VAALCO Energy, Inc. (EGY) Q4 2021 Earnings Report, Transcript and Summary

Good day, and welcome to the VAALCO Energy Year End 2021 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 Fourth Quarter and Full Year 2021 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 questions. [Operator Instructions] I'd like to point out that we posted a Q4 2021supplemmental investor 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 Securities Exchange Commission, including our Form 10-K. Please note, this call is being recorded. Let me turn the call over to George.

Thank you, Al. Good morning, everyone. And welcome to our fourth quarter and full year 2021 earnings conference call. Our ability to execute on our strategic vision is evident in our 2021 operational and financial results. This past year was one of the best in VAALCO’s history and 2022 could be an even better one. Production in 2021 was up by almost 50% over 2020 driven by the acquisition of Sasol’s working interest at Etame in February 2021. In June, we secured a charter break for the 2021, 2022 drilling campaign, which began in December. Our first well was a development well, the Etame 8H-ST, which was highly successful came online in February and exceeded our internal forecasts. We then move the rig from the Etame platform to the Avouma platform and are currently drilling the Avouma 3H-ST development well. In August, we finalized an agreement with World Carrier for a new FSO solution that costs almost 50% less than the current FPSO and will reduce our overall cost by approximately 17% to 20%. Thus allowing us to extend the economic life at Etame while increasing our margins and profitability. We successfully performed two work overs in September and October, which resulted in an increase to production of approximately 1,050 barrels of oil per day gross or 540 barrels of oil per day net to VAALCO. In October, we were provisionally awarded two offshore blocks as part of a consortium with BW Energy and Panoro Energy adjacent to establish development fields at Etame and Dussafu. We also moving forward with a standalone field development concept of the Venus Discovery at Block P in Equatorial Guinea. In November, we announced our board established a quarterly cash dividend policy to return cash to our shareholders and we are paying our first quarterly cash dividend later this month. We also announced the outstanding results of a yearend reserves with proved SEC reserves increasing by 250% to 11.2 million barrels of oil under two PCPR reserves increasing by 88% to 19.5 million barrels of oil. 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 fourth quarter and full year 2021 operational and financial results. We produced an average of 7,554 net barrels of oil per day, which was above the midpoint of guidance, and for the full year 2021, we produced 7,119 net barrels of oil per day, an increase of over 46% over 2020. We continued with strong oil sales in the fourth quarter reporting 709,000 barrels sold. For the full year 2021, we sold 2.7 million barrels of oil, which was an increase of 67% over 2020, primarily due to the Sasol acquisition. We continue to see rising oil prices and saw price increases every quarter in 2021 was drove revenue significantly higher as well. Our adjusted EBITDAX was $22.6 million in Q4 2021, and $85.8 million for the full year 2021, which is more than triple what we generated in 2020. These factors enabled us to build a significant cash position providing 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 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 the 2021 and 2022 drilling campaign. Additionally, we are de-risking future drilling locations and potentially identifying new drilling locations with further 3D interpretation. In December, we kicked off a drilling campaign on the Etame platform with the Etame 8H-ST development well. In February, we reported that we completed and placed the 8H-ST well online, with an initial flow rate of approximately 5,000 barrels oil per day, or 2,560 barrels oil per day net to VAALCO. After the strong results, we choked back for reservoir management purposes to just over 4,000 gross barrels of oil per day. The new well will go through a natural decline, and we continue to monitor its performance with currently exceeds our initial estimates. We are currently drilling the next well in the program the Avouma 3H-ST, development well and expect to have results on the well in the coming weeks. The rig will stay on the Avouma platform following the 3H-ST development well, to drill the third development well in the program. As a reminder, we initially said with a successful drilling program, the estimated increase in gross field production could be 7,000 to 8,000 barrels of oil per day, or 3,500 to 4,100 net barrels of oil per day to VAALCO when the full well drilling campaign is complete in 2022. We are well on our way to meeting these initial expectations. Hand-in-hand with the production increase will be margin expansion and per barrel cost reductions. As we have previously advised, about 90% of production costs are fixed, and as production increases, per barrel cost will decrease. Every new barrel will bring online is more economic because of the low variable costs. So as we grow production, we're also growing our margin per barrel and reducing our cost per barrel. From a capital standpoint, the estimated cost of 2021-2022 drilling program in 2022 is expected to be between $65 million to $75 million net to VAALCO. Given the increased oil price environment, upcoming drilling campaign has the potential to generate significant additional free cash flow, and the returns on these investments should be very strong. With the drilling program at Etame progressing forward nicely. We're also managing our FSO solution project simultaneously at Etame, which will reduce costs and improve margins. In August, we announced we had signed and received partner approval for new FSO solution. The new FSO will significantly reduce storage and offloading costs by almost 50%, increase effective capacity for storage by over 50% and lead to an extension of the economic field life, resulting in a corresponding increase in recovery and reserves at Etame. Last week, we announced the all of the associated engineering, long lead equipment and significant contracts for the FSO are proceeding in line with the projected timelines, which has the expected deployment of the FSO in the third quarter of 2022. Field reconfiguration activities are expected to begin later this month as planned. The Cut Diamond, a double whole crew tanker built in 2001 that has been reengineered as new FSO arrived at a shipyard in Bahrain in late February for the final modifications and certifications. We are expecting that the vessel will begin sea trials in late June before being mobilized to Gabon. Current estimated capital costs with FSO conversion and field reconfiguration in 2022 are expected to be between $25 million to $30 million net to VAALCO, which are in addition to our 2021 and 2022 drilling campaign costs. This capital investment is projected to save approximately $13 million to $16 million net to VAALCO and operational costs through 2030 given the project a very attractive payback period of only about two years. Turning to reserves, we are very pleased with the substantial growth of our reserve base. The proved reserve increased resulting from a combination of positive factors including improved world performance, Etame field life extension resulting from a changeover to a more cost effective FSO this year, had additions positive oil pricing revisions and acquisitions. SEC proved reserves at year end increased 250% to 11.2 million barrels, the 7.2 million barrels improved develop reserves, and 4 million barrels improved undeveloped reserves. Three main factors for the increase in our SEC proved reserves were the acquisition of Sasol’s interest at Etame, which added 2.6 million barrels positive pricing revisions with added 3 million barrels and 5 million barrels due to positive well performance revisions and FSO related field life exertion. As in prior years we continue to see positive reserve revisions due to well performance which demonstrates the strength of a premier Etame asset. These additions were partially offset by 2.6 million barrels due to full year 2021 production. The PV-10 value of approved reserves utilizing SEC pricing at $69.10 per barrel of crude oil increased to $99.3 million more than 6.5 times a PV-10 of $14.7 million as at December 31, 2020. That pricing used in the 2021 calculation is still significantly below the current strip pricing. We're also pleased with the increases we saw in our 2P CPR estimate, which increased proven and probable reserves using VAALCO’s management's assumptions for future brand escalated crude oil pricing and cost reported on a working interest basis prior to deductions for government royalties. The year end 2021 2P CPR increased 88% to 19.5 million barrels compared to 10.4 million barrels as at December 31, 2020. The PV-10 value of VAALCO’s 2P CPR reserves at year end 2021 is $183.7 million, up 117% from $84.4 million as of December 31, 2020. In October, we announced an exciting new opportunity 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 expiration periods totaling eight years which may be extended by further two years. The two blocks G12 and 13 and 812 and 13 are adjacent to VAALCO’s Etame PSC as well as BW Energy and Panoro’s disapproved PSC offshore Southern Gabon. The majority of these two blocks and water depth similar to Etame. Both Etame and Dussafu have been highly successful exploration, development and production projects undertaken by the consortium 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 Gabon’s government. Another area that holds significant future potential for VAALCO is Equatorial Guinea. We have a substantial working interest in Block P and we're 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 for potential development. Last summer, we completed a feasibility study for the standalone development of the Venus Discovery in Block P and we are moving forward now with the field development concept. As we work through development concept, we will provide more details about potential timing, capital costs and reserves and production estimate. We are committed to profitably exploiting the resource potential of our assets and EG can become a significant operational asset moving forward. Turning to our ESG efforts, we recently hired a full time ESG manager who will be based in Houston, who will begin drafting our annual ESG report shortly which will continue to show the progress we're making towards improving our environmental, social and governance metrics. Let me know review our production and sales volume guidance before I turn the call over to Ron. In the first quarter we had Etame 8H-ST well come on line in February, which boosted production ahead of our planned production levels for this well. Unfortunately, we had some operational issues in February that temporarily impacted our production. Abnormally strong currents caused a short delay in the planned lifting from the FPSO as a crude oil tanker could not get moved safely. This caused us to reduce production for a few days since the FPSO was at near capacity. Additionally, to accommodate the drilling of the Avouma 3H-ST development well we had to shut in production from a platform to allow the rig to move into position and begin drilling. This occurs whenever a jacked up rig is mobilized to drill a well and happened when we began the Etame 8H-ST well on the Etame platform, as a result of the shortening of Avouma, oil flow from the pipeline that transmits oil from the Avouma and sent platforms to the FPSO operated at a lower volume than usual. This in combination with a chemical imbalance in the fluids in the pipeline caused the paraffin buildup, resulting a temporary blockage in the pipeline. We had to shut in production at the Avouma sent fields for more than a week, we were able to restore production after running some chemicals to remove the paraffin buildup. These are the major factors as to why our first quarter 2022 production guidance is between 8,000 and 8,300 NRI barrels of oil per day, or 9,200 to 9,550 working interest barrels of oil per day. I would like to point out that the Q1 midpoint is still an increase of 8% over our Q4 2021 production number, despite the issues faced in the quarter. Because of a temporary lifting delay in a second lifting scheduled for the end of March, our sales for the first quarter will be lower than production. For the first quarter, our sales are expected to be between 6,600 and 6,9000 NRI barrels oil per day or 7,600 to 7,950 working interest barrels of oil per day. If oil prices continue to rise, this could be beneficial as we may receive higher prices on the lifting in Q2 than we would have received in Q1. For the full year, we are guiding production to be between 9,500 and 10,500 NRI barrels of oil per day or 10,900 to 12,050 working interest barrels of oil per day. Also for the full year, we are guiding sales to be in the same ranges as production. So we're expecting that the lower sales in Q1 will be made up in Q2 and Q3 in 2022. As you can see, we are projecting strong growth and production in 2022, an increase of about 40% year-over-year at the midpoint of our 2022 guidance range. In summary, there is a lot to be excited about as we enter 2022. I would like to thank our hard working team here at VAALCO who continue to operate and execute on our strategic vision of future growth and free cash flow generation. As you can see, we are firmly focused on maximizing shareholder return opportunities and operating with the highest regards towards ESG while we progress our strategic objectives focused on accretive growth. With that, I'd like to turn the call over to Ron to share our financial results.

Thank you, George. And good morning, everyone. As you can see from our accomplishments that George reviewed 2021 was a pivotal year for VAALCO and we're in a very good position both operationally and financially for 2022 and the future. Our earnings release included detailed financial information for both the fourth quarter and the full year 2021. So I will focus on just some highlights in addition to providing forward guidance. We reported net income of $34.4 million or $0.58 per diluted share for the fourth quarter of 2021, which compared favorably with a net income of $31.7 million or $0.53 per diluted share in the third quarter of 2021 and a loss of $3.6 million or $0.06 per diluted share in the fourth quarter of 2020. The fourth quarter of 2021 reflected stronger revenue due to the increased sales in the quarter, higher realized pricing and the non-cash deferred tax benefit compared with the fourth quarter of 2020. The fourth quarter of 2021 included $16.1 million non-cash deferred tax benefit, partially offset by a $1.8 million loss on derivative instruments. For the full year of 2021, we reported net income of $81.8 million or $1.57 per diluted share, compared with a loss of $48.2 million or $0.83 per diluted share in the year 2020. The year-over-year increase is primarily the result of increased sales, higher oil pricing and a change in deferred taxes of $66.6 million. Deferred taxes in 2020 was an expense of $24.2 million and is a benefit of $42.4 million in 2021. Also in 2020, there was a $30.6 million impairment charge to crude oil properties as a result of lower oil prices at that time. Our adjusted EBITDA totaled $22.6 million in the fourth quarter of 2021, a slight decrease compared with $23.3 million in the third quarter. However, fourth quarter 2021 EBITDAX was more than 6x to $3.5 million generated in the same period in 2020, primarily due to improved realized prices and increased sales partially offset by higher production costs, and higher realized losses on derivatives. Our full year 2021 adjusted EBITDAX totaled $85.8 million, or more than tripled to $26.6 million we reported in 2020. The increase was primarily the result of stronger revenues as a result of increased crude oil prices and higher sales volumes, partially offset change and realized losses between the periods. This strong cash flow generation has allowed us to continue to fund our strategic initiatives with internally generated funds. After normalizing for the deferred tax benefit and the unrealized derivative loss, our adjusted net income for the fourth quarter of 2021 grew to $12.5 million or $0.21 per diluted share, as compared to $10 million or $0.17 per diluted share for the third quarter of 2021. In the fourth quarter of 2020, our adjusted net income was a loss of $5.6 million, or $0.10 per diluted share. For the full year 2021, adjusted net income totaled $39.6 million or $0.67 per diluted share, compared to adjusted net income for the full year 2020 of $9 million or $0.16 per diluted share. Daily production for the fourth quarter totaled 7,554 net barrels of oil per day, down slightly from the 7,694 net barrels of oil per day in the third quarter of 202. Fourth quarter 2021 production was up 62% from the fourth quarter of 2020, primarily due to the additional Sasol interest. Sales volumes in Q4 of 2021 were down 4% from the third quarter, but up 144% compared to the same period in 2020. The increase in volumes year-over-year is also primarily due to the additional Sasol interest. Our accrued oil price realization increased 6% to 7,751 per barrel in the fourth quarter of 2021 versus 7,302 per barrel in the third quarter of 2021 and was up 84% compared to the 42.07 per barrel in the fourth quarter of 2020. We entered into several hedging contracts in 2021 with the goal of ensuring cash flow generation to fund our 2021- 2022 drilling campaign on our FSO conversion. We have continued to opportunistically hedge a portion of our expected production in 2022 to lock in strong cash flow generation to assist in funding our capital program and dividend. At the end of January 2022, legacy hedges of approximately 61,000 barrels of oil per month priced at $53.10 per barrel of dated Brent expired. We added hedges in January for 125,000 barrels of oil per month for July, August and September 2022 at the dated Brent price of $76.53 per barrel and 78,000 barrels per month for April, May and June 2022 to dated Brent price of $85.01 per barrel. In Toto, we currently have about 1/3 of a full year 2022 guided production hedged. Our full hedge position can be found in yesterday's earnings release, as well as in our Q4 supplemental information presentation on our website. Turning to expenses, production expense excluding workovers for the fourth quarter of 2021 declines $19 million compared with $21.4 million in the third quarter, due to the cost associated with the annual turnaround recorded in the third quarter of 2021. Production costs increased compared to the same period in 2020, primarily due to the increase in work and interest associated with the Sasol acquisition. We expect to benefit from production cost savings associated with the FSO conversion in late 2022. Workover expense incurred in the fourth quarter of 2021 was $4.5 million while in the third quarter, it was $3.8 million. VAALCO had to plan workovers completed in 2021, one in the fourth quarter, and one in the third quarter, both of which were successfully completed. The per unit production expense excluding workovers of $26.82 per barrel in the fourth quarter of 2021 and declined 7% as compared to the $28.85 per barrel in the third quarter of 2021 due to lower costs partially offset by slightly lower sales volumes. Q4 2021 was up 18% compared to $22.66 in Q4 2020, due to higher oil prices, which drives our domestic marketing obligation and production in volume natural decline, since we did not drill new wells, and a majority of our costs are fixed. Production expense for the first quarter of 2022, excluding workovers, is projected to be between $17.5 million and $19 million, or $28 to $31 per barrel of oil sales. While absolute costs are lower compared to the prior quarter, our cost per barrel are up due to the lower projected sales volumes in the quarter that George discussed. For the full year 2022, we're expecting total production costs excluding workovers of $73 million to $83 million, compared with $73 million in the full year of 2021. Absolute costs will rise primarily due to the higher production volumes and some inflationary cost pressure we're seeing on fuel, chemicals and service costs. Our estimated production cost per barrel, excluding workovers of oil sales for the full year 2022 declined significantly to $19.50 to $22.50 compared with $26.77 per barrel in 021 primarily due to the higher projected sales volumes and the initial cost saving benefit of the FSO conversion late in 2022. We are currently projecting only one workover in 2022 with an estimated cost of between $2 million to $4 million net to VAALCO. The workover is not planned for the first quarter and we will let you know if and when the 2022 workover will occur. DDA for the fourth quarter of 2021 was $4.1 million, or $5.83 per net barrel of oil sales compared with $7 million, or $9.41 per barrel in the third quarter of 2021 and $1.3 million or $4.37 per barrel on the fourth quarter of 2020. DDA was lower compared to the prior quarter due to increased reserve bookings at year end 2021. Fourth quarter 2021 was higher than the same period in 2020 due to higher depletable costs associated with the Sasol acquisition. G&A expense, excluding stock-based compensation in the fourth quarter of 2021 totaled $2.2 million, which is lower than both the third quarter of 2021 and the fourth quarter of 2020, primarily as a result of lower wages and salaries and lower legal costs. On a per unit basis, cash G&A declined to $3 a week per barrel in the fourth quarter of 2021 versus $3.93 per barrel in the third quarter 2021 and $8.73 per barrel in the fourth quarter 2020 reflecting lower costs and the benefit of higher sales volumes that did not result in increased G&A costs. Cash G&A is expected to be between $2.5 million to $3.5 million for the first quarter of 2022 and $9.5 million to $12.5 million for the full year 2022. Non cash stock-based compensation expense for the fourth quarter of 2021 was $0.4 million included non-SARS stock-based expense of $0.3 million and SARS related expense of $0.1 million. For the third quarter of 2021, stock-based compensation expense was not material. For the fourth quarter of 2020, stock-based compensation expense was $2.2 million almost comprised of non-SARS related expense of $0.3 million and SARS related expense of $1.9 million. Turning now to taxes, there was a tax benefit for the three months ended December 31, 2021 of $10.9 million. This was comprised of a $16.1 million of deferred tax benefit and a current tax expense of $5.2 million. Income tax expense benefit for the three months ended September 30, 2021, was a benefit of $17.2 million. This was comprised of a $22.7 million have deferred tax benefit and a current tax expense of $5.5 million. In both the fourth and third quarters of 2021, we determined the partial reversal of the valuation allowance on our deferred tax assets was warranted due to improving oil prices, as well as other factors that indicate that VAALCO will utilize a portion of its deferred tax assets. Income tax benefit for the three months ended December 30th, 2020 was a benefit of $0.8 million and included $2.8 million of deferred tax benefit and a current tax expense of $2 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 credit and then for United States tax purposes. I would like to refer you to our supplemental information deck that we posted to our website this morning. On slide 11, we have updated our netback slide that shows the strong cash flow we're generating at current prices. We've incorporated the midpoint of our 2022 guidance using a $75 realized oil price. We've seen exceptional early results in our drilling campaign and remain on track to deliver a lower cost FSO solution on time, which will result in substantial savings on an absolute and per barrel basis, despite these inflationary pressures. On the same side, we've shown an indicative Q4 of 2022 netback, assuming continued success in the drilling campaign, and full conversion of the FSO solution. As you can see, we're meaningfully improving our margins with successful execution of the strategic initiatives. At yearend 2021, we had an unrestricted cash balance of $48.7 million, which did not include the proceeds from the December 2021 lifting of $22.5 million, which were received in early January 2022. Working capital at December the 31, 2021 was $4 million, compared with $0.8 million at September 30, 2021 and $11.4 million for the year end of 2020. Adjusted working capital at December 31, 2021 totaled $13.7 million compared to $13.5 million at September 30, 2021 and $24.3 million at December 31, 2020. For the fourth quarter of 2021, net capital expenditures totaled $8.1 million on a cash basis and $25.5 million on an accrual basis. These expenditures related to drilling the Etame 8H-ST well, additional long lead items for the 2021-2022 drilling program at the FSO conversion related cost. For the full year 2021, VAALCO invested $16.6 million on a cash basis and $36.5 million on an accrual basis, excluding the Sasol acquisition. As George mentioned, for the full year 2022, we estimate our net capital expenditure to be approximately $90 million to $110 million and $36 million to $ 44 million for the first quarter of 2022. As has been the case since the second quarter of 2018, we are cutting new debt. In the fourth quarter of 2021, the Board of Directors approved a cash dividend policy of $0.0325 per common share per quarter, our full year 2022 annualized a $0.13 cents per share. The first dividend is payable on March 18, 2022 to stockholders of record at the close of business on February the 18th 2022 with our next payment expected in the second quarter of 2022. And with that, I will now turn the call back over to George.

Thanks Ron. The future remains very bright for VAALCO and this is a very dynamic time in our 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 returns to shareholders. We have a strong asset base at Etame that is generating meaningful free cash flow and adjusted EBITDAX even more so in the current pricing environment which enhances our financial flexibility and allows us to return cash to shareholders through a quarterly dividends. We forecast our 2021-2022 drilling program under FSO conversion at Etame will be fully funded by cash on hand and internally generated cash flow. We have already seen the first results of a drilling campaign with the Etame 8H-ST well exceeding your our expectations. And the FSO conversion is on schedule, both of which will enhance our ability to generate additional cash flows in 2022 and beyond. We have completed a drilling feasibility study for the standalone development of the Venus Discovery of Block P in Equatorial Guinea. And we're moving forward now with the field development concept. We're negotiating the PSC term with the Gabon’s government on the new blocks in Gabon that we were awarded in Q4 2021. As part of the consortium with BW Energy and Panoro Energy. The blocks are adjacent to our existing Etame field and we believe they hold tremendous potential to help us establish sustainable long-term production in Gabon. Etame, Block P and potentially now 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 and 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 will be paying our first quarterly dividend later this month. 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 and operating with the highest regards towards ESG, where we execute on our strategic objectives in 2022 focused on sustainable and accretive growth. Thank you. And with that, operator, we're ready to take questions.

[Operator Instructions] Our first question comes from John White from ROTH Capital.

Good morning, gentlemen. Or good afternoon, whatever the case may be, I don't know if you're in Houston or London. Your production expense guidance for 2022 is quite a bit lower than I had been projecting. And as you detailed on the call, I guess a good portion of that is due to your new FSO.

John, that's perfectly correct. I mean, in Q4 of 2022, we get the benefit of the FSO coming in. And we've guided to the reduction when we were taking about 50% of our costs. So with regards to the FSO versus the FPSO. And I think the range is 17% to 20% in overall production expense. So yes, it's great news.

Yes, very encouraging. On Gabon, the new blocks, G and H, have you started shooting seismic there?

No, we haven't, John. And right now we're still in along with our partners within commercial discussions with the DGH on the term surrounding the PSC. Obviously, the way this works as you're aware, we make a bid. And we bid to own this signature bonus when we bid the commercial terms the government then review that bid and conditionally award, as we announced last quarter. And that conditional award is subject to successful negotiations through both the signature bonus and the terms and we've been working through that in Q1. So seismic, just to remind everyone that commitments on well that we bid is basically one exploration well per block, one on G and one on H and on some of the part of the block there, we have some seismic coverage from previous times in this area. But we hope to conclude these negotiations in the coming weeks.

Yes, good luck on those. On the Equatorial Guinea, what a little more color on what stage you're in there. Is that still geologic evaluation?

No, we're well beyond geological evaluation. We are well beyond well design. And we're well beyond the proof of development. We have a position where draft documentation and [Indiscernible] to the MMH with EG which I guess anticipate and hopefully within Q1 but certainly early Q2.

Of 2022?

Absolutely.

The next question comes from Charlie Sharp from Canaccord.

Thank you very much and good afternoon, gentlemen, and thanks for taking my question. Two, if I may. Firstly, in the past, you've provided indications of contingent resources. I just wonder, can you outline for me again, what the contingent resource potential is and how you would see converting that to reserves? And in due course, to cash flow? That's one question. And then second is a bit more general, really, given where the oil price has moved to what sort of pricing to sellers of the sort of assets that you might be interested in? What are they looking for? Have they shifted the goalposts with the current oil price change?

I don't like the second question. But the first question, let me address the first question. So yes, of course, no, we're looking for movement of contingent resource into reserves. And clearly, as you see what we're trying to do in Equatorial Guinea, I get to the slide that we put on Equatorial Guinea, to gross position of 23 million to 24 million barrels of contingent resource now, that particular position to reserves we need to get the POD approval from the MMH. And whilst we won't be able to secure all of those as reserves, we'll certainly be able to secure a large proportion of that 2C position into 1P crude. But not for SEC purposes. When we look at and that's a key message I think for Equatorial Guinea, because this can be achieved without the drill bit because a wells are already been drilled. Now, when we look at Etame and then the key area there is twofold. One is looking at where opportunities for contingent resources exist in our existing drilling program. And the majority of a drilling program at the moment is converting 2P into 1P. We have some opportunities to do some pilot positions and perhaps something a little slightly different within the subsequent two to three wells that we still have to drill that may give rise to proving off some of that contingent resource. But the majority of the contingent resource that resides around the time it will fall into our Phase3 drilling program in 2023. On the second question, of course, we continue to look for accretive opportunities that makes and fit to our strategic vision of how we can be more meaningful within West Africa, our focused area of operation, anyone who is disposing of assets in West Africa, and in the press has been quite speculative about the assets that are available and who's looking at them and who's going to be successful in getting them, we have to be realistic, and the price point that we're willing to look at assets, and the price point of which the existing owners are looking to exit. And I think in reality, holders of assets who are looking to divest, take a reasonably pragmatic view, they're not looking at the top of the curve, because the top of the curve for selling an asset is never achievable. Similarly, as a buyer or a potential buyer, no one buys at the top of the curve. So there's always a meeting point where we run our economics and we run a reasonableness check as to where we would find value. And we, again, we kind of guide a little bit to where our thinking is. And when we look at the indicative numbers, we put in a slide deck around bout the $75.50 to $75 level you can see where we run our numbers and where we sell check the positions.

The next question comes from Stephane Foucaud from Auctus.

Yes, good afternoon, guys. Thanks as well for taking my question. I've got a few, the first now in quite detail, the first one is around OpEx. So once the FSO is completely on, if we look at 2023, could you give a split on what fixed income of millions of dollars per year? And what drivable income of dollar per barrel? That's my first question. So millions of dollars fixed and [Indiscernible] drivable on top of CapEx. Then, if we look at as well as in 2023, assess during programming starting, so how should we think about production in 2023 directionally and in CapEx? And lastly, it seems that EG things are accelerating, when will you expect CapEx spending to start? Thank you.

Stephane, it’s Ron, I'll take the first part of the question there in relation to looking at 2023. I think a good slide to go through in our supplemental deck is slide 13, which looks at the netbacks. And specifically why we put that one on there, in relation to Q4 is, is Q4 is the first quarter where we got the FSO fully up and running in 2022. And we've done that it is $75 per barrel oil and you can see the netback at $75 per barrel oil we got $47 coming through and basically free cash flow before CapEx, and you'll see that the production expense is running at just under $16 per barrel. And as you know, generally our fixed costs basis, sorry, our cost basis is about 90% fixed. So you can get some guidance from that fourth quarter to extrapolate out into 2023. What I would say, [Indiscernible] pointed out that slide and in relation to 2022, it's $75 oil, we will double our EBITDA, adjusted EBITDA that we had in 2021.

That's clear, thank you.

Hi, Stephane, it’s George. So around 2023 drilling program, part of the drilling program in 2023, is interdependent on the results of 2021-2022. And so and we look at the potential program in 2023, one of the objectives we've been looking, since we revise the strategy is to try and get to a multiple year drilling program to maintain a plateau of production rather than having a cyclical position, especially when we've got higher oil prices with the mantra we need to get the oil lay to the ground as early as possible. So when we look at how we should guide CapEx, I mean, we will be looking at perhaps a two to three well program potentially, and in starting Q3, 2023. The first question someone will ask me is well, why Q3, well, there's a number of issues, we need to know the results from the 2021-2022 program, we need to continue with the evaluation of the reprocessed and updated seismic analysis. So we make sure we're hitting the highs that we see. And thirdly, we then have well design and long lead items that we have to then place which will take anything from 9 to 12 months for delivery. So that program is there. So if we guide for Q3 2023, you can allow a CapEx of perhaps two wells in that program before we move into 2024. With regard to EG capex, at the moment, we do have some contingent CapEx for EG subject to the POD being approved by the MMH in Equatorial Guinea, it's very, very small. It's a gross number of about $7 million this year that we've got contingent, the real spend will start in 2023. We will start to procure long lead items for a planned 2024 well, and in 2023, even the long lead items which are going to be gross between $10 million and $15 million

Great. Thank you. And so therefore, back on Gabon, is that be fair to take therefore, rationally flattish production from what you say? With declined being offset by the three well campaign of 2023.

That's exactly the strategy. We will be looking to continue, have a continuous program that creates that plateau and arrest decline. I mean, the assets we have through both the -- through Gamba and Dentale, we think there's opportunities to get ourselves to a plateau and hold it there. Particularly maximize the utilization of the olage that we have in field.

Thank you, and as a follow on EG, so there won't be any development until that first well in 2024 is being drilled, that's what you're saying.

Yes, that's the plan right now. Of course, there are always opportunities to accelerate that. But right now the plan is and the submission for the plan that we're discussing with the partners is the plan to 2024 development well an additional pilot well that will come off of that.

The next question comes from Kenneth Pounds from Castleberry Advisory.

Hello, good morning. Kind of like little more clarification. And you said there could be results on the second well in the coming weeks. Is there a timeline for when that could potentially go on production? And then what's the timeline for the third well on the program?

Yes, the second well, no, we're currently drilling ahead on the second well, so we expect probably to get to TT in the next three weeks. And then once the evaluation completion so within the next four to five weeks, we should have that well on production and immediately after that wells up and running, the rig will remain on the Avouma platform and moved towards the third well. And because there's no rig move involved, it will simultaneously just move over to the next slot and begin drilling.

Okay, so what would be the timeline potentially if that well went well to two or three months or four months after the second one comes on production?

The second well, it would be at least two months after the second well.

Okay. And you talked about the FPSO coming on, will that basically fulfill all your needs for the new production that will be coming on in the summer and the fall?

Yes, I mean, the FSO is really the key position here inside the field is processing olage, the FSOs going to purely be storage, but it does provide us is the opportunity to enhance the storage capacity, which allows us to do larger liftings. And therefore, higher economic returns with the larger liftings. So the olage around the plot and in the field is between 26,000 to 28,000 barrels per day. But like I say the FSOs is greatly reducing operating costs and enhancing our ability to have greater storage. So avoiding a position of what we call tank tops in the field where we have to shut down because the capacity of storage has been reached. So that will avoid that risk.

We had bottlenecks before for sure. So this basically could eliminate any bottlenecks for the next several years.

Definitely, this will definitely eliminate those bottlenecks, we will be able to cushion any environmental impact that sometimes occurs with trying to load a tanker without having to impact production.

Our next question comes from Richard Dearnley from Longport Partners.

Good morning. Is my calculation that you're going to exit, the exit rate for this quarter is around 8,300 barrels a day?

I mean, it couldn't go back to the guidance and reboot for Q1 on the sheet, just pulling off that guidance. Basically, our production guidance from a net revenue interest is basically 8,000 to 8,300. So if you look at the midpoint of that, it's 8,150.

Okay, thank you.

The exit will be slightly higher. Exit will be slightly higher but that's the average for the period.

There are no more questions in the queue. 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 very much. I think it's, we've spent a lot of time and listening to Ron and I talk about 2021 and the prospects for 2022. You can see that activity inside the company has increased tremendously both from our drilling activity, our production activity, our infield activities to make our opportunities more efficient and therefore take advantage of higher oil prices and greater netbacks. The future in 2022 and beyond as we outlined what we are planning in Etame for a potential Phase 3 drilling program and the opportunities inside Equatorial Guinea as we expand the opportunities in West Africa make it a very, very exciting time. So I would like to thank everyone for participating in the call. I think the 2022 with the position of commodity prices, and we have the double whammy opportunity of higher commodity prices, slightly lower our cost base makes a very exciting time for us. Thank you very much.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.