PetroTal Corp. (OTCPK:PTALF) Q1 2022 Earnings Conference Call May 26, 2022 10:00 AM ET

Manuel Zúñiga - President and CEO

Doug Urch - EVP and CFO

Dewi Jones - VP of Exploration and Production

Guillermo Florez - Deputy General Manager

Hello, ladies and gentlemen. Welcome to the PetroTal Extended Virtual Investor Meeting. Your host for this call will be Manuel Zúñiga, President and CEO; and Doug Urch, Executive VP and CFO.

On this extended webcast, management will provide further in-depth information regarding certain aspects of the Bretana asset, a run-through of the Q1 2022 results, further insight into the company's short and long-term strategy, followed by a Q&A session.

I will now hand over to the host to take the call away.

Thank you so much, and good day, everyone, and thank you for joining the PetroTal first quarter 2022 webcast and extended investor morning discussion, where we will provide a brief summary of our Q1 2022 operational and financial results, followed unscripted presentation of PetroTal's short and long-term strategy and robust value proposition. If anyone wants further information on the company, please see our website for additional materials.

My name is Manuel Zúñiga, and I am the President and CEO of PetroTal. And I am joined by my colleague, Doug Urch, Executive VP and CFO; and as well this time with Dewi Jones, our VP of Exploration and Production; and Guillermo Florez, our Deputy General Manager based in Lima. Both Dewi and actually - is also in Lima. If you have click on the link from last week's 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, please contact petrotal@celicourt.uk 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. And in addition, we have revamped the presentation with a new look and feel with some additional slides for context and transparency that we're excited to share with you.

For those that are new to the story, PetroTal is an onshore Peru-focused oil company. As shown in Slide 2, the company is listed on London's AIM market, in Toronto Venture Exchange and the OTCQX and has market cap of approximately $400 million.

Now I see that probably we're in the $450 million range. And net cash of around $9 million and trading at 1.2x estimated 2022 EBITDA. We have a 100% working interest in the Bretana oil field, which we have expanded from minimal production to over 10,000 barrels of oil per day in late 2019 and reaching over 21,000 barrels per day this past quarter despite material social challenges in March, which caused a temporary shutdown of operations for most of March and early April.

The Bretana field has 2021 year end 2P reserves of 28 million barrels and now has 11 producing wells with the 12th to be completed in late June 2022. All of our producing wells have paid out their initial investment as of March 31, 2022, with a field potentially having over six additional years of consistent drilling and a production profile lasting for the 30 years until the term of the license contracts and beyond, like many others surrounding heavy oil fields in Peru.

Despite the social challenges, Q1 2022 turned out to be a record selling quarter. And with the tailwind of the incredible robust Brent prices, our company is on course to deliver a transformative year of production, cash flow and social leadership in Peru.

We are excited to communicate our Q1 2022 results and we want to reinforce our strategy of being corporate debt free in Q4 2022 or early in 2023 with a minimum buyback and/or dividend strategy to follow, should it be economically viable, of course.

Before we recap the Q1 2022 operating results, I wanted to reiterate our main value proposition to shareholders with six key factors that drive success, as shown in Slide 3. First one, capital efficiency of under $5,000 per flowing barrel. We are extremely efficient with our capital and have a track record for successfully managing the field in a very capital-efficient way, having only deployed a cumulative $250 million since starting the asset in late 2017 and having reached over 20,000 barrels of oil per day.

We have delivered extremely attractive well results since drilling our first horizontal well in 2019 with the latest ones paying out in 100 months, while showing improved reserve metrics this year since PetroTal's inception. The field realizes natural pressure support from a strong water-driven reservoir and has no additional cost to shareholders and helps achieve strong fluid rates and long reserve scales over time, leading to high recoring factors from primary extraction techniques.

We delivered an excellent heavy oil cost structure that is scalable with production growth. There is sufficient drilling development running room for up to a potential over six additional years of drilling. And as number six, all leading to the most important factor and true differentiators versus our peers, the ability to generate growth and minimum free cash flow yield simultaneously.

As shown in Slide 4, PetroTal delivered an extremely solid operational quarter despite being shut in for just under six weeks. Quarterly production averaged a record 11,746 barrels of oil per day and 15,778 barrels of oil per day if just producing days accounting. This was up 60% from Q1 2022 and 16% from Q4 2021 and will be the company's sixth straight quarter of production growth.

Quarterly sales averaged a record 15,518 barrels of oil per day, up 80% from Q1 2021 and over two-fold from prior quarter. Capital expenditures were $17.5 million and weighted to drilling and completion work on well 10H early in the year, which was under budget by approximately 50% due to the social protest. Well 10H set a new company record averaging 10,500 barrels of oil per day over its first 10 days and paying back in four weeks, which was the main driver for the company reaching 21,000 barrels of oil per day twice in the quarter, also a record for PetroTal.

The CPF-2 facilities received government approvals to operate up to 26,000 barrels of oil per day of oil processing capacity, paving the way for future development. Current production for the month of May today is approximately 15,700 barrels of oil per day and drilling has commenced on well 11H on May 7, 2022, which is estimated to be on production in July 2022 at a capital cost of around $13.5 million.

Slide 5 shows that due to the social downtime and rig maintenance in March and early April, in 2022 drilling schedule was delayed and had the impact of reducing the number of drilled and completed wells in 2022 by one with well 14H commencing drilling at the end of this year, but with production started in early 2023.

Because of the mostly delayed production, we have had to revise 2022 production guidance to 15,500 barrels of oil per day, down approximately 2,750 barrels of oil per day from our original guidance of 18,250 barrels of oil per day, of which 11,140 was also due to shutdown of the field for most of the month of March and some of April and the remainder 1,610 barrels of oil per day due to the impact of the delayed drilling and extended rig maintenance.

Due to the incredibly strong Brent pricing environment, the EBITDA impact from the drop in 2022 production was more than offset by the rise in the forward Brent stream, now well over 100 barrels - $100 per barrel and up materially from $88 per barrel in the original guidance. Adjusted EBITDA, including the lower and revised derivative impact of $30 million is $341 million, which is relatively flat from the original budget.

As Doug will cover in the financial section, another key cash flow driver in 2022 which emerged over the last couple of months is our ability to sell oil to Brazil without diluent, adding up to $10 million to net operating income as a net 2022 impact. This was a direct result of having a great commercial counter-party and a successful commercial and technical effort led by our Lima team.

From a CapEx perspective, our total 2022 spend is revised down approximately $9 million as we look to defer some non-core infrastructure work into 2023 to maximize working capital in Q3 and Q4 2022 in preparation of our total debt repayment.

Finally, we have slightly increased our 2022 estimate of free cash flow approximately $1 million to just under $231 million before any debt service and/or working capital adjustments, which Doug will outline later in the discussion.

Before I turn over the call to Doug, I would like to take a brief moment to highlight a few important points regarding the social trust status and general ESG initiatives. Slide 6 is an illustration of how the social trust will operate and outlines the contribution from participating parties. The working table, as announced last month shared by the Minister of Energy and Mines, aims to coordinate purpose and actions of the social trust and was formally adopted by Ministry of Resolution.

This formal framework establishes the central element for further development of the social trust administrative body with its main purpose to identify and propose actions based on an appropriate and respectful dialogue process aimed at improving the state response to requirements of Puinahua district population where Bretana is located.

The social trust will continue to develop its administrative policies over the course of the next three months with the formal adoption of the working tables seen as a major milestone. As you can see in the graphical illustration, the less carbon concept is incorporated into the social trust investment policies, a material stack of capital can be used to generate investment amount in perpetuity.

On Slide 7, we are highlighting some of the areas of focus in our upcoming 2021 ESG report to be released over the coming months. A particular note is our carbon footprint per produced barrel of 13.8 kilograms per produced barrel of oil for Scope 1 and 2. This is well below some of our peers and a leading indicator of the minimal environmental footprint we have in Bretana.

Let's go to Slide 8, please. I'm Doug Urch, PetroTal's CFO, and would like to start off highlighting a few select financial items from our recent press release with visual support in Slide 8 and from our recent publication of the other corporate presentation.

From a balance sheet standpoint, PetroTal exited the quarter with over $52.9 million of total cash compared to $75 million at the end of the prior quarter. The decrease is substantially due to working capital burdens related to our Q4 2021 program and early Q1 2022 drilling programs. The company had its strongest quarter to date achieving records in many financial areas to complement strong operations.

To summarize, PetroTal achieved the following in this quarter. Achieved record revenue of $92 million, representing $66.41 per barrel; realized record net operating income of $64 million at $45.96 per barrel and realized record EBITDA of $59 million, representing $42 per barrel; delivered record free cash flow before debt service and working capital adjustments of $42 million; generated record net income of $65 million for the quarter, which was higher than all of 2021 combined and an indicator of our favorable below the line non-cash charges to our P&L.

Royalties for the quarter were $6.4 million, representing $4.56 per barrel and represents 7% as a percentage of total realized net revenue. Lifting costs were just over $10 million and stable on a per barrel basis from prior quarter at $7.20 per barrel.

Variable costs, mainly diluent and barging, were $12.1 million for the quarter, $8.68 per barrel and with Brent increasing over 50% from Q1 2021 driven by increased diluent and diesel price and diesel transportation along with increased loading storage used in the quarter.

G&A was $4.7 million for the quarter at $3.38 per barrel and down 28% and 43% from Q1 2021 and Q4 2021 respectively on a per barrel basis. PetroTal achieved an incredible milestone in the quarter, delivering a record $41 million of free cash flow prior to debt service and working capital adjustments. This allowed the company to pay down $20 million of its corporate bonds on April 1, 2022 and bolstered cash and working capital reserves to pivot through the social protest downtime.

As mentioned earlier, the 2022 revised EBITDA guidance is stable at $341 million, including an additional $13 million in true-up revenue related to restructured barrels in the ONP pipeline that will be realized when the journey through the ONP is complete.

Due to the ONP being down for maintenance, the next true-up payment will not be realized until October or November of 2022 with $40 million to $45 million now being deferred until 2023. Also of note, PetroTal is technically net debt free as at Q1 2022, which represents a major milestone for the company. The net cash position at March 31, 2022 was $9 million. Please see our corporate presentation for the definition of corporate net debt.

All bond covenants were met as at March 31, 2022 with no forecast reaches in our revised 2022 budget. From a valuation perspective, at our current share price, PetroTal is trading at 1.2x 2022 EBITDA and less than 1x 2023 EBITDA, well below peer average in LatAm, Europe and Canada.

At March 31, 2022, PetroTal's corporate hedge position for the remainder of 2022 stands at approximately 1.2 million barrels with strike prices around $70 per barrel using foot structures. Approximately 830,000 barrels are hedged in the ONP under predominantly swap instruments. Both hedge books have an estimated mark-to-market loss of $27 million at March 31, 2022 and are factored into the realized $13 million net derivative impact for 2022.

Currently, in the pipeline, there are over 3 million barrels and that represents a value of approximately $86 million in true-up revenue. After factoring the estimated $27 million losses, I just mentioned, PetroTal has a net derivative asset of $59 million on its balance sheet that is fully realizable over the next 15 to 24 months.

In summary, PetroTal remained incredibly resilient around March's social downtime event from a financial perspective and we'll continue to make commercial and financial decisions that provide shareholders with a risk-adverse, stable liquidity position.

On Slide 9, despite the ONP being down for maintenance, the commercial team continues to show resiliency in the face of challenges, accomplishing two main commercial goals that will have a long lasting impact on cash flow.

First, Brazilian shipments have now successfully been upsized to 16,500 barrels of oil per day. This commercial win paired with the now upsized Iquitos shipments of 2,000 barrels per day, PetroTal can successfully ship 18,500 barrels per day without using the ONP pipeline route. As mentioned earlier, the Brazilian shipments can now be sent diluent fee, creating up to $10 million in additional net operating income in 2022 and significantly shrinking PetroTal's transportation costs.

On Slide 10, finally, PetroTal would like to reinforce its message to shareholders that its current strategy of debt reduction followed by meaningful return of capital policies will be more lucrative to shareholders in the long run under our continued development program. We look forward to updating the market on further developments as the year progresses.

On Slide 11, we have updated our 2022 cash waterfall chart showing a strong liquidity profile throughout the year with various uses of cash, ending with over $60 million of potential discretionary cash flow.

Thank you to all the investors who called in. And I'll turn it back to Manuel, who will start the informal investor presentation. Thank you.

Thank you, Doug. And again, good morning, everyone. Let's go to the presentation that we posted and make sure that it's for everybody to view. Jimmy, is that presentation now available for everybody?

I believe so. Yes, Manuel.

So I always like to start with this initial front slide and this is a different picture that we have shown before. It gives you a very good view of the Bretana field. And as you look at, that's actually the Bretana community is about a mile long. It starts adjacent to our field and they ends up on the other side of the river.

So we interact with them very closely. Again, the field, as we will show you in the presentation, is quite large. It has like 6,000 hectares, that's close to 15,000 acres. And we are developing that on our footprint that is living hectares, very small.

Across the river is in fact the Pacaya Samiria reserves. And we work very closely with the state entity that manages that, and I'll show you some of that. I always like to start with that. One of the reasons that we keep our costs down, we were fortunate to be adjacent to the river. We have always tried to manage the river because it can have erosion issues and so on. But this is the Ucayali River that, as I'll show you in the following slide, if you go to the next slide, please.

You see how to the north it joins the Maranon river, as you can see in that map, and it forms the mighty Amazon river. I always like to highlight that. And also the fact that the Amazon river is counted - is leaned from all the way south in the area of Arequipa in Southern Peru, that's where my father was born. And this is why it's probably, I think, the second longest river. And for sure, it's probably one of the strongest in the world. That allows us to move barges back and forth. And as those - the rivers are the highways of the channel, as you can imagine.

Some of the numbers on the left hand side, already I just mentioned them to you, but I would like to go back to the map and showcase that in the Bretana field, that is part of the Block 95 adjacent to a river, produces from the Vivian formation. That is same formation that in the blocks to the north have produced more than 1 billion barrels of oil per day - I mean, billion barrels of oil.

And most of that, 70% of that or 700 million come from the same Vivian formation, highly permeable, supported by strong natural forces. But when we took over the field, we had to manage that. And we set-up a team initially of senior technical guys, 12 of us and Dewi Jones is also - that will join us later, is also ex-Occidental Petroleum, knows this type of environment. And that's why we've been able to execute as well, of course, now using technology that was not available in the past.

I always like to highlight the fact that just that we see big numbers on these fields, just to the south where those purple lines start, that's the Kametza project that has more than - or used to have more than 20 TCF of cash reserve, more than 1 billion barrels of condensate and has two lines going to the coast, one for gas and the other one for liquids, which are later fractionated, produces more than - about 1.5 Bcf per day and about at one time, more than 100,000 barrels of condensate, now about 90,000.

Again, I mentioned all of that just to give you the idea of the size of projects that we could be pursuing in the future, which for the first time on this presentation, we are going to give you some more color of what we are hoping to accomplish just on our two main assets; Block 95 and then the Block 107 where we have this large Osheki-Kametza prospect.

Let's go to the next one. We have already discussed a lot of these. Let's go to the following one, number four. Also like to always emphasize and tell a little bit of the story for people that don't know us that much.

We were able to buy the Gran Tierra Peru assets at the end of 2017. At that time, Tierra used to have five blocks. We quickly returned three of them and retained of course Block 95 where Bretana is located. That contract lasts all the way to the end of 2021. And we of course retained also Block 107 because we saw a large potential in those prospects and leads.

When we raised initial money, we ended up with a total of $52 million and it was to prove the concept of Bretana. We promised our investors we were going to put that original well builder of Gran Tierra on production in less than a year and for less than $25 million.

And we ended up doing it in five months, that well was already online. We say that all of the equipment - initial equipment, it costs $17.5 million. That has set the stage from then on how the team is being executing.

We also told investors very upfront as people know me, that this initial capital was just to test the concept, which meant that we needed to drill a well across the river into Pacaya Samiria reserves, a deviated well and that will prove the concept, which we did, but we have told investors, we're going to have to come back and raise more capital, which we did, and it was very welcomed in the market. We were able to raise $25 million gross.

And by the end of 2019, we had already reached 10,000 barrels of oil per day, just as we had promised investors. Unfortunately, 2020 hit us hard - hit everybody hard with COVID. But in our case, we had ensuing social unrest, which we are working very hard, as you know, to try to resolve not only for Bretana and our growth, but for entire oil business in the jungle and maybe other industry like the mining as well, which means we try to empower the local communities as much as possible in a good way.

And then in early 2021, after we had done an initial pilot export via Brazil, we raised $100 million in bonds, which as we have mentioned in the presentation, we intend to pay as soon as we can, hopefully before the end of the year, so we can start giving money back to investors. But one thing that we promised also and that was the main model of the proposition - business proposition when we raised the initial capital in late 2017 is that we promised to triple the investors' money.

And I'm glad that early this year, we actually tripled the share price of the company. And I've seen some of the analyst reports that talk now that we could actually triple that again in the next couple of years. And I can assure you that the whole team is very eager to continue providing more value to all of our investors.

Let's go to the next Slide number 5. This one actually I like this slide a lot. And in the past, we had sort of a split. Again, the value proposition. We started with 2P reserves in - it was in the order of 40 million barrels, 37.5, 3P of 75.8%. And we have made sure to investors that our experience in the Amazon jungle even in the Oriente of Ecuador is that fields usually end up being twice as large as originally estimated by the geologists and the reservoir engineers and so on.

And we have basically, I wouldn't say proven yet, because they're still on the 3P category, but you can see that from 76 now we're at 147 of 3P reserves as of year-end. However, at year end 2021, we had already produced 7 million barrels. So actually, it's 154 million on an EUR basis, which is the estimated ultimate recovery. On the 2P, it used to be the initial 3P. So that's key for us.

We have in the middle of the chart, you can see our production forecast. This is certified by Netherland Sewell. I was in London in March. I met with a few investors. And some of you may remember that I will draw with a pen, you know that given that our CPF-2 can handle about 26,000 barrels of oil per day, we will probably try to maintain that plateau. That's the way Netherland Sewell certifies the 3P case and we will see how we manage that. But I expect the team to continue delivering as they have been doing it all along.

But one of the also main proposition that we gave investors at the beginning is that this project, it was going to be cash flow - free cash flow for years to come. And in the white line, horizontal line at 10,000 barrels per day, it shows that now we have actually I think 60 years beyond - above 10,000 barrels of oil per day. We started with eight and then we moved to nine and 12. And again, that's because we are being able to drill wells and we'll show you a little bit more about that. They are very prolific and that's the intent of the company now as we get to know the field better.

The bottom table, you have probably heard me say before, we still have a larger spread on the oil in place from the 1P oil in place of 247, which initially was 180 only, to 3P or 618, which is actually larger than what it used to be at the beginning. Of course, that reflects into the number of wells that we can - in that drilling in this. We started on the 2P case with a total of 12 wells. Now we have a total of 22 wells.

Interestingly enough, you can see that now with the reporting factor is 22%, originally it was 11.5% and now it's 22%. That was another thing that we have told our investors. The value proposition here is that you invest on a 2P conservative recovery factor. And then with the proper drilling and development, we should be able to double that. And here we're at 22%. And of course, in the 3P case, it's 25%. But of course, that involves a total of 29 producing wells.

Part of the concept as well is the fact that we have told investors that we're building a factory to process fluids. The more fluids we process, the more we can extract oil out of the fluids. Don't forget, we have a strong aquifer, the water, the formation of water is out of frame which I need to manage properly and we need to make sure that we can dispose of it properly. So the more we manage, the better off we are. And at the end, I have those numbers to showcase.

This is important for us. When we started the company, the original 2P oil in place was 329. So at a 1% recovery per well there was 3.29 million barrels per well. Now it's basically 3.89 million barrels per well. And that's what we see also on an average basis of course. Some are going to be higher, others are going to be lower. That's the concept.

And of course, what we expect by the end of the year is that the spread between the oil in place in numbers of 1P to 3P to narrow. And I have always guided that we should be closer to the 2P case and it's us being able to recover as much oil as possible, try to move into the 3P reserve basis and squeezing more oil out of the Bretana.

Let's go to the next slide. On this, I would like to highlight a couple of things here. As you know, in Peru, given all of the issues that we have, we cannot just follow ESG. We have to actually lead on ESG. And given that we're next to a reserve in Bretana, the Pacaya Samiria reserve, and even in Block 107, we are in the San Matias and Thomas fully reserved. And so we - our team is used to working very closely to try to protect and enhance the natural beauty of these areas, and that's actually what we have been doing.

Last year, the [indiscernible] that manages all of these, gave us a price for how much we're helping protect nature here. And look at in the top left second bullet or second check, I mentioned that earlier, how we manage our CO2 and we intend to continue dropping that and eventually being completely neutral. That for us is extremely important.

I'll show you a little bit more about the 2.5% also, but on the fore winner side, let's go to the next slide, and we'll show you a little bit more about all of these. Here, on Slide 7, we always try to make sure that all of our efforts have a vision. And of course, these are poor communities that were forgotten by the government.

Even though a lot of oil was produced in the Amazon jungle for the last 40 years, most of the money went to Lima, the capital of Peru or Iquitos, the capital of the Amazon jungle. They forgot all of these communities where the production was coming from. So of course, we're changing that.

And in the meantime, we have to work very closely now especially as the company grows to tackle some of the key issues. A lot of this of course are the empowerment concept that 2.5% should allow them to do it themselves, of course with our support because we know how to manage projects, but we have to tackle the medical issues. I have always been a firm believer, education is key. The future or any country is the education or the young people. And you can see how we're managing that.

There are some projects that are important. These are people that like water, like power. So we are working on that. Some of the landmarks, library, for example, that's something I firmly believe on, but then also help them setup projects. I'm an entrepreneur, I know how to setup companies and we're trying to provide them with training and support for them to do their own things. And some of these projects are quite fantastic.

We are, for example, providing them commercial ice makers so they can take care of their fish. One of the largest fish - freshwater fish in the world [indiscernible]. We have now a joint venture with a famous chef in Peru to allow them to actually package that and export it. So these are beautiful projects that we're working on and very proud of. You can get a sense of our vision here, sustainable development. That's the key for us.

Let's go to the next one. And here it's about 2.5%. I did touch earlier a little bit about this. I have been paying attention to the Alaska model that - and it's quite amazing what Alaska did 40 years ago. Amazingly, the Alaska pipeline was built and completed about the same time as the pipeline that we are using with the ONP about the same time.

It's a different order of magnitude, of course, Alaska was able to produce more than 2 million barrels, while the jungle only reached 200,000. But imagine if the Government of Peru would have done the same 40 years ago, we would not have any of these issues. They would have had the money.

So under the 2.5% consent, and it helps of course that our royalties are low. Our royalties start at 5%, 25,000, it's going to be 8.25% net of transportation. It's actually 7.5%. So we are able to provide that 2.5% and we're working with the government to make sure that they can do this - predicate this in other places.

But I've been telling the teams that they need to follow that model. That half the money needs to be saved because this is as the Alaska model shows, they actually have it. It says this is for the life plus petroleum. And here, we need to do the same. Make sure that the future generation will have some source of funding or they can develop the project and so on.

I believe that this would change Peru for the better. And I'm hoping that we can accomplish this and the whole team and the government now is fully involved working with us as well and as well as the local people. The majority of the people in the Bretana area and the Puinahua district, support this concept. And also we're working very closely as well as with the indigenous communities, of course, to make sure that everybody is fully aligned.

Let's go to the next one. So here, we are now in the - a little bit of the technical side, Bretana field. As I mentioned before, it's 6,000 hectares. That's close to 15,000 acres. But it's interesting to see that like 6,000 city blocks. That's the size of the Island of Manhattan in New York. That's the size of the field. And I remember when we used to raise capital initially in 2017 and I visited some investors in Denver and I told them that we were going to develop.

At that time, we had a total of 20 wells on the 3P case field that was that large with 20 wells, they thought I was crazy. I had to explain that these are highly preamble sands and we're going to drill horizontal wells, most of them, and they are going to produce a lot of oil, they could not believe it. Funny enough, one of those are actually now I believe an investor of ours, because it's truly amazing how these wells are going to behave in the future.

On the right hand side, you see - and looking at the color, you can see the wells that have already been drilled, which are the black ones. The whites are the current development plan. These are all proved locations. And then the red is the probable locations and then the P3, the possible locations. And we have been very careful. We drilled pad location, a proved and developed location. And then the P2 location should have proven-up as we are drilling into the pad location and so on. And you see how there we are expanding and reaching out and reaching out and we've got to be very careful.

You may have seen some of the older maps. The field changes somewhat. We have a little bit more to the left hand side and it's going to be important to see how the 11H, we hit the deviant and then the 4WD also should give us a lot of information to be able to assess the true oil in place in the next few wells.

But again, one of the propositions, as I mentioned earlier was, when we started, we started at a 12% recovery that we are going to be able to do much more than that. And I think now there's a quite a bit of consensus even with Netherland Sewel, our auditors, that we should be in the 20% range.

Let's go to the next one. So this is the drilling campaign. And unfortunately, the combination of the detailed rig maintenance that we did early in the year, which was slowed down by the social unrest in most of March, the people doing the rig maintenance had to leave the field. So it took us longer.

So that have delayed things. But fortunately now as we start the drilling campaign, you see that red arrow is coincide when we expected - actually Petroperu have told us that they expect to have the maintenance on the pipeline ready.

And so just in time when they well 12H comes in and we're going to need to use the pipeline again. But in the meantime, as I mentioned in the earlier presentation, now being able to go all the way to 100,000 barrels of oil per month to Brazil, minimizes the need of the ONP, that's the pipeline.

And unfortunately, for the 2022 numbers, the well 14H comes in now early next year. So it's a delay on the production. But we're very steadfast on our approach, building the factory that we need as many wells as possible.

Let's go to the next one.

On Slide 11, I want to talk about the revised 2022 guidance that we provided. Now that we've completed Q1 and we can assess the impact of the social unrest and not being able to produce for about 30 days at that point in time, we'd like to go back from our original budget, which you see identified there in the third column, and look at where things stand at this point and what we expect the balance of the year to be. And that's what you see in the column in the middle in the dark box.

So in essence, the key item first of all, it's the production has dropped from - we expected an average of 18,250 barrels per day, it dropped to 15,500. So it's been reduced. And why is that? Well, as you heard Manuel mention and you can see summarized at the bottom above the charts - above the chart at the bottom, the reduction of 2,800 barrels per day, two reasons for that. One is a result - just having to shut the field in for the month. So losing about 1,200 per barrels per day, representing an average for the year. So that represented a part of it.

The other part is due to the delayed drilling, as Manuel mentioned. So by virtue of that drilling is not happening and we just started drilling recently. So that 1,600 barrels per day pertains to just a delay. And so - especially the well that we're going to drill at the end of the year has now been deferred into the following year. So production has been reduced to accommodate that actual information for Q1.

And then - but also, what is the other thing we took a look at. We took a look at pricing. Well, oil prices have changed dramatically from when we published our original budget back in mid-February. We used an average contracted Brent price of $88 per barrel. That was our projection at that point in time, representing the forward strip.

Now when we used the price recently, about a week ago, the average is about $103 per barrel. So now we're factoring in the higher pricing. And you can see the resulting impact on net operating income. $335 million was the original budget and now it's $351 million. So fortunately, higher oil prices have offset the reduction and delayed production of 2,800 barrels per day. So we're on track still with our net operating income.

G&A remains the same. And then you see the derivative impact. That has changed a bit. It's been just delayed as a result of the pipeline. So we're now realizing - expect to realize $13 million of the true-up revenue in the current year. The balance will be pushed out into 2023. And you see that now reflected on our balance sheet between the short-term and long-term portion.

Takes to adjusted EBITDA. And that's basically still on track with where we were $350 million in the original budget, now at $342 million, pretty much on track. And then you look at the CapEx. CapEx has been reduced a little bit because some of the infrastructure projects have been deferred into 2023, so down to $111 million.

So as it turns out, free cash flow expectations for the year are about the same, $231 million and comparable to our original budget. And so this - and I just want to point out that prior two years that we're showing on here. Even in 2020, that's a very difficult year for the world and the industry, our adjusted EBITDA - we've always had positive adjusted EBITDA. So - and that has continued to increase, a nice bump into 2022.

At the bottom, you also see that quarterly production. So consistently - and we're increasing production as a result of the ongoing drilling program. And I just want to point out, in case people didn't see it in the press release that Q1 2022 production of 11,800 barrels per day, that essentially represents considering the field was only on six to seven days during that quarter, that's about 15,800 barrels per day.

So that's what it would have been had it not been for the social unrest. And now you can see our projection going forward. And we continue to have a buffer built into our production guidance. Right now the buffer is about 10% for the balance of the year, representing if there are any additional social issues that come up or just any technical or maintenance issue. So we do build a buffer in for that.

Just to point out, the impact of oil price changes, production changes on our free cash flow, you can see that metrics at the top right. And the two bullets in there are the numbers that we have in our current guidance of 2022. But you can see then that if production went to 20,000 barrels and prices were $110, it would be $371 million. So you can see our sensitivity both as prices increase and as they reduce. I think those are the key items there.

And then the next couple of slides, I would like to have Guillermo Florez describe them. And I would like to introduce Guillermo. As I mentioned earlier, he is our Deputy General Manager. He is a young executive. Very promised future career. He has been instrumental actually on the exports to Brazil as well as the ongoing dealings with Petroperu. Even a potential future new contract once the current contract - the pipeline expires.

So I'll have Guillermo go ahead for the next two slides.

Thanks, Manuel for the introduction. Good morning. In this slide, we are showing the three main roads for our Bretana crude oil. It's in Iquitos refinery. Exports through Brazil on that pipeline. Iquitos, the reservoir preferred market is now taking 60,000 barrels per month. Now that the pipeline is closed for maintenance, we are exporting between 400,000 and 500,000 barrels per month through Brazil. In the short-term, all remaining oil could go then to the pipeline one it's fully operating valuable mining.

Iquitos, you could see it's located 355 kilometers away from Bretana. We access to the refinery by river. We barge the oil and it will take us approximately three days to get to the refinery. For the Brazilian exports, which is our second main market, we continue selling FOB Bretana where our client takes property and risk and then they barge it until the Manaus terminal that is located approximately 2,100 kilometers away from Bretana.

To reach Pump Station 1, which is our currently point of sales in the Petroperu contract, it takes us four days by barge. So very, very close to our location. In terms of storage, including the tanks in Bretana, for 90,000 barrels capacity and the different markets, we have approximately 80 days of autonomy considering a production of 15,000 barrels of oil.

The next slide, please. PetroTal has invested near $100 million in production facilities since we started the project back in 2018. We have invested on a modular basis through a very disciplined capital allocation. With a permit already granted, we have capacity to produce 26,000 barrels of oil per day with the CPF-2 finally completed.

All facilities are located in the Bretana North surface and you could see in the picture below on the left, which is adjacent to the river, facilitating the logistics of selling crude and all the materials management in general.

The fact that we have drilled all our existing wells from the same pad, it has considerable efficiencies and let us minimize and optimize our footprint. As part of the production facilities, we started last year leasing power generators that bends our crude oil which ended up increasing our net present value in approximately $100 million. This is basically the information that allow us to continue generating value and which set the future for this year investments and continued development a few.

Thank you, Guillermo. Just to let people know, Guillermo reports to our General Manager, whose name is Lucho Pantoja or Luis, but we call him Lucho Pantoja. Lucho is a true operations expert. He actually worked for Occidental as well. He is one of our Occidental guys in Block 192. At that time, it used to be known as Block 1AB in Block 8, also in Kametza.

So he has to work in the three largest oil and gas projects in Peru. Lucho replaced our prior general manager who retired, Ronald Egusquiza, in the beginning of the year. And I have the fortune to continue having access to Ronald. He is actually here with us in Houston now because he's supporting my efforts on the sustainability side of the company. I'm very happy to have Ronald advising the company and both Doug and myself directly. That's fantastic.

So go ahead for the next one.

Sure. Let's go to Slide 14, please. Equally important to PetroTal is looking after the communities and the areas that we're operating in and providing that empowerment. Equally important for us to have a shareholder return and provide feedback and a return on your investment.

We recognize the importance of the shareholders that have invested money along the way and continued to show support for the company. In fact, back in 2019, when we had a very positive cash flow at the end of that year, we declared and paid our first dividend to investors. And it's important for us to maintain a capital investment, but also very important for our return strategy.

So let's look at what our options are on this slide here. So essentially then the steps are required is that - and of course, this is all subject to board approval and economic viability as things go throughout the year. But we won't need any further financing for the programs that we've talked about and have portrayed here, both currently as well as on the longer term going forward. We're self-sustaining in that sense.

So the key then is to pay out the debt that we took on last year. And again, the $100 million of bond that we realized last year, that was really an important catalyst to get us going again, get the drilling and get the production that we're currently at. So first step was on April 1 of this year, we repaid $20 million, leaving only $80 million of the facility available that we continue to use, and I'll show you what we'll do with that.

So with the expected 15,500 barrels per day of production, that will deliver consistent production throughout the year and the cash flows that we've talked about. And so it's our intention with the cash flow that builds, especially as we see it in Q4, maybe early in Q1 2023, but certainly towards the latter part of the year, expectation is that we could retire the remaining $80 million. And that would then free up first from the covenant that we aren't allowed to pay any returns to investors while the bonds remain outstanding. So that really is a key priority for us.

And then what will we do after the bonds are retired, well, then we can look at share buybacks, and that's subject to the exchange rules that you can only buy back a certain amount. It's very important to have a regular form of dividend. So we would look to build that into our structure going forward.

And then we'd also use the funds after we needed for the Bretana development, the 2P and perhaps going into the 3P depending on how those reserves morph into that other category, as Manuel mentioned. So we then will have some funding available for continued development on Block 95 and 107.

Let's go to the next slide. In the initial, it's like to get a sense of what we have accomplished in this couple of slides, just very briefly, the basic strategy for the next three years. And as you can imagine, debt-free balance sheet is key, Doug just mentioned about that. The execution of 2P.

We will try our best to update the 3P as well, building a factory. And for that, you need to have as many wells as possible. Returning money to investors. I always say that my wife will be very happy if that happens as well. And then, of course, we have a potential in Block 95 and in Block 107, we'll look into that. So in the next three years, we're very focused on that.

Let's go to the next one. On a long-term basis, we have promised that PetroTal will offer long plateau or free cash flow. Of course, that is the key for us. And once we are done with all of the drilling that - even during the drilling, there should be a lot of free cash flow, but that's in concept. We offer that. And now we've promised something, I will do my best to deliver. ESG, we have covered that already. And you'll see how beautiful from another view of Bretana where we are located and how we take care of everything, the free cash flow for years to come. And always, always optimizing things always.

Guillermo mentioned and I have shown in the past when I showed the facilities of Bretana, setting up this power generation using our own crude oil instead of buying expensive diesel. That's increase in net present value of the company by $100 million. Now we're saving about $2 net on diluent because we're sending oil to Brazil with no diluent; always, always optimizing things.

So let's go to the next one. And we have now Dewi Jones that I will like for him to cover the next four slides. Dewi Jones, we worked together in the past and others, as I mentioned, Oxy person, extremely experienced. He is actually an exploration expert by nature. But of course, knows a lot of our operations. That's why he's the VP of E&P. I would like Dewi to please cover those slides briefly.

Thank you, Manolo, and good day to all. I wanted to give an overview of the petroleum geology of the area and the basinal areas, especially where we have our main assets. As you know, we are in the Maranon Basin of Peru, which is actually a subbasin of a major foreland basin in South America that we call the Greater Maranon Basin. It encompasses the Maranon to the south, the Oriente basin in Ecuador and the Putumayo Basin in Colombia.

The interesting fact here, of course, is that this is one of the most important petroliferous basins of South America with reserves or accumulated production of up to 8 billion barrels if we take into account the three basins involved. Of those basins, the Oriente basin is the most mature and of course, the most productive. And there's giant fields in the Oriente basin, Shushufindi and Sacha, specifically with 1 billion to 1.3 billion barrels of oil in these basins.

And one of the interesting facts is the Maranon subbasin is probably the most underexplored in the whole of this area of South America. We, of course, at PetroTal, think there's a lot of potential not only in our asset and our Block 95. And as I'll show you a little ahead - further ahead, we have identified other prospects and leads in our Block 95.

The other point I want to make here, if you see the stratigraphic chart in the middle of the slide, we have very similar topography, of course, in this large basin for the Putumayo, Oriente and Maranon. The main source rocks to the north in Putumayo and Oriente is the, what's called the Villeta in Colombia, the Napo in Oriente, and we call that Chonta in Peru.

However, in the Maranon in the Peruvian soil, we have an additional source rock, which you see at the bottom of the chart of the Maranon, it's the Pucara Group. It's a carbonate source rock that makes two petroleum systems that are active in the Maranon Basin and that's not the same situation in Putumayo and Oriente. So we have this additional petroleum system that actually the Pucara source rock is the source rock for the oil in the Bretana field.

And this is an important fact because we're looking at migration halfway from a pad of mature source rock from the west. But as I'll show you later, there is a potential in our Block 95, a potential even deeper source rocks over Paleozoic. So we are very enthusiastic about continue exploring not only developing our main asset, which is the Bretana field, but a continuation of the exploration with the potential of finding some additional Bretana in a trend that I'll show you in a different slide.

So the Bretana field is a structural trap. It's an anticlinal, very subtle anticlinal feature. It was used by an inverted fault. As you can see from the seismic line the - or sorry, Slide 18, please, if you didn't get that. I'm sorry.

The Bretana field, a very subtle trap inverted fault. And the interesting fact of this type of structure is that if you go from Colombia to Oriente in Ecuador, to Maranon, it is the main dominant trap play concept. This has size ranges. As I mentioned, Ecuador has giant fields is up to 1.3 billion barrels. Bretana, of course, as Manolo mentioned, we have 2P reserves at the moment of 78 million barrels with the potential growing also if we go into the 3P. But the Vivian formation is the main reservoir.

And I'll go to the next slide, Slide 19, to describe briefly the Vivian. As you can see in the right - in the left of the slide, there are two processions, one north to south and one west to east. You can see a very thick sequence of braided stream, a coarse to medium-braided sandstones that makes up the Vivian formation. This is an interval - a gross interval of about 144 meters of sand with about 104 - 135 meters of gross reservoir, net reservoir.

However, as you can see, the blue line in the sections is the Bayovar contract we have approximately 18 meters average of net pay section throughout the field. The field - I think Manolo mentioned 6,000 hectares. It's about 15 - a little more than 15,000 acres. It's a large sort of feature. And in the lot to the lower corner, you can see the pay section there and the Bayovar contract. I won't get in - you can read yourself the reservoir parameters.

But one additional point I want to make here is, if you see in the upper corner to the right, the core photographs, these are amazing cross-braided medium to cross-braided sandstone with very high permeability. The numbers here, of course, show permeabilities that are not on fine pressure, so they're very high. But the average may be between two and one millidarcy actually in the field. So we're dealing with a wonderful reservoir, aquifer below it. I think Manolo after will discuss a little bit how we complete these wells in order to control the volume.

Our next slide, Slide 20. What we are showing here is the additional potential in the left of the slide, the additional potential in Block 9. If you see the map, the green is the Bretana field. But to the South, Southeast, there is a trend of additional features that we will be doing seismic in the next two years, hopefully, if we can get those permits going to identify and delineate prospects that can be drilled in the next coming years. Further ahead in the presentation, Manolo will discuss the potential of finding additional and what would that will do to the project.

The block diagram to the right shows the surface. Sometimes we've been talking about the surface. We're trying to tie here for you to visualize surface to subsurface. We are drilling wells to three kilometers depth, and then we go - we are horizontal in the most recent wells. Block 10H, for instance, we drilled 1.2 kilometers of lateral section - of horizontal section. And that well came in at more than 10,000 barrels a day.

I would like to mention because Manolo mentioned, we have an impact area in our location of about 11 hectares. And as we mentioned to the north, we have a natural reserve, Pacaya Samiria reserve. But we drilled horizontal wells at 3,000 meters, more or less below the reserve. So we have no impact. Our pad, our drilling pad and production facilities are within this 11-hectare production facility and drilling facility. The idea here is to minimize the impact of the overall operation here.

Again, I think the idea here is for us to realize that it's not only Bretana with a possibility in Block 95, we have other potential prospects to be drilled and hopefully, with success there, we can increase the value for the shareholders also.

I'll leave it at that. Manolo?

Thank you, Dewi. Let's move to the next slide. Yes, very briefly, a lot of people ask how is that you guys manage these strong aquifers? We use these valves called the AICDs that help us start. We actually are using three companies, and then we are going to decide with this 11H well. After that, I think we're going to decide which technology to use from then on. But it seems that they all work fantastic.

You may have seen in our website last week, were embedded by Schlumberger to make a couple of presentations in Iquitos, Ecuador. We spoke about the positive impact of our AICDs. We have a rather slag on that as well as how we are managing our really the horizontal drilling, where in Peru now we're drilling the longest horizontal. That is very simple. Less water intrusion, less water disposal, less power drawn, less carbon footprint. That's PetroTal at its best.

Let's go to the next one. And this is - again, we like to tie things up. The less water we have to manage, the less power. So it does have an impact, and you can see very clearly here, these horizontal wells, you can see with production of 500,000 barrels of oil, hardly any water is being produced. Eventually you're going to produce it in the future, yes, but much lesser than the other one. It has a huge impact in our economics and emissions and so on.

Let's go to the next one. And this one is actually - now we're going through a lot of technical details. We talk about building a factory - and we give you an example here on our 2P case of 22 wells. Keep in mind that originally, the 3P case had 20 wells. Now we had 22 wells. On average, we're using 10,000 barrels of fuel per day. You're going to be moving 220,000 barrels of fuel per day and at a 5% oil cut, that's 11,000 barrels of oil per day. That long plateau that we want to be free cash flowing for years to come.

So here you can see that it's not only on the horizontal wells because these are so permeable. You know that even on the vertical wells, they also pull a lot of fluid and the pumps that will allow us to even drill more. We're very cautious, very, very conservative how we do things. And here, you can see that everything points in the right direction, the productivity index, which shows you for every pound of drawdown, how much you can lift in other areas, usually productivity indexes, 2, 1. You were talking about 30. There are some wells like the 70 with 50. The 9H, I think, is 100, huge productivity indexes. And of course, the higher the productivity index, the lower they draw down.

They always tell me, Manolo, don't pull too hard. We hardly don't pull much at all, draw down of 194 pounds, that's nothing. In Block 192 with the old technologies, the draw down was 1,500 pounds. You're pulling a lot. You were not very careful. We have also - and we have not shown here that with tracers on the 8H, we see that actually oil is being brought in through the entire horizontal section, which is also very efficient.

So at the end, I'll give you an idea. And you get a sense, you know that on the 2P case, we will be moving so much oil and in the 3P case, with 29 wells at 13,000, you're going to be moving 377,000 at a 10% oil cut, that's 28,600 or the 37,000 barrels of oil per day.

Those are - if you go back and look at our presentations on the 2P and the 3P production forecast, that's it. There you have it. So now you know how Netherland Sewell does its work. And of course, they see that these wells are capable of producing that, fantastic.

And then ESPs, Luis Pantoja, he's now our General Manager was responsible to scaling up ESPs in the time of oxy 20 years - 7 ago. So we have a team oxy guys. They know how to manage these extremely well. They try to elongate the life of those pumps because you don't want to shut these wells to change them.

So that's - this is the essence of the company, building the factory through processed fluid, have a long plateau of free cash flow for years to come.

Let's go to the next one. I think, of course, we have shown this in our presentation before. All of that, that's results. You see how these horizontal wells, even the - our vertical, deviated wells, they performed on standard. The way they are drilled and completed, we do a very good job at that.

And with that, let Doug go through some of the next few slides, which are more financial.

Sure. On Slide 25, it's a good depiction of some of the items that you've seen already. You've seen our production charts earlier. So far, we produced 7 million barrels of oil from the field. A second chart there shows the cumulative investment that we've made on the CapEx program represented about $250 million.

And interesting to look at, if we consider the barrels of oil and one of the stats that a lot of companies looking at, what's been your cost per flowing barrel? Well, it's been less than $10,000 per flowing barrel, an excellent stat there. And these wells are paying out within 30 days. At the bottom there, you can see the historical EBITDA. So since 2018, generated $200 million of EBITDA, again, showing strong financial performance there.

If you take a look at - going to Slide 26, please. Financial summary again for the previous years, we've covered off some of this before. What I really want to point out on here represents the net operating income in 2021 and $105 million and already in Q1 of 2022 of $64 million, with the expectation, as you saw before, $351 million for 2022.

The key highlights here are that we are currently net debt free, cash is building, and we're covering our CapEx program to continue building that factory, as Manolo mentioned. And what you'll see there on the right chart on the top right is a waterfall chart showing cash flow for the year. So we started the year with $75 million.

You can see the EBITDA that we're generating here as well as then how those funds will be deployed. You've got financing costs, you've probably got the CapEx there of $111 million. And you see that we have a provision there for the $85 million of bond retirement sometime later in the year, assuming cash builds as expected.

So where it would be at the end of the year, about $137 million of cash is what this is portraying. And because of all kinds of uncertainties, we always need to have a good cash buffer since we don't have a reserve-based credit facility. So we believe it's prudent to keep about $75 million as a good cash buffer going forward, which still leaves over $60 million there available for that shareholder return policy that I summarized earlier.

Let's go on to Slide 27. People have asked about our netbacks as well as by contract. You heard Guillermo speak about the three different sales routes that we have. Well, we're providing some detail here as we have in previous presentations, this ties to our 2022 budget. So what we expect is there's the 15,500 total barrels that we expect to sell. And into Brazil, we'll be selling about 13,300 barrels per day. So nearly 70% of our oil will be going to the Brazil market this year.

Iquitos will take the 2,000 barrels a day that Guillermo mentioned. And then the rest will go into the pipeline. So that will represent about 1,200 barrels per day. And so the drilling program, as you saw, is time to be coming back on when we need access to the pipeline, which is later in the year.

So based on the contracted rent price here of $102 for the year, how do we get to the price of $75 per barrel is what would be our contracted revenue as well as take it after royalties. So you can see there is that Brazil is - represents our cost of - it takes us down to $74 per barrel, $80 per barrel for Iquitos after the deductions that they would have, as well as the $76 per barrel at Saramuro.

And taking off, our lifting costs that you see identified in there, we allocate them evenly on all 3. With Brazil, as you heard mentioned, there are no additional margin costs or diluent costs required. So that is our best netback of $67 per barrel. Second best would be Iquitos, $62 per barrel. You can see the costs associated there.

We're still using some diluent blend there. And then there's the margin cost. Margin costs are about $3 per barrel by the time you look at the margin service itself and then the diesel costs, which - and then going into the pipeline because of the higher cost structure there for the pipeline usage that takes our netback to $57 per barrel. So on average, it's about $63 per barrel, and then looking at the EBITDA, it gives us $59 per barrel at that level.

And looking at the impact of oil in the O&P, you can see it summarized on the top right there as to what we're expecting in 2022, and then the majority of it now will be trued up in 2023 as those physical sales occur.

Let's take a look now at Slide 28. What you see here is you're going to see a series of three slides. Basically, they're all the same, so I'll just summarize the structure at this point in time. So what if we just stopped drilling after this current well and did nothing else? So that would be considered a blowdown analysis.

And that's what we're showing here. We always talk about the importance of maintaining production going forward because we have the facilities that are already built. We need to utilize them. So if we stopped drilling after this current well, you can see CapEx as - for the year is only $40 million. And then - so a well count would stay at 11. We would not be adding any more wells and that would just be the natural decline for all of them.

EBITDA sure is nice and strong this year, and you'll see how it declines over the next five years as well as free cash flow. Free cash flow now after this well, it would be $170 million, but then it would decline very quickly down to only about $28 million by the time you get to 2026. So you see from here, it's important to continue to utilize our facilities to maintain and maximize cash flow.

The two columns there just in the center, so just looking at the next 4-year period, sure, we would be generating $414 million of free cash flow. But going beyond that, taking it all the way out to 2031, only provides an additional $51 million of free cash flow. So that would be the blowdown analysis. And what can be done? Well, if we continue ongoing development, and you'll see that on Slide 29.

So Slide 29 represents the optimal return. This is the 2P. This is drilling up to the 22 wells that are identified in our reserve report. So you'll see that on average CapEx, we continue to drill wells there and then free cash flow is building. So if we reached a peak production of 25,000 barrels per day, whereas in the past, we were just under 10,000 barrels per day under that other blowdown scenario.

So now what you see here in the cumulative amount of free cash flow in that column in 2022 to 2026, $1.3 billion. And then after the investment of $314 million, the ongoing capital program that's needed, there's no additional capital to go beyond 2026, but you can see the bump there, another $700 million of free cash flow would be generated, getting us to over $2 billion over that ensuing period from completion of the 2P program, drilling those additional 11 wells. So an excellent shareholder return potential of $920 million as one looks at the cash flow that's generated.

So let's go one step further now on Slide 30. This represents the 3P development. So as Manolo mentioned, wells will move into the 2P category as we're drilling up the 2P. So it's essentially drilling an additional seven wells. So this takes us to 29 wells in total. The CapEx, as you can see there, is $512 million that would be required to do that.

And that would generate $1.8 billion in the next four years of free cash flow. And then look at the balance going out to 2031, gives us $3.3 billion of free cash flow. So an excellent impact there from that ongoing production from the additional seven wells. And you can see, it reaches peak production of nearly 38,000 barrels per day under the 3P scenario.

Slide 31. So what I want to show on here, as we look at the Block 95 extension, Manolo will speak about that, but look at the information at the bottom left corner there. So an NPV of $530 million to drill some of the other prospects that we have there, net project CapEx of $630 million and provides for an excellent return. So cash from this area would be $140 million that would be invested.

And then we touched on this a little bit earlier, something that we are now highlighting more is the fact that the Bretana Field, which is the one to the north of the block was filled to this spill-point, which means that the oil continued migrating going south. And this oil has actually come all the way north in migrations hundreds of million years ago.

And we have some of these leads, as you see on the bottom table, again, the presumption is that this eventually - if we find oil, commercial oil is eventually going to be twice as large. You can see the lead - D&E, you add both, it's about the same as our original 3P case or Bretana which now you have double in size. We used to map elatedly and independently, something that also based on our experience in the area that when you have two nearby structures, ended up usually being a single one. And that's what we are now - you see how we map the D&E combined.

So the potential is high. We like the idea a lot. Probably we're going to go - as we usually do on a step-by-step basis. Of course, we have to do seismic. The permit is not going to be ready to deploy year or next year. I tell our investors don't worry, don't panic. The per median process in Peru is such that sort of paces yourself on how much money you can invest on exploration. But having all of the facilities in Bretana, you can imagine that this actually should allow us to put these fields of production quite fast.

So let's go to the next slide. And keeping on the geology, you can see here on the case of the Osheki Kametza. And this is actually extremely important for us because in the case of - in the bottom right figure, you can see we zoom in into the actual road that takes us from the brand new road that was built from Pucallpa, the Los Angeles Field south into Constitucion. That in yellow, you see is the road that actually Gran Tierra built to do the seismic years ago.

We now - as we do our scouting, we find out that is still available. So in immediately when we find that out, we changed gears because Osheki was supposed to be reached given that it's in the middle of this reserve, forest reserve by helicopter. And this one, we can move it by truck, much cheaper. And it's a single structure - that may sound shaky - two combinations. So we will build that first. That's the plan.

You see on the table to the left, the chances of sales are high. And we've been doing a lot of work here from a geologic point of view. We're very excited, hoping also to get permitted by next year, they'll be able to drill next year. I have previously mentioned that we were hoping to have the permit this year, it looks like it's going to take longer. Again, the permitting process sort of puts the - paces yourself on what you can do and how much money you can spend on exploration.

Looking at the mean potential, 500 million, these are from three horizons. Even if you're finding only one, for example, the Cushabatay that produces from the Los Angeles field, that is 60 miles north of us, that's 150 million barrels or so. So that's why we're so excited about this possibility.

Let's go to the next one. And here, you can see the Osheki economics that Doug will cover.

Yes. And the Osheki economics, you can see a net present value of $400 million will generate free cash flow of $1.7 billion, so almost the same as what we would have seen on Block 95 extension, which was $1.9 billion. And this will require CapEx of $765 million. And that's - we're looking at it on the risk side. And then the expected case, you can see the numbers are even higher up to an NPV of $900 million.

And this is based on a 50% working interest, which means that we foresee that Osheki-Kametza could produce closer to 70,000 barrels of oil per day. The Los Angeles field that we're looking at, it has 40 API gravity. We compare the quality of the oil. So this is going to be a fully API gravity oil, 70,000. That will be fantastic. Hopefully, by the end of next year, we can drill this well. It will be outstanding.

Let's go to the next one. So here, you can see now all combined through time, the Bretana, the other leads, it really shows a company that it could be major producers for a year to come.

And look at the economics at the bottom there under the risk production profile on the left side. The net present value discount of 10% of $1.6 billion, this includes now Bretana because we're layering on all of these prospects together. It will generate free cash flow of $3.5 billion over the life of the field with CapEx required of $1.8 billion. And if we were to look at the expected side on the right side there, you can see the economics improve even more.

And then on the last slide of this presentation, I found this graph, and this comes from our 2017 investor presentation. Some of you that invested at the beginning with PetroTal, you may remember this. The light blue is basically our 2P case that we had at that time that we were not going to even reach the 14,000. And on the 3P, we will not even going to reach the 20,000 mark. Funny enough, we are here.

We actually reached that level about the same right time on the 3P case that we were showing the investors at that time at the end of '17. So - and now you can see that on our 3P case, certified by Milan SUO, we could go up to 35,000. But don't forget what actually at the beginning, we have CPF-2 facilities for about 26,000. We're probably going to try to manage this.

In the dark blue line, why is the production went down and didn't went up? At that time, we're thinking we will move the rig out, and then we'll bring it back later. But now we see that, that's extremely cumbersome to do. There's already people asking about the rig and so on. So no, the rig is under contract.

So we don't want to keep it. That actually is going to help us maintain our cost down because it's - I think in the next 2.5 years, we have that rig to continue drilling our 2P wells and then we have to extend it in the future. But that is amazing, delivering on what we promised in 2017, even on a 3P basis. That's PetroTal at its best. Thank you so much.

And now we can open it for questions.

Manolo, Doug. First question, when is the company going to start using Station 1 and 5.

As we mentioned in the presentation, we expect Petroperu to be done with the maintenance on the pipeline. I just have to provide more detail in the section of the pipe after the west of Pump Station 5, the river erosion we're just finishing the rainy season, caused some potential danger to the pipe because of the river erosion. So they have had to do quite a bit of maintenance on that. So as soon as the pipeline starts flowing again, we can put oil into Pump Station 1.

Keep in mind that Pump Station 1 is full of oil. So we have to push the oil out. The entire pipeline is full. So actually, we push the oil from Pump Station 1 all the way to Bayovar. We put a barrel one up in site and a barrel comes out on the other side. That's how, of course, that's why you have Pump Station 5, because they do it by batches. That's how they do this. Anyway, in September, as we mentioned in the presentation.

Is the company working on better terms for, the ONP during 2023?

The contract currently is going to stop in December - actually expires in December 2022. But because of some of the force majeure issues that we have had is going to be some time in - probably by mid-2023 or something like that.

So we have plenty of time to get ready for that. We - Petroperu knows that we will - we need to go back and do that. And now that the Talara Refinery has started - is commissioning last month, it's going to take about six months of commissioning. Ideally, the concept is that all of the oil in the jungle should go to the Talara Refinery. So we are working with - talking to Petroperu to do a new contract that will be a win-win for everybody.

In Q1 2022, there was a $9.38 difference between the average Brent price and the concentrated price. Please, can you explain this differential, which is usually sub-$3?

Yes. If you take a look at that chart that I showed, showing the three different contracts and the netback analysis there, the contracts are priced using future strips, so steep backwardization in the Brent price curve versus the prior quarter, it leads to that. For instance, the sales that go into the pipeline are priced at the eight months using that core price strip. So that is one aspect because of the backwardation - even the sales in Brazil, they're priced based on the future third month to represent timing of when product will reach market.

Why the trade debt is so high at the end of the quarter? Has this now been collected by the company?

Yes. We indicated in our financial statements as a subsequent event that we've received a payment of $10 million on that amount and expect the rest to be paid to us shortly.

Can you give us a general overview of the company's transportation cost per barrel basis comparing pipeline cost to ship and costs?

Well, again, back on that netback schedule there, the pipeline costs we're paying about $9 per barrel and another administration fee of $3 per barrel. And these are the items that I talked about are deducted before you see contracted price. So that's the breakdown there. And then we're paying around $20 a barrel to - for the Brazil shipments. So again, contracted prices are deducted from the revenues.

So that's how IFRS requires that we report it. The true margin costs, as we showed there, are about $3 per barrel representing the margin service as well as the diesel that the barges use. So it's about $3 per barrel to be all in the oil to the Iquitos, and about $4 per barrel to haul it to Pump Station 1 since it's a little bit further.

Could you please comment on the field's average annual decline rate and how this decline rate currently compares to the past?

Yes. Actually, that's a question that we've been asked before. That's why in Slide 37 of this presentation, which is in the appendix, we provide some of the actual well data. IP started at about 6,500 barrels of oil per day on an average basis, declining to 1,500 to 2,000 after 12 months. And in past 12 months, we see the rates being significantly shallow as per the bottom graph of the slides, which should be easy to follow, should the investors want to model these types of wells. Again, this is a typical behavior of strong aquifer when you have this type of shape.

Could you please clarify if dividends or share buybacks will come first to the shareholder return strategy?

At this point, it's hard to clarify exactly what we'll be approving. But as I showed on the chart there, we believe both are viable strategy. And from a shareholders' perspective, it's important to have, I think, a regular annualized quarterly payment of dividend. So you need something on a regular basis. So I would like to think that we'll get to the point of approving a regular dividend going forward and then have some available capital for share buybacks.

Looking into next year, what are your thoughts around cost inflation and rig and crew availability?

That's a good question. We have fortunately fixed contracts which are inflation protected. We assume when those contracts are up, we will have some escalation, and we intend to manage that as best as possible. But there are - some of them are long-term contracts.

From an infrastructure standpoint, the majority of the 2P build is behind the company with the CPF-2 recently paid for and completed. And then with only one rig to manage, we feel we are not exposed from a labor shortage standpoint versus a company with high volume drilling.

What is the estimated annual CapEx cost in 2023 and beyond of four to five annual wells plateau production and growth CapEx associated with development and growth in the field?

As I was showing in the slides there, on a run rate basis, that we'd be drilling about four to five wells per year and developing some additional infrastructure and water disposal wells. So we expect that a regularized CapEx will be about $100 million to $110 million per year.

And is the company producing at maximum capacity today?

I would say, yes. Although as I show in that other figure with the ESP curves, that we could actually pull more. But we're being cautious. So I think it's yes.

Two questions on AICD. Firstly, when did the company start using it? And secondly, will AICD increase the ultimate recovery factor? And if so, by how much?

We actually started using the AICDs from the first horizontal, from the 4H. So the 4H, 5H, 6H and the 8H and 9H and 10H, they have all that AICDs. Actually, it's quite amazing. I don't know probably, this is the first oil field that all of the horizontals have AICD wells. Today, increased recovery, yes, we believe so.

The data is clearly pointing to that. And that's why our - the people selling the AICDs, of course, say. But no, we've seen it in the data. We see it. By how much? You can get a sense of how we are growing the reserves, how we started initially on the two PKs. We've an average of 3.2 million per well. Now we're at 3.9 million is we are seeing an impact.

Let's wait a little bit longer to provide a more accurate number, but we do see it's very important what we did. And testing three technologies to then select the best one, it was important. For example, the one that we set up on the 10H well, that is behaving very nicely, the technology tells us that once the water cuts go closer to 70%, that's where the - those AICDs will perform the best. We will see. That's why we decided to test these technologies and pick the best.

And why is there a restriction on how much the company can ship to Brazil and what work is being done to increase these numbers?

Well, as we showed in the map, Guillermo explained, it's a long distance to Brazil. The logistics are cumbersome for people to commit to a project that is all the way to Peru, it takes time. And again, we always go on a step-by-step basis, trying to prove the concept. So 500,000 right now is actually quite amazing that we are already at that level. Keep in mind also that it's always good. I'm a firm believer in Murphy's law, always good to have two markets, three with Iquitos, although Iquitos is small. So we balance things very carefully.

It seems a significant amount of PetroTal's oil is in the pipeline, but then no other uses of the ONP?

At this point in time, the only other producer in the area is Branco, and they only provide a small amount of oil into the pipeline. So essentially, we are the ones that are putting in most of the oil. And I just want to clarify that when we sell the oil into the pipeline at Pump Station 1, we are paid for the oil at that point in time.

So the revenue is booked, and then it's subject to that price adjustment when it gets to the other end, and the physical sale by Petroperu occurs. So that typically - that's that $59 million of derivative assets that we show on the balance sheet, representing an incremental value of the oil when it's physically sold.

Could you expand more on the average horizontal well lengths?

We started the first one, the 4H, I think, was like 600 meters - and the latest one was twice as long, 1,200 meters. And now that we set up the synthetic match system, it allows us to reach those longer horizontals because it allows us to maintain the torque of the field pipe to lower levels. I think that in the future, 1,200 meters probably is going to be sort of the norm.

What is the oil price deck used for the blow down 2P and 3P development analysis?

You can see in the slide what the price assumptions were for each upcoming year. And then what we've done beyond 2026 is we've used flat $70 Brent.

Why isn't Envidia being scheduled for sooner development since it is closer to Bretana?

Well, we want to - although Envidia is consider prospects, we want to also do additional seismic in Envidia, just to be sure. So for that, we need the permit to do the seismic. The permit will allow us to do the seismic in top of Envidia and all of the other leads that I've shown in the presentation. And then we will - we may - based on what we see on the remapped Envidia, we may decide to go to that one, which is close by. That would be the logical step going south step by step.

With the flush production from 11H or 12H, your production could be higher than the Brazil and Iquitos capacity. The repairs to the ONP are due to be completed by late September. Are you considering restarting barging Station 1 before that date? Alternatively, could you stock oil on the ONP barges?

The Petroperu has said that they could complete the maintenance sooner. So we're paying attention to that. We have mentioned to Petroperu maybe the possibility of taking some of the oil that is in - from Station 1 out and take it to Brazil, so we can empty the tanks. So we're looking at all of the logistics. I can assure you that Guillermo that you heard him earlier, he's paying a lot of attention to all of that. We will try to maximize production.

Is there a limitation on the barges available to carry the oil and what is the maximum barrels a day PetroTal can secure?

We - you have seen, for example, in this slide, where in case of a shutdown and that happened in the fourth quarter, we had about 360,000 barrels of oil stored in barges, floating in the river next to Pump Station 1. The reason that we're being able to increase the volumes to Brazil is that now we have been able to get the Peruvian barges to also go to Brazil. They were not permitted before and that has opened more for that. These barges are - usually, we try to use barges of about 20,000 barrels each. Sometimes little bit less or little bit more, but give you an idea of how we do this.

Some E&Ps have institutionalized their capital return policy. Does management intend to come out with a firm capital return policy? And if so, when?

Well, possibly, we'll be doing that. However, we don't feel there's any need to make that decision at this point in time. Our priority needs to be to pay out the bond, which we'll do - expect to do by the end of the year. And then we'll be announcing to the market what the intentions are once it's been approved by our Board. But we believe, as mentioned, a combination of a regular dividend as well as our share buyback is the way to go.

Is the company full out, it's around 17,000 barrels a day now or can you produce more if the ONP was open?

That's about right. And we will have the new well timing online at the end of June. And so the forecast of production will allow us to maintain the production at a constraint for the near future. I sort of explained that in the earlier question.

Has PetroTal considered SIB over NCIB to eliminate any outstanding shares?

Well, again, to reiterate the existing covenants of our bond prohibit us from providing any returns to shareholders, be it through a buyback, SIB or dividend, hence the focus on repaying the bond.

Has the company experienced any supply chain issues?

Not out of the norm. Keep in mind that Peru's industries is small. So we use Schlumberger and some of the large service companies. So we - the planning has to be done way ahead of schedule. Part of the success of PetroTal is how we've been managing our logistics and the procurement on things. But otherwise, we didn't - doing this very well.

Could you come back on why the true-up will only be $13 million in 2022 with the balance moving to 2023?

Well, the $13 million represents a net amount, netted against our hedge losses that I referenced. And because the ONP is closed, oil is not moving through the pipeline. So the next delivery to Bayovar through the pipeline and then the physical sale as a result of that is expected in Q4 2022, which then pushes out that revenue true-up.

The company shares are relatively liquid, making it harder and more expensive to invest. Is there anything the company can do to improve liquidity?

Well, we do take a look at the exchanges we trade on. A few months ago, we upgraded on the U.S. exchange. Granted, there aren't many volumes there, but that has allowed for an additional U.S. trading. So we've gone to the OTXQC.

And we do continue to look at graduation into other stocks, I mean, in other exchanges. So the TSX would be a logical choice. That's something that we're pursuing. We're looking into that.

Please, could you provide an update on the political situation in Peru as you see it?

Things in Peru from a political point of view, are somewhat calmer now recently, just last Sunday, the President changed four ministers, including the Energy and Mines Minister. The new Energy and Mines Minister is actually a woman with a lot of experience. It's going to be very supportive of taking care of Petroperu, the state-owned company that has been going some financial issues because of the prior administration. So the fact that we have a new Minister of Energy and Mines, plus the support of the finance minister, I think we're going to be okay.

How will the communities be accounted for in the P&L or the cash flow statement? It seems there were no funds allocated to communities in Q1. If there were, could you please confirm where we can see them in the accounts?

Yes. I mean, we have an ongoing community development program. And then where you see those costs and then there were costs in Q1, they are either put in the operating expense section, so you'll see it as part of operating expense, but mostly, they appear in the G&A. So you'll see a breakdown in the MD&A that shows the amount that was dedicated to community development.

And with respect to the new social trust that we talked about, that 2.5%, we expect the framework for that to be developed soon. And when it is, we'll be funding into that. So not until the framework is developed and agreed to by all parties will we be showing that on our balance sheet and our income statement.

Could you please reexplain the different hedging programs, corporate, Petroperu, et cetera?

Essentially, we buy - at the corporate level, about 22% of our production for the balance of this year, we purchased puts and the swap program. So that's how we've covered that at the $60, $70 per barrel level. And with respect to the oil in the pipeline, Petroperu have put some hedges in place that anticipate the timing difference of when the oil would be delivered to Bayovar for physical sales.

How will the company handle the spud from the well-being finished in July since there is no storage?

Actually, as we mentioned, the well we're drilling now, the 11H, will be completed at the end of June. We will spud a new well early July that will not be completed until the end of August. So we have time to three months to take care of making sure that we can have all of the wells flowing at their full potential. And we're confident to be able to do that. Otherwise, we will probably constrain some of the lesser producing wells to allow the new wells to come in strong.

As the ONP is shut and with the high value of derivative assets, is it not possible for the company to ask the part payment of the true-up amount today?

The contract is very clear in that regard, and unfortunately not.

Will there be substantial political pressure to end the Brazil routes and start selling all the oil to the Talara Refinery?

The contract with Petroperu, Petroperu is actually behaves itself that are private companies owned by the state that actually runs as a - is supposed to run as a private company. So this is an agreement between two companies. I don't think there's going to be a political pressure per se. The government, what they want is to make sure that the companies invest as much as possible and the companies are free to sell their oil anywhere they want to. And that's part of the license contract as well, which are known as contracts loan.

Now the - for us, again, we need to make sure that we might try to maintain two markets, so we will accommodate both. Us having now three markets, Iquitos, Brazil and Talara in the future, that will be fantastic. So we'll do it smartly.

Is there any change to hedging arrangements plan should oil prices rise significantly?

Well, we meet and discuss our hedging program on a monthly basis and update with our Board on a quarterly basis. At this point in time, we haven't identified any changes going forward. So we keep our program fairly flexible, and we'll modify it as we need.

When is the next reserves update expected? And does the company foresee an increase in recovery factors similar to offsetting fields?

The reserve report are usually published in February, so it'll be next February - at the end of next February. That's when it will come out. The recovering factors, I think, for the last four years, we have shown how things have developed with time. And so at 22%, and we're very happy. That's what I promise investors. And of course, we're going to try to squeeze as much oil as possible out of the field. But right now, it's too early to say.

Manolo, Doug, thank you. That's the end of the Q&A. So I'll now hand back to you for closing remarks.

Well, thank you so much. And I would like to thank everybody for spending almost two hours with us through this detailed presentation. I hope you all enjoyed the added color that we have provided to the PetroTal story and where we would like to take this company and for the benefit of all. Thank you.