EGY - NYSE

Ladies and gentlemen, thank you for standing by. Welcome to the VAALCO Energy First Quarter 2023 Conference Call. [Operator Instructions] This conference is being recorded, and a replay will be made available on the company's website following the call. I would now like to turn the conference over to Chris Delange, Investor Relations Coordinator. Please go ahead.

Thank you, operator. Good morning, everyone, and welcome to VAALCO Energy's first quarter 2023 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. During our question-and-answer session, we ask you to limit your questions to one and a follow-up. You can always re-enter the queue with additional questions. I would like to point out that we posted a first quarter 2023 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 the Form 10-K and Forms 10-Q. Please note that this conference call is being recorded. Let me turn the call over to George.

Thank you, Chris. Good morning, everyone, and welcome to our first quarter 2023 earnings conference call. We have had a lot to review in each of our calls over the last year, but today's prepared comments will be pleasantly shorter. We have made significant progress integrating TransGlobe into VAALCO and are now focused on optimizing production, managing our costs, fine-tuning our operations, and allocating capital to drilling, future growth plans and shareholder returns. This was our first full quarter of reporting as a combined company following the transformational combination with TransGlobe, which has built a business of scale with a stronger balance sheet and a more diversified production base. I would like to point out some key highlights and accomplishments for the first quarter. We were at the high-end of production and saw a quarterly increase of 27% to 18,306 NRI barrels of oil equivalent per day or 23,152 barrels of oil equivalent on a working interest basis. You can truly see how we have grown when you compare first quarter production this year with first quarter production last year, we are up 127%. We generated $47.8 million in adjusted EBITDA, which was only $2 million lower than Q4, despite lower sales due to lifting timing and lower realized pricing. We also generated $42 million in cash from operations, which allowed us to fund $27.7 million in CapEx and still grow our cash balance at quarter-end to 52.1 million with no debt. We also paid our quarterly dividend in Q1, which was increased by 92% and continued to repurchase common stock through our buyback program. We have positive momentum as we enter the second quarter of 2023, both operationally and financially, and we are building size and scale to substantially grow VAALCO. With our diversified portfolio of assets across four countries, including Gabon, Egypt, Equatorial Guinea, and Canada, I will spend a little time detailing operational activity in each area. Let's begin with Egypt, where we have the largest amount of capital spending in the first quarter. We are focused on drilling opportunities in Egypt, which included drilling the first ever Nukhul horizontal well on our acreage. In the past, across our acreage in Egypt, only vertical wells were drilled. The recent Arta horizontal well was a 4,400-foot lateral. The well is flowing at approximately 200 barrels of oil per day with minimal water, and we expect cleanup on this well to continue for an extended period of time. We also use micro-seismic on the Arta well, which will give us additional information for future horizontal wells. We're going to do as much data collection and evaluation as we can before we drill additional horizontal wells in Egypt. We plan to study the results, refine the drilling and completion techniques, and look to potentially drill another lateral well either later in 2023 or in 2024. This initial horizontal well was initially designed and planned before the transaction closed. We believe we will be able to continue to make changes to future wells and completions design and achieve better production results. On an overall basis, we are very pleased with the drilling performance on the vertical wells as we are seeing significantly faster drilling and completions performance overall, moving from a 2022 average of roughly 38 days per well to 8 days to 15 days per well in 2023. We believe that we can now drill future vertical wells in around 10 days to 15 days, which is very positive for the overall economics, compared to the 38 days that we had been seeing. After completing the Arta-77 horizontal well in January 2023, we drilled five vertical development wells in Q1 2023. One well required a frac stimulation and the other four vertical wells added over 700 barrels of oil per day at the end of Q1, and those wells continue to perform very well, with early May production from these wells at nearly 1,100 barrels of oil per day. These additional wells and work cover in conjunction with the work completed for production optimization and increasing production well in excess of our decline rates. We have spent meaningful time and effort in Egypt reviewing the facilities and operations. This additional cost and effort have resulted in two meaningful changes that were enacted recently. The first is that we took steps to relieve pressure bottlenecks and back pressure, which resulted in a 500 barrel per day improvement in oil production. The second was to improve our ability to prevent and capture potential stills by improving well sites with secondary containment measures and increased use of composites spoolable pipe for replacement of old lines and on the installation of new lines. We believe that this will make a significant move towards eliminating uncontained spills. In early April, we had a two-year record daily production level of over 11,800 barrels of oil per day in Egypt. Our drilling and completions program in Egypt is a significant part of our 2023 capital program as we continue to develop one of our core assets. We still plan to drill 15 wells to 20 wells in Egypt this year and expect about six to be drilled in the second quarter. In Canada, as you recall, we drilled several wells, but completions were delayed, and these wells came online in late December 2022 and January 2023. We also drilled two additional wells in the first quarter, and those wells were brought online in May. Our Q1 drilling consisted of three wells with a 1-mile later and a 1.5-mile lateral and a 3-mile lateral. It is our intention to move to longer 3-mile laterals, exclusively improving the overall economics of future drilling programs. We are currently evaluating our future drilling in Canada, working on ways to further optimize both lateral lengths, frac intensity, and shortening cycle times. If we combine this with facility and pad optimization, we believe that we can materially improve the production cycle times and overall economics of our drilling opportunities in Canada, where we have an impressive 2P resource base. Turning to Gabon. As you know, we completed our 2021-2022 drilling campaign in the fourth quarter of 2022. We are currently evaluating locations and planning for our next drilling campaign at Etame and expect to complete this review this summer, and we'll advise the market when we have more details. Also in the fourth quarter, we completed the FSO and field reconfiguration project, which is allowing us to operate more efficiently and economically, while focusing operational excellence, including production uptime and enhancement in 2023 to minimize decline, including the next drilling campaign. Overall, our first quarter saw strong production levels at the high-end of our guidance, driven by strong performance at Etame and overall, our production costs were at the lower end of our guidance. We are seeing the impact of the cost savings from the new FSO, but they have been partially offset by some higher costs from inflationary and industry supply pressures that we discussed during our last call. We have some minor pipeline work underway, which has reduced the fuel gas supply normally used for power generation within the Etame field. This has resulted in us using more diesel for a temporary period, adding about $1 million per month for OpEx for the next few months. Our second quarter production cost guidance reflects this temporary increase, but we saw no need to adjust the full year production guidance. Let me now turn to a discussion on Equatorial Guinea, another area that holds significant future potential for VAALCO. VAALCO has a working interest in Block P offshore Equatorial Guinea where that are previously discovered and undeveloped resources, as well as additional exploration potential. In March 2023, we held productive meetings with the MMH and its partners in Houston. During these meetings, we finalized multiple sustained documents for Block P, which included the venous development relating to the production-sharing contract. Following our meetings in March, we continue to work towards the finalization of documents between the partners, having completed the PSC documentation with the ministry. We are now moving forward with the project, subject to the finalization of JOA documentation with a more detailed review of the drilling and top size development of the Venus project with the objective of reducing the overall project cost in conjunction with our partners. Following a detailed peer review, we are considering options for the drilling of all 3 wells, 2 producers and 1 water injector are drilled as a single campaign which will reduce the overall drilling costs through lower mobilization costs. We're also building detailed options for the production and evacuation facilities throughout Q2 and Q3 of 2023. Planned activity included a detailed seabed survey to identify the prime location for the development facilities. Upon completion of the JOA documentation, we plan to move $4 million into capital expenditures for 2023, but we believe that this amount will not impact our full-year 2023 guidance of between $70 million to $90 million. We are excited about the future at EG, and we anticipate a strong, efficient, and economic development of this discovery with first oil projected for 2026. Additionally, there are clear strategic benefits and further diversifying the revenue generation and country focus of our portfolio. We have a proven track record for a development of this kind, and we look forward to demonstrating these capabilities as we progress the venous discovery into production. In closing, there are a lot of exciting projects and developments in 2023 and moving into 2024 that will continue to help VAALCO grow production, reserves, and value for our shareholders. I would like to thank our hard-working team who continue to operate and execute our plans. We have captured meaningful synergies of the TransGlobe acquisition already and continue to make progress towards capturing more oil wells, continue to build size and scale. We are debt-free and remain 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 continued strong performance. And as we look to 2023 and beyond, we are better positioned today to execute on our strategy, while adding and returning value to our shareholders. In the first quarter of this year, we generated adjusted EBITDAX of $47.8 million. This was slightly less than the 49.8 million in the fourth quarter of 2022, but up 43% from the 33.5 million in the first quarter of 2022. We benefited from a full quarter of production from Egypt and Canada, and had essentially no impact from derivatives compared with a large loss in the first quarter of 2022. Revenue declined from the fourth quarter due to lower sales volumes related to the delayed lifting and lower realized pricing. We reported net income of $3.5 million or $0.03 per diluted share in the first quarter of 2023, compared with $17.8 million or $0.17 per share in the fourth quarter of 2022. This decline in earnings was mainly due to lower sales volumes and realized oil pricing. Higher income taxes, increased interest expense, mainly due to the FSO lease and increased other income expense costs. Other income expense net during the fourth quarter of 2022, we recorded a $10.8 million bargain purchase gain that was partially offset by $7 million of transaction costs. During the first quarter of 2023, we recorded a transition period adjustment related to the acquisition that reduced the original bargain purchase gain by $1.4 million. In regard to the higher effective tax rate during the first quarter of each year, we project out our tax position for the full-year based on certain assumptions and then monitor it for the balance of the year. We are forecasting that our Gabonese tax rate will increase in this year's fourth quarter when our cost pool is forecasted to be fully utilized. This increases the profit oil barrels due to the Gabonese government in Q4 2023. We have a slide in our investment deck that discusses the impact of cost oil and profit oil and accounts on how that affects our tax rate. After normalizing for the transition period adjustment and deferred tax expense, our adjusted net income for Q1 2023 totaled $7.3 million or $0.07 per diluted share. Production for the first quarter of 2023 was 18,306 net barrels of oil equivalent per day, a 27% increase from the 14,390 net barrels of oil equivalent per day in the fourth quarter of 2022 and up 127% from the first quarter of 2022. We clearly benefited from a full quarter of production in Egypt and Canada from the TransGlobe acquisition that closed on October 14, 2022, as well as increases in Gabon from having the field back up and running for the entire quarter following the successful FSO and full field reconfiguration that occurred in Q4 2022. Sales volumes in Q1 2023 were 1.22 million barrels of oil equivalent, which was up 99%, compared with the first quarter of 2022, but down about 11% from the fourth quarter. As we mentioned during our last call, a 630,000 barrel gross listing in Gabon originally planned for March 2023 was delayed until April 3, due to adverse weather conditions, which resulted in lower NRI sales volumes. If these sales were added to the Q1 2023 sales, sales volumes would have been 1.6 million barrels of oil equivalent. We expect second quarter total NRI sales to increase as a result of the lifting timing in Gabon and to be between 15,600 and 17,300 barrels of oil equivalent per day. This is slightly less than the production guidance impacted on a total basis for the quarter, due to lifting timing in Egypt, where the cargo is being moved from Q2 to Q3. Realized commodity pricing in the first quarter was about 7% lower than the fourth quarter, but 40% below the first quarter of 2022. While commodity prices have fallen, I'd also like to point out that a year ago we had just oil from Gabon that trades in-line with or slightly above Brent. With Canadian production, including natural gas and natural gas liquids, and Egyptian oil driven by the Ras Gara blend, where pricing will be a blended price versus the past when it was tied only to Brent oil. In regard to hedging, as shown in our earnings release yesterday and in our investment deck, we didn't add any new contracts since our last call. We will continue to implement a hedging program to help us mitigate risk and also to protect our commitment to shareholder return. We have protected via costless colors, a floor price of $65 for a percentage of our production through late summer of this year with an upside of around $100. As we look at 2023 and beyond, we will continue to implement our strategy and examine our capital spending outlay in the near-term and longer-term. Turning to costs. Production expense, excluding workovers and stock-based compensation for the first quarter of 2023 was $29.3 million, which was at the low-end of our guidance. Production costs decreased compared to the 40.8 million in the fourth quarter of 2022, primarily due to lower costs related to the completion of the FSO conversion and field reconfiguration, a lower expense associated with lower sales volumes. We recorded a credit of $1.1 million in offshore workover expense in the first quarter, a result of over accruals in 2022. Workovers in Q4 2022 totaled $4.7 million. As we have discussed this morning, we had lifting delays due to weather in Gabon, which did increase our Q1 book costs due to having extra marine equipment in field for the lifting longer than planned. We also have higher cost year-on-year in relation to personnel and commodity-related operating costs due to inflation. We are monitoring our operating costs and looking for ways to safely reduce expense, but believe that elevated cost levels driven by inflation will continue into 2023, unless all prices weakened further and slow down activity levels. Over the past two years, we saw a decrease in the number of overall service providers across the supply chain. In addition to these inflationary pressures, we have some gas pipeline work underway at Etame that is temporarily preventing the normal use of produced natural gas and resulting in higher diesel usage, also driving costs higher in the near term. We believe this will continue into Q2 2023, but will be resolved in early Q3 with the completion of the gas pipeline work. This is resulting in additional diesel costs of about $1 million per month. DD&A expense for the three months ended March 31, 2023, decreased 24.4 million from the 26.3 million in the fourth quarter of 2022, primarily due to lower sales volumes. The rate per barrel of oil equivalent was up about 5%, which reflects additional capital costs incurred since year-end 2022. General and administrative expenses for the first quarter of 2023, excluding stock-based compensation expense, totaled $4.6 million, compared with a credit of $300,000 in the fourth quarter of 2022. The fourth quarter benefited from the large increase in operational projects during that period involving a majority of corporate resources, which realized a high percentage of costs charged to those projects. While first quarter 2023 G&A was within our guidance range, it did include higher audit costs associated with the year-end audit. G&A non-cash stock-based compensation expense for the first quarter of 2023 was 600,000, compared with a negative 100,000 in the fourth quarter. Income tax expense for the three months ended March 31, 2023 was 14.8 million and is comprised of a 12.3 million of current tax expense and a deferred tax provision of $2.5 million. As explained previously, from a cash tax standpoint, the only tax paid is on the profit oil barrels in both Gabon and Egypt. No cash tax is payable in Canada, due to the availability of net operating losses. The Gabonese government takes their taxes in kind through an annual listing. They took their most recent listing last December. 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 lifting occurs. I discussed earlier why our estimated effective tax rate has increased. In the first quarter, we funded all of our CapEx, quarterly dividends and share buybacks with cash flow and cash on hand and grew our cash position at the end of the first quarter to $52.1 million. Adjusted working capital at quarter-end declined slightly to 40.2 million from 42.2 million at year-end 2022, while working capital totaled [$30.5 million] [ph] at March 31 compared with $38 million at year-end 2022. Other balance sheet items worth highlighting include other assets where we hold the back dated entitlement receivable with EGPC of approximately $51 million and continue to work closely with EGPC on collection. As has been the case since the third quarter of 2018, recurring no bank debt and have credit facilities available to utilize for additional accretive acquisition opportunities to continue to build value. For the first quarter, net capital expenditures totaled 27.7 million on a cash basis and 25.4 million on an accrual basis. These expenditures were primarily related to our drilling programs in Egypt and Canada. In 2022, VAALCO paid quarterly cash dividends of [$0.0325] [ph] per common share beginning in Q1 2022 for a total of $0.13 per share annually. That equates to about $9.3 million in cash returned to shareholders through dividends in 2022. In addition, for 2023, the Board approved nearly doubling the dividend to $0.065 per share quarterly or $0.25 per share annually. The Q1 2023 dividend was paid on March 31, 2023. And yesterday, we announced the same dividend amount for the second quarter of 2023 to stockholders of record on May 24 and payable on June 23. As stated previously, growing our dividend is a direct result of our expanded asset base and cash flow generation ability as a result of the TransGlobe acquisition. Additionally, in November 2022, the Board approved a share buyback program that provides for an aggregate purchase of currently outstanding common stock of up to $30 million. Through May 9, 2023, VAALCO repurchased a total of $10.4 million worth of shares or about 2.2 million shares. Let me now turn to guidance. As a reminder, we report all of our production with both working interest and net revenue interest. The difference between production, working interest, and NRI represents royalties paid or taken in barrels. Since we have not changed the full-year guidance we provided during our recent year-end 2022 call, I will only discuss our Q2 guidance. For the total company, we are forecasting Q2 2023 production to be between 22,600 and 24,600 work interest barrels of oil equivalent per day and between 17,300 and 19,000 NRI barrels of oil equivalent per day. Looking at NRI production by asset, we are expecting Gabon to be between 8,300 and 9,000 NRI barrels of oil per day. Egypt to be between 6,900 and 7,700 NRI barrels of oil per day and Canada to be between 2,100 and 2,300 NRI barrels of oil equivalent per day. For the second quarter of 2023, we are expecting our sales volumes to be 15,600 to 17,300 barrels of oil equivalent per day, reflecting the delayed March lifting of 630,000 barrels that will benefit the second quarter. As I discussed earlier, this also includes lowering liftings in Egypt due to timing. Turning to costs for the second quarter of 2023, we expect production expense, excluding workover and stock compensation to be between 32.5 million and 39 million on an absolute basis or between $15.50 and $20.50 on a working interest per BOE basis or between $22 and $29 on an NRI per BOE basis. We also expect offshore workovers to be between $0 and $1 million. Our cash G&A for the combined company is expected to be between $3.5 million and $5.5 million. Finally, looking at CapEx for the second quarter of 2023, we are forecasting modestly lower investment compared with the first quarter and should be in the range between $18 million and $28 million. We're still expecting full-year 2023 capital spending to be between $70 million and $90 million. As you can see by our Q1 capital spend on our Q2 forecast that our total capital spending this year is heavily weighted towards the first half of 2023. In 2023, our drilling and completions program is focused in Egypt and Canada. In addition, we have some long lead items for the future drilling campaign in Gabon and some maintenance capital. Approximately 50% of our 2023 capital was earmarked for Egypt, with the remaining 50% split between Canada, long lead items, and maintenance capital. We have 15 wells to 20 wells planned in Egypt. And in Canada, we are planning to drill between 3 wells and 4 wells. You can see our full-year and second quarter 2023 guidance in the supplemental slide deck on our website. I'd like to point out that last quarter, we developed a netback slide in the presentation that shows netbacks for each of the areas broken out by liquids and natural gas, and we've included it again this quarter for reference. There's also a total company blended netback at different realized pricing, where we break-out the major cash costs to approximate a free cash flow before CapEx and working capital changes. One of the costs shown is a differential. Traditionally, VAALCO sold in Gabon based on dated Brent with a differential that was sometimes a premium and sometimes a discount, but overall, it was negligible. Now we have Canadian oil, natural gas and NGLs, all of which trade on a discount based on the market that they are sold in. Also in Egypt, we are marked off of Ras Gara blend, which is generally a discount to Brent with a further discount for the quality of our crude. We are hoping that this additional information and transparency will provide better clarity to the profitability of our producing areas and company in total at different pricing scenarios. With our recent stock price around $4.25, we continue to trade at very low multiples of EBITDAX, despite paying a strong dividend yield and being bank debt free. Additionally, with the TransGlobe combination, we should see a step-up in adjusted EBITDAX in 2023, depending on commodity prices. 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 the 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 cash balance. Overall, we've had a good quarter to start the year with and are benefiting from relatively stable activity levels with a more diverse portfolio that allows us to generate significant free cash flow and invest in the long-term sustainability of our business. With that, I will now turn the call back over to George.

Thanks, Ron. As you've heard this morning, 2023 is off to a strong start. We were able to generate strong adjusted EBITDAX, while funding all of our CapEx, quarterly dividends and share buybacks with cash flow and cash-on-hand and grew our cash position at the end of the first quarter to $52.1 million. We accomplished all of this with slightly lower sales and realized commodity pricing, which shows our continued efforts towards capturing synergies and increasing margins have begun to positively impact 2023 results already. We continue to expect additional cost savings being captured in 2023, and we are projecting increased quarterly sales in Q2. Additionally, we have remained focused on returning value to our shareholders. In Q1 2023, we nearly doubled the quarterly dividend and announced the Q2 dividend payment, which remains at $6.25 per share level. We also continued to repurchase common shares through the buyback program approved in 2022. Through the first seven months of the program, we have returned approximately 10.5 million to shareholders and return repurchased 2.2 million common shares through buybacks. We are delivering on what we committed to the market and to our shareholders, and we are in a solid financial position with no debt and a growing cash balance. Our strategy remains unchanged, operate efficiently, invest prudently, increase, and return value to our shareholders, maximize our asset base, and look for accretive opportunities. In the first quarter, you saw our capital spend ramped down significantly as we have finished the drilling and facilities projects in Gabon, and we are focused on drilling in Egypt and Canada in 2023. The lower capital spend profile should allow us to build meaningful cash throughout the year. But as we mentioned last quarter, our forecasted CapEx range of $70 million to $90 million is heavily weighted in the first half of 2023. Based on current commodity prices, we are forecasting returning about $45 million to our shareholders in 2023 through dividends and share buybacks. This is a significant percentage of our projected operating cash flow at current strip pricing, which demonstrates our ongoing commitment to our shareholders. The plans for the significant cash flow generated throughout 2023 above our existing obligations are to build up a cash reserve for future drilling campaigns and developments. We are working with our partners in EG on the exciting development plan for the venous discovery at Block P, as well as evaluating locations and planning for the next drilling campaign at Etame. Both should see significant increases in activity in 2024, which will continue to grow production and reserves. We are very excited for the future of VAALCO and remain confident that we will continue to deliver superior long-term value to our shareholders. Before I open the call to questions, I would like to point out that as part of our commitment to the environmental fuel ship, social awareness, and good corporate governance, we have made a concerted effort in addressing and improving our ESG transparency and reporting. During 2022, we completed a materiality study, led by our EST engineer with input from key personnel across the organization with responsibility for engaging with key stakeholder groups. Working with an external consultancy group, VAALCO created an ESG materiality framework against which we reported material topics informed by the global reporting initiative, the GRI and the Sustainability Accounting Standards Board, SASB. Additionally, we adopted the framework of the task force on climate-related financial disclosures, TCFD, to drive our focus on response to climate change risks and opportunities. In accordance with our objective to reduce our emissions footprint, we have taken significant steps to progress our approach. We developed a decarbonization program, which was received and reviewed by our Board. This has established a decarbonization steering group, which is comprised of senior management that is responsible for setting the direction of our carbon reduction efforts. Early stage projects are currently being scoped and we look forward to updating our stakeholders on progress in due course. Everything that I've mentioned can be found in our most recent annual ESG report that was published in April of 2023. The report covers VAALCO's ESG initiatives and related key performance indicators and is available on our website under the Sustainability tab. Thank you. And with that, operator, we are ready to take questions.

We will now begin the question-and-answer session. [Operator Instructions] The first question is from John White of Roth Capital. Please go ahead.

Yes. Good morning. My question was about the split on CapEx – drilling and completion CapEx between your three regions and Mr. Bain covered that in his remarks. So, I'll pass it back to the operator and say congratulations on the quarter.

Thanks, John.

The next question is from Stephane Foucaud from Auctus Advisors. Please go ahead.

Good morning, guys. Congratulations as well. A few questions for me and thanks for taking my questions. The first one is on Egypt and again the receivable. And I'm trying to see whether I'm comparing apple with apple. So, at the end of December, we had 140 million total receivable. And I think 100 million of that was Egypt, including the receivable. At the end of Q1, it seems we have about [100 million] [ph] total. And you're saying 50 million are receivable for Egypt, that would suggest you got 50 million payments of receivable in Q1, which is the case is fantastic. That will be my first question. And my second question is, could you talk about the difference in economics between vertical and horizontal well in Egypt in terms of cost, IP rate and recovery? Thank you.

Okay. Thanks for that, Stephane. It's Ron here. I'll take the first part of that question on liquidity around receivables and Egypt, if I understand your question correctly. I think the first thing to bear in mind is, in Q1, we actually had a cargo that we got 450,000 barrels listed and obviously taken out of country and paid offshore. That was $28.5 million worth of receivables, which is great because, obviously, there's no EGPC involved there. We're dealing with a trader. With regards to the receivables for EGPC, generally, obviously, we heard some of the issues that other companies are having, but we certainly did not see it through Q1. Our cash collections and offsets in Q1 were about $19.5 million, Stephane. And we sold directly through domestic sales or January sales of about $11.5 million. So, we actually had a reduction in our receivable from year-end through to Q1. We ended up in Q1 with about $26.5 million worth of receivables in trade AR and then, of course, we still got the $51 million receivable, which is the – backdated entitlement barrels that we continue to have discussions with EGPC and the ministry on to realize cargo's based on that. That's probably giving you some color to Q1 and the liquidity there. With regards to the capital components, George can jump in on this one. But the vertical wells themselves are – obviously, just for our guys, especially our old VAALCO guys who are used to seeing wells being drilled offshore at $25 million, $35 million. A vertical well in Egypt is typically under $1 million or around about $1 million. We have seen some, obviously, increases in costs over the last six months, just again due to the supply chain issues that you see globally and the fact that there's not that many service providers actually operating in Egypt. The Arta well that was drilled at the beginning of Q1, that was our long lateral, the first time that we've drilled a long lateral well in Egypt. And that well is probably coming in about $3 million, $3.5 million. So that's a differentiation between the well costs. These wells are very economic, although you may see discussions about 100 barrels 200 barrels of oil per day coming out of these wells. Because of such low cost, we're looking at internal rates of return well above 100%. So again, we're quite happy to continue to invest in Egypt at those economic criteria as long as we continue to crystallize on the cash position. The only negative part for Q2 going forward is that we don't have a lifting in Q2 and export listing in Q2, but we are building up our inventory. We will have enough inventory as we exit Q2 to push for a Q3 cargo.

Thank you. And with regards to...

I'll just add on – on two points, particularly within the drilling campaign in Egypt, as I mentioned earlier in the call, we've seen significant improvements in the production numbers in Egypt. We've seen considerable success in the drilling campaign, not just from the vertical wells. Obviously, the complexity in the first Nukhul Arta well, Arta-77, it's – that particular well is currently producing around to 200 barrels a day and is still cleanup. So, we expect it to continue that cleanup over the next few months. But we also – because of the length of the lateral, we expect a very low decline rate on that well. So, that well is difficult to – it's still a very economic well, but it was a well just due to the well of the lateral, it took some time to drill and complete. When we look at the cycle times now that we're achieving in Egypt from the traditional or the historic position between drill and complete, I mean we are really pushing the efficiencies to the maximum on that drilling campaign. So, even though the costs are relatively low, it's 1 million, 1.5 million per well, we're actually driving those costs more because we're basically managing to drilling complete about 1.5 wells every month. So, we're very, very quickly getting to getting through that drilling program and comfortably staying within the CapEx, we currently do all the CapEx gains in Q2.

Great. Thank you.

The next question is from Charlie Sharp of Canaccord. Please go ahead.

Yes, thank you very much and good morning gentlemen. I appreciate the thoughts update for the Q1 numbers and operations. I just wonder if you can highlight high level, the next – let's say, over the next six months, the key internal and external point in terms of Equatorial Guinea and Gabon that you need to sort of bed in before a return to capital expenditure rising again next year? Thank you.

I partly missed that question, Charlie. Was that for Equatorial Guinea and Gabon, the key points?

Yes. Just the sort of high-level key points that you need to get in place internally and externally before you know exactly what next year will look like in [indiscernible]?

Okay. So, let me start with Gabon. Obviously, from the drilling campaign last year, we had a mixed bag of results. We had some very strong performance in the first two wells in the Gamba sands. And then on this – on the latter two wells, we didn't find the Gamba sands on the third well and had a success on the Dentale exploration leg from a reference standpoint. And then obviously, from the fourth well, it didn't pan out as we had modeled for the Dentale well there. So, we are taking and we have taken all these geological data points in addition to the new seismic analysis that was acquired in 2020 and interpreted in 2021. To look at the opportunities for the drilling campaign in Etame where we reduced the overall risk of the campaign for either additional Gamba targets for accelerants, but also looking at step-out opportunities and what the risk factors are around step opportunities to continue to fill the [indiscernible]. So, for the last six months or so and continuing for the next few months, one of the key analysis is going to be the subsurface analysis and mapping around the Etame field, the reason [indiscernible] as well is key for us to understand the geological place and where we put the campaign together for 2024, 2025 we are looking at the lower risk prospects to increase the production and increase the drilling success. So that's really the key focus in the Gabon right now is a deep dive into the subsurface structure and the risk profile. With regard to Equatorial Guinea, as I mentioned earlier on the call, we've got to get to a point of finalizing the documentation with the partners. Once we do anticipate that to be completed by the summer, and I also mentioned on the call, we brought about six or seven detailed studies that are kicking off on completion of that documentation, which will move into free production CapEx – and that's one of the – so the external element that you mentioned would be the finalization of the documents and sitting down and agreeing with our partners in the upcoming TCM meetings. And the internal side is with that work schedule going through optimizing the top side analysis within the program for venous looking at the, as I mention, the effectiveness of doing a dedicated campaign of three wells rather than moving the rig in and out and the economic efficiencies that come with that. And the practical piece of work that we'll be doing this year is obviously conducting a seabed survey around the shelf area for the location of top side facility.

That’s great. Thank you.

The next question is from Jeff Robertson of Water Tower Research. Please go ahead.

George, on Slide 5 of the deck, you showed the benefits that you all have seen in production in Egypt from optimization efforts. Can you talk about how much more heavy lifting there is to do just trying to improve field operations and what that could mean for production?

Yes. I mean we've done a considerable amount of work in a very short period of time, as I mentioned, about reducing the back pressure and eliminating the blockages that were in the production facilities in Egypt. We've got – and we will be putting together a presentation for EGPC and the Ministry to show before and after scenario, both on the field locations and in the production locations. So, when I look at the heavy lift on production optimization, I think, and I know stores in the room beside [Ron] [ph]. But my view is, I think we've done a lot of the heavy lifting in relation to production optimization, and we're reaping the benefits of that. And as I mentioned, we're really focused right now on the drilling optimization. So, we're reducing our drilling plans. But one of the other items we're looking at is that workover in the South, [has a lot well] [ph] to see if we can bring that well back on production, which regard a few hundred barrels per day to the field. The other key elements there that we've been working on, as I mentioned earlier, is feeling that we improve the CSG position inside the field of preventing and for the reducing the opportunity for uncontained spills. That's been a big program with us going through the field operations in the first quarter and into the second quarter. I think we still have more to do there. But I'll pass over to Ron, if he wants to add any color to that operation.

Yes. Thanks, George. Yes, I think, I mean, we've put – we've sort of set the stage for a lot of the big projects. I think that will impact us and provide, I guess, positive results going forward. There is still a large, I guess, inventory of smaller items that we're looking at, specifically around downtime, pipeline integrity, facility integrity, emissions, electrification and crude oil polishing that we think we can make a significant impact on going forward. But I think you've covered most of the other ones off.

In Canada, I think you all talked about improving operating efficiency as well, including pad designs and facilities. Will the outcome of that work have an impact on how you think about a 2024 capital program?

Well, most definitely. I'll let Ron jump in in a minute. But we have always said that we need to try and ensure that we reduce our time lines between drilling and complete and we need to figure out within the existing environmental conditions that happen in Canada. So, how do we drill and complete in the same cycle and now have wells basically suspended for months on end. I think what we've seen in Q1 and coming into Q2 is a significant improvement in those cycle times. As mentioned earlier on the call, we've seen the two wells that were delayed from 2020 to come online in Q1. And we've seen another two wells coming online in Q2 to the point where we've got production on a BOE basis in Canada well above 3,000 barrels a day at the moment. So almost, if not a record production level for that operation. So, we are driving those efficiencies. We are reducing those cycle times, and we are starting to see the dividends both in Canada and in Egypt with the increased production. So, when we look at our guidance position in Q1 and the production levels that we've actually achieved, we're right up there where we would plan to be. Anything you want to add to that, Ron?

Yes. I mean, I think the key to Canada is, as you mentioned already, George, cycle times. Canada is unique in a sense that you have access to a lot of the technology and the infrastructure, and it's being able to, I guess, engage those services and the technology and time. What causes the long cycle times is predominantly surrounding the weather. So, these are your breakup periods in the spring and in the fall. And it's building a program that, I guess, fits into that weather window that allows you those faster cycle times. From a drilling perspective, the Canadian oilfield is an experienced segment when it comes to drilling the horizontals, so long horizontals. And again, our focus needs to be on drilling long laterals, not short laterals. So, we're looking at the 3-mile laterals versus 1.5-mile laterals – and then the other thing is doing pre-facility work ahead of the drilling campaign so that when it comes time to tie in, you've already got the pipelines in place and you've already got the facilities geared up to do that. So, it's a combination of those things that will make Canada is successful.

Thank you.

We have time for questions from one more person. Next question comes from Bill Dezellem of Tieton Capital. Please go ahead.

Thank you. That’s Tieton Capital. Let me start with the timing of the lifting. I need a little clarification because I was thinking that the move to the FSO tele that, that was going to give you a lot more consistent liftings. What am I missing or what was different in this quarter?

George, I could take that one if you want.

Yes. No, go ahead. That's fine.

Yes. So generally, we target our liftings to be roughly every 4 to 5 weeks. And in the winter months, particularly in the Gabon segment of West Africa, you see a lot of heavy currents that impact, I guess, the ability for vessels to more adjacent to the tanker safely. And we had a lifting scheduled for late March. I think it was around 26th, 27th of March. And basically for five or six consecutive days due to the heavy currents, we were unable to actually hook-up the tanker and proceed with that lifting. So, what happened is that lifting got moved into early April, I think, April 3. So it was delayed by about six days, but it did miss the first quarter cutoff. The FSO has the ability contrary to what we previously had with the FPSO is to continue producing into the FSO, due to the additional cargo volume that we have now. So, normally, in the past, we would have had to probably shut-in because we would have been at tank tops because of the lifting had been delayed. What happens now is that because of the additional cargo volume, we can continue producing and then the sale or the movement of the cargo, if it's delayed a couple of days, it's delayed, but it doesn't impact our production.

Sure. That's really helpful. So, it was also my impression that the FSO was positioned in such a way to minimize the impact of the weather. So, is the implication that the currents were really, really strong or did you find that, that positioning maybe wasn't exactly what you originally hoped for?

Well, I guess the positioning of the FSO as with any vessel is a judgment call between trying to mitigate, I guess, the currents for most of the time. So, we know that January, February, March are generally times of the year when there's a massive current swing in Gabon. Starting in, sort of April, that current swing goes 180 degrees the other way. So, it's trying to come up with a location and a mooring location that sort of gives you the best odds for the most liftings on time. So, for instance, we had another lifting that was scheduled to start a couple of days ago. It started on time. It's underway. No issues with currents. So, it's really do you set your lifting up so you can only do those three guaranteed – or do you set it up so that your vessel can handle most of the liftings most of the time.

So, really well prepared for 9 out of 12 months and the other 3 is just going to be a little more on mother nature.

Exactly. And with the additional capacity we have now in the FSO, it doesn't actually impact our production, just impacts the sales from quarter-to-quarter if it's a quarter end lifting.

Great. Well, that's really helpful. And then would you discuss the field gas line work that's being done an Etame? I didn't fully understand what was actually being done and ultimately, the end goal of that project?

Sure. So, there's a low-pressure fuel gas line that runs from the SEENT platform to the Etame platform supplying fuel gas, to the Etame platform, power generation and process. And that also supplies gas from Etame to the new FSO for boiler service. We, during one of our routine inspections picked up a flange leak or what we've now identified as a flange leak. It's a very small leak, but nevertheless, it is a small flange league adjacent to the SEENT platform. That will require diver intervention. So, at this point, we're essentially scoping out the [boats] [ph] that are in the area and when those boats are available because we're obviously trying to tie that in with some additional work with some of the other operators to mitigate the cost of that. The impact of not having fuel gas essentially means that the tele or the FSO is burning liquid fuel in the boilers, and that's the additional cost that we're seeing.

That's helpful. Thank you. And then one final question, if I may. If I recall correctly, you all were looking at a potential adjacent field to Etame with – in conjunction with a new partner to develop. What is the update on that?

I guess on that one, Bill, we actually did have some good discussions with the Gabonese government in Q1. The data, it is in conjunction with our partners, which are BWE and Panoro. We were hopeful of – because this has been going on now for some 12, 15 months. But we are hopeful that a conclusion is arriving relatively soon, certainly hopeful in the next few months. It is key to say that there has been more progression in this last six weeks period to do with block G&A, and we are very encouraged with the adjacent block to Etame than there has been in the previous six or seven months. So, hopefully, we'll see some more movement the next time we report it.

So George, the issue is with the Gabonese government as opposed to amongst the partners?

I've met with the partners directly – one of them directly who – there's no issues between the partners and the issues directly with the DTH and the Gabonese government.

Great. Thank you both.

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

Thank you very much, operator. Well, I can say that we got back on track for Q1, we've had a very strong performance in the production side in Q1. We've seen some sensitivity around commodity pricing, however, we've maintained [Technical Difficulty] that we made to the market with regard to buyback and regard to dividend because the commodity prices have remained above the levels on which we made those commitments. The company's operating performance is strong, albeit that we have to acknowledge that, as Ron mentioned, the stock price performance has not been strong, and that's something we have to wrestle with and something we have to look at when we're looking at how we are conducting our share buyback program. At the moment, we remain restricted in our blackout period, but it is something that we will be addressing and how we accurately adjust these levers to maximize the opportunity for repurchase on the undervalued stock position. As always, I say this at the end of every call, anyone that we haven't got to who was in the queue, and I fortunately can't see the queue today, but anyone we haven't got to or anyone who wants to reach out and have a discussion, please contact [our Chris] [ph] directly, and we'll make sure that, that can be arranged for you. In the meantime, thank you very much for your time taken and listening to the call today.