Image source: The Motley Fool.

Kosmos Energy (KOS) Q2 2025 Earnings Call Transcript

DATE

Monday, Aug. 4, 2025 at 3:00 p.m. ET

Call participants

Chairman and Chief Executive Officer — Andrew G. Inglis

Chief Financial Officer — Neal D. Shah

Need a quote from one of our analysts? Email [email protected]

Risks

Jubilee gross production averaged 55,000 barrels of oil per day, which was described as "lower than expected" for the second quarter of 2025 due to a combination of a nine-day planned FPSO shutdown, riser instability post-restart, and well underperformance on the eastern side.

Production in Equatorial Guinea fell below expectation because of subsea pump mechanical failures at Sabre, requiring installation of replacement pumps in the fourth quarter before recovery is anticipated.

Quarterly production came in below guidance, attributed primarily to delayed GTA ramp-up and weak performance at Jubilee during the reporting period.

Takeaways

GTA FLNG commercial operations date— Achieved in late June, marking full operational status and ending Kosmos Energy's requirement to fund NOC capital expenditures for the project.

GTA LNG production— 6.5 gross cargoes lifted year-to-date through the second quarter of 2025, targeting an annual nameplate capacity of 2.7 million tonnes for the GTA FLNG project with a full-year guidance of 20 gross cargoes.

Jubilee drilling restart— First producer well online, delivering initial gross output of approximately 10,000 barrels of oil per day from the first well of the 2025-2026 Jubilee drilling program; a second producer is expected online by year-end, with four additional wells in 2026.

Production metrics— Net production at GTA exceeded 7,000 barrels of oil equivalent per day in the second quarter of 2025; Ghana net production reached 29,100 barrels of oil equivalent per day; net Gulf of America production was 19,600 barrels of oil equivalent per day; Equatorial Guinea net production fell just under 8,000 barrels of oil per day.

Capital expenditures reduction— Capital expenditures for 2025 were revised downward to approximately $350 million from $400 million, supported by actuals in the first half as longer-term projects are slowed.

OpEx and cost initiatives— GTA operational expenditures per BOE are declining as ramp-up continues; $25 million in targeted savings are on track to be delivered by the end of 2025, with the full benefit expected in 2026 and beyond.

Financing actions— Indicative terms have been agreed for a $250 million term loan secured by Gulf of America assets, intended for 2026 bond repayment; further financing initiatives underway for longer-dated maturities.

Hedging strategy— 7 million barrels of 2026 oil production are now hedged (floor $66, ceiling $75 per barrel), with the intent to cover around 50% of 2026 production by the end of 2025.

RBL covenant— Waiver obtained on debt cover ratio covenant, in effect until March 2026, reflecting the GTA ramp-up impact on leverage metrics.

Jubilee license extension— Memorandum of understanding signed with Ghana government to extend field licenses to 2040, with an undertaking to drill up to 20 wells and a volume uplift of 130 million standard cubic feet per day, as committed in the license extension MOU for the Jubilee field with a discounted gas price; no change to broader fiscal terms.

Winterfell well— Fourth well drilled and expected online late in the third quarter, with anticipated net contribution to Kosmos Energy of 1,000 barrels of oil equivalent per day from the Winterfell #4 well, expected online in late third quarter 2025.

GTA condensate sales— First condensate cargo expected late in the third quarter, providing a new revenue stream for the project.

Unit cost trajectory— GTA start-up and commissioning costs are expected to decline in the second half of 2025; refinancing of FPSO and operating model evaluations aim to lower long-term unit costs further.

Production outlook— Additional Jubilee and Winterfell wells, along with Sabre pump replacements and GTA ramp-up, are expected to drive sequential production increases into 2026.

Summary

Kosmos Energy(KOS 1.67%) achieved a major milestone with the GTA FLNG commencing commercial operations in June 2025, positioning the company to shift from investment mode to a period of rising production and cost reduction. Management reported a significant reduction in capital expenditures for 2025, lowering the full-year forecast from around $400 million to around $350 million, along with an active hedging strategy and a liquidity initiative through a $250 million term loan announced in the second quarter of 2025. License extensions and drilling in Jubilee, operational progress in Gulf of America, and mitigation measures in Equatorial Guinea formed the core of near-term and long-term portfolio development updates.

Andy Inglis said, "we're making good progress against our financial objectives," signaling confidence in the ongoing execution of cost, production, and balance sheet initiatives.

Neal Shah confirmed that reduced capital expenditures and the wind-down of associated funding, combined with current production levels, enable Kosmos Energy to generate free cash flow at prevailing oil prices as of the second quarter of 2025.

The company expects continued quarter-over-quarter production growth through 2026, driven by the addition of new wells and asset optimizations.

Hedging positions are being expanded for 2026, with 7 million barrels of oil now hedged and a target to hedge around 50% of 2026 production by year-end, aiming to mitigate volatility and underpin cash flow stability despite commodity price swings.

The partnership is prioritizing future expansion at GTA via brownfield investment and working toward further operating cost efficiencies, with new domestic gas and LNG opportunities dependent on contractual clarity and government alignment.

Industry glossary

FLNG (Floating Liquefied Natural Gas): A vessel-based facility that enables the production, liquefaction, and shipment of natural gas offshore from remote fields.

FPSO (Floating Production, Storage, and Offloading Vessel): A ship used to process and store hydrocarbons produced offshore before offloading to a tanker.

NAS (Narrow Azimuth Seismic): A specific 4D seismic imaging technique enabling enhanced subsurface resolution for precise field development and well targeting.

OBN (Ocean Bottom Node Seismic): Seismic acquisition technology that collects subsurface data using nodes placed on the seafloor, facilitating improved imaging and reservoir modeling.

RBL (Reserve-Based Lending): A credit facility structured around the value of a borrower's oil and gas reserves.

TCF (Trillion Cubic Feet): A measurement unit denoting the volume of natural gas resources.

FID (Final Investment Decision): The point at which project partners approve moving forward with full development and spending commitments.

2P reserves: The sum of proven and probable hydrocarbon reserves assessed as recoverable under current economic and operational conditions.

Full Conference Call Transcript

Andy Inglis: Thanks, Jamie, and good morning and afternoon to everyone. Thank you for joining us today for our second quarter results call. I'll start off the call by talking about Kosmos' priorities, reinforcing the key messages I gave last quarter before updating you on progress across the portfolio. Neal will then walk through the financials and the work we've been doing to enhance the resilience of the balance sheet before I wrap up with closing remarks. We'll then open up the call for Q&A. Starting on slide three, as we navigate the ongoing commodity price volatility, our key priorities have not changed.

Last quarter, I talked about growing production and reducing costs to prioritize free cash flow while continuing to strengthen our balance sheet. I'm pleased to say we've made good progress this quarter across each of these areas. Starting with production, in June, we announced the Gimi floating LNG vessel had achieved commercial operations date, or COD, a key milestone for the GTA project. COD is achieved when LNG production is 10 for a period of 72 hours at the annual contracted rate around 2,450,000 tonnes per annum equivalent. The FLNG has a nameplate capacity around 2,700,000 tonnes per annum, and we're targeting reaching that level in the 6.5 gross cargoes year to date.

In Ghana, we're pleased that drilling on Jubilee has restarted with the first producer well of the 2025-2026 drilling program now online. Initial gross production from the well is around 10,000 barrels of oil per day, in line with our expectations. We have also optimized the drilling program by accelerating the scheduled rig maintenance of 3Q, which allows us to drill a second producer this year, replacing a previously planned injector. This planned producer well is expected to add further Jubilee production around the end of the year, ahead of four more wells planned in 2026. I'll talk about that alongside two few Jubilee production later in the material.

In the Gulf Of America, the partnership has drilled the Winterfell four well with completion operations underway. The well is expected online around the end of the quarter. We are now approaching Kosmos record high production levels with further near-term growth expected as we push GTA towards the FLNG nameplate capacity and bring on more wells at Jubilee and Winterfell.

Neal Shah: Moving to cost. We focused on three areas and are making good progress across all three. Firstly, on CapEx. CapEx in 2025 was around $170 million, down around 65% from 2024 as we come out of a heavy investment period and start to see the benefits of those investments. With a sharp focus on CapEx in 2025, we've reduced our full-year CapEx forecast from around $400 million to around $350 million, with the first half actual supporting this lower forecast as we've slowed down some longer-term investment. Secondly, on OpEx. The largest opportunity for OpEx reduction is on GTA, and we're seeing OpEx per BOE fall as production ramps up.

We're also targeting the refinancing of the GTA FPSO in the second half of the year. We're working with the operator to explore alternative lower-cost operating models, which could further drive down costs across the project. And thirdly, overhead. We remain on track to deliver $25 million of targeted savings by the end of this year, with the full benefit being seen in 2026 and beyond. And finally, the balance sheet, where we continue to prioritize our financial resilience with a focus on cash flow and debt pay down. On liquidity, we're taking steps to address our upcoming debt maturities.

As part of today's material, we announced we've agreed indicative terms for a term loan of up to $250 million secured against our Gulf Of America assets. We would anticipate using the proceeds to repay our 2026 bond maturity. We're also progressing additional financing activities to fund some of our longer-dated maturities. On hedging, we took advantage of higher prices in late 2Q and early 3Q to hedge more 2026 oil production, with 7 million barrels now hedged in 2026. We're looking to hedge around 50% of 2026 production by the end of this year.

And finally, on the RBL, to reflect the timing impact of GTA ramp-up cost on leverage, we were granted a waiver from our banks on the debt cover ratio covenant through to March 2026. Neal will talk about all of these in more detail later. But in summary, we're making good progress against our financial objectives. Turning to slide four, which looks at operations for the quarter. Starting with the GTA project in Senegal and Mauritania. Second quarter net production was just over 7,000 barrels of oil equivalent per day. The partnership lifted 3.5 gross LNG cargoes as previously communicated. As mentioned on the previous slide, the FLNG commercial operations date was achieved in late June.

This is an important operational and financial milestone for Kosmos, as it signals the end of us funding the NOC's CapEx on the project. In Ghana, total net production was around 29,100 barrels of oil equivalent per day. Jubilee gross production of around 55,000 barrels of oil per day was lower than expected in the second quarter, driven by nine days of planned FPSO shutdown, a period of riser instability following the restart, which has since been addressed, and underperformance of some wells on the eastern side of the field. I'll talk more on the following slides about how the partnership is addressing these issues and the actions being taken to reestablish the full production potential of the field.

As mentioned on the previous slide, the first producer well of the 2025-2026 program was brought online late last month and is performing well. Jubilee gross gas production was around 16,600 barrels of oil equivalent per day in the second quarter.

Andy Inglis: In early June, we announced that we had signed an MOU with the government of Ghana to extend the licenses to 2040. The license extensions are a win-win for the project partners and the government. The partners are now planning long-term investments in the fields to maximize value for all stakeholders. We are working with our partners and the government to finalize the documentation, targeting completion in the second half of the year. When I met with President Muhammad earlier this year, we discussed his desire to reinvigorate the oil and gas sector in Ghana with increased investment in some of the country's most valuable assets. The license extensions on TEN are aligned with that agenda.

At TEN, gross oil production in the quarter was just under 60,000 barrels of oil per day. In the Gulf Of America, net production was around 19,600 barrels of oil equivalent per day, at the upper end of guidance, driven by strong performance from the Kodiak and Odd Job fields. At Winterfell, the partnership has drilled a number four well with completion operations underway, and the well is expected online later this quarter. On Tiberias, we continue to advance the development with our fifty-fifty partner Oxy, with FID targeted next year. In Equatorial Guinea, net production was just under 8,000 barrels of oil per day, lower than expectation due to some subsea pump mechanical failures at Sabre.

The operator expects the first replacement pump to be installed in the fourth quarter, with production expected to rise thereafter. Turning to slide five. At GTA, we continue to see a lot of positive progress with the project now fully operational. Year to date, we've lifted 6.5 gross cargoes, and the cadence of cargo listings is increasing as production ramps up. Further progress is expected, with production expected to rise towards nameplate capacity of 2,700,000 tons per annum in the fourth quarter. Production of the project is expected to fluctuate slightly with seasonal temperatures, with higher production expected during the winter months when the air and sea temperatures are cooler.

Full-year guidance of 20 gross cargoes reflects slightly slower production ramp-up that we saw in the second quarter and early third quarter. Importantly, the subsurface is performing well, which is a key factor as we plan future expansion phases. As a reminder, there is around 25 TCF of discovered gas in place at GTA. Phase one only requires around three TCF for twenty years of production at the contracted rate. This is a world-class gas resource with significant running room. The partnership also expects the first condensate cargo late in the third quarter, a meaningful additional revenue stream for the project.

On operating costs, both start-up and commissioning costs should start to fall away in the second half of the year. We're also progressing the refinancing of the FPSO lease, targeting completion in the second half of the year. Additionally, the partners are working with the operators to explore alternative lower-cost operating models to drive down costs further. As we look out with phase one now fully operational, the next major opportunity to enhance value is through future expansion. Phase one plus, a low-cost brownfield expansion, leverages the existing phase one infrastructure to enable gas production to double at a fraction of the cost to increase LNG production and domestic gas to our host countries.

During an official visit to the US in July, the presidents of Senegal and Mauritania met with President Trump at the White House. President Fei of Senegal spoke positively to President Trump about Kosmos and our critical role in discovering the GTA field ten years ago. He also talked about the importance to Senegal of US investment from companies like Kosmos and the joint opportunities that could be created through investment in sectors core to the country's economic growth, such as natural gas. The videos of the meetings are online and worth watching. Turning to slide six. 2025 is an important year for our operations in Ghana. We return to drilling.

The timeline on the slide shows the journey we are on to deliver the full potential of Jubilee Field. The 2024 marked the end of the previous three-year drilling campaign, which was done using 4D seismic shot in 2017. At the end of that drilling campaign, Jubilee production peaked above 100,000 barrels of oil per day. In the second half of the year, we saw the start of a twelve-month drilling hiatus resulting in some expected natural decline of the field, which was exacerbated by facility issues that we talked about in detail last year, namely reliability of water injection and power generation.

In 2025, the partnership carried out a significant facilities work scope on the FPSO during the scheduled shutdown. While Vonage replacement for the first half of the year has been above 100%, production declines have been higher than anticipated in certain wells on the eastern side of the field, including Jubilee Southeast. Riser-based gas lift was introduced to the eastern side of the field, which has helped to restore and stabilize production, and plans are in place to do the same on the western side of the field in the future.

In early 2025, we acquired new 4D across the field, the first since 2017, to ensure the next set of wells we drilled in Jubilee are the best targets derisked with the best data and technology. A key event in the second quarter was the arrival of the rig to commence the 2025-2026 drilling campaign. In July, we brought the first new well online in over a year, a producer in the 10,000 barrels of oil a day. The 2025 rig program has been optimized to drill a second producer well in the Jubilee main field following a period of scheduled rig maintenance. The second producer well is expected online around the end of the year.

We're excited to see the enhanced imaging of the fast-track 4D seismic data now coming through, which we plan to further improve using Ocean Bottom Node Seismic, or OBN, which we expect to acquire later in the year. I'll talk more about that on the following slide. As we look forward to next year and beyond, we're back to a more regular drilling cadence with four wells committed in 2026, which will start to benefit from the new seismic. Turning to slide seven. I want to spend some time on this slide talking about the importance of consistent drilling and how the Partnership is planning to use the latest technologies to deliver the full potential of Jubilee.

Using cutting-edge seismic technology to enhance resource recovery in midlife fields is a growing theme across the industry, with recent communications from some of the majors highlighting the significant role they expect it to play over the coming years. The 4D narrow azimuth seismic, or NAS, shot in the first quarter of the year was the first seismic acquired over the field since 2017. This new seismic data processed with the latest technologies is generating a better understanding of the subsurface through enhanced imaging, which is helping to identify new undrilled lobes and unswept oil.

As can be seen on the slide, the modern NAS data on the bottom right shows much greater definition of existing reservoirs and yields an improved understanding of fluid movements over time compared to the legacy seismic in the top right. Improved imaging of the new data also provides greater visibility and understanding of deeper potential. At Kosmos, we've taken the lead in coupling this modern seismic with new AI-enhanced data interpretation and reservoir modeling to maximize recovery. As mentioned on the previous slide, we're planning to acquire OBN data over the field later in the year, which will enhance the velocity model to further uplift the NAS processing.

The velocity model inserts to the two images on the slide show the evolution and improvement in clarity from 2017 to the present day, and we think there's more to go with OBN data. The second message on the slide I want to focus on is drilling. We talked at length in the past about the need for regular drilling on Jubilee. A key part of delivering the field's potential alongside high facility uptime and sustained water injection. As I mentioned, the 2025-2026 drilling program is now underway with the first Jubilee producer, J72, online and a second Jubilee main field producer expected online around the end of the year.

Following completion of that well, the rig is scheduled to drill four wells in Jubilee in 2026, targeting well-defined main field producers supported by good adjacent well control similar to J72. Going forward, we expect three to four wells per year will be needed to maximize the field's full potential over a multi-year period and sustain higher production levels. With the license extension MOU, the partnership can now plan on long-term investment in Jubilee, which should also drive a material uplift in 2P reserves. In summary, Jubilee is a big field that we expect will get bigger through regular drilling supported by new imaging and reservoir management technology. Turning to slide eight.

The Gulf Of America second quarter performance was good, with production at the upper end of guidance helped by strong output from both Oddjob and Kodiak. At Winterfell, the number four well was drilled in the second quarter and is anticipated to come online late 3Q. The well is expected to contribute a net rate to Kosmos of around 1,000 barrels of oil equivalent per day. On our development activity, we, together with Oxy, are continuing to progress Tiberias, an outboard Wilcox discovery working on improved lower-cost development plans supported by new OBN seismic that we expect to acquire later in the year. FID would then be targeted for next year.

Gettysburg is a discovered resource opportunity we acquired in their previous lease sale in the Norfolk trend. To advance the project, we brought in Shell as a 75% partner and operator and are working alongside them in a joint team to progress a low-cost single well development that would be tied back to Shell's operated Appomattox platform. That concludes the review of the portfolio. And Neal will now take you through the financials.

Neal Shah: Thanks, Andy. Turning now to slide nine, which looks at the quarter in detail. Production was higher sequentially due to GTA coming on and strong performance in the Gulf Of America, partly offset by lower production in Jubilee and Equatorial Guinea. Production did come in lower than guidance, mainly due to the ramp-up timing on GTA, which we communicated in June, and lower Jubilee production in the quarter. With GTA ramped up and the first Jubilee well online in July, current production is approaching record highs as Andy previously mentioned.

With additional wells at Jubilee and Winterfell, the installation of replacement pumps at Sabre, and ramp-up further of GTA targeting the FLNG nameplate capacity, we expect production to continue to rise quarter over quarter into 2026. OpEx per BOE, as shown on the slide excluding GTA, was higher in the quarter, largely reflecting the 110 lifting we expect this year since 10 operating costs are booked in the quarter the cargo is lifted. G&A was lower as we start to see the impact of some of the overhead savings coming through. And finally, CapEx came in under budget due to the timing of activity in the Gulf Of America and lower GTA costs in the quarter.

As Andy discussed earlier, we have lowered our full-year CapEx guidance to approximately $350 million from $400 million, and with 1Q and 2Q CapEx demonstrating we are on track to achieve that lower amount, which we believe is sustainable into 2026. With our CapEx and NFC funding winding down and production increasing, at current oil prices, we are generating free cash flow. While the timing has been slightly delayed, we remain focused on maximizing cash flow in the near term and reducing the absolute amount of net debt.

I also want to mention that while working capital is difficult to predict on a quarterly basis, we do expect a working capital draw in the third quarter to reflect the timing of some payments. Turning to slide 10. As Andy said in his opening remarks, one of the priorities for the company this year is enhancing the resilience of the balance sheet, and we've made progress in several key areas recently. On liquidity, we have agreed indicative terms for a senior secured term loan with an investment-grade counterparty at a cost similar to our existing RBL for up to $250 million, which we would use to repay the outstanding 2026 unsecured notes.

This facility would be secured against our assets in the Gulf Of America, with a final maturity date four years after closing, which is anticipated by the end of the third quarter. The chart on the right shows the pro forma impact of this transaction on our maturity schedule, assuming we fully draw down on the new facility to repay the outstanding 2026 note. Through the second half of this year, we plan to continue working on accessing additional attractive sources of liquidity to potentially repay some of our other longer-dated maturities. On hedging, we continue to add additional protection against commodity price downside through the back half of the year into 2026.

For the remainder of 2025, we have 5 million barrels of oil production hedged, with a $62 per barrel floor and a $77 per barrel ceiling. We also took advantage of higher prices in late 2Q and early 3Q to add more hedges for 2026. We now have 7 million barrels of oil hedged next year, with a floor of $66 per barrel and a ceiling of $75 per barrel. On CapEx, I talked on the previous slide about reducing full-year guidance to approximately $350 million from $400 million. The chart on the bottom right shows the material drop in quarterly CapEx from last year, with lower levels of CapEx expected to continue as we prioritize free cash flow.

Finally, we worked with our banks to amend the debt cover ratio calculation for the RBL, increasing the ratio for the next two scheduled test dates to reflect the timing impact of the start-up of the GTA project on the backward-looking leverage calculation. The debt cover ratio will return to the original agreed level thereafter when full-year revenues from the GTA project are better aligned with operating expenses. So in summary, we remain proactive on improving the balance sheet, raising liquidity, increasing hedging, and reducing cost. And we'll continue to update the market as we make further progress in the second half of this year. With that, I'll hand it back to Andy.

Andy Inglis: Thanks, Neal. Turning now to slide 11 to conclude today's presentation. As I stated in my opening remarks, our near-term focus is on growing production, reducing costs, and enhancing the resilience of the balance sheet. We're making good progress in all three areas. As we look beyond the near term, there's significant scope to add long-term value for our investors through high-quality production and development opportunities across the portfolio. On GTA, with the first phase now fully operational, we are focusing our efforts towards reducing cost and doubling production to further drive down unit costs through advancing the low-cost brownfield expansion that leverages the existing infrastructure.

In Ghana, Jubilee is a big midlife field with significant reserves yet to be produced, which can be accessed by consistent drilling enabled by new technology and the license extension. The Gulf Of America, a proven basin with significant running room, we continue to advance an attractive portfolio of infrastructure-led exploration and development options in the outboard Wilcox and Norfolk trends that leverage Kosmos' capability. In Equatorial Guinea, our assets should deliver cash flow as we selectively invest in production optimization opportunities. So in summary, Kosmos has a diverse differentiated portfolio with a 2P reserves to production life of over twenty years, with considerable discovered resource beyond that.

The conversion of this discovered resource into high-value reserves and then into production will be done at the right pace in a capital-efficient manner, prioritizing cash flow and the balance sheet in the near term. We look forward to delivering on these near-term objectives, which will support long-term value creation for our investors. Thank you. And I'd now like to turn the call over to the operator to open the session for questions.

Operator: Thank you. Star one on your telephone keypad. A confirmation tone will indicate your line is in the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. Our first question is from Charles Meade with Johnson Rice. Please proceed.

Charles Meade: Yes. Good morning, Andy. Good morning, Neal, and to your whole team there. Andy, I want to ask a question about Jubilee. You've given us a lot of great detail here, and I love all the technical detail. But looking at the story from the top down, you gave us the mention that in the first half of '24, the field was producing over 100,000 barrels. And a year later, you're down to 55 or let's call it 60 adjusted for downtime. So that 40% decline in a year strikes me as high, maybe anomalously high, but if I look at it from a different way and say, okay.

Well, you need to drill four new producers every year to keep the field flat. And if those producers come in like your latest one, maybe that 40% annual decline is the slope you're fighting every year. So I wonder if you could comment on whether that's a valid way of looking at it and what you'd add to that picture.

Andy Inglis: Yeah. Thanks, Charles. Look, you know, it's a really, really good question. I think when you look at it from the top down, I think you're rightly sort of focused on where we are in 2Q. Not only was the shutdown a little challenge, but we did have the additional issues of the riser instability, which we've ironed out. So you sort of have to look into 2Q in the right context. But it was also impacted, I think, by higher than expected decline, certainly in some of the wells on the Eastern side of the field, in particular, Jubilee Southeast. So you go, okay. Well, what are we doing about that now?

I think we talked in quite a lot of detail in the prepared section about the impact of two things. One is better data. We're really pleased with the uplift we're seeing from the fast-track data in the NAS. Again, you need to remember this is fast-track, very early product. To me, the uplift is huge in terms of our ability to see better opportunities in the field both from under a load and unswept oil. So you're starting to see now a much clearer picture, and I think, you know, we did suffer towards the end of the last drilling campaign from the quality of the data we stated back to 2017.

So you've got much better data and then the ability then to improve it further than ours to the ODN. I think we're going to see a big uplift in the velocity model. So I think the imaging is only going to become clearer. And then as you rightly say, the second part of the story is how do you harness that improved data. You've got to drill regularly. We've said all along that you need to get three to four wells in a year to sort of maintain the production level. So if you sort of take that and sort of track forward, I think we drilled the first of those wells and brought it online last month.

And, you know, we're seeing production rising as a result. You know, we hope to get a second well on around by year-end, and I think that's, you know, can push production up to around 70,000 barrels a day. So the drilling is more than offsetting the underlying decline and leading to growth. And then four more wells in '26, you know, we think they're likely going to be producers. If you think each of those is adding 5,000 to 10,000 barrels a day, you know, you can see your way with the, you know, even with the decline that we're seeing building up towards that sort of 90,000 barrels a day.

So I think that's how you get back to where we need to be. And then you can sort of rinse repeat because you've got quality data and you're starting to deliver a regular consistent drilling program targeting high-quality wells. So, you know, yes, you know, 2Q was lower than expectation, you know, and you've sort of done the maths on that. But I think even when you were sort of, you adjusted for the one-offs that were in there, and then you start to look at the performance we're seeing from some of the wells that we're drilling, you know, you can reestablish the potential of the field. It's going to require the two things we talked about.

It requires good data. I think I'm really pleased with what we're seeing with the NAS, and I think the Fast Track NAS is that it'll only get better with the four products and then the uplift from the OBN. And then back to a regular drilling program.

Charles Meade: Got it. That's great detail, Andy. Thank you. And then on GTA, I think you mentioned in your prepared comments and the slides and also in the press release talking about exploring, you know, different operating models to lower costs. And can you give us a sense of, you know, what they might be or more importantly, what the order of magnitude might be for reducing the cost? And I'm guessing that means an absolute sense, not in a, you know, as a precursor to producing it in a unit basis.

Andy Inglis: You know, absolutely. Yeah. Look. It's I think just sort of remember that, you know, GTA has certainly been a major project for us. The start-up of a major facility such as this is an LNG scheme. You know, always comes. I think the first year is always a challenging period because you're building plateau. You're removing those shutdown and commissioning costs and getting to steady state. I think the first order of business is sort of to deliver that outcome. And get to that sort of plateau. And I think, you know, we got COD in June. I think we're holding at those levels now. And, you know, we're producing at the ACQ.

I think but we know there's more to go when we look at the individual trains and the optimization that can be done. You know, there's absolutely ability to get to nameplate and beyond. So that's part of the journey in the half of the year. Then part of the journey in the second half of the year is getting those projects and start-up costs commissioning costs out of the system and getting to a lower level, which we think will achieve both in the fourth quarter. And then looking beyond that, the conversation with the operator is around a couple of things. We're looking at how we refinance the FPSO in the second half of the year.

That will bring a significant benefit to Kosmos and to the NOCs. And then beyond that is how do you reduce the operating costs even lower? And, you know, that ultimately charges about exploring, you know, sort of all operating models. At the moment, we have a model which is exclusively, you know, BP personnel both on the FPSO and the hub. All the ways in which you can look at models that are employed elsewhere that ultimately get you to a more competitive position. So those are the things that follow next. So I think there's a lot of opportunity to take cost down. And it isn't simply about moving the volume up.

It is fundamentally about attacking the cost base from all of the angles that I've talked about.

Charles Meade: That's helpful detail. Thank you.

Andy Inglis: Great. Thanks, Charles.

Operator: Our next question is from Matt Smith with Bank of America. Please proceed.

Matt Smith: Thanks for all those details so far. Perhaps just have one sort of broad on CapEx. Welcome to see that coming down in the guidance for 2025. I guess my question really is, is that CapEx envelope now well below $400 million around $350 million? Is that a sensible CapEx envelope to think about going forward? You referenced, of course, Tiberius FID potentially next year at some stage, Phase one plus on GTA. I'm just wondering, are you comfortable that you could operate within that $350 million going forward? Or should we expect you to perhaps need to go above that if you're to progress those projects?

And perhaps if I tack on the second one, related to that, it's just whether you're seeing any momentum on that GTA Phase one plus project at the moment, good alignment from the partnership or how close to near term is progress there? Is the crux of my question, please?

Andy Inglis: Okay. Good. Yes, Matt. If you look at the CapEx reduction from $400 to $350, it is about really sort of making every dollar count as we look at the investment going into the company and prioritizing the free cash flow. So, you know, it is at a lot of, you know, lots of opportunities right across the core portfolio. But I'd say that the majority has been slowing down some of the longer-term projects, in particular, time periods. So as you sort of look to the next question then is, can you sustain the $350 into 2026? You know, we haven't given CapEx guidance yet.

If you sort of step back and say that the primary call on capital in '26 is the four wells that we've got committed in Jubilee. There is that's a primary call on CapEx. Actually, in Equatorial Guinea, not really any significant CapEx call. You know, on GTA, I'll come on to it in a minute. You know, we don't believe phase one is going to be a significant part of '26. It'll follow slightly slower. Therefore, you know, and probably the FID of Tiberius will come probably towards the end of the year.

When you take that and you look at the focus on particularly in the volatile oil price environment that we have today, you know, a forward number of around $350 million can not only sustain the company, but it will grow the company as I just talked about, through the impact of the 50 probably right. Yes, around $350 million is going to continue to grow. Then, you know, you have the subsequent follow-on, which is more 2027, 2028 period. Of where you would see some spend on Tiberius, some spend on phase one plus.

Then on phase one plus, the most important thing to start with on that is actually, you know, the performance of the subsurface on phase one. You know, though, we've got three wells online at the moment. They're all performing in line with expectation. So that, you know, that was a little bit of a gating item amongst the partnership wanting to see the reservoir performance. We're now sort of, you know, we started up at the right at the end of the year, December 31. So we got essentially more than, you know, sort of seven months of production data and feel good about what we're seeing.

So there is absolutely alignment there in terms of the ability to expand the project. In terms of alignment around the partnership, there is alignment around a brownfield expansion, the ability to double volume through brownfield expansion of the FPSO, which was designed to do so it could double the rate that it's doing today. And the incremental investment to get it there is very small. So alignment around that. Alignment around actually that incremental gap will go into LNG and domestic gas. As a call from the government for domestic gas. Equally, the rate at which they ramp up that domestic gas call is one issue that we're working.

And then the ability to debottleneck the Gimi to provide additional LNG capacity is the other part of the exam question. So how do I use that incremental, you know, 300 to 400,000,000 standard cubic feet. So that's the work that we're doing at the moment. So I'd say that, you know, the fundamental issue is, of course, therefore around the number of wells which you need to support that incremental sort of $350 million. And, you know, good that the reservoir is performing, we're getting track record now. Therefore, I believe we have the opportunity, I think, to sort of really refine that well cap. So that's the sort of the work that's ongoing at the moment.

There are three things. Get the well count right, how many wells do you need, when do you need them, support the incremental volume, what's the timing of that volume, in terms of domestic gas and what uplift can you see from the Gimi to be able to deliver that?

Matt Smith: Perfect. Well, thank you, Andy. Happy to pass it on.

Andy Inglis: Great. Thanks.

Operator: Our next question is from Bob Brackett with Bernstein Research. Please proceed.

Bob Brackett: Hey. Good morning. I have a clarification maybe and then a question. The clarification follows what Charles had alluded to, a 40% decline in the 100,000 a day Jubilee field. The way I read the release is something more like three to four wells a year to maintain flat performance and maybe those split between producers and injectors. And that gets you to something like a 15 to 20% base decline. Is that the better way to think of it?

Andy Inglis: Yeah. It is, Bob. Yeah. I think you've described it accurately. So if you think about either the near-term program, we're going to heavily weigh producers because we believe we've got sufficient injection capacity as you ramp up from where we are today up to that sort of, you know, 90,000 barrels of oil per day. So you don't really need today additional injectors. So you can sort of high-grade the program to producers. But to be able to do that, you need the data, etcetera, as I talked through with Charles. When you're at that higher level, then I think the decline rate that you've talked about is the level in which you can manage the field.

And therefore, you will need injectors because you've got a high level of take and therefore a mix of producers and injectors three to four wells per year. Is the right way to think about it.

Bob Brackett: And then I guess my core question is which is on the license extension. You have an MOU, can you share whether there's any change in the fiscal terms or any work program commitment or is that still up in the air?

Andy Inglis: No. What we've said, Bob, is that, you know, we've described the intent of the MOU. And the dimensions that it covers. It's a win-win really for both the government and ourselves. What we're doing is there is a decrease in the gas price, but there's more volume. So we've committed to move the volume up 130,000,000 standard cubic feet a day with a small discount to the gas price. There is an undertaking to drill up to 20 wells. And clearly, the number will depend on the emerging opportunity set that we see from the NAS. But today, we see it as being a positive view that we're getting of the reservoir. No change to the fiscal terms.

It's under the existing law and those are the key elements. So I think for us, the most important part is that you can properly invest in the field to deliver a consistent drilling program where you're continuing to invest in the data because I think, you know, we see the uplift from the NAS having sort of not been shooting seismic for almost eight years. You know, we need to get back to a regular program probably every three years. Where you shoot NAS. Probably no need to redo OBN, but we would come back to that given that you calibrated the velocity model.

So that's the real win-win from this is that with a greater purview, you can invest properly upfront to deliver that regular program that we talked about where the data is enabling you to drill the best wells that are available.

Bob Brackett: Very clear. Thanks for that.

Andy Inglis: Great. Thanks, Bob.

Operator: Our next question is from Alexa Petrich with Goldman Sachs. Please proceed.

Alexa Petrich: Hey. Good morning, team, and thank you for taking our question. Wanted to ask one question on GTA costs. I think the 3Q guide came in a little higher than our expectations. Just want to get your sense of what's in those costs. How do we think about them in April 2026? Thanks.

Neal Shah: Yes, Deo. Do you want to pick that up?

Neal Shah: Yes. So, hi, Alexa. So the, you know, the three components in the GTA cost number are sort of, yeah, the FLNG toll. The FPSO lease, and the field just sort of regular field OpEx. And so yes, LNG toll is a bit higher in February, given we had some bonus payments that are payable to Golar. That's really normalized on a per MCF basis. It's a little over, you know, $2 an m on a recurring basis. So it's a volume-based calculation. And so it should be relatively steady both into the back half of this year and into next year. The FPSO is about $50 million a quarter in terms of operating cost of that lease.

And, again, I think, you know, we're saying, you know, we're working on, you know, we said we're working on refinancing that in the second half of this year if that's on track. So you'll see the cost come through. The cost reduction come through when that's complete. And, again, yeah, that's about a little over a quarter of the operating cost.

And then the third one, you know, like I said, is sort of field OpEx, and that sort of will be flat, closer to 3Q to 2Q as we sort of still rationalize some of the start-up and commissioning costs, and then you'll see a drop-off in that in terms of the fourth quarter that, you know, again, we anticipate we can hold into 2025. Or into '26. And then also looking at the alternative models. And so, again, I think on a per unit basis, you'll continue to see, you know, both sides of the equation improve both in terms of increased volume and cost coming down.

Alexa Petrich: Okay. That's helpful. And then just wanted to ask, we recognize right now we're in a period of GTA start-up costs, production is ramping. But as we think about getting to a point where we have more normalized volumes and costs come off, any thoughts about how we should think about a normalized free cash flow for the business?

Neal Shah: Yes. And, again, I would say, again, our view on that sort of hasn't changed, which is sort of, you know, bring the breakeven for the business down to sort of the $50 to $55 per barrel. Type range. And then, again, the sensitivity depending on what oil price using is about $100 million of free cash flow for every $5 we're selling above that. So, again, I think that's a, yeah. Again, I think that's, yeah. Again, it won't it doesn't exactly work out quarterly just because the timing was listings and so on. Again, I think sort of that rate is what we're targeting sort of across the business on a consistent basis.

Alexa Petrich: Okay. That's helpful. I'll turn it over. Thank you all.

Neal Shah: Great. Thanks, Alexa.

Operator: Our next question is from Mark Wilson with Jefferies. Please proceed.

Mark Wilson: Thanks, gents. A couple of questions, please. First, on GTA, thinking ahead to Phase one plus. Is the most important thing we should be looking for, gas sales agreement either with Senegal, Mauritania, or with a third party? The first question. And then on Jubilee, a lot of commentary and detail in the presentation, and some hindsight views, I would say as well. The question I have going forward is particularly with this new seismic data and the processing of that and the work that needs to be done on the longer term. Should you be the operator of that field, and is that something we're looking for? Thank you.

Andy Inglis: Right. Thank you. Thank you, Mark. Yeah. On the first question, absolutely. You know, I think I was clear when we talked about earlier what we're looking to do is work with a partnership and the play the partnership involves the government to find the right blend now of domestic gas versus increased LNG sales. Yeah? And so, yes, absolutely. Part of that whole optimization is around, you know, what level of gas can they take. What are the what's the expected ramp-up? And therefore, what would a gas sales contract look like?

So, absolutely, you know, you put it in terms of the Pacific in terms of an output we would need is certainly as we move towards FID of that, we would need clarity around what that gas sales would look like. Yeah? But, again, the government's clear about the need and actually the need in the country. Is absolutely clear. Growing economy needs to be able to leverage gas, displace heavier, displace higher-cost heavy fuel oil. And therefore, there is a real economic gain for all parties here by being able to do that. So I don't believe that is a barrier but it does absolutely need to be addressed.

In terms of your second question, look, we work very closely with Tullow as you know. I think it's a good partnership. I think we each have our individual skills. Clearly, I think being based, in particular, actually being based in the Gulf Of America, I think the view of being able to leverage seismic, the processing, the acquisition techniques, so on has been something that we've been able to bring to the partnership. I think we're working really well with Tullow at the moment to leverage their skills and our skills in this domain to make a difference. So there's no difference between where the companies stand on that. And we know we clearly have the rig locked in.

We have six wells in front of us. We're aligned around the well choices and what is going to take to drive the field forward. So I think that in response to your question, is the most important thing. That we're aligned and actually, you know, Kosmos is bringing something to the party and clearly so is Tullow.

Mark Wilson: Very good. Thank you for your attention.

Andy Inglis: Great. Thank you, Mark.

Operator: Our next question is from Stella Cridge with Barclays. Please proceed.

Stella Cridge: Hi there. Afternoon, everyone. Many thanks for all of the updates. I was wondering if I could ask on the debt side. So you mentioned that you're progressing additional financing options. I just wondered if you could talk about the different options that might be available to you, how far out on the curve that you're thinking about in terms of maturities. That would be great. And in the RBL, of course, you do have some requirements to address debt a reasonable amount ahead of time. I could just wonder if you could talk about how confident you are in meeting some of those requirements of the lending. That would be good. Thanks.

Neal Shah: Yeah. Hi, Dawn. I'll take that. Just on the further out maturities, again, I think, yeah, when we set up the maturity schedule in the past, the goal was to leave a few maturities out there and then repay them with cash flow generated from the business. And, you know, again, recognizing that, you know, the goal from our perspective is to not just reduce leverage, but to reduce the amount of absolute debt. And therefore, you know, paying off the bonds and cash flow that's generated, you know, makes sense. And so and I think, inherently, that continues to be part of the plan and, you know, the big variable there is sort of is around oil prices.

And so, you know, with the wobble that we had, sort of in the oil price, we thought it was prudent to sort of take off the '26 maturity ahead of time with the refinancing. And that gives us a bit of space combined with the other proactive measures that we've taken on the financing side to clear sort of a runway. And, yes, and in that space of time, again, continue to, yeah, work in a work in a manner to match cash flow for the business so that we can continue reducing debt.

Alongside that, we'll continue to look at proactive other alternative attractive sources of capital to see if there's, you know, cost of capital advantage to be gained in terms of addressing the 2027s and 2028 maturities as well. You know, they're trading at a discount. Yeah. If we can raise low-cost finance, secured against our assets, there's a cost there's a return to be earned there. And so, you know, the plan is to finish, you know, the Gulf facility here this quarter and then continue to evaluate those options. And part of that will depend on where things trade.

If they continue to trade at a discount, then there becomes an opportunity for us to accelerate the net debt reduction through the early retirement of those bonds. So I think it'll be an ongoing process of evaluating that. To your second question, just around the RBL, you know, again, we went through the test, you know, comfortably in sort of March. Again, we used an RBL price deck to show, you know, both from existing liquidity and cash generated between now and the maturities. We have sufficient sources to cover the uses.

Again, I think, you know, the oil prices moved up and down, but, you know, fundamentally, we're well still above borrowing base price decks and so feel good about some of the generation future cash generation. From ability and especially combined with the facility that we put in the Gulf. You know, we'll have, you know, my expectation is we'll continue to have decent coverage as we pass through those tests on a regular basis.

Stella Cridge: Super many. Thanks for that.

Neal Shah: Right. Thanks, Stella.

Operator: Our next question is a follow-up from Bob Brackett with Bernstein Research. Please proceed.

Bob Brackett: Great. Thanks for taking the question. Again, this has to do with GTA, and you mentioned domestic gas component. Can you remind me, is that a pipe to Saint Louis? Or is that some LNG into regas and say Dakar or something? What's envisioned there?

Andy Inglis: No. I think well, look. I think the primary source would be actually sort of pipeline gas. Yeah. So this would be a pipe gas solution rather than LNG to Dakar. Although, you know, there is an LNG regas facility in Dakar. So you could add incremental volume that way. I think it would be, you know, what we're looking at today, Bob, is a more permanent solution.

Bob Brackett: Okay. Very clear. Thanks for that.

Andy Inglis: Right. Thanks.

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