Good everyone, welcome to Kosmos Energy’s Second Quarter 2021 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. The 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 material 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 and expectations. Actual results and outcomes could differ materially due to factors that we note in this presentation and in our U.K. and SEC filings. Please refer to our Annual Report, Stock Exchange Announcement and SEC filings for more detail. 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'll run through the highlights for the quarter before handing over to Neal to take you through the financials and guidance for the remainder of the year. Starting on Slide 2, Kosmos continues to successfully execute our plans in the second quarter, delivering on the three key priorities outlined on the slide. First, we posted strong cash performance in 2Q with free cash flow of $115 million in the quarter. We expect this strong performance to continue in the second half of the year as production increases with new wells coming online. As previously communicated, we target a year-end exit rate of around 60,000 barrels of oil equivalent per day and are making good progress towards that target. Importantly, as our 2021 hedges continue to roll off, cash generation should be materially enhanced through 2022 at oil prices around current levels. As a result, we expect leverage to fall significantly by year-end and continue to reduce through 2022 at current prices. Second, we continue to strengthen our financial position in the quarter. We announced today the completion of the FPSO sale and leaseback transaction for The Greater Tortue Ahmeyim project, an important step in funding our remaining capital to first gas. The transaction will fund our outstanding capital requirements for the project through 2021 and partially into 2022 with additional savings from the transfer of future FPSO milestone payments to BP. Additionally, in May, we successfully completed amendments and an extension of our reserves-based lending facility which pushed out any material near-term debt maturities to 2024 and beyond. Third, we remain on track with our operational delivery for the year; 2021 has been an active year so far for Kosmos with momentum building across all areas of the portfolio. We plan to drill nine infill wells this year and are starting to see new wells come online, which is having a positive impact on production levels. One example is the first Jubilee producer well that came online in July and has added around 10,000 barrels per day of incremental growth in oil production. We look forward to more wells coming online in the third quarter, which should further drive production levels towards our targeted year-end exit rate. In Mauritania and Senegal, all key work streams on the GTA projects have made good progress with first gas expected in the third quarter of 2023. In the Gulf of Mexico, we expect to drill a Winterfell appraisal well later this quarter.

Thanks, Andy. Turning to Slide 5, as Andy said, the second quarter posted a strong cash performance on the back of higher sales volumes, which saw a reversal of the end of the position in the first quarter together with improving realized oil prices. I don't plan to focus on every line on this slide. Instead, I'll walk through a handful of key items. We're going to continue to deliver solid performance; net entitlement production fell slightly quarter-on-quarter, mainly due to lower than expected production in EG and the Gulf of Mexico. Those areas were affected by more downtime than expected as we indicated in our July operational update, with EG also impacted by higher prices reducing our entitlement production under our PSC. The realized price per barrel post hedges was around 20% higher quarter-on-quarter, reflecting higher oil prices and some hedges rolling off during 2Q, which will continue during the third and fourth quarters. OpEx per barrel rose slightly due to lower production and also due to production mix with 10 cargos sold in the second quarter, which has a higher OpEx per barrel largely responsible for the quarter-on-quarter move. Net interest increased to $39 million in the second quarter, up from the first quarter, as indicated in May. Additionally, 2Q includes $15 million of one-time costs associated with the extinguishment of debt when we completed the RBL amendment and extension. Lastly, base business CapEx increased quarter-on-quarter as we began our drilling activity in Ghana and Equatorial Guinea in the second quarter. Turning to Slide 6, this slide looks at our guidance for the third quarter and for the full-year. Our full-year production guidance remains unchanged with production expected to trend higher in the second half as new wells come online in Ghana, EG, and the Gulf of Mexico. From a sales perspective, we expect to lift one cargo in Ghana during the third quarter and half a cargo in EG, which will lead to an under-lift in the quarter similar to the first quarter, which should reverse in the fourth quarter as it did in the second quarter. OpEx guidance for the third quarter is expected to be between $15 and $17 per barrel. We are increasing our OpEx guidance for the year by around $1 per barrel due to some higher costs we've seen across the portfolio thus far this year. Base business CapEx remains the same, but as Andy flagged in his earlier remarks, we now expect around $90 million of capital for GTA to be funded in 2021.

Our first question comes from Nick Stefanou with Ren Capital. Please go ahead with your question.

It's Nick Stefanou from Ren Cap. Thank you for taking my questions. I've got two to ask, if I may. Andy, starting is for you. The LNG market has rebounded quite strongly in the past few months, so I was just wondering if you are considering perhaps a farm-down in any part of the Mauritania and Senegal assets there, and maybe something that might make sense. The second question is for Neal regarding the hedging policy. My perspective is that they don't really protect against excessive volatility and don't provide much upside, only downside protection. Are you thinking of changing your approach to hedging going forward? Thank you.

Yes, thanks, Nick. I will take your first question. We are pleased with the progress on GTA. The step we announced today regarding FPSO financing has been an important milestone for us. The next step for us involves NOC financing, and we can now see a direct path to first gas. As you note, regarding the scale of the resource we have in Mauritania and Senegal, with more than 100 Tcf of gas in place across the trend, there is clearly more than Kosmos can effectively develop with our current working interest. Our focus is on GTA and ensuring we deliver the project on time and within budget while also maximizing cash flow from it. It's important to highlight that part of our Phase 2 strategy includes leveraging the strong LNG market. Thus, our push in Mauritania and Senegal revolves around accelerating cash flows from the portfolio we presently possess. This aligns with our outlined strategy moving forward. I will turn over to Neal now to discuss the hedging strategy.

Yes, good morning, Nick. In response to your question on hedging, we've used a variety of structures within our hedging portfolio and intend to do so going forward. A portfolio composed entirely of three-way collars does not sufficiently provide adequate downside protection for the equity, debt, and overall business. We're working to find a balance between managing downside protection while also minimizing costs and retaining upside potential. Currently, our portfolio features a mixture of about 50-50 between the two structures, which we find suitable for our needs.

Our next question comes from the line of James Carmichael with Berenberg. Please proceed with your question.

Just a couple from me. Firstly, regarding the deleveraging chart on Slide 3: given current oil prices trend to be moving around quite a bit, could you specify the assumptions in that chart and provide some sensitivities? Secondly, I’d like a bit of color around the Kodiak well and any early indications on the timeline to resolving the issues there. Regarding the Winterfell appraisal, what key risks are associated with deeper M4 reservoir testing, and how does the well perform in terms of de-risking an estimated $100 million in the area?

Thanks, James. I will address your U.S. inquiries, and Neal will cover the deleveraging. Regarding the Kodiak well, it hasn't performed as anticipated, and we're currently evaluating potential interventions. I would estimate that securing the necessary equipment could take until year-end or early next year. On a positive note, Tornado's strong performance has compensated for the underperformance of the Kodiak well. In terms of Winterfell, we are testing the adjacent fault block to the north where we've identified a successful horizon on the discovery well. The key test is to verify if this adjacent fault block has sufficient volume to support initial development, which could lead to further appraisal or phased development based on the results. We're eager to see the results of the appraisal well and engage our partners in the discussions that follow.

So, to answer your question regarding the charts, James, they were generated based on oil prices of $65 to $70, which is aligned with current oil prices. Despite fluctuations in prices, our business generates substantial cash flow. We're well-hedged, especially in the short term, particularly for 2021. Thus, price changes will have lesser impact on our deleveraging profile and allow us to benefit from rising prices to accelerate debt reduction.

In reference to the U.S. concerns, yes, we're observing stronger production from Tornado than anticipated, and we're pleased with that outcome. Unfortunately, Kodiak has not met our expectations, and we are exploring intervention options. We expect resolving issues there to take until the end of the year. Fortunately, Tornado's strong performance offsets some of the challenges we're facing with the Kodiak well. For Winterfell, we're testing an adjacent fault block similar to the successful discovery well. The outcome will determine the volume for initial development and whether we proceed with further appraisal or a phased development approach. We're optimistic about the potential as we await the well results and subsequent discussions with our partners.

A few housekeeping points first. Congratulations on executing the sale and leaseback of the Tortue FPSO. Can you clarify the overall financing inflow you expect from that transaction across 2021 and 2022? Additionally, regarding the expected operational expenditure (OpEx) at the target output of 60,000 barrels per day into 2022, what should we anticipate? Lastly, concerning Tortue, what OpEx should we anticipate factoring in the FPSO leaseback?

Neal, would you like to address that?

Good morning, Mark. Regarding the FPSO transaction, after August, we will no longer show CapEx related to Mauritania and Senegal until the past costs are fully recovered. Initially, we recorded a receivable from BP for costs incurred and will report a corresponding liability. CapEx for Tortue will offset that receivable until exhausted, meaning no cash flow impact until the first half of 2022. Beyond that, we anticipate around $200 million in overall savings for the 2022 timeframe, in addition to the $160 million benefit in 2021. Does that clarify your question? Regarding the OpEx, we have raised the midpoint of the guidance to approximately $16.50 per barrel. There is potential to optimize that downward by $1 to $2 per barrel with production improvements. Additionally, we have not provided explicit OpEx guidance post-FPSO but can follow up with you later. Yes, the working capital has seen significant movement this year, especially in the second quarter. Given a strong sales quarter, we experienced a positive working capital impact, but we anticipate a reverse in the third quarter. The lumpy nature of cargo sizes will lead to a drop in working capital in Q3, reverting back in Q4. It's a timing issue due to contractual lifting schedules.

That's quite clear, thank you, Neal. One final point I have is concerning the FPSO and how it fits into the sale and leaseback scenario compared to an FLNG vessel.

Both assets will be treated similarly. The FLNG was initiated as a leased project while the FPSO was switched into a lease arrangement, so it will be accounted for the same way as FLNG in terms of operational expenditure in the future.

Great, thanks, Mark.

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

This is Carly on for Neil. Thanks for taking the questions. First, on costs, can you elaborate on the higher OpEx guidance? Is this driven by inflation or other factors? How do you plan to manage costs moving forward?

Yes, Carly, I'll answer that and then Neal can provide additional insight. This quarter had some variability due to the nature of the liftings and their associated costs. We had a TEN cargo in Q2, leading to a higher OpEx per barrel. Additionally, there's a lease cost related to the FPSO, resulting in higher OpEx overall for that quarter. Tornado also had strong production, which came with price factors that positively impacted our costs. We had some structural challenges partly due to COVID as well, but we're getting better at managing that. Overall, the quarterly variability largely stemmed from certain one-time factors. Regarding the Tortue financing update, can you provide details on the outstanding processes involved and any milestones we should watch for?

Sure, Carly. We're waiting for the completion of the FPSO as it significantly impacts the project's cash flows. We've initiated discussions with the banks regarding NOC financing and hope to finalize this in Q4, providing all goes as planned.

Yes, Carly, we're on track with our plans. The FPSO financing was the critical step we needed to complete, and now we can proceed with the NOC loan refinancing. Everything is progressing as we anticipated.

Thank you. Ladies and gentlemen, 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. Thank you for your participation.