VAALCO Energy, Inc. (EGY) Q1 2022 Earnings Report, Transcript and Summary

Good morning, and welcome to the VAALCO Energy First Quarter 2022 Earnings Conference Call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Al Petrie, Investor Relations Coordinator. Please go ahead.

Thank you, Operator. Good morning, everyone, and welcome to VAALCO Energy’s First Quarter 2022 Earnings Conference Call. After I cover the forward-looking statements, George Maxwell, our CEO, will review key highlights along with operational results. Ron Bain, our CFO, will then provide a more in-depth financial review. George will then return for some closing comments before we take your questions. [Operator Instructions] I'd like to point out that we posted a first quarter 2022 supplemental investor deck on our website this morning that has additional financial analysis, comparisons and guidance that should be helpful. With that, let me proceed with our forward-looking statement comments. During the course of this conference call, the company will be making forward-looking statements. Investors are cautioned that forward-looking statements are not guarantees of future performance and those actual results or developments may differ materially from those projected in the forward-looking statements. VAALCO disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Accordingly, you should not place undue reliance on forward-looking statements. These and other risks are described in yesterday's press release, the presentation posted on our website and in the reports we filed with the SEC, including our Form 10-K. Please note that this conference call is being recorded. Let me now turn the call over to George.

Thank you, Al. Good morning, everyone, and welcome to our first quarter 2022 earnings conference call. We continued to execute on our strategic vision, built around accretive growth while creating and returning value to our shareholders. Production in Q1 2022 was up 6% and adjusted EBITDA increased by 49% over fourth quarter of 2021. We have now successfully drilled, completed and placed on production the first two development wells of our current drilling campaign at Etame. Our first well was a development well, the Etame 8H-ST, which was highly successful, came online in February and exceeded our internal forecast. We then moved the rig from the Etame platform to the Avouma platform, drilled and brought online the Avouma 3H-ST development well in late April, also above our internal forecast. We are now drilling the third well of our four currently planned wells in the 2021, 2022 program. We are also progressing the field reconfiguration and conversion to an FSO at Etame on time and on budget. In March, we paid our first quarterly cash dividend and announced that we are paying our second quarterly cash dividend later this quarter. As you can see, we are delivering on our strategic objectives and in many cases, exceeding expectations, which is firmly placed VAALCO in a financially enviable position. Turning to our first quarter 2022 operational and financial results. We produced an average of 8,015 net barrels of oil per day. We had two listings in the quarter, which resulted in total oil sales of 616,000 barrels sold. As we discussed in the last call, due to operational and weather factors, we had some operational issues, which resulted in reduced production in February and lower liftings in the first quarter. At the end of March, with the recovery from the downtime and addition of the successful Etame 8H-ST well, our production rate increased to 9,500 barrels of all net per day, and is well above that level now. In the first quarter, we saw sustained higher oil prices, which drove revenue significantly higher as well. Our adjusted net income excluding the impact of unrealized derivatives and deferred income taxes was a very strong $21.1 million or $0.36 per share. Our adjusted EBITDAX was 33.5 million in quarter 1, 2022, compared with 22.6 million last quarter. We are currently more than sufficient line of sight to fund our 2021, 2022 drilling campaign, FSO conversion capital, and dividend from cash on hand and operational cash flow in 2022. We continue to be focused on growing our production levels through this period of high oil prices. Turning our attention to the future. Our strategic vision is built on accretive growth through organic drilling opportunities, expanding our margins and accretive acquisitions. We have used the 3D seismic that we acquired over Etame to maximize the impact of our 2021 and 2022 drilling campaign. Additionally, we are derisking future drilling locations and potentially identifying new drilling locations with further 3D processing. In February, we reported that we completed and placed the 8H-ST well online at rates above our initial estimates. In late April, the Avouma 3H-ST development well was completed and brought online again with initial rates above our internal estimates. The rig has stayed on the Avouma platform when we have begun on the third well in the program, the site to below 1H-ST development well. This well is targeting the Gamba reservoir, but is also being drilled deeper to test the Dentale formation. As a reminder, the Dentale is productive in another area Etame, and did this well has a good shows we can potentially complete and produce from the Dentale and the Gamba. This well can move 2P Gamba reserves to PDP, and as exciting as it could also bring contingent resources in the Dentale to PDP and potentially de-risk additional Dentale resources. For the second quarter 2022, we are estimating our production to be between 10,000 and 10,700 barrel of oil per day net. At the midpoint of guidance this would be 29% increase compared to the first quarter. In addition, we are forecasting a significant increase in sales between 10,700 and 11,300 net barrels of oil per day. At the midpoint of guidance, this would be a 61% increase compared to the first quarter. This is particularly opportune time to have a significantly increased sales at the prices we are seeing now. And in hand with production increase will be margin expansion and a per barrel cost reductions. As we have previously advised about 90% of production costs are fixed and as production increases our barrel costs will decrease. Every new barrel we bring online is more economic because of the low available cost. So as we grow production, we are also growing our margins per barrel, and reducing our cost per barrel. For the second quarter, we expect our barrel production cost, excluding workovers to be between $22 and $25, which represents a 20% decrease at the midpoint of guidance compared to the first quarter. From a capital standpoint, we continue to see our capital expenditures related to the 2021, 2022 drilling program. The field reconfiguration at Etame, and the FSO conversion to be in the range of 90 million to 110 million for the full year 2022. We expect to spend about 40 million to 50 million in CapEx in the second quarter of this year. We continue to forecast that all of our capital commitments in 2022, as well as our dividend will fully funded from cash in hand and cash from operations. With the drilling program Etame progressing forward nicely, we are also managing our FSO solution project simultaneously at Etame, which will reduce costs and improve margins. Last August, we announced that we had signed and received partner approval for the new FSO solution. The new FSO will significantly reduce storage and offloading costs by about 50%, increase effective capacity for storage by over 50% and lead to an extension of economic field life resulting in a corresponding increase in recovery and reserves at Etame. During the second quarter, we signed a major construction contract with DOF for the field reconfiguration and upgrade. This secured a significant portion of the [works group] for the overall FSO project. The field reconfiguration work has begun and the capital conversion are on schedule and on budget. We are expecting that the vessel will begin sea trials in late June before being mobilized to Gabon. As a reminder, our estimated capital cost associated with the FSO conversion and field reconfiguration in 2022 are expected to be between 25 million to 30 million net to VAALCO and are included in our CapEx guidance. This capital investment is projected to save approximately 13 million to 16 million net to VAALCO in operational costs through 2013, giving the project a very attractive payback period of only about two years. We will continue to keep our shareholders appraised of the progress of both the field reconfiguration and the FSO conversion through our press releases. In October, we announced exciting new opportunities in Gabon. VAALCO has entered into a consortium with BW Energy and Panoro Energy. The consortium has been provisionally awarded two blocks in the 12th Offshore Licensing Round in Gabon, with two exploration periods totaling eight years, which may be extended by further two years. The two blocks G12-13 and H12-13 are adjacent to VAALCO’s Etame PSC as well as BW Energy and Panoro’s Dussafu PSC offshore Southern Gabon. The majority of these two blocks are in water depth similar to Etame, both in Etame and Dussafu have been highly successful exploration development and production projects, undertaken by the consulting members over the past 20 years with approximately 250 million barrels discovered to date. The consortium is working through detailed production sharing contract discussions with the Gabonese government. Another layer that holds significant future potential for VAALCO is Equatorial Guinea. We have a substantial working interest in Block P and we are evaluating several development step out and exploration opportunities on our acreage. We are excited about our opportunities on the block and believe it makes sense to move this project forward with a more definable timeline and potential development. Last summer, we completed our feasibility study for the standalone development of the Venus discovery in Block P and we're moving forward now with the few development concepts. We are in advanced discussions with our partners and government and anticipate making significant progress towards an agreement to allow approval within the second quarter 2022. We are committed to profitably exploiting the resource potential of our assets and EG could become a significant operational asset moving forward. Turning to our ESG efforts. We recently recruited a full-time ESG manager who will be based in Houston. We are in the process of a completing our annual ESG report and it should be published in the second quarter ahead of our Annual General Meeting. We remain focused on showing progress and improvement in our environmental, social and government metrics. In summary, there is a lot to be excited about as we enter the second quarter of 2022. We are accretively growing production at Etame through our successful drilling campaign while continuing to progress forward exciting projects in Gabon and Equatorial Guinea. I would like to thank our hardworking team here at Vaalco who continue to operate and execute our strategic vision. As you can see, we are firmly focused on maximizing shareholder return opportunities and operating with the highest regards towards ESG. With that, I would like to turn the call over to Ron to share our financial results.

Thank you, George, and good morning, everyone. Let me begin by saying I'm also pleased with our operational financial performance and we remain very well positioned to execute in our strategy of accretive growth while adding and returning value to our shareholders. Turning to our financials. Adjusted EBITDAX rose 49% to $33.5 million in the first quarter of 2022, compared with $22.6 million in the prior quarter and nearly double the $18 million in the same period of 2021. We've clearly benefited from sustained higher realized pricing. This has allowed us to fund our strategic initiatives with cash flow and cash in hand, including our 2021, ‘22 drilling campaign CapEx, FSO conversion, and field reconfiguration costs. We also reported strong net income of $12.2 million or $0.20 per diluted share in the first quarter of 2022, which included a 19.3 million non-cash unrealized derivative loss, and 10.3 million deferred tax benefit. After normalizing for the deferred tax benefit, an unrealized derivative loss, our adjusted net income for the first quarter of 2022 totaled $21.1 million or $0.36 per diluted share, as compared to an adjusted net income of $12.5 million or $0.21 per diluted share for the fourth quarter of 2021. On the first quarter of 2021, VAALCO reported $8.7 million in adjusted net income or $0.15 per diluted share. Production for the quarter of 8,051 net barrels of oil per day was higher compared to 7,554 net barrels of oil per day in the fourth quarter of 2021, which was expected due to the first well of the drilling program being brought online in February, but was partially offset by deferred production due to temporary operational issues in February. Production was up 55% from the same period in 2021. Sales volumes in quarter 1, 2022, were down 13% from the fourth quarter, but we're within guidance and flat with the same period in 2021. The decrease in volumes is primarily due to only having two listings in the first quarter 2022. As we discussed in the Q4 earnings call, this was due to timing issues from the temporary operational challenges in February, which resulted in lower listing volumes. This will be a timing difference with production on stripping sales volumes and will result in higher sales volumes in the second quarter of 2022, which you can see in our Q2 sales guidance of between 10,700 and 11,300 barrels of oil per day. Our crude oil price realization increased 42% to 109.65 per barrel in the first quarter of 2022 versus $77.31 per barrel in the fourth quarter of 2021 and was up 79% compared to $61.31 per barrel in the first quarter of 2021. At the end of 2021, and the beginning of 2022, we hedged a portion of our expected production in 2022 to lock in strong cash from generation to assist in funding our capital program and dividend commitments. As of the 31st of March, we have 954,000 barrels hedge for the remainder of the year, an average price of $76.97. In total, we currently have about one third of our full year 2022 guided production hedged. Our full derivative position can be found in yesterday's earnings release as well as in our Q1 supplemental information presentation pack on our website. Turning to expenses. Production expense, excluding workovers for the first quarter 2022 was within guidance at 18.4 million. This was slightly lower on an absolute basis compared to the fourth quarter of 2021. Costs were 14% higher than the same period in 2021, primarily driven by a full quarter of production in quarter 1, 2022 from the acquisition of Sasol's interest in Etame that closed in February 2021, compared with just over 1 month in Q1 2021. The per unit production expense, excluding workovers are $29.83 per barrel. In the first quarter of 2022 increased as compared to $26.82 per barrel in the fourth quarter of 2021 and $26.02 in quarter one 2021, primarily due to lower sales volumes. Given the expected increase in sales for the second quarter, our guidance range for production expense excluding workovers for second quarter 2022 is expected to be $23 million to $24.5 million or between $22 to $25 per barrel of oil sales. We're not changing our full year 2022 production guidance of $73 million to $83 million or $19.50 to $22.50 per barrel. We had no workovers in the quarter of 2022, but based on timing, we are forecasting a potential workover towards the end of the second quarter of 2022. Depreciation, depletion and amortization for the first quarter of 2022 was $4.7 million or $7.59 per net barrel of oil sales compared to $4.1 million or $5.83 per barrel on the fourth quarter of 2021. And $4.1 million or $6.70 per barrel in the first quarter of 2021. DD&A expense in the first quarter of ‘22 on a per net realizable barrel of crude oil sales basis was higher compared to the prior periods presented due to higher depletable costs associated with ’21-22 drilling campaign. We anticipate DD&A to be in the range of 7.75 to 9.50 per barrel for the second quarter of 2022. General and administrative expense for the first quarter of 2022, excluding stock-based compensation expense was $3.6 million, slightly above our guidance compared with $2.2 million in the fourth quarter of 2021 and $3 million in the first quarter 2021. The increase compared to prior periods was a result of higher salary and wages costs and audit related costs partially offset by lower legal fees. The per unit G&A rate excluding stock-based compensation in the first quarter of ‘22 of 5.88 per barrel of all sales was higher than both the fourth quarter of ‘21 and the first quarter of ‘21 due to lower sales and higher expense. For the second quarter of 2022, we expect cash G&A to be in the range of $2.5 million to $3.5 million. We're not changing our full-year 2022 cash G&A guidance of $9.5 million to $12.5 million. Non-cash stock-based compensation expense for the first quarter of 2022 was $1.4 million and was comprised of non-SARs-related expense of 400,000 and SARs-related expense of 1 million. For the fourth quarter of ’21, stock-based compensation was 400,000. And for the first quarter of 2021 stock-based compensation expense was $1.6 million. Turning now to taxes. Foreign income taxes are attributable to Gabon and are settled by the government taking their oil in kind. Income tax expense for the three months ended March 31, 2022 was a benefit of $4.6 million. This comprised of 10.3 million deferred tax benefit and a current tax expense of $5.7 million. Income tax expense for three months ended December 31, 2021 was a benefit of $10.9 million. This was comprised of $16.1 million of deferred tax benefit and a current tax expense of 5.2 million. Income tax expense for the three months ended March 31, 2021 was 3.1 million and included 300,000 of deferred tax benefits and a current tax expense of 3.4 million. For all three periods, the overall effective tax rate was impacted by non-deductible items associated with operations and deducting foreign taxes rather than crediting them for United States tax purposes. I'd like to refer you to our supplemental information deck that we posted to our website. We've updated our net BOPD slide that shows a strong cashflow we are generating at current prices. We've incorporated the midpoint of our 2022 guidance using a 90 BOPD realized oil price. We've seen exceptional early results in our drilling campaign and remain on track to deliver our lower cost FSO solution on time, which will result in substantial savings on an absolute and per barrel basis despite inflationary pressures. On the same slide, we've shown an indicative quarter four 2022 net BOPD, assuming continued success in the drilling campaign and a full conversion of our FSO solution. Our sales guidance for the rest of the year is meaningfully higher than what we realized in the first quarter 2022. Even with our lower sales volume for this first quarter, our Q1 2022 annualized EBITDAX is about $134 million, $2.28 per share annualized. With a recent stock price in the range of $6.57 bucks, we're trading at a low multiple of EBITDA of about 3x despite paying a dividend and being debt free. At March 31, 2021, we had an unrestricted cash balance of $18.9 million. This does not include the proceeds from the March listing of 44.6 million, which were received in April 22, plus 3.8 million in non-operating joint owner receivables. Working capital at March 31, 2022 was negative 21.3 million compared to 4 million at December 31, 2021. The decrease in working capital is related in large part due to the crude capital costs associated with adrenaline program and derivatives. For the first quarter 2022, net capital expenditures, excluding acquisitions, total $23.1 million on a cash basis and 31.8 million on an accrual basis. These expenditures were primarily related to cost associated with the ’21-22 drilling program, the FSO conversion, and the Etame field reconfiguration. As George mentioned, for the second quarter of 2022, we estimate our net CapEx to be approximately $40 million to $50 million and continue to expect our full year CapEx to be in the range of $90 million to $110 million. As has been the case since the second quarter of 2018, we are cutting no debt. Last week, the Board of Directors approved a cash dividend of $0.0325 per common share that is payable on June the 24, 2022 to stockholders on record at the close of business on May the 25, 2022. This equates to a full-year 2022 annualized cash dividend of $0.13 per year. With that, I'll now turn the call back over to George.

Thanks, Ron. The future remains for very bright for Vaalco, and this is a very dynamic time in the energy industry. We are accretively growing production and cash flow through organic drilling and continue to evaluate additional opportunities with a focus on providing sustainable return to our shareholders. We've already seen the successful initial results in our drilling campaign with the combined production of Etame 8H-ST well, and Avouma 3H-ST both exceeding our internal expectations. Additionally, we are on schedule and on budget for Etame field reconfiguration and the FSO conversion. With the higher sustained commodity pricing, we are confident that our 2021-2022 drilling program, our field reconfiguration and FSO conversion and the dividend we instituted this year will be fully funded by cash in hand and internally generated cash flow. Etame Block P and potential now for the new blocks in Gabon can enhance our business and provide a strong platform for organic growth, allowing Vaalco to build size and scale in West Africa. We believe that with a strong cash position and our increasing size on scale, we can evaluate and more easily incorporate accretive acquisitions that meet our stringent investment criteria and strategic vision. Finally, as part of our value creation strategy moving forward. We paid our first quarterly dividend in March and announced our next dividend will be paid later this quarter. We believe that prudently returning cash to shareholders is a great way to complement our accretive growth strategy. As you can see, we are firmly focused on ways to increase total shareholder return, while operating with the highest regards towards ESG. We are executing our strategic objectives and are excited about the near-term and long-term opportunities for Vaalco. Thank you. And with that, operator, we're ready to take questions.

[Operator Instructions] And our first question will come from John White of ROTH Capital.

Congratulations on the -- these very nice results. And everything going so smoothly at Etame, I'll skip that and go to the new blocks at Gabon block G12,13 and H12, 13. Can you update us on that in terms of the official awarding of the blocks PSC and your seismic program?

Yes, John, I can. I mean, at the moment, we continue to be in negotiations with the Gabonese government around the commercial terms of both of these blocks with our partners. So those discussions were -- have been taking place through Q1 and are continuing into Q2. We are hopeful to see a resolution towards a formal award of the block, so completion of the commercial discussions. I'm hoping we can see that in Q2, but it may stretch into Q3. And if it does come into Q3, then it's -- the seismic acquisition will definitely not happen in 2022. And in Q3, it's probably getting to a to even get some of the reprocessing done in 2022. So most of that will slip into 2023.

Okay. Well, thanks very much, and good luck with all of that. And any updates on EG Block P?

Yes. On EG Block P, we've been in discussion with the partners, and we are, I think, I'm confident we can get to a resolution on an arrangement with the partners in Block P during Q2. And certainly, that's what we're planning. And I think as soon as we come to that resolution, I'm confident that the position with the minister that we'll get the approval that we require to move Block P forward. For the POD draft that we have at the moment, we're -- as we mentioned previously, we've completed the feasibility studies. We've looked at how we're going to execute this first well. And from a planning standpoint, we're looking at that first well in early 2024, probably the January, February 2024, subject to the POD approval.

The next question comes from Charlie Sharp of Canaccord.

Just a question actually on the current well and the Dentale formation and the plans to test that. How important do you think the test results from this well is in trying to determine what you think the license why potential is of the Dentale.

A good question, Charlie. I don't think it's not a make or break position on the Dentale for this well. So I don't think it it gives us a benchmark for the overall performance of that particular sand. What this does do for us to though is and this is why we're doing the test it does give us that opportunity to convert the contingent resource direct into 1P reserves. And with the -- when we looked at this option, the original well was only going to go down as far as the Gamba. But we like what we see in the deeper position in the Dentale. With these commodity prices, it made sense to increase that well cost at this time and take that opportunity. So we deliberately took a position to test and case down to the Dentale so that if we find what we hope to find is a good oil-bearing sand that we can immediately make it a producer. And then at some point in the future come back and then produce from the Gamba.

I see. And if this is a successful well, do you think that there are in the near term opportunities for you to pursue the Dentale?

There are -- I mean, the next program is also going to look at a Dentale target.

The next question comes from Stephane Foucaud of Auctus.

Bidding up on what the question from Charlie. So if we look at the ongoing Dentale well, how much do you think contingent resources might be converted in a success case to 2P? And then this, again, on this ongoing well, from a -- if we look at the Gamba, are we -- would you expect that this -- the Gamba reservoir would deliver for rate similar to the first well of this year, the second well of this year or something else just wondering what will be the expectations?

Okay. With regard to what the prospectivity is in the Dentale, I mean, we have 1 well producing from the Dentale at the moment of the Defense platform. I think we -- this opportunity will start to increase our knowledge of the Dentale area, and the next well we'll expand that even more. how much we can move from contingent resource into 2P? Obviously, that is purely going to be based on the well results. But I mean we're -- we're hopeful and we're encouraged by the opportunity to go into an additional sand over and above the Gamba. So I don't have an exact number for you, Stephane, because it would be based on what we see from the from the logs and the results we get from this first and -- the first well we're drilling now in the second well that we're drilling next in the North Tchibala. With regard to what we expect from this well? Do we expect the kind of results we saw in 88 or do we expect the kind of results we saw on 38? Again, looking at the location and what we've seen in the past, I would align it more towards the 38 position. However, we were actually -- it was successful in the Dentale, we won't know what that's going to be until sometime in the future because we will be producing from the Dentale before we come shallow in the Gamba. But if the Dentale is unsuccessful when we come shallow, we would expect the rates similar to what we're seeing on 38.

Next question comes from Bill Dezellem of Tieton Capital.

Let me start with your -- the 2 wells of this program that you have both came in better than expectations. Is that because the rock is just a higher quality than you recognized? Or were your expectations just simply being modest?

We always want to be modest. But no, I think there's 2 factors that gave us better results than we anticipated. Obviously, we announced in the wells, both permeability and the porosities were better than anticipated. So we did see better reservoir characteristics than we initially forecast. But in addition to that, we've got to also tanker drillers because we've also seen excellent well placing both on Etame and Avouma. So the well placing position is also critical to well performance, as you know.

Right. Okay. And can we read anything into that permeability and porosity being better than anticipated with your remaining locations? Or is there enough of a difference between the locations that we shouldn't be reading too much into it too early?

I wouldn't read too much into the next 2 wells too early, primarily because both wells are initially targeting the Dentale, which is completely separate from the signs we're producing from and the first 2 wells. So there's not a direct read across there. But certainly, there is obviously a degree of some correlation between 38 and this well if we were in the Gamba.

And what is your suspicion just relative to the Dentale sands versus the Gamba sands in terms of their flow rates production potential for the field, et cetera, et cetera? Similar, less than or more than or unknown truly and you need to figure it out?

Well, I think from what we know with the producing well, we would say similar too. But the key areas where we're going into right now is whether we're going into a prolific hypercarbonarea or whether we go into a water wet area and there's not sufficient hydrocarbons there to make it work, especially in this first opportunity. So I think it's -- the overall that we experienced between the Gamba and obviously, we've got other producers in the area that produce them from the Dentale, I think we are fairly excited by the opportunity to test the Dentale or we wouldn't be doing it. So our position is -- but subject to the hydrocarbon position on the Dentale are not being walker wet. I think it's to see we would expect similar characteristics.

That's very helpful. Allow me to shift, if I may, to your tanker offloading or loadings. What as your production increases, what are you considering -- philosophically considering the normal cadence of offloads to be? Is it 2 a quarter? Is it 3 a quarter? Or does it go back and forth between 2 and 3? I'm trying to get my head wrapped around this higher production and what that ultimately means.

Bill, it's Ron here. I'll step in on this one. On the scheduling, generally, we would schedule 1 list per month. Outside of, obviously, the GOC, the government's oil, they take that once a year generally. But that will all depend on on production volumes and quantities as the year progresses. Generally, that lifting has happened at the end of Q3 in the last year or 2. So we're looking at something similar in 2022. The other part and the other variable on this is that as we get through Q3 and the new FSO comes into play, it has a much larger capacity, which allows us to look at, let me say, better optimization of loading from that vessel. So it allows us also to ensure that there's no stoppage from a production point of view due to the tanks being filled soon. The capacity goes up quite considerably from the existing FPSO to FSO. So what I would say is in we're looking at a little bit over 1 per month because we had the last lifting kind of slipped into April 2 from Q1. So you'll definitely see from our sales guidance. Our sales guidance is way up for Q1. I think it's about 60% up on Q1, and that really reflects, I would say, an extra lifting in there.

So basically, the starting point is on offloading per month, and then you have to bring operational realities into it, it will adjust that up or down depending on.

Exactly.

That's helpful. And then 1 additional question, please. Earlier on, the question was asked about the BW Energy Gabon block. And I'd like to take that question 1 step further. With what you know today, when would you anticipate production coming from that block benefiting VAALCO?

Okay. Well, what we know today, and I'll go back to my earlier answer, that it's unlikely we'll even get a reprocessing of existing parts of seismic done in '22. So we're looking at capture and interpretation in '23. And then the commitment of an exploration well probably '24 or '25. Depending on the location of the exploration world and its proximity to existing infrastructure, either Dussafu or Etame, there may be an opportunity for a tieback on a production well in '25 or '26. But it's really down to the location of a commercial find and how that locates to each of our infrastructures. But certainly, nothing I would say in my mind be before '25. And even 25%, we'd be looking at a single well tieback to either Dussafu or Etame. If something more substantive was found that justifies separate structures inside each of the blocks, then that will push the production date further out.

Next question comes from Jamie Wilen of Wilen Management.

One more question about the new drilling. Could you tell us about the timing for how long will it be to test the Gamba and then how much longer to go to the Dentale? And will you issue the results from the Gamba prior to? Or will you do that all in 1 time?

Okay. We're looking to drill through, I believe, it's mid-June towards the end of June, sorry. We will be issuing the results all at the same time. So we will be drilling through the Gamba where we know we've got proven oil-bearing sands and then deeper into the Dentale. And obviously, the current well designs are looking for us to basically perforate in the Dentale should we find commercial volumes of hydrocarbons. We would immediately announced that or we would then announce that there is no commercial volumes of hydrocarbons in that particular location of the Dentale, and we will be pulling back to perforate the Gamba complete there.

Got you. As I look at the chart that you provided for your netbacks for 2022, the first layer is the 2022 margins at $90 realized oil. Is that for the fourth quarter? Or is that for the entire year when you talk about the $53.83 per barrel of free cash flow?

Jamie, it's Ron. Again, that's a full year. So it's not Q4. So what we wanted to do there was kind of demonstrate similar pricing, how '22 is lining up now versus 2021 at the $90 pricing level.

Okay. So let me run through some numbers and tell me how far off I am. If you're going to do, let's just say, 1 million barrels in the fourth quarter and you're going to be realizing of $55 to $60 per barrel of free cash flow, we're looking at somewhere in the neighborhood of $1 per share of free cash flow in the fourth -- just in that fourth quarter alone?

Again, I've got to really point to the guidance there, Jamie. But I would say Q2, where we've given you the guidance for our sales. That's going to be -- it's probably going to be one of the strongest quarters we've ever seen at local. And if you look at that on the basis of 1 million barrels, which is about the midpoint for our forecast for Q2, that's going to be not 1 million off of what you're talking about on a per share basis based on 59 million shares -- 59 million to 60 million shares.

Okay. And then lastly, could you talk about your hedging strategy? Obviously, you needed to secure your drilling program that's now more more very well secured, but you have hedged a portion of our of your production? Are you looking to hedge any -- or do we not need to do that since we are kind of playing offense as opposed to defense?

With a great analogy. At the moment, Jamie, we've got about 1/3 of our production hedged for this year. Our forecast to basically say that we're well covered for our commitments. So there's been no approach from us to go into Q4. Obviously, we take a look at the hedge position at any point in time. But there's obviously still a large degree of volatility in the marketplace overall, which impacts obviously forward positions. Yes. We've taken a look at Q4. We've taken a look at it into Q1 2023. But as you're aware, a lot of our capital expenditures and commitments fall off through Q3 of this year. Q4 will have some, but not the level of spending that we got through the first 3 quarters of this year. So we've not felt the necessity or the need to go in and hedge in at these prices. I mean Q4 hedges at this point in time if we're doing simple swaps that we've done in the past, you're talking about the high $80 to $90 oil. And I don't want to -- we're not speculate, but we don't want to rush in and lock into that when there's not necessarily a need. But it's certainly something, Jamie, and we will always keep a look at. And as you're aware, our commitment is always to look at our overall cash flow to meet our capital and operational requirements as well as our dividend position. And one of the things I would say is we have had a look at core. And certainly, if we've got a bottom number there from a position that covers our commitments allows us to get as much of the upside as possible. That may well be something that we look at going into 2023.

Okay. And then also another lastly. When you first announced your dividend program, the price of oil was obviously much, much lower. And this was prior to to successful runs with the drill bit. What is your policy with raising that dividend given the cash flow that you're looking at moving forward is higher than what you had achieved, what you were achieving when you initially announced the formation of the dividend policy?

Yes. I mean I think we commit with our inaugural dividend just this Q1 policy was derived from a Q4 position on a 2023 -- sorry, 2022 budget. And if you recall, what we said with that dividend is that we put a dividend in place that we regard fully sustainable through and we committed to that through 2025 at this particular level. Obviously, we, as a Board, continue to monitor opportunities to amend that position through additional windfall cash accretion that we've seen with the higher commodity prices, and that's balanced with other opportunities that we may consider where that cash can be deployed partly through dividends, partly through additional program activities partly through trying to increase production further. So there's a balance to be had. The question is, have we as a Board, directly reviewed and address that. As of this point, no, we have not. But I think it's obviously what we said from the put the algal dividend in place was that there was always scope for that to be amended, but that was most likely to be in a position once we got through the significant CapEx expenditures we have in the first 3 quarters.

The next question comes from Robert Carlson of Janney.

You covered my question on hedging in the last call. So congratulations and keep up the good work. You guys you're doing great.

The next question comes from Kenneth Pounds of Castlebury Advisory.

Are you putting together a drilling plan for next year yet? And is that going to be Gabon also in addition to Block P?

Yes. Well, we haven't landed on our drilling plan as of yet. But what we're trying to get to with -- Gabon with the time is get to a plateau level of production that fully utilizes our and that means that we have to look at a more continuous drilling program rather than a cyclical drilling program where we're selecting opportunities that will increase the overall production to utilize the but at the same time, arrest decline that we see in the existing well inventory. So we are closely looking at the targets for 2023. We're looking at opportunities that we have within existing contractual positions in 2022. And we're very also very conscious that the pricing of the drilling units and the long-lead equipment is currently increasing substantially, both in terms of cost and in terms of time frame to secure these. So that's something we are very focused on, and we're looking at block , I think I heard you mention blocked be if we can secure a drilling program for 2023 blocking would be at the end of that program in January 2024. But I was as of right now, we'll continue to mature targets for those programs.

Right. That was my next idea. I'm sure our day rates are starting to go up and I suppose there's an opportunity if you elect in some rigs now for next year that, that might be better.

Yes. That's certainly on our agenda as well. And as we answered in the last question regarding the excess cash generation that we possibly will see in Q4 some commodity prices hold, there's a lot of opportunity to perhaps utilize that at existing drilling rig rates as opposed to having to look at the higher rates.

Great. Maybe you could remind us again that the FPSO sounds like a great advantage. Is there some production limiting factor to that down the road?

Absolutely not. There's no production limiting fact moving from the FPSO to the FSO. We currently have between 26,000 to 40,000 barrels of oil and that will not change with the with the FSO coming in. We're putting additional equipment and based on to term to allow that processing to continue. We're reversing the flow of a couple of the lines to make sure they're directed back towards the platforms instead of the existing FPSO. And the FSO itself is located in a different location from the FPSO more central in the field between the existing platforms. So there will be no constraint point forward in an always position with the FSO.

The next question comes from Richard Dearnley of Wan Partners.

What is the IP of the Dentale for the for BW and Panoro. And is that a guide for what you're looking for in your well?

Yes. Hopefully, I got that right. I mean, right now, I don't think the distance is too far, and I'd have to defer to my geo guys, but I think the distance is too far for a correlation between the Dentale that's being produced with Dussafu and the Dentale sands that we have in Etame. So I don't think there's an opportunity to correlate IPs on that one. And then I'm sorry, forgive me, I missed the second part of your question.

No, that answers it.

Our next question is a follow-up from Stephane Foucaud of Acutus.

Picking up of some of the comments you made about ongoing negotiation for the exploration of Gabon block and on the P block with with a partner. Could you perhaps give me a sense of what are the sticking points in both situations on basically what needs to be resolved? Is it, for instance, for the Gabon the question about cost all that you -- cost recovery at you're discussing, it's something else. And likewise, with the partner for the P Block, are there any really salient sticking put that need to be resolved?

Thanks, Stephane. I'll start with the Gabonese blocks. I mean, I'm not going to go into the detail of what the commercial discussions are with the government and our partners, but they cover a suite of fiscal and terms. We're in the licensing round in Gabon or this particular licence round you have the opportunity to bid both the the same to price and the terms around which you wish to operate in the block. It was slightly different from some other jurisdictions where you get the terms through legislation and you need a signature bonus. So it is the suite of PSC conditions that are being negotiated. Some may be we can see with our partners in view of obtaining others, but I can't really go into the specifics of which points we're negotiating on. With regards to Block P, there's no real sticking point at all. The real issue or on Block P with our partners is more about project ranking in portfolios as opposed to specific issues of economic viability and Block P. So as in any oil company operations where you have partners and we have multiple assets and multiple blocks, we all have projects being ramped in different ways that have demands on our cash and it's just coming to an equilibrium, we'll be combining those rankings between our portfolio and our partners' portfolio.

This concludes our question-and-answer session. I would like to turn the conference back over to George Maxwell for any closing remarks.

Thank you, operator. I think that Q1 has been a very strong quarter for VAALCO. I think that we've come across a couple of operational issues in Q1, which we've already highlighted which allows us to really come out with the gate in Q2 and blow Q2 away, but all indications are that we will. I'm increasingly pleased with the attendance on our calls and the quality of questions that we're receiving. This encourages me that we're getting an investor base and an analyst base that's really getting into the activities of the company and following along with us. So thank you for the call for your questions, and thank you for listening to us today.

The conference has now concluded. Thank you for attending today's presentation, and you may now disconnect. Thank you, operator. Good morning, everyone, and welcome to VAALCO Energy's First Quarter 2022 Earnings Conference Call. After I cover the forward-looking statements, George Maxwell, our CEO will review key highlights along with operational results. Ron Bain, our CFO will then provide a more in-depth financial review. George, will then return for more closing comments before we take your