Genel Energy plc (GENL) Earnings Call Transcript & Summary

Hello, and welcome to the Genel Energy Half Year Results Call. My name is Rosie, and I'll be your coordinator for today's event. Please note, this call is being recorded. [Operator Instructions] I will now hand you over to Bill Higgs to begin today's conference. Thank you.

Good morning, ladies and gentlemen. I'm Bill Higgs, CEO of Genel Energy, and I welcome you all to our 2021 half year results. I'm joined as usual today by Esa Ikaheimonen, our Chief Financial Officer; Paul Weir, our Chief Operating Officer; and Mike Adams, our Technical Director. We'll run through the presentation, and then there will be an opportunity for analysts to ask questions. I'm going to start by showing you a couple of slides demonstrating our focus on delivering our strategy and keeping our promises. Our strategy remains simple, albeit delivering on it takes a lot of hard work. We aim to generate cash, investing growth and return excess cash to shareholders, with an aim of growing all 3 sustainably. And this is what we've achieved in the first half of the year. Our production is always low cost. And this year, the override resumed and oil price increased, and so too did our margins, the cash per barrel that remains after allowing for OpEx and CapEx to produce, helping us generate material cash flow from our production assets. Once again, our production assets' cash flow this year is being invested in production and importantly, growth. We have 4 high-impact wells being drilled in the second half of the year that can all make a very positive difference to the future of Genel Energy. Such is the strength of our production asset cash generation and confidence in our prospects, we have announced today an increase in our interim dividend, fulfilling our aim of making it progressive. Inseparable from our strategy for creation of shareholder value is our focus on ESG. This starts as ever with safety. Our record here remains exceptional, and I take this opportunity to pay tribute to all the staff across our operations for remaining vigilant in their focus on keeping themselves and others safe. We have rapidly scaled up our operating capabilities, having gone from being a joint operator at 1 asset to having boots on the ground at 3 assets within 18 months. And now we have active drilling at 2 of them and will soon be operating our third rig. It is a testament to our efforts at embedding excellence into our culture that this expansion has taken place while retaining our strong ESG performance. The importance of ESG to Genel can be seen in our second annual sustainability report, which I'm pleased to say has been issued today and is available on our website. We are aware that we are on a journey, but we are proud of what we have achieved so far. We also believe that we're doing a lot better -- a much better job of telling investors over the focus that we have on delivering on our purpose to be a socially responsible contributor to the global energy mix. Our second sustainability report, which is GRI-compliant, details our commitments across a range of areas, not least our greenhouse gas emissions. Gas reinjection continues at Tawke, and this ensures that our carbon footprint remains materially ahead of the industry average. Our assets are aligned with the goals of the Paris Agreement, and we are committed to achieving net zero by 2050. The report also details the material benefits to society that we aim to have as we continue to produce the right barrels with the right footprint in the right areas. We see this as a fundamental to ensuring our business model and strategy can stand up to the challenges that the sector faces in the coming years. So back to the pillars of our strategy, the first being the necessary pillar of what must be achieved as a business, cash generation. Our production has increased in line with guidance, driven by the ongoing strength of Peshkabir's performance. While the pilot production at Sarta, despite not reaching the early volumes we had hoped, has offset declines at Taq Taq. There's more to come from Peshkabir in the second half of the year with ongoing work at the field set to see 2 more well completions and 2 new wells drilled. We also expect drilling to resume at Tawke with 5 wells scheduled for the second half of the year. We hope that the new Sarta-1D well can also be on production before the end of the year which should see our exit rate production higher than the average for the year, which promises further good things for 2022. The cash flow our production is generating supports material investment in our growth assets. There's a lot to come in the second half of the year with 4 high-impact wells to be drilled, 2 of which are underway. The QD-2 well has been drilling ahead since April, and Sarta-5 for a number of weeks now. Results from both can be expected in late Q3 or early Q4. Mike will shortly give a deep dive on what we've learned from Sarta over the last 8 months and something of what we can anticipate from our exciting appraisal program later this year. Once we've drilled these 4 wells, we will know a lot more about the potential of the existing oil resources in our portfolio, and we'll be able to set the path forward for those assets. In addition, of course, we also have gas resources. Bina Bawi still had an enormous unfilled potential. Having been close to an agreement with the Kurdistan regional government almost 2 years ago, it has proven frustratingly hard to align with them on how to move the project forward. We're still seeking approvals to undertake the FEED studies and other work needed to define the project prior to an investment decision, and we'll keep trying. But we'll only spend shareholder money when there is a clear route forward and good prospects for recovery of that investment. Work being done to realize the potential of the portfolio in the second half of the year means that our capital expenditure is heavily weighted towards H2. Despite that, such is the high margin of our production at the prevailing oil price, we expect to generate free cash flow and end the year in a net cash position. This allowed us to boost our first strategic pillar, returning of cash to shareholders. Over to Esa for more.

Thanks, Bill, and good morning to you all. Before I provide the financial update for the period, I wanted to briefly remind you how we think about capital allocation as part of our business model. The value proposition of the business model is to deliver consistent returns and value to shareholders and to do so through cycles and in spite of the challenges faced frequently by the sector. But first of all, a reminder building on Bill's comments on ESG that in order to stand up to the challenges the sector increasingly faces, we commit to barrels that are low cost, low carbon and operations that deliver material societal benefits. As you already know, when we allocate capital, we prioritize investment in the Tawke PSC, where the expenditure is generally recovered within a month through the PSC mechanism and where each incremental barrel we produce delivers an exceptionally high margin in return. And we look to invest in growing and diversifying our production and reserves. And this year, that means we are investing principally in reserves through our appraisal wells at Sarta and Qara Dagh. Then importantly, we continue to commit to a sustainable and progressive dividend. We don't want to put capital at risk if we don't see it coming back to us quickly enough or it doesn't have the right risk/reward balance. This means 2 of our projects with very big potential have not seen material investment for a while. Investment in Bina Bawi requires the right conditions and commercial framework, which so far we have not been able to agree with the KRG, as Bill already mentioned. Exploration at Somaliland needs the right partners and funding. And then some way behind those, the third one, Morocco, requires the same. We will continue to be disciplined on all 3 of these longer-dated projects. Bill has already talked about production, which has increased a little year-on-year in terms of barrels, but has improved considerably in terms of the dollars that those barrels generate. In fact, the producing asset margins tripled to $111 million compared to $35 million in the first half of the year -- sorry, first half of last year, I should have said. Obviously, oil prices made a big difference. In addition, Tawke has recently benefited from the return of the override. Thirdly, Sarta revenue per barrel is very high, higher than Tawke, in fact, because it is at the early stages of the PSC term and also because we recover an elevated 50% of costs, including very significant back costs, in line with our paying interest commitment versus our 30% equity ownership. Sarta margin will further improve as production increases and matches the capacity of the processing facility. Increased production will also reduce OpEx per barrel, expected to be around or below $5 per barrel. As you can see from the table, that production asset margin of the $111 million converts into free cash flow before investment in growth of $62 million, which includes positive impact of payments for deferred receivables of $14 million. Just to add some perspective, we received only 4 repayments during the period, so we expect more in the second half. It also includes one-off negative impact of KRG, changing the payment terms and moving from 1 month in arrears to 2 months in arrears, which had a $30 million adverse impact on our cash flow for the period. A lot of that $62 million of free cash flow has been put to work on Sarta and Qara Dagh, and Mike will talk about the technical side later, but from an economics point of view, if there is scale as we expect, then the high revenue per barrel that I referred to earlier will mean that those would become very valuable high-margin future barrels and fields. As you can see, that leads to an overall free cash flow of $22 million at the half year. In summary, a highly cash-generative production business that clearly supports growth investments as well as an increase to the dividend. So today, we announced a 20% increase to the interim dividend from $0.05 per share to $0.06 per share. This is our usual liquidity sources and uses waterfall. Opening liquidity on this chart on the left is shown after the $81 million settlement of the remaining 2022 bonds, which were called in December 2020 and which we consider to be part of the refinancing work that took place in 2 stages last year. With that refinancing, we moved the maturity of our entire debt out to 2025. Overall, you can see we have a nicely balanced picture of sources and uses with small net debt position and an additional $145 million of overdue receivables, which I come on to on the next slide. As to the guidance for the full year, having spent about $58 million in CapEx during the first half, we will ramp up our spending during the second half of the year and expect a full year CapEx around the middle of our original CapEx guidance of $150 million to $200 million. The other elements of our 2021 guidance remain unchanged. Further regarding outlook. Despite materially increased capital expenditure in the second half, we expect the same picture to be balanced again at the end of the year with that small net debt position moving to net cash so long as we receive the 6 KRG payments due for the period. This means that we are not capital constrained regarding the future development of our priority projects at Bina Bawi, Sarta and Qara Dagh, nor the progression of the dividend. We have referred to outstanding payments regularly. So I thought we should have a slide on our overdue receivables. At period end, we are owed a total of $145 million by the government, a bit down from the $159 million at year-end 2020. On deferred receivables alone, which is money owed for export sales from November 2019 to February 2020, we started the period with a balance of $121 million owed and received $14 million from 4 payments. So we are now owed a net of $107 million. At current oil price and flat production in the second half, we would earn another $28 million with the actual cash received a month or 2 later. In addition to the money owed for export sales, we're also owed $38 million for the suspended override from March to December last year. Current position is that the same mechanism as above pace is back as well. So we've receive suspended override money after we have received $107 million owed for export sales. A total of $145 million of value owed is obviously a big number and one that we are extremely focused on. We are fully confident about receiving full payment for these arrears, but are working to improve the terms of such repayment. That effect, we have had conversations with the KRG, and we have made a commercial counterproposal, which we believe is fair and very reasonable. They have not formally responded to our proposal yet, but have committed to refining the mechanism. So we hope to see what that refinement looks like in the near future. And now I hand over to Mike, who will give an update on those exciting growth projects on which we are putting our capital to work and which we hope to be expanding in future years. Over to you, Mike.

Thanks, Esa, and good morning, everyone. So let me talk a little about the 2021 journey to date and the road still to come with respect to our organic growth portfolio. Starting with a big picture view of the various elements of the Sarta project. And as you can see, that picture really is on a very large scale. The current pilot production project centered on the 2 existing wells, S-2 and S-3, and the early production facility somewhat dwarfed by the potential scale of the development about to be tested this second half of 2021 through the appraised program of 3 wells, notably the S-5 and S-6 appraisal wells, 14 kilometers and 7 kilometers, respectively, from this Phase IA pilot hub. I'll come on to talk about these individual elements of the project, representing the P and the A of our paddy philosophy, but staying firstly with that big picture theme. One notable piece of technical work out with the ongoing operations which had a significant impact on the potential scale of the project and specifically the size of the Sarta container is a detailed reevaluation of the seismic depth conversion and associated reinterpretation by our partner, Chevron, and adopted by the joint venture for well planning purposes. This work resulting in a revised and more robust velocity model, incorporating offset well data not originally available to Genel, has resulted in a significant upward revision to the gross volume associated with the field i.e., the size of the container. What you can see from the illustrations on the slide is that this is a function of a change in container shape. In simple terms, a transition to a shallower, broader structure with more gently dipping flanks from the legacy interpretation. And with that, an associated increase in gross rock volume, the implications of which from a resource perspective, I'll come back to you shortly. Okay. So let's zoom in now on the pilot production project? Let me start with the usual reminder that Phase 1A is a low-cost pilot development of 34 million barrels of 2P reserves from the Mus-Adaiyah reservoir, initially by 2 existing wells, S-2 and S-3, with crude processed in a rental early production facility prior to being trucked to Khurmala and the export pipeline. So cash-generative, high-margin production for which the downside is protected and the upside frugally planned for. So where are we now? And what have we seen to date from the pilot project, 8 months from first oil in November last year? Production has, as Bill mentioned, been a little disappointing to date. But it's important that we look beyond such early results to the bigger picture. Production averaged over 7,000 barrels of oil per day in the first half of 2021, with June seeing the highest average monthly production in the year-to-date at 8,400 barrels per day, following the maximization of uptime in the month. Of this production, the Sarta-2 well produced circa 6,400 barrels per day, and the Sarta-3 well circa 2,000 barrels per day, with the latter having been partially and temporarily plugged back to manage water ingress from the Adaiyah production stream, the origin of which is yet to be determined. With production temporarily limited to the thinner, less volumetrically significant Mus reservoir, a fall in reservoir pressure in June across both wells resulted in Genel and the operator, Chevron, reassessing the optimal way to produce these wells ahead of the addition of production from Sarta-1D, a well set to access production from the entire Adaiyah reservoir section for the first time and via a smart completion. Reservoir surveillance work at the start of the year had already proved strong communication between the Mus reservoir in Sarta-3 and in -- and Sarta-2 over a short distance of circa 3 kilometers. Pressure data suggests that 2 wells constitute a portion of the container more limited than our expected extend of the Mus reservoir. So think of them as potentially representing a container within the overall much larger container, a relative postage stamp, as you can see from the cross section. Connected volume in the naturally fractured reservoirs of the KRI, especially in early production life is, of course, a common theme and as such, not one to be overly concerned about at such an early juncture. In order to analyze Mus pressure data and provide valuable learnings for longer-term field production, the Sarta-3 well was taken offline at the end of June for data gathering purposes. Since then, Mus pressure decline at the Sarta-2 well has in response, slowed considerably, potentially indicative of secondary pressure support and associated oil influx kicking in. To prudently manage the reservoir and associated production from the pilot facility until Sarta-1D comes online around the end of the year, the joint venture partners plan to continue to manage the offtake from the thinner Mus. Once we have Sarta-6 in success added to the production mix, now expected around the end of Q1 next year, our well stock will be up to a healthy 4 wells, giving us many more levers towards greater production management flexibility. And in the meantime, we'll take the opportunities available to us to gather more invaluable data from the S-2 and S-3 pilot to inform both our short-term strategy and our longer-term planning. So in essence, it's still very early days. Much of the pre-first oil uncertainty that the pilot project was designed to inform us on remains as yet unresolved. The pilot continues to deliver its dynamic data part of the paddy philosophy ahead of its twin, the appraised element, which has only just commenced. And only together can they properly inform Genel and Chevron of the optimal field development plan. So let's look at the eagerly awaited 2021 program and what implications these early pilot learnings have for it. In short, not impacted at all. The appraisal program was always designed to complement the pilot by gathering different information, i.e., the aerial and vertical extent of the Mus and Adaiyah accumulation up dip and down dip, whilst appraising for and flow testing the other Jurassic reservoir intervals contributing to the 250 million barrels of Jurassic contingent resources, along with prospective resources in a deeper formation. Preparations for Sarta-1D and the construction of a flow line linking it to the facility are well underway. Clearing the right of way is nearing completion and the Viking Rig is mobilizing to the location ahead of spud in the coming days. The Sarta-5 well was spud in June is currently drilling ahead at circa 2,100 meters in the cretaceous overburden with results expected in Q4. And this will be followed immediately by Sarta-6 drilled with the same rig with results expected by late Q1 2022. In a success case, Sarta-6 will then be brought onto production in short order via a flow line back to the facility, while Sarta-5 will be produced via a stand-alone temporary facility given its distance from the EPF with year-end 2022, the target. These 3 2020 wells -- 2021 wells will, of course, test the seismic reinterpretation work and associated mapping. To date, the actual formation talks from Sarta-5 are very much corroborating that new work, which is great news. Whilst pilot production utilized the 2 existing wells in the crest of the structure, inheriting their trajectories and completions and enabling us to start monetizing the asset without the additional CapEx burden of drilling new feedstock wells, the completion strategy for all 3 appraisal wells is the installation of a cementless multi-zone completion over each of the Jurassic reservoirs, allowing for individual zones to be accessed or shut-in for production management purposes. In the case of the Adaiyah, this is particularly valuable given the interbedded nature of the formation. It consists of 6 discrete reservoir zones, each capped by sealing and hydrates known to result in stack separate hydrocarbon accumulations in fields elsewhere in the KRI. What this means is that if the water we're seeing is from the reservoir and not from deeper, either mechanically, so a leaking plug from the base of the S-3 well or geologically a fault accessing deeper water, both of which remain possibilities at this stage. We will be well placed to manage what is essentially a very conventional production management issue with the appropriate levers. Continuing that theme of impacts and implications, this time with respect to reserves and resources. Our booked 2P reserves remain unchanged. If anything, the early results are suggesting that perhaps more wells will be required to deliver the relatively modest net 2P 10 million barrels of booked volume. So the pilot is doing its job, informing future investment decisions. Whereas on the contingent resources side of the ledger, the extent volumes are very likely to increase regardless of success or failure of the 2 step-out wells as a consequence of that new mapping. The magnitude of that increase, obviously, dependent on those well results. Okay. Changing gears now to Qara Dagh, a step further back at the exploration and appraisal end of the spectrum, drilling of the pivotal QD-2 well commenced in April, still very early in the piece. So not really a great deal to add to what we said previously pre-drill. The exciting bit is still to come. To recap, the well is appraising the crest of a 50-kilometer long structure at Qara Dagh, around 10 kilometers from the location of the QD-1 well, the only other well drilled on this huge structure, a well, which 10 years ago flowed light oil to surface to give a flavor of the potential price hidden under the Black Mountain. Armed with the learnings from that legacy well and much above drilling techniques and strategies, this challenging well geologically and operationally is currently at a depth of circa 2.5 kilometers, still within the overburden section, with results still anticipated around the end of Q3 2021, in pursuit of converting a further portion of the 400 million barrels of prospective resources into the discovered resource category. We continue to tread gently and collaboratively in this environmentally and socially sensitive area with our social and environmental conscience thoroughly backed up by our actions. Active social investment in the communities adjacent to us, direct employment of over 200 people from the local population and rigorous environmentally-friendly practices at the rig site and support operations. Finally, a few words on the exploration end of our preproduction portfolio, specifically in Somaliland, a project that we continue to see as an exciting growth catalyst through a longer-term lens of resource build and reserves replacement. Whilst our existing business more broadly is clearly not exploration-led, and our focus is on discovered resources, this legacy asset remains in our portfolio for very good reasons. More than just romance, the prospectivity here remains compelling with high impact resource potential in multiple stacked prospects with the opportunity to target more than 500 million barrels of prospective resources with 1 well at the Toosan prospect alone. Having preserved our optionality at minimal capital outlay over a number of years, the next step remains to bring in a partner ahead of committing to drilling a well. To which end, we are currently actively engaged with potential investing partners. So with that summary of progress to date along our 2021 organic portfolio journey and the exciting growth catalyst to come this second half of the year and shaping the years ahead, let me bring Bill back in to wrap the presentation up.

Thank you, Mike. So to sum up, we have a tremendously exciting few months ahead of us. The increase in oil price and our low cost means that our producing assets will generate material cash flow, more than covering the cost of our high-impact exploration -- high impact wells. Results of these will come through thick and fast as we move towards the end of the third quarter and can help signpost material growth for Genel. We look forward to updating you on our progress. And now I'd like to open up for questions.

[Operator Instructions] And the first question comes from the line of David Round from Stifel.

Three questions from me, please. I suppose the obvious place to start is Sarta and the water ingress. I think you mentioned a couple of reasons as to why this may be happening. But would you mind just going back and setting out a bit more clearly your early thoughts around the water and then when will you actually be able to get the bottom of this issue? Jumping to Peshkabir, wouldn't mind some comments on the reasons behind the strength there. Is that just IP rates from new wells? And then maybe just any thoughts on possible reserve revisions there. And finally, there have been some press reports regarding flaring in Kurdistan. Would you mind just commenting on that, and what that means for you?

Thanks, Dave. What I'll do is I'll get Mike to answer the Sarta question, Paul to answer the Peshkabir question. And maybe what we'll do is I'll start with -- actually with the third question and just talk a little bit about the gas. I think the key thing here is, David, as you know, we're focused on emissions over the life cycle of our assets and aligning with the Paris Agreement to make sure that our assets remain best-in-class today and into the future. And we factor all of this into our asset development plans. And we're working -- continue to work very closely with MNR in the past and today on how to achieve this sort of best-in-class environmental management. Maybe a little bit more details, Mike, you can talk specifically about Sarta and then link into the -- Dave's question about the Adaiyah water.

Yes, sure. David, let me do that. I'll perhaps answer this a bit more holistically just to help pull the threads together, conscious, I shared a lot of detail with you there in the presentation. So the facts are that we saw water earlier, and we saw pressure decline faster than anticipated from parts of our pilot reservoirs. But breaking this down logically and rationally, there's a few points to make in conjunction, I think. It's still very early days. So as I said, much of the pre-first oil uncertainty that the pilot project was designed to inform us on that remains as yet unresolved. Specifically on the water, if the water is from the reservoir, which I think is far from certain still and if so, potentially from a part of it only, as is the case in other KRI fields, we simply need to be prepared to process and dispose of it to maximize recovery. So some additional spend to deal with what is ultimately a very conventional production management issue. Further data gathering is ongoing and that will involve things like production logging tools in the existing wells. And of course, Sarta-1D well with its smart completion is going to be a well which will allow us to interrogate the origin of that water in a lot more detail. And then we've got strategizing ongoing to the effect of dealing with water right now, such as a low cost conversion of the old S-4 well into a water injector. So we're giving ourselves maximum ground cover going forward to deal with that. On the pressure decline, the faster than expected pressure decline, as I've said, it's suggesting that our connected volume that the 2 pilot wells are tapping into is less than our expected extent of the container, the reservoir container. Again, perhaps not a huge surprise in these fractured reservoirs where connectivity is commonly baffled. The learning though is a very straightforward one. We'll potentially need more wells to recover the reserves and resources. But on the flip side, the Mus pressure decline has slowed considerably in response to the reduced offtake, and that's potentially indicative of secondary pressure support and oil flux kicking in. And then overall, of course, the discovered resources do look set to increase in the next reserves and resources cycle as a consequence of that increase in the gross rock volume. And finally, and very importantly, and I think it was stressed a few times in the presentation, we really can't treat a pilot in isolation. We've only just started the appraised program. That's a program which not only will tell us about the Mus and Adaiyah, but also will flow test all of those other Jurassic reservoirs and complete them for future production optionality. So apologies, that's a bit of a longer question probably -- a longer answer than you wanted to the question. But I think given that there's a few threads here, which need to be pulled together to kind of give us the state of play right now, but hopefully that answers your question, David.

Mike, would you like to also -- Mike, do you want to also comment on the gas management strategy for Sarta zone.

Yes, yes, let me do that. So on gas management, our gas management plans for Sarta, they effectively remain unchanged. So the content of the recent MNR letter that I think people are aware of is not too different from what's in our PSCs nor, I would say, in our plans already. So Tawke and Peshkabir clearly are in great shape, as you know, courtesy of our gas injection project. At Sarta, as part of our approved field development plan, we have ministerial dispensation to flat for at least 3 years after first oil, which is the time -- which the time frame the JV have been working to. It's really -- it's an absolutely embedded part of our asset development plan. We're carrying out feasibility studies this year for a gas injection option, which actually has always been our preference, and that's with a view to entering a defined phase, i.e. tendering and FEED next year. The economics behind -- the economics of it all are a little bit chicken-and-egg situation, as you can imagine while we evolve our understanding of the scale of the development through the ongoing pilot and appraised program. But we -- yes, we feel pretty well set in the context of gas management in respect of our assets.

Thanks, Mike. Maybe, Paul, you can add a little bit of color to the performance of Peshkabir, and what we might expect later in the year.

Yes. Thank you, Bill. There isn't a great deal to talk about in terms of reserve revision. We don't anticipate revising our reserves for Peshkabir currently. The current super performance really is, as you -- as the question I suggested around excellent productivity from the wells that we have there, and as Bill mentioned at the start of the piece. There is still quite a lot of activity taking place in Peshkabir in the second half of the year. We're in the process of completing 2 wells campaign, and there are 2 more wells to drill there before year-end. So we anticipate the current production levels to remain fairly flat for the remainder of the year.

The next question comes from the line of Teodor Nilsen from SB1 Markets.

Three questions from me. First, you said that you had made a commercial proposal to KRG for a new payment mechanism. Just on -- could you shed some light on what we should expect? Are we talking about a change to the 20% of the revenue above $50 per barrel? Maybe it can get up to $50, again? Or what should we expect in terms of a new payment mechanism? And second question is on Sarta. Thank you for the very detailed update, that's useful. Just wonder what we should expect in terms of exit rate production for 2021? And also third one, a similar question on Qara Dagh. You said that you anticipate results from QD-2 during third quarter. But when should we expect then kind of first oil for commercial production?

Thanks, Teodor. I'll let Esa pick up on the first, and then Mike can answer the Sarta and QD questions.

Yes. Teodor, thanks for the opportunity, good question. I don't want to go into too many details regarding our counter proposal. It's very much work in progress. And I think as and when discussions mature with KRG, then that will be the right time to be a bit more detailed. But there's just 2 things. KRG themselves undertook to reconsider their most recent proposal. That's an industry-wide suggestion. And secondly, given the fact that, particularly the time to full recovery in our case and in our view, is simply too slow. We have proposed a couple of rather straightforward mechanisms that would improve the recovery and particularly the timing to full recovery in our particular case. So there's kind of 2 elements there -- proposals, which we put forward a couple of months ago. And then an industry-wide undertaking by the KRG to kind of rethink and look for ways to slightly improve the situation. But in either of these 2, I think the expectation is that the 20% will probably prevail.

Mike, do you want to...

Yes. Yes. Yes, let me take that.

Yes, Sarta and QD.

Yes, Yes. So on Sarta, on the kind of short-term production piece, I think just to reiterate what I said during the presentation from a 2021 perspective, we're taking a very prudent approach to reservoir and production management. And as I've said, it's very commensurate with the project being a pilot and at such an early stage and commensurate really with our resource to be data driven, and that includes gathering valuable data for the long-term good at the expense occasionally of short-term barrels. We've talked a little bit about what the production -- the current production figure is. I think if you work along those lines as being something around that for an exit rate for 2021, I think that would be reasonable.

Do you want to comment, Mike, on expectations of when we might have S-1D and S-6 up and running in the S-6 success case. Just remind people of that.

Yes. So S-1D is obviously a well that we're looking -- yes, let me talk a bit then more about the longer-term guidance, which obviously is something that we set out in January, but we're careful not to get ahead of ourselves. And that means, as Bill alluded to there, it means looking at this on a very well-by-well basis. S-1D, we're looking for that to be added to the mix around the end of the year. That has the potential to add production along the lines of what you're seeing at the moment from the S-2 well, for example, so that S-2 well currently producing on a stand-alone basis from a single thin reservoir. And then a little bit further ahead for S-6, in 2022, is looking to get that well tied in towards the end of the first quarter of 2022, into the existing production facility. S-5, a little bit further down the line given that's further away and it needs its own temporary production facility. But -- so we're looking to be adding that into the mix towards the end of 2022. But as I said, by the end of Q1 of next year, we'll have 4 wells, and that will give us many more levers really in terms of our production from Sarta.

And on QD, Mike, could you just talk a little bit about the way forward on the success case?

Yes, I think -- so the question there really wasn't -- it was around -- if I can remember, short-term memory already. Yes, it was around how quickly we could get QD on production in a success case, I guess. So we're already in the process of assessing a number of potential concepts. Given the size of the structure, we would likely drill a follow-up appraisal well in pretty short order, so we'd be thinking circa end of 2022, so that we were armed with 2 wells as feedstock into an early production pilot. And from there, we'd be looking to take that down -- take Qara Dagh down its own paddy route. The nature of the fluid we're anticipating there, so low to no gas oil ratio and H2S that we've seen from the historical well QD-1. If that's confirmed as part of us concerning commerciality through the QD-2 well, that certainly will help in terms of expediting early production.

Thanks, Mike.

So then in terms of commercial production, are you talking about 2023 or 2024?

No, I think we -- I think -- no, 2024, I think, is potentially looking too far ahead. We'd be -- there are a number of things we need to be weighing up here, and it's the -- it's a little bit of the balancing act between what we always knew would be the key to Qara Dagh was flow testing and getting early production data again so that we're gathering that dynamic data versus the convention, if you like, of drilling appraisal wells to prove up volume. What we're anticipating is potentially a little bit of both, where we want a further appraisal well, which gives us additional feedstock. But there is a possibility that later next year, we could be looking towards piloting production from the existing QD-2 well, potentially whilst we're in the throes of drilling another appraisal well to add to that. So it could be that, that lens is a bit shorter term than the one you're than you're thinking of there.

Okay. Understood. And just -- and finally, just to confirm. You said that you expected a 20% ratio to prevail. Is that correct?

Well, that will be, I think, a fair expectation. Now as I said, there are 2 components here. One is that the KRG themselves undertook to reconsider sort of industry-wide their own proposal. Now it's difficult for me to kind of anticipate as to what they might want to suggest. So it's possible, of course, that they would increase that percentage from 20% to something else. But that's speculation until we hear back from the KRG and from the minister, particularly who personally made this commitment towards the industry. In terms of our proposals, we kind of see this percentage as being an industry-wide issue, but we've got a couple of issues that are very Genel specific, such as the override -- treatment of the override. And as I mentioned, the override recovery -- the suspended override recovery, the $38 million, that I mentioned is at the back end of the Q now, which means that it gets recovered really late. So it's quite obvious that we've got an interest in looking for ways to accelerate that. So that's an example as to what sort of things we are looking with some more company-specific rather than industry-wide. The percentage is really an industry-wide issue, and it would be much better if KRG would reconsider that percentage for the entire industry rather than on a company-by-company basis. So I think that -- I hope that makes sense.

I think it's also fair to say that we'd be very content if the KRG as was also to return and agree that there is a cost of capital for their debt and put interest on it, we'd be awful lot more content.

Yes, that kind of relates to the issue of late re period, if you like, or so if you think about repaying -- if you get it back in a year, you're less worried about cost capital than if you get it back in 3 years or 4 years. So there's sort of components that need conversation and discussion and negotiation with the government, and we're obviously pursuing those because it's a big deal for the company and our shareholders.

The next question comes from the line of Nick Stefanou from RenCap.

It's Nick from RenCap. I've got 3 to ask as well. I just wanted to go back to that, let's say, KRG sent on the 13th of July. I want to get a bit more clarity on how to interpret that because I mean, they're saying 18 months for flaring to stop. What does that mean? Is this like routine flaring? I mean does it like differentiate between which stage you operator is in their kind of like the development lifetime? And then is this really compatible with the way development is secured on this pilot appraised produce model that really makes developments sort of like gradual, careful and really spreads out CapEx quite a bit like over the life cycle of the development as opposed to having a pickup from sort of like cost with -- maybe some of the offshore assets? That's the first question. The second one is -- actually, they are both for Mike. Mike, did I hear you correctly? Did you say the well stock in Sarta is 34 wells. So is that -- is this the amount of wells to recover, what is like, like 250 million barrels 2C resource? And then the third question, just on the water cut in at the Mus reservoir there. I'm just wondering how to interpret that in terms of like materiality for the entire of Sarta? Because from the looks of it, Mus is not that material for Sarta in general. Is it more -- should that be kind of like -- is it more like noise where most of the resource would be in the Adaiyah and the Butmah reservoirs?

I'll pick up on the gas comment, and then I'll let Mike pick up on the well stock and water point. So again, I think the starting framework for all of the conversation on gas and this recent letter from MNR is that the PSCs themselves actually recognize the expectation that we should move to non-routine flaring as part of the development of the assets. And that, as Mike explained earlier, in the context of Sarta or as we've talked about the context of Peshkabir and Tawke that we're able to put in place strategies in agreement with MNR that enable routine flaring for short periods of time while you're able to get the gas management strategies in place. And that's what we did at Peshkabir, and that's what we have approval with MNR to do at Sarta. So we see very much the fact that, one, we're in compliance with the expectations of the letter from MNR, but also that we've been very much leading the way with our pilot DNO at Tawke in implementing the first sort of non-routine flaring reduction project, which has been very successful because it's also an enhanced oil recovery project at Tawke. And we expect to move forward on that basis at Sarta as well. So I think it's really more an expectation of restating the government's position with respect to the desire to eliminate nonroutine flaring as part of the operations and field development plans going forward. And that's clearly been -- again, clearly been a stated position for KRG for a number of years.

No. But thing is that pretty much every operator in Kurdistan has some sort of like gas management program in their plants. And that you did mention Tawke, but I think you started this reinjection maybe 10 years after maybe the field like reached 100,000 barrels per day. So if we're talking -- if you -- like Sarta, this thing could be in many, many years, maybe been a decade from now.

So if you -- sorry, if you look at Peshkabir, so Peshkabir where we take the -- because Peshkabir has got high GOR and Tawke and Taq Taq may have really very low GOR fields, which is part of the -- sort of because of pilot gas management plan in themselves because you've got very little gas coming to surface. And so Peshkabir, we actually started the gas reinjection project 18 months after the start of production, which was consistent with the agreement we had in place with MNR. And then simply what we're looking to do with Sarta, as Mike alluded to, as we have in our field development plan an approved program to establish a gas management strategy, consistent -- as you said, consistent with the paddy philosophy, which makes tremendous amount of sense from a capital management point of view and very much something that we've learned from these tough reservoirs in Kurdistan, which is it is very helpful and useful to do some early pilot production work to understand the full extent of the reservoir before optimizing your field development plan, and therefore, also optimizing your gas management strategy associated with that full development plan. And in fact, actually also just -- we actually have a second phase of the gas management strategy in the Tawke PSC, which is to collect the -- so the produced gas at Tawke and reinject that, and that project is in -- it's currently in for approval, has yet to be approved by MNR.

Let me tackle the other bit then, Bill. So yes, on the well stock, I think you misheard me there. I wasn't -- yes, I didn't -- I wasn't making any comment there on the future -- on future number of development wells. Next year, we'll have a series of -- rather than a single financial investment decision on development wells. It's really more a series of investment decisions starting early in the year with things like long lead items for those development wells and then later in the year on the wells themselves. So yes, apologies if that was the case, but no, I wasn't talking about numbers of development wells. And then on the water, Nick, my -- yes, mainly -- I was really mainly there talking about the Adaiyah formation. So interestingly, given the interbedded nature of that formation that I was describing with some of these stacked reservoir intervals with ceiling anhydrites in between, it wouldn't be a surprise, for example, if that water was from part of that reservoir, and that's a very -- definitely a theme that we see elsewhere in fields in the KRI, and in fact, in our own field, the oil in Bina Bawi where we have stacked hydrocarbon accumulations with hydrocarbons over water, et cetera, over hydrocarbons again. So that wouldn't be a huge surprise. And as we said, we've got a lot of upcoming work that will address those uncertainties, and that's both with the existing wells, but then, of course, the 3 appraisal wells as well. But once we gathered more data from a combination of those existing wells and the S-1D well first up in particular, we'll be able to talk in more granularity about water, origin, quantum, et cetera. And we'll be doing that from a position of water handling comfort, if you like, which was something I was trying to describe there in terms of getting our plans in place for dealing with what's ultimately a pretty conventional production operations management issue.

Look, I think it's worth reminding, Nick, that the -- we're producing from 2 exploration wells, which at the time were pretty much wildcat exploration wells. So they don't have sophisticated completions in any way, shape or form, and we have very little control over the intervals for which we have on production at any one time. And that's not the way that we drill and complete our production wells generally as we go forward. So we'll have a -- as Mike alluded to, we'll have a lot more sophistication, a lot more control and management of the each individual interval within all of the reservoir levels within the Jurassic once we get these more sophisticated wells completed.

Yes. And that was the schematic on one of the slides there, Nick, that I was trying to get that across with the way that even just for the Adaiyah, we can isolate each of the individual zones. I'd hesitate to -- I have called the existing well dumb completions or I slightly hesitate to say that. But they are what they are, right? They were wells that we used for a different reason because we could get those on at some and get the pilot going at low cost without drilling additional wells. So there was a lot of merit in doing that in the short term to enable us to start gathering the pilot data, which is now starting to inform us going forward. Thanks, Nick.

Okay. So we have no further questions coming through. So I'll now hand back to Bill for any closing remarks.

Okay. Thanks for listening to us today. I wanted to give you a bit of a deeper dive on Sarta, as we said at the beginning, hopefully, you found that useful. And actively encourage all of you to take a look at our new 2020 sustainability report. We're pleased -- very pleased with our second issue and feel that does very fairly reflect the journey that we're on in terms of ESG. And we look forward to communicating the exciting results that we have ahead of us as the year progresses. So I look forward to talking to you all again in the not-too-distant future. Thanks now..

Thank you, everyone, for joining today's conference. You may now disconnect your lines. Thank you.