Good day, everyone. And welcome to Kosmos Energy Third Quarter 2021 Conference Call. Just as 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 Kosmos Energy.

Thank you, operator, and thanks to everyone for joining us today. This morning, we issued our third quarter earnings release. And this release and the slide presentation to accompany today's call are available on the Investors page of our website. Joining me on the call today to go through the materials are Andy Inglis, Chairman and CEO; and Neal Shah, 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 that we note in this presentation and in our U.K. 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.

Thanks Jamie and good morning and afternoon to everyone. Thank you for joining us today for our third-quarter results call. I'll run through the highlights for the quarter before handing over to Neal to take you through the financials. I'll then provide a few closing thoughts in summary before taking questions at the end. Starting on slide 1, a lot has been achieved at Kosmos Energy since our last quarterly call in August; we delivered several transactions that have advanced the company's strategy and significantly improved our financial position. We'll talk more about the Oxy Ghana acquisition shortly. But in summary, the acquisition is expected to materially increase our free cash flow from high-margin oil assets, which we plan to invest in our portfolio transition to LNG at a time of rising global natural gas demand while reducing debt. The transaction is strategically consistent and financially compelling for Kosmos and is highly accretive across all financial metrics. In Mauritania and Senegal, we closed the FPSO transaction in mid-August, which materially reduces our capital expenditure to first gas. With increased production, including from the Oxy Ghana transaction and higher oil prices, we now expect to fund our remaining CapEx to first gas through organic cash flow. We expect the newly acquired assets and our base business to generate significant free cash flow from 4Q 2021 and are currently hedging our growing production at attractive levels. With EBITDAX growing and excess cash used to reduce absolute debt going forward, we expect to leverage the balance sheet rapidly and we are targeting a leverage ratio of less than 2x at year-end 2022 at $65 Brent. Using current oil prices, that target will be around 1.5x. And finally on this slide, the recent transactions continue to strengthen our ESG agenda with growing investment in Africa across our portfolio aligned with our objective of supporting a just energy transition. Turning to slide 2, the acquisition of additional interest in the Jubilee and TEN fields in Ghana accelerates Kosmos' strategic delivery across three key dimensions. Firstly, acquired assets generate significant free cash flow; at $65 Brent we expect the assets to generate around $1 billion of incremental free cash flow between now and the end of 2026, over 2x our initial investment. At current prices, that figure could be materially higher. While we manage our business to perform at much lower oil prices, the recent strength in Brent and WTI does highlight the considerable upside potential if OPEC plus continues to be disciplined on supply management over the coming years. Second, we expect the assets to really enhance EBITDAX and cash flow, enabling us to grow the company organically while reducing our absolute debt. With rising EBITDAX and excess cash to further pay down debt, we expect the transaction to accelerate the pace of deleveraging to our target level of 1x to 1.5x. Third, we plan to use some of our increased cash flow to fund our growing gas activities in Mauritania and Senegal, including our remaining CapEx to first gas on Tortue Phase. On the right-hand side of the slide, you will see how the portfolio mix is expected to change as our LNG activities in Mauritania and Senegal ramp up. We plan to use low-cost lower carbon oil production to finance the transition to low-cost lower carbon natural gas, thereby shifting the balance of our portfolio over time and increasing our exposure to the fuel with the strongest long-term demand and a necessary part of the energy transition. In our 1Q result earlier this year, we detailed the five-year goal to get production up to around 100,000 barrels a day of oil equivalent by 2026 when Phases 1 and 2 Tortue are expected online. Clearly, this transaction accelerates our production goal by several years, while at the same time strengthening the balance sheet. Turning now to slide 3; we announced the Oxy Ghana transaction on the 13th of October, with our intention to fund the transactions through a mix of new equity and new senior notes. With a green issue, we issued around 43 million shares in total, raising approximately $140 million of equity overall. The shares were issued at a small premium to the previous night's closing price, with the transaction multiple times oversubscribed, with strong demand from new and existing investors in Europe and the US. We launched the senior notes offering the following week, issuing $400 million of five and a half-year notes non-call two, which were priced at 7.75%. The issue was also heavily oversubscribed with strong demand from both high yield and emerging market investors. I'd like to thank our equity and bond investors for their support about the deal itself and the subsequent financings, which have put the company and the balance sheet in great shape to execute our strategy. It's very much appreciated. The bottom of the slide you can see the impact of the transaction on our near-term metrics. Pro forma for the assets acquired, we expect our year-end exit productions to be greater than 75,000 barrels of oil equivalent per day, with pro forma EBITDAX of over $900 million for 2021 resulting in year-end pro forma leverage of around 2.5x. Turning to slide 4; operationally, we continue to make good progress in each of our production hubs. In Ghana, Jubilee is currently producing above 80,000 barrels of oil per day gross with a J-56P coming online in July, and the J-55 water injector online in September. The second Jubilee producer is currently being drilled and is expected to be online before year-end. This should result in Jubilee production exiting the year above 85,000 barrels per day. At TEN, gross production is currently around 30,000 barrels of oil per day. The gas injector came online last month as expected to support current production levels. At Equatorial Guinea, gross production is currently around 30,000 barrels of oil per day. The partnership finished the Ceiba reliability projects in the third quarter with the completion of the Okume academy upgrade project expected this quarter. The first of three planned infill wells in the Okume complex was completed in August, with hookup currently in progress. In the third quarter, the operator began drilling the second well which is expected to be online in December. The third planned well is now expected to be deferred as the rig is being utilized to plug and abandon existing wells in Equatorial Guinea that are required to mobilize for its next contract before it can complete the drilling of the last well. We do expect the output from the first two wells will largely compensate for any deferral of the third well given reservoir data to the high end of expectations from the first two wells. In the Gulf of Mexico, as previously noted, production in the quarter was impacted by Hurricane IDA which resulted in around 4,000 barrels of oil equivalent being shut in versus our previous guidance. While none of Kosmos' infrastructure in the Gulf of Mexico was damaged in the storm, lengthy shut-ins arose from key pipelines and receiving terminals being offline, leading to basin-wide shutdowns in the aftermath of the hurricane. Production across our GOM assets was restored to pre-IDA levels by the end of September, which should allow for a strong rebound in the fourth quarter. We are currently in the process of drilling the Winterfell appraisal well, with the results expected later this quarter. Turning to slide 5, with respect to Tortue, our world-class gas development. As I've said in the past, Tortue is the right project at the right time; the chart on the left is one you've seen before. It shows that Tortue is the right project because of where it sits on the cost curve. With Phase 1 gas also to BP, the real upside potential is with Phase 2, where we have a huge amount of optionality because the gas is currently uncontracted. We believe that Tortue Phase 2 can deliver gas at a breakeven cost of just over $4 per MMBtu, which therefore competes very favorably with other new LNG projects expected to start production in coming years. The chart on the right shows the project is due to come online at the right time, with global gas demand continuing to grow strongly as the world exits the restrictions of the pandemic. The chart shows the forward curves for JKM and TTF today versus the forward curves a year ago. If we ignore the near-term elevated prices and look further out to December 2023, the chart shows a re-rating of future price expectations with both JKM and TTF leveling out at around $10 per MMBtu, approximately double the same curve from a year ago. This is fundamentally about robust, long-term demand for gas as it displaces more carbon-intensive alternatives and acts as a base load partner to renewables in the energy transition. As demand grows, long-term gas prices are likely to be supported at a level necessary for the marginal cost of supply to meet that demand. In their recent research note, Morgan Stanley predicted that LNG demand is set to rise twice as fast as supply to 2025, with prices expected to be 60% higher over the next five years versus the last five years on average. In this environment, the lowest-cost gas projects should come out on top with Tortue making good progress and other significant gas discoveries we have in Mauritania and Senegal, we believe Kosmos is well placed to take advantage of the strengthening market dynamics. We've contracted Phase 1 volumes to the slope around 10% Brent, which means we'd be selling Phase 1 gas at around $8 per MMBtu at current oil prices. For Phase 2, we are yet to sell the gas which gives us greater flexibility on pricing, whether we choose long-term contracts, different indices, spot sales, or a combination. Turning to slide 6, Tortue Phase 1 continues to make good operational and funding progress with the four key workstreams all moving forward. On the floating LNG vessel, mechanical completion activities have commenced with instrument loop checks, and control system commissioning is expected to commence in the first quarter of next year. On the FPSO topsides integration and hull and living quarters mechanical completion activities have commenced. Pre-commissioning activities are expected to commence later this quarter. On the breakwater, we commenced fabrication of 20 of the 21 caissons with 12 now installed. Jetty piling is expected to commence later this quarter. And finally, on the subsea, Nouakchott and Dakar marine supply bases are being established. This is expected to enable the offshore installation campaign to commence in the first quarter of next year. As you can see in the top picture on the slide, the hub terminal and breakwater is now starting to take shape. The image shows the caissons in position, and you can see the impact on the sea state on the protected side of the breakwater. The bottom picture on the cover slide of today's presentation shows the topside modules being loaded onto the FPSO. Another significant milestone for that key workstream. With regards to project funding, we've completed the FPSO transaction and now have a clear financing path to the first gas on Tortue. The FPSO transaction materially reduces our outstanding CapEx on the project, with all 2021 cash flows now funded through year-end and the remaining benefit expected in 2022. As mentioned earlier, we now expect to fund our extending CapEx to first gas with the free cash flow from our base business, which we are currently hedging at attractive levels. We're also working on the NOC loan refinancing, targeting completion around year-end. As BP plans on its earnings call last week, the project partners and the governments of Mauritania and Senegal are working hard to advance Phase 2 of the project, and we expect a final investment decision in 2022. I'll now hand over to Neal Shah to take you through the financials for the quarter.

Thanks Andy, turning to slide 7. Production of approximately 49,000 barrels of oil equivalent in the quarter was in line with expectations, taking into account the unplanned downtime in the Gulf of Mexico from Hurricane Ida that Andy talked about, which had an impact of around 4,000 barrels of oil equivalent per day in 3Q. As guided last quarter, sales volumes for 3Q were expected to be low due to the number of cargo lifted which resulted in a significant underlift of around 1.5 million barrels at the end of the quarter. Most sales volumes coupled with a working capital draw, partly related to the underlift and partly related to cash payments in Mauritania and Senegal, prior to the FPSO transaction closing, led to a cash outflow within the quarter. The lower realized price in 3Q reflects regular monthly settlements as hedges despite lower sales volumes in the quarter, with 5.5 cargoes expected in Ghana and EG in the fourth quarter and GOM production restored to pre-Hurricane Ida levels, we expect a significant cash inflow in the fourth quarter as we close out the year with more production selling at significantly higher realized prices. The rest of the line items were largely in line with prior guidance. Turning the slide 8. You've heard both Andy and myself talking about our commitment to reducing leverage with a target of between 1x and 1.5x. The Oxy Ghana transaction helps to accelerate delivery of that goal. The equity debt mix we put in place to execute the Ghana transaction meant the acquired assets had a leveraged multiple of less than 2x using a trailing 12 months EBITDAX. This meant the transaction was deleveraging immediately. The chart on the short slide shows the pace of expected deleveraging through year-end '21 and into '22 as we benefit from growing production and higher oil prices, which we are able to lock in with new hedges. We have started to hedge the acquired barrels with two-way collars that have a floor of $70 per barrel and a ceiling of around $90 per barrel. This gives us EBITDAX and cash flow visibility, both of which should positively enhance leverage over the coming months. By the end of next year, we are targeting leverage of around 1.5x at current oil prices, which would be below the level at which we exited 2019 before any benefit from new production in 4Q and 2023. With that, let Andy wrap up today's presentation.

Thanks Neal. Turning to slide 9. As I said in my opening remarks, it's a transformational time for Kosmos, and I'm proud of what the team has achieved within the last quarter. As I look back, 2020 was a year of survival for the sector where Kosmos took the opportunity to reposition its portfolio to be fit for the future. 2021 has been a year of resuming operational activity and strengthening the balance sheet, which has been significantly enhanced by the two major transactions I've talked about in today's presentation. Looking ahead, 2022 is the year in which Kosmos can really start to thrive. We have the right portfolio for the future and a clear pathway to unlocking shareholder value. Looking at some of the important milestones we see through 4Q and into next year. First, we expect our base business assets and the newly acquired assets from the Oxy Ghana transaction to generate significant free cash flow, which we plan to use to fund the Tortue project and to pay down debt. As we move through 2022, first gas at Tortue comes into view with the bulk of the capital funded. We also expect to take FID on Phase 2 during the year. Now 2021 hedges are now rolling off and we are able to hedge our growing production base at significantly higher levels, giving us increased visibility to enhance future cash flows. And finally, building on Neal's comments from the previous slide, we're committed to deleveraging the company with a 2022 year-end leverage of around 1.5x at current oil prices. Thank you, and I'd now like to turn the call over to the operator to open the session for questions.

Our first question is from Charles Meade with Johnson Rice.

Good morning, Andy and Neal. My first question is on the Phase 2 FID for Tortue. Are there any significant questions or unknowns you guys are still grappling with, or alternatively is this just you have to follow the process? But this is a fait accompli?

Okay, Charles, yes, I'll take that question. I believe we have a clear strategy, which involves our prior investments in the infrastructure to support both Phase 1 and Phase 2 developments. Our goal is to fully optimize Phase 2. To achieve this, we need to have the right strategy for the subsea pipeline and LNG solution. The work on the offshore component is well understood; we know how to maximize our pre-investment regarding the FPSO and pipeline with minimal additional spending. We are currently engaging in commercial negotiations to enhance the LNG solution, which is our primary focus. With this structured approach, we are well-positioned to proceed effectively and in a timely manner. Furthermore, the current external environment is beneficial for all parties involved, including our partners, BP, and the NOCs.

Got it, thank you for that, Andy. And then a follow-up question on your activity levels. So your CapEx levels, from the outside looking in, it looks to me like your activity levels across your portfolio in '22 are going to be about the level that we're seeing for Q4. And I guess the question is, is that a fair reading? Is 4Q kind of activity and spending a reasonable baseline to use for '22 levels?

Yes, so let me take that Andy or Charles. Yes, I'd say the piece of 4Q doesn't reflect in terms of the implications for 2018. We're really rounding sort of Mauritania and Senegal, and so I think from a Ghana business, the activity level will be the same, EG spend is sort of moves around by quarter, but broadly will be similar to sort of the levels we spent this year as well as within the Gulf of Mexico. And so we will be spending a bit more and more in Mauritania and Senegal to get sort of the Phase 1 to first gas when we've talked about that around having $300 million left to go post the FPSO transaction in the '22, '23 timeframe.

Our next question is from Neil Mehta with Goldman.

Hi, team. Can you hear me, okay? Thanks, Andy. So first question is just around Tortue and how you're thinking about Phase 2, and specifically, the economics of Phase 2 relative to Phase 1. I think that the Brent slope on Phase 1 is lower than maybe some would have desired, although the economics will get better if we sustain an $80 Brent type of environment. But Phase 2, it feels like there could be some outsized economics. Talk about where we are in terms of the gating process to getting to Phase 2, and just how you think about the contracting environment, especially with global LNG prices having firmed up so much.

Yes, thanks, Neil. I think as I said to Charles, I think we were clear on the basis for the expansion of Phase 2, the minimum amount of CapEx to put into the expansion and using the capital that we've invested in Phase 1. So that enables some very low breakeven costs, which is what we showed in the presentation. So as you look around the world for brownfield expansions, we believe it is one of the most cost-competitive projects around, so hence the desire of the partnership to move forward. So it's advantageous from that perspective. And then I think from a Kosmos perspective, it's advantageous because we have flexibility now on how we price the back gas. Yes, we have flexibility because we have the cash flows clearly from Phase 1. The funding for Phase 2 is considerably lower than for Phase 1; we've talked as a partnership of a number gross being less than $1 billion. So from a funding perspective, there are no financing requirements that cause us to not optimize the pricing. So I think you'll see us going forward now look at how we capture the current market conditions in the best way. And, as I said in my remarks, I think we have opportunities now to look at different indexation, we have the ability to look at some gas being contracted longer term, some proportion of the gas being spot. So we see it as a significant opportunity now, to capture what I believe will be a strong LNG market going through the rest of this decade, and firmly believe in engineering sense, it's the right project at the right time because it has a very low cost of supply. And it's the right project at the right time because it's entering the market when there are very few competing projects, and therefore it can benefit from a very good price environment. So, I think, all of that is to come, Neil. And as you sort of sense, we see it as a major upside.

There are a lot of moving pieces with the business, certainly toward 2. As is in slide that the Oxy Ghana transaction is in motion as well. And obviously the oil price, but is there any way you guys can help us understand what the mid-cycle free cash flow power of this business looks like in a more constructive commodity price environment? Or at a minimum at the curve once you have Phase 1 on? And layered in the Ghana assets as well?

Yes, Neil, to respond to that, we have provided guidance for Phase 1 and Phase 2 free cash flow in the range of $150 million to $200 million per year. The idea is that we need to invest to get it operational, and Phase 1 will fund Phase 2. Once both phases are operational, we should achieve that $150 million to $200 million figure over approximately 20 years from the business. Modeling the oil business at this stage should be straightforward. Our operations in Ghana, EG, and the Gulf of Mexico have similar operating costs, which are around $10 to $15 per barrel, along with some additional maintenance capital expenditures to maintain production at approximately 75,000 barrels per day, and we’ll have some cash taxes, especially in the early years in Ghana and EG. We expect to start paying cash taxes in about three to four years in the Gulf of Mexico. While there are several factors to consider, all aspects should generate solid free cash flow even at an oil price environment of $40 to $50, and we will also see free cash flow from the gas business starting in 2026 and beyond.

Yes. So it's around $100 million unhedged every year for a $5 change by the change in the oil price.

Our next question is from Bob Brackett with Bernstein Research.

Good morning. I've got a short-term question and a longer-term question. On the short term, can you talk about the path to the refinancing of the NOC loans by year-end? Anything we should watch for or worry about?

Yes, Bob, we are actively in discussions with several banks and financial institutions regarding this matter. There aren't any specific milestones to expect in the meantime; it's primarily about facilitating these conversations. We needed to finalize the FPSO transaction before we could engage in discussions about the NOCs, and in recent weeks or months, we've been focused on securing financing for the Oxy Ghana transaction. So, to clarify, I don't anticipate any other milestones until we finalize a deal.

Great. And then the bit of a longer-term question, if I think about Winterfell going to appraisal, is you maintaining the ability to convert that appraisal well into a development well, or is that something you shy away from?

Now we're maintaining that optionality, Bob, yes, so as you rightly say, we had the first discovery well, we are now drilling the second full block, and we're currently, operations are underway. And once we have the results of that, we could then have the opportunity of an early production scheme that brought those wells back online.

Our next question is from Nick Stefanou with Renaissance Capital.

Hi, guys, it's Nick from Renaissance Capital. Thank you for taking my questions. And I've got three to ask if I may, and Andy first one is for you. If I go back a year ago, when BP announced its plan to reduce the scope of Tortue and make it smaller project like the Bir Allah at a low cost. That time it made a lot of sense. But, I mean, gas markets moved up quite a bit since then, just wondering do you think about that decision still made sense? And then a kind of like the follow-up to that question, how should I be thinking about future phases of Tortue? I mean from the first one to a brownfield development, after Phase 2 not adopted, I don't think that would be anymore. So what would then other phases look like? And then my third question is for Neal. I think we've got maybe less than a week left for your partners on Ghana to exercise their pre-emption rights. Can we kind of take it as a given that they are not going to exercise at this point?

Yes, Nick, good questions. I think fundamentally, every dollar we put into Kosmos has to earn the highest possible return. And our objective on the next phase of Tortue was to absolutely deliver the most capital-efficient scheme. And the scheme we described of expansion to 5 million tonnes, essentially, sort of utilizing fully the infrastructure we have in place, is, I believe, absolutely the right decision. And we're driven by ensuring that we create the highest possible returns and generate the most value, and this scheme is the one that actually does that. So I think it's absolutely the right objective, irrespective of the price environment clearly, at a higher price will make a much stronger margin. And that's great for any day of the week. I think when you then look beyond that, I think we would then look, I think for the next phase, as it were Phase 3, to sort of fully optimize the resource base, which can support around 10 million tonnes per annum. And I think that's where you then make the next step up. You fully sort of utilize the existing offshore infrastructure in terms of the FPSO and the pipeline; how do you then increment to 10 million tonnes? It will require additional facilities offshore, it will require additional pipeline; how do you then add out then integrate that into the existing hub terminal? So I think that to me is a very logical process. Yes, you enabled the project through the first phase. Phase 2 is the logical brownfield development to fully utilize invested capital, and delivers the highest return. The third phase should then be about the long-term expansion to fully utilize all of the resource. So that was the objective. I think we've stuck to that plan in a really rigorous way. And I believe through that we've optimized the rigor of that approach, we've optimized the capital efficiency, and therefore the value creation.

Yes, so just on the preemption, Nick, yes, you're right, I mean there's about a week left within that option. And again, we're not going to apply in terms of what the partners do; I think if you sort of step back, the transaction for us was around sort of gaining access to a materially larger stake in Ghana, particularly in the Jubilee Field, where we've gone up from 24% to 42%. And while preemption is possible, the good thing from our perspective is we retain a much larger stake in Jubilee, which is where we see the largest sort of near-term upside and the impact of largely beyond a reduction in the TEN asset. And so it's still outstanding, and we'll know when the times gone through.

Okay, the carbon sensitivity you mentioned a few minutes ago seems to be for the previous Oxy estimate, right? Shouldn't that now be a bit higher due to the increased stake in Ghana?

Yes, no, yes. I mean, there's a, yes, I mean, the number hasn't materially changed in terms of maybe there's another $15 million, $20 million per $5. But again, it's just sort of not a huge overall change.

Our next question is from James Hosie with Barclays.

Yes, hi, thank you. Just a couple of questions for me just first off, how should we think about shareholder returns now? Is that something that can come and leverage falls below 1.5x EBITDA or other considerations or metrics, we can think of a trigger for that catalyst? And then just on Tortue, I was wondering what is the carbon intensity of that production and what you expect it to be? And if there's scope for you to look at marketing carbon neutral cargoes from that project?

Yes, obviously there are talks of shareholder returns and the Neal will chime in. We talked about getting to a leverage range of 1x to 1.5x; clearly, when we're in that range, I think it is a valid conversation to have. And I think the only comments I'll add on top of that is it needs to be sort of sustainable. So how do we get to a world where we can see a sustainable average of 1x to 1.5x? And when we're in that world, we'll then have that debate? Clearly, our objective is to get there as fast as we can. And I think we're pretty clear today on how we know we're doing that, while supporting this transition of the business from purely a low carbon low cost oil business to a balanced portfolio.

Yes, the only thing I'd add on that, Andy, is to Neil's question earlier; the business generates a lot of free cash flow in oil prices, where we are right now. So as we do get leverage to that point, within that range, by the end of next year, we've gotten the capital from Tortue largely behind us to that point. And then additional production on the Ghana. I think that's the appropriate time to have that conversation. And again, I think we're sort of well-positioned to do it at that timeframe stuff, and there's some more work to be done on our end, again, we got a pretty clear line of sight to the delivery of that in a reasonably short timeframe.

Yes, when you look at it how to benchmark from a carbon intensity perspective, it's pretty good. When you look across the range of both existing projects and new projects that are being brought on, it's got a significantly better than average carbon intensity. So we feel good about it from that perspective. And then looking forward to the marketing of carbon neutral cargoes. Yes, it is something that we're looking into; clearly we're a little ways from that point in terms of having those cargoes on the water, but it would be another opportunity, I think, for us to get a differential price for the cargoes, and that's ultimately what it is initially, the cargo is obviously being sold to BP. So in that sense that's their will. I think the opportunity comes when we start to think about Phase 2 and cargos that we may market through different mechanisms. I think that's where we would focus that effort on, James, is the sort of the longer-term view of Tortue and particularly the unmarked Phase 2 cargoes.

Our next question is from Mark Wilson with Jefferies.

Thank you, gentlemen. And I'd like to ask about Ghana; there was some discussion around the time of the deal, potential implications for the operatorship of Jubilee. Is there any reason to think that could change about this deal and could you remind us of the timing of that break into Ghana and whether that might be done a right thing? And then lastly, and you mentioned about TEN gas injector supporting current levels is 30,000 level should be looked at through '22, let's say drilling up on the Ghana side. And then lastly, if there's any commentary regarding the Greater Tortue like right now Bir Allah, yes, whether are that challenge too what do you think about the monetization of those assets?

Thank you, Mark. Regarding Ghana, I want to emphasize our strong operatorship. We have an excellent working relationship with Talos, which has led to substantial progress in operational delivery, particularly in water injection, gas offtake, and drilling performance. Our focus now is to maintain this partnership, which is beneficial for GNPC, especially with their significant stake in the transaction. We aim to leverage this partnership to increase production, manage costs effectively, and meet our targets. On the topic of the second rig, we are currently discussing our drilling program with our partners, with a decision expected by year-end. This timing will allow us to fully utilize a rig for Jubilee, starting with drilling in Jubilee Southeast, while also considering additional opportunities in existing development areas in Jubilee and TEN. It's crucial that we maintain strong drilling performance, driven by a clear program with defined targets. Looking ahead, we see significant potential in Jubilee, particularly in Jubilee South East, and in TEN, where we just completed gas injection to support production. Future improvements from TEN will stem from drilling additional wells, and we need to balance our drilling activities between Jubilee and TEN as we plan for 2023, with a focus on optimizing production. As for Mauritania and Senegal, our immediate priority is ensuring that Phase 1 is on track for timely production while advancing Phase 2. We have considerable gas resources in Mauritania's Bir Allah and Senegal's Yakaar Teranga. The latter aims to create a domestic gas scheme that replaces diesel with gas, and we are collaborating with BP on the front-end engineering for this project, as well as engaging with the government on its commercial aspects. In Mauritania, our goal is to advance the Bir Allah project, potentially as an export initiative given the lower domestic energy demands. We plan to leverage the technologies and approaches developed for the Tortue project. In a market with sustained long-term gas demand, and considering the low carbon emissions from the gas in Mauritania and Senegal, we are focused on facilitating the development of these resources. I am optimistic about our progress in both areas, as we have significant resources to develop that meet future gas needs.

Our final question is from Matthew Smith with Bank of America.

Yes, hi there. Andy and Neal, thanks for taking the question; just one to finish off, and that was just whether you were looking into revenue sharing and toll on your cargoes in Ghana, in particular, because it does seem as though the market sometimes struggles to assess the underlying sort of free cash flow, or earnings potential of the company just due to the quarter-on-quarter volatility. And I sometimes feel that the share price reaction is almost a bit inevitable based upon the nature of the quarter. And I think we've had a few questions on this call around the underlying sort of free cash flow potential of the business. So I was just wondering if a revenue sharing agreement is something you're considering at this stage?

Yes. Thanks Matthew. No, that's a good question. It's something obviously we're cognizant of, and actually have been almost exacerbated as production levels in Ghana decreased in the early part of this year. And so increasing the production actually will help even out that issue. So where it should be less of a concern and then, to your point, we are planning to coalesce our own barrels. So in terms of the acquired barrels plus our existing barrels, if we put them together, we will also get rid of some of the regular sort of timing issue. So we'll have much more regular volume going forward. So it is something that we're, yes, attempting to do because I agree, I think it does create a bit of a distraction around some of the quarterly numbers and it will as we look to '22, it does naturally become less of an issue as we're both growing production and actually coalescing our barrels. The ones that we acquired plus our existing barrels help move that out to where we don't have as much variation, yes, in 4Q and beyond.

Since there are no further questions at this time, I will bring the call to a close. Thanks to everyone for joining us today. You may disconnect your line at this time. And thank you for your participation.