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spk03: Good day, everyone. Welcome to Cosmos Energy's second quarter 2022 conference call. Just a reminder, today's call is being recorded. At this time, let me turn the call over to Jamie Buckland, Vice President of Investor Relations at Cosmos Energy.
spk08: Thank you, Operator, and thanks to everyone for joining us today. This morning, we issued our second quarter earnings release. This release and the slide presentation to accompany today's calls are available on the Investors page of our website. Joining me on the call today and to go through the materials are Andy Ingalls, Chairman and CEO, and Neil Sharpe, CFO. During today's presentation, we will make forward-looking statements that refer to our estimates, plans, and expectations. Actual results and outcomes could differ materially due to factors we note in this presentation and in our UK and SEC filings. Please refer to our annual report, stock exchange announcement, and SEC filings for more details. These documents are available on our website. At this time, I will turn the call over to Andy.
spk05: Thanks, Jamie, and good morning and afternoon to everyone. Thank you for joining us today for our second quarter results call. I'd like to start today's presentation looking at the operational delivery in the quarter. I'll then hand over to Neil to talk through the financials before I wrap up today's presentation. We'll then open up the call for Q&A. Turning to slide three, 2Q was another quarter of strong execution for Cosmos as highlighted by the boxes on this slide. Our production assets are performing well with production for the quarter at the upper end of guidance. Our three development projects, Tortue Phase 1, Jubilee Southeast, and Winterfell, are continuing to make good progress and are expected to deliver production growth of around 50% by 2024. We continue to optimize our world-class gas portfolio in Mauritania and Senegal, working closely with partners and the governments to accelerate and deliver value from our significant discovered resources. Today, Cosmos announced its plan to utilize existing contractual rights in the sales agreement for GTA Phase 1 volumes to divert cargos to prospective buyers in order to benefit from the current market environment. More on that in a moment. And finally, the balance sheet continues to improve as the portfolio generates cash and drives down leverage, all while supporting our differentiated growth. We'll dig into each of these things later in today's presentation. Turning to slide four, which looks at our producing assets, which are performing well with 2Q production coming in at the upper end of guidance. In Ghana, the Jubilee field continues to deliver. Gross production for the quarter, excluding the impact of the shutdown, was around 92,000 barrels of oil per day. Including this impact, gross production was around 74,000 barrels of oil per day. In May, the partnership completed the planned two-week shutdown, achieving our key objectives, which included important maintenance and the tie-ins for the risers for the Jubilee Southeast development. Following the shutdown, gross production has averaged over 90,000 barrels of oil per day, benefiting from the producer well and the injector well completed and tied in during the quarter. As the operator recently communicated, the Ghana drilling performance has been excellent, with wells coming in ahead of schedule and under budget. The partnership will now focus on managing the performance and reliability of the field until the Jubilee Southeast wells come online, which are scheduled for mid-next year. These wells should drive the next step up in production towards the 100,000 barrels a day field target. A 10 gross production of around 24,000 barrels of oil per day was in line with expectations. One producer well is currently being drilled at Enyenra, with production for that well expected in the fourth quarter. As the operator highlighted in its recent trading update, the partnership has been performing a review of the 10 resource development opportunities. We believe there remains a significant amount of undeveloped oil and gas and are evaluating the optimal path to bring these resources online over the coming years. As part of that optimization plan, We had two riser-based wells planned at 10 this year to support the delineation of the ENTOME resource. In July, the partnership drilled the first of the two riser-based wells. The NT10 well was drilled to test two separate reservoir objectives with the reservoir quality and thickness better than expectations, but the well encountered water. The well was drilled in a structural load to test the boundary conditions for the ENTOME resource modelling. The second riser-based well, NT11, is planned for late 2022, targeting a different fairway in a structurally higher setting. The results of the two wells should allow us to high-grade and optimize the future drilling plans for the TEN enhancement project. Next, Royal Guinea, gross production of around 31,300 barrels of oil per day was in line with expectations. but sequentially lower quarter on quarter due to higher facility downtime and certain wells being offline for work over activity. We have two ESB installations planned this year with the first completed during the quarter. As we flagged in May, the partnership extended licenses of both Sabre and Akume to 2040, extending our 2P reserves base by around 6 million barrels, which creates an incremental NPV10 of around $100 million at a $75 margin. per barrel oil price. With the extension, the partnership has committed to drill a package of four infill and ILX wells. A rig has been selected and we expect to begin that work in the second half of 2023. In the Gulf of Mexico, net production of 20,600 barrels of oil equivalent per day was above expectations and around 10% higher than the previous quarter due to less downtime of third party facilities in the second quarter. The HP-1 vessel, which processed production from the tornado field, had been scheduled for a routine dry dock in late 2Q. This has now been deferred to the third quarter, so we expect there will be downtime of around 45 days related to tornado in 3Q. Four-year production guidance remains unchanged. The Kodiak sidetrack has now been drilled with completion activities ongoing. Drilling results of the well are in line with our expectations, and initial production is expected later this quarter. Also on Kodiak, we completed the preemption transaction in June to acquire an additional 6% interest, taking our total interest to around 35%. The new sidetrack well, combined with our larger working interest, should increase our net production in the Gulf of Mexico by approximately 3,000 barrels of oil equivalent per day after the Kodiak sidetrack comes online. Finally, at the end of the second quarter, we sanctioned a new subsidy pump project at the odd job field, which should both accelerate production and also increase recoverable reserves by extending the economic life of the field. A great investment, which we expect to have a very short payback, particularly in a higher price or environment. Turning now to slide five. We've talked in previous presentations of growing production by around 50% by 2024. This slide has a status update of the three key developments that we expect will drive that growth. First, Tortue Phase 1, our LNG project in Mauritania and Senegal. All work streams continue to make good progress with the project over 80% complete at the end of the second quarter. On the hub terminal, all 21 concrete caissons have now been installed, an important milestone for the project. Piling installation is on schedule and nearing completion, with the construction of the living quarters platform complete and in transit to the site. On the floating LNG vessel, which has been constructed in Singapore, construction and mechanical completion activities continue and commissioning works have commenced. On the SCSO, which is being constructed at the Costco yard in Kedong, In China, mechanical completion loop checking activities continue and were approximately 50% complete at the end of the second quarter. BP is working hard to mitigate the impact of the April lockdown of the Costco yard and the ongoing COVID disruptions in China whilst ensuring the FPSO leaves the yard with a targeted high level of completion. However, the operator has not been able to fully mitigate these impacts and we now expect the FPSO sail away to slip from end September into the fourth quarter. Despite this later sail-away date, the partnership is working to maintain the overall project timeline to first gas by optimizing the sequencing of the hookup activities. On the subsea, the installation of the subsea pipeline began in the second quarter, with a second pipeline vessel expected to arrive later this year to begin the deepwater portion of the pipeline. There have been quality issues with the fabrication of some of the subsidy equipment, which will require repair. We don't currently anticipate this to impact the overall project timeline. And finally, on drilling, we've successfully drilled two of the four wells required for first gas. The third well is in progress. So even with the supply chain challenges, we continue to make good progress quarterly and are still targeting first gas in the third quarter of 2023 with the first LNG cargo targeted for year-end 2023. On Jubilee Southeast, the project's approximately 40% complete, with long lead items ordered and the drilling on track to commence in the fourth quarter. As I mentioned earlier in the presentation, work was done during the Jubilee FPSO shutdown to allow the tie-in of these wells. Initial production is targeted for the middle of 2023, with the new wells expected to increase total Jubilee field production to over 100,000 barrels per day. At Winterfell, the field development plan has been submitted to the partnership, and formal FID is expected by the end of the third quarter. Based on the additional technical work we completed on the initial wells, we now believe the total resource is significantly larger than previous estimates, with up to 200 million barrels of gross recoverable resource. I'll talk more about the development plan on slide six. As we've described in the past, we plan to develop Winterfell as a phase subsidy tieback project. The first phase, which can be seen on the right side of the slide, is expected to include five wells, three drilled before first oil, targeting around 100 million barrels of gross recoverable resource. Based on the pressure work from the discovery wells, we now believe the total resource could be around double the original 100 million barrel estimate. which we expect to prove up as we drill and produce the Phase 1 wells. Winterfell is already well advanced with long lead items ordered and a rig selected to drill and complete the first wells next year. The partners have received a field development plan from the operator and we expect FRD approval by the end of the third quarter. This low-cost, lower-carbon oil development is expected to have strong economics. Development costs are expected to be around $10 per barrel, with operating costs around $12.50 per barrel, delivering a break-even of less than $25 per barrel. First oil is expected around 18 months from FID approval. Turning to slide seven. Over the last two slides, I've discussed the development projects in the portfolio that we expect to drive production growth around 50% over the next two years. This slide looks at the deep hopper of opportunities in Mauritania and Senegal that we expect can deliver significant additional value and contribute to a growing gas weighting across the portfolio. First, Tortue Phase 1. To optimize the commercial value of sales for the gas production from Tortue, Cosmos plans to utilize existing contractual rights under our Phase 1 LNG agreement to divert cargoes to prospective buyers in order to benefit from the current market environment. In the gas sales agreement for phase one, we have a deliver or pay contractual right, which allows us to take advantage of elevated global LNG prices for a portion of our phase one volumes. By exercising this right and diverting cargoes, COSMOS could retain significantly more upside to global gas prices, especially if current gas prices severely dissipated from oil prices. Second, Tortue Phase 2. As we said last quarter, given the structural changes to the global gas markets we have seen in recent months, we are working with the operator and the government to ensure we have the right development concept for Phase 2 with regard to scope and scale. We are therefore working closely with our partners to optimise the development scheme to best utilise the existing Phase 1 infrastructure to maximise cash flow and return to the partnership. We also want to manage cost exposure in light of the supply chain constraints and inflationary pressures we are seeing across the industry. A development decision is now planned for the end of the third quarter. Third, on Borrella, with the expiration of the C8 license in 2Q, the partnership has agreed the substantial terms and conditions of a new PSC and the license is awaiting government approval. The new PSC, which retains the area surrounding our successful Borrella and Orca discoveries, would grant the partnership two years to submit a development plan. As we discussed in the past, the area has future development potential of around 10 million tonnes of LNG per annum and we would also plan to develop these resources in phases. As we would have a new PSC carved out from the existing C8 license, we were required to write off our historical E&A costs from an accounting perspective, although they are still tax deductible and cost recoverable against our torture development. Lastly, at Yakuturanga, the partnership continues to progress the initial phase of the gas development with the government, which centers on a domestic gas solution to provide low-cost gas to support the country's energy needs to drive its rapidly growing economy. I recently visited Senegal and Mauritania to meet with their respective energy ministers and President Sal of Senegal to discuss the future gas opportunities in the region. With both countries, there is an aligned view around what the future could hold for their gas resource development. There is a significant lower carbon advantage gas resource available offshore that could help provide more energy security for the world and Europe in particular. Equally important, given the characteristics of the gas and its lower carbon intensity, this resource could play a significant part in bridging the energy transition and in providing the affordable energy that Mauritania and Senegal rightly demand for their own development. The very embodiment of a just transition. Both governments recognize that we are living in a volatile world, as the pandemic and the events in the Ukraine have shown. And I believe both countries have the vision to see through this volatility and become important players on the world energy stage in the coming years. As we refine the next phases of our LNG projects, I believe the futures for Mauritania and Senegal are bright. With that, I'll turn the call over to Neil to take you through the financials for the quarter.
spk11: Thanks, Andy. Turning to slide eight. The second quarter saw continued progress as we further enhanced our financial position. We are taking advantage of higher oil prices to rapidly strengthen our balance sheet with net debt approximately down $400 million in the first half of this year to $2.1 billion. EBITDAX in 2Q was around $385 million, which resulted in free cash flow of around $70 million in the quarter and around $290 million for the first half of the year. Excluding capital expenditures in Mauritania-Senegal, base business free cash flow in the first half of the year was around $450 million, demonstrating the strong cash generation ability of our business before our development projects come online. The solid cash performance and continued net debt reduction helped drive leverage down to 1.6 times. Liquidity, which has grown consistently over the last year, was over $1 billion at the end of the second quarter, which is the highest it's been since 2018. As we look forward, with expectations that the business continues to generate strong levels of free cash, we plan to continue to prioritize debt paydown, aiming to get beyond our leveraged target of less than 1.5 times at year end, and net debt below $2 billion. Turning to slide nine. As Andy mentioned, net production of over 62,000 barrels of oil equivalent per day was at the upper end of guidance, helped in particular by strong performance at Jubilee and less downtime in the Gulf of Mexico. We realized a price of $86 per BOE, including the impact of hedging. Excluding hedging, the realized price was around $109 per BOE. Operating costs were lower than guidance during the quarter, reflecting production coming in at the upper end of guidance and some deferred maintenance activity in Equatorial Guinea. CapEx in the quarter was slightly higher than forecast, primarily a result of higher accrued capital related to activity in Mauritania and Senegal. As many companies in our industry have reported, we are seeing the impact of some inflationary pressures, particularly at the Tortu project in Mauritania and Senegal, as we get closer to the finish line. As a result, we are increasing our full-year CapEx guidance by approximately 5% to around $700 million. Although we are seeing some higher costs, we have maintained our free cash flow guidance for 2022 of approximately $420 million, assuming current oil prices, offsetting the inflationary cost impacts. So to conclude the financial section of today's presentation, it was another good performance in the quarter with continued progress across all key areas. We delivered a strong cash flow performance with rising liquidity, material debt pay down, and a meaningful reduction to leverage. I'll now hand back to Andy to close today's presentation.
spk05: Thanks, Neil. Turning to slide 10 to wrap up today's results presentation. While the macro environment continues to be volatile, Cosmos has had another solid quarter of operational and financial delivery. Our production assets continue to perform well, coming in at the upper end of guidance. Our three development projects continue to make good progress to drive the 50% growth in production we expect from current levels by 2024. We are working closely with our partners to optimize the value of our gas portfolio that we expect will deliver growth beyond 2024. Our financial position continues to improve with continued strong free cash flow generation. This has enabled liquidity to rise to multi-year highs with leverage falling sharply, well on track to exceed our year-end targets. And finally, we have the right portfolio at the right time, providing the energy the world needs today and supporting a just transition that addresses the trilemma of energy security, energy affordability, and climate change. Thank you. I'd now like to turn the call over to the operator to open the session for questions.
spk03: Thank you. And ladies and gentlemen, at this time, we will conduct our question and answer sessions. If you would like to ask a question, please press star 1 on your telephone keypad. A confirmation tone will indicate that your line is in the question queue. You may press star 2 if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys.
spk02: One moment, please, while we pull for questions. Our first question comes from Austin Alcoyne with Johnson Rice.
spk03: Please state your question.
spk01: Good morning, Andrew, Neil, and Jamie. Thank you for taking the questions this morning.
spk05: Yeah, hey, good morning, Austin.
spk01: On Tour 2 Phase 1, could you help me understand the mechanics of the spot pricing opportunity? Also, does this increase the potential value to Cosmos over the first year or two of the contract?
spk05: Yeah, sure, Austin. You know, we think there's a differential value in COSMOS versus peers because of the material and growing exposure to international gas. You know, the structural changes in the global gas market on the back of the Ukraine war mean that gas prices are likely to stay higher for longer and, you know, remain dislocated from oil. Now, clearly we've talked about in the past our phase one volumes are priced against a Brent slope. So the price we receive is driven by oil prices. However, there is a deliver or pay clause that would allow us to utilize and take advantage of current gas prices in instances where pricing allows us to pay for it by an agreed non-delivery penalty to our current buyer. This is a typical provision in an LNG sales agreement. We can't share with you the exact details of the contract, but of contracts of this era, the penalty is typically in the range of 20% to 30% of the contractual price, the price that's linked to the Brent slope. So if you take those inputs and you look at an average gas price, let's say, for 24 and 25 of around $20, and an oil price of, let's say, $100 per barrel, the opportunity could be around $200 million of additional revenue net to Cosmos in total over those two years. If you look out at the forward strip and you look at where that's sitting today, TTF is closer to an average of 25 over the 24-25 time period. And with those assumptions, the revenue benefit to Cosmos in aggregate over the two years would be around $350 million. So it's a significant opportunity for us, and we believe it's important to start engagement with prospective buyers now because the opportunity is clearly there.
spk01: I appreciate the color on that. And as a follow-up, You provided a positive update on your Winterfell project with FID approval expected later this quarter and doubling the expected gross recoverable resources. Did the recent technical work from the initial two wells cause any modifications to your development plan slash timeline of this project?
spk05: No, it hasn't, Austin. I think we're targeting FID at the end of this quarter, and we see first oil 18 months afterwards. Clearly, it's a technical work from the first two wells, which we believe has indicated a significantly larger resource. The first phase is a five-well development, as I said in my remarks. That's targeting development of the initial 100 million barrel opportunity. But we think with production data from those initial wells, we would see that being the indicator of a larger resource. And clearly the infrastructure that we're putting in would enable us then to build and expand to fully access that. So I think the work we've been doing over the quarter to get to FID is around that phase one, three initial wells pre-first oil, followed by two follow-up wells. But we're anticipating a larger resource and therefore the ability to expand from there.
spk01: I appreciate the color. That's all from me.
spk05: Great. Thanks, Austin.
spk03: Our next question comes from with Goldman Sachs. Please state your question.
spk10: Hey, good morning. This is Carly on for Neil. Thanks for taking the time. I wanted to just start on TOR2 as we think about the potential for Phase 2. Could you talk a little bit about what are the outstanding gating factors as we should be keeping in mind to get that project to FID? And then are there any changes to the timeline to expected first gas there?
spk05: Yeah, hi, Carly. No, I think that, you know, we've taken the time to make sure that we've got the right project for Phase 2, but in terms of the sort of scale and scope of the project. You know, a lot's happened in the last six months with regard to the LNG market, in particular the European market, and it's important that we've got, you know, the right project that enables us to, you know, fully access that opportunity. We also need to make sure that from a contracting perspective at a time of real inflationary pressures, we've got the right approach to the market. And the development concept that we pursue is clearly an important part of that. So that's been the work that we're doing at the moment. The objective is to come to a decision on that concept by the end of the third quarter. That will then enable us to do the detailed work, the feed work to get to the costs In Mauritania and Senegal, to get formal approval, which is FID, we have to go to the government with the full contractual position, the full costs, etc. And the anticipation would be that we would do that in 2023. And that leads you to a first gas date in the sort of end 26, 27 timeframe. So no fundamental change to that. But I think it's ultimately about have we got the concept which allows us to best take advantage of the current market conditions and allows us to ensure that we've got the optimum scope from managing the inflationary pressures which are clearly in the market today.
spk10: Got it. That's helpful. And then the follow-up was just kind of on your last point on inflation. As you're pursuing these different development projects across the portfolio, can you just flush out a little bit kind of what you're seeing from an inflation perspective and what steps that you're taking to mitigate those pressures?
spk05: Yeah, you know, it's clear that we're seeing in the deep water now, you know, supply chain challenges really across all dimensions, you know, whether it's sort of drilling rigs being sort of the high level of utilization or subsidy equipment, installation vessels, et cetera. So I think the mitigations are around doing the work up front to ensure that you've got a concept and an approach to the contracting strategy, which allows us to get to the most cost-effective approach. And I think that's a clear part of the work that we'll be doing on Winterfell. Again, as an example on Winterfell, without getting ahead of our skis, we have been ordering the long lead items. We moved ahead to select a rig. We've done that for the program in Equatorial Guinea. Access to the right equipment is clearly important. I think these are all tried and tested techniques that the industry has used. I think for us it's about being rigorous now about the management of this literally on a day-by-day basis. No increase in scope, don't allow the projects to have any gold plating, and then it's about the rigor of execution, right approaches to the market, access to the best equipment, et cetera. And I think that is the other challenge the industry has today. It's not only an equipment issue, but it's also a human issue, getting access to equipment you know, the A teams. So I think those are all of the areas we're focused on, but, you know, from a Cosmos perspective, you know, we have three projects. We're clear where we stand on each of those projects, and now it's the rigor and discipline of managing them through to first production.
spk10: Great. Thanks for that, Collar.
spk02: Our next question comes from Matt Smith with Bank of America. Please go ahead.
spk06: Hey, thanks, guys. The first couple of questions are just around the LNG pricing, if I could. Could I just double check on the phase one volumes? Does that contractual right apply to 100% of your net entitlement of the phase one volumes? And then the second question on the same topic was really around sort of phase two and the contracting opportunity there. I guess each time we talk about this, the gas curve keeps moving higher and higher. Is it fair to characterize that you're more likely to look for gas exposure for the phase two volumes? And if so, is that likely to be through pure spot pricing? Or do you think there's perhaps a happy medium in between?
spk05: Yeah, thanks, Matt. Yeah, actually, the LNG contract is public, actually. So If you look through that contract, Matt, what you'll find is that we have to maintain every second year 50% of the ACQ. So that means sort of year one, you can divert 50%. Year two, you can divert 100%. Year three, you can divert 50%. Year four, you can divert 100% while still meeting all of your obligations under the contract. with the penalty for the diverted cargoes. So what it means is, you know, to do the math, you're paying a penalty on the diverted cargo, and you can divert up to, on average, 75% of the cargoes, with it sort of, in a modeling sense, 50%, 100%, 50%, 100%. Let's say typically, you know, I can't share with you the actual penalty, but contracts of that era had a penalty of around, you know, somewhere between 20% and 30% of the price to the buyer. Yeah, sorry, on phase two. Look, I think the step on phase one is an indication of where we intend to go on phase two. You know, we would want to sort of, build a relationship with customers that could take those volumes in that 24, 25, 26, 27 timeline. Phase two volumes would be following absolutely in that time period. And we would look to overlay it with contracts that gave us real exposure to the gas, gas exposure, as you said. But look, I think genuinely it is going to be a mix. The big difference for phase two versus phase one was that we don't anticipate any financing requirements for phase two. We put the infrastructure in place for phase one, and therefore the incremental build-out in terms of additional capital is very modest. You know, we've talked of a number of less than a billion dollars in the past. So as you start to think about the flexibility that gives us, it's significant. And that's really, you know, the excitement that we have now around, you know, the exposure to the international gas price. As I said, you know, in my answer to Austin's question, I think we're quite unique amongst our peers in having this exposure to not only, you know, sort of high-margin low-carbon oil, but actually high-margin low-carbon gas. And, you know, as you start to look at now where the forward curve is going for gas, you know, due to, you know, the important extension of the war in Ukraine, we believe there's a fundamental opportunity for us to access. So in terms of bringing that forward, we can do it with the phase one volumes, as we've described with the diversions, and then clearly back that up then with the phase two volumes and become a very sort of credible seller into the market.
spk06: Perfect. Thanks, Andy. Really appreciate the detail. Perhaps if I'm okay to sneak one more in. It was just around the sort of NOC cost carry that you have at Tortue. It sort of sounds as though you're sort of no longer prioritizing the refinancing of that, you know, given that you don't have necessarily balance sheet constraints anymore. So just wondering if you could remind us sort of on the default mechanism of how you will recoup that cost and perhaps even if you're able to give any color on how quickly you might recoup that, that would be much appreciated.
spk11: Yeah, I'll ask Neil just to pick that up, Matt. Yeah, so Matt, the mechanism is meant for sort of the phase one revenue to the NOCs to repay sort of the NOC loan, and sort of there is some flexibility built in in terms of the duration of that repayment. So, but, you know, clearly the more they generate from the phase one volumes means the faster we can potentially get our, you know, get our proceeds from the loan back. Alternatively, you know, as you noted, sort of the, sort of, while the sort of immediate pressure is still off from getting the NFC loan off of our It's still something we want to pursue. I think just from a timing perspective, that naturally will make sense around sort of the phase two project sanction to bring back into the fold. So it's still something on the agenda.
spk06: All right. Okay. Thanks, both. I'll pass over. Cheers.
spk11: Great. Thanks, Matt.
spk03: Our next question comes from Alex Smith with Investec. Please go ahead.
spk04: Hi, guys. Thanks for the call. Just two quick ones from me. First one, you're rapidly approaching your gearing target and producing healthy levels of cash flow. Just when can we begin to see maybe a decision on dividends or buybacks? And would there be a preference for either? And then just on Ghana, can you just comment on the cost of the wells that you have been drilling? You mentioned that they've come in slightly under expectations and the plans for a decision of the second rig. Given the current oil price environment, is there an opportunity to accelerate this decision given how well the drilling program has gone to date?
spk05: Thank you. I'll talk about Ghana first and then Neil can pick up the financial framework. I think in terms of the decision around the second rig, as I've commented in my remarks. We are, you know, drilling well in Ghana at the moment. You know, the wells are ahead of schedule, you know, under cost. And actually, the opportunity, therefore, is to deliver the volume increase that we intended across the assets, but actually do it through a high-graded, you know, one-rig program. And that's the focus for today. So we don't anticipate bringing a second rig in currently. We're going to continue to evaluate that opportunity. But I think it's all around this mantra of capital discipline today. You know, as you start to deal with the inflationary pressures, You know, the opportunity ultimately is around operate more efficiently. That's how you mitigate the increase in the unit cost. So, you know, that's our focus today, and I feel confident that we can actually do that. So we don't, you know, we're not making a decision today to bring in a second rig. We've got, you know, a clear program that will enable us to start the drilling of the Jubilee Southeast Wells this year. That enables us to deliver on that project where we anticipate startup once the subsidy equipment is in place in the middle of the year. And that, in terms of driving 23 volumes, that is the big driver. And then we have the follow-up of the 10 enhancement project that would follow in 24, 25. So I think we're well-placed today, and we don't have to... There is no economic benefit from bringing a second rig today. And then, Neil, in terms of the gearing targets?
spk11: Yeah, so in terms of the gearing and as well as allocation of capital, our views really haven't changed overly too much, Alex. I think, you know, the goal is to fund, you know, the capital program, both the maintenance and the growth projects that we have. And then within that, you know, while leverage is, you know, continue to sort of prioritize debt pay down until leverage is less than sort of one and a half times. We've said we're sort of get on track to get there before the end of this year, but we want that to be sustainable before we sort of look at sort of shareholder returns. But it is sort of clearly next on the agenda that we would look to. In terms of buybacks versus dividends, again, I think that will be more to come on that in terms of which specific method. It will largely depend on where both the share price looks like at that time period, but I'd say currently sort of more tilted towards the buybacks, but we'll look at that as we achieve our debt targets.
spk02: Great. Thank you very much.
spk03: Our next question comes from Bob Brackett with Bernstein Research. Please state your question.
spk00: Yes, please. I saw that you drilled two of the four producers at Tour 2 Phase 1. Can you comment on, did they come in at least based on the log analysis in line with pre-drill predictions?
spk05: Yeah, overall, you know, we're looking to build well capacity, Bob, where we've got sort of coverage really from sort of two-slice-three wells that will deliver the required, you know, plateau versus four wells. So the first two wells have been able to stay on track to do that. We're currently drilling the third well, and then the fourth well is actually a twin of one of the original exploration well. So in terms of having the required well productivity with the appropriate level of insurance at first gas, we feel good about what we've seen so far.
spk00: Great. Thanks for that. In terms of EG, you mentioned the four wells as part of a drilling program split between infills and ILX. How are you strategically deciding whether to go for a more sure infill versus a greater upside ILX? What's the logic there?
spk05: Yeah, great question actually. We see two really good opportunity sets. You know the history of why we went into EG. We felt from two perspectives that it hadn't been fully developed from an infill perspective and there was a sort of remaining exploration opportunity in the Rio Muni. We've built a pretty good hopper now of infill opportunities And we're going to high-grade the first three of those, actually, Bob, in terms of the drilling program. And then the fourth well will be the ILX well, which is targeting a deeper, you know, untested albion opportunity, you know, underneath the Sabre and Akume infrastructure that looks really interesting. So that's the balance. And, you know, clearly the ILX opportunity is significant and will be a significant opportunity a game changer in terms of our position there in Sobhra to Kume. Whilst the infill wells are really high quality, high rate of return, short payback, you know, tied back to the existing infrastructure. So we've got, you know, both of those opportunities on the roster. And clearly gaining the license extension out to 2040 has made both of those opportunities even better, yeah, because clearly, you know, with the extension we have, if we were successful with the Albion, we've got a significant amount of time then to drill out, you know, quite a large associated inventory. So, you know, the drilling program will start the back end of next year, and I think will be an interesting phase of the development of Sabre and Akume.
spk00: Great. Thanks for that. A super quick one, if I may. In terms of just the follow-on on exercise and contractual rights on the TOR2 Phase 1, I believe is BP both the counterparty of those as well as the operating partner, and is everything amicable between you all?
spk05: No, I think you've got to be quite important that BP is the upstream operator. BP Gas Marketing is the purchaser. So there's actually a Chinese wall between BP as the upstream operator and BP Gas Marketing as the buyer of the gas. And actually everything is Amacron.
spk00: Perfect.
spk02: Thank you.
spk05: Thanks.
spk03: Our next question comes from James Hosey with Barclays. Please state your question.
spk07: Yeah, hi there. A couple for me. I guess going back to your right to divert some of the Tortoise Phase I cargos, how much notice do you need to give on this? I'm just wondering how far ahead do you need to make a call on LNG spot prices?
spk05: Yeah, I don't want to get into too much of the detail, James, because it is, you know, But in terms of the ability, we have the right to, you know, divert cargo by cargo, and therefore we have the ability to build a program. So, you know, we can, you know, dictate the duration of the scale of the diversions.
spk07: Okay. Okay, and then just on another topic, if you could give us some colour on how the 2022 capital budget is shaping up. I'm just thinking that you're talking about Winterfell, sounds like it's a billion-dollar project gross, and obviously inflationary pressure as well. Should we be assuming higher topics compared to the 2022 budget of $700 million?
spk05: Yeah, so look, we don't normally give CapEx guidance for the following year until we can match it with our final year results. But I think if you know conceptually the way to think about it is, you know, the base business, as we talked about, it's a sort of sustained production that we're spending around sort of $350 million on that in 22. And looking forward with the rigs locked in, et cetera, you know, we feel sort of good about that number. Then you've really got the capital that goes into the growth projects, and you've got a couple of dynamics, yeah? You've probably got a similar level of spend on Jubilee Southeast. You've got a reducing level of spend in Mauritania, significantly reducing. And then you've got an uptick in Winterfell, as you described. So I think that's the way to think about it. And then of the margin, you've got discretionary capital around the ILX programs. So I think that's the way to think about it, and clearly the timing around the relative ramp-up and ramp-down of those projects is, you know, so you've clearly got, you know, significant decrease in spending in Senegal, but you will have, as you say, an uptick in the Winterfell spend.
spk07: Okay, very good. Thank you.
spk03: Thank you. And just a reminder, to ask a question, press star 1 on your telephone keypad. Our next question comes from Mark Wilson with Jefferies. Please state your question.
spk09: Hi. Thanks for taking my questions. A few points here. So it sounds like you're not bringing a second rig in or don't plan to do the Jubilee Southeast development drilling. That's the first clarification. Could we also just understand where we stand on those shell exploration payments after success in Namibia and then lastly we've seen a Biala Berala PSC extension some change terms there do we expect something else like that on Yakarta Ranga thanks a lot yeah you know as I said answering a prior question on the second rig I think it's actually a good news story
spk05: At a time of real inflation, it's about driving efficiency into the business. And I think on Jubilee, we've seen the demonstration of that in terms of the drilling performance. And so for us, it's about continuing down that path, high grading the well selections, being able to deliver the volume increase that we've outlined in Jubilee, and, you know, deliver the benefit from that project. So we don't, you know, we're not anticipating making a decision on a second rig currently. You know, clearly we'll continue to evaluate that mark, but the answer is no, no second rig at the moment. In terms of Shell, they have success with two wells in Nabibia, La Rona and Grasse. Our understanding is that they intend to submit an appraisal plan at the beginning of the fourth quarter, and with the submission of the appraisal plan, they would be obligated to pay the bonus from the contract that we have in place with them. So that's what we anticipate. On Borrella, yeah, Borrella, you know, it's an important step forward in UPSC. You know, clearly we had to separate out in a development sense the discoveries that we had in Orca and the surrounding acreage. Better to do it now ahead of a sort of development proposal than do it later. So, you know, we spent the time now to do that. In an accounting sense, that has been an impact, but actually in an economic sense, the costs that were associated with the, essentially, was the orca exploration well, we get the benefit of that both in cost recovery and tax on tortue. So there's no economic impact from this. But what we do have, we have a new PSC. It's substantially the same terms. You have some small modifications around local content, etc., But ultimately, we now have the basis on which to move forward now with Borrella on a very sort of, you know, clean, forward-looking perspective. And as I said, I think, you know, for us it was important to do this now rather than sort of get to the development decision and then have to negotiate the new PSC as part of that development decision. So I think, you know, we're on track now to move forward and do the concept work that's required to bring that forward as a real opportunity. And, you know, there's a big resource base there. You know, again, it's characterized, you know, by low-cost, low-carbon gas adjacent to the European market. And our objective, as I said in remarks, will be to tackle that with a phased approach very much in the same way as we've done on torturing.
spk09: Got it. Okay. No, thank you. And turn it over.
spk05: Great. Thanks, Mark. Appreciate it.
spk03: Thank you. Since there are no further questions at this time, I would like to bring the call to a close. Thanks to everyone joining today. You may disconnect your lines at this time. Thank you for your participation.
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