GeoPark Limited (GPRK) Earnings Call Transcript & Summary

Ladies and gentlemen, good morning, and welcome to the GeoPark Limited conference call following the announcement of the strategic entry into Venezuela. [Operator Instructions] If you do not have a copy of the press release, it is available at the Invest with Us section on the company's corporate website at www.geo-park.com. A replay of today's call may be accessed through this website in the Invest with Us section of the GeoPark corporate website. Before we begin, please note that certain statements contained in the results press release and on this conference call are forward-looking statements rather than historical facts and are subject to risks and uncertainties that could cause actual results to differ materially from those described. With respect to such forward-looking statements, the company seeks protections afforded by the Private Securities Litigation Reform Act of 1995. These risks include a variety of factors, including competitive developments and risk factors listed from time to time in the company's SEC reports and public releases. Those lists are intended to identify certain principal factors that could cause actual results to differ materially from those described in the forward-looking statements, but are not intended to represent a complete list of the company's business. All financial figures included herein were prepared in accordance with the IFRS and are stated in U.S. dollars unless otherwise noted. Reserves figures correspond to PRMS standards. On the call today from GeoPark is Felipe Bayon, Chief Executive Officer; Jaime Caballero, Chief Financial Officer; Martin Terrado, Chief Operating Officer; Rodrigo Dalle Fiore, Chief Exploration and Development Officer; and Maria Catalina Escobar, Shareholder Value and Capital Markets Director. And now I'll turn the call over to Mr. Felipe Bayon. Mr. Bayon, you may begin.

Good morning, everyone, and thank you for joining us today. On September 2, we announced our strategic entry into Venezuela through the acquisition of the Bare Block, a large-scale producing asset in the Orinoco Heavy Oil Belt, one of the largest hydrocarbon resource basins in the world. We are very excited about this opportunity, both for what it can mean for GeoPark and for the role we believe we can play in the reactivation of Venezuela's energy sector and for our shareholders. I want to acknowledge both PDVSA and Grupo Gilinski for the role they have played in bringing this opportunity together and for the confidence placed in GeoPark. Over the last several months, our teams have spent significant time together, including field visits and understanding the asset, the operating environment and the contractual framework. Bare brings together characteristics that are very difficult to find in a single opportunity, exceptional resource scale, a long production history, significant infrastructure already in place and a substantial redevelopment potential. This is a producing brownfield asset, not a greenfield exploration opportunity. Our role is to bring capital, technology, reservoir management and operating discipline to that existing asset base, progressively restore production and unlock more of its potential. And that plays very directly to what we know how to do at GeoPark. At the same time, we understand very clearly that questions remain around Venezuela. Over the last few months, we have carefully evaluated the execution, capital and infrastructure requirements, sanctions, contractual protections and the broader operating environment. We believe the transaction structure and development plan addresses these concerns and create unique opportunities within a disciplined framework. Our goal today is to explain why we believe Bare can be a game changer for GeoPark and create significant long-term value for our shareholders while contributing to the reactivation of Venezuela's energy sector. Let me start with the main message that I would like you to take away from today's presentation. The first is the opportunity itself. GeoPark is establishing an early and meaningful position in Venezuela through a 25-year Production Participation Contract with PDVSA. GeoPark will have operating control of the Bare Block. We believe an early entrant position in the Orinoco Heavy Oil Belt with the right contractual framework creates a very significant opportunity for us. Second, the quality and scale of the asset. Bare has approximately 15.7 billion barrels of oil original in place. It is a producing brownfield asset with decades of operating history. Third is how we intend to develop it. We begin with what is already there, existing wells, reactivations, workovers, artificial lift optimization and critical infrastructure, and progressively moving to larger drilling and thermal recovery phases. The investment plan is phased and support the production ranges we are presenting while maintaining capital discipline. Fourth, the transaction preserves our financial flexibility. This is an all-stock acquisition with no upfront cash payment. That allows us to retain the cash and financing capacity we need to develop Bare while continuing to invest both in Colombia and Vaca Muerta. And fifth is the value for our shareholders. The transaction recognizes GeoPark equity at $12.22 per share, a premium to recent trading, while the acquisition economics reflect an independently assessed value for Bare. The tender offer committed to by Grupo Gilinski also provides our existing shareholders with an additional liquidity option. Finally, it is important to highlight that our investment case does not depend on broader normalization of Venezuela. We have evaluated the opportunity based on the asset, the contractual framework and the operating environment that exists today. This slide shows what Bare can mean for GeoPark over time. Under the 25-year CPP, GeoPark will operate Bare and hold a 65% net working interest. Based on the current development plan that represents approximately 400 million barrels of cumulative net production to GeoPark over this 25-year contractual life of the asset. For a company of our current size, that changes the duration and scale of our resource base in a very meaningful way. The other important point is how Bare fits with what we already have. Colombia remains our foundation and cash flow engine, while Vaca Muerta is our growth engine with world-class unconventional resources and short-cycle development opportunities. Venezuela adds a different and complementary element to our long-duration heavy oil redevelopment platform in the Orinoco Belt. Together, we have conventional production and cash generation in Colombia, and conventional growth in Argentina and a large brownfield redevelopment opportunity in Venezuela with different resources, development cycles and cash flow profiles that create a stronger and more advantaged company. We produced approximately 28,000 barrels of oil equivalent per day in 2025. With continued growth across the existing portfolio and the development of Bare, we see a pathway towards approximately 75,000 to 85,000 barrels of oil equivalent per day by 2030 and a company capable of generating adjusted EBITDA of around $1.2 billion by 2030. The scale changes, but the strategy does not. We remain a Latin American operator and our objective remains unchanged, protect what we have and return to growth by deploying capital where we can generate attractive risk-adjusted returns. Now let me spend a little more time on the asset itself. Bare has approximately 15.7 billion barrels of original oil in place, more than 700 million barrels already produced and approximately 1,100 existing wells and a current production of approximately 11,000 barrels of oil per day. For us, that production history matters enormously. Bare has already demonstrated that it can produce at significant scale. With such a significant original oil in place, relatively modest improvements in recovery can translate into a very significant additional production and value. The current recovery factor is only around 4% to 5%, so there is room to grow. We also have a large installed base of wells and infrastructure that gives us different ways to begin improving performance before we move into the more capital-intensive phases of the development. The size of the resource matters only if it is matched by credible development plan and our approach to Bare is intentionally phased. The first phase from 2026 through 2030 is about restarting and reactivating the existing asset base. We plan approximately 400 to 450 well reactivations, around 100 workovers, approximately 30 horizontal wells, optimizing the artificial lift systems and rehabilitation of critical infrastructure. Under this plan, gross production grows from today's level towards more than 56,000 barrels per day by 2030. The first phase gives us a very practical way to develop the field with existing wells, understand their integrity and performance, identify infrastructure bottlenecks and learn more about the reservoir as we progressively increase activity. From 2031 onwards, we move into a build phase with additional horizontal drilling, workovers and thermal recovery. Production increases towards approximately 90,000 barrels of oil per day. Later, thermal recovery becomes more important as we seek to increase recovery and sustain the production plateau. Before the asset moves into a long-duration harvest phase focused on reservoir management and maximizing recovery. The investment plan shown on this slide supports the production ranges we are presenting to you today. This slide is really about how we fund the growth. In 2026 and 2027, the portfolio absorbs the early investment in Bare, while Colombia continues to generate cash and Vaca Muerta continues to grow. From 2028 onwards, as Bare production and EBITDA build, the combined portfolio moves into positive and growing free cash flow. Venezuela CapEx rises from approximately $10 million in 2026 to around $131 million by 2030, but against a much larger EBITDA contribution. The investment plan supports the production ramp without displacing our priorities, both in Colombia and Argentina. We also entered this development period with approximately $700 million of liquidity and committed or negotiated financing sources, including approximately $310 million of cash in hand. That is why the 3 assets are complementary financially and strategically. By 2030, production has the potential to be nearly 3x our 2025 level and adjusted EBITDA could be approximately 4x larger. Based on preliminary estimates and subject to confirmation from an independent reserves report, our 2P reserve base could increase from approximately 121 million barrels to 240 million to 260 million barrels of oil equivalent. It is important to understand what that reserve indication represents. It is a point-in-time estimate associated with the initial development phase, subject to the appropriate certification processes. It is not a measure of Bare's ultimately reserve potential over the 25-year contract. As the development plan advances and additional activities incorporate into independent evaluations, we expect the reserve estimate to evolve as such. Equally important, our operational breakeven declines under the plan from approximately $51 per barrel of oil equivalent in 2025 to some $28 per barrel in 2030. In summary, the larger scale and the quality of the underlying barrels that we are capturing with this transaction make GeoPark more resilient, more efficient and financially stronger. Furthermore, a larger production and reserve base also gives us greater relevance to investors, service companies, technology providers and capital markets. Diversification provides more alternatives for capital allocation while a lower breakeven improves resilience across different commodity price environments. As mentioned earlier, by 2030, GeoPark has the potential to produce approximately 75,000 to 85,000 barrels of oil equivalent per day, generate around $1.2 billion of adjusted EBITDA and hold approximately 240 million to 260 million barrels of oil equivalent in 2P reserves. At that scale, GeoPark would sit in a very different peer group. But while the scale changes, the focus remains on exceptional hydrocarbon systems, the Llanos Basin in Colombia, Vaca Muerta in Argentina and the Orinoco Belt in Venezuela. Together, they give us exposure to conventional, unconventional and heavy oil resources across different development cycles and provide different cash flow characteristics. We remain an operator focused on Latin America, technical excellence and disciplined value creation. Let me now turn the call over to Jaime to discuss the transaction structure, value equation and path to closing.

Thank you, Felipe. Good morning, everyone. I'll begin with a quick overview of the transaction structure and how the different pieces fit together. GeoPark obtained an initial 5% interest in the CPP signing vehicle for no consideration in recognition for its direct contribution to the asset's technical evaluation and negotiation process with PDVSA. Following execution and effectiveness of the CPP, GeoPark will acquire the remaining 95% interest from Grupo Gilinski. The consideration for the remaining interest will be paid in GeoPark shares. This is an all-stock transaction with no upfront cash acquisition payment. This funding mechanism is strategic in nature because it preserves our cash and balance sheet capacity to develop Bare while continuing to invest at pace in the growing opportunity set that we have in Colombia and Argentina. Following the share issuance, Grupo Gilinski is expected to become GeoPark's controlling shareholder. The Board considered this change of control carefully alongside the scale and quality of Bare, the valuation framework and the overall terms negotiated for GeoPark shareholders. Given the change of control implications, rigorous management of potential conflicts was exercised. The Gilinski nominated directors were recused from the Board's deliberations and votes, and the transaction was reviewed with independent financial and legal advisers, including a fairness opinion from BTG Pactual. Going forward, GeoPark will continue to operate as a New York Stock Exchange listed company with independent directors and the applicable governance and related party protections. Let me walk you now through the economics of the transaction. The independently established value of 100% of Bare is approximately $570 million. This fair value was independently assessed by BTG Pactual using established valuation methodologies, including a full discounted cash flow analysis of our development case, cross-checked against relevant operating and transaction benchmarks and reflecting country risk-adjusted discount rates. As mentioned previously, GeoPark obtained an initial 5% interest for no consideration. Therefore, the fair value of the remaining 95% is approximately $541 million. We will acquire that remaining interest for approximately $515 million, representing an acquisition discount of approximately 5%. Together, the initial interest received for no consideration and the acquisition discount represents approximately $55 million of implied value accretion. At the same time, the new shares are being issued at $12.22 per share, representing a 26% premium to the 30-day VWAP. Combining the acquisition discount with the premium at which we are issuing GeoPark equity results in approximately $160 million or approximately $1.50 per share of implied immediate value accretion. Grupo Gilinski has also committed to launch within 90 days after closing, a tender offer for up to $100 million at the same price of $12.22 per share. If the offer is oversubscribed, purchases will be made on a pro rata basis. For existing shareholders, this provides direct optionality. Those who prefer liquidity will have a monetization alternative at a premium to the reference trading price, while those who remain invested will continue to participate in the potential long-term value of the enlarged GeoPark platform. Let's now look at some of the key transaction metrics. The $12.22 per share exchange price is above GeoPark's 52-week undisturbed high of $11.98 and above every month end closing price since February 2023. To put that in further context, it is also approximately 36% above the $9 per share unsolicited takeover proposal received in the fourth quarter of last year. At this price, GeoPark equity is recognized at an implied enterprise value to EBITDA multiple of approximately 4.1x compared with approximately 3.5x at the reference market price. We see the same uplift across the flowing barrel and reserve metrics presented on this slide. Under these conditions, the transaction recognizes a compelling value for GeoPark equity while allowing us to acquire Bare at attractive entry economics relative to the independent valuation. Let me now conclude with the path to closing. Following the signing of the CPP, we enter an interim period expected to last no more than 120 calendar days. During this period, the key work streams include approval of the business plan, execution of the complementary agreements and receipt of the required permit on authorizations. In parallel, we will prepare the operating organization, including people, systems, supply chain and field readiness for the takeover and transition. The CPP becomes effective once the required conditions have been satisfied. At that point, GeoPark will issue the shares to Grupo Gilinski. There is significant work to complete during the interim period, but the milestones and responsibilities are well defined. Once the CPP becomes effective, our focus will shift from transaction execution to operational and financial delivery. Felipe, let me turn it back to you.

Thank you, Jaime. We understand that investors will look carefully at the risks of operating in Venezuela. We have assessed those risks in detail, quantified them where possible and structured both the development plan and the contractual framework to mitigate them. First, operating readiness. After years of underinvestment, we need to understand the conditions of the wells, infrastructure, power systems and facilities. That is one reason the development begins with reactivations, workovers and stabilizing before moving into larger investments. Second, heavy oil logistics. Diluent supply, transportation and commercialization are critical for an extra heavy oil operation. The contractual framework addresses the full commercial chain required to monetize production, including direct commercialization rights, procurement of diluent, transportation, reimbursement and related production adjustments. Third, the regulatory sanctions and contractual framework. The agreements signed were structured under an OFAC-compliant framework. The framework includes defined remedies for material PDVSA or PPSA default, protections in prolonged force majeure situations, international arbitration, economic rebalancing mechanisms for legal or regulatory changes and defined termination and cure provisions. Fourth, governance. A change of control makes governance especially important. GeoPark will continue to have independent directors and appropriate related party protections. The last point is our people. Members of our leadership and technical teams have different operating experiences in the country and in the Orinoco Belt specifically. Martin Terrado, our COO, led Chevron's Venezuela operations from 2012 to 2018, including Petropiar immediately adjacent to Bare. We also expect approximately 60 members of the existing PDVSA operating team to join GeoPark's operational team. We have people who know the country, people who know heavy oil and people who know the basin. Let me now close by bringing the main points together. I'm an optimist by nature, but optimism by itself, it's not a strategy. You need a plan, the right people and the discipline to execute. We believe in GeoPark, we have all 3 of them. Bare is a unique opportunity for GeoPark. It gives us early strategic positioning in the reactivation of Venezuela's energy sector through a 25-year contract in one of the largest hydrocarbon basins in the world. Based on the current development plan, it adds approximately 400 million barrels of cumulative net production to GeoPark over the life of the CPP and creates a pathway towards a company that can be approximately 3x larger in production and approximately 4x larger in EBITDA by 2030. Importantly, the transaction preserves our financial flexibility. We are using equity rather than cash. Our shares are being recognized at a premium to recent trading and the committed tender offer gives the shareholders an additional liquidity option. Colombia remains our cash flow engine. Vaca Muerta remains our short-cycle growth platform and Venezuela has a very large long-duration redevelopment opportunity. Together, they create a more diversified, resilient and robust GeoPark. We're excited about what this opportunity can mean for GeoPark and are already focused on execution and mindful of the responsibility that comes with it to our shareholders, to our partners, to our people and to the communities where we operate. Thank you again for being today with us. We will now open the floor for questions.

[Operator Instructions] And our first question comes from the line of Daniel Guardiola with BTG.

Congrats for the transaction. I have a series of questions. So perhaps it will be easy if I do one by one, if that's okay with you. And my first question is on Venezuela. And I would like to know your thoughts on how do you assess Venezuela's country risk? And what -- I mean, contractual financial and operational protections are in place to mitigate the risk and protect GeoPark's invested capital. And it would be great to know if you could share with us what is the discount rate at which you are basically discounting the expected free cash flows from Venezuela. So that will be my first question.

Thanks, Daniel, and thanks for being here with us this morning. Yes, I mean, I'll share my view. And obviously, if Jaime wants to chime in, we will do that. But I think the way I view it, the investment decision was based on a very thorough and disciplined review of legal, contractual, regulatory framework under which Bare would be redeveloped and we will operate. And in that sense, the counterparties, both PDVSA and the Ministry are the institutions that are legally responsible for managing the hydrocarbon sector. And we do believe that CPP provides the right contractual framework in terms of rights, obligations, investor protections and the like. So from that point of view, I think we're quite comfortable. You could always think, Daniel, would you wait? Or would have you waited in terms of the entry. And we do believe that being the first mover, the first mover advantage into Venezuela with our Colombian background, with the long history ties that both countries have, it does provide the right conditions for GeoPark to move in. And the other thing is that, Daniel, we do believe that GeoPark, as we mentioned it, becomes probably the only independent oil and gas company in the region that has access to Venezuela while maintaining our access to unconventional development in Vaca Muerta and our developments in Colombia. So from that point of view, a great addition, and we do believe that protections and everything else in terms of our investment are there. And probably the last thing I'd say, Daniel, is that our decision was based on the quality of the assets. It's a field that has been in production for a very long time. It reached over 120,000 barrels per day peak. It has a significant number of wells, more than 1,100 wells that we can reactivate. And as we presented today, we have a phased approach to development. So we're -- from that point of view, we're comfortable. On the discount rate, I'm not sure, Jaime, if we're comfortable with disclosing the rate.

Yes, Felipe. So let me chip in on 2 or 3 angles. I think one thing that I'd say on the contractual angle is that the new CPP that is the outcome of the new hydrocarbons law in Venezuela is a CPP that is consistent with industry standards elsewhere. When you look at that contract, it's the sort of contract that you would -- that has the balance of rights and protections that you would expect as an investor in any sense. It has its own idiosyncratic elements. But when you look at it as a whole, it's very clear what are the rights that you have. There are dispute resolution mechanisms that are effective and there are importantly, instances where you can go to if you enter into conflict. So I think that from a contractual standpoint and given all the time that we spent going through that over the last 3 months, the CPP is a contract that, that is the sort of contract that you would expect in any serious jurisdiction. I think that PDVSA and the Venezuelan government were very receptive to the feedback provided on certain clauses that perhaps were key. Things in Venezuela that are particularly important in the contract are the relationship with PDVSA and ensuring that, that relationship is adequately documented in the contract and particularly where you have dependencies, things like volumetric balances or things like the role -- the access to infrastructure, access to ports, those sort of things are all well documented in the contract. With regards to the discount rate, and I'm not going to cover the operational protections because I'm sure that later on with Martin, we're going to address a lot of the operational path that we have ahead of us. I think on the discount rate, I think the key message that I can share is that, of course, Venezuela is in a transition period. It has a good direction, but it's not yet in a place that is necessarily comparable to other jurisdictions around LatAm. Therefore, an appropriate risk premium has to be applied, and we applied it. And the process to go around that was through the independent parties that we involved in the process. BTG Pactual provided a fairness opinion. We also involved a separate legal counsel in different aspects, particularly the OFAC-related components associated to this, which all have to do with country risk. So we -- I'm not going to be specific around the discount rate that we use because, obviously, discount rates are a competitive topic, I'd say. But I would say that it's a discount rate that is appropriately higher than the discount rates that we've used for our capital thresholds in GeoPark, which, as you know, because we've been vocal about this, we test all our investments with a 15% return threshold. And for this particular investment, we are including a higher risk premium associated to it.

My second question is on the economics of the asset. And it would be great to better understand perhaps the waterfall from Brent to Bare EBITDA, perhaps including crude differential, royalties, taxes, government participation, dividend, transportation, lifting costs and other expenses -- operating expenses, sorry, so we can better assess the implied EBITDA netback on a per barrel basis from Bare.

Jaime, you want to take this one?

Absolutely. Absolutely, Felipe. So Daniel on the implied netback, I'd say that we need to first recognize that given the nature of the asset, these netbacks will evolve rapidly over the phases of the project, right? When you look at the logic of the project, as we indicated in the presentation, you have a first phase that it's all about reactivation of the existing well stock. It's all about that. And there is -- I would characterize too that there is this transition phase where we need to deliver the incremental production that puts us at par, if you will, with PDVSA on the 65-35 basis. So the first 2, 3 years of the contract have its own particularities as we get to a more balanced and sustainable stage. I'd say that in that context, when you think about that first phase that gets us to 2030, and that's the guidance that we provided. When you think about the sort of numbers that you see in the $70 to $80 range, I would provide you 4 or 5 key numbers. Firstly, the Merey discount. The Merey discount is the commercial and quality differential associated to -- that is going to apply to these barrels, right? It includes a transport to port consideration in this because that's where the sales actually take place. And directionally, what we're seeing for that is somewhere in the lines of $14 to $15 per barrel, right? So that's kind of your first number, depending on where you want to sit on Brent, if you want to sit on $70 or you want to sit on $80, that's the first, I'd say, deduction that you need to make. The second one is around the volumetric compensation associated to the integrated tax and royalty. The way that we've described this is you have a gross production for the field, right? And to that, there's this 35% that belongs to the government of Venezuela that's split into -- it's 25% an integrated tax and royalty, and it's a 10% a PDVSA, if you will, working interest, right? That -- those 2 components together are paid in kind through a volumetric compensation. That volumetric compensation throughout this kind of first phase of the project is in the order of $5 to $6 per barrel. Then you go to the next key component, which is OpEx/working capital, right? And OpEx/working capital is all the activities that we need to do, which are comparable to lifting cost in our operations elsewhere. What we see leading towards 2030 is that we're going to start with relatively high OpEx that is going to be well into the double-digit area, probably high teens over the first couple of years as we reactivate wells and as we get the production growing. But once we see that volumetric effect, it's going to stabilize around $8 to $10 per barrel. That's what we see as the, if you will, level loaded OpEx and working capital over time around 2030 and beyond. And then last but not least, there is a G&A component associated to the operations in Venezuela, like specific to the operations in Venezuela, and it captures the incremental overhead associated to running this operation. And that, again, we estimate in the $1 to $2 per barrel once we reach the level production status of the field. So if you run the numbers, this kind of puts us in the range of between $42 to $47 per barrel of operating cash flow. That's the OCF kind of that we are expecting. And then I know you asked about Brent to EBITDA, but I'm going to include a CapEx indication as well on this that takes you to free cash flow. And what we're seeing is that, that CapEx indication is in the order of $10 to $12 per barrel, which puts us at a free cash flow breakeven of between $32 to $35 per barrel. So that's kind of like the -- directionally, the breakdown that we see for Bare. As I said, the first 18 to 24 months are going to be a bit atypical around these numbers because you are -- we are ramping up. We are having start-up costs and one-off costs and things like that, which we should expect to see. But as we go into 2029 and 2030, these are the sort of numbers that we're going to be gravitating around. Thanks, Daniel.

Thank you, Jaime, very thorough answer. And just the last one, super quick. I saw in the press release, you announced the implicit acquisition multiples for the medium term and the long term, which was 2.1 for the next 3, 4 years, if I'm mistaken. And there for the long run, 0.7x EV to EBITDA. But it seems that, that multiple is only considering the equity consideration against future EBITDA. So I would like to know what would be the effective multiple if we include to the acquisition -- to the equity consideration, sorry, the CapEx behind the development of Bare?

Sure, Daniel. I think there's 2 or 3 things that we need to pound on as we see this deal. I think firstly, it's important to consider that there are no upfront cash payments associated to this deal. So the way that we've communicated the multiple is intentional, and it's consistent with that. There is no upfront cash payment. There is no entry ticket from a cash standpoint. So the way that we've indicated the CapEx to EBITDA over time is consistent with that. It's consistent with that. But if you will, let me give you a little bit more color around how to think about the CapEx to EBITDA relationship over time. When you think about the 3 or 4 phases of the project that Felipe described in one of his slides, there's this first phase, which is the aggressive reactivation phase, which goes to 2030. What we are anticipating is that phase considers around $300 million to $400 million of EBITDA -- sorry, of CapEx cumulative. And at 2030, we're going to be in an EBITDA that is in excess of $600 million. So that gives you immediately like an indication of that CapEx to EBITDA relationship. The second phase, which is, if you will, the 2030 decade from 2030 to 2039, what we are anticipating is average CapEx deployment over that period of $100 million per year, right? Again, and I think here, it's important. This is not the full investment. Of course, there's a significant operational investment on these fields that is actually captured in the OpEx side of the equation. But from a CapEx, strictly CapEx standpoint, those are the average that we're seeing. And that $100 million per year compares to an EBITDA consideration that we estimate depending on the price environment between $800 million to $1 billion per annum. Then you go to the third phase, which is the 2039 to 2045 type period where we start to scale down CapEx and it reduces in an important way to what we see probably around $50 million per year with a sustained EBITDA over time. So all this to say, what I'm trying to go here, Daniel, is that actually, once you consider CapEx over time, given these phases and given how EBITDA evolves over the life of the project, as the full-in multiple always stays in that 0.7 to 0.9 type range. That's, of course, at $70 per barrel and above.

And the next question comes from the line of Vicente Falanga with BBI.

Congratulations on the acquisition. I think it gives GeoPark a very unique edge within the LatAm investment horizon. I have 2 questions here. Number one, if you could please provide potential bottlenecks you anticipate you could have to complete your first 5-year phase of well reactivations/workovers, such as equipment availability or even labor availability or anything else that we're not thinking about here? And then my second question, if I'm not mistaken, the Gilinski family, they had a lockup period of 18 months since you purchased GeoPark shares in March. I wanted to understand if this transaction somehow extends this? And if not, what is an official message of the Gilinski Group in terms of its investment horizon in GeoPark? And once again, congratulations.

I'll ask Martin to talk about the bottlenecks and the -- specifically some of the facilities investments and reactivations that are required. And just bear in mind, Vicente, that actually Martin and the team visited the field and we're able to look at extensive information on some of the facilities. And the -- I'll start with the second one. In terms of the investment horizon for the Gilinski's and the conversations that we've had is that they're a long-term investor in the company. And they've described GeoPark as a platform that has regional presence. And I was talking about Colombia, obviously, a cash engine, $120 million of CapEx per year. We've reset the company and stabilized production, which is good. Vaca Muerta, we're pressing the accelerator on that one. We've drilled our first 5 wells, horizontal wells, and we've done the fracking and production that we received at 1,500 barrels per day back in October of last year is now over 4,000 barrels. So Vaca Muerta in Argentina is going well. And it's public that we've presented ourselves for the bidding round that the province of Neuquen is leading. And then Venezuela provides, as we've shown today in the slides, a very, very long-term view of this regional platform that creates probably the only oil and gas company in the region that has presence in these 3 countries different types of development, different types of hydrocarbons and probably in particular, in Venezuela, the only proxy, if you will, of somebody who wants to invest into Venezuela. So I'll just reinforce saying their view is a long-term view of the company, and they're long-term investors. And as we've described today, we're multiplying production by 3. We're taking EBITDA and multiplying it by 4 over the next 3 to 4 years, which is transformational for us. So that's their view on the company. And Martin, why don't you take us through some of the reactivations and availability of equipment and people.

Yes, absolutely, Felipe. Vicente and again, thanks for the question. Concerning directly the question around bottlenecks, very quickly, I want to go a little bit back but say that since our first visit to Venezuela, we've been getting ready and encountering and discussing with PDVSA and some old friends that many of us had from previous responsibilities. One week after our first visit, we were ready in the field visiting and spent 2 full days with Rodrigo and our team understanding the conditions. Clearly, that's not enough on one visit. But since then, we also had a data package that we acquired. So we've been getting more information from the field. If we talk about the bottlenecks specifically, the field currently has no bottlenecks. And why we're saying that? The field is producing around 10,000 to 11,000 barrels of oil with 20% water cut. It's a field that has the advantage that has been on production. So it has energy coming into the block. It has diluent coming into the block, and it has diluted crude oil that is going out of the block. Obviously, it has services that are ongoing, and it's around 100-plus wells that are on production. So we will encounter bottlenecks as we go from the current 10,000 barrels of oil per day to approximately the 56,000 barrels of oil per day that we were envisioning and that we got in our plan for 2030. So specifically, bottlenecks, facilities capacity -- right now, the field has capacity for up to 30,000 barrels. So it will be something that we will be looking into immediately, but we don't need to come in and start doing upgrades. We will be doing maintenance, understanding the condition of the facilities and in the future, doing upgrades and restarting some of the facilities in some pads that were shut in. At the same time, the other condition that we're going to be assessing is the condition of the shut-in wells. We have, like Felipe said, more than 600 wells that are in what's called Category 2 and 3, which are basically the wells that have an ease to be restarted with pulling jobs or Category 3 with workovers. So we already identified with PDVSA, which are the first batch of wells that we're going to be doing the workover. And from that perspective, the bottleneck could be, okay, on the assessment that we did on how many of those wells were going to restart, we did not have in our plan 100% of restarting the wells. It's much lower than that. The next bottleneck could be energy, and it is something that, again, from day 1, we are aware, this field currently needs 3 megawatts, just so that you have an idea, Llanos 34 is 70-plus megawatts. So 3 megawatts and much lower energy consumption because there's not that much water. When we take it to 56, our plan is to consume around 3x more. So we will have a consumption of around 10 megawatts and how we're going to go around that. This field comes with associated gas with the production. From day 0, we're going to be in our contracting plan, we're going to be treating the gas and generating energy from the gas. The third one is diluent. Right now, the field has around 4,000 barrels of diluent coming in. When we get to the 50,000 to 60,000 barrels of oil, we will need in the order of 20,000 to 25,000, 30,000 barrels of diluent. So how we go about that? We will -- we have a contract addendum that specifically describes and rules how diluent is going to be treated between us, the operator and PDVSA, so PDVSA will be supporting and providing the diluent. We also have the availability to purchase the diluent, bring it to Jose Terminal. PDVSA will transport it, deliver it into the field, and then we will get recouped for that amount. So the diluent is something that it's already been discussed throughout these 5 months. The other bottleneck that everybody talks about is business partners or supply chain, like Jaime was saying, so we already triggered what we call the Phase 1 supply chain bidding process, and we discussed it with PDVSA. In this process, it's basically all the services and goods that we need for reactivation of wells, artificial lift optimization and also some initial facilities that we need such as the LACT unit, which is a measuring unit. For those we're well into the process, including companies that are already in Venezuela, but also a lot of our allies here in Colombia and many of them already are in Venezuela registered. And the final one is talent. So, how we're going about that. We have a team that it's already defined from our team in GeoPark. That will be part of the team that goes again, and we're actually going tonight, and we're going to spend the next 10 days there. We're going to be understanding and talking with PDVSA to see who are the PDVSA team. Again, PDVSA has been operating this field since the beginning back in 1970. So they know the asset very well, and they have been doing very good technical pilots in the past. And we already identified which are some of the positions that with our people or HR group were filling the position. So just to close, I want to say that all of these fronts have been discussed internally and with PDVSA. We're aware of those bottlenecks, but I shortly try to describe to you, Vicente, what -- how we're going about that.

Thanks, Martin. And Vicente, one thing if I may, just to close on your questions that just to let you know and confirm that the lockup for the PIPE shares and for this transaction will be superseded once the CPPH, which is a contract with PDVSA is made effective and everything is closed on this transaction. So back to the presentation that could be up to 120 days, we're trying to do that faster than that.

If I may, just a follow-up on water. How easy it is to discard water on the Orinoco Belt? I know in Colombia, it could be complicated, but what's the plan there? Would you reinject it in the wells? And -- or what would you do with the water cut once it becomes a problem?

Yes. So for us, water, it's not a problem, something we're used to, right, with Rodrigo. So right now, the field is separating oil from water and being injected in disposal wells in the same block. We basically continue doing that. So again, it's something that we feel very, very confident. And as you know from previous discussions, even in Llanos 123, we have developed a modular water treatment plant. So it's something that we will be injecting per the permits and the permits are already granted.