Genel Energy plc (GENL) Earnings Call Transcript & Summary

Good morning, ladies and gentlemen. I am Bill Higgs, CEO of Genel Energy, and I welcome you to -- all to our 2020 annual results. I'm joined as usual by Esa Ikaheimonen, our Chief Financial Officer; Paul Weir, Chief Operating Officer; and Mike Adams, our Technical Director. We will run through a 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 that for me demonstrate our focus on delivery and keeping our promises. And now I'm going to show you a slide about what we plan to deliver going forward in 2021, and then I'll hand over to the team to explain how our model works. Starting with 2020, in spite of what was a very challenging year for the world, we did what we said we would do, and you can see that in the numbers. Our production was robust, and given the low production cost, it meant that we continue to generate material cash at an asset level, helping us retain our financial strength. Given the fact that we are owed $159 million, including the unpaid override, a cash outflow of only a few million last year shows how advantageous our cost position and free cash flow potential. We successfully refinanced our bond, confirming our liquidity runway and ability to continue our investment plans as we see fit. And investment in our growth assets helped deliver Sarta to production in November. This boosted the diversity of production in our portfolio, which was already unmatched by any of our other KRI peers. Getting the asset to production was a tremendous performance given the impact of COVID-19, and the field is already producing at over 10,000 barrels a day with more to come. The margins here are impressive, and Sarta is now generating cash at the same time as we appraise the full extent of the field. Given our positive outlook, we have retained our material final dividend of $0.10 per share, a total of $0.15 per share for 2020. It shows how quickly things turn that, in March last year, our decision to retain the dividend looked bold as oil price collapsed. We believe that it helped to illustrate the strength of our business model though. We know that we have the resilience to ride out negative fluctuations and the flexibility to adapt to market conditions. We have the strategic resilience to press on when oil price falls and the experience not to get ahead of ourselves as it increases. We do, however, look forward to fulfilling our promises of the dividend being progressive as we continue to develop the business. Our performance in 2020 was laudable, given the environment, but we see it very much as a foundation from which to build, and it sets us up very well for 2021 and the years to come. On to the next slide. We are working hard on all aspects of ESG as we believe that it is fundamental to our future to also deliver in this area. We are very aware of our role in the energy transition and believe that the market's focus turns -- I believe that as the market's focus turns to making sure that the right barrels are produced, it is those that are low cost and low carbon and that deliver societal benefits that will be the ones that power the transition towards clean energy. By having the right portfolio of assets and a clear commitment to align with the Paris Agreement, we aim to continue to be attractive to investors throughout the transition. We have a specialist ESG team who have done some great work on driving all that we do, and we are proud of the GRI compliance sustainability report that we issued last year. If anyone has any questions about our work in this area, we'll be happy to discuss. As we expand our operational footprint, which Paul will discuss more later, the focus on our social and environmental responsibilities increases. This begins with our responsibility to our employees and the communities in which we work. Our safety record remains impeccable as we have not had an LTI for over 5 years now. This is the result of a lot of hard work and a commitment to a culture of incident-free operations for which I take this opportunity to pay tribute to our team. We continue to invest in the local community while maximizing local employment at our sites. Finally and importantly, the energy transition. We have now formalized our Greenhouse Gas Emissions Management Standard, which sets up our stringent targets over the life of our fields. We will look to build on the EOR project for the Tawke PSC and are committed to reducing emissions as our portfolio grows to meet the need for fewer but better energy projects. We're aiming for ESG work to mean that we fit into a wide range of investor portfolios. But of course, to warrant that place, we need to keep offering a compelling investment proposition, more of which on the next slide. And we aim to continue the delivery of our simple strategy and provide that compelling proposition. Our high-margin production is set to grow year-on-year with the Sarta-1D well having the potential to add to the end of the year on a -- finish the end of the year on a high. We have multiple drilling catalysts with Sarta appraisal moving ahead rapidly as we set to drill Sarta 5 and Sarta 6 back to back early in the second quarter. We will get results from the first well in Q3, and both will be completed by the end of Q4. This is a potentially huge resource with over 250 million barrels of gross 2C resources. Qara Dagh is also a potentially massive resource, and the long-awaited QD-2 well offers the opportunity to unlock a fifth producing field. More from Mike on these shortly. As we make the significant investment in preproduction opportunities, the increase in the oil price and the resumption of full payments means that we expect to generate free cash flow and retain a net cash position at the end of the year. This, in turn, means that once -- we can once again retain our material dividend and offer investors a mix of growth and returns. And now for further details on our robust financial position and capital allocation priorities over to Esa.

Thanks, Bill, and good morning all. When we presented 2019 results a year ago, we promised to maintain a resilient business model with low-cost, high-margin assets and significant capital flexibility. We outlined the business with a strong balance sheet and a capital discipline that leads to predictability and delivery of results through cycles. Importantly and very much against the industry trend, we decided to maintain our dividend and eventually paid a full $42 million last year or $0.15 per share. Today, a full year later, I'm going to talk to you about how we delivered on that business model and how we continue to grow more resilient with the balance sheet also set to get stronger. The table on the right of this slide shows that the production business made money irrespective of the low oil price. Production was in line with our -- budget costs were in line with guidance and overall, Tawke and Taq Taq generated about $85 million of cash flow, more than enough to cover our costs and nearly enough to cover our investment in growth, resulting in a small free cash outflow, as Bill mentioned, of $4 million, a solid result despite almost $160 million that was not paid by the KRG during the year. You will remember that we had asset impairments at the half year as a result of oil price. These impairments cannot be reversed despite oil price improvement; and as a result, we reported an operating loss of $365 million. On to the next slide. This one shows where our income came from and where we put our capital to work. If you start with our opening cash of $377 million, you can see that Tawke and Peshkabir asset cash flows covered our costs and our dividend, taken us to $380 million in cash before we make our key capital allocation decisions. We then booked the balance sheet to work principally to bring Sarta to first oil and progress Qara Dagh further. We also refinanced our debt paying about $20 million to call the 2022 bonds. This, by the way, was about $6 million more than it would have been if we had waited for another full year. Another $20 million to reduce bond debt from $300 million to $280 million with the rest on issuance discount and fees effectively accelerated interest, resulting in an implied cost of just under 10%. Our closing liquidity of $274 million, which is after the final settlement of the 2022 bond, which, by the way, happened just after the year-end, continues to give us the ability to invest in those areas that have the potential to provide the highest returns to shareholders. On to the next slide. The chart on the right shows how the $280 million of gross debt looks relative to the book value of our 2P production assets. Together with our cash and the amounts owed by the KRG, we have over $900 million of book value, illustrating the low leverage of our balance sheet. As a result of the half year impairment, these book values effectively reflect the June 2020 oil price outlook, which was a lot lower than what we forecast today. The early refinancing moved debt maturity out to 2025 and cleared the path for material investment without reliance on oil price or payment for deferred receivables. First priority investment is the appraisal of Sarta and trailing Qara Dagh 2. Pending the success case, expansion of Sarta and bringing other assets onto production will follow. Our business model remains focused around risk mitigation, and we continuously look to accelerate low-cost development to first oil, rapid ramp-up and flexible capital commitments. On to the next slide, please. What we did in 2020 has positioned us well to benefit from improving conditions, which we expect to continue. We have also added earnings quality to our production with Sarta. At an oil price of $50 per barrel, Sarta delivers a margin that is more than $10 per barrel higher than the Taq Taq production it is replacing. Further, we continue to benefit from the strong production performance in the Tawke PSC, where we can maximize the value of the license now that we also benefit from the recovery of the outstanding payments from the KRG as well as the override. What's hurt our cash flow in 2020 will boost it in '21 and '22. As you know, in March last year, the KRG committed to a repayment plan once oil price reached $50 per barrel. And indeed, the override payments were resumed from January, and we have received our first payment of override. At the same time, the repayment of unpaid receivables also started, and we received about $2.5 million for this purpose for January production alone. Calculated very simply, these payments are for paying interest production multiplied by $0.50 for every dollar that average Brent for the month is about $50 per barrel. You can see from the chart the difference that the increased oil price plus the override and recovery payments make, with a blended proceeds of $6 per barrel in 2020, increasing to over $20 per barrel at $60 oil price in 2021 and above $25 per barrel at prevailing oil prices. If around $60 Brent maintains through the year, then based on our guidance production and CapEx, we would expect to see a meaningful net cash position come the end of the year even after significant CapEx and after paying another sizable dividend. Next slide, please. As I said, we aim to be predictable, so there will be no change in our business model or capital allocation philosophy nor in our commitment to protecting the balance sheet. We only put capital to work within a development framework that maximizes payback and cash generation. So for this year, our CapEx guidance is $150 million to $200 million. The current oil price and outlook suggest that we would spend towards the top end of that range. Our first priority remains the maximization of the value of our low cost production. Around $80 million of that CapEx will be spent on producing assets, mainly at Tawke and Peshkabir, but remember that this expenditure is all cost recoverable. We received incremental revenue through the field level cost oil and revenue from the incremental production to pay back the entire cash spend the month after we spend it. Thereafter, it's pure profit. It will be nearly criminal not to invest and maximize the NPV of these fields whenever the oil price is anywhere near current levels. We will spend around $100 million on growth, focusing on appraising Sarta that could see a material uplift through an increase in both reserves and production in the next couple of years. The profitability of this growth is exceptional. Paul will show you later that a Sarta barrel apparel at $60 oil price earns us more than a Tawke barrel even with the override included. In addition, we will drill the well at Qara Dagh, which Mike will tell you more about. We're also keen to invest in Bina Bawi to make progress towards gas production as well as towards the production of light oil at the license. But we will only do this once we have full clarity and alignment with the KRG on the commercial agreement. We have been in active discussion with them, and we hope for a breakthrough on this. But until we get there, we'll not be allocating material capital to the project. We have other priorities. Regarding the dividend, the current outlook is very supportive. When we started the dividend 2 years ago, we stated it would be sustainable and progressive. A year ago, the outlook was a lot less supportive, but we maintained the dividend when the oil price was $24 per barrel and other companies were dropping or reducing theirs. You may ask how the oil price impacts our dividend policy. I'm not going to give you a hard number because that's not the way we think about it. We look at the forward shape of our liquidity range much more than the prevailing oil price at any one time. But to give you an indication, when we prepared our budget for this year, we were using an oil price below $50 per barrel. And we plan to maintain dividends and deliver the same capital program as we are setting out today. Now we are affirming our final dividend at $0.10 per share. And importantly, we are reaffirming our commitment to it being both sustainable and progressive, consistent and predictable again. We will consider the level of dividend periodically as we gain better visibility on oil price receivables and success with Sarta and Qara Dagh. The next time we consider it is already for the interim 2021 dividend later this year. And now over to Paul, who will provide an update from the engine room. Paul?

Thanks, Esa, and good morning, everyone. Bill and Esa have both already made clear that the basis of our business is our production and the low-cost and high-margin nature of our production that lies behind our financial strength. Our OpEx cost per barrel was $2.80 in 2020, and this enviable OpEx per barrel figure is driven by the nature of our operations, which are onshore operations in a region that's sometimes difficult but that's served quite well by oil and gas industry support. Our operations are very efficient, too. They are well-established mature operations, and they're well run at all locations. We'd like to take our hats off to DNO for keeping Tawke running through COVID, with no production downtime at all due to the pandemic and to the TT OpCo team for a similar outcome at Taq Taq. You can see on this slide, the margins that our production is expected to generate in 2021. $15 a barrel blended margin is an impressive figure. Of course, that's based on our current work plan and budget. Should we elect to do more in response to an improving economic climate, those margin figures might improve further still, at Tawke, for example, of where incremental barrels had value almost immediately. And as you've already heard from Esa, we'll be working with the operator to determine what more we might do there in 2021. Another notable point about our production and our production base is its diversity. Genel used to be reliant on a relatively small number of major oil wells at 2 fields. Our production now comes from 4 fields on 3 licenses with a total of 70 wells contributing production. We've seen in the past that the geology of Kurdistan can be tricky, so this diversity helps to mitigate against any surprises from individual wells. On to the next slide, please. And as our production is increasingly diverse through our operational footprint expense, our experience in the KRI gives us a real advantage here. Our years of working in the region have shown us how best to operate fields at a low cost with maximized efficiency driving our margin. We are always a lean machine, and this comes back to our business model. We aim to always run as if we're in a low-cost environment -- low price environment. While many of our peers cut costs materially last year in response to the emerging COVID emergency, our costs were already very low. We, therefore, cut CapEx, but our production operations effort continued largely unchanged. It was this approach, this cost position that helped support Chevron's decision to use Genel as its partner at Sarta where our field development plan removed hundreds of millions of dollars in cost on the journey to first oil. Just as we've already acknowledged the efforts of the DNO and TT OpCo teams, we should also commend the Genel team at Sarta who, together with the Chevron and contractor teams there, were able to complete construction and then commissioning start-ups out to production in very challenging circumstances, a truly outstanding achievement given the environment in Kurdistan where COVID hit hard. That world-class effort was not conducted at the expense of other essential operational considerations, though. We take the safety and well-being of our people very seriously. We are enormously proud of our work at Taq Taq, where we've now expended 13 million man-hours over 6 years since the last lost time incident. We are now taking this focus to Sarta where 600,000 man-hours have now been worked without incident, all more remarkable given that a large proportion of those man-hours were worked in a construction and hook-up environment, where incident frequency often increases. We applied this sort of rigor in our approach to the pandemic also, acting early to put a strict plan in place and continuing to evolve it with the science and as we learned more about what worked best. Staffing requirements were altered. Discrete working group bubbles were created. Quarantine distancing and testing procedures were introduced and strictly enforced, and these precautions remain in place today and are working well. The success of these measures and those put in place at Tawke by DNO allowed us to deliver almost 32,000 barrels of oil per day of production in 2020, and we expect that figure to grow in 2021. On to the next slide now to explain how. In a nutshell, we expect production from Sarta to more than offset declines at Tawke and Taq Taq. Comp portfolio production is now around 33,000 barrels of oil per day. With the Sarta asset already producing more than 10,000 barrels of oil per day in gross terms, our share will more than compensate for decline elsewhere. And we don't expect declines elsewhere to be huge and the Tawke WP&B agreed with DNO, at least 8 wells will be drilled this year. The success of drilling when it resumed last year shows what can be delivered, and the operator expects production to be above 100,000 barrels of oil per day in gross terms in 2021. As mentioned a few moments ago, production surplus [ currently ] over 10,000 barrels a day, and this has the potential to rise as we optimize the new facilities there. While the focus of drilling at Sarta has done appraisal this year, our expectation is that the Sarta-1D well will be able to move rapidly into production later this year. Mike will explain how the geography of the field supports this and how Sarta-1D production can add to the exit rate at the end of the year. Finally, on this slide, Taq Taq continues to tick along. It's a minor part of the portfolio now, as you saw from the margin slide earlier, but it still generates cash. And with the increase in oil price, there are ways of extracting more value from the field. As it stands, we don't expect any major activity there in 2021, although we are working very closely with our Taq Taq partners to determine a suitable investment program for 2022. On to the next slide, please. This slide shows our robust reserves position, providing confidence in our long-term cash generation. Tawke's reserve replacement was impressive last year with almost 100% at 1P. We still don't book reserve related to the enhanced oil recovery program at Tawke. The initial results there are very encouraging, but it's still early days, and the project has yet to be completed. Work continues to convert more wells into gas injectors, and Phase 2 of the project only starts this year. So we feel it's a little early to book reserves, but there is certainly possible upside there. It is the upside at Sarta and Qara Dagh that's really exciting though, as you can see from the chart on the right of this slide. Drilling at Sarta this year has the potential to add a great deal of those 79 million barrels of the Sarta 2C resource onto our reserves ledger, and success at Qara Dagh would open up another field and more cash generation for Genel and the KRI. So I'll pass you to Mike now, who will explain how we aim to convert these resources into reserves. Thank you. Mike?

Thank you, Paul, and good morning, everyone. So essentially, there was a project with the capacity to deliver the all-important movement through the gears of resources to reserves at Sarta given the enviable way in which discovered hydrocarbons are stacked through the full KRI stratigraphy in this structure, i.e., stacked option for monetization beyond the initial Mus-Adaiyah pilot development. Let's come back to that in the context of the 2021 Sarta appraisal program, which capitalizes this element of our ongoing value creation. But in the first instance and with a nod to our remarkable achievements on the asset in that most challenging of years for all of us, 2020, let's talk about the completion of our journey to first oil. The traffic lights of our action tracker are now all shining green for go. Against all the odds directly or indirectly related to the COVID-19 pandemic, together with our partner, Chevron, we were able to successfully deliver first oil at Sarta in November last year on budget, on schedule and only 20 months after completing the transaction that created the Genel-Chevron partnership. That we were able to do so was a testament to one of our core Genel values, collaboration, something that was lived and breathed through our workforce and, by extension, to our partner, Chevron and our contractors, and was the foundation of this success. To recap, Phase 1A is a low-cost pilot development of 34 million barrels of 2P reserves from the Mus-Adaiyah reservoir initially via 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 planned for. Having commenced production in November initially from the S-3 well only, we are now transitioning to gain pace after the additional hookup of the S-2 well in mid-February. Combined daily production now sits at around 10,000 barrels of oil per day, a number that we anticipate ramping up beyond in the coming weeks and months as we optimize the surface facilities in combination with careful reservoir management informed by the early subsurface data. On the next slide, let's turn our attention now to the 3-well 2021 appraisal campaign, a "bang for your buck" capital investment program, which epitomizes our "appraise where we produce" philosophy by targeting a combination of material reserve and resource additions whilst adding to the Phase 1A pilot production revenue stream. From an operational perspective, the program is due to commence early in Q2 with the updip S-5 well followed by the S-1D and downdip S-6 wells in Q3, meaning results from the first well can be expected in Q3 at all 3 by the end of the year, a tremendous civil works effort again against the backdrop of COVID restrictions and limitations but coupled with the Kurdish winter, delivered appraisal well sites on schedule. As you can see, the Sarta 5-well site is ready and waiting to receive the drilling rig. Likewise, Sarta 6 with the Great Zab River providing its backdrop. On to the next slide. So from a well delivery perspective, these 2021 appraisal wells are designed to give us an eclectic mix of information, targeting volumetric and deliverability contingencies across multiple reservoir intervals and both aerially and vertically, narrowing the resource range by testing multiple Jurassic reservoirs away from the immediate Phase 1A pilot development area, potentially adding to our 2C resources and converting further contingent resources to the commercial realms of reserves. Our well completions are designed such that we will be able to test and subsequently access multiple Jurassic reservoir intervals as future production options, so beyond the Mus-Adaiyah of our initial primary focus and into the other reservoirs contributing to that already impressive contingent resource stack of 264 million barrels of gross 2C. By planning ahead and employing project capital efficiently and at pace whilst minimizing regret cost, earliest possible monetization of success at each of these appraisal locations is being secured. Sarta-1D and Sarta 6 distances allow for fast track oil production in success to be tied back to the existing EPF via 2 flowlines, with first oil from Sarta-1D potentially by year-end. Sarta 5 being somewhat further from the EPF requires a stand-alone pilot production facility, which, in success, would represent the birth of a second processing and production hub. These fast track solutions for early oil production are, of course, the catalyst for that evolution from resources to reserves. As always, we protect the downside while planning for success, which in the case of Sarta means combining production performance from the Phase 1A pilot with the results of the 2021 appraisal program to make a series of investment decisions on a larger development from 2022. Next slide, please. Moving on then now to Qara Dagh, a slightly different animal to Sarta, still at the appraisal end of the discovered resource spectrum but nonetheless, well placed to be monetized quickly post-appraisal success through our same early production philosophy. As the image suggests, completed well site at the center. And as the action tracker shows, we are shortly going to be breaking the ice on the black mountain. Rig mobilization has commenced ahead of an April spud of the QD-2 well. At which point, we begin our quest towards answering the key commercial questions associated with this potentially giant resource that would allow us to step through the stage gate to early production. Those results expected in late Q3. Next slide please. On the eve of the QD-2 well, it's perhaps a good time to recap the nature of the beast and why we're drilling this appraisal well on Qara Dagh. The structure is more than 50 kilometers long, so essentially the length of the block and around a kilometer wide with only 1 well previously drilled on it, QD-1, back in 2011. That vertical well, whilst beset with drilling problems having been drilled downdip and off structure was nonetheless a discovery having tested sweet light oil from fractured cretaceous carbonates. Armed with those legacy learnings, we're now going to drill an appraisal well, QD-2, in a more optimal crystal position, 10 kilometers from QD-1 with much evolved drilling techniques and most importantly, with the trajectory designed to maximize contact with those productive fractures. As the schematic zoom shows, the vertical to subvertical nature of the fracture networks means that a well like QD-2 -- like QD-1 have limited fracture intersection, whereas the QD-2 well is designed to maximize such connections by drilling at 40 to 50 degrees through the reservoir section. Proving up deliverability is the primary objective, and we're giving ourselves every chance of succeeding in doing so. Without getting ahead of ourselves, the ultimate size of the prize here could, as we've always said, be potentially very large with Pmean Prospective Resources for the Qara Dagh anticline greater than 400 million barrels, 47 million barrels of which are already discovered. So that's 2C associated with the QD-1 well and a high case touching 1 billion barrels. The fact that we're dealing with the same reservoir and similar fluid as Taq Taq also gives us a tremendous advantage in terms of optimal development of the broader QD resource base. Through our planning for success lens, we started assess level work to screen pilot production concepts and key decision preferences. Paramount amongst those preferences is our commitment to minimize our environmental footprint in the crestal valley ecosystem of Qara Dagh, something that we see as an opportunity to show thought and action leadership from an ESG perspective. Hopefully, the nature of the rocks we target affords us this opportunity to collaborate with the nature of the mountain itself. Next slide, please. And finally, continuing that theme of resources to reserves conversion that Paul segued me into the presentation on, at the exploration end of our pre-production portfolio, the aspiration for our legacy African assets remains to contribute towards long-term reserve replacement but at the lowest possible capital outlay. In Somaliland, the farm-out process continues to progress. And whilst the uncertainty created by COVID has delayed proceedings, discussions are ongoing with a number of potential investors. The constants here are firstly the technical case, which remains compelling, high-impact resource potential and multiple stacked prospects with the opportunity to target greater than 500 million barrels of prospective resource with 1 well at the Toosan prospect; and secondly, the strategy, which remains to bring in a partner ahead of drilling a noncommitment well. In Morocco, additional prospectivity within regionally proven reservoir targets, illuminated by the final processing products of the multi-azimuth broadband 3D seismic, has added further to the already impressive prospect inventory, 20 prospects with combined prospective resources in excess of 2.5 billion barrels. But once again, capital discipline dictated, especially at this end of the E&P spectrum, a part will be sought through a farm-out campaign prior to considering further commitment, whilst in the meantime, we preserve our optionality. So with that summary of the exciting growth catalysts characterizing 2021 and starting to shape the years beyond, let me bring the rest of the team back in and open up the floor to questions.

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

A few from me, please. If could -- can I start with the production optimization at Sarta, really just if it's possible to get a bit more detail about what exactly needs to happen there? And also you've had some delays and obviously, this is a constraint, but you've managed to keep production guidance the same. So should I be reading anything into the potential you're seeing at the field? Or am I getting ahead of myself there? And really, the second question is -- that was Part a and b, sorry. The second question is really around the risks around the Sarta appraisal. You say it's going to target a material proportion of the resource, which is great as long as it works. But if it doesn't, we'll obviously be questioning how much to write off. And I know that's a very simplistic approach, but just wondering if you can help us at all think about the potential outcomes there.

Thanks, David. Yes, good questions. And sort of given the fact that it is very much an appraisal program, we've been very keen to point out to everybody that the nature of which we've actually deployed capital to Sarta is one in which we stated that capital consistent with the knowledge and understanding we have in the field so that we can keep -- we don't get ahead of ourselves and overinvest for what we know to be true. But with -- I'll let Mike pick up on the specifics of those 2 questions.

Yes. Thanks, Bill So I think in terms of the first part of that around optimizations without getting into the weeds or perhaps, I should say, the nuts and the bolts in this case, we're talking about relatively simple modifications here, which are designed to enhance production. Now we have actual reservoir and production data over days, weeks and months as opposed to the hours of the kind of at time of drilling and testing. I would say, a little bit, it's all part of the fun of the fair when it comes to start-ups, and we'll continue to look for aspects and areas of the production stream, which can be optimized and add to our margins. On the second part of that around production. And I guess I could probably take a bit more holistically in terms of what kind of production ramp-up this year looks like. In a success case for each well, ramp-up is -- it's primarily a function of how quickly we can get the wells tied into a processing facility. As I said during the presentation, for S-1D and S-6, that's by flowlines back to the EPF given they're only 2 and 7 kilometers away from that EPF, respectively. For S-5 being, I think, nearly 14 kilometers away, that will most likely be through an additional temporary processing facility, which would be the embryo of a second hub, and that will inevitably take a little longer. So first up will S-1D with the aim to get that on production by the end of this year and contributing to our exit rate with an assumption, I think you can take an assumption there of at least more of the S-2 and S-3 type initial production and then the others to follow in due course. So likely S-6 in the first half of 2022, S-5 by the end of '20 and then the first of the development, the 2020 development wells and success case comes on shortly thereafter. So I'll leave you to do the math there a little bit in terms of those wells coming on at those kind of S-2 and S-3 rates.

Want to touch on the risk, Mike?

Yes. Yes, my mind only managed to -- managed the first 2 parts of that. So yes, the kind of main risks associated with the appraisal wells, the fact that the wells are appraisal wells reflects the fact that they're being drilled in part to reduce uncertainty associated with the nature and size of the accumulation. In both cases, the most common theme for wells in this basin is the one which is common here. So the main uncertainty is around reservoir effectiveness, which is a link into deliverability. So it's back to the old intersection with productive fractures story in fracture-dominated reservoirs, which, of course, we're mitigating by drilling these appraisal wells as high angle wells, together with the fact from a container size perspective, we're pushing the envelope deeper and laterally further.

Okay. So if it's more about deliverability, it feels to me that if you have an unsuccessful well, it wouldn't necessarily write off the resource in that area. You might need to drill another well.

Yes. Yes. I think if you're talking of these wells as sort of failure, there's probably -- a potential failure is a bit of a kind of end-member given the way that the wells are designed as well because as I sort of set out their designs, they also intersect the other Jurassic reservoir intervals and are targeting the rest of those contingent resources as well. So they're quite eclectic in their sort of appraisal objectives and how they set themselves up as future monetization options.

And I think it's worth reminding everybody, David, that when we went into this investment, we were very keen to make sure that as part of the reason of having a pilot development that we manage the downside outcomes so that the company wouldn't be exposed to poor outcomes financially. And that is this pilot appraise program that we have in front of us. It's very exciting for us to be able to look at drilling for material appraisal wells in 2021. And by the end of the year, we'll have a very good understanding of the opportunity that Sarta and Qara Dagh present to the company, which is great. But that's not -- as you said, it's not without risk because that's the reason why they're called appraisal wells.

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

Two question there. One was partly related to David's questions, whether that's on activity in 2021. You said that the CapEx guidance is $150 million to $200 million, and that we likely will end in the top end. So if you're just assuming that you actually will spend $200 million and not end up in the midpart of that range, is it fair to assume that incremental dollars will be spent on Sarta? Or any other projects that you want to highlight? And second question is on Qara Dagh. You have 19 million barrels booked as 2C. Any potential conversion to 2P reserves? Is that a 2021 event? Or do we need to look into 2022 to see any reserve conversion at Qara Dagh?

Thanks, Teodor. I'll get Esa to answer the first and Mike take on the second.

Yes. Thanks, Bill. Thanks, Teodor. Thoughtful questions as always. You already heard us sort of using some numbers in our prepared part of the session. You do remember that we mentioned that the growth CapEx indication today is about $100 million and production CapEx, about $80 million. So put the numbers together, you're already above the midpoint of the range. The incremental expenditure also indicated at least a couple of times during the presentation today, we are obviously quite excited about the potential Tawke and Peshkabir has got in terms of value creation. So further activity in line with our capital allocation priorities ideally would come in Tawke and Peshkabir because of the sort of incredible economics that it provides. So we haven't really determined that yet, and it's work in progress. But we try and think about capital allocation in line with our predetermined priorities, and they're very much driven by the underlying economics, and therefore, spending a bit more than the indicated $80 million on Tawke and Peshkabir would make perfect sense. Work is ongoing together with our partner, DNO, to identify additional opportunities because, obviously, the environment is very favorable for that.

Let me take the second part of that question, Teodor, then. Yes. So 2021 is really around prospective resources to contingent resources conversion. That next step of contingent resources to reserves is more likely a 2022 piece, and it's really a link into how quickly we can -- we could get QD on production in a success case. So it's probably worth just touching on that a little bit because that really -- that -- the investment decisions around that drive that conversion. So as I said during the presentation, we're already in the process of assessing a number of potential concepts for early oil production. Given the size of the structure, we'd likely drill a follow-up appraisal well in pretty short order in 2022 such that we were armed with 2 wells' worth of feedstock into an early production pilot. But we could also go with an extended well test type early production solution from QD-1 -- from QD-2, sorry, in a success case, and that would facilitate that conversion from contingent to reserves.

I think just worth saying, maybe adding to that -- to Mike. As Mike said in the presentation, the contingent resources at Qara Dagh at the moment are associated with the QD-1 well, which is not optimal as an early production system. So it is about drilling QD-2 and subsequent appraisal wells in a success case and then looking at how best to get early production going that will then drive that further resource to reserves.

Yes, that's right. And that conversion to contingent resources would be something of the same kind of [ algo ] as those numbers were quoting for QD-1 but obviously at the QD-2 location.

The next question comes from the line of Dan Slater from Arden.

I just wanted to ask about the Tawke override. The original agreement for this was, I think, for it to end in summer 2022. Given that it was suspended for most last year, is there any scope to extend that, do we think, potentially or? Is it definitely just the same agreement as before, ending in 2022?

Do you want to pick up on that, Esa?

Yes. Happy to do that. Thanks, Dan. So the industry-wide methodology that KRG introduced for January and which is currently in play simply just includes the override -- suspended override -- the unpaid override into that generic model, so called reconciliation model. In other words, the companies that have got an override and an outstanding receivable associated to the override would recover that override -- the outstanding override through the standard methodology. We are still in conversation with KRG about potential ways to optimize and perhaps even improve that model for a sort of win-win solution. And that potentially could include an extension of the original 2017 receivables agreement term. But the current methodology is that the override comes to an end and the outstanding comes to an end in August next year. And the outstanding override would get recovered through that standard methodology.

Your next question comes from the line of Nick Stefanou from Renaissance Capital.

It's Nick from Ren Cap. I have 3, please, if I may. First one is for Mike for Qara Dagh. Mike, given that this is Shiranish rock [ happened ] and would expect pretty much nothing from the metrics there. I would have though what you would want to do is try and get an idea of the fracture and intensity and also what the fracture water contact might be. So I mean -- but you wouldn't be able to do that if you just drill at the crest of the reservoir. So could you maybe talk a bit about why you chose that asset target? I do understand the potential optimization of the oil flow and the [ bad ], say, kind of like fracture contact, but it doesn't really answer the overall recoverability question for the Shiranish. That's my first question. The second one is for -- sorry, is that a contingent resource got -- for the gas injection program? Do you not, I think it, consider that to be 2P reserves? I just want to understand why you would consider it as contingent instead of [ semi ] or maybe 3P because contingent is -- seems to be -- I don't know if [ spot ] is effectively increasing the recovery factor as opposed to transferring contingent to reserve. So that's why I was quite a bit confused on that. And then the final one on the receivables. I think DNO was talking about discussing interest on top. They made a good point, but I mean they borrow from the market, something like a 9% discount rate. So they wouldn't be lending to the KRG at 0. Has there been any progress on that discussion? Is -- do you guys expect that you might actually get a bit more on just the nominal value of those arrears?

Thanks, Nick. We'll let Mike pick up on those first 2 questions first, and then we'll come back to the receivables discussion.

Yes. Yes. Thank you. So I think the key point here in terms of the location that we've chosen is we've chosen a crestal location, which is targeting the proven reservoir. So the Shiranish is the proven reservoir from the QD-1 well. So clearly, entirely logical that, that would be the reservoir that we would be targeting with this appraisal well. The fracture intersection piece, clearly, very important. Here, it's all about deliverability. It's in the first -- success at QD-2 is all about proving deliverability. So the trajectory that we have planned for this well is designed so that we give ourselves a maximum possible chance of intersecting those fractures and addressing that key uncertainty around deliverability. And then, of course, we have a data gathering program as part of drilling the well, which will be gathering really important information about those fracture networks from a -- in the first instance from an imaging perspective. So image tools, which help us to further understand how those fracture networks work in the context of this reservoir is going to be really important in terms of planning our subsequent wells in a success case. So we think we're giving ourselves every possibility with the way we've designed this well. It is the logical well -- the logical place to drill the reservoir, which has been proven within this structure. Now clearly, there is deeper potential within the remainder of the Cretaceous as well and Jurassic, but there -- I would sort of badge those as being for another day.

Maybe just to add to that, Nick, obviously, we've got tremendous amount of experience from managing the Shiranish reservoir at Taq Taq. I think the plan to have an EWT in the early information that we can collect even from the crest of the reservoir will tell us quite a lot about the size of the container, which is obviously important from a point of view of understanding what we do next. But it will be early days, and as Mike has said, there will be subsequent appraisal activity there to define the true extent of the container. Maybe on the gas injection project, we've always maintained a view that we kept the EOR project in contingent as part of a PRMS -- alignment with PRMS, where we have to have demonstrated performance in order to move those contingent resources to reserves. And while we've made great progress, we've seen some good early performance from the gas injection project at Tawke. We've decided with our auditors and with our reserves committee that we'd like to see a little bit more of the performance data and complete the project, as Mike alluded to, the Phase 2 of the projects ongoing this year, before we make that move. And I think it's consistent with PRMS. You could make an argument that you can put it into 3P, but we like the consistency with what we've done in prior years to sort of say, once we've got demonstrated performance, then we'll move it across. On the receivables point, firstly, I think it's really important to commend and -- the Kurdistan regional government for doing exactly what they said they were going to do. And 2020, as we've talked about, everybody knows, is a really, really tough year for everybody. And they were very clear in their early communications around the nonpayment that once we got close to $50 a barrel, they were going to come up with a plan for repayment and a plan to reestablish the [ RE ]. And they've done exactly that. I think it was 2 days before we hit $50 Brent that they actually came back with that proposal to everybody. Now clearly, all of the producers have embraced that model and clearly see it as a very good step forward. But it's also fair to say that, that model in a lower price environment, so just above $50 environment, it gives a very slow recovery of the outstanding debt. And I think that's been an area, therefore, that everybody has been looking at and been in conversation with the government on, which is, well, what -- we either have to come up with a model where there's some form of accelerated recovery to compensate for that or we have to start looking at the cost of capital as a way of compensating for that very slow recovery. So that's where those conversations are -- have been undertaken. There's no further clarity at this time about the KRG's position with respect to those requests will be coming from -- not just from DNO and ourselves, but others -- I understand, others in the -- who are obviously operating in KRI.

Just a quick follow-up on that. Are these conversations with the MNR? Or is it with the KRG leadership directly?

It'd be both. Obviously, one of the good things that's happened this -- early this year is the appointment of the new Minister for MNR has clearly helped in establishing a clear contact for all of the issues related to the industry. And that's, I think, an excellent step forward again also from KRG to get the Minister in place, but we'll see where that goes over the coming weeks and months.

Your next question comes from the line of Tom Kristiansen from Pareto.

I have 2 of them basically. Number one, could you add a bit more color on how much the situation in Kurdistan has improved from last year? Given where oil price is now, kind of how is the situation on the ground? And how much more confidence do you have in their ability to balance the budget next year -- run with a surplus now? Secondly, if you take Sarta, your expectations there and just assume that it goes as planned, could you provide any kind of reasonable range to expect the production in 2022, 2023?

Thanks, Tom. Thanks for the question. Yes, clearly, in terms of KRI and Iraq, in general, clearly a higher oil price environment helps tremendously. We've always talked about the fact that, from our analysis and others' analysis, that the economy in Kurdistan region probably breaks even around $48 a barrel. So anything above that and getting materially above that number helps. We've also been very consistent in our view throughout 2020 and into this year that we were very confident that the Kurdistan regional government would come up with a mechanism to repay the debt from the receivables. They've clearly demonstrated a commitment to the industry and have always been very good, particularly over the last 5 years have been almost flawless in their payments. So I think it's really good to see their -- as I said, see their commitment to getting a program in place to establish that repayment scheme. So I think we're very confident that those debts will be repaid. And it's really a question, therefore, of timing of how quickly they can be repaid given mechanism that's in place. Certainly, I think it's a good thing -- clearly a good thing for the people in -- of Kurdistan and again, more broadly, in Iraq that a higher oil price environment means that they can start to look at fulfilling their salary payment obligations, which are being, again, restricted in 2020, which helps with the stability of the region. On Sarta, Mike, do you want to pick up on that?

Yes. Let me do that, Bill. So I think I've kind of probably partly answered it a little bit already, but in -- we need to be careful not to get too far ahead of ourselves in what's a pilot project. I think what I described was line of sight towards having 5 producer wells by the end of 2020. I've talked a little bit about what kind of production you could expect in those if you were to apply a similar kind of rule to what we're seeing from Sarta, Sarta 2 and Sarta 3 at the moment. And then beyond that, 2022, we start to -- in a success case, we start to see the rollout of the developed phase, the [ D of our paddy ]. We start to drill development wells associated with that towards the end of 2022. And so the first of those wells would be coming on in shallow -- in pretty short order after 2022 and early into 2023. So you can see that, quite quickly, with all of that, we're clearly pushing the processing capacity -- facility capacity that we have at the EPF, where we would, in that case, have added some processing facility capacity at the Sarta 5 location, which we would hope would become something of a second hub. So I think that's the kind of scale that you can apply in terms of number of wells and apply that against the kind of production we're seeing from S-2 and S-3 would be probably how I would badge it.

As our eloquent CFO always says, there's plenty of wood to chop before we get to that. So yes, we're excited about the program we have ahead of us in '21 because, as I said earlier, we're going to know so much more by the end of the year than we know today, and then we can optimize and adjust our plans accordingly to that new information as we narrow the uncertainty for Sarta and for Qara Dagh.

The last question comes from the line of James Thompson from JPMorgan.

So I just want to sort of follow up on that point, really, Bill. And as you say, you've got plenty of catalysts in 2021, around 2 assets, which could potentially be pretty significant for you. I think the first question was, you talked about Qara Dagh as a sleeping giant. Does that also mean giant CapEx as well going forward? And I guess I'm thinking about the earlier comments, Esa, in terms of capital returns. Obviously, you've got a business plan set at 50. We're a long way above that right now. The cash flow is coming in from the receivables. So I was just trying to think about this over a sort of multiyear view and how we should think about the calls on your capital over the next 3 or 4 years versus kind of cash returns in the near term. I mean is it the case that the receivable recovery here in 2021 is excess cash flow? And so should we be thinking that, by the time you've done the appraisal in the second half of 2021, there's scope for some sort of special dividend? Or are you contemplating kind of rebasing the dividend to a higher level given the higher production outlook? So maybe you could just sort of wrap it into -- wrap it up for us about how you think capital returns can grow from here and how significant the capital commitment on the assets is if the appraisal is successful on both Qara Dagh and Sarta?

Yes. Thanks, James. Great question. I'll maybe say a couple of words and then hand over to Esa. And it's a great way to be looking at it, and it's something that Esa mentioned earlier when we were talking about the progressive dividend, which is we don't particularly look just at the environment of the day when we're making a judgment on what we want to do with our dividend. It is very much looking at the liquidity forecasting out over a number of years for the sources and uses of capital. And linking back to this appraisal program, as you've clearly indicated and as I said earlier, we see this appraisal program is going to tell us a tremendous amount about what the uses of capital could be in the coming years as we understand more about that Sarta and more about Qara Dagh. In terms of Qara Dagh itself, sleeping giant, yes, I wouldn't expect or you shouldn't expect us to look to develop a successful Qara Dagh any differently than how we've developed Sarta and we developed Peshkabir. It is about -- these rocks are very unforgiving. And so we have to deploy capital commensurate with our understanding of the reservoir. And so these early production systems, the [ paddy ] scheme works exceptionally well, both from a business model point of view and from a reservoir management point of view. Again, looking at the Sarta example, we've got the Sarta pilot up and running, and you've seen the margins. So it's generating a tremendous amount of cash that supports the appraisal program as we go forward this year. So I wouldn't expect the scheme to be any different. Maybe with that, I'll just get Esa to talk more about the -- our thinking about that the excess cash environment, shall we say, in the wonderful situation where we'd have to invest in a successful outcome at Sarta and Qara Dagh.

Yes. Thanks, Bill. In order to comprehensively answer your question, James, as you would expect, actually, it requires quite a multifaceted answer and it's not exactly a straightforward one. For us, it's all about growth and returns and finding the right balance at any one point in time. And the way we kind of develop our business model is that we try and keep our capital commitments as flexible as they possibly can be so that we can actually play that balance irrespective of the external environment. And you saw that last year. We significantly reduced our capital expenditure and did that successfully because the flexibility allows us to do that whilst maintaining the minimum dividend level of $0.15 per share. And that minimum dividend level is still $0.15 per share, and it's consistent with the 2019 policy announcement that we made, and we continue with that. We need clear line of sight, quite honestly, regarding oil price; the sustainability of the receivable recovery, which is heavily oil price related. We need some further clarity on Sarta success, et cetera, et cetera, to answer very explicitly these questions. But the company is very determined and the company -- when I say company, it includes our Board as well, very determined to scale up which means that we will continue to look for ways to grow the company in a success case. Our organic portfolio provides a lot of those opportunities. But as I said, those capital commitments and other capital commitments that may relate to inorganic growth, we will have to manage those over time in such a way that we've got enough liquidity available for our dividend. Now if all goes incredibly well and the external environment is super supportive, as promised in 2019, as repeatedly promised thereafter, we would be looking to increase our dividend as and when we've got the affordability to do so without damaging our growth opportunities and prospects. I think reasonable to expect because we kind of like to be a bit boring and if not boring, at least predictable is that we'll be looking to increase the dividend over time without sort of a more variable model where we were distributing special dividends every now and then. Consistency is important to us. Predictability is important to us. And therefore, I would personally prefer just distributing a higher dividend going forward on a consistent basis.

There are no further questions, so I will hand back to Bill for some quick closing remarks.

Great. Thank you, everybody, for listening in today. Hopefully, you've seen, at Genel, we do believe that we have a business model that is resilient through the cycle. We've had the opportunity to demonstrate that last year and a business model that's focused on delivering both growth and returns. And we're excited about the multiple catalysts that we have ahead of us in 2021 to really be able to show what our organic portfolio can deliver. And we look forward to getting back together again in a year's time and being able to talk about the outcomes of that exciting program. So thanks for making the time today for listening.