VAALCO Energy, Inc.

Q1 2023 Earnings Conference Call


spk01: Ladies and gentlemen, thank you for standing by. Welcome to the Valco 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.
spk11: Thank you, operator. Good morning, everyone, and welcome to Valco 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. DACO 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 pressure lead, the presentation posted on our website, and in the reports we filed with the SEC, including the Form 10-K and Form 10-Q. Please note that this conference call is being recorded. Let me turn the call over to George.
spk05: 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 Valco 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 EBITDAX, 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, and we are building size and scale to substantially grow Valco. With a diversified portfolio of assets across four countries, including Gabon, Egypt, Equatorial Guinea and Canada, I will spend a little time detailing operation 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 nuchal 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 well and completions design and achieve better production results. 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 to 15 days per well in 2023. We believe that we can now drill future vertical wells in around 10 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 1100 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 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 one mile later 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, track 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 Itami and 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 SSO 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 minimise 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 the TAMI And overall, our production costs were at the lower end of our guidance. We're 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. 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 our full year production guidance. Let me now turn to a discussion on Equatorial Guinea, another area that holds significant future potential for Valco. FALCA 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 finalised multiple substantive documents for Block P, which included the Venus development relating to the production sharing contract. Following our meetings in March, we continue to work towards the finalisation of documents between the partners, having completed the PSC documentation with the Ministry. We are now moving forward with the project, subject to the finalisation 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 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're 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, but we believe that this amount will not impact our full year 2023 guidance of between $70 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 in 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 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 Valco 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 transport acquisition already and continue to make progress towards capturing more, all while continuing to build size and scale. We are debt-free and remain firmly focused on our strategic vision of accretive growth while maximising 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.
spk06: 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 EBIT DAX 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 3 cents per diluted share in the first quarter of 2023, compared with 17.8 million or 17 cents 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 utilised. This increases the profit all borrows 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 normalising for the transition period adjustment and deferred tax expense or adjusted net income for Q1 2023 totalled $7.3 million or seven cents 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 lifting 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 listing 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 listing timing in Egypt where a cargo is being moved from Q2 to Q3. Realised 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, 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've protected via costless callers 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 work over expense in the first quarter, a result of over accruals in 2022. Workovers in Q4 2022 total $4.7 million. As we have discussed this morning, we had lifting delays due to weather in Gabon, which did increase our Q1 bulk costs due to having extra marine equipment in field for the lifting longer than planned. We also have higher costs 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 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 Tatami 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 a million dollars per month. DD&A expense for the three months ended March 31st, 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 cost charge 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 of all 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 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 listing 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 31, compared with $38 million at year-end 2022. Other balance sheet items worth highlighting include other assets where we hold the 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 cutting no bank debt and have credit facilities available to utilise 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 programmes in Egypt and Canada. In 2022, Valco paid quarterly cash dividends of three and a quarter cents per common share beginning in Q1 2022 for a total of 13 cents 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 25 cents 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 the 9th, 2023, Falcos 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 a 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 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 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 work over 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 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 and $28 million. We're still expecting full year 2023 capital spending to be between $70 and $90 million. As you can see by our Q1 capital spend and our Q2 forecast, 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 to 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, 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, Falco 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 Raskara 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 transflow 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. With that, I will now turn the call back over to George.
spk05: Thanks, Ron. As you've heard this morning, 2023 is off to a strong start. We were able to generate strong adjusted EBIT DATs 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, 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 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 returned, 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, maximise 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, 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 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 Venus Discovery at Block P, as well as evaluating locations and planning for the next drilling campaign at Itami. 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 Valco 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 EST engineer with input from key personnel across the organization with responsibility for engaging with key stakeholder groups. Working with an external consultancy group, Valco created an EST materiality framework against which we plotted material topics informed by the Global Reporting Initiative, 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 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 developed a decarbonisation programme which was received and reviewed by our board. This has established a decarbonisation 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 Valco'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.
spk01: We will now begin the question and answer session. To ask a question, you may press star then 1 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.
spk08: Yeah, 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.
spk06: Thanks, John.
spk01: The next question is from Sussane Foucault of Octus Advisors. Please go ahead.
spk09: Good morning, guys. Congratulations as well. A few questions for me, and thanks for taking my question. The first one is on Egypt and, again, the receivables. And I'm trying to see whether I'm comparing Apple with Apple. So at the end of December, we had 140 million total receivables, and I think 100 of that was Egypt, including the receivables. At the end of Q1, it seems we have about 100 total receivables, and you're saying 50 are receivables for Egypt, that would suggest you got 50 million payments of receivables in Q1, which is the case, is fantastic. That would be my first question. And 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.
spk06: Okay, thanks for that, Stefan. 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 $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'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 and in Q1 were about $19.5 million, Stefan. 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've 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 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 Valco guys who are used to seeing wells being drilled offshore at, you know, $25, $35 million, a vertical well in Egypt is typically under a million bucks or around about a 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 a long lateral, the first time that we've drilled a long lateral in Egypt, and that well is probably coming in about three, three and a half million dollars. That's a differentiation between the well costs. These wells are very economic, although you may see discussions about 1-200 barrels of oil per day coming out of these wells. Because of 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 economic criteria. as long as we continue to crystallise on the cash position. The only negative part for Q2 going forward is that we don't have a listing in Q2, an 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.
spk09: Thank you.
spk05: And with regard to... I'll just add to that question on... 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 in the first nuchal Archer well, Archer 77. That particular well is currently producing around 200 barrels a day and is still cleaning up. So we expect it to continue that cleanup over the next few months. But we also, because of the length of the lateral, 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 length of the lateral that 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 a million, a million and a half per well, we're actually driving those costs lower because we're basically managing to drill and complete about one and a half wells every month. So we're very, very quickly getting through that drilling program and comfortably staying within the CAPEX range or currently below the CAPEX range in TT.
spk09: Great. Thank you. Thanks, Stefan.
spk01: The next question is from Charlie Sharp of Canada Accord. Please go ahead.
spk04: Yes, thank you very much, and good morning, gentlemen. Appreciate the awesome update for 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.
spk05: I've partly missed that question, Charlie. Was that for Equatorial Guinea and Gabon, the key points?
spk04: Yeah, just the sort of high-level focus key points that you need to get in place internally and externally before you know exactly what next year will look like in West Manchester?
spk05: 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 the latter two wells, we didn't find the gamba sand on the third well and had a success on the dental exploration leg from a reference standpoint. And then obviously from the fourth well, it didn't pan out as we had modeled for the dental well there. So 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 looked at the opportunities for the drilling campaign in Itami and 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-out opportunities to continue to fill the ullage. So for the last six months or so, and for the next few months, one of the key analysis is going to be the subsurface analysis and mapping around the Tami Field. The regional map as well is key for us to understand the geological plays and where we put the campaign Together for 2024-25, 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 profiles. With regard to Equatorial Guinea, as I mentioned earlier on the call, we've got to get to the point of finalising the documentation with our partners. 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 topics. And that's one of the external elements that you mentioned would be the finalization of the documents and sitting down and agreeing with our partners in the TCM, upcoming TCM meetings. And the internal side is with that work schedule, going through and optimizing the top sides analysis within the program for Venus, looking at the, as I mentioned, the effectiveness of doing a, 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 the topside facilities. That's great. Thank you.
spk01: The next question is from Jeff Robertson of Water Tower Research. Please go ahead.
spk10: 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 trying to improve field operations and what that could mean for production?
spk05: 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. So when I look at the heavy lift on production optimization, I think, and I know Thor's in the room beside Ron, 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 times. But one of the other items we're looking at is... that work over in the South Gasolat 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 CSE position inside the field both for venting 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 Thor if he wants to add any color to that operation.
spk02: Yeah, thanks, George. Yeah, I think, I mean, 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.
spk10: 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?
spk05: Well, most definitely. 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. So 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 and we've seen another two wells coming online in Q2 to the point where we've got production and a BUE 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, Thor?
spk02: Yeah, I mean, I think the key to Canada is, you know, as you mentioned already, George, cycle times. You know, Canada is unique in the 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 in 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, you know, the Canadian oil field is an experienced segment when it comes to drilling, you know, the horizontals, the long horizontals. And again, you know, our focus needs to be on drilling long laterals, not short laterals. So, you know, we've looking at the three-mile laterals versus the one-and-a-half-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 successful. Thank you.
spk01: We have time for questions from one more person. Next questions come from Bill DeZellum of Teton Capital. Please go ahead.
spk07: Thank you. That's Tietan 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?
spk02: George, I could take that one if you want.
spk05: Yeah, no, go ahead. That's fine.
spk02: Yeah. So generally, we target our liftings to be roughly every four to five 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 moor adjacent to the tanker safely. We had a lifting scheduled for late March. I think it was around the 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 3rd. 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 the lifting had been delayed. What happens now is that because of the additional cargo volume, we can continue producing, and then the sale rate
spk07: the movement of the cargo if it's delayed a couple of days it's delayed but it doesn't impact our production or that's really helpful so it was also my impression that the FSO was was positioned in such a way to minimize the impact of the poor weather so is the implication that the currents were were really really strong or did you did you find that that that positioning maybe wasn't exactly what you were originally hoped for?
spk02: 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, you know, we had another lifting that was scheduled to start a couple days ago. It started on time. It's underway. No issues with clearance. So it's really, you know, 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?
spk07: So really well prepared for nine out of 12 months, and the other three, it's going to be a little more up to Mother Nature.
spk02: Exactly. And 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.
spk07: Great. Well, that's really helpful. Thank you. And then would you discuss the field gas line work that's being done in ATOM? I didn't fully understand what was actually being done and ultimately the end goal. of that project?
spk02: Sure. So there's a low-pressure fuel gas line that runs from the SENT platform to the ETOM platform supplying fuel gas to the ETOM platform power generation and process. And that also supplies gas from ETOM 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 scent platform. That'll require a diver intervention. So 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 tele or the FSO is burning liquid fuel in the boilers, and that's the additional cost that we're seeing.
spk07: 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 ATOM with in conjunction with a new partner to develop. What is the update on that?
spk05: 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-week period to do with block G and H. And we are very encouraged with the adjacent block to Tame than there has been in the previous six or seven months. So hopefully we'll see some more movement the next time we report out.
spk07: So George, the issue is with the Gabonese government as opposed to amongst the partners.
spk05: I've met with the partners directly, one of them directly. There's no issues between the partners. There's issues directly with the DTH and the government. Great. Thank you both.
spk01: This concludes our question and answer session. I would like to turn the conference back over to George Maxwell for closing remarks.
spk05: 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 made to the market with regard to buyback and with 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, 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 programme. 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 levels 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, of course, can't see the queue today, but anyone who 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.
spk01: The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.

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