Hello, ladies and gentlemen. Welcome to the PetroTal Q3 2023 Results Investor Webcast. Your host today will be Manolo Zúñiga, CEO, and Doug Urch, CFO of PetroTal. There will be a Q&A session following the presentation. If you would like to ask a question, please do so via the webcast platform, and the team will do their best to answer it in the time allotted. I will now hand over to Manolo and Doug. Please take it away.
Thank you, Jimmy, and good day, everyone, and thank you for joining the PetroTal 2023 third quarter webcast, where we will provide a brief summary of our third quarter 2023 operational and financial results. If anyone wants further information on the company, please see our website for additional materials. My name is Manolo Zúñiga, and I am the President and CEO of PetroTal, and I'm joined by my colleague, Doug Urch, Executive VP and CFO. You have clicked on the link in last evening'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. As shown in slide two, PetroTal is an onshore Peru-focused oil company that in just five years has become Peru's largest crude oil producer. The company's listed on London's AIM market, the Toronto Stock Exchange, and the U.S. OTC, having a market cap of approximately $500 million. We have a 100% working interest in the Bretaña Oil Field, which we have expanded from no production to over 25,000 barrels of oil per day in late June 2022. The third quarter of 2023 was a resilient quarter as we navigated through another severe drought dry season, which limited our Brazilian barge transport and tanker unloading capacity at Manaus.
Despite this challenge, the company delivered free cash flow in Q3 2023 that was on par with Q2 2023 due to prudent capital spending and high realized Brent prices. This has allowed us to again top off our dividend payment, this time at $0.02 per share instead of the nominal $0.015 per share, as Doug will later explain. But first, a brief summary of our assets. The Bretaña field in northeastern Peru delivered first commercial production in mid-2018 and has since grown from no production to over 20,000 barrels of oil per day in five short years. Currently, the 2022 year-end 2P reserves are 97 million barrels, which have an after-tax 2P NPV-10 per share of $1.75.
The field currently has 16 producing wells and three water disposal wells capable of disposing approximately 50,000 barrels of water per day each. The company is able to deliver all of these on just a tiny 30-acre surface field footprint, with emissions of approximately 6.96 kg per barrel of a Scope 1 carbon emission in 2022, as will be shown in the soon-to-be-published 2022 sustainability report. We would like to cover our Q3 2023 in detail in this webcast and also showcase some of the critical sales route expansion work our commercial team has been doing. Slide 3 summarizes key and selected Q3 2023 highlights.
From an operational perspective, during the third quarter, we delivered 10,009 barrels of oil per day, with corresponding sales of 11,553 barrels of oil per day in sales. The production level was highly constrained for the entire quarter as the dry season materially impacted barge transport and tanker unloading capacity at Manaus. During Q3 2023, we invested approximately $17 million of CapEx, mostly on continuing infrastructure projects. It is important to note that the company was not drilling during the quarter, as the construction of the new L2 West platform, where we plan to drill an additional nine wells, was ongoing while the rig was on standby.
For Q4 2023, we're anticipating a very active and significant quarter with various fluid handling infrastructure projects concluding and the restart of the drilling campaign with Well 16H that should occur later this week. Of course, 16H is another horizontal well. The company estimates the total capital spend for 2023 to still be between $120 million-$130 million, as we have guided recently. From a per barrel perspective, lifting costs were $8.45 per barrel in the quarter, versus $4.22 in Q2 2023, due to lower sales volumes and an additional $2 million from well servicing and erosion control costs. Transportation costs were $4.64 per barrel versus $1.58 in Q2 2023, due to additional floating storage costs related to the Brazilian route.
Note that these floating storage costs allowed the company to quickly ramp up production, avoiding longer barge normalization times when river levels improve. All in, the company delivered a total OpEx per barrel cost of $13.09 per barrel versus the prior quarter of $5.80 per barrel. The company believes with higher sales volumes and the avoidance of one-time well servicing costs, it will be able to lower this total cost next quarter. Slide four shows why, during the month of October, the company had to fine-tune its full year production and sales guidance to the lower end of the previously guided 14,000-15,000 barrels of oil per day range, as the full impact of the dry season reached critical levels during that month, as shown in the left graph.
As shown in the right picture, the drought also impacted tributaries to the Amazon River in Brazil, which impacted operations at the Port of Manaus. The graph to the left also shows the historically high and low river levels that occurred in 2012 and 2010, respectively. I just saw this morning's transportation report. I noticed a large river level jump for the black line that shows the 2023 level, now back at 80 meters subsea level. It is important to highlight that on average years, as shown with the green line, the Amazon River is a perfect highway to transport our crude oil and all types of merchandise. A year of river level difficulties have challenged our commercial team to further optimize the Brazilian route.
As shown in slide 5, one of the things the team has been working on is the ability to avoid long barge queues, times for barges waiting to unload at Manaus. Our current unloading process is seen in the picture on the left. We're now solving that problem with a new commercial arrangement recently approved by Transpetro. Under the commercial arrangement, PetroTal will unload its crude oil barges directly to an available and dedicated tanker. This development will increase PetroTal's monthly sales on the Brazilian route by reducing substantial barge queue time mandated by port terminal availability. It will also allow the company to produce and sell more oil through the Brazil route, both during the dry and wet river seasons.
The company produced 13,400 barrels of oil per day from October 17th to November 9th, 2023, at which time it increased production to 15,300 barrels of oil per day, and estimates it will ramp up back to around 20,000 barrels of oil per day by the end of this week, coinciding with rising river levels. With the new L2 West platform completed and fully commissioned, the company will commence drilling Well 16H, shortly allowing us to maintain production at these levels. As shown in slide 6, Well 16H lies to the southern part of the field and is estimated to cost approximately $50 million. As mentioned before, if all the wells were allowed to produce unconstrained, the field would easily be producing more than 20,000 barrels of oil per day.
As with the prior quarter, we have updated our commercial sales route strategy, as shown on slide 7. This slide summarizes what the company's short- and long-term plan is around existing and new sales routes in Peru. As previously mentioned, the company is undertaking a 100,000-barrel pilot through Ecuador using the OCP, Ecuador's heavy oil pipeline, with the oil eventually ending up at the port of Esmeraldas. This initial pilot will have a slightly lower netback compared to the Brazilian route. However, with larger volumes, the company estimates a very competitive netback with other current routes. The company is also diligently working to barge oil to Yurimaguas and then by truck onto Bayóvar, without using the ONP. This would involve a 750-km trip to Yurimaguas, and just under 1,000 km to Bayóvar.
The operations team previously used this route in 2019 and is familiar with its corresponding logistics, safety protocols, and infrastructure. Currently, the company has advanced work on this route and is currently risk scouting and waiting for permits approvals. This route will have approximately 5,000 barrels of oil per day of potential sales capacity, and given the robust differentials seen at Bayóvar, should have a competitive netback after accounting for the increased trucking and barging costs required for this route. Infrastructure upgrades are required for this route to be used regularly and are related to barge-to-truck transfer of oil. The company estimates an initial pilot to be done in mid 2024. I will now turn over the meeting to our CFO, Doug Urch, who will provide a brief financial update.
Thank you, Manolo. I'm Doug Urch, PetroTal's CFO, and would like to start off highlighting a few select financial items from our recent press release and financial statements, with visual support from slide 8. From a balance sheet standpoint, PetroTal exited the quarter with over $113 million of total cash, and is in a $87 million net surplus position, considering all other working capital amounts. The company has no long-term debt and no amounts drawn on its $20 million short-term credit facility, as at the end of Q3 2023. The company delivered strong financial metrics in the quarter on 1 million barrels of oil sales in the quarter, representing 11,553 barrels of oil per day, compared to just 1.7 million barrels in Q2 2023, which represented 19,031 barrels of oil per day.
Following is a short summary of key P&L line items. Net revenue of $69.1 million, $65.05 per barrel. Contracted Brent in the quarter was $84.31 per barrel, compared to $77.88 per barrel in Q2, with the Brazilian transportation differentials and backwardation reconciling the realized net revenue per barrel amounts. Royalties for the quarter were $5.8 million, or $5.49 per barrel, inclusive of social trust provisions. This was up slightly on a per barrel basis from Q2 2023. Total operating expenses in the quarter were $13.9 million, representing $13.09 per barrel, compared to $9.7 million, or $5.80 per barrel, in Q2 2023.
The Q3 2023 fixed operating costs included approximately $2 million in well servicing and erosion costs that were not present in previous quarters. Q3 2023 net operating income of $49.4 million, or $46.47 per barrel, compared to $76.6 million, or $45.53 per barrel, in Q2 2023. Q3 2023 free funds flow was $36.9 million, compared to $37.7 million in the prior quarter, due to higher Brent prices and lower capital expenditure spending in the quarter, and positive derivative realizations. Net income for the quarter of approximately $25.4 million, representing $0.03 per share, compared to $46.6 million in Q2, making it the 15th consecutive quarter of net income for the company.
On Slide 9, the company is guiding its 2023 production to the lower end of the 14,000-15,000 barrel of oil per day range, as Manolo has already mentioned. EBITDA and capital expenditure guidance are still on trend with prior estimates, with the company still estimating between $80 million and $90 million of after-tax free funds flow, of which we have generated $82 million year to date, ending September 30, 2023. Ending cash in 2023 is estimated to exit in our minimum liquidity range of around $60 million, leaving it a small buffer for unexpected working capital needs. We encourage investors to view our free cash flow matrix on Slide 9 in our November investor presentation for production level and oil price free cash flow sensitivity. Slide 10 summarizes our return of capital policy and amounts paid to date.
During Q3 2023, PetroTal was very pleased to announce that a dividend of $0.025 per share, based on the strong Q2 2023 results, was paid on September 15. That represented an additional $0.01 per share over the base $0.015 per share, in accordance with the company's cash sweep policy. The company is also pleased to announce its Q4 2023 dividend. Based on Q3 2023 results and cash balances, PetroTal has approved a $0.02 per share dividend, payable on December 15, 2023, representing an estimated 15% annualized dividend yield. This includes an additional half a cent per share over the base one and a half cent per share as a result of available cash and projected working capital requirements.
The company views this amount as a strong indicator on its ability to maintain and increase its capital return policy under challenging operational conditions, as we experienced in Q3. The key upcoming dividend dates are summarized as follows: the ex-dividend date, November 29th; record date, November 30th; and the payment of the dividend will be on December 15th. The company has also substantially increased its buyback program in Q3 versus Q2, buying back 5.6 million shares. Cumulatively, the company has purchased over 7 million shares, totaling $4.3 million to the end of October, and has paid over $55 million in dividends, including the December 15th amount, representing approximately 12% of our market cap. To conclude, slide 11, now in our corporate, inv.
Presentation, represents the immense value proposition that PetroTal can deliver to shareholders on a short- and long-term basis, while maintaining a lucrative dividend and share buyback program. According to this internal and unconstrained forecast, the company will generate material short- and long-term discretionary cash flows at $80 Brent, and after return of capital. PetroTal will have many exciting future projects to evaluate from both an exploration and external M&A perspective, inclusive of our return of capital policies, substantially or sustainably down to $60 per barrel Brent. I thank you for your continuing investor support, and will now turn the meeting back to Celicourt for the Q&A session.
Thank you, Manolo. Doug, what sort of range do you expect for Bretaña production in 2024?
Well, you know, we have yet to complete our 2024 budget, so we, we are constrained on providing that. As we have shown in our talk, we are looking at different routes, so we do expect to do better than this year, but we cannot yet give a number, but we will do better.
Can you please discuss the reopening of the ONP?
Yes. We actually met with PetroPerú last week with the head of the ONP and that person, that manager, was indicating that the pipeline now is ready to flow. The issue right now is that all of the tanks at the Bayóvar are being used by crude oil that the PetroPerú purchased for the commissioning of the Talara Refinery, which they hope to have complete by the end of this year. At which time, then they will free some tanks and hopefully, you know, oil could start flowing again. Keep in mind that for oil to flow, someone has to inject oil at on the other end of the pipeline.
So we are proposing to our board, the idea of, of going back to the ONP, but in the old-fashioned way, where, not with the contract that we had, before, that we did that, derivative. So just putting oil and waiting for it to come out but we will see in the meantime how things shape up with the ONP. Some of you may not be aware, but last month, the national police was able to capture a 20-man band that was responsible for cutting the pipe to then make money, with, with those repairs. Since then, there have been no more cuts in the pipe, so PetroPerú is hopeful that things will normalize, sometime next year, you know, but we cannot provide a specific time.
What changes can be made to improve share liquidity? Is a U.S. listing a possibility in the future?
Well, we are looking for ways to generate additional liquidity in the stock. We are trying to target generalist funds and additional retail investors, both in the U.K. and North America, to accomplish this and work with our brokers to address this. We currently trade on the OTC; however, there are no plans right now to expand on that U.S. listing.
Is there an update on the PetroPerú receivables situation?
There have been no changes in the PetroPerú receivable other than the, you'll read in the original amount they owed us from the lifting in the prior year. The final payment was received on that in August. So July and August were represented the final payments of the $64 million from the prior year. At this point in time, PetroPerú have not, you know, increased their credit facilities, and nor have we been delivering any oil to the pipeline. All amounts that they owe us from deliveries to Iquitos are current.
How long do you predict an increased demand for oil? In the guidance in the investor presentation, you have a forecast for plenty of years. Do you see a threat from the change to green fossil-free resources or a possible ban on fossil fuel energy?
You know, I can, I can answer that one. You know, we're, we're bullish on both short and term and long term for oil and gas demand. You know, we believe there should be a long-term balance between green energy and legacy fossil fuels over the long range. You know, we also believe the lack of investment in major oil and gas projects over the last 3-5 years will have a significant impact on providing a strong macroeconomic conditions over the next 5-7 years, when investment levels could be higher at PetroTal.
Thank you. Could you please quantify further the impact of the barge to ship optimization for the Brazil route?
Yes. We have been doing a lot of work on that, as I mentioned on my talk. You know, back of the envelope, I will say about 10%-15%, something in that range. You know, today, for example, in 2023, we have sent 3.75 million barrels to Brazil, to Manaus. So, 10% will be at the equivalent of 1,000 barrels per day, on an average basis, you know, and the same for the 15%, so it is significant.
What will total oil processing capacity be after the CPF 3 is installed in December?
The idea for us is to be able to maintain production in the order of 25,000 barrels per day. Keep in mind that we also need to be concerned about the water handling, so it's both combined, oil, water, you know. And that's why I have always said we're building a large plant to process as much fluids as possible, to squeeze as much oil and, of course, on a very economic basis.
Could additional Venezuelan heavy crude oil entering the market depress the price of Bretaña crude?
Well, potentially that could happen. This is. It's currently difficult to know, as our current deal with our Brazilian route fluctuates based on volumes and not necessarily market differentials. We would need a sale at Bayóvar to potentially obtain more data on that front. Storage costs in Q4 2023 should be lower, as they will not have as much of an impact with the dead freight storage charges as they did for July, August, and September. So what we'll see is October and a little bit of November, so it should be substantially lower than what we saw in Q2, sorry, in Q3. We're currently finalizing commercial terms of the Ecuador route, and it is too early for us to comment on that at this point in time.
Based on well performance and depletion, should we expect 2023 year-end reserves to look similar to the 2022 year-end figures?
Well, yes. You know, we're targeting that. I have always said that I wanted to grab some of the 3P, which in essence you try to replace the 2P, you know? So it should be the same. On the 2P. On the 3P, eventually they need to converge, so the 3P eventually needs to come down.
Management has indicated in the past that they want to maintain a $60 million cash balance, and that other monies over and above will be available for distribution, such as special dividends, et cetera. We have $94 million at the end of Q3. Why are we not receiving a larger special dividend above $0.015? We could very easily handle an additional $0.01-$0.02.
Well, we stated our return of capital plan and excess liquidity calculation, and it needs to factor in the future working capital and CapEx needs over the next 2-3 months. Q4 will be a busy quarter for us, technically, and hence, capital expenditures and payables will be higher versus Q3 2023. So all of that is factored into the liquidity test that we look at of $60 million and what's available for the distribution to shareholders.
Yeah, and we have always mentioned that we need to be careful with that concept of liquidity. You know, we as management, we need to look, you know, a year from now. So I think whoever asked the question probably spoke to my wife, you know, that of course, she also likes more dividends. We're fully aligned, but we need to look, you know, for the health of the company for the future.
Have any further testing results been confirmed with regards to oil reserves at Osheki?
Not yet. We have yet to drill that key well where management is very excited about the potential. Permits take a long time, unfortunately, so things have been pushed late into the future. Now, we're projecting in 2025 to be able to drill that well. And in the meantime, we continue to do more geologic work, you know, seismic reprocessing, things like that, you know, just to be 100% sure. And then see if anyone would like to join us on this, I believe, a great project.
Some of your peers have looked to broaden their Latin American portfolios into new countries. Is M&A outside of Peru also an option being considered by the company?
Yes, absolutely. You know, now we have made it clear that we're gonna look for something that makes a lot of sense. I have always stated since I set up this company, it's almost six years ago, I have always liked Ecuador, you know. And so the team, senior team is ex-Oxy, so they know Ecuador, Colombia, very well. But again, we always compare against Bretaña, and it's difficult when you have such a wonderful field like Bretaña. You know, but we are and it has to be something that truly adds value.
It was previously mentioned, adding storage downstream to prevent low water levels from impacting barging. Is this part of this year's CapEx, and could this be completed by next summer?
We have been looking at that, but we don't have yet a specific timetable. What we have done in the past is add to the barge fleet. We have 1.7 million barrels of barge fleet, and as I showed, the way we are now unloading oil in Manaus, you know, sort of fits into that equation, you know, that we are accelerating the move of the barges.
What is the M&A opportunity set in Peru as you see it? Would you prefer to acquire cash flow positive production assets, or are you more interested in higher return exploration, appraisal, and development assets?
You know, I believe that we could, and as Doug mentioned in his presentation, tackle both. You know, so a nd again, you know, we maybe bring a partner for Block 107. We can look at some M&A. We are managing and looking at everything.
Two questions. Can you hire more barges during the low season for the Amazon to keep production flat? Is the first question.
Well, the issue that we have is that in the barges from Brazil, their draft is much, you know, higher than the ones in Peru. And in Peru, we basically are using the entire fleet. So some of the local companies in Peru have offered to build more barges, and hopefully they're ready by next year, so that will improve quite a bit. So we're looking at ways to optimize the entire, you know, transport highway that we have, as I mentioned in my presentation. That, so Peruvian barges, they need to build some more, because the Brazilian ones in the dry season, they have difficulty getting into Peru.
Is there any chance you will increase share buybacks?
Well, that's not likely at this point in time. We are currently near the maximum of what we are allowed to buy back from the TSX rules for standpoint. We could potentially look at this once we're able to increase liquidity of the stock over the longer term, since that's one of the key drivers.
Just a reminder, if you'd like to ask a question, please do so via the platform. This is currently the final question on the list. Has PetroTal been hedging at these oil prices where Brent has been around $85?
No, we have not been hedging at this point in time. We watch the oil prices closely, and with our advisors, we'll determine if we need to put some other hedging in place. You know, one of the key reasons we had hedges in place in the prior year was because of the bond repayments and that were required. So not having any scheduled debt that needs to be covered gives us a bit more flexibility, and of course, we have flexibility with our capital investment program as well. So that's our perspective at this point in time.
Manolo, Doug, thank you. I'll now hand back to you for closing remarks.
Well, I wanna thank everyone listening to this presentation, and, and for your questions, you know, showed the, the interest in, on PetroTal. We're extremely excited, you know, try to finish this year, with increased production and setting ourselves to have a fantastic 2024. Thank you so much.