Kosmos Energy - Earnings Call - Q1 2025

Executive Summary

• Q1 2025 came in soft versus expectations: revenue of $290.43M and diluted EPS of $(0.23) missed S&P Global consensus of $319.16M and $(0.08), driven by planned shutdowns (Jubilee FPSO, Kodiak), underlift (~1.2 mmboe), and no Q1 cash contribution from GTA sales; free cash flow was $(91.1)M.
• Guidance intact: FY25 production 70–80 mboe/d and CapEx “<$400M” maintained; 2Q25 step-up to 66–72 mboe/d as GTA ramps and maintenance subsides; OpEx $25–27/boe in 2Q and $18–20/boe FY (ex-GTA costs).
• Strategic positives: first LNG cargo at GTA in April; all four FLNG trains operational and being tested ~10% above nameplate; FPSO refinancing targeted in 2H25 to lower phase-1 OpEx; Phase 1+ low-cost brownfield expansion work underway.
• Balance sheet and risk management: RBL redetermination maintained $1.35B facility; ~40% of remaining 2025 oil production hedged with ~$65 floor/~$80 ceiling; net debt $2.85B, liquidity ~$400M.
• Near-term stock catalysts: sustained GTA cargo cadence and cost normalization, Ghana infill drilling (rig arrival May; two Jubilee wells 2025), Winterfell-4 online in 3Q25, and clarity on FPSO refinancing lowering GTA OpEx.

What Went Well and What Went Wrong

• What Went Well

  • GTA reached first LNG cargo in April; second cargo lifting underway; all FLNG trains operational and tested ~10% above nameplate; reservoir performance ahead of expectations (potentially fewer future wells).
  • Cost discipline progressing: Q1 CapEx $86M (below plan on Ghana 4D seismic and Winterfell-4 delay); pushing FY CapEx below prior $400M guide; overhead reduction program advancing.
  • Balance sheet resilience: RBL spring redetermination supported $1.35B facility; rolling hedges increased (~40% of remaining 2025 oil) with $65 floor/$80 ceiling.

• What Went Wrong

  • Earnings miss and negative FCF: revenue $290.43M and EPS $(0.23) below consensus; FCF $(91.1)M as liftings timing, heavy planned maintenance, and no Q1 GTA cash inflow weighed on results.
  • Higher unit costs: OpEx/boe rose to $37.64 (vs $16.42 YoY) on lower volumes and maintenance; ex-GTA OpEx/boe $24.99.
  • GoA operational hiccup: Winterfell-3 remediation unsuccessful; sidetrack under evaluation; production underperformed in 1Q due to Kodiak host shutdown (now completed).

Transcript

Operator (participant)

Good day, everyone. Welcome to Kosmos Energy's First Quarter 2025 Conference Call. 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.

Jamie Buckland (VP of Investor Relations)

Thank you, Operator, and thanks to everyone for joining us today. This morning, we issued our first quarter 2025 earnings release. 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 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, and at this time, I will turn the call over to Andy.

Andy Inglis (Chairman and CEO)

Thanks, Jamie, and good morning and afternoon to everyone. Thank you for joining us today for our first quarter results call. I'll start off the call by reinforcing the messages I gave in February with our full-year results, which apply even more so in today's volatile market. Kosmos continues to focus on prioritizing cash generation, rigorous cost control, and enhancing the financial resilience of the company. I'll then provide an update on the operational progress we've made so far this year and the outlook for the remainder of 2025. Neal will then walk you through the quarter's results and the balance sheet before I wrap up with closing remarks. We'll then open up the call for Q&A. Starting on slide three, while we're seeing heightened volatility in our sector and across global markets more broadly, our priorities remain unchanged.

I talked in detail in February about prioritizing cash generation, and that continues to be our primary focus, and we deliver that through a combination of increasing production and lowering costs. Starting with production, we were pleased to announce the export of the first cargo from the GTA project last month. All four trains on the FLNG vessel are now operational, with daily production ramping up towards the contracted sales volume equivalent to 2.45 million tons of LNG per annum, with potential to go higher. I'll talk more about that on the following slide. In Ghana, we expect the drilling rig to arrive late this month, with two Jubilee wells planned in 2025, which should help deliver production growth in the second half of the year.

The partnership also plans to drill an additional four Jubilee wells in 2026, which should further enhance production with low-cost, high-margin barrels, even in a lower oil price environment. In the Gulf of America, we're currently drilling the fourth infill well, which is expected online in the third quarter. On costs, I talked in February about a material reduction in costs across both capital expenditures and overhead, with the ability to exercise greater control over our CapEx going forward. We expect CapEx to fall by over 50% year-on-year, with evidence of this in Q1, with CapEx of $86 million, $200 million lower than the same quarter last year. We also committed to reduce our annual overhead by $25 million by year-end, and we've already made significant progress against that target through April.

Finally, as we navigate a volatile market backdrop, the important actions taken last year to enhance the financial resilience of the company have put us in good shape for the year ahead. In 2024, we raised new capital, refinanced, and upsized our reserve-based lending facility, which pushed out our average maturity lend. We continue to protect our balance sheet with a rolling hedging program and minimal near-term maturities and ample liquidity. Our portfolio is also made up of assets, particularly on the oil side, with low operating costs and therefore low breakevens. Neal will go into more detail on the actions we're taking later in the presentation, but the activities we have completed leave us the flexibility to maintain the resilience of our balance sheet through the current volatility.

In summary, we're focused on keeping the business in good shape through a period of market uncertainty, with growing production, material cost reduction, and an unchanged priority on cash delivery to pay down debt. Turning to slide four, we achieved several key milestones in Mauritania and Senegal in recent months, with first gas and LNG production in the GTA project, followed by the first LNG cargo. With the export of this first cargo, Mauritania and Senegal have become the latest LNG exporting nations, and Kosmos is proud to become an LNG producer. On the FLNG vessel, all four liquefaction trains are now operational, with production ramping up towards a contracted daily rate equivalent of 2.45 million tons per annum. The second cargo listing is underway, and our full-year gross cargo guidance of 20-25 cargo remains unchanged.

We also expect the first condensate cargo to be exported in the second half of the year. On costs, we're targeting material reductions in both operating costs and our FPSO lease costs. We expect routine operating costs to reduce near-term as the commissioning work naturally comes to an end. In addition, we're working with BP on the FPSO refinancing, which should further reduce OpEx, targeting completion in the second half of the year. Over the medium to longer term, the operator is investigating alternative operating models that could materially reduce costs and enhance the overall returns of the project. We look forward to working with them on this initiative. We see future upside potential in GTA with increased production through the existing facilities and then a potential material step-up in production through some low-cost modifications to those facilities.

The FLNG vessel has a nameplate capacity of 2.7 million tons per annum, and the liquefaction trains are being tested at around 10% above this equivalent nameplate capacity. Next, we'll test the common systems at the maximum rate to get a better picture of where we can safely operate the facility above the contracted sales volume. We're also working with the operator and goal to explore potential upgrades to the FLNG vessel, which could help increase LNG production capacity to beyond three million tons per annum. Initial work suggests this can be achieved with relatively modest upgrades. This would likely be done as part of phase I plus, where work has begun with the project partners to fully leverage the existing infrastructure.

Phase I plus is a low-cost brownfield expansion to potentially double future gas sales with minor modifications to the FPSO, in addition to the upgrades to the FLNG vessel and the provision of additional domestic gas. The performance of the GTA reservoir based on data from the initial production has been positive, which creates the potential to reduce future well counts and CapEx. We'll continue to update the market as we make further progress. Turning to slide five, which looks at operations in Ghana. It's been a busy start to the year in Ghana, where we've completed two major pieces of work. Firstly, the partnership shot a new 4D seismic survey, the first over the field in around eight years, and that data is now being processed using state-of-the-art algorithms.

We believe the enhanced 4D image will greatly improve our reservoir models, and when combined with AI-supported production optimization, will enable a partnership to high-grade future infill drilling campaigns and optimize reservoir management strategies to drive higher field recovery over the life of the asset. The second major piece of work was the scheduled Jubilee FPSO shutdown, which was completed safely and on budget in early April. The work scope should help to sustain high levels of reliability at higher production as we drill new wells in the future. This year, the operator has been delivering good facilities uptime and consistent water injection into the fields necessary to mitigate the natural decline rate. On drilling, the rig is expected to arrive this month with two Jubilee wells planned in 2025.

The partnership then plans to drill four Jubilee wells in 2026, with an option of additional wells if the external environment is supported. Jubilee infill wells provide the highest returns across our portfolio, with full payback typically in months due to the low operating and development costs and high cash margins of the barrels, even in a lower oil price environment. Finally, last month, I had a very productive meeting with President Mahama and the craw to discuss his vision for the future of Ghana's energy sector. We share a very aligned agenda around the importance of investment in the oil and gas sector to support the long-term economic and social development of the country. We look forward to continuing to work with the President and his government to invest in and advance Ghana's energy sector under his leadership.

Turning to slide six, in the Gulf of America, production for the first quarter was in line with expectations and included a planned 30-day shutdown of the facility that hosts the Kodiak field, which has been completed. Our Gulf of America production has ramped back up to around 20,000 barrels of oil equivalent today net. On Winterfell, the workover of the number three well was unsuccessful, and we are currently working with partners to evaluate a future sidetrack to access those reserves. The rig is currently drilling the Winterfell four well, and that is expected online in the third quarter. On Tiberius, where Kosmos is operator, we're making good progress on an improved lower-cost development plan, which will be supported by new Ocean Bottom Node seismic, or OBN, being acquired this year.

We're working closely with Occidental Petroleum, who are 15% partners on the project, and also own the nearby Lucius facility, which we expect would host production from the field. Post-acquisition of the OBN, the farm-out process will continue with the aim of bringing a partner ahead of project sanction. In Equatorial Guinea, production for the quarter was steady at around 9,000 barrels of oil per day net. Post the recent infill drilling campaign, activity is relatively light this year as the partnership focuses on well work to support current production levels. In addition, we're working with the operator to reprocess seismic we have with modern technology to high-grade the future infill drilling potential. There's a lot of opportunity in EG, so the key is making sure we have the best understanding of the subsurface before our next drilling program. Neal will now take you through the financials.

Neal Shah (CFO)

Thanks, Andy.

Turning now to slide seven, which looks at the quarter in detail. Production for the first quarter was impacted by a number of one-offs. We had heavy scheduled maintenance, as communicated in February, primarily driven by the Jubilee and Kodiak shutdowns, which led to a large underlift in one Q. Entitlement production did come in slightly lower than guidance, primarily due to the timing of the GTA ramp-up. As Andy talked about earlier, the GTA ramp-up has progressed in April, and our full-year GTA cargo guidance is unchanged. two Q production guidance reflects this GTA ramp-up, with production in the second quarter expected to be around 15% higher than the first quarter at the midpoint of our guidance.

OpEx per barrel of oil equivalent was in line with guidance, but higher year-on-year, reflecting the lower production and higher maintenance in one Q 2025, including a construction support vessel at Jubilee prior to and during the scheduled shutdown and the Winterfell three workover. The biggest change was CapEx, which is materially lower year-on-year, in line with our commitment to deliver capital for the year of $400 million or lower. G&A, exploration, and interest expense were also all down year-on-year. Tax was lower year-on-year, primarily reflecting lower commodity prices. As you'll see in the appendix, we have put in our updated guidance. Full-year guidance has not changed. However, I want to point out a couple of items related to two Q. The increase in two Q OpEx is a function of our 110 cargo being lifted this quarter.

Higher CapEx in two Q is a function of some activity moving to two Q from one Q and commencing the drilling activity in Ghana and the Gulf of America. Turning to slide eight, as Andy touched on earlier, 2024 was an important year of financing activity to position us well for the future. Last year, we refinanced and upsized the reserve-based lending facility, and we have recently concluded the spring redetermination with our banks. That process went well with the borrowing base well in excess of the current facility size, with the banks using a long-term price deck below the current strip. Importantly, this borrowing base excludes any value for our GTA and Gulf of America assets, which could be used to access financing in the future. We continue to actively manage all the levers we have to maximize cash generation to repay debt, including our 2026 maturity.

As part of that effort, post-quarter end, we continued our rolling hedging program, adding a further two million barrels. We now have around 40% of remaining 2025 oil production hedged, with a floor of approximately $65 per barrel and a ceiling of approximately $80 per barrel. In addition, as I mentioned on the previous slide, first quarter CapEx this year was materially lower year-on-year, as can be seen on the chart on the bottom right, and we are working to reduce full-year CapEx further from the $400 million we communicated at our full-year results. Going into next year, we have minimal capital committed, which provides us a lot of flexibility to further manage our activity set. While the environment is volatile, we continue to be active in managing our options to maintain our financial resilience. With that, I'll hand it back to Andy.

Andy Inglis (Chairman and CEO)

Thanks, Neal.

Turning now to slide nine to conclude today's presentation. Our focus on cash generation and cost discipline remains unchanged, is even more important given the current market volatility. Production is rising as we ramp up GTA, and the near-term drilling in Ghana and the Gulf of America expected to lead to further production gains in the second half of the year. We're prioritizing cash generation through the rigorous cost and capital discipline we've outlined in today's materials. We have assets with low-grade deals that generate cash in a low commodity price environment, and the long-term value proposition of the company is underpinned by a 2P reserve production life of over 20 years. Thank you, and now I'd like to turn the call over to the operator to open the session for questions.

Operator (participant)

Thank you. We will now be conducting a question and answer session.

If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star two 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. One moment, please, while we poll for your questions. Our first questions come from the line of David Round with Stifel. Please proceed with your questions.

David Round (E and P Analyst)

Great. Thanks. Thanks, guys. A couple from me, please. Firstly, just on the nameplate capacity test at GTA, can you talk about the timeframe there for actually understanding the potential rates and what do you actually need to see to have confidence that the higher rates might be sustainable there?

The second one, just in your presentation, you talk about break-evens a few times, so interested if you can talk about where you see your break-evens today and potentially how those might evolve in future years.

Andy Inglis (Chairman and CEO)

Yeah. Hey, David. Yeah. No, thanks for those two questions. In terms of the nameplate capacity, as I said in the remarks, the nameplate capacity of the FLNG vessel is 2.7 million tons per annum. The process of getting to that level and beyond is testing each of the trains individually, and we're going through that process now, and we've tested several, and they're sort of coming in at around 10% higher, which is typical. Work's ongoing then to test the overall system, and then that'll give us the rate that we can deliver reliably, safely above that 2.7.

That's the first step, and I think that work's sort of going to go on through the second quarter. Yeah. Then beyond that, once we know we're at that level, the objective then will be to deliver reliably at that, and therefore you have the option of additional volumes above the ACQ of 2.45. That's the process. There's sort of nothing unusual here. I think if you look at LNG facilities around the world, they typically operate at about 10% higher than nameplate, and that's what we're seeing on the FLNG vessel at GTA. Moving to your second question on the break-evens, I think, look, at oil prices around current levels, for the remainder of the year as a whole, we expect to be free cash flow positive, and we'd obviously use that free cash flow to pay down debt.

As you look sort of forward beyond where we are today, we've got a ramp-up in volume in the second half of the year and into 2026 as we expect productions to rise, obviously, with the ramp-up of GTA that I've just talked about, and then with Jubilee drilling, which should commence shortly. Again, as we've talked about today, we've been pretty clear about our focus on cost control, which is bringing down CapEx, reducing the overhead, and I think as we showed with the first quarter CapEx, we're making good progress on that. We haven't given CapEx guidance for 2026, but in a low-priced environment, Neal talked about the minimal committed CapEx we have for 2026, which is really just the four well Jubilee program.

If you have that plus maintenance CapEx across the rest of the portfolio, we get to a target break-even of around $50 per barrel Brent. In that scenario, you still see production growth year-on-year 2025 to 2026, but we would be deferring future growth projects in that lower price environment. The thing about that is in that scenario, I think probably around 85% of the lion's share of capital is going into the Jubilee infill wells, which again, as we said in the remarks, are our highest return projects, and they've got a very low break-even, probably on a project basis around $30 a barrel. Even in a low-price world, those are things that are going to be adding value for the company.

I think you just want to make sure I have sort of communicated two things: your sense of where that break-even would be going forward, where the capital would be allocated, and our ability to manage in that lower-price world.

David Round (E and P Analyst)

Okay. That is very clear. Thanks, Andy. Great. Thanks, David.

Operator (participant)

Thank you. Our next question has come from the line of Lydia Gould with Goldman Sachs. Please proceed with your questions.

Lydia Gould (Global Investment Research Analyst)

Good morning. Thanks for taking my question. My question is around credit and the balance sheet. How are you thinking about financial leverage in a lower commodity price environment and liquidity in those circumstances? Would love your perspective on how you are thinking about the 1.5 times leverage target as well.

Andy Inglis (Chairman and CEO)

Yeah. Thanks, Lydia. I will pass the question across to Neal.

Neal Shah (CFO)

Yeah. Hi, Lydia.

I would say, again, I think our focus on sort of reducing financial leverage and maintaining sufficient liquidity for the business has not changed. The direction of travel for us is to continue to generate free cash, which, as Andy just commented, we can generate at an oil price around this price at the current price level and use that to pay down debt. As a result of that, leverage will come down over time. The pace really changes based on the oil price, but again, that's something outside of our control. We have taken the steps to both increase production and lower the capital expenses and operating expenses that are sort of conducive to that environment. I would say in addition to that, we talked a bit about hedging on the call.

That's another tool that we're actively using to protect, insulate the cash flow from the business. If I hit your second part of the question around sort of liquidity, yeah, again, I'd still say we've got questions around sort of the debt maturities in 2026 and 2027. We did a lot of work last year to sort of manage those maturities down. We'd still anticipate paying the bulk of the outstanding 2026 notes with cash flow generated from the business. If oil prices move lower or stay lower for a sort of extended period of time, we have clearly other options in terms of leaning into existing liquidity as well as accessing financing on some of our unencumbered assets.

The Gulf of America assets and our assets in Mauritania Senegal clearly do not have any debt, and they provide us some flexibility if we want to go raise cost-effective secured financing against those assets. We have a lot of levers that we can manage if the environment gets worse.

Lydia Gould (Global Investment Research Analyst)

Thanks, team.

Neal Shah (CFO)

Great. Thanks, Lydia.

Operator (participant)

Thank you. Our next question has come from the line of Bob Brackett with Bernstein Research. Please proceed with your questions.

Bob Brackett (Head)

Good morning. This might be a stretch, but if I talk about Tiberius and I see you are looking at a lower-cost development plan with new OBN seismic data, and if I compare that to some of the department of interior studies around co-mingled production or higher drawdown production, how do you think about the evolving policy in the Gulf of Mexico, and is that driving anything that you are doing there?

Andy Inglis (Chairman and CEO)

Yeah.

No, interesting question, Bob. Yeah. I'd say there's nothing specific today that is changing our plans. Yeah. It remains, I think, a basin where we see the ability to conduct business. It's a basin where we can leverage technology. I think over half of the seismic in the Gulf of Mexico now is OBN, and that provides us with, we think, a much-enhanced image and therefore the ability to de-risk and optimize the development. A piece of the optimization is the leverage of that OBN, and then a piece of it is actually work that we're doing with Oxy, who are our co-partner there, 50/50, but it's tied back to Lucius. That's our objective. The ability then to figure out how you fully optimize the existing infrastructure on Lucius.

I don't think for Tiberius in the Pacific, there's been something that the Department of Interior has done, which is making a big change for us. This is work that we have going for some time now, and for me, it's more about the ability to leverage the technology, the pace at which that's evolving, and then I would say just good, honest engineering to take out cost. I think those are the things.

Bob Brackett (Head)

Very clear. Thanks.

Andy Inglis (Chairman and CEO)

Thanks, Bob.

Operator (participant)

Thank you. Our next question has come from the line of Matt Smith with Bank of America. Please proceed with your questions.

Matt Smith (Data Support Manager)

Hi there, Andy. Hi, Neal. I guess my questions were really around, in the current price environment, the current oil prices, would you be comfortable deploying that growth CapEx on the Tortue expansions that you referenced earlier, specifically, I think, the phase I plus?

Would you be willing to deploy that growth CapEx at the current oil price? Was really the first question. The second question related was, are you considering in any greater way sort of monetizing part of your stakes in Senegal, Mauritania at the moment, whether that be Tortue itself or the peripheral discoveries as well?

Andy Inglis (Chairman and CEO)

Yeah. Good questions, Matt. Look, it's a tough one to answer because it obviously depends on what the price is, right? I think we've been very clear on the call today about our ability to manage it. In a lower-priced environment, it is about the committed CapEx, and that's the scenario I talked about when David asked the original question. I think going forward, we would say that the growth CapEx on phase I plus is not committed today, and therefore we have the option around the pace.

I think that's the important thing around the resource there is that it's not an option we're going to lose. It's about the pace of the development, and it's therefore about ensuring that we're doing it in a way which doesn't interfere with the overall financial resilience of the company. I feel good about the fact that we have greater clarity now, I think, on what that option is. I think we have greater alignment with ourselves, BP, and the national oil companies. I think really strong alignment now, and the work that we're doing now is at the front end. It's very low CapEx allowing us over the next 12-18 months to understand the engineering and make sure that we've got the right basis on which to proceed.

It's a really low-cost spend initially, and clearly, you'll monitor that progress and therefore decide when you would move into a higher CapEx spend. Look, and then in terms of monetization, I know there's value being added to GTA as we speak. We're ramping up. We're demonstrating the field is working. We've got optionality. I think I'm moving beyond the ACQ. I think there's work to be done, Matt, to make sure that we fully describe the full potential of GTA before we start to think about any dilution. Nothing's sacred. Everything ultimately in the portfolio has a value. What we need to do is make sure that we're in the point of the cycle where we've properly described the value. I feel good about the subsurface. We talked about that in the remarks.

I think that the initial production data we're getting now is very positive, so that's a good sign. I think we need to demonstrate that the facility has greater potential than what is currently described in terms of the offtake and therefore building that into future models. I think we're a little ways away from that, but it's something that we're working towards getting ourselves to the place where we've fully described the potential of GTA.

Matt Smith (Data Support Manager)

Okay. Great. Thank you, Andy. Happy to pass it on.

Operator (participant)

Great. Thank you.

Thank you. Our next question has come from the line of Stella Cridge with Barclays. Please proceed with your questions.

Stella Cridge (Head of Eemea Corporation Credit Research)

Hi there. Afternoon, everyone. Many thanks for all the updates. There was a couple of areas I wanted to ask on. The first, you talked about recent meeting in Ghana and engaging positively there.

I noted recently Tullow on their call talked about potential multiple future rounds of investment in Ghana. I just wondered, what were your takeaways from those discussions? Are there any kind of key action points in the near term with regarding the partnership there over the longer term? That was the first one. The second one was that I noted that there was a cash outflow from notes receivable in Q1. I just wondered, will there be any more outflows from receivables, or could potentially there be any inflows from Senegal, Mauritania in the future? That would be great.

Andy Inglis (Chairman and CEO)

Yeah. Thanks, Stella. I'll ask Neal to pick up the question around the cash outflow.

Ghana has been there a long time. We've seen, obviously, multiple governments. For me, it was great to meet President Mahama again.

He was clearly there in power eight years ago, and it was an opportunity to connect with him and sort of his view and vision of the industry in Ghana. My big takeaway is that he has a very clear mandate, I think, to re-energize the sector. There is, I think, a lot of potential remaining in the basin, but it's a potential that is actually around sort of near-term activity where you're getting the most out of your existing fields that are on production. I think the big point to take away from it is that I think I've talked on previous calls about the potential that we see in Jubilee, the remaining reserves to be produced. An important element of that is you have an aligned agenda with the government and obviously with the national oil company.

That's what I took away from it, that we have the same aligned agenda. It's a place where Kosmos is welcome. We're embarking on a program now with obviously two wells in 2025, but then four wells in 2026 to ramp up Jubilee production, and then the potential to work and continue to work on enhanced recovery from the field. I think the big message is around the fact that we have a country where we're welcome. We have a long history there, and we have very much an aligned agenda as we look to get maximize both the efficiency and the effectiveness of the recovery, which will benefit both the country and Kosmos's shareholders. I think that's a big message from that. As I say, we're starting on that journey now with the inflow program that we're drilling rig to arrive this quarter.

Maybe if I just pass the call across to Neal just to cover your question about the cash flow.

Neal Shah (CFO)

Yeah. Hi, Stella. I think the question you asked was just around the NOC financing that was in one Q. That is part of the development loan that we put in place with GTA. That comes to a close basically this quarter. In terms of our obligation to finance their sort of development expense. As you noted, then there will be a repayment schedule in terms of then starting to get that cash flow back. Again, in the second half of the year, it would be stopping an outflow.

Then as we deliver the increase in production and reductions in operating expenses, there is capacity for that cash flow to start being repaid back to both us and BP as part of that repayment of the NFC loans. We are sort of near the peak of that in terms of capital expended.

Stella Cridge (Head of Eemea Corporation Credit Research)

That is it for me. Many thanks for the answers.

Andy Inglis (Chairman and CEO)

Great. Thanks, Stella.

Operator (participant)

Thank you. Our next question has come from the line of Nicole Beck with JP Morgan. Please proceed with your questions.

Nicole Beck (Pega Developer)

Morning. I just have one quick one, more of a clarification on your LNG offtake agreement with BP. Could you please remind me if there is any annual quota of volumes or cargoes that you are contracted to sell to BP? Also, could you remind me what is the contracted price again, please? Thanks.

Andy Inglis (Chairman and CEO)

Yeah.

The annual contract quantity is 2.45 million tons per annum, and the price is 0.95 or 9.5% slope against Brent, FOB. Thank you. Does that make sense, Nicole? Yeah. I know that's sort of short machine gun stuff, but that is precisely the answer.

Nicole Beck (Pega Developer)

Thank you.

Operator (participant)

Okay. Our next question comes from the line of Mark Wilson with Jefferies. Please proceed with your questions.

Mark Wilson (Managing Director)

Thank you. And good afternoon, gents. First off, on tour two, just give a bit more color on what is it you've seen with the subsurface performance that you mentioned is ahead of expectations, which sounds good. The second point, I wonder what are the steps to domestic obligation offtake physically with regard to pipeline? And also financially, does that connect to what Neal was just talking about, NOC payback? Do you need that domestic obligation in place?Thanks. Those are my two points.

Andy Inglis (Chairman and CEO)

Yeah.

Yeah. Start looking on the subsurface. You sort of go back in time. Obviously, you understand this, but seismic, you then do, we had three exploration wells, one appraisal well, and we've got four development wells. The four development wells, we did flow back for a short period of time. It's tough on those shorter flowbacks to sort of see where you are getting any connected volumes, yeah? I think the big, as it were, new piece of data we've got is from the flowback from the first two wells, actually, where we're seeing a greater connection in volume than we'd originally mapped.

I think that's very positive, obviously, because as you start to think about the future, therefore, if you have the opportunity to reduce the number of wells you need for a given amount of recovered volume, which again would enhance the returns from the project. In terms of the, and the same question, Mark, just remind me. Domestic gas and the build-out of the infrastructure, yeah? Okay. Yeah. We don't, in essence, yeah, the obligation, just so we're clear on the obligation, the obligation is with the offtaker, which is the national oil company, to build any infrastructure. They're responsible for building the pipeline from the hub terminal, which is the offtake point, to whatever their chosen landing point is. We don't have any capital liability for that. I think that was really the essence of your question, wasn't it?

Mark Wilson (Managing Director)

Yes, it is.

Obviously, until they do that, you,

Andy Inglis (Chairman and CEO)

I guess, can sell at nameplate prices.

Mark Wilson (Managing Director)

You have more gas to sell,

Andy Inglis (Chairman and CEO)

yeah. Exactly. You have more gas to sell, yeah. I do not think there is a, if you think about the limits of the system, the FPSO, all right, and then its associated infrastructure can do well more than three million tons per annum, yeah? In terms of delivering LNG, the constraint is the capacity of the facility itself. If it is at its full capacity and that number is beyond the 2.7 million tons per annum, there is still gas available for domestic. We are not, it is not about sort of one being exchanged for the other. There is plenty of capacity in the system.

Mark Wilson (Managing Director)

Absolutely. It makes sense. Thank you. I will hand that over.

All right. Good. Thanks, Mark. Thank you.

Andy Inglis (Chairman and CEO)

Since there are no further questions at this time, I would like to bring the call to a close. Thanks to everyone for joining today. You may now disconnect your lines, and thank you for your participation.