Kosmos Energy (KOS) Q2 2021 Earnings Call Transcript
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Kosmos Energy (NYSE: KOS)
Q2 2021 Earnings Call
Aug 09, 2021, 11:00 a.m. ET
Contents:
- Prepared Remarks
- Questions and Answers
- Call Participants
Prepared Remarks:
Operator
Good day, 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.
Jamie Buckland — Vice President, Investor Relations
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 materials are Andy Inglis, chairman and CEO; and Neal Shah, CFO.
During today’s presentation, we will make forward-looking statements that refer to our estimates, plans, and expectations. Actual results and outcomes could differ materially due to factors that we note in this presentation and in our U.K. and SEC filings. Please refer to our annual report, stock exchange announcement, and SEC filings for more details.
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These documents are available on our website. At this time, I will turn the call over to Andy.
Andy Inglis — Chairman and Chief Executive Officer
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 Neil to take you through the financials and guidance for the remainder of the year. Starting on Slide 2.
Kosmos continued 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 toward 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 on the project through 2021 and partially into 2022 with additional savings from the transfer of future FPSO milestone payments to BP. In addition, in May this year, we successfully completed an amendment and extension of our reserve-based lending facility which pushed out any material near-term debt maturities to 2024 and beyond. And 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 gross oil production. We look forward to more wells coming online in the third quarter, which should further drive production levels toward our targeted year-end exit rate. In Mauritania and Senegal, all key workstreams on the GTA project 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. Turning to Slide 3. As mentioned on the previous slide, Kosmos delivered strong cash performance in the second quarter with around $115 million of free cash flow for the company. Free cash flow generated from the base business for the first half of the year was around $125 million.
That excludes capex related to Mauritania and Senegal and includes a slight working capital benefit. The second-quarter cash generation allowed us to reduce net debt by around $100 million by quarter-end. As shown on the top chart on this slide, our leverage ratio has fallen sharply since year-end 2020 and should continue to do so going forward. Higher oil prices are driving higher EBITDAX with 2Q ’21 EBITDAX over three times higher than the same quarter last year.
This, along with our growing production and absolute debt reduction are positively impacting our leverage ratio, and we look forward to further progress through year-end and into 2022. As I previously mentioned, we’re pleased to have completed the Greater Tortue Ahmeyim FPSO sale and leaseback transaction, which is expected to fund our remaining GTA capital through 2021 with additional savings coming in 2022. At the beginning of the year, we talked about 2021 capital expenditures for Mauritania and Senegal net to Kosmos of around $350 million. The FPSO financing is now expected to cover around $160 million.
This is slightly less than previously expected given the short delay in closing the FPSO transaction, but we expect to see additional savings in 2022 as a result. An additional $100 million benefit in 2021 is expected from the NOC loan refinancing that we aim to complete in the fourth quarter of the year. This leaves around $90 million of 2021 Mauritania and Senegal capex for Kosmos to fund in 2021, which occurred in the first half of the year. In May, we completed an amendment and extension of the reserve-based lending facility, and I’d like to thank our banking group for their continued support.
The facility, which is a total size of $1.25 billion was $1 billion drawn at the end of the second quarter. Importantly, the extension pushed out maturities by another two years, meaning that we have no material maturities until 2024 and beyond. Turning now to Slide 4. The first-quarter results in May, I talked about momentum returning to the business with activities signed to ramp up across the portfolio.
I’m pleased to say this momentum has continued to build through the second quarter, and we remain on track to achieve our objectives. We’ve seen drilling across our three production hubs and continued progress with our GTA project in Mauritania and Senegal. Taking each hub in turn. In Ghana, as I mentioned, we’re starting to see positive results from this year’s drilling campaign with the Jubilee J-56 producer now online.
Production at Jubilee is now around 80,000 barrels of oil per day, up from around 70,000 barrels in the first half of the year. The second well, a Jubilee water injector should come online shortly and further enhance production. The rig will then move to drill our gas injector on 10, which is expected online in the first — in the fourth quarter. The partnership then plans to drill a second Jubilee producer that is expected online around the end of the year, with further production increases expected as we move into 2022.
In Equatorial Guinea at the Ceiba field, a major infrastructure integrity project has been completed, which is expected to improve reliability and allow greater flexibility for gas lift to additional wells. The Okume upgrade project is expected to be completed in the fourth quarter, adding additional power, water injection, and gas lift capacity necessary for further facilities debottlenecking and additional electrical submersible pumps or ESPs. In April ’21, one ESP conversion was completed with further ESPs expected post completion of the upgrade project. The first of three infill wells spudded in June with positive initial results.
The rig will now move to the second well location and hookup has commenced for the first well. All three wells to be drilled in the Okume complex are expected to be online in the fourth quarter of 2021. In the Gulf of Mexico, the Tornado-5 producer well was drilled in the second quarter and came online in July and is currently producing at the top end of the operators 8,000 to 10,000 barrels of oil equivalent per day guidance. Later this quarter, we’re planning to drill the Winterfell appraisal well.
In Mauritania Senegal, the partnership continued to make progress across all the major workstreams during the quarter. As we noted in the release, the nearshore terminal started to take shape with three concrete caissons now installed and several more in transit. The critical path to delivery of first gas now sits with the FPSO, which is being built by Technip Energies at the Costco yard in China. We’re working diligently with BP to ensure that the revised timeline to first gas is delivered.
I’ll now hand over to Neil to take you through the financials.
Neal Shah — Chief Financial Officer
Thanks, Andy. Turning to Slide 5. As Andy said, the second quarter posted a strong cash performance on the back of higher sales volumes. We saw a reversal of the underlift position in the first quarter, together with improving realized oil prices.
I don’t plan to focus on every line on this slide but instead walk through a handful of key items. While Ghana continued 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. Both 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. 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 was slightly — rose due to slightly lower production and also due to production mix with the 10 cargoes sold in the second quarter, which has a higher opex per barrel, largely responsible for the quarter-on-quarter move. Net interest was $39 million — up $39 million was higher than the first quarter. As indicated in May, 2Q includes $15 million of one-time costs associated with the extinguishment of debt when we completed the RBL amendment to the 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. 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 list one cargo in Ghana during the third quarter and half a cargo in EG, which will lead to an underlift 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 so 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.
That concludes today’s presentation. I’d now like to turn the call over to the operator to open the session for any questions.
Questions & Answers:
Operator
Thank you. At this time, we’ll be conducting a question-and-answer session. [Operator instructions] One moment please while we poll for questions. Our first question comes from the line of Nick Stefanou with Rencap.
Please proceed with your question.
Nick Stefanou — Renaissance Capital — Analyst
This is Nick Stefanou from Rencap. Thank you for taking my questions. I’ve got two to ask if I may. I mean, the first thing is for you.
So the LNG market has reported part strongly in the past few months. So I was just wondering, are you be considering maybe a farm-down maybe like a like if I’m down in any kind of like the Mauritania Senegal assets there? Is this something that will make sense? And the second question is for Neal, it’s on the hedging policy. These three-week colors, I mean, the good thing about them is that pretty much free because don’t pretty much premium, but they don’t really protect if there is like way too much volatility, don’t give you much of the upside in reported when there’s sort of like downside. But if you think about, I mean, the diners protect, I guess, volatility.
So are you thinking of maybe changing the way you do this status going forward? Thank you.
Andy Inglis — Chairman and Chief Executive Officer
Yes. Thanks, Nick. Why don’t I take your first question? I think we’re pleased with the progress on GTA. I think the step that we announced today on getting the FPSO.
Financing has been an important step forward. And clearly, the next thing for us to work on is the NOC financing, and so we can see a direct path now to get to first gas. I think, as you look at the scale of the resource that we have in Mauritania and Senegal, more than 100 TCF of gas in place across the whole of the trend through Mauritania into Senegal. There’s clearly more there than Kosmos ever develop at its working interest today.
So I think the focus is on GTA and ensuring that we deliver the project on time, on budget, that we deliver the cash flow from the project. And actually, the important part of our phase 2 is that it’s currently not priced. And I think the opportunity to FID that project and get the benefit from a much stronger LNG environment is part of the overall plan. So I think you’re going to see us in terms of lightening the opportunity in Mauritania and Senegal, it is about how do we look at some of the more longer-dated opportunities and advance the cash flow from there.
And I think that’s our real push in Mauritania and Senegal is how do we bring forward the cash flows from the portfolio we have there. And I think that has to — that will focus there for all the things where the development plans are less well developed, and we can’t see a direct line to the cash flow. So I think that’s going to be our focus, and I think it’s no different from the strategy that we outlined to you in the past. And I think if I hand over to Neil now and he can talk about the hedging strategy.
Neal Shah — Chief Financial Officer
Yeah. Good morning, Nick. So yeah, as your question on hedging, I think for us, we have used a variety of structures within the hedging portfolio. And I think we’ll continue to do that going forward because I agree.
I think a portfolio of 100% three-way collars doesn’t provide sort of both the equity debt and the business sort of sufficient downside protection. So we have looked at balancing how to — what’s the right balance to manage the downside protection, but also the cost and retaining as much upside potential as possible. And so there’s a couple of things that we’re trying to balance in and clearly, we can get a higher floor with the lower cost of the three ways, but the two ways provide sort of absolute protection. So when you look at the portfolio today, particularly in ’22, it’s about sort of 50-50 mix between those two structures.
I think that general shape is something we’re comfortable where we can get — manage the cost of the overall hedging portfolio. But at the same time, put in protection mostly around the area where it’s needed between the sort of $60 to $40 range.
Nick Stefanou — Renaissance Capital — Analyst
OK. Thank you.
Operator
Thank you. Our next question comes from the line of James Carmichael with Berenberg. Please proceed with your question.
James Carmichael — Berenberg — Analyst
A couple from me. Just on, first, on the deleveraging chart on Slide 3, obviously, as the current oil prices. Oil prices are moving around a fair bit of times. So I just wondered if you could be sort of specific about the assumption if in that chart and perhaps provide some sensitivities.
Now then couple on the U.S. I guess, first, on Kodiak should be helpful. Just to get a bit of color around issues in that well and perhaps any early indications on the timeline to finding a solution. And then on Winterfell appraisal, and perhaps you could remind us of any sort of key risks around that deeper M4 reservoir you’re testing and put the well in context in terms of the derisking the sort of $100 million a barrel potentially, talk about in that area.
Thanks.
Andy Inglis — Chairman and Chief Executive Officer
All right. Thanks, James. I will pick up the U.S. question.
Neal, do you just want to cover deleveraging.
Neal Shah — Chief Financial Officer
Yeah. Just on the chart, just to answer your question, James. The charts have been generated based on sort of $65 to $70 deck, which I think is still pretty down the fairway in terms of current oil prices and so there is clearly a movement in there, and there’s a number of assumptions within that, which is why we sort of faded the chart. But I think the reality is, anywhere sort of in the ballpark regardless of today’s sort of negative movement in the oil price.
The business generates a lot of cash. Clearly, we’re hedged, particularly in the short be it more so in ’21. So the price movement in the prompt has less of an impact on the deleveraging profile. And we’ve got more access to that upside in ’22, whereas higher prices will help delever the business faster.
James Carmichael — Berenberg — Analyst
OK. Thanks.
Andy Inglis — Chairman and Chief Executive Officer
James, in terms of the U.S., yeah, we’re clearly seeing stronger production from Tornado than we anticipated. So we’re pleased with that well. Kodiak has not performed where we had anticipated. And we’re currently reviewing ways in which we can intervene on the well.
If I would sort of give you — our best view of that. I think it’s probably going to be around year-end into next year before we can secure the equipment that we need to actually do that. So I think in the — as you look at the Gulf of Mexico, the good news is that the strong performance from Tornado is more than offsetting the Kodiak wells. So there is a net negative from that.
And we clearly would see in ’22 the upside from getting the Kodiak well back online. On Winterfell, we’re testing the adjacent fault block to the north. We’re testing a similar horizon that was successful on the discovery well, and we’re also deepening it. The deepening would be an upside from the well, the real test is to demonstrate the adjacent fold block in the same reservoir.
It’s got the same horizon. It’s got the same seismic signature and that actually creates the sufficient volume, I think, for an initial development. And I think now we need to see the results of that appraisal well to decide is that the basis on which we move forward with incremental appraisal thereafter to do a phased development? Or is there another step in the appraisal program that results were encouraging, whereby you had a larger initial starting development. So I think it’s all positive.
And I think there’s lots of optionality on Winterfell to phase the development and also increase its scale. So we’ll be obviously interested to see the results of that well and then the discussions that would ensue with partners.
James Carmichael — Berenberg — Analyst
OK. Thanks.
Operator
Thank you. Our next question comes from the line of Mark Wilson with Jefferies. Please proceed with your question.
Mark Wilson — Jefferies — Analyst
Good morning, guys. A few housekeeping points first. On the sale and leaseback Tortue FPSO, congratulations for getting that done, firstly. But can I check the overall financing inflow you should expect for that across ’21 and ’22, please? Second point is in terms of a go-forward opex level for the group let’s say, producing at a 60,000 level through ’22, what should we be looking at there? And then finally, Tortue once on stream, what sort of opex should we be factoring in there to include the FPSO leaseback as well? Those are the three housekeeping points.
Thanks.
Andy Inglis — Chairman and Chief Executive Officer
OK. Neal, do you want to —
Neal Shah — Chief Financial Officer
Yeah. So just on this question — on the first question, just in terms of the FPSO transaction, I think what you’ll see is basically through the rest of this year post August, we will show no more sort of capex related to Mauritania Senegal until sort of the past costs are recovered. So basically, on Day 1, we’ve recorded a receivable from BP for the inception-to-date cost. And we’ll also report sort of a corresponding liability to deliver the FPSO to BP after construction.
And then the capex for Tortue gets offset against that receivable until it’s exhausted. So nothing shows up on the cash flow statement until the first half of ’22. And then beyond that, you’ll see sort of the capex related to Tortue. That excludes the portion related to the FPSO start back to flow through to the income statement.
So we’d expect around a benefit of around $200 million in terms of overall savings in the ’22 time frame in addition to the $160 million in ’21. Does that make sense?
Mark Wilson — Jefferies — Analyst
No, that’s exactly what I was looking for. That’s great, Neal. Yes. And then the second 2 points was opex has ticked up.
What would we expect that to be if we could maintain a 60,000 level and then the Tortue opex once on stream?
Neal Shah — Chief Financial Officer
Yeah. So you know, we’ve raised the midpoint of the guidance to around sort of $16.50 per barrel. I think we do have the ability to bring that down sort of $1, $2 per barrel as we sort of manage the costs within the portfolio. And actually, the production is higher by our, call it, 5% or 10%.
And so you will see that sort of rationalize back toward the mid-teens as you have both those effects coming through in terms of higher production and lower costs. And as for Tortue, we haven’t given sort of explicit sort of opex guidance post the FPSO. So I’d like to come back to you on that a bit later.
Mark Wilson — Jefferies — Analyst
OK. No, that’s fine. Then also, Neal, so working capital is quite a moving feast this year. It’s been very positive in the second quarter, but you had a very strong quarter for sales productions.
Q3 certainly from cargo looked to be quite a low sales quarter. So should we see or expect a negative working capital effect in association with that in 3Q?
Neal Shah — Chief Financial Officer
Yeah, Mark, that’s a very good question. Yes, the biggest driver around sort of our working capital timing is ultimately cargos, which again is just a function of the lifting schedules that are in each of the contracts. And so we did get a benefit in 2Q as a result of the increased cargo liftings that reverses in 3Q so you will see a drop on working capital. You’ll likely see a drop in the third quarter, which reverses in the fourth quarter.
And so there is sort of the unfortunate lumpiness due to the oil price and the cargo sizing, but it does sort of even out over the year.
Mark Wilson — Jefferies — Analyst
Got it. OK. And then one last point. This is more a broader one that just struck me as we were thinking about this.
I’m just wondering why it is the FPSO is fit for the sale and leaseback scenario. And then FLNG vessel may not be or maybe it is. What’s the difference there?
Neal Shah — Chief Financial Officer
Actually, it will be treated similar to the FLNG. The FLNG, we just started as a leased project. So Golar is the operator, and they can lease it to the JV. This had started a piece of equipment within the partnership that we’re switching to sort of a lease arrangement.
So now it will be accounted for similar — basically the same as the FLNG, will be a sort of opex in the future.
Mark Wilson — Jefferies — Analyst
And now you mentioned it, it makes complete sense. OK. Thank you very much. I’ll hand it over.
Neal Shah — Chief Financial Officer
Great. Thanks, Mark.
Operator
Thank you. [Operator instructions] Our next question comes from the line of Neil Mehta with Goldman Sachs. Please proceed with your question.
Carly Shavel — Goldman Sachs — Analyst
Good morning. This is Carly on for Neil. Just wanted to start on the cost side. I know you mentioned the higher opex guide.
Can you just talk about the drivers there? Is that inflation-driven? Or are there other factors at play? And then I guess, what are you looking at to potentially manage costs going forward?
Andy Inglis — Chairman and Chief Executive Officer
Yeah. Carly, maybe I’ll talk about that, and then Neal can also chime in. I think the quarter was a little unusual because you get variability in the costs because of the nature of when the liftings have occurred. There was a 10 cargo in 2Q.
So it actually comes with a higher opex per barrel. There’s a lease cost associated with the FPSO there so it’s naturally higher. So we have that variation in the quarter. We also had sort of strong production in Tornado.
Tornado’s PHA actually has a price factor associated with it. So we’ve obviously got the benefit of the higher prices. but we also saw a slight rise in the PHA. And obviously, if prices persist at the current levels, that would continue.
And I think underlying, I’d say, there’s a small sort of what I would call underlying structural element to it and that’s ultimately just about the challenges of getting things done in the COVID world. We have some continuation of some of the COVID measures now as a result of Delta. But I think we’re getting much smarter about how we manage those and how we reduce the cost by using more sophisticated protocols. So I’m less worried about that.
And I think the thing that you should sort of look at is just the quarter had a couple of one-offs associated with it, which, in particular, the TEN cargo.
Carly Shavel — Goldman Sachs — Analyst
Great. That’s really helpful. Thanks. And then the follow-up is just on Tortue financing.
The release mentioned you guys expect to complete the refinancing of the NOC loans later this year. Could you just talk a little about what’s left outstanding in that process? And if there’s any milestones that we should be watching for?
Andy Inglis — Chairman and Chief Executive Officer
Yeah. And well I’ll have Neal pick that up, Carly.
Neal Shah — Chief Financial Officer
Yeah. So I mean, the main thing that we’re waiting on for the NOC financing was really the completion of the FPSO because obviously, it sort of shapes the cash flows of the project. And so we’ve had some initial conversations with the banks, and we’ll push that now. We have sort of defined structure around the FPSO.
And so our best view on sort of timing is to get that done in the fourth quarter, which gives us plenty of time to go execute it.
Andy Inglis — Chairman and Chief Executive Officer
Yes. I’d say, Carly, we’re just sort of moving — we’re executing on what we state would do. The other most important step was to get the FPSO financing done. We’ve done that.
We’ve got the NOCs on board with that. So we have alignment with all of the parties. With that in place, we can then move to the next item, which is the refinancing of the NOC loan. So I think everything is going along as we anticipated.
Carly Shavel — Goldman Sachs — Analyst
Great. Appreciate that color. Great. Thanks.
Operator
[Operator signoff]
Duration: 35 minutes
Call participants:
Jamie Buckland — Vice President, Investor Relations
Andy Inglis — Chairman and Chief Executive Officer
Neal Shah — Chief Financial Officer
Nick Stefanou — Renaissance Capital — Analyst
James Carmichael — Berenberg — Analyst
Mark Wilson — Jefferies — Analyst
Carly Shavel — Goldman Sachs — Analyst
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