PetroTal Corp. (TAL) Earnings Call Transcript & Summary

Hello, ladies and gentlemen, thank you for taking the time to join PetroTal's 2022 guidance and reserves webcast. Your host today will be Manolo Zuniga, President and CEO; and Doug Urch, Executive Vice President and CFO. Manolo and Doug will go through the latest corporate presentation, and there will be a Q&A session afterwards. [Operator Instructions] I will now hand over to Manolo. Please take it away.

Thank you, Jimmy. And good day, everyone, and thank you for joining the 2022 guidance and reserves update webcast, where we will provide a summary of our 2022 guidance, 2021 reserve report and some exciting return of capital strategies recently supported by our Board of Directors. If anyone wants further information on the company, please see our website for additional materials. As mentioned before, my name is Manolo Zuniga, and I am the President and CEO of PetroTal, and I'm joined by my colleague Doug Urch, Executive VP and CFO. If you have clicked on the link in our web -- February 22 press release, you should hopefully have signed up to the webcast, so you may see the slides on your screen. But if you are having issues seeing them, just contract [email protected], and they will be able to assist you. Before I begin, I need to mention that there are some disclaimers towards the end of the presentation, which I would urge you to read at your own leisure. Also, all amounts referenced are in U.S. dollars unless otherwise stated. For those that are new to the story, PetroTal is an onshore Peru-focused oil company and Peru's largest crude oil producers nowadays. As shown in Slide 1, the company is listed on London's end market, the Toronto Venture Stock Exchange and recently upgraded to the OTCQX in the United States. We have a market cap of approximately $467 million with net debt of around $75 million and trading at around 1.5x estimated 2022 EBITDA. We have a 100% working interest in the Bretaña oil field. We had never produced when we took it over at the beginning of 2018 and is now producing just over 20,000 barrels of oil per day for the past few weeks. Just announced last week, the Bretaña field has 2021 year-end 2P reserves of 78 million barrels and now has 11 producing wells with the 11th well recently on production at a record flow rate at over 10,000 barrels of oil per day. The company has over 1.2 million barrels of total storage capacity and almost $350 million and $70 million in tax loss carryforwards in Peru and Canada, respectively. In short, we have an amazing asset that is now delivering a beautiful combination of growth and yield, and that is resilient down to [indiscernible] per barrel Brent. We also have a proven technical team in place with a track record that delivers operational excellence. With the recent uptick in our share price, I'm happy to announce that we have delivered a 3x share value multiple promised to investors in late 2017 when we raised our initial capital. The theme of -- for this webcast that I would like to convey to shareholders is that based on our robust 2022 guidance, an exciting reserves upgrade, our Board of Directors is supportive of a return of capital policy that shareholders can be excited about. That said, we have a few steps we want to walk through, so the logic and the strategy is understood on how we think about free cash flow allocation, operations and liquidity risk. As shown in Slide 2, we estimate next year's production rates to be between 17,500 and 19,500 barrels of oil per day. We obtained this range by running different scenarios with technical and ONP pipeline-related social downtime. We feel that the government and communities are aligned as we have worked hard to support Federal tax should be closer to the higher end of the production range. If the opposite happens and we encounter some protesting-related disruptions during 2022, the production could be closer to the lower end of the range. Overall, the [indiscernible] budget scenario with approximately 13% total downtime during 2022 will deliver approximately 18,250 barrels of oil per day at 100% growth over 2021 average production of 8,956 barrels of oil per day and could reach as high as 19,500 barrels of oil per day should little or no downtime occur in 2022. As you can see in the 2022 summary, we plan on generating around $230 million in free cash flow pre debt service, and we expect to retarget corporate bonds early, thereby reinstating a return of capital program if economically viable, which we will detail in the coming slides. It's important that we are transferring in our downtime assumptions compared to prior years, so the market is aware of management's expectations in this area. We're very excited to update everyone on our recently approved reserve report as prepared by Netherland Sewell & Associates, and that was announced last week. Slide 3 summarizes the key highlights and metrics from the 2021 year-end report. It's very clear that for just 4 years into the development of this field, the recovery factor percentages are now similar to analogous fields such as those located in Block 192. So I'm very eager to unlock the additional immense value from this amazing asset. To summarize, we had material year-over-year increases in all research categories with 1P, 2P and 3P reserves now at 37 million, 78 million and 147 million barrels, respectively. Due to these increases, and now with a more robust Brent price deck, we now have a 1P before tax net present value NPV-10 that [indiscernible] with our company currently trading at approximately 65% of this value, representing just over a blowdown before tax NPV-10 valuation. Our reserves metrics are strong with a 2P F&D per barrel under $5 and a reserve life index of 30 years, drastically extending the potential running room of the asset by double in terms of reserve life. A critical driver to these positive changes, while the 2021 successful drilling program, which provided valuable well calibration data that NSAI was able to incorporate into the analysis, increasing the 2P original-oil-in-place to 389 million barrels and the 2P recovery factor grew 22%, something we had always predicted. Because of this, the corresponding 2P book well count has increased from 15 wells to 22 wells, which fits the concept of having sufficient wells to sustain a long production plateau. We can now focus on derisking future probable and possible locations and moving them into the [ improved ] category in the coming years, just as we have done before. After all, we now show over 50 years of production above 10,000 barrels of oil per day under 3P development assumption and giving us confidence that reaching 25,000 barrels of oil per day should be our new goal. Slide 4 shows at a detailed level that we plan on drilling and completing 4 new wells in 2022 with recent completion of the prolific 10H well, which we brought on production on January 31, 2022, for 5 new wells in total. This slide outlines our well timing and estimated start date, which could be adjusted based on economic conditions and equipment performance. I would also like to point out we have some planned rig maintenance underway right now and again in early December as we plan for our 2023 program. Overall, we will spend an estimated $75 million in drilling and completion capital through 2022. Whilst all these wells come on production, we expect to exit 2022 at over 21,500 barrels of oil per day. We have also provided an updated location map, so you can see our focus in 2022 is in the southeastern part of the field moving to the northwest with the 14H well. Strategically, it is important that we continue to expand the boundaries of the field to obtain as much drilling data as possible for future reserves update. Slide 5 in our 2022 guidance summary. Here, we show the net result of the drilling plan shown on Slide 4 and the division between base and new production growth. I'd like to point out that when production is high enough and flush enough in its current state that if we stopped drilling, our production blowdown would be impactful and quickly dial the production and cash flow back to pre-2019 levels. This is why it's important for shareholders to understand the factor of wells concept that we emphasize in our strategy. A drilling plan of 1 well per quarter is optimal to maximize free cash flow in this trend environment and to scale the past investments in infrastructure that now let the company produce for an optimal production run rate of between 24,000 to 26,000 barrels of oil per day. Production will largely vary in 2022, with [ peak through ] passing 20,000 of oil per day, followed by aggressive base declines on various flush production that was seen in our previous wells. Overall, in 2022, we're spending $120 million in CapEx that is very evenly distributed throughout 2022. Aside from the $75 million in drilling capital, we are also investing in some important infrastructure and projects in 2022 and beyond. Some items include a new diluent tank and separators estimated at $10 million, allowing us more flexibility on how we transport and pay for diluent as well as many small production optimization and facility add-ons to optimize and enhance our processing of fluids for another $18 million. Finally, we're spending $15 million to engineer and started mechanical and installation work for the CPF-3, so the company could have optionality to handle the expected formation water production in 2023. Lastly, as you can see in the cash flow table, we're running our 2022 budget at $88 Brent. The forward prices stripped at February 7, 2022, and applying our current contract terms and cost structure to that top line. Based on those assumptions, we feel we can generate around $350 million in EBITDA under a mid-case scenario. We have also provided an EBITDA metric that investors can calibrate to, which highlights the large, expected influx of 2022 net true-up revenue expected from oil reaching Bayovar and settlement to the final contracted price. Doug Urch, our CFO, will discuss more of these and the financial details of the 2022 budget in the coming slides. Slide 6 is our way of communicating to shareholders that we're supportive of the return of capital requests and are doing everything we can as a management team to ensure the company can pivot to a material yield generator. We would like to explain how we intend to meet these requests via our 2022 financial strategy. Just to rewind, we have historically returned capital to shareholders, and this type of strategy is not new to PetroTal. When market and pricing conditions allowed in late 2019, PetroTal paid out over CAD 1.1 million in dividends with the intention of a recurring plan into 2020 and beyond. This was halted by the COVID-19 pandemic and the collapse in world oil prices. The bonds contain a restriction of any return of capital to shareholders. So in order to do so, we must either eliminate our debt or try to modify bond terms. Both options have costs associated with them. We believe that the best and most cost-effective way to activate our shareholder return policy is to build cash and return the bonds early as soon as Q3 2022, so only 6 to 7 months from now. There are strategic and financial reasons why this is our recommended approach, and we will cover these topics in the coming slides. To conclude, our board is supportive of this strategy and over the long term, will allow for hundreds of millions to be [indiscernible] back to shareholders through the life of the asset. We are excited to be able to deliver this if pricing and performance allow only 4 short years after having silver production and on the addition of the Bretaña field. Slide 7 shows that as part of our 2022 strategic plan, we have also been working hard to ensure we're maximizing sales flows to Iquitos and Brazil. The commercial team has done an amazing job of potentially expanding the Brazil route to allow sales of an estimated 12,000 barrels of oil per day. This will help minimize disruption risk and create healthy competition for our crude oil. We still intend to flow sales to the ONP pipeline. And if we were to stop doing so with a little pressure support from other fields, it would essentially hold or severally slow down movements to the ONP where we have over 2 million barrels currently for [ monthly ] basis for the true-up derivatives settlement. We're also exploring other small effective sales options which are in their commercial infancy. We wanted to touch on this slide in Slide 8 as it has some really positive messages. Firstly, we now have access to over 1.2 million barrels of total storage capacity, adding up all of the available and contracted areas we have, we can store oil into. Secondly, since we can readily sell over 13,000 barrels of oil per day to Brazil and Iquitos, we can now essentially continue producing oil for over a month just using our field and floating storage. Including our dedicated tankage at pump station 1 and 5, we can now -- we can continue producing for over 100 days at 25,000 barrels of oil per day run rate. This has 2 key benefits: commercial development risk mitigation and helping create cash flow stability or at least the Federal cash flow into storage compared to shutting in for extended periods of time. Storing oil, especially in barges, does have a cost, which has been evident in our past quarterly transportation costs. We view this as a necessary trade compared to shutting in production, and we'll continue to optimize our operations in this area. I will now turn the presentation over to our CFO, Doug Urch.

Thank you, Manolo. On to Slide 9. I'm Doug Urch, PetroTal's CFO, and I would like to start off by echoing my enthusiasm and confidence in this 2022 guidance. As Manolo indicated, under the 18,250 barrels per day budget case, the company expects to generate free cash flow before debt service of $230 million. Considering a base carryforward from February 2022 of around $30 million in unrestricted cash, we are really describing a cash flow allocation menu of $260 million under an $88 per barrel Brent price environment. The bar chart on the right shows our recommended allocation choices for that capital. To quickly summarize, there's a $20 million bond repayment option that we recently provided payment notice on, and it will be repaid in Q1 2022. This is followed by an estimated $30 million in cost for interest, factoring our ONP sales, VAT, lease payments and hedging collateral and cash costs for 2022. By mid-Q3 2022, once cash balances permit, it will take $85 million to retire the $80 million in remaining bonds. We feel this is the optimal time because we expect to have the cash in hand to pay it out, the call premium penalty stabilizes in Q3 2022 until mid-2023 at around $5 million, with little to no further benefit in waiting past Q3 2022. Post payout of the bond, a reasonable level of cash and working capital remain in the business and the business saves an estimated $8 million by waiting until Q3 2022 versus paying out the bonds in Q1 2022, as outlined on the next slide. Post bond payout and if economic conditions prevail, the company requires a healthy working capital buffer until revolving debt may become available. We estimate that, that cash buffer level should be between $50 million and $70 million, which would fully support a prolonged period of depressed Brent prices, future derivative margin cost and a smaller capital program with light G&A costs. Based on our mid budget case and Brent assumptions, this would leave up to $50 million available for dividends and/or share buybacks in Q4 of 2022. Lastly, we believe that going forward, being debt -- net debt free, is prudent in the current price environment given our capital needs at this time. Additional leverage may be considered for future M&A activity should the right asset be sourced and approved. Slide 10 summarizes why we believe Q3 2022 is the optimal time to retire the bonds. The staircase shows cash on the right and the bond balance with call premium on the left, aligns nicely in August and September and requires no refinancing to execute. Furthermore, the table shows -- the table below summarizes the incremental cost and savings retiring the bonds early would create. Management believes $8 million as an appropriate justification for waiting 5 to 6 months to retire the remaining bonds. By avoiding another refinancing, cash flow allocation to shareholders will be greater over the next 3 to 4 years with the sacrifice of only waiting 5 to 7 more months. Slide 11 has netback analysis. I now want to touch on a few key metrics regarding our 2022 budget. Slide 22 summarizes the 2022 program, mid-case and sales market. The royalties now include the previously announced 2.5% community trust payment, obviously prorated for downtime and our latest OpEx run rates. Of note in the table is our barging costs, which will now be broken down in more detail for investors. Barging in remote parts of the Peruvian jungle consists of 3 parts: service, standby and fuel. PetroTal pays for barge and fuel as we feel it is a more transparent way of doing business. In 2022, our total barging cost allocation will be around $3 per barrel with the actual barging service at $1.70 per barrel. On the diluent side, which is a major OpEx item, we want to remind investors that the $4.20 per barrel reflects diluent and diluent transportation costs at $88 per barrel Brent. The diluent is sold with our sales crude at our current contract sales routes and claws back approximately 2.8 million barrels -- 2.8 -- $2.80 per barrel. However, this is shown in revenue and not on a net cost basis. On a net cost basis, our diluent cost of the company, $1.40 per barrel. Overall, a $92 per barrel Brent price generates a contracted Brent price of $88 per barrel Brent, which generates a netback of $50 per barrel, showing a $38 per barrel all-in cost structure. This equates to a 57% netback margin, which is substantial for a heavier weighted crude oil producer. With our CapEx program of $120 million or $18 per barrel, there is substantial free cash generated on a per barrel basis. Slide 12 is an exciting slide, showing the 3-year free cash flow potential subsequent to our 2022 strategy. Assuming a 22 2P well development program and used in a heavily backward-dated Brent strip as at February 7, 2022, it's possible that the company builds over $600 million in cash through 2025, of which a substantial portion could be returned to equity holders under these assumptions and economic conditions. In Slide 13, we want to remind investors how the ONP contract functions and why it is still important to keep some oil flowing into the ONP. With over 2.2 million barrels in the pipeline and few other operators producing in the area, PetroTal's oil is providing the pressure needed to push its own oil through the ONP. As proof of that -- as proof that the current commercial contracts are functioning as expected, we have provided an update on what we have actually received in terms of true-up payments. To date, we have received over $31 million in true-up payments from oil reaching Bayovar and its final price being substantially higher compared to what was factored to us some time ago by Petroperu. In 2022 and at current Brent prices, this variation is expected to grow to over $70 million. With some derivative losses netted in to reach the true net payment of approximately $37 million in 2022. In summary, 2022 will be an exciting time for PetroTal investors as our investment considerations are unique compared to our peers. With the following to leave you with, as assuming current economic conditions will be debt-free in 2022, reinstatement of a return of capital plan post payout of the bonds, 100% year-over-year average production growth in 2022 from 2021, well over $0.5 billion in distributable cash generated over the next 3 to 4 years, 15 years of production at a higher than 10,000 barrels per day run rate under the 3P development case and further material recovery factor upside in the coming years. Thank you for listening to our call today. I will turn it back to the moderator for questions.

The ONP is quite expensive today. Do you see an opportunity to lower the costs in 2023?

Yes. Actually, we do. But keep in mind that the ONP contract ties the pipeline tariffs to Brent prices. That's why Brent pricing has gone up, the tariff has gone up some as well. The expectation, and this is something that we've been discussing with Petroperu is that once the Talara refinery is finally working and the oil will go to Talara, then we could have an adjustment on the transport prices, but that's still to be negotiated. But that will be our goal.

And what is the company doing to lower OpEx costs such as barging costs?

We use barging not just as a transportation arm but as a storage arm for the business. As such, there are additional costs that are factored when the barges are not moving, for instance, storing oil. In addition, when barges -- when barrels are not being sold, cost per barrel increase very quickly, which has been the case in prior quarters. This year, barging service is expected to be $1.70 per barrel plus standby and fuel, much lower versus prior years.

The company previously mentioned that it had equipment from early start of production are defined on Block 107 for around 5,000 barrels a day. Might you be able to elaborate a little bit more on that?

Yes, of course, although we are jumping a little bit as we still need to drill the exploration wells in Block 107. What I have mentioned is that the initial equipment that we brought to Bretaña to put that initial well drilled by the prior operator online, we could move that one. That equipment is idle right now in the field. We could move it to Block 107. And it will allow us to produce about 2,000 barrels of oil per day. I did not say 5,000, that's about 2,000. We can always [ exclude ] some extra production capacity. And the idea, of course, is to put that initial discovery, assuming we do the discovery on production and put the well on test as fast as we can, just like we did in Bretaña.

What investments are needed to be able to drill as well as produce from some of your leads on Block 95?

In Block 95, this year, we are working on obtaining the environmental permit to do seismic. We are -- we feel quite positive about those leads, although Envidia is considered a prospect. And the reason for that is that the Bretaña field was filled with oil to the spill point, which means that the migration of oil that comes from the north has continued -- should have continued going south, southeast and therefore, those leads assuming that they have closure will -- they have oil. So for that, we need seismic to make sure that they have closure. And then we confirm that we will need to drill an exploration well in each one of those to confirm that and we put them on production as soon as possible. We're very comfortable with that. We should have [indiscernible].

What does the budget increase in G&A costs in 2022 cover?

Contained in that amount is $4 million for social-related costs in 2022. With normalizing those costs out, our G&A represents about $2.70 per barrel, which is in line with peers.

The Q1 and Q2 production guidance of 16,300 barrels a day and 15,000 barrels a day seems low. Please can you talk us through how you arrived at these figures?

Yes. We need to keep in mind that the Bretaña field is a typical oil field supported by a strong aquifer. And the water from the aquifer is [ our friend ], we just need to manage it. That's why I always talk about building a factory to process fluids. And so these wells come in very strong. The [indiscernible] is extremely printable, 2, 3, 4 [ darcies of inability ]. That's why this well stand so strong. But then when the water finally breaks through and the water cuts start going up, the oil cuts drop, the typical decline on an oil well supported by strong aquifer is very much hyperbolic. So you're going to have some declines initially, especially you have a heavier oil like ours that is 19° API and eventually with settle down. You can see some of that in the actual Slide 3, and where we have, for the first time, broken up the production forecast, and this is based on NSAI's report between the PDPs, the PUDs, Probable and Possible. And you get a sense. And then at the end, you can get an idea of how this is going to be settled and been producing for a long, long time. Again, this is why we emphasize the concept of building a factory to process fluids that will allow us to maintain a plateau above 10,000. So we can have a strong free cash flow for years to come. Even at 5,000 barrels of oil per day, the oil prices are reasonable, we will be free cash flow for a long time.

The work on CPF-3 will start in April and it will then be ready by mid-2023. Do you expect production to exceed 24,000 barrels a day in 2023, therefore, requiring the new facility?

Again, we go back to that Slide 3, the production forecast by NSAI. You see that potentially; we could surpass the 25,000 barrels of oil per day. We are confident that based on the equipment that we have [indiscernible] now, although in the presentation, we talked about being able to manage 24,000 barrels of oil per day, we believe that we can go to 26,000, even, I believe, more than that. So the question is going to be, should we put more capital on oil facilities or just try to maintain a plateau at about 26%, 27%. And that's part of the conversations that we're having internally. For me, the most important thing is to make sure we have the equipment to process and reinject the formation water. That's key because by law, we have to reinject the formation water. And otherwise, we have to constrain production. So we will see how things shape up. But as you can see in the past, we always talk about reaching 20,000 barrels per day, and now we're guiding to reaching 25,000 barrels per day.

And when is the 11H well expected to spud?

It's expected to start by mid-March, as you see in the presentation. And the -- keep in mind that the rig is ongoing maintenance. So it's going to be very much dependent [indiscernible] contractor, it feels that the equipment is ready to [indiscernible].

You've hedged using a combination of puts and collars. How much production has been hedged with collars? And what is the ceiling price?

About 750,000 barrels has been hedged in the form of synthetic puts where PetroTal participates in Brent gains above $70 per barrel.

And how much production can be exported through Brazil currently? And what are the plans to increase this?

Right now, we're shipping about 8,000 barrels per day through the Brazil export and increasing to almost 13,000 barrels per day. We're currently testing a 400,000-barrel cargo shortly.

A group from a local district has said they may take action against Block 95 on February 28. Please, can you confirm how serious this action could be? And give a general update on the situation with indigenous people?

Yes. This is a typical, an unfortunate case where the government takes extra time to deliver on what's promised to them. And that's why, out of frustration, they have put out that threat. We feel that we can manage it and to avoid that, especially given some of the initiatives that we have put forward that the local people are looking forward to having been fully implemented, including that social fund that we have set up.

Excellent. And what is the status on the farmout process of Block 107?

There's not been much progress at all. And I believe that once -- as we are working to get the permits to drill in Block 107, we expect to have some interest coming back. We have time to try to bring up a partner, something that we are emphasizing is that we are again paying a lot of attention to the Osheki-Kametza structure. And you have seen -- you can see that in our main presentation that is in our website, and we are reducing the cost of that potential well. All of that should enhance our chances to bring up from a great partner.

And how's the fantastic result from the 10-H well been taken into account in the reserve update?

Partially, in the sense that Netherland Sewell, that's the reserves as of year-end, at December 31, we had seen the logs, so they could see the quality. But of course, they did not have the results of the actual well production. But the report was continuing after we put the well on production. So at least it was a check for them that the forecast on production was a good one. So that make them happy and more comfortable with the numbers that they put out.

Has the company used the latest results from 9H and 10H in its guidance for 2022? Or do you believe there is room to exceed guidance?

Well, the 9H, of course, because that well was completed in early December. The 10H, I just explained how Netherland Sewell actually have seen the results of the well in their models. Of course, we're [indiscernible] again, the room to exceed guidance, there's always room. I'm always very optimistic, but I have learned my lesson that we need to manage expectations, and that's why we have made it clear how is that we came up with this guidance. Therefore, this year, knowing there is some unknowns that we don't have full control upon, especially on the social side.

And does the company also plan to drill water reinjection wells? And if so, how many in the 2P case?

Yes. Of course, we need to drill more of the water injection wells in the map that you see on Slide 4, you can see actually the location of the future wells. The [indiscernible] is going to play a key role. We intend to drill that well early next year. And then seeing how things develop, we will need to drill 2, 3 more wells. Again, this is all about managing fluids and ensuring that we enjoy the benefit of a long plateau of oil production and free cash flow.

Assuming limited protester disruption to production in 2022, is it possible or a likelihood that the current production guidance will be beat given the production as of today is above 20,000 barrels a day?

Well, in this sense, that's sort of the message that we have given that we could be around that in a range of the 20,000 mark. We have no or minimum social disruptions, yes. We're very happy with the well -- wells are behaving -- is more -- I'm going to work hard to make sure that we can exceed the 20,000 mark.

Can drilling be sped up to react to higher prices as it seems rig maintenance -- as it seems rig maintenance costs are quite high?

The -- by the way, the rig maintenance is something that is done on a yearly basis since we started every -- at the beginning of every year, we have done with maintenance. Keep in mind, [indiscernible] in the middle of the Amazon jungle with all of that humidity, so it needs to be maintained properly. Otherwise, we could have issues. We only have one platform to drill wells from. Unfortunately, we're not in West Texas that you can bring 3, 4 or 5 drilling rigs at the same time. We can do one at a time. That's part of the issue of why you see production dropping some. We put a well on production last month, and then we do the rig maintenance, and then we drill a new well. And that new well won't come on production until May. That's why you see a dip in the production and then we [indiscernible] drill the other wells.

The oil-in-place in the 3P case is 2x the 2P case, what is driving the large uplift in the 3P case oil-in-place and what needs to be done to derisk the 3P oil-in-place? And when might we be able to expect these derisking activities to take place?

In the last couple of quarters, as we were completing these great wells in the 2021 campaign, I guess enough hints that the oil-in-place will go up some. The reserve will go up and both of -- happen. But I also had mentioned that I was expecting Netherland Sewell to narrow the large spread between the 1P and the 3P oil-in-place numbers. So this question actually targets that. And as you see, we go back to the Slide 4 and look at the map, you can see that it has grown potentially, it could grow potentially to the west. So there's additional potential reserves. And that's why Netherland Sewell have maintained that large spread between the 1P, 2P and 3P oil-in-place. One of the key wells that are going to help us understand that is when we drill the [indiscernible]. And you look at the position of that well, we want to target that to be able to enter the Vivian on top of a seismic line and that way will allow us to tie up our maps properly and give us confidence that we can continue growing west, and that will be fantastic if that is the case. So yes, we need to -- during the drilling campaign of this year and early next year, we're going to hopefully narrow the spread of oil-in-place. And hopefully, we can go towards the 3P case. Although keep in mind that we, as always, guided to the 2P oil-in-place number and we have always guided that the key for us was to ensure that the recovery factors were going to be higher, which based on our models [ if that was ] going to be the case, which we have seen with the new reserve report.

Management guided that it would spend $152 million in CapEx until 2023. The new CapEx plan is $120 million plus $100 million from 2021, meaning total CapEx now stands at $220 million against the earlier $152 million. What is the basis of this new change, considering that production would not top the 25,000-barrel capacity of CPF-2?

Well, essentially, it ties into noticing that the reserve report has gone up. So in there, we talk about the fact there are more wells, so 15 to 22 wells. So $100 million to $120 million in '22 would have substantially finished off the old 2P reserve case plus some additional facilities. Now with the larger [indiscernible] room, we are also starting to plan for the new 2P case with the additional investments starting in this year.

As I mentioned, we are very focused on making sure that we have the ability to process the fluids and the disposal of the formation water. And we're comfortable with the capacity of our oil processing facilities as we know that we can manage more than 25,000 barrel of oil per day, but it's all about the water. And [indiscernible] were supported fortunately by strong aquifer.

And with CPF-2 installed, can we expect lower decline rates in well productivity?

Yes. The CPF-2 -- nothing to do with the decline rates. Again, we have a strong aquifer support in this reservoir. And so the one thing is the facility is to manage the fluids. Again, we're building a factory to manage fluids. And the other thing is the way the wells are going to behave. What is going to come in oil production, the oil cuts are going to drop. Eventually, they're going to follow a very much hyperbolic effect for as you can see, again, on Slide 3, then the decline is lower, and this field is going to produce for a long, long time.

Has the company received approval to increase production to 25,000 barrels a day?

Not yet. We're now expecting it for later this week.

And would the company be able to give an update on the current state of negotiations with the local communities?

Well, yes. We have actually very active with the local communities, with the indigenous generations. We actually -- as you see in our budget, we were dedicating a lot of funds for that. And we are very optimistic that the Block 95, the Bretaña field will become an example for other oil companies in Peru. Keep in mind that now we have become the largest crude oil producer in Peru, we had 20,000 barrels of oil per day. And actually, we are, I think, the third largest liquids production including the condensate from [indiscernible]. And what we do, people are taking notice.

The 75% ratio of free cash flow mentioned in one of the slides, is that what investors can expect once the bond is paid back?

Well, that's too early to say. However, what we're trying to do there is demonstrate that using current economic conditions and the forecast strip price of $88 per barrel Brent. And under a scenario where there are no material downtime events that the business generates a large amount of free cash. If the company has no debt, it come assume that the company will do something proactive with that capital in the form of returns to investors and/or M&A. The payout ratio could include M&A from our perspective, but that is too early to predict that. We would likely keep $100 million for working capital purposes, representing about 20% of that. However, this is all subject to future pricing markets. And as well, we've talked about the possibility for Block 95 and 107. So those are all things to consider going forward.

What is management's expectation of the value of the existing PDP NPV-10 after tax at $95 Brent?

Can you repeat the question again, Mark?

Sure. What is management's expectation of the value of the existing PDP NPV-10 after tax at $95 Brent?

Actually, I don't have those numbers at hand at the moment. So we need to provide that as in the presentation, we only showed the total 1P not the PDP, but I can give the numbers.

And can the company comment on the current share price?

Well, we certainly like the direction that it's going and nice to see getting some recognition for the success that we've had. We still think it's undervalued that 1.5x enterprise value to EBITDA versus our peers.

And what is the company's best and worst-case scenario forecast to 2022's production?

Well, in the presentation, we made the comment that our range is between 17,500 to 19,500. So that's the range that we are thinking.

If cash flow for 2022 comes in above guidance, will the additional cash be distributed to shareholders?

Again, similar to the previous question, we're unable to say at this point in time. We will definitely prioritize shareholder returns versus other uses of free cash flow if that will generate the largest equity returns. So if the appropriate working capital and liquidity is in the business, we don't see why it's hard not to make statements as to what will happen, but certainly return to shareholder policy is important to us. And dividends is what we've done in the past. Of course, there are also possibilities of share buybacks, too.

And is the company receiving more institutional requests to participate in PetroTal Capital?

No, we have not. We don't need fresh capital. We like the fact that there is good volume in our shares, both in London and Toronto, even in the U.S., which helps bring the price up, but we don't need capital right now.

Will the company potentially look at doing a reverse stock split?

Well, that's certainly something to think about. And we've looked at that and gathered some feedback. At this stage, the feedback we have is that investors are somewhat neutral on that. So that's something that still is under review.

Apologies. Manolo, Doug, there are no further questions. So I'll hand back to you both to give your closing remarks.

Mark, I see something related to Block 8. I would like to touch on that.

Okay. We read in the local press that you're interested in Block 8; might you be able to elaborate on this a bit?

Yes, I would like to. I was asked a question about Block 8. Keep in mind that Block 8 is sort of a continuation of Bretaña. It's actually a continuation of Block 8. And my response was that [indiscernible] what we are doing in Bretaña is replicated in Block 8. That was from a technical and social point of view -- that was my answer. It's not that we wanted to be there per se. So anyway, I think there's some confusion. And actually, locals from different people in the different blocks, they are always asking about how come PetroTal doesn't go and operate Block 192, Block 64. Yes, they really are impressed on a company, we don't have a single expat in Peru, we're all Peruvians, extremely experienced people that have worked all over the world, and that has a lot of appeal. So that's why people asked what about this? What about that? And we always answer [indiscernible] it can be replicated. But for that, let's make sure that we do it right in Bretaña and we have yet to fully say that the social fund that we're working on and things like that. That's it. So I just wanted to clarify that.

Thank you very much for that. Now I'll hand back to you now, Manolo for closing remarks.

Well, I want to appreciate all of these wonderful questions. Hopefully, we have been able to explain what we are doing and what we plan to do. I'm actually quite amazed that from the initial review that we did over at Bretaña in -- at the end of 2016, 2017, when we were raising the initial capital and some of our guidance at the time, everything is coming true. And we will continue managing expectations very carefully. And as you know, in Peru, the social issues are a great concern. The fact that we are a team composed of all Peruvians helps quite a bit and the reputation of our team is such that I'm very hopeful that we can get things done for the benefit of all stakeholders. We are shareholders as well. So the idea of returning capital to shareholders is very important. I put my own capital when I setup the company in 2017, so I want that as well. So we're very much aligned with everybody. Thank you so much.