Good morning and welcome to the VAALCO Energy Third Quarter 2022 Conference Call. All participants will be in listen-only mode. [Operator Instructions] After today’s presentation, there will be an opportunity to ask questions. [Operator Instructions] During the question-and-answer session, we ask you to limit your questions to one and a follow-up.

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 third quarter 2022 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. Please keep in mind that George and Ron will only be speaking to VAALCO Energy's third quarter results and not TransGlobe’s, as the business combination did not close until Q4.

During our question-and-answer session, we ask you to limit your questions to one and a follow-up. You can always reenter the queue with additional questions.

I'd like to point out that we posted a third 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 file with the SEC, including our Form 10-K and forms 10-Q. Please note that this conference call is being recorded. And let me now turn the call over to George..

Gabon, Egypt, Equatorial Guinea and Canada. This larger diversified production base should allow us to generate meaningful cash flow, to fund increased stockholder dividends, share buybacks and potential supplemental stockholder returns, at a rate that would not have been achievable by either VAALCO or TransGlobe on a stand-alone basis.

As part of the value proposition around the combination of these two great companies, was a significant increase to shareholder returns.

On August 8, we announced that VAALCO Board approved a share buyback program of up to $30 million, to be commenced promptly subject to completion of the proposed combination of VAALCO and TransGlobe taking place and confirmation by the new enlarged Board.

The proposed share buyback was in addition, to the previously announced post-closing targeted dividend, of $0.25 per share annually. The dividend is to be paid quarterly, with the first payment planned to be made in the first quarter of post completion.

On November 1, a couple of weeks post the closing of the combination, we announced the newly expanded Board had formally ratified and approved the share buyback program, for an aggregate purchase of currently outstanding common stock up to $30 million.

Following this earnings call, and after lifting our quarterly blackout period, we will now be able to commence the program to repurchase our equity.

We believe the market has not yet incorporated the value that will be created from the combination of our two companies into a single entity, and right now is a particularly opportune time to initiate the buyback program, given our recent stock price.

The second component to returning shareholder value, was to double the dividend, the quarter following the completion of the transaction. On October 31, we reiterated our plan to increase our dividend to $0.25 per share annually, commencing in Q1, 2023.

When you combine the increased dividend with our buyback program, we will be returning about $0.50 per diluted share back to our shareholders in 2023. Our stock has been trading between $5 and $5.50. So this represents, a 9% to 10% dividend and buyback yield, which is quite healthy when compared to other energy companies.

Bottom line is we are delivering exactly, what we said we would, and we are looking at maximizing shareholder value. This is done through returning some of that value, but also prudently investing in the future and our very promising asset bases across four countries to continue to grow cash flow.

We continue to evaluate additional accretive acquisition opportunities to invest our cash, into that and that will continue to build volume. We're delivering on our strategic objectives and delivering strong financial results, which have firmly placed VAALCO in a financially enviable position.

We successfully completed the highly complex FSO installation, field grade configuration and full field turnaround in October. As we have noted, we expect to realize substantial and sustainable operating cost savings from this project that will begin in the fourth quarter and tire on through the remainder of the decade.

The new FSO provides us with additional flexibility and has an effective capacity, for storage that is approximately 50% larger than the previous FPSO. The lower overall cost, will also lead to an extension of the economic field life, resulting in a corresponding increase in recovery and reserves at Etame.

From a cost standpoint like all other E&P companies, we have seen some higher costs driven by inflationary pressures that are impacting the project. There's a lot of pressure on fuel prices, services, equipment prices, availability of equipment and consumables and global logistic costs and delays.

We have also had to employ additional engineering as well as incurring increased supply chain and inspection costs. I would like to put this into perspective for you.

We had about five times the number of personnel in the field during the project with additional boats, equipment and operational responsibilities, all working to ensure that we coordinate and complete the substantial project with minimal downtime to our production.

To reduce project risk exposure, we elected to use a larger offshore installation vessel that we mobilize from Europe. This vessel brought the flexible pipe reels with it instead of shipping the reel from Europe.

This increased project cost but eliminated the use of a dedicated heavy lift transportation vessel or double handling the pipe in our West African port. We calculated that this decision reduced the number of interface points by as much as 30%, helping to mitigate the overall project risk.

A project of this magnitude with regards to Etame occurs once every 20 years and I'm proud of how our team managed a minimalized the risk associated with such a large project and complex project. These factors have increased our estimated capital costs associated with the FSO conversion and field reconfiguration by about $10 million net to VAALCO.

We expect the related capital spend in 2022 to be between $30 million and $40 million net to VAALCO, which is in addition to our 2021 2022 drilling campaign costs. This capital investment is projected to save approximately $13 million to $16 million annually in net of VAALCO and operating costs through 2030.

Another area that holds significant future value for VAALCO is Equatorial Guinea. On September 26, we announced the approval of our Venus discovery development plan at Block P by the government of Equatorial Guinea.

Upon execution of final documents amongst all parties, which we are negotiating and approval by the government, we anticipate having a majority working interest in the project as operator.

The Block P PSC provides for a development and production period of 25 years from the date of approval of the POD, subject to the completion of final PSC amendment documentation, which we are diligently working towards. We are excited and look forward to adding significantly to our reserves once final documents are agreed and approved.

There is also additional future upside with Europa development and exploration upside with Saturno and Southwest Grande prospects. As part of the development of the Venus discovery we're planning to spud the first development well in early 2024.

Over the next three years we will work to acquire, convert and install production facilities to support the discovery. We also expect to spud an additional development and water injection well in before potentially bringing the field online in 2026.

We are committed to profitably exploiting the resource potential in AG and are excited to be adding a four-producing asset into the portfolio. Turning our attention to the drilling campaign at Etame. We have a tremendous success at Etame drilling and developing the vast resource over the past 20 years.

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 rates above our initial internal estimates.

The third well, South Tchibala 1HB-ST encountered two potential dental producing zones, the D1 and the D9 but the production rates from the D1 zone were below the minimum recommended operating ranges for the ESP.

We may return to the well in the future to complete the D9 dental interval that had 15 meters of net hydrocarbon shows and an estimated original oil in place range of between 4 million and 15 million barrels. We recently finished the drilling and completion of the North Tchibala 2H-ST well also targeting a dental formation.

This well was ready to flow in late October, but has remained shut in due to other operational factors, including the recent workover activity and continued optimizing of the attorney field following the FSO and field reconfiguration. The well is currently cleaning up and we're recovering frac fluid water and oil.

We had a large frac in this well and thus far only about 20% of the frac fluid has been recovered. We will continue to flow the well and we'll update the market accordingly. Following the 2H-ST well we performed our first of two workovers. The workover on the North Tchibala 1H well was needed due to a safety valve in the well that required replacement.

With the rig already on site, it was easier and more economic to utilize a way to complete the workover following the completion of the 2H-ST well. The final well operation plan for the rig is another workover. The ETSEM-4H, which is expected to restore production of between 1,000 and 1,500 gross barrels of oil per day upon completion.

This well went offline in early September as a result of an upper ESP failure and we were unable to restart the upper or the lower ESP to restore production. Again, utilizing the rig for the workovers instead of new wells that were previously planned is reducing the overall total cost of the 2021/2022 drilling campaign at Etame.

We will defer the additional wells with originally targeted for the future drilling campaign at Etame. With the anticipated success of the 2H-ST well and the workover on the ETSEM-4H well we expect for December exit rate this year at Etame to be between 10,000 and 10,500 net barrels of oil per day.

This coupled with the addition of the TransGlobe production should allow us to enter 2023 around 19,500 to 20,000 net barrels of oil equivalent per day setting us up for a strong opening to 2023. In summary, there is a lot to be excited about as we enter 2023.

We have completed the highly complex FSO and full field reconfiguration of Etame, while completing another growing campaign. We have an approved development plan for the venous discovery at Equatorial Guinea. We are incorporating the TransGlobe team and assets building size and scale.

I would like to thank our hardworking team who continue to operate and execute on our strategic vision. We are firmly focused on our strategic vision of accretive growth, while 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 echoing George's comments about our ability to successfully execute on several complex operational and corporate projects simultaneously.

I am pleased with our performance thus far in 2022 and we are better positioned today to execute on our strategy of accretive growth, while adding and returning value to our shareholders than we were at the start of the year. Turning to our quarterly financials.

We generated adjusted EBITDAX of $42.4 million in the third quarter of 2022, compared with a record $60.8 million in the prior quarter, but nearly double the $23.3 million in the same period of 2021.

The decrease in adjusted EBITDAX compared to the second quarter of 2022 was primarily due to lower sales volumes with three listings in Q3 compared to four listings in Q2. Year-to-date in 2022 we have clearly benefited from higher realized oil pricing and strong net sales volumes.

This has allowed us to fund our strategic initiatives with cash flow and cash on hand including our 2021/2022 drilling campaign CapEx our FSO conversion our field reconfiguration costs and our quarterly dividends.

We also reported net income of $6.9 million, or $0.11 per diluted share in the third quarter of 2022, which included a $24 million deferred tax expense and a $6.4 million in transaction costs associated with the TransGlobe combination, and $8.9 million of onetime FPSO demobilization and decommissioning costs, which were partially offset by $12.9 million non-cash unrealized derivative gain.

After normalizing for the deferred tax charge, transaction costs, FPSO charges and the unrealized derivative gain, our adjusted net income for the third quarter of 2022 totaled $33.3 million or $0.56 per diluted share as compared to an adjusted net income of $30.7 million or $0.52 per diluted share for the second quarter of 2022.

In the third quarter of 2021, VAALCO reported $10 million in adjusted net income or $0.17 per diluted share. Production for the quarter of 9,157 net barrels of oil per day was nearly flat compared to 9,211 net barrels of oil per day in the second quarter of 2022. Production was up 19% from the same period in 2021 due to our drilling program.

Sales volumes in Q3 2022 were 731,000 barrels, which was 24% lower than the quarterly record high of 958,000 barrels in Q2 2022 and essentially flat on the same period in 2021. In the third quarter, we had three liftings compared to four liftings in the second quarter of 2022.

We also saw a 9% decrease in realized crude oil pricing in the quarter compared to Q2 2022.

Despite the decline, we are pleased with our continued strong crude oil price realization, which was $103.61 per barrel in the third quarter of 2022 versus $113.38 per barrel in the second quarter of 2022 and was up 42% compared to $73.02 per barrel in the third quarter of 2021.

At the end of 2021 and at the beginning of 2022, we hedge a portion of our expected production in 2022 to lock in cash flow generation to assist in funding our capital program and our dividend.

The average price net of realized commodity derivatives was $91.13 per barrel for the third quarter of 2022 compared to $91.39 per barrel for the second quarter of 2022. Our hedging program has provided us with a surety to fund the largest capital program that VAALCO has undertaken in over a decade.

On July 25, 2022 VAALCO entered into a costless commodity collar arrangement for a quantity of 326,000 barrels of oil sales with a weighted average crude price of $70 per barrel and a weighted average coal price of $122 bucks per barrel. On October 26, VAALCO entered into additional derivative contracts for the first quarter of 2023.

These derivative contracts are called for approximately 303,000 barrels of oil sales with a weighted average put price of $65 per barrel and a weighted average coal price of $120 per barrel. Our full derivative position can be found in yesterday's earnings release as well as in our Q3 supplemental information presentation on our website.

Our hedging strategy is to risk mitigate and protect our commitments to drilling and shareholder return. This together with the closing of the RBL facility in 2022 affords significant risk mitigation and the event of any unforeseen events. Turning to expenses.

Production expense excluding workovers and stock-based compensation for the third quarter 2022 was $23.2 million. This was lower than the second quarter due to less sales volumes, but higher than the same quarter in 2021.

This was primarily driven by the annual maintenance costs, the additional operational activities associated with the FSO and field reconfiguration and higher costs associated with both personnel, chemicals and costs.

We expect to see these supply chain issues higher marine costs, chemicals fuel and personnel costs as well as continued inflationary pressures likely to continue into 2023. There is increased competition for services right now. And over the past two years we saw a decrease in the number of overall service providers across the supply chain.

From a macro level both the higher demand and the lower supplier services is driving costs higher across the industry. We believe inflationary pressures will continue while we benefit from sustained higher commodity pricing. We had no workovers in the first three quarters of 2022, but we planned two workovers in the fourth quarter 2022.

We recently utilized the rig to perform a workover on the North Tchibala 1H well due to a safety valve in the well that required replacement.

With a rig already in the field, it was easier and more economic to utilize the rig to complete the workover following the completion of the North Tchibala 2H-ST well rather than to use our mobile workover unit.

The final well operation plan for the rig is another workover the Southeast Etame 4H well which is expected to restore production between 1,000 and 1,500 gross barrels of oil per day upon completion.

The well went off-line in early September as a result of an upper ESP failure and VAALCO was unable to restart the upper ESP or the lower ESP to restore production. Utilizing the rig for the workovers instead of new wells that were previously planned has reduced the total CapEx cost of the 2021, 2022 drilling campaign in Etame.

In the quarter and highlighted in our 8-K filing, we had a onetime charge related to the FPSO demobilization cost of $8.9 million. This allowed us to continue producing into the Nautipa beyond the term of the original contract and allowed us to produce more barrels than we'd previously guided for Q3.

These one-time costs were incurred to retire the FPSO as we transition the block to the FSO. There were no similar expenses incurred in the third quarter of 2021.

Depreciation, depletion, and amortization expense for the three months ended September 30th, 2022 increased to $9 million which was higher than the second quarter of 2022 of $8.2 million and higher than the $7 million in the third quarter of 2021.

The increase in depreciation, depletion, and amortization expense compared to both periods is due to higher depletable costs associated with the 2021, 2022 drilling campaign.

General and administrative expense for the third quarter of 2022 excluding stock-based compensation expense decreased to $2 million compared with $2.7 million in the second quarter of 2022 and $2.9 million in the third quarter of 2021.

The decrease compared to prior periods was primarily driven by higher corporate overhead allocation for the three months ended September 30th, 2022 and reflects the increased project work invoiced to the PSC from corporate in Q3 2022.

The per unit G&A rate excluding stock-based compensation in the third quarter of 2022 was $2.74 per barrel of oil sales, which was significantly lower than the second quarter of 2022 and the third quarter of 2021. G&A noncash stock-based compensation expense for the third quarter of 2022 was less than $100,000.

And for the second quarter 2022, it was $0.8 million and less than $100,000 and for the third quarter of 2021. Turning now to taxes. Foreign income taxes are attributable to Gabon and are settled by the government taking their oil in kind.

As a reminder, our PSC tax rate in Gabon is about 52.5% and can be reduced via cost recovery by both production and capital costs.

The overall corporate effective tax rate is influenced by nondeductible items like derivatives, corporate costs that cannot be recovered into the PSC, and to a lesser extent some costs associated with operations like our Equatorial Guinea losses. Income tax expense for the three months ended September 30th, 2022 was $22.8 million.

This comprised of a $24 million of deferred tax expense and a current tax benefit of $1.2 million. This was higher than the income tax expense for the third quarter of 2021 where we benefited with the reversal of a valuation allowance leading to a tax benefit of approximately $22.7 million.

Our valuation allowances are now substantially at least and our net operating losses from previous periods are being utilized. From a cash tax standpoint, the only tax paid is our profit oil barrels. As a reminder, the Gabonese government takes their taxes in kind through an annual listing. We expect that listing to occur in November.

We accrued quarterly during the year for the estimated value of the barrels they will lift using quarter-end oil pricing. We then adjust for the actual cost, based on the pricing at the time the listing occurs.

The foreign tax rate in Gabon via the PSC is more than the US tax rate and we are now in a position where we are crediting foreign taxes rather than deducting them. I would like to refer you to our supplemental information deck that we posted to our website this morning. You will find scenarios around the calculation of our cost and profit all.

In 2022, we have benefited from our brought forward cost pool. High commodity pricing and strong production has seen full utilization of that carry forward cost pool in 2022.

The FSO and the drilling campaign will allow us to continue to take advantage of our favorable PSC terms to allocate as much as 80% of cost oil through much of the remainder of 2022. With the inclusion of TransGlobe in Q4, we should see an overall reduction in the effective tax rate.

If commodity pricing remains high for 2023, we'll see an increase in overall profit barrels for the state and we do expect to have more than one lifting in Etame in the calendar year to the GOC. We have generated $136.8 million in adjusted EBITDAX year-to-date in 2022, which is more than double what we generated in the same period in 2021.

With the recent stock price around $5, we continue to trade at a low multiple of EBITDAX, despite paying a dividend and despite being debt free. Additionally, with the TransGlobe combination and sustained commodity pricing, we should see a step-up in adjusted EBITDAX in 2023.

Our increased market cap implies that we should be trading at a much higher multiple that similar sized companies enjoy. We believe that we are truly undervalued and that is another reason that we're excited about our share buyback program.

We believe right now is an excellent opportunity to buy our common shares at a discount to their intrinsic value and a very attractive investment of our strong cash balance. At September 30, 2022, we had an unrestricted cash balance of $69.3 million.

This does not include the proceeds from our September listing of $16.8 million, which we received in October. Working capital at September 30, 2022 was negative $19.7 million, compared with negative $8 million at June 30, 2022.

The increase in working capital is related to the increase in tax payable aligned with the planned government lift in November 2022 and increased accounts payable, which was partially offset by the increase in accounts receivable. Since the transaction closed on October 13, both TransGlobe and VAALCO paid transaction fees subsequent to quarter end.

In addition, TransGlobe paid the $3 million outstanding debt balance with Alberta Treasury Bank or ATB. For the third quarter of 2022, net capital expenditures, excluding acquisitions, totaled $43.6 million on a cash basis and $51.7 million on an accrual basis.

These expenditures were primarily related to costs associated with the 2021-2022 drilling program, the FSO conversion on the Etame field reconfiguration. As has been the case since the third quarter of 2018, we are carrying no debt and have facilities available to utilize for additional accretive acquisition opportunities to continue to build value.

Last week, the Board of Directors approved a cash dividend of $0.35 per common share that was payable on December 22, 2022 to stockholders of record at the close of business on November 22, 2022. This equates to a full year 2022 annualized dividend of $0.13 per share.

We also plan to nearly double our dividend to $0.25 per share annually, beginning in 2023, in line with our announced increase associated with the TransGlobe combination. As stated previously, growing the dividend will be from the quarter following the acquisition. This will be considered by the Board in Q1 2023 following the year-end results.

With the completion of the TransGlobe acquisition on October 30, 2022, we have incorporated all assets and costs into our combined Q4 guidance, and is available within our supplemental deck. A key differentiation between TransGlobe reporting and VAALCO is that we report all production as net realizable interest barrels.

The difference between production working interest and net realizable interest represents the government take and royalties paid or taken in barrels in Egypt and in Canada.

For the total company, we are forecasting Q4 production to be between 18,000 and 20,600 on a working interest barrel of oil equivalent per day and between 3,900 and 16,300 net realizable interest barrel of oil equivalent per day.

As a reminder for the fourth quarter, we are only including half of October, and all of November and December for the TransGlobe assets. Looking at production by asset, we are expecting Gabon to be between 6,400 and 7,600 NRI barrels of oil equivalent per day.

Egypt to be between 5,300 and 6,000 NRI barrels of oil equivalent per day and Canada to be between 2,200 and 2,700 NRI barrels oil equivalent per day. Gabon was impacted in the fourth quarter by the FSO and full field reconfiguration being shifted from September into October and by additional downtime.

With fuel being brought back online, we are around 9,200 on a net realizable interest barrels of oil per day at Gabon today. When you add in the restoration of production from the workover and the new well cleaning up, we expect Gabon to exit 2022 at around 10,000 to 10,500 NRI barrels of oil equivalent per day.

When you add in our expectation of Egypt and Canada to be between 9,500 and 10,000 NRI barrels of oil equivalent per day you get to combined exit rate of between 19,500 and 20,000 NRI barrels of oil equivalent per day.

Our sales guidance is in line with production, but slightly higher at between 18,600 to 21,100 when are working to dice barrels of oil equivalent per day or between 14,500 and 16,700 NRI barrels of oil equivalent per day.

There is a slide in the supplemental deck that provides additional details on the impact on Q4 as production ramps up post the change from the FPSO and the full field maintenance shutdown.

Turning to costs for the fourth quarter, we expect production expense, excluding workover and stock compensation to be between $33.5 million and $39 million on an absolute basis or between $23.50 and $27.50 on an NRI per barrel of oil equivalent basis. We also expect workovers to be between $5 million and $7 million.

Our cash G&A for the combined company is expected to be between $3.5 million and $5 million. We're currently in our 2023 budget process, and we're beginning to identify additional synergistic cost-saving opportunities that we will incorporate into our 2023 guidance.

Finally, looking at CapEx for the fourth quarter, we are forecasting between $34 million and $50 million of CapEx spend. This includes the drilling program in Canada and Egypt as well as the completion of the drilling campaign at Etame. With that, I will now turn the call back over to George..

Gabon, Egypt, Equatorial Guinea and Canada. Our 2P CPR reserves with TransGlobe are estimated to be over 50 million barrels and that should improve after we do a reserve update at year-end. We are forecasting Q4 net production to be more than 3.5 times where we were in Q1 2021.

We are implementing a $30 million share buyback triple the size of the last one VAALCO announced in 2019 and announced plans to nearly double our annualized dividend in 2023 to $0.25 per share from the current $0.13 per share.

We have done all this while doubling the share price staying debt-free and increasing the cash balance -- cash on the balance sheet to $70 million at the end of third quarter of 2022. We've done an excellent growing VAALCO prudently returning cash to shareholders and enhancing the value of the company.

We are delivering on what we committed to the market and to our shareholders and we are better positioned today than we were 18 months ago. We're generating significant cash and up-growing production organically through the drill wells. We have improved the average market liquidity almost sevenfold from early 2021.

We have also have the cash on hand and unused borrowing base to quickly execute on accretive acquisitions. We are very excited for the future of VAALCO and we will continue to be measured and methodical, as we grow the company in the future.

Our combined teams are working closely to high-grade our capital program and budget as well as finalize our guidance for 2023. We plan to update the market on this information in the first quarter of next year. We are confident that we will continue to deliver superior long-term value to our shareholders. Thank you.

And with that, operator, we are ready to take questions..

Thank you. We will now begin the question-and-answer session [Operator Instructions] And our first question will come from John White with ROTH Capital. Please go ahead..

Good morning all. Congratulations on all of your accomplishments this year there in many and very positive work in my opinion. On the Venus Development Block P George I appreciated all your detail on the time line there. I was going to ask that you provided it anyway. And Ron spoke of 2023 guidance.

And just to confirm I believe with your final comments, you mentioned that will be released in the first quarter 2023.

Is that correct?.

Yeah, the full year guidance I think you're referring to John. We will do full year guidance and we'll get that out to you guys in the first quarter of 2023..

Okay. I don't have any further questions, so I'll pass it back to the operator..

Thank you John..

Our next question will come from Stephane Foucaud with Auctus Advisors. Please go ahead..

Hi team. Thanks for taking my question. So, I've got two. So I'll start by the first one. That's a bit building up on the previous question about 2023 production. So I appreciate you don't give any guidance, but how should we look at it? So you gave the end of the year, the exit production, or the Q4 production for the asset.

As we look at 2023, is that a reasonable number? Should we start from there and putting some decline? Do you more or less expect that you will be able to grow on that? What's the general thinking without being specific appreciate there is no precise guidance given yet?.

Thank you Stephane. No we can't be specific, but I can give you in general terms. So as I previously mentioned, we're coming to the end of the drilling campaign in Gabon and we're utilizing the rig for these last two workovers. And as I mentioned one was a safety workover, which was had to be completed.

And the other one was the restoring of between up to 1500 barrels that went down due to an electrical failure. We called it an ESP failure. So it wasn't a failure of the pump. It was an electrical failure on the cabling.

And just to make it further clear, the reason we utilize the rig is because we couldn't utilize our cut unit, because we didn't have either space on the platform to deploy the cut unit, or the available personnel to operate it. So the rig was the definite choice to restore that production in the near-term.

So we come to the end of the Etame drilling, but we're just rigging up right now to commence drilling in Egypt this week. So the drilling program starts with two exploration wells in Egypt and we also commenced a drilling program at the beginning of January in Canada.

So I can't be specific, but we will be continuing to add production from the drill pit from our other assets..

So basically Gabon declining a bit and maybe some production increase in Egypt and Canada.

Is that…?.

That's exactly, yes..

Okay. Wonderful. Thanks. That's my first question. My second question is part for Ron is about -- and it's about modeling and looking forward to things and starting given you provided some production number and CapEx number for Q4. So we're starting to be some financial.

And, of course, the big question is the starting point with regard to the cash coming from TransGlobe. So looking at I think in June, TransGlobe had something like $60 million in cash. You had about $80 million if you include all the working capital.

Is that -- they generated each quarter I think that if you look at the first half of the year, they have generated a lot.

So as a starting point on closing is $80 million, a good number to start with for working capital? Is it higher? Is it below what's your sense?.

Well, I think first of all Stephane, I would point you to the fact that TransGlobe released their Q3 results. There was a 6-K filing. You can refer to that. That is a cash balance as at the 30th of September. Yes, we didn't take over that business until October the 13th. So in that time period there will be transactional costs in relation to the deal.

So if you take into consideration their cash balance at the end of September and there's going to be transactional costs that will come out of there. Again I'll guide you to the proxy, the information memorandum in Canada, both of which will identify costs that will occur on the combination.

And I think that will be the guide I would give you for your opening position..

Thank you..

Our next question will come from Charlie Sharp with Canaccord. Please go ahead..

Thank you very much gentlemen and thank you for very comprehensive update. Just one question, I think it's slide 5 in your presentation you gave an indication of the rebuild if you like in production from Etame through the FSO through October and into November.

We're now halfway through that that would suggest that you're back up to that 15,000, 16,000, 17,000 level.

Is that correct, or has there been any further sort of small delays that might impinge on Q4 numbers?.

No. I mean, if we look at -- the reason we included that particular tar was to clearly identify that the Q4 issues that relate to the lower production levels for Etame are behind us.

So we are up at the levels you've indicated without me giving you exact numbers and the float that you see in that chart is basically in relation to the ST sort of the SEENT well cleanup. And I'll just put a little bit of color into that well right now just for all listeners.

The well was available to turn over to production on the 23rd of October within the time line that we had previously indicated to market. We were unable to flow the well and turn it to production for two reasons.

One, we had to move the rig on SEENT and making the rig move to do the safety workover our oil production has to remain shortened for safety purposes.

And secondly, it was delayed due to the field reconfiguration as we start up the Etame field first confirm the integrity of the lines and the integrity of the vessel receiving crude as we started a phased -- as we did a phased start-up and SEENT came on after Etame and those processing capabilities were confirmed.

So we then look at in detail with the well, please keep in mind this is the deepest well that VAALCO have ever drilled at 16,000 feet. And we fracked into two zones. So we have considerable completion fluid in there and quite a distance of fluid to extract. But so we've allowed quite a long cleanup period.

We do have good Bohol pressure being indicated that under 3000 psi. So our confidence levels remain very high and that's why we've got that indicative in that production chart, but it will take some time to clean up. .

Okay. Thank you. And one short follow-up if I may. The excellent theme that you've assembled and they've shown how excellent they are to carry out the conversion on a Etame.

Are you going to be able to retain all of the key elements of that team and transfer them to Equatorial Guinea, or do you see that team perhaps having other duties to perform?.

Well, obviously, we have given a plan of development which is really CapEx intensive, when it looks at what we're planning to do in Block P.

Obviously, with the -- when we've got a team of such experience and having completed such a monumental task within that time frame, we are certainly looking to redeploy that team almost immediately into optimizing the Block P development.

And when I say optimizing, it's a combination of optimizing the efficiency of construction and design and also the efficiency of the economics. So can we deploy that particular engineering skill set to become -- make Block P even more efficient and reduce that initial CapEx spend. That's certainly the target Charlie..

Okay. That’s great. Thank you..

Our next question will come from Bill Dezellem with Tieton Capital. Please go ahead..

Thank you. First of all the kind of been in Gabon and seeing the assets and what you accomplished over there is truly remarkable. So congratulations. And with that, really solid execution, I guess that leads to the question of what you think you can do say over the course of the next 12 months, if I realize it's a super short period of time.

But in Egypt with the TransGlobe assets and just taking your execution and applying that over there?.

Oh. That's the top one, Bill. We have -- and I'm sure as most of the listeners are aware, we have a specific methodology of operating and we go to the lowest common denominator both to understand the operations and to make them efficient and as efficient as they can be.

Now I'm not saying that that hasn't already been done in TransGlobe, but we need to accomplish that both in the field and with our partners in Egypt, so that we can maximize both the production and maximize the efficiency and making that the position in Egypt as prolific as it can possibly be.

And certainly, we will be setting some challenging targets that we will be looking at, with regards to production and cost efficiency. We'll be setting targets with regard to our export barrels and how we plan to maximize the value of those and how we have a better understanding of the pricing of that particular crude with the discount to Brent.

So, we are very hands on, when it comes to executive management on the assets. And so, that's where we'll be in Egypt. And in fact it'll be in Egypt the week after next.

And we will do exactly the same with the operation in Canada, how quickly can we accelerate the planned production increases and bring that as far forward into 2023, as possible, obviously, doing it safely and efficiently.

So, as Gabon goes into a study phase in 2023 for the subsurface which effectively it is with the exploration assets and the development in Etame, we will have more than enough time to focus our operational positions into Canada and Egypt..

Thank you. And then second question is relative to the new FSO given the significantly larger capacity.

How do you anticipate the cadence of offloads will take place relative to the cadence that you've had with the FPSO?.

Yes. We're kind of hopeful as -- for those who are not aware with the lower parcel sizes from the Nitipa, we always were in a coal load position. So in looking at the opportunities for vessels in West Africa nine times out of 10, we would be co-loading with a vessel that's either preloaded or going about to take a second load into Nigeria.

So what this does allow us is to have a specific 100% loading coming from the tele going into a single tanker. Now that allows -- we can't quantify us yet, but it's certainly the large or the loading the reduced cost for vessels and towns et cetera that we have for that.

And the larger loading the better opportunity to market that as a single parcel going on to one of the refineries. So, we are planning to see benefit from that cost savings and price enhancements, but we haven't factored those in at this time..

Okay. Thank you and congratulations again on the fabulous execution in Gabon..

Thanks Bill..

Our next question will come from Jamie Wilen with Wilen Management. Please go ahead..

Hi fellows. You always seem to get a bit of a premium to Brent.

Could you kind of quantify, what pricing we were able to achieve and how we're able to do that?.

Okay. What we've recently done Jamie is we switched away from a term contract with Exxon. This is for Gabon. Let me clarify. So we've switched away from a term contract with Exxon to a market-based marketing contract with Glencore. So, in the term-based contract we were dated Brent minus.

So it was a fixed position on Brent minus whatever the position was in the contract and it went from $0.50 to $1. So we would Brent minus $1 in most of our liftings. Moving to marketing contract. We paid $0.25 per barrel on the marketing fee.

And the trader effectively goes and sources the best price possible in the marketplace for each parcel that we scheduled to deliver. On the last parcel, we were trading at a $5 premium to Brent on that particular parcel. And what we try to do is maximize the volume. Now we've got a couple of smaller lifts coming up in Q4.

One of them I think is marketed a slight discount to Brent. So it's all about being able to capture the market at the right time. with the right volume. But we are into a marketing contract now. So it gives us a much larger control of spectrum of the crude.

For the other jurisdictions in Egypt, there's a mixture of a marketing contract with Mercuria for offtakes and they historically do one or two offtakes a year, plus an option to price and sell to EGPC for domestic use, which is linked to a dollar based -- it's a dollar sale linked to about an $8 discount to Brent for that crude quality.

Again, something we're just getting into to see how we can improve that crude quality through processing in the field. In Canada, it's a little bit different. They've got a mixture of oil, NGLs and gas. So theirs is a combination price that basically everything is sold at the wellhead..

On the North Tchibala well that has been paused, can you give us a little bit more clarity on the timing of how long it will take to clean up the well and kind of looking at the tea leaves for, say, what the workover wells will be, versus what this will come online? It looks like we're looking at 1,000 to 1,500 NRI is what you're forecasting there?.

Yes, that we're keeping it at 1,500. And we've got no reason, given from the subsurface side or the geological side for us to, at this point, change that estimate. Like I said, we've got to keep in mind that it's a 16,000-foot well, 4,950 meters in depth. It's quite -- it's going to take quite some time to clean up.

And if you look at that chart we've allowed about 10 days -- 10 to 12 days to clean and to get stabilized flow. And that's where we expect. And as soon as we have that and it's cleaned up, we'll straight back market with the stabilized rates..

As you look at the results of the drilling program of what we've accomplished in the Gabon and the Dentale does that affect how you look down the road at what we're going to do? The Gabon seems to have been so productive; the Dentale has been a little bit more elusive.

How do you look at the drilling program for 2023 and beyond in those two areas?.

Yes. That's a great question. And the reason I think it's a great question, Jamie, is because, it allows me to provide the opportunity of exactly what we're trying to do right now. What we're trying to do right now is, about -- it was over 18 months ago that we identified this program. In fact, it was the end of 2020, the beginning of 2021.

And we identified this program with four pre-designated wells and we did that ahead of our full seismic interpretation. And as you're aware through this program, we've had to substitute wells as our seismic interpretation and knowledge grew.

And then, in substituting these wells, we tend to -- in any drilling campaign you do your firmer wells first in your riskier wells at the end on a percentage chance of success basis. And -- well -- and that's exactly how this program has panned out.

For 2023, we have a year where we're going to do a really deep dive into that seismic interpretation a really deep dive into the step-out and productive drilling opportunities within both the Gabon and the Dentale and then have that portfolio risked, so we can again identify clear targets within four to six high-grade drilling targets that we'll come to announce towards Q3 of 2023.

With that, we'll also be looking at what is the longevity of Etame, how far we've got an opportunity to take this to 2038. How do we do that from a subsurface perspective how do we do that from a full utilization of the facilities perspective. And what I'm planning to try and do is, get that analysis in a Capital Markets Day towards middle of Q2.

And that's what we're trying to achieve. Now, don't hold me to that Q2 date, it will be ready when we've completed the interpretation.

But we will come out to market and give them a full overview of not just initially the Etame asset, because that's the one we're focused on right now and then, an opportunity to expand that with both our Canadian and Egyptian assets later in the year..

We have time for one last question. Our last question will come from Stephane Foucaud with Auctus Advisors. Please, go ahead..

If I can, gents, two boring question for Ron. The first one on the balance sheet on the non-current liabilities, I think, I saw for the first time a non-current tax of about $41 million.

And I was wondering what that corresponding to -- was corresponding to? And the other one related, are there any residual CapEx from the FPSO in 2023? Because I think only part of the overall, budget was paying to 2022. So I guess, that should -- the balance according to Q1 2023, if you could confirm that would be great. Thank you..

Okay. So on the first part, you've got both the deferred tax asset and a deferred tax liability. You can net these off for accounting purposes, Stefan. So the liability is really the deferred tax liability in foreign taxes for, Gabon. So essentially, that is our projections out there that will – obviously, we're utilizing the cost pool the 80%.

So we're getting the deductions upfront, but we have the liability for the profit oil barrels, as we look into the future. At the same point in time, because our tax rate in Gabon is higher than our US tax rate, you've effectively got the asset appearing in the US side deferred tax assets.

So one virtually offsets the other at this point in time, but that's why you develop it to. I mean previously, we would have had deferred tax assets in Gabon, but we had valuation allowances against them when COVID hit and when prices were low.

Those valuation allowances were basically, reversed as we go in through 2021 and the final reversal happened in the beginning of 2022. So there is quite a bit of noise, as those deferred taxes roll themselves out over the year. But we finished -- we're looking at the year-to-date position now with an effective tax rate of around 65%.

So it's kind of coming back in line with what we expected, in that 60% to 65% level. Second point, I'll go to is, on the FSO, no I think we'll largely see all of those costs rolling through in Q4. So there shouldn't be any carry forward into Q1, not in material anyway. .

Great. Thank you..

Thank you..

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. Well I think this has been an excellent call. As you can tell from the length of the call, and the detail of the questions that we've been performing considerable activities through this year.

And we put an awful lot of information out to the market and that is reflective like I say, with the quality of the questioning that we've received. I think we look forward to Q4, and starting to harvest some of the benefits both of the combination and of the drilling campaign and the infield upgrades and FSO installation that are now completed.

I would like to say to my staff, it's time you take a well-earned pause, but I think after Thanksgiving, I'll be asking them to get back on the hobby horse and let's keep driving again. So, on that, thank you very much for the call. And obviously, we as an executive team, are available to take calls from investors on a one-to-one as and when required.

Thank you very much. .

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