Good day, everyone. Welcome to Kosmos Energy's Second Quarter 2022 Conference Call. Just a reminder, today's call is being recorded. At this time, let me turn the call over to Jamie Buckland, Vice President of Investor Relations at Kosmos Energy

Thank you, operator, and thanks to everyone for joining us today. This morning, we issued our second quarter earnings release. This release and the slide presentation to accompany today's call are available on the Investors page of our website. Joining me on the call today and 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 UK and SEC filings. Please refer to our Annual Report, stock exchange announcement, and SEC filings for more details. These documents are available on our website. At this time, I will turn the call over to Andy.

Thanks, Jamie, and good morning and afternoon to everyone. Thank you for joining us today for our second quarter results call. I'd like to start today's presentation looking at the operational delivery in the quarter, I'll then hand over to Neal to talk through the financials before I wrap up today's presentation. We'll then open up the call for Q&A. Turning to slide three. 2Q was another quarter of strong execution for Kosmos as highlighted by the boxes on this slide. Our production assets are performing well with production for the quarter at the upper-end of guidance. Our three development projects, Tortue Phase 1, Jubilee Southeast and Winterfell are continuing to make good progress and are expected to deliver production growth of around 50% by 2024. We continue to optimize our world-class gas portfolio in Mauritania and Senegal, working closely with partners and the governments to accelerate and deliver value from our significant discovered resource. Today, Kosmos announced its plan to utilize existing contractual rights in the sales agreement for GTA Phase 1 volumes to divert cargos to prospective buyers in order to benefit from the current market environment. More on that in a moment. And finally, the balance sheet continues to improve as the portfolio generates cash and drives down leverage, all while supporting our differentiated growth. We'll dig into each of these things later in today's presentation. Turning to slide four, which looks at our producing assets which are performing well with 2Q production coming in at the upper-end of guidance. In Ghana, the Jubilee field continues to deliver. Gross production for the quarter, excluding the impact of the shutdown was around 92,000 barrels of oil per day. Including this impact, gross production was around 74,000 barrels of oil per day. In May, the partnership completed the planned…

Thanks, Andy. Turning to slide eight, the second quarter saw continued progress as we further enhanced our financial position. We are taking advantage of higher oil prices to rapidly strengthen our balance sheet with net debt approximately down $400 million in the first half this year to $2.1 billion. EBITDAX in 2Q was around $385 million, which resulted in free cash flow of around $70 million in the quarter and around $290 million for the first half of the year. Excluding capital expenditures in Mauritania and Senegal, base business free cash flow in the first half of the year was around $450 million, demonstrating the strong cash generation ability of our business before our development projects come online. The solid cash performance and continued net debt reduction helped drive leverage down to 1.6 times. Liquidity, which has grown consistently over the last year, was over $1 billion at the end of the second quarter, which is the highest it's been since 2018. As we look forward with expectations that the business continues to generate strong levels of free cash, we plan to continue to prioritize debt pay down, aiming to get beyond our leverage target of less than 1.5 times at year-end and net debt below $2 billion. Turning to slide 9. As Andy mentioned, net production of over 62,000 barrels of oil equivalent per day was at the upper-end of guidance, helped in particular by strong performance at Jubilee and less downtime in the Gulf of Mexico. We realized a price of $86 per boe, including the impact of hedging. Excluding hedging, the realized price was around $109 per boe. Operating costs were lower than guidance during the quarter, reflecting production coming in at the upper-end of guidance and some deferred maintenance activity in Equatorial Guinea. CapEx in the quarter was slightly higher than forecast, primarily a result of higher accrued capital related to activity in Mauritania and Senegal. As many companies in our industry have reported, we are seeing the impact of some inflationary pressures, particularly at the Tortue project in Mauritania and Senegal as we get closer to the finish line. As a result, we are increasing our full year CapEx guidance by approximately 5% to around $700 million. Although we are seeing some higher cost, we have maintained our free cash flow guidance for 2022 of approximately $420 million, assuming current oil prices offsetting the inflationary cost impacts. So to conclude the financial section of today's presentation, it was another good performance in the quarter with continued progress across all key areas. We delivered a strong cash flow performance with the rising liquidity, material debt pay down, and a meaningful reduction to leverage. I'll now hand back to Andy to close today's presentation.

Thanks, Neal. Turning to slide 10 to wrap up today's results presentation. While the macro environment continues to be volatile, Kosmos has had another solid quarter of operational and financial delivery. Our production assets continue to perform well, coming in at the upper-end of guidance. Our three development projects continue to make good progress to drive a 50% growth in production we expect from current levels by 2024. We are working closely with our partners to optimize the value of our gas portfolio that we expect will deliver growth beyond 2024. Our financial position continues to improve with continued strong free cash flow generation. This has enabled liquidity to rise to multi-year highs with leverage falling sharply, well on track to exceed our year-end target. And finally, we have the right portfolio at the right time, providing the energy the world needs today and supporting a just transition that addresses the trilemma of energy security, energy affordability, and climate change. Thank you. I'd now like to turn the call over to the operator to open the session for questions.

Thank you. And ladies and gentlemen, at this time, we will conduct our question-and-answer session. [Operator Instructions] Our first question comes from Austin [indiscernible] with Johnson Rice. Please state your question.

Good morning, Andrew, Neal and Jamie. Thank you for taking the questions this morning.

Yeah. Hey, good morning, Austin.

On Tortue Phase 1, could you help me understand the mechanics of the spot pricing opportunity? Also, does this increase the potential value to Kosmos over the first year or two of the contract?

Yeah, sure, Austin. We think there is a differential value in Kosmos versus peers because of the material and growing exposure to international gas, the structural changes in global gas market on the back of the Ukraine war mean gas prices are likely to stay higher for longer and remain dislocated from oil. So clearly we've talked about in the past, our Phase 1 volumes are priced against a Brent slope, so the price we receive is driven by oil prices. However, there is a deliver or pay clause that would allow us to utilize and take advantage of current gas prices in instances where pricing allows us to pay for it by an agreed non-delivery penalty to our current buyer. This is a typical provision in an LNG sales agreement. We can't share with you the exact details of the contract. But contracts of this era, the penalties typically in the range of 20% to 30% of the contractual price, the price that's linked to the Brent slope. So if you take those inputs and you look at an average gas price, let's say, for '24 and '25 of around $20 and an oil price of, let's say, $100 per barrel, the opportunity could be around $200 million of additional revenue net to Kosmos in total over those two years. If you look out at the forward strip and you look to where that's sitting today, TTF is closer to an average of '25 -- the '24, '25 time period. And with those assumptions, the revenue benefit to Kosmos in aggregate over the two years would be around $350 million. So it's a significant opportunity for us and we believe it's important to start engagement with prospective buyers now because the opportunity is clearly there.

I appreciate the color on that. And as a follow-up, you provided a positive update on your Winterfell project with FID approval expected later this quarter and doubling the expected gross recoverable resources. Did the recent technical work from the initial two wells caused any modifications to your development plans/timeline of this project?

No, it hasn’t, Austin. I think, we're targeting FID at the end of this quarter and that -- and we see first oil 18 months afterwards. Clearly, we've -- it's a technical work from the first two wells, which we believe has indicated a significantly larger resource. The first phase is a five-well development, as I said in my remarks, that's targeting development -- the initial 100 million barrel opportunity, but we think with production data from those initial wells, we would see that being the indicator of a larger resource, and clearly, the infrastructure that we're putting in would enable us then to build and expand to fully access that. So I think the work we've been doing over the quarter to go after FID is around that Phase 1, three initial wells pre-first oil followed by two follow-up wells, but we're anticipating a larger resource, and therefore, the ability to expand from there.

I appreciate the color. That's all from me.

Great. Thanks, Austin.

Our next question comes from Neil Mehta with Goldman Sachs. Please state your question.

Hey, good morning. This is Carly on for Neil. Thanks for taking the time. I wanted to just start on Tortue, as we think about the potential for Phase 2. Could you talk a little bit about what are the outstanding gating factors that we should be keeping in mind to get that project to FID? And then, are there any changes to the timeline to expected first gas there?

Yeah. Hi, Carly. No, I think -- we've taken the time to make sure that we've got the right project for Phase 2, both in terms of the sort of scale and scope of the project. A lot happened in the last six months with regard to the LNG market, in particular, the European market, and it's important that we've got the right project that enables us to fully access that opportunity. We also need to make sure that, from a contracting perspective at a time of real inflationary pressures, we've got the right approach to the market, and the development concept that we pursue is clearly an important part of that. So that's been the work we're doing at the moment. The objective is to come to a decision on that concept by the end of the third quarter that will then enable us to do the detailed work, the FEED work to get to the costs in Mauritania and Senegal to get formal approval of -- which is FID. We have to go to the governments with the full contractual position, the forecast, et cetera. And the anticipation would be that we would do that in 2023 and that leads you to a first gas date in the sort of end '26, '27 timeframe. So no fundamental change to that, but I think it's ultimately about have we got the concept, which allows us to best take advantage of the current market conditions and allows us to ensure that we've got the optimum scope from managing the inflationary pressures, which are clearly in the market today.

Got it. That's helpful. And then the follow-up is just kind of on your last point on inflation. As you're pursuing these different development projects across the portfolio, can you just flesh out a little bit kind of what you're seeing from an inflation perspective and what steps that you're taking to mitigate those pressures?

Yeah, it's clear that we're seeing in the deepwater now supply chain challenge is really across all dimensions, whether it's sort of drilling rigs being sort of at the high level of utilization, subsea equipment, installation vessels, et cetera. So I think the mitigations are around doing the work out front to ensure that you've got a concept and an approach to the contracting strategy, which allows us to get to the most cost-effective approach, and I think that's part of the work that we've been doing on Winterfell. Again, as an example, on Winterfell without getting ahead of our skis, we have been ordering the long lead items, we've moved ahead to select a rig. We've done that for the program in Equatorial Guinea. Access to the right equipment is clearly important. So I think these are old tried and tested techniques that the industry has used. I think, for us, it's about being rigorous now about the management of this literally on a day-by-day basis. No increase in scope, don't allow the projects to have any gold-plating , and then it's about the rigor of execution, right approaches to the market, access to the best equipment, et cetera. And I think that is the other challenge the industry has today, it's not only an equipment issue, but it's also a human issue, getting access to the A teams. So I think those are earl of the areas we're focused on. But from a Kosmos perspective, we have three projects, we're clear on where we stand on each of those projects, and now it's the rigor and discipline of managing them through to first production.

Great. Thanks for that color.

Our next question comes from Matt Smith with Bank of America. Please go ahead.

Hey, thanks, guys. First, a couple of questions just around the LNG price, if I could. Could I just double check on the Phase 1 volumes, does that contractual right applied to 100% of your [indiscernible] Phase 1 volumes? And then the second question on the same topic was really around sort of Phase 2 and the contracting opportunity there. I guess, each time we talk about this, the gas curve keeps moving higher and higher. Is it fair to characterize that you're more likely to look for gas exposure for the Phase 2 volumes? And if so, is that likely to be through pure spot pricing? Or do you think there's perhaps a happy medium in between?

Yeah, thanks, Matt. Yeah, actually the LNG contract is public actually. So if you look through that contract, Matt, what you'll find is that we can to -- we have to maintain every second year 50% of the ACQ. So that means sort of year one you can divert 50%, year two you can divert 100%, year three you can divert 50%, year four you can divert 100%, while still meeting all your obligations under the contract with the penalty for the diverted cargoes. So what it means is, to do the math, you're paying a penalty on the diverted cargo and you can divert up to, on average, 75% of the cargoes with it sort of in a modeling sense 50%, 100%, 50%, 100% . And as I typically -- I can't share with you the actual penalty, but contracts of that era had a penalty of around -- somewhere between 20% and 30% of the price to the buyer Yeah, sorry. Then on Phase 2, I think the step on Phase 1 is an indication of where we intend to go on Phase 2. We would want to sort of build a relationship with customers that could take those volumes in that '24, '25, '26, '27 timeline. Phase 2 volumes would be following absolutely after -- in that time period, and we would look to overlay it with contracts that gave us real exposure to the gas exposure as you said. But look, I think genuinely it is going to be a mix. The big difference for Phase 2 versus Phase 1 was that, we don't anticipate any financing requirements for Phase 2. We put the infrastructure in place for Phase 1, and therefore, the incremental build-out in terms of additional capital is very modest. We've talked of a number of less than $1 billion in the past. So as you start to think about the flexibility that gives us, it's significant. And that's really the excitement that we have now around the exposure to the international gas price. As I said in my answer to Austin's question, I think we're quite unique amongst our peers and having this exposure to, not only in sort of a high-margin, low carbon oil, but actually high margin, low carbon gas. And as you start to look at now where the forward curve is going for gas due to the unfortunate extension of the war in Ukraine, we believe there is a fundamental opportunity for us to access. So again, in terms of bringing that forward, we can do it with the Phase 1 volumes, as we've described with the diversions, and then clearly back that up then with the Phase 2 volumes and become a very sort of credible seller into the market.

Perfect. Thanks. Andy. Really appreciate the detail. And perhaps if I can just sneak one more in, it was just around the sort of NOC cost carry that you have at Tortue. It sort of sounds as, though, you sort of no longer prioritizing the refinancing of that, given that you don't have necessarily balance sheet constraints anymore. So just wondering if you could remind us sort of on the default mechanism of how you will recoup that cost and perhaps even if you're able to give any color on how quickly you might recoup that that would be much appreciated. That's all from my side .

Yeah, I'll ask Neal just to pick that up, Matt.

Yeah. So Matt, the mechanism is meant for sort of the Phase 1 revenue to the NOC is to repay sort of the NOC loan, and sort of there is some flexibility built in, in terms of the duration of that repayment. So -- but clearly, the more they generate from the Phase 1 volumes means the faster we can potentially get our proceeds from the loan back. Alternatively, the -- as you noted sort of the -- while the sort of immediate pressure is still off from getting the NOC loan off of our books, it's still something we want to pursue. I think just from a timing perspective, that naturally will make sense around sort of the Phase 2 project sanction to bring back into the fold. So it's still something on the agenda.

All right. Okay, thanks, Both. I'll pass over. Cheers.

Great. Tanks, Matt

Our next question comes from Alex Smith with Investec. Please go ahead.

Hi, guys. Thanks for the call. Just two quick ones from me. First one, you're rapidly approaching your gearing target and producing healthy levels of cash flows. Just when could we begin to see maybe a decision on dividends or buybacks? And would there be a preference for [Eva] (ph). And then just on Ghana, can you just comment on the cost of the wells that you have been drilling, you mentioned they come in slightly under expectations. And the plans for decision of the second rig, given the current oil price environment, is there an opportunity to accelerate this decision given how well the drilling program is going to date? Thank you.

Yeah. Hey, Alex. So let me just -- I'll talk about Ghana first and then Neal can pick up the financial framework. I think in terms of the decision around the second rig, as I commented in my remarks, we are drilling well in Ghana at the moment. The wells are ahead of schedule, under cost. And actually the opportunity, therefore, is to deliver the volume increase that we intended across the assets, but actually do it through a high graded one-rig program, and that's the focus for today. So we don't anticipate bringing a second rig in currently. We're going to continue to evaluate that opportunity, but I think it's all around this mantra of capital discipline today. As you start to deal with the inflationary pressures, the opportunity ultimately is around operate more efficiently. That's how you mitigate the increase in the unit cost. So that's our focus today, and I feel confident that we can actually do that. So we don't -- we're not making a decision today to bring in a second rig. We've got a clear program that enable us to start the drilling of the Jubilee Southeast wells this year that enables us to deliver on that project where we anticipate start-up once the subsea equipment is in place in the middle of the year. And that -- in terms of driving '23 volumes, that is the big driver. And then we have a follow-up of the TEN Enhancement Project that would follow in '24, '25. So I think we're well placed today and we don't have to -- there is no economic benefit from bringing a second rig today. And then Neal in terms of the gearing targets?

Yeah, so in terms of the gearing and as well as allocation of capital, these really haven't changed overly too much, Alex. I think the goal is to fund the capital program, both the maintenance in the growth projects that we have, and then within that, while leverages continue to sort of prioritize debt pay down until leverage is less than sort of 1.5 times. We said we're sort of get on track to get there before the end of this year, but we want that to be sustainable before we sort of look at sort of shareholder returns. But it is sort of clearly next on the agenda that we would look to. In terms of buybacks versus dividends, again, I think that will be more to come on that in terms of which specific method, it will largely depend on where sort of both the share price looks like at that time period, but I'd say, currently sort of more tilted towards the buybacks. But we'll look at that as we achieve our debt targets.

Great. Thank you very much.

Our next question comes from Bob Brackett with Bernstein Research. Please state your question.

Yes, please. I saw that you drilled two of the four producers at Tortue Phase 1. Can you comment on did they come in at least based on the log analysis in line with pre-drill predictions?

Yeah, overall, we're looking to build well capacity, Bob, where we've got to the coverage and really from sort of two/three wells that will deliver the required plateau versus four. So the first two wells have enabled to stay on track to do that. We're currently drilling the third well, and then the fourth one is actually a twin of one of the original exploration well. So in terms of having the required well productivity with the appropriate level of insurance at first gas, we feel good about what we've seen so far.

Great. Thanks for that. In terms of EG, you mentioned the four wells as part of a drilling program split between infills and ILX. How are you strategically deciding whether to go for a more sure infill versus a greater upside ILX, what's the logic there?

Yeah, A great question actually, where we see two really good opportunity sets, yeah. You know the history of why we went into EG, we felt from two perspectives that it hadn't been fully developed from an infill perspective and there was a sort of remaining exploration opportunity in the Rio Muni. We've built a pretty good hopper now of infill opportunities, and we're going to high grade the first three of those actually, Bob, in terms of the drilling program. And then the fourth well will be the ILX well, which is targeting a deeper untested Albian opportunity underneath the Ceiba and Okume infrastructure that looks really interesting. So that's the balance. And clearly, the ILX opportunity is significant and will be a significant check game changer in terms of our position there in Ceiba and Okume, whilst infill wells are really high quality, high rate of return, short payback, tied back to the existing infrastructure. So we've got both of those opportunities on the roster. And clearly, gaining the license extension out to 2040 has made both of those opportunities even better, because clearly, with the extension we have, if we were successful with the Albian, we've got significant amount of time then to drill out quite a large associated inventory. So the drilling program will start at the back end of next year and I think will be an interesting phase of the development of Ceiba and Okume.

Great. Thanks for that. A super quick one, if I may. In terms of just a follow-on on exercising contractual rights on the Tortue Phase 1, I believe is BP both the counterparty of those as well as the operating partner? And is everything amicable between you all?

No, I think you've got to be -- it's quite important that BP is the upstream operator, yeah? BP Gas Marketing is the purchaser. So there's actually Chinese Wall between BP as the upstream operator and BP Gas Marketing as the buyer of the gas. And actually everything is amicable.

Perfect. Thank you.

Thanks

Our next question comes from James Hosie with Barclays. Please state your question.

Yeah, hi, there. A couple from me. I guess going back to your right to divert some of the Tortue Phase 1 cargoes. How much notice you to need to give on this? Just wondering how far ahead you can make a call with LNG spot prices?

Yeah. I don't want to get into too much of the detail, James, because it is -- but in terms of the ability, we have the right to divert cargo by cargo, and therefore, we have the ability to build a program, so we can dictate the duration of the scale of the diversions.

Okay, okay. And then just on other topic. If you could give us some color on has the 2022 [capsule] (ph) budget shaping up? I'm just thinking, are you talking about Winterfell? It sounds like it a $1 billion project gross and then obviously inflationary pressure as well. Just should we be assuming higher CapEx compared to 2022 budget of $700 million?

Yeah, so look, we don't normally give CapEx guidance for the following year, so we can match it with our final year results. But I think conceptually, the way to think about it is, the base business, as we’ve talked about it, it's a sort of sustained production there. We're spending around sort of $350 million on that in '22. And looking forward with the rigs locked in, et cetera, we feel sort of good about that number. Then you really got the capital that goes into the growth projects and you've got a couple of dynamics, yeah. You probably got a similar level of spend on Jubilee Southeast, you've got a reducing level of spend in Mauritania, significantly reducing, and then you've got an uptick in Winterfell as you described. So I think that's the way to think about it. And then of the margin, you've got discretionary capital around the ILX programs. So I think that's the way to think about it. And clearly, the timing around the relative ramp up, ramp down of those projects is -- so you've clearly got significant decrease in spend in Mauritania and Senegal, but you will have, as you say, an uptick in the Winterfell spend.

Okay, very good. Thank you.

Thank you. [Operator Instructions] Our next question comes from Mark Wilson with Jefferies. Please state your question.

Hi, thanks for taking my questions. A few points here. So it sounds like you're not bringing a second rig or plan to do the Jubilee Southeast development drilling, that’s the first clarification. Could we also just understand where we stand on those Shell exploration payments after the success in Namibia? And then lastly, we've seen the BirAllah PSC extension, some change in terms there. Do we expect something else like that on Yakaar-Teranga? Thanks a lot.

Yeah, as I said, answering a prior question on the second rig, I think it's actually good news story. At a time of a real inflation, it's about driving efficiency into the business. And I think on Jubilee, we've seen the demonstration of that in terms of the drilling performance. And so for us, it's about continuing down that path and high grading the well selections, being able to deliver the volume increase that we've outlined in Jubilee and deliver the benefit from that project. So we don't -- we're not anticipating making a decision on a second rig currently, and clearly, we'll continue to evaluate that, Mark. But the answer is, no, no second rig at the moment. In terms of Shell, they have success with two wells in Namibia, Lebanon and Graff. Our understanding is that they intend to submit an appraisal plan at the beginning of the fourth quarter, and with the submission of the appraisal plan, they would be obligated to pay the bonus from the contract that we have in place with them. So that's what we anticipate. On BirAllah, yes, BirAllah is a -- it's taken an important step forward in new PSC. Clearly, we have to separate out in a development sense the discoveries that we had in Orca and the surrounding acreage. Better to do it now ahead of a sort of development proposal then do it later. So we spend the time now to do that. In an accounting sense, there has been an impact, but actually in an economic sense, the costs that were associated with the -- essentially, it was the Orca exploration well. We get the benefit of that both in cost recovery and tax on Tortue. So no economic impact from this. But what we do have, we have a new PSC at substantially the same terms. You have some small modifications around local contents, et cetera. But ultimately, we now have the basis on which to move forward now with BirAllah on a very sort of a clean forward-looking perspective. And as I said, I think, for us, it was important to do this now rather than sort of get to the development decision then have to negotiate the new PSC as part of that development decision. So I think we're on track now to move forward and do the concept work that's required to bring that forward is a real opportunity. And there is a big resource base there. Again, it's characterized by low cost, low carbon gas adjacent to the European market, and our objective, as I said, in remarks will be to tackle that with a phased approach very much in the same way as we've done on Tortue.

Got it. Okay, no, thank you. And I'll turn over .

Great. Thanks, Mark. Appreciate it.

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