking, for your question related to the infrastructure, yes, there is still need a piece of infrastructure, and there was an announcement over the last weeks. Indeed, when the gas arrive in Tuzla, we need to connect to Tuzla, to Podișor. I think what is important with this infrastructure, it give us also access to different markets, because you connect to TI, which is a Trans Balkan, which is going, you know, north to south. It's connected then to the, of course, the National Transmission System of Romania, but also connecting to the Buhaci pipeline, so it's a very important infrastructure. The contractor, the EPC contractor, has been also already selected by Transgaz.
The contract has been signed, and the expectation from the EPC contractors is by the end of 2025, this piece of infrastructure will be delivered.
Thank you.
Let me remind you that if you want to ask a question, you should raise your hand using the raise hand function. Next question comes from Jonathan Lamb from Wood. Jonathan, can you hear us?
Sorry, I didn't mean to raise my hand.
That's fine. No worries. I see on my screen now that Yuri might also have another question. Yuri, could you please confirm that you want to address another question? Thanks.
Yes, please.
Please go ahead.
Two follow-ups, please. Christina, you said that the process of approval can take 90 days. Did I understand correctly? Just if you could talk about, you know, functionality here, I mean, what's the approval process? What do they need to do? Because I still don't understand that. The Offshore Law, I understand, is done. You don't have any comments to the Offshore Law. That's my first question is just a clarification. Why is it 90 days? Why is it so much, so long? Second follow-up is on pricing. Does the government still have the first right of purchase of gas according to the draft of Offshore Law from last year, I think? Or you will be selling gas on the open market. Thank you.
Your microphone.
Sorry, my microphone was off. Apologies. I'll cover the first question, and then Frank will talk about the Article 21 and right of first offer. 90 days is what's written into the regulation, and it's the right of the regulator to take that. Ultimately, they're reviewing the field development plan, the resources that will be developed, et cetera, to sign off on it. That's not uncommon around the world. Of that, obviously, we've been working closely with the regulator, so what's coming in is not a surprise to them, and we are hopeful that they will be able to do it in less time to them. It's their right to take 90 days to look at it, so it's how it's written in the regulation.
I think that's not unique to Neptun. That's just how it's written. Hopefully that answers your question.
Christina?
Yeah.
Christina, sorry. Do you have all the environmental permits already from the government? Everything is approved, or there's still something that needs to be approved by the government?
Yeah.
Just an FID revision.
The field development plan is about how you plan to develop the field. It's not about the permitting. The permitting and the different permits is a separate process, done by actually different regulators. If you can imagine, it's done by different regulators.
You don't have, you don't have environmental permits?
Yeah. Okay. Well, we can talk through that, and Chrissy can talk where we are with regards to the environmental permitting.
Okay.
Thank you for the question. As you probably know, it's... You cannot apply, you cannot have a construction permit, and that's hence the environmental permit, as long as you don't have the field development plan approved and final. We're in the process, we applied for the environmental permit. We are aligned with the authorities. There was several meetings and technical committees. We are not seeing... We are well on track. We are not seeing hiccups because of this process. You cannot have basically those permits before the approval of the project. I mean, the FDP from the regulator.
Maybe just one more.
Well, I can give you the example of Rosebank in the U.K., which is exactly the reason why they are not FID in the project, the Rosebank in the U.K., because they haven't received the environmental permits for the project.
Yeah.
So-
Yeah. Yeah.
I don't know.
Yuri, I can understand, obviously, different things around the world. What we have, and I think we've had this conversation in the past, what we see is, given the national importance of this project, all aspects of the Romanian authorities are very keen to see that move forward at pace. We had a joint press conference this morning with the Prime Minister, the President of the Senate, as well as OMV Petrom and Romgaz, and I think we see a lot of national support to move this project through at pace of that. That's just one maybe piece of color that I would add. Obviously, I'm not saying that makes it different necessarily from the U.K., but this obviously is a game changer, not just for the company, but also for the country as well.
Okay, thank you. The sales, please?
Yes.
The government first right of purchase. Thank you.
Yuri. In the article, yes, 21 of the Offshore Law, The titleholders have to propose to the state agency the possibility to match the offer we have on the market. It's not a preemption, but it's the possibility to match the offers we have on the market.
Okay. Thank you very much. Thank you. This closure is still there, it's still in the contract, in the law? You have to offer volume to the government first before you sell it on the open market?
No.
Do I understand it correctly or not?
Yes, this is correct, but, it's based on the offer we receive as well. They will have to match the conditions we receive from the market, from whoever the buyer. Yeah.
Okay. Thank you.
The next question comes from Daniela Mândru from Swiss. Dana?
Hi. Hello. Can you hear me now?
Very well.
Okay, good. I have only one question regarding the net present value of the project, because it is very important. I have an estimated value of EUR 4 billion. Please confirm me that I'm not out a lot of your range.
One for Alina.
Hello, Dana. I am very happy that we hear you and you could be today with us. Unfortunately, I will not be able to disclose the net present value. What I can say is that you have all the relevant information there. The only one which is, of course, there are many opinions that could exist, is the price, the gas price. Otherwise, you have the CapEx, you have the past CapEx as well. You have the operating cost, and depending on production profile and depending on the gas price, you can calculate and of course, discount rate, the net present value. I'm not in a position to be able to disclose this to you.
Okay, regarding the on consumption of technological loss, my assumption is around 6%, 5.7%. I know you have a higher technological rate compared with Romgaz, that's why I'm confused. I didn't know what rate to use.
I think that is not relevant for Neptun Deep. We do not disclose any kind of technological loss or anything like that. What you refer to is about our onshore, our traditional business, which is very different than this project. Thank you.
It is below compared to the onshore business?
You can take more.
Yes.
You can take more.
Okay, thank you. That is all from my part. Thank you.
Next question comes from Tamas Pletser, from Erste. Please go ahead.
I'm sorry, I don't have anything else to ask.
No worries.
left my hand raised.
What about Oleg Galbur? colleague, you also have your hand raised.
Yes, I do have a small follow-up. Just, if you can clarify, from your press release, you mentioned that the 100 BCM of recoverable reserves are a gross number. I wanted to ask if the 140,000 BOE of daily production is also a gross figure or a net figure? How should we look at it?
They're both gross. Yeah, 100 is gross, and 140,000 barrels a day is also gross, so we would be 50% of that.
Understood. Thank you.
I also see Donna's hand raised. Donna, do you have further questions? If not, we go back.
No, I also
Okay, thanks. If not, then we go back to Iuliana Ciopraga from Wood.
Hi, hi. Just a clarification, actually, to the 12% IRR, I guess this is not based on the. Is that based on the EUR 25-30 per megawatt that you are mentioning? My second question would be actually regarding OpEx. On the OpEx side, and at $3 per Boe, is that based on binding offers as well? Is that something that you're looking to contract right now? How would that work to guarantee this $3 per Boe? Thank you.
Okay. Maybe, just Alina, you take the first question. On the second question, the OpEx is the operating cost, which is what's tendering right now, is the CapEx costs. They're quite different costs, because the OpEx is really the operational side of it. It doesn't include royalties, it doesn't include depreciation or anything like that. It's quite a different kind of cost than the CapEx. It's not linked to... totally to the tendering side of it.
How would you guarantee that? I mean, how are you going to sign a contract right now to guarantee this $3 per BOE? How would that work? Or it's just operating costs, it's something internal related to Petrom?
Yeah, it's an operating cost related to Petrom and the running of the equipment that you saw in the video and all those aspects that you would see of it. It.
It's not based on contractors. Okay, thank you.
No.
Mm-hmm.
With regards to the 12% IRR, we mentioned in our in our strategy that the hurdle rate is minimum 12%, and we wanted to confirm that on full cycle basis, this project is above the 12%. Yes, indeed, 12% is calculated with a hub price of 25-30 EUR per megawatt. We do a lot of scenarios with regards to pricing. Yeah, that's absolutely the case, and sensitivities and so on, but I can confirm that with a hub price around 25-30, we reach above 12% IRR.
Thank you.
We also have a follow-up question from Raphaël Dubois, from Société Générale.
Yes. Thank you very much. Can you hear me?
Yes, very well.
Yes. Excellent. Just maybe let me ask differently: Would Neptune be working at capacity now? Would you be at plateau with Neptune? How would the EBIT per BOE compare with the rest of your upstream business? Just to have a feel for the increase in the gas exposure, but the lower OpEx per BOE. How does it end up?
Okay, Alina, for you.
Thank you, Raphael, for follow-up. I can confirm that considering lower cost coming from Neptun Deep, if this will be today on stream, our EBIT generated by Neptun Deep per BOE will be significantly higher than the rest of the portfolio.
Thank you.
Thank you. As there are no more questions, I want to thank you again for taking part in our conference. For further information, please do not hesitate to contact our investor relations team. Until our next call, we wish you all the best.