Ladies and gentlemen, thank you for standing by. Welcome to the VAALCO Energy First Quarter 2023 Conference Call. During today's call, all parties will be in a listen only mode. Following the company's prepared remarks, the call will be opened for a question-and-answer session. During the question-and-answer session, we ask that you limit your questions to one and a follow-up. You can always rejoin the queue. 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, 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 provide a more in-depth financial review. George will 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 BOE per day or 23,152 BOE 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 flow 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. We are building size and scale to substantially grow VAALCO. With a 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 acres 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. 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 are 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 well and completions design and achieve better production results. On 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 eight days -15 days per well in 2023. We believe that we can now drill future vertical wells in around 10 days -15 days, which is very positive for the overall economics compared to the 38 days that we had been seeing. After completing the Orca-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. 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 over in conjunction with the work completed for production optimization are 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 spills by improving well sites with secondary containment measures and increased use of composite 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 hit 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 15-20 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 one-mile lateral and a 1.5-mile lateral and a three-mile lateral. It is our intention to move to longer three-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, expect to complete this review this summer and will 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. 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, 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. We saw no need to adjust our full year production guidance. Let me now turn to a discussion on Equatorial Guinea, another area that holds significant future potential for VAALCO. VAALCO owns a working interest in Block P offshore Equatorial Guinea, where there 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 substantive documents for Block P, which included the Venus development relating to the production sharing contract. Following our meetings in March, we continued 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 topsides 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 three wells, two producers and one water injector, are drilled as a single campaign, which will reduce the overall drilling costs through lower mobilization costs. We are also building detailed options for the production and evacuation facilities throughout Q2 and Q3 of 2023. Planned activity include 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. We believe that this amount will not impact our full year 2023 guidance of between $70 million-$90 million. We are excited about the future at EG. We anticipate a strong, efficient, and economic development of this discovery with first oil projected for 2026. Additionally, there are clear strategic benefits in further diversifying the revenue generation and country focus of our portfolio. We have a proven track record for a development of this kind. We look forward to demonstrating these capabilities as we progress the Venus 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 hardworking 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 while continuing 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, good morning, everyone. Let me begin by echoing George's comments about our continued strong performance. 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 14th, 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. Down about 11% from the fourth quarter. As we mentioned during our last call, a 630,000 barrel gross lifting in Gabon, originally planned for March 2023, was delayed until April 3rd due to adverse weather conditions, which resulted in lower NRI sales volumes. If these sales were added to the Q1 2023 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 Gharib blend, our 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 collars 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 $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 overaccruals 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 boat costs due to having extra marine equipment in field for the lifting longer than planned. We also have higher costs year-over-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 oil prices weaken 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 Harmattan 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 31st, 2023, decreased to $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 31st, 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 of 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 lifting. They took their most recent lifting last December. We accrue 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 at March 31st, compared with $38 million at year-end 2022. Other balance sheet items worth highlighting include other assets where we hold a backdated 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, we are carrying 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 three and a quarter cents 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 six and a quarter cents per share quarterly or $0.25 per share annually. The Q1 2023 dividend was paid on March 31st, 2023, and yesterday we announced the same dividend amount for the second quarter of 2023 to stockholders of record on May 24th and payable on June 23rd. 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 9th, 2023, VAALCO's 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 the 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 working interest barrels of oil equivalent per day and between 17,300 NRI barrels 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 NRI barrels and 9,000 NRI barrels of oil per day, Egypt to be between 6,900 NRI barrels and 7,700 NRI barrels of oil per day, and Canada to be between 2,100 NRI barrels 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 barrels - 70,300 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 three and a half and five and a half million dollars. 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 are still expecting full year 2023 capital spending to be between $70 million and $90 million. As you can see by our Q1 capital spend and 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 is earmarked for Egypt, with the remaining 50% split between Canada, long lead items, and maintenance capital. We have 15-20 wells planned in Egypt, and in Canada we are planning to drill between three and four 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. 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. In Egypt, we are marked off Ras Gharib 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 EBITDA, despite paying a strong dividend yield and being bank debt-free. 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 size 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. 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 has begun to positively impact 2023 results already. We continue to expect additional cost savings being captured in 2023. 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 six and a quarter cents 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. 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 ramp down significantly as we have finished the drilling and facilities projects in Gabon. 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. As we mentioned last quarter, our forecasted CapEx range of $70 million-$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 Egypt on the exciting development plan for the Venus 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 stewardship, 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 ESG 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 plotted material topics informed by the Global Reporting Initiative, GRI, and the Sustainability Accounting Standards Board, SASB. We adopted the framework of the Task Force on Climate-related Financial Disclosures, TCFD, to drive our focus and response to climate change risks and opportunities. In accordance with our objectives to reduce our emissions footprint, we have taken significant steps to progress our approach. We have de-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. 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. With that operator, we are ready to take questions. We will now begin the question and answer session. To ask a question, you may press Star then One on your touchtone phone. If you are using a speakerphone, please pick up your handset before pressing the keys. To withdraw from the question queue, please press star then two. As a reminder, we ask that you limit your questions to one and a follow-up. If you have additional questions, you can rejoin the question queue. The first question is from John White of Roth Capital. Please go ahead. Yeah. Good morning. My question was about the split on CapEx, drilling and completion CapEx between your three regions. Mr. Bain covered that in his remarks, I'll pass it back to the operator and say congratulations on the quarter. Thanks, John. The next question is from Stephane Foucaud of Auctus Advisors. Please go ahead. Morning, guys. Congratulations as well. A few question from me, and thanks for taking my question. The first one is on Egypt and again, the receivable. I'm trying to see whether I'm comparing apple with apple. At the end of December, we had $140 million total receivable, and I think $100 of that was Egypt, including the receivables. At the end of Q1, it seems we have about $100 total, and you're saying $50 are receivable for Egypt. That would suggest you got $50 million payments of receivable in Q1, which if the case, is fantastic. Will be my first question. My second question is, could you talk about the difference in economics between a vertical and a horizontal well in Egypt, perhaps in terms of cost, IP rate, and recovery? Thank you. Yeah, thanks for that, Stephan. It's Ron here. I'll take the first part of that question on liquidity around receivables in 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 twenty-eight and a half million dollars worth of receivables, which is great because obviously there's no EGPC involved there. We're dealing, you know, with a trader. With regards to the receivables for EGPC, generally, obviously, we've 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 nineteen and a 0.5 million, Stephan. We sold directly through domestic sales or January sales of about eleven and a half million. We actually had a reduction in our receivable from year-end through to Q1. We ended up in Q1 with about twenty-six and a half million dollars worth of receivables in trade AR. Of course, we still got the $51 million receivable, which is the entitled backdated entitlement barrels, that we continue to have discussions with EGPC and the ministry on to realize cargoes based on that. That's probably giving you some color to Q1 and the liquidity there. That's great. With regards to the capital components, and George can jump in on this one, but the vertical wells themselves are, you know, obviously just for our guys, especially our old VAALCO guys who are used to seeing wells being drilled offshore at, you know, $25 million, $35 million. A vertical well in Egypt is typically under $1 million bucks or around about $1 million bucks. 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 in Egypt. That well is probably coming in about $3 million-$3.5 million. 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 they're such low costs, we're looking at internal rates of return well above 100%. Again, we're quite happy to continue to invest in Egypt at those economics 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, an export lifting in Q2. We are building up our inventory. We will have enough inventory as we exit Q2 to push for a Q3 cargo. Thank you. With regards to that, I'll just add to that, Stephane, on two points. Particularly within the drilling campaign in Egypt, as I mentioned earlier in the call. You know, 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 and the first Nukhul Arta well, Arta 77, it's that particular well is currently producing around 200 barrels a day, and it's still cleaning up, so we expect it to continue that cleanup over the next few months. We also, because of the length of the lateral, expect a very low decline rate on that well. That well is difficult to... It's still a very economic well, but it was a well just due to the length 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, on... 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. Even though, you know, 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 drill and complete about one and a half wells every month. We're very, very quickly getting through that drilling program and comfortably staying within the CapEx range or currently below the CapEx range in Q2. Great. Thank you. Thanks, Stephan. The next question is from Charlie Sharp of Canaccord. Please go ahead. Yes, thank you very much. Good morning, gentlemen. Appreciate the awesome 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 points 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? Yeah, 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 West Africa. Okay. let me start with with Gabon. Obviously from the drilling campaign last year, we had, you know, a mixed bag of results. We had some very strong performance in the first, the first two wells in the Gamba Sands. On this, on the latter two wells, you know, we didn't find the Gamba Sand on the third well and had a success on the Dentale exploration leg from a, from a reference standpoint. Obviously from the fourth well, you know, it didn't, it didn't pan out as we had modeled for the, for the Dentale well there. We are taking, and we have taken all these geological data points and in addition to the new seismic analysis that was acquired in 2020 and interpreted in 2021. We look at the opportunities for the drilling campaign in Etame and where we reduce the overall risk of the campaign for either, you know, additional Gamba targets for accelerants. Also looking at step out opportunities and what the risk factors are around step out opportunities to continue to fill the adage. For the last six months or so, and continuously for the next few months, one of the key analysis is going to be the subsurface analysis and mapping around the Etame field. The regional map as well is key for us to understand the geological plays 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. That, that's really the key focus in the Gabon right now is, a deep dive into the subsurface structures and the risk profiles. With regard to Equatorial Guinea, as I mentioned earlier on the call, you know, we've got to get to the point of finalizing the documentation with the partners. There's. Once we do anticipate that to be completed by the summer, as I also mentioned on the call, we've got about six or seven detailed studies that are kicking off on completion of that documentation, which will move into pre-production CapEx. And that's one of the. The external elements that you mentioned would be, you know, the finalization of the documents and sitting down and agreeing with our partners in the TCM, upcoming TCM meetings. The internal side is with that work schedule, going through and optimizing the top side analysis within the program for Venus, looking at the, as I mentioned, 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. 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 the top set facilities. That's great. Thank you. The next question is from Jeff Robertson of WaterTower Research. Please go ahead. Thank you. George, on slide five of the deck, you show 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 in trying to improve field operations and what that could mean for production? Yeah, 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 a before and after scenario, both on the field locations, and in the production locations. When I look at the heavy lift on production optimization, I think, and I know Thor's in the room to say otherwise, 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. As I mentioned, we're really focused right now on the drilling optimization. We're reducing our drilling times. One of the other items we're looking at is that work over in the South Ghazalat well to see if we can bring that well back on production, which would add 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 ensuring that we improve the CSP position inside the field, both for preventing and for 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. I'll pass over to Thor if he wants to add any color to that operation. Yeah. Thanks, George. I mean, we've sort of set the stage for a lot of the big projects I think that'll impact us and provide, I guess, positive results going forward. There is a still a large, I guess, inventory of smaller items that we're looking at, you know, specifically around downtime, you know, pipeline integrity, facility integrity, emissions, electrification and crude oil polishing that we think we can make a significant impact on going forward. 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, and I'll let Thor jump in in a minute, but we have always said that we need to try and ensure that we reduce our timelines between drilling and complete, and we need to figure that out within the existing environmental conditions that happen in Canada. How do we drill and complete in the same cycle, and not 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 2022 come online in Q1. We've seen another two wells coming online in Q2 to the point where, you know, we've got production on a BOE basis in Canada, well above 3,000 barrels a day at the moment. Almost a, if not a record production level for that operation. 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. When we look at our guidance position in Q1 and the production levels that we've actually achieved, you know, we're right up there where we would plan to be. Anything you want to add to that, Thor? Yeah, I mean, I think the key to Canada is, you know, as you mentioned already, George, is cycle times. You know, 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 that those services and the technology and time. What causes the long cycle times is predominantly surrounding the weather. 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, you know, the Canadian oil field is an experienced segment when it comes to drilling, you know, the horizontals, the long horizontals. Again, you know, our focus needs to be on drilling long laterals, not short laterals. You know, Looking at the three-mile laterals versus the one-and-a-half mile laterals. 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. You know, It's a combination of those things that'll make Canada 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 Teli, 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. Yeah, no, go ahead. That's fine. Yeah. Generally, we target our liftings to be roughly every, you know, four weeks to five weeks. 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 moor adjacent to the tanker safely. We had a lifting schedule for late March. I think it was around the 26th, 27th of March. You know, for 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. What happened is that lifting got moved into early April, I think April 3rd. 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. 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. It was also my impression that the FSO was positioned in such a way to minimize the impact of the poor weather. Is the implication that the currents were really, really strong, or did you find that positioning maybe wasn't exactly what you originally hoped for? I guess the positioning of the FSO is a judgment call between trying to mitigate, I guess, the currents for most of the time. We know that, you know, January, February, March are generally times of the year when there's a massive current swing in Gabon. You know, starting in sort of April, that current swing goes, you know, 180 degrees the other way. 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. For instance, you know, 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. It's really, you know, do you set your lifting up so you can only do those 3 guaranteed, or do you set it up so that your vessel can handle most of the liftings most of the time? Really well prepared for 9 out of 12 months and the other 3, it's gonna be a little more up to mother nature. Exactly. With the additional capacity we have now in the FSO, it doesn't actually impact our production. It just impacts the sales from quarter to quarter if it's a quarter end lifting. Great. Well, that's really helpful. Thank you. Then, would you discuss the field gas line work that's being done in Etame? I didn't fully understand, you know, what was actually being done and ultimately the end goal of that project. Sure. There's a low pressure fuel gas line that runs from the CENT Platform to the Etame Platform, supplying fuel gas to the Etame Platform power generation and process. 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 leak adjacent to the CENT Platform. That'll require a diver intervention. At this point, we're essentially scoping out the boats 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 Teli or the FSO is burning liquid fuel in the boilers. That's the additional cost that we're seeing. That's, that's helpful. Thank you. 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 another... A A new partner to develop. What is the update on that? I guess on that one, Bill, we've 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 months, 15 months. 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 DNA. We are very encouraged with the adjacent block to Etame than there has been in the previous six or seven months. Hopefully, we'll see some more movement, the next time we report out. 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. There's no issues between the partners. There's issues directly with the DGH 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've 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, but we've maintained commitments that we've made to the market with regard to buyback and regard to dividend because the commodity prices have remained above the levels under 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, 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 unfortunately can't see the queue today, but anyone we haven't got to or anyone that wants to reach out and have a discussion, please contact Al or Chris directly, and we'll make sure that that can be arranged for you. In the meantime, thank you very much for your time taken listening to the call today. The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.