VAALCO Energy Inc (EGY) 2021 Q4 法說會逐字稿

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 some closing comments before we take your questions.

(Operator Instructions) I'd like to point out that we posted a Q4 2021 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 Securities Exchange Commission, 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 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 jack-up rig for the 2021, 2022 drilling campaign, which began in December. Our first well was a development well, the Etame 8H sidetrack, 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 and are currently drilling the Avouma 3H sidetrack development well.

In August, we finalized an agreement with World Carrier for a new FSO solution that cost 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 of Etame while increasing our margins and profitability. We successfully performed 2 workovers in September and October, which resulted in an increase to production of approximately 1,050 barrels of oil per day growth or 540 barrels of oil per day net to VAALCO.

In October, we were provisionally awarded 2 offshore blocks as part of a consortium with BW Energy and Panoro Energy adjacent to established development fields at Etame and Dussafu. We also are moving forward with a stand-alone field development concept of the Venus discovery at Block P in Equatorial Guinea.

In November, we announced that 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 our year-end reserves, with proved SEC reserves increasing by 250% to 11.2 million barrels of oil and of 2P CPR 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 has 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, which 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 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 derisking 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 sidetrack development well. In February, we reported that we completed and placed the 8H sidetrack well online with an initial flow rate of approximately 5,000 gross barrels of oil per day or 2,560 barrels of oil per day net to VAALCO. After these strong results, we took the well 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, which currently exceeds our initial estimates.

We are currently drilling the next well in the program. We have Avouma 3H sidetrack 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 sidetrack development well to drill the third development well in the program. As a reminder, we initially said that 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 4-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 our production costs are fixed and as production increases, our per barrel cost will decrease. Every new barrel we 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, the 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 are also managing our FSO solution project simultaneously at Etame, which will reduce costs and improve margins. In August, we announced that we had signed and received partner approval for a 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 that all of the associated engineering, long lead equipment and significant contracts for the FSO are proceeding in line with the projected time lines, 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 Cap Diamant, a double-hull crude tanker built in 2001 that is being reengineered as the 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 cost with the 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, giving the project a very attractive payback period of only about 2 years.

Turning to reserves. We are very pleased with the substantial growth of our reserve base. The proved reserve increase resulted from a combination of positive factors, including improved well performance, Etame field life extension resulting from our change over to a more cost-effective FSO this year, PUD additions, positive oil pricing revisions and acquisitions.

SEC proved reserves at year-end increased 250% to 11.2 million barrels with 7.2 million barrels in proved developed reserves and 4 million barrels in proved undeveloped reserves. 3 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 which added 3 million barrels and 5 million barrels due to positive well performance revisions and FSO related field life extension.

As in prior years, we continue to see positive reserve revisions due to well performance, which demonstrates the strength of our 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 6.5x of 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 includes proven and probable reserves using VAALCO's management's assumptions for future Brent escalated crude oil pricing and costs 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 of 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 at 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 2 blocks in the 12th Offshore Licensing Round in Gabon with 2 exploration periods totaling 8 years, which may be extended by a further 2 years. The 2 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 2 blocks are on 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 Gabonese 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 time line for potential development. Last summer, we completed a feasibility study for the stand-alone development of the Venus discovery in Block P, and we are moving forward now with a field development concept. As we work through the development concept, we will provide more details about potential timing, capital costs and reserves and production estimates. 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 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 now review our production and sales volume guidance before I turn the call over to Ron. In the first quarter, we had Etame 8H sidetrack well come online 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 the 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 sidetrack development well, we had to shut in production from the platform to allow the rig to move into position and begin growing. This occurs whenever a jack-up rig is mobilized to drill a well and happened when we began the Etame 8H sidetrack well on the Etame platform. As a result of certain in Avouma oil flow from the pipeline that transmits oil from the Avouma and sand platforms to the FPSO operated at a lower volume than usual.

This in combination with the chemical imbalance in the fluids in the pipeline caused a paraffin buildup resulting in a temporary blockage in the pipeline. We had to shut production at the Avouma and sand fields for more than a week. We were able to restore production after running some chemicals to remove the paraffin build up. 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 and a second lifting schedule 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 6,900 NRI barrels of 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 range 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 in 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 accretive 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 2021 reflected stronger revenue due to the increased sales in the quarter, higher realized pricing and a non-cash deferred tax benefit compared with the fourth quarter of 2020.

The fourth quarter of 2021 included a $16.1 million non-cash deferred tax benefit, partially offset by a $1.8 million loss on derivative instruments. For the full year 2021, we reported net income of $81.8 million or $1.37 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 EBITDAX totaled $22.6 million in the fourth quarter of 2021, a slight decrease compared with a $23.3 million in the third quarter. However, fourth quarter 2021 EBITDAX was more than 6x the $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 triple the $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 in realized losses between the periods. The 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 7,694 net barrels of oil per day in the third quarter of 2021. Fourth quarter 2021 production was up 62% from the fourth quarter of 2020, primarily due to the additional Sasol interest. Sales volumes in Q4 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 crude oil price realization increased 6% to $77.31 per barrel in the fourth quarter of 2021 versus $73.02 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 a dated Brent price of $76.53 per barrel and 78,000 barrels per month for April, May and June 2022 at a dated Brent price of $85.01 per barrel. In total, we currently have about 1/3 of our 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 declined $19 million compared with $21.4 million in the third quarter due to the costs 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 working 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 2 planned 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 volume natural decline since we did not drill new wells and the 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 all sales for the full year 2022 declined significantly to $19.50 to $22.50 compared with $26.77 per barrel in 2021, 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 in 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 $3.08 per barrel in the fourth quarter of 2021 versus $3.93 per barrel in the third quarter of 2021 and $8.73 per barrel in the fourth quarter of 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 million, $3.5 million for the first quarter of 2022 and $9.5 million to $12.5 million for the full year 2022.

Noncash stock-based compensation expense for the fourth quarter of 2021 was $0.4 million, which included non-SAR 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 and was 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 3 months ended December 31, 2021, with $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 3 months ended September 30, 2021, was a benefit of $17.2 million. This was comprised of a $22.7 million of deferred tax benefit and a current tax expense of $5.5 million.

In both the fourth and third quarters of 2021, we determined a partial release of the valuation allowance on our deferred tax assets which 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 3 months ended December the 30, 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 3 periods, the overall effective tax rate was impacted by nondeductible items associated with operations and deducting foreign taxes rather than crediting them 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 have 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 these inflationary pressures.

On the same slide, we've shown an indicative Q4 2022 netback, assuming continued success in the drilling campaign and full conversion of the FSO solution. As you can see, we are meaningfully improving our margins with successful execution of these strategic initiatives. At year-end 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 31, 2021, was $4 million compared with $0.8 million at September 30, 2021 and $11.4 million at 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 sidetrack well, additional long-lead items for the 2021-2022 drilling program and the FSO conversion-related costs. 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 carrying no debt. In the fourth quarter of 2021, the Board of Directors approved a cash dividend policy of $0.0325 per common share per quarter or full year 2022 annualized of $0.13 per share. The first dividend is payable on March 18, 2022 to stockholders of record at the close of business on February 18, 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 our 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 our shareholders through our quarterly dividends. We forecast our 2021-2022 drilling program and our 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 sidetrack well exceeding 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 our drilling feasibility study for the stand-alone development of the Venus discovery at Block P in Equatorial Guinea, and we are moving forward now with the field development concept.

We're negotiating the PSC term with the Gabonese government on the new block from Gabon that we were awarded in Q4 2021 as part of the consortium with BW Energy and Panoro Energy. The blocks are adjusted 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 our 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, while 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.

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. And we were thinking about 50% of our cost save with regards to the FSO versus the FPSO. And I think the range is 17% to 20% in our overall production expense. So yes, it's great news.

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

No, we haven't, John. Right now we're still in -- along with our partners, we're in 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 not only the signature bonus, but 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 synergy bonus and the terms, and we've been working through that in Q1.

So seismic, just to remind everyone, the commitments on this well that we bid is basically one exploration well per block, one on G and one on H. And we -- on some of the part of the blocks, we already have some seismic coverage from our previous times in the area. So -- 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 -- there is still geologic evaluation?

No, no. We are well beyond geological evaluation. We are well beyond, well designed, and we're well beyond proof of development. We have a position where the draft documentation in discussion with (inaudible) to the MMH within [ENT] which I can anticipate in -- hopefully within Q1, but certainly early Q2.

Of 2022?

Absolutely.

The next question comes from Charlie Sharp from Canaccord.

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, a little 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 goalpost as 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, we're looking for movement of contingent resource into reserves. And clearly, as you see what we're trying to do in Editorial Guinea -- the slide that we put on Equatorial Guinea to a 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 proved, 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 the well has already been drilled.

Now when we look at -- then the key area there is twofold. One is looking at where opportunities for contingent resource exists in our existing drilling program. The majority of our drilling program at the moment is converting 2P into 1P. We have some opportunities to do some pilot positions and perhaps something that's a little slightly different within the subsequent 2 to 3 wells that we still have to drill that may give rise to proving up some of that contingent resource. But the majority of the contingent resource that resides around Etame will fall into our Phase III 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 and more within West Africa, our focused area of operation anyone who is disposing of assets in West Africa and the press has been quite speculative about the assets that are available and who's looking at them and who's really be successful in getting them. We have to be realistic in the price point that we're willing to look at assets and the price point at 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 again, we kind of guide a little bit to where our thinking is. And when we look at the indicative numbers we put in our slide deck, around about the $75, $50 to $75 level. You can see where we run our numbers and we since check the positions.

The next question comes from Stephane Foucaud from Auctus.

I've got a few -- they are all quite detailed. 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's fixed in terms of million of dollars per year? And what's variable in terms of dollar per barrel? That's my first question. So million of dollars fixed and per barrel variable on top of the fixed. Then if we look at as well as 2023, the third drilling program is starting. So how should we think about production in 2023 directionally and CapEx? And lastly, it seems that EG things are accelerating, when would you expect CapEx spending to start?

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, Q4 is the first quarter where we've got the FSO fully up and running in 2022. And we've done that at $75 oil. And you can see the netbacks there at $75 oil we've got $47 coming through and basically free cash flow before CapEx.

You'll see that the production expense is running at just under $16 per barrel. And as you know, generally, our fixed cost base is -- sorry, our cost base is about 90% fixed. So you can get some guidance from that fourth quarter to extrapolate out into 2023. What I would say -- and it's in the (inaudible) point to that slide, and in relation to 2022, it's $75 oil. We will double our EBITDA -- adjusted EBITDA that we had in 2021.

It's George. So around 2023 drilling program, part of the drilling program in 2023 is interdependent on the results of 2021, 2022. So -- and when we look at the potential program in 2023, one of the objectives we've been looking since we revised 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 (inaudible) we need to get the oil right to the ground as early as possible.

So when we look at how you should guide CapEx, we will be looking at perhaps a 2 to 3 well program potentially 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 CapEx of perhaps 2 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 along these items would round to be -- gross between $10 million and $15 million.

Great. And so therefore, back on Gabon, is that be fair to take, therefore, a roughly flattish production from what you say with decline being offset by the 3-well campaign of 2023?

That's exactly the strategy. We'll 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 outage that we have in the field.

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

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 a planned 2024 development well with an additional pilot well that will come off of that.

The next question comes from Kenneth Pounds from Castlebury Advisory.

Give a little more clarification on -- you said there could be results on the second well in the coming weeks. Is there a time line for when that could potentially go on production and then what's the time line for the third well in the program?

Yes. The second well, we're currently drilling ahead on the second well. So we expect probably to get to TP in the next 3 weeks and then on the evaluation and completion. So within the next 4 to 5 weeks, we should have that well on production. Immediately after that well is up and running, the rig will remain on the Avouma platform and move towards the third well. And because there's no rig move involved that will simultaneously just move over to the next spot and begin drilling.

Okay. So what would be the time line potentially, if that well went -- well to 2 or 3 months or 4 months after the second one comes on production?

The second well, it would be at least 2 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 a processing knowledge. The FSO is going to purely be storage. What 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 outage around in the field is between 26,000 to 28,000 barrels per day. But like I said, the FSO is greatly reducing our operating costs and enhancing our ability to have greater storage. So avoiding a position of what we call tank talks in the field where we have to shut down because the capacity of storage has been reached. So that will avoid that.

You 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 and without having to impact production.

(Operator Instructions) Our next question comes from Richard Dearnley from Long Partners.

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

I mean I couldn't go back to the guidance that we put for Q1 on the sheet, just pulling off that guidance now. 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.

Yes. Okay.

I think the exit will be slightly higher, the exit will be slightly higher than that, 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 listening to Ron and I talk about 2021 and the prospect for 2022. You can see that activity inside the company has increased tremendously, both from our drilling activity, our production activity, our in-field 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're planning in Etame for a potential Phase 3 drilling program and the opportunities inside Equatorial Guinea as we expand our 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 in the 2022, with the position of commodity prices and where we have the double whammy opportunity of higher commodity prices while we lower our cost base makes it a very exciting time for us. Thank you very much.

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