Vaalco Energy Inc /De/ Q3 FY2022 Earnings Call

Good morning and welcome to the VAALCO Energy Third Quarter 2022 Conference Call. All participants will be in listen-only mode. After today’s presentation, there will be an opportunity to ask questions. 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.

Thank you, Al. Good morning, everyone, and welcome to our third quarter 2022 earnings conference call. We continued our solid financial and operational results in the third quarter. We benefited from sustained high Brent pricing over $103 per barrel and solid sales of 731,000 barrels. This combination allowed us to continue to generate significant cash flow, execute on our accretive growth strategy and fully fund our capital commitments. We remain committed to paying out dividends to our shareholders. And with a debt-free balance sheet, we are clearly in a very strong financial position. We delivered adjusted EBITDAX of $42.4 million and have now generated $136.8 million of adjusted EBITDAX in the first nine months of 2022. To put this in perspective, we generated $85.8 million in all of 2021 and $26.6 million in 2020. We have used this to pay three quarterly dividends thus far in 2022 and the Board approved a fourth dividend payable in the fourth quarter of this year. Our strong balance sheet remains debt-free and our unrestricted cash balance grew to $69.3 million, which does not include $16.8 million in proceeds from our September lifting that were received in October. As you can see, we have grown our cash position even while we execute on our capital drilling program as well as the field reconfiguration and conversion to an FSO at Etame. In addition to our operational and financial results, we had several other major projects occurring these past few months. Operationally, in Gabon, we are very pleased to have successfully delivered a highly complex full-field reconfiguration maintenance turnaround and upgraded FSO installation in October. This project was completed despite a difficult global supply chain environment and is a testament to the dedication of our workforce and partners who help complete this project, underlying VAALCO's status as a quality operator. As we have said before, we expect to realize substantial and sustainable operating cost savings from this project, which will begin in the fourth quarter and carry on throughout the remainder of the decade. Our successes were not just in Gabon. In September, we received approval of the plan of development for the Venus discovery at Block P, Equatorial Guinea. We are diligently negotiating final documents, amongst all our parties for approval by the Ministry of Mines and hydrocarbons. We anticipate a strong efficient and highly economic development of this exciting discovery and look forward to proceeding with our plans, to begin producing in Equatorial Guinea over the next few years, and adding significantly to our reserves once final documents are agreed and approved. On October 13, we completed the transformational combination with TransGlobe, which has built a business of scale, with a stronger balance sheet and a more diversified baseline of production that will underpin VAALCO's future opportunities for success. VAALCO now has a diversified portfolio of assets across four countries: 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 mobilized 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 and minimized the risk associated with such a large 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 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 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 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 economical 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 Venus 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 one-time 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 hedged 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 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 in 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 offline 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 one-time 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 from 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 oil. 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 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 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.

Thank you, Ron. As mentioned earlier today, 2022 has been a highly successful and transformative year for VAALCO. I have served as CEO of VAALCO for the past 18 months. In the first quarter of 2021, we were producing about 5,000 barrels per day, with a 2P CPR reserve estimate of 10.4 million barrels from a single producing asset. We had no debt, approximately $20 million in cash, and our stock was trading around $2.50 per share. My primary goals were to grow production and value through organic drilling, acquisitions, and unlocking the inherent value in our asset base. We are committed to being long-term stewards of VAALCO and are building a sustainable business that maximizes value. While operating in a risk-based environment with variability but significant upside, we believe we have effectively managed these risks while achieving record results. We continued drilling at Etame and entered into a consortium to explore a prospective area offshore Gabon, south of Etame, which holds significant potential for the future. We successfully completed one of the most comprehensive operational projects in nearly 20 years at Etame, involving the FSO conversion and full field reconfiguration. It's remarkable that a project of this scope was successfully managed and executed by a company our size. We developed and received government approval for a POD concerning the Venus discovery of Block P and are finalizing documents with the Ministry of Mines and Hydrocarbons. Acquired in 2012, that concession had no major activity for nearly nine years until our team created a unique, economically viable development plan. We launched the first-ever dividend program for VAALCO in the first quarter of 2022 and have built a business capable of sustaining a quarterly dividend. We completed an all-equity merger of two undervalued companies, VAALCO and TransGlobe, which enhances our size, scale, cash flow, geographical diversity and reduces portfolio risk. We anticipate that our increased size and scale will yield significant cost synergies in the future and should result in a higher trading multiple given the larger market capitalization. We now boast a substantial resource base of organic opportunities across four countries: Gabon, Egypt, Equatorial Guinea, and Canada. Our 2P CPR reserves with TransGlobe are projected to exceed 50 million barrels and should improve following a reserve update at year-end. We forecast our Q4 net production to be over 3.5 times what it was in Q1 2021. Additionally, we are executing a $30 million share buyback, tripling the size of our last buyback in 2019, and have announced plans to nearly double our annual dividend in 2023 to $0.25 per share from the current $0.13. We have achieved all of this while doubling our share price, remaining debt-free, and increasing our cash balance to $70 million at the end of the third quarter of 2022. Our team has done an excellent job growing VAALCO prudently, returning cash to our shareholders, and enhancing the company's value. We are fulfilling our commitments to the market and our shareholders and find ourselves in a stronger position today than we were 18 months ago. We are generating significant cash and increasing production organically through drilling efforts. We have improved our average market liquidity almost sevenfold since early 2021. We also have ample cash reserves and an unused borrowing base to swiftly act on accretive acquisitions. We are enthusiastic about the future of VAALCO and remain committed to a measured and methodical growth strategy. Our combined teams are closely collaborating to optimize our capital program and budget while finalizing our guidance for 2023. We plan to share updates with the market in the first quarter of next year. We are confident that we will continue to provide superior long-term value to our shareholders. Thank you. We are now ready to take questions.

Thank you. We will now begin the question-and-answer session. 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 timeline 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 had to be completed. And the other one was the restoring of between up to 1,500 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 utilized 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.

Thank you. That's my first question. My second question is for Ron regarding modeling and projections, particularly since you provided production and capital expenditure numbers for Q4. We're starting to look at the financials, and a key point is the cash situation with TransGlobe. In June, TransGlobe had approximately $60 million in cash, and if we include all working capital, you had about $80 million. They generated significant cash each quarter, especially in the first half of the year. Therefore, as a baseline, is $80 million a reasonable starting point for working capital? Is it higher or lower? What is your perspective?

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 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. The reason we included that particular detail was to clearly indicate that the issues affecting the lower production levels for Etame in Q4 are resolved. We are reaching the levels you mentioned without providing exact numbers. The float in the chart corresponds to the SEENT well cleanup. Just for everyone listening, the well was ready for production turnover on October 23rd, following our previous timeline. However, we couldn't begin production for two reasons. First, we needed to move the rig for safety work, which meant our oil production was temporarily limited for safety reasons. Second, there was a delay due to the field reconfiguration as we initiated operations in the Etame field—we first confirmed the integrity of the lines and the vessel receiving crude, then proceeded with a phased startup, with SEENT starting after Etame once processing capabilities were verified. Regarding the well, please remember this is the deepest well VAALCO has ever drilled at 16,000 feet. We have fracked into two zones, resulting in a significant amount of completion fluid that needs to be extracted. Thus, we've allowed for a lengthy cleanup period. We are seeing positive pressure indications below 3000 psi, which keeps our confidence high, as shown in the 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?

We have outlined a development plan that is quite capital intensive, particularly regarding our plans for Block P. With a highly experienced team that has successfully completed a significant project within a tight timeframe, we are eager to assign that team to optimize the Block P development right away. Optimizing means improving both construction and design efficiency as well as enhancing the economic aspects. Our goal is to leverage this engineering expertise to make Block P more efficient and minimize the initial capital expenditures. That's definitely our target.

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?

We have a specific method of operation that focuses on streamlining our processes to enhance efficiency. While some of this has been addressed in TransGlobe, it's crucial for us to achieve this with our partners in Egypt to optimize both production and efficiency, making the operation in Egypt as productive as possible. We will set ambitious targets related to production and cost efficiency, as well as targets for our export barrels, maximizing their value and better understanding the pricing of that crude in relation to Brent. Our executive management will take an active role in these assets. I'll be traveling to Egypt in two weeks to focus on this. We will also approach our operation in Canada with the same intensity, aiming to accelerate planned production increases safely and efficiently in 2023. As Gabon enters a study phase for its exploration and development, we will have ample opportunity to concentrate on our operations in 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 hopeful because, for those who are not aware, with the smaller parcel sizes from the Nitipa, we have always been in a coal loading position. When looking at opportunities for vessels in West Africa, more often than not, we would be co-loading with a vessel that's either preloaded or about to take a second load into Nigeria. This allows us to achieve a specific 100% loading coming from the tele into a single tanker. While we can't quantify it yet, this certainly means lower loading costs for vessels and towns. The larger loading presents a better opportunity to market that as a single parcel to one of the refineries. We are planning to see benefits from these cost savings and price enhancements, but we haven't factored them 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?

Recently, we transitioned from a term contract with Exxon for Gabon to a market-based marketing contract with Glencore. Under the previous term contract, we were dealing with a fixed position of Brent minus a certain amount, which ranged from $0.50 to $1, resulting in most liftings being Brent minus $1. With the new marketing contract, we now pay a $0.25 per barrel marketing fee, and the trader is responsible for sourcing the best price in the market for each scheduled delivery. In our last delivery, we achieved a $5 premium to Brent. Our focus is on maximizing volume, and while we have a couple of smaller liftings coming in Q4, one is expected to be at a slight discount to Brent. We are now operating under a marketing contract that gives us greater control over the crude spectrum. In Egypt, we have a mix of marketing contracts with Mercuria for offtakes, which typically happen one or two times a year, along with an option to price and sell to EGPC for domestic use, linked to a dollar sale with about an $8 discount to Brent for that crude quality. We are also exploring ways to enhance crude quality through processing in the field. In Canada, the situation is a bit different, as they sell a mix of oil, NGLs, and gas, and the pricing is determined based on sales 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, we are maintaining the estimate at 1,500 and have no current reason to adjust that based on our subsurface or geological analysis. It's important to remember that this is a 16,000-foot well, approximately 4,950 meters deep, which means it will take some time to clean up. According to our projections, we anticipate needing about 10 to 12 days for cleaning and achieving stabilized flow. Once we reach that point, we will be ready to market with the stabilized rates.

As you look at the results of the drilling program of what we've accomplished in 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 an excellent question, Jamie. It gives me the chance to explain what we're currently focused on. Over 18 months ago, at the end of 2020 and the beginning of 2021, we identified this program involving four pre-designated wells prior to completing our full seismic interpretation. As our understanding grew with the seismic interpretation, we needed to substitute some wells. In any drilling campaign, you usually drill the more certain wells first, leaving the riskier ones for later based on the likelihood of success. This approach has shaped how our program has unfolded. In 2023, we plan to conduct an in-depth analysis of the seismic interpretations and explore both step-out and productive drilling opportunities in Gabon and Dentale. From this analysis, we aim to identify four to six high-grade drilling targets, which we plan to announce around Q3 of 2023. Additionally, we will assess the longevity of the Etame project, exploring possibilities to extend operations until 2038, focusing on subsurface and facility utilization. My goal is to present the findings at a Capital Markets Day sometime in mid-Q2. However, please note that the Q2 timeline is tentative, and the presentation will be finalized once the interpretation is complete. Overall, we intend to provide a comprehensive overview of the Etame asset first and then consider potential expansions with our Canadian and Egyptian assets later this year.

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

If I may, I have two straightforward questions for Ron. First, regarding the balance sheet and the non-current liabilities, I noticed a non-current tax of about $41 million for the first time. I was curious about what this corresponds to. The second question is related to whether there are any remaining capital expenditures from the FPSO in 2023, since it seems that only part of the overall budget was allocated to 2022. I would appreciate your confirmation on this according to Q1 2023. Thank you.

On the first point, we have both a deferred tax asset and a deferred tax liability that can be netted for accounting purposes. The liability mainly represents the deferred tax liability for foreign taxes in Gabon. Essentially, we're utilizing the cost pool of 80%, allowing us to take deductions upfront while still having a liability for future profit oil barrels. Since our tax rate in Gabon is higher than in the US, this creates a deferred tax asset on the US side that offsets the liability. Previously, we had deferred tax assets in Gabon with valuation allowances during the COVID period and low prices, but those allowances were reversed throughout 2021, and the final reversal occurred early in 2022. As a result, there's been some fluctuation as these deferred taxes are processed over the year. Currently, we are looking at a year-to-date effective tax rate of approximately 65%, which aligns with our expectations in the 60% to 65% range. Regarding the FSO, we expect all associated costs to be accounted for in Q4, with no significant carryover into Q1.

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.