Genel Energy plc (GENL) Earnings Call Transcript & Summary

Welcome to Genel Energy 2019 results conference call. [Operator Instructions] And now over to Bill Higgs to begin today's conference. Thank you.

Good morning, ladies and gentlemen. I am Bill Higgs, CEO of Genel Energy, and I welcome you all to our full year results for 2019. Today, I'm joined by Esa, our Chief Financial Officer; Paul, our Chief Operating Officer; and Mike, our Technical Director. They will help me describe our resilience to the headwinds facing not just the industry but society more broadly. And how we are positioned to be a natural winner in these uncertain times. These are unprecedented times and as a management team, we are well aware of the challenges we face. Operational reliability, low-cost productions and balance sheet strength are key. We'll take you through the presentation, after which we will be happy to answer any questions. Please quickly note the disclaimer. These are tough times, times in which only the most resilient of businesses, particularly in our sector, will survive. Our strategy at Genel is about managing downside risks, delivering in the tough times and outperforming when times are good. It's about growth and growing returns even in those tough times. Financial discipline has been the heart of everything we do for a long time, and downside risk mitigation is part of our culture. Focusing on low-cost, and up until recently, high-margin production, has helped our financial position to rapidly improve in recent years and provide the resilience that supports our investment and returns even in the current low oil prices. It's not by chance that our 2020 outlook that the current prevailing price delivers these productions. It's also not by chance that we're able to reaffirm our dividend today, when all around us are cutting their prior promises. What is the point of being an industry veteran if you don't learn the lessons from the past? We learned our lessons and set in place a strategy that shelters us from extreme circumstances. It is a strategy that is fit for the current market environment as we have been long focused on reducing costs, retaining a strong balance sheet and maximizing our flexibility to use this balance sheet in whatever way we can create the most shareholder value. We have low-cost production that we aim to grow through efficient and rapid development. The cash this generates is almost -- in almost any foreseeable price environment, that we quickly recycled into other growth opportunity. With more than left -- not left over to fund the material dividend today, and hopefully, a progressive dividend once we are through the worst of COVID-19. It's a simple strategy and one that we feel gives us a compelling competitive advantage. I'm pleased to say that we delivered again on this strategy last year. Our high-margin production in 2019 increased by 8%, driving more cash generation that gave us the firepower to invest in growth and delivering growing returns. Tawke is set to start producing in a matter of months, and the QD-2 well is an exciting opportunity that we look forward to drilling. These assets provide a clear route to converting material resources to reserves, and we're delighted to have them in our portfolio. Even while making these growth investments, our net cash position increased by over $50 million, in spite of having received only 10 out of 12 payments in the year. And more importantly, this increase in cash happened as we doubled capital expenditure on growth and paid our maiden and material dividends. This illustrates the resilience of our business well and helps to explain the reason why we have maintained our dividend with an expectation that we'll deliver on our promise of rise in pricing it once the path out of the current landscape becomes more clear. We are very well set up for a low-price environment. Our assets are low-cost with an OpEx per barrel currently about $3. As you will hear from Esa, our producing assets make money even in the prevailing prices helped by Genel having the highest average netback price for oil production in the KRI, $39 a barrel in 2019. Our significant cash balance of just under $400 million and a net cash of just under $100 million, together with the long stop date of December 22 on our bond, delivered significant balance sheet strength for a low-price environment. And our limited capital commitment allows us to a great deal of flexibility to spend appropriately to the external environment. This flexibility positions us well and allows us to match the expenditure to the external conditions. Even in the prevailing condition, in a constant payment environment, we will be able to proceed with all growth plans and production investment and still end the year with a material net cash position. We have the financial strength to continue executing our strategy. This is what we can control. What we can't control is COVID-19 and its impact on our ability to do work. At present, our operations are ongoing at all sites, but it's clearly a fluid situation. We are keen to execute on our high potential work program. But of course, we have a duty to care for the health of our workforce. And like every company, a role to play a hook, hoping to contain the impact of this virus. Of course, our financial strength only proceeds if payments are forthcoming. Payments were made consistently at a time of greater financial strain on the KRG. The oil price has been below $30 a barrel before, and they paid monthly despite assets and the lack of any central government payments from bank data. We have been informed that the recent disruption of 2 payments have been due to external factors. Notably, the Lebanese banking crisis causing $1 billion of funds belonging to the trader that pays the IOCs being tracked. As promised, NRG caught up on overdue payments in January only to fall behind again as a consequence of a reorganization of a payment process with the KRG because of the banking problems. And as far as we understand, because of a low volume of contamination that was found in Kurdistan blend in late December, early January. It's now time for oil producers to see a firm commitment from the KRG to make ongoing payments, and we do expect to see these payments, which provides us with a real opportunity in this environment. We are primed to take advantage of our position of strength. Our cost may come down even further as we look ahead and our liquidity position may help us find some exciting opportunistic M&A. It is a difficult time at present, but we are far better positioned than most to ride down this storm. We are well positioned for the present. We are also well positioned for the future. As we transition to a future of fewer and more efficient natural resources projects, there will, again, be winners and losers in the energy sector. This provides an exciting opportunity to position Genel as a winner in meeting the challenges that mankind faces in relation to energy need. We have the right assets in the right location with the right footprint to position us well. We're good being low cost, our onshore operations are also low carbon, and this figure will reduce further once the gas reinjection project at Tawke is completed. Our carbon emissions will reduce then to circa 7 kilograms per barrel. Management performance uncertainty of the new fields in the KRI requires short-term clarity, beginning the production at Sarta with the temporary flaring up, this we'll see will cause our emissions to initially rise while projects are able to deliver low emission energy over their life. We have worked in the KRG for a long time that have made significant economic and sufficient contributions to the region. More than ever, we feel very proud. The government always supported our ESG work as well as Kurdistan and we will issue a full sustainability report later this year as well as adding enhanced disclosures to the forthcoming annual reports. This will help better illustrate who we are as a company. One step that we've taken is to formalize values that guides the direction which we're heading. Adhering to these values will support the delivery of the strategic business and make sure we have the right people delivering the right actions, the right way to create value for shareholders and to fulfill our statement of being a socially responsible contributor to the global energy mix. But for now, we remain focused on the present. We're the only multi-licensed producer in KRI, with production from 3 fields on 2 licenses. Further diversifying this production has been a key goal since I joined the company and Sarta will add a fourth field to this production, offering material growth and also mitigating risk. We have a mix of assets that are in complementary stages of their development with production development and appraisals. We remain hopeful of progress in Bina Bawi and share the frustration of investors that an agreement has not yet been reached. We have a commercial understanding months ago, but the documents have not been forthcoming and it's not within our gauge to bring them forward. We continue to press and understand the concerns as we reach the start of the period where, theoretically, KRG has the right to initiate the contract termination process. We remain confident, though, that it won't come to this, and if it did, we have various ways to delay any action. Oil production from Bina Bawi is only a small part of the exciting organic growth potential we have, which, with a fair wind, could see oil production double. As you will hear from Mike, Sarta alone could become the biggest field in KRI, and Qara Dagh's untapped potential is exciting. There's a long way to go, but we are well positioned to progress this journey. I will now pass over to Esa to provide more details on how we fund this journey and the material dividends along the way.

Thanks, Bill, and good morning, ladies and gentlemen. It is starting to feel like a long time ago, but it's still worth reminding you of our strong performance in 2019. Our annual results are underpinned by how margin barrels have delivered an average of a $29 per barrel revenue share for Genel. We continue to invest the majority of that revenue in our producing assets, particularly in line with our stated capital allocation priorities. With very competitive OpEx, we generated a material cash reserves from these producing barrels of $183 million. During the last 3 years, we have put a lot of its surplus to bank in order to derisk our balance sheet and our business model. Our capital allocation has been ultra prudent and biased to those areas that provide highest shareholder value. We could have invested a lot more but we did not. Our balance sheet now permitting in 2019, we increased our spend on growth assets and initiated repayment of a competitive dividend. In total, we invested $43 million in growth, principally on Sarta and Qara Dagh. On the negative side, the annual results suffered from a delay of government payments in total of $54 million that was received in early 2020 as promised by the KRG. All that resulted in underlying earnings of $0.54 per share and a free cash flow of $99 million, a strong performance even if those missed payments had a negative impact. The performance that translated to free cash flow of $0.36 per share, which was around 15% of share price for most of the year. Unfortunately, it is an awful lot more today. From that free cash flow we collect dividends of $0.15 per share distributed in 2 installments. We made a material dividend last year, and we just this morning, announced a decision to maintain it. So why do we continue paying these dividends when so many others are pulling theirs? Well, as Bill said already, our business model is set up for this environment and for a sustainable dividend. Firstly, our current asset base and commercial structure is bid for purpose and very resistant to low oil price. Secondly, we develop and maintain our assets cheaply and always look to move to production and cash flow quickly, with a relentless focus on risk mitigation and cash flow maximization, particularly in the low oil price environment. We maintain a high level of liquidity and prefer to move money to the bank rather than spend it on high-risk exploration or risky M&A. Our discipline has meant that we have walked away from very interesting M&A opportunities that simply didn't fit that goal. We have also not spent money on developing our gas assets when the commercial environment didn't support it, let alone investing in explorations from Qara Dagh and [indiscernible]. All of this was possible. All of this could be possible if we had a source of attractive oil but we chose not to bid. You can see from the waterfall that there will be a focus of our spend on producing assets where we get most attractive and most certain payback, and can get focused on progression of relatively low-risk and high-reward size towards first oil and [ Qara Dagh ] which we see also as hugely exciting albeit with some usual M&A risk. Now that the macro events have developed in the industry, we get the benefit of our financial discipline [indiscernible]. Finally and importantly, we have maintain the dividend, a key part of our balanced capital allocation philosophy, as we said before, despite the softening of oil price in the early part of the year and the very recent. That's what this all means to us. We're disciplined on the promises we made to trust that business model and the strategy and adjust and stay on course, and just as important, we are disciplined on delivering against those promises. I believe our business again sustained a material dividend through cycles, something we said when we introduced it last year. We have the appropriate high cost of producing assets, asset diversification and an exciting organic and profitable growth story to support that dividend long term. I'll now talk a bit more about the way we look at 2020. One of the foundations for initiating dividend last year was our confidence in our portfolio and the future upside for us but also our resilience to any downside scenario. And the material cash balance and comfortable debt position of [ client cost ] that can circle out of our control. Our operating costs in 2019 were under $3 per barrel and our forecast again is to be around that figure in 2020. So how does 2020 look? Well, if we will have Brent at about $30 per barrel on average for the rest of the year, then average for 2020 is around $35 per barrel. At that price, you can see we effectively breakeven after dividend with any catch-up on payments added on top. This allows us to have confidence about the coming year, for the ongoing year, I should say, irrespective of the huge macro turmoil as we can rephase investment without major regret and support the current level of dividend even at prevailing oil price. Furthermore, our cash flow is not particularly sensitive to CapEx, this is due to the PSC mechanisms. So if more work is needed or wanted, the liquidity impact is only around 20% of the costs incurred. This makes it possible for us to pretty much execute our entire growth plan at about $40 per barrel without tapping into our cash reserves. We would all like a higher oil price, but we can make strategic moves and choices this year that most of our peers simply cannot, to adjust but also to maximize our growth potential as the market recovers in the coming months and years. This slide shows the potential what our organic oil portfolio can deliver. And let me repeat, we do not need to dream up oil prices that are double or triple what we have today to develop these assets profitably. As I've said, we've been disciplined and focused in asset acquisition and the use of capital and succeeded in assembling an exciting portfolio that can fund itself over time, perhaps not at $30 per barrel but at about $40 per barrel. Our development plan for each asset will be very much the same as before, but if we focus on low cost, low-risk early development and simultaneous acceleration of production and cash flow. You will hear more from Mike later as to how we, in practice, plan to apply this development model to Sarta. In developing these new assets and new production, we will benefit from our increasing scale and footprint and the economics of scale of operating multiple licenses in the KRI. We have very limited amount of committed CapEx, and we maintain the ability to increase or decrease the pace of development to match the investment conditions and external environment. But right now that low regret flexibility is very valuable. The diagram at the bottom illustrate the low-cost development potential of what we have in our portfolio and what these organic opportunities can do to further transform our business. As you can see, this only includes our oil assets. I should also add that the recent year-end external resources audit supported our bullish views on the potential of Sarta and Qara Dagh, which was very satisfying. Both Paul and Mike will cover this topic in more detail shortly. Our financial priorities for 2020 are broadly the same as before, no point in reconfiguring a model that serves us well. It is to continue future-proofing our business. We'll be super focused on maintaining our financial strength, and run the business so that our top capital allocation priorities remain unchanged. Our capital allocation opportunities have a very wide range that we can leverage as we navigate the current environment. We can manage our business at a CapEx level of as low as $60 million in 2020 against our original guidance range of $160 million to $200 million. Having said that, we want to invest more and can do so, but only when the external drivers are lined up to support a higher spending. Our current thinking is that in a $30 per barrel of oil, our CapEx is likely to be somewhere around $100 million this year. In other words, we do not intend to bring CapEx as low as we could, as we do not think it is appropriate or in the best interest of our shareholders. Our capital allocation will be focused on the optimization of the balance between highest value and near-term cash flow impact. Perhaps needless to say, the current environment also may provide M&A opportunities, as Bill has already mentioned. With our cash and low-cost business model, we're likely well positioned to be opportunistic, and we continue to seek to add high-quality assets that fit our model. However, we will maintain a high level of selectivity and discipline in this area. What is it that we are looking for? Well, this may be a bit boring, but it's really more of the same. It's the same whether we are looking at an asset within our portfolio or outside that we look primarily for discovered resource, assets with relatively low technical risk. We look for assets that would contribute to near-term cash generation, and we would look for opportunities to apply our risk management model and high level of certainty that we can mitigate downside risk sufficiently. And obviously, we'll look for competitiveness in low cost and low carbon. So with this, I hand over to Paul. Paul?

Thank you, Esa, and good morning, everybody. Our producing assets are an important foundation of the business. Our production that supports and informs our investment decisions. Genel has a substantial production footprint in KRI with more than 80 producing wells across 3 fields, those being Tawke and Peshkabir in the north, and Taq Taq in the center of the region. The 80 number includes 19 wells that were drilled in 2019, and our footprint will grow further from production start from Sarta later in the year. Our ability to generate cash from our productions improved by the current arrangements in place at Tawke, where we enjoy enhanced earnings from production there through a receivable settlement agreement. Recent changes to the operational landscape, the ongoing COVID-19 situation and the low oil price that have been mentioned already several times, require that we rethink what we intend to carry out and how much money we plan to spend in 2020. Even so, and as you've already heard from both Bill and Esa, we are confident that we will have sufficient production and resulting cash to fund our midterm goals. Our daily average production rate in 2019 was 36,250 barrels a day that represents an increase of 8% in the previous year's figures, and it's in line with the guidance provided early in 2019. Production was particularly strong in the first half of the year, and we had to combat a number of operational-type issues in the second half of the year. For the most part, divergence from the plan was down to procurement and operational-type issues, rather than reservoir performance surprises. The Tawke and Taq Taq reservoirs are generally reliable and predictable. Our 2P reserves at the end of 2019 stand at 124 million barrels after a year of steady production and a downward technical revision at Tawke that incidentally has no material impact on near-term or midterm -- or near-term or midterm production. I should also point out that we haven't yet added any reserves in anticipation of what might result from the EOR project needing completion at Tawke. I'll talk more about that in a minute. We've seen a significant increase in our contingent resources in 2019. As you can see from the net 2C oil resources diagram on this slide, our legend now includes almost 80 million barrels from Sarta and almost 20 million barrels from Qara Dagh as a result of technical work done there. This means that our combined net 2P and 2C position is positive for the year to the tune of about 47 million barrels. Mike will be providing some detail in a little while about the program we have planned in 2020 and 2021 that will further derisk and convert much of that resource into the reserve base. As the newest member of the Genel team and the person responsible for producing that have been keen to build up a picture of how these operations perform. Now I've just made the point that Tawke and Taq Taq reservoirs are generally reliable and predictable, which is true, but they're also different. The diagram on this slide serves to illustrate these differences. I'm afraid it isn't a very technical slide, but I think it does a reasonable job of explaining how Taq Taq and Tawke reservoirs react to an increase in water production. The x-axis in this diagram is water cut, and the y-axis is production rate or rather, the ratio of rate versus the peak production rate from water starting to appear. As many of you already know, Tawke and Taq Taq reservoirs, both have fractures, they're naturally fractured reservoirs. Those fractures have an effect to varying degrees on how the hydrocarbons within these reservoirs are stored, how they move about and how they are eventually produced. The reservoirs are characterized in different types. You can see it mentioned in the slide that Taq Taq is fracture-dominated. It's a type-1 reservoir. The fractures are prevalent, and they play a big part in how the reservoir behaves. The effect of the fractures at Tawke is less prevalent. It's more of what's called a type-3 reservoir, which means there's much more reliance on the matrix that the fractures run through rather than the fractures themselves. Tawke is much closer to a conventional matrix reservoir. Typical characteristics of a Taq Taq type-1 reservoir are rapid decline rate, rapid water coning, rapid water breakthrough and often the need to restrict rate to avoid pulling water along the fractures and out through the wells. You can see that dramatic Taq Taq decline once water appeared. That's a great data set, from 3% water to about 15% water, the production rate dropped dramatically. For Tawke, which is the light green data set, the decline is much gentler and less dramatic, more like a conventional matrix reservoir. In short, different rocks gives you different production performance. The relative performance that we've seen quite easily are the 20% water cut point on the x-axis where Taq Taq is producing only 30% of peak production, whereas Tawke is still producing 70% of peak production. It's also worth mentioning, although you can't really see it here, that it took much longer to get from dry peak production of a 20% water cut at Tawke than it did at Taq Taq. Why is all this important? Well, we use this information to optimize production, and it's important that we understand and recognize these different reservoir characteristics, I think. As an example, I mentioned a few minutes ago, an important project that's been underway on the Tawke license to take flared gas from Peshkabir, treat it, pump it to Tawke and reinject it there. The aim is twofold, we'll capture the gas at Peshkabir that has, up until now, being flared and use it elsewhere. That reduces our emissions and improves our carbon footprint, which is a good thing. That gas injection is also an EOR initiative at Tawke. It will be injected with the aim of improving or enhancing oil recovery there, while PRMS rules required us to see some sort of response to this effort before booking additional request, and while that response may take a little while to become apparent, our knowledge of the reservoir characteristics, Tawke, type-3 predominantly matrix, means that we are confident of an eventual benefit there. Next slide. Understandably, Genel and its partners are carefully considering what work needs to continue in 2020 and what further investment makes sense. DNO, our partner and the operator at the Tawke PSC have been in touch and some important and sensible decisions have been made around the level and nature of activity cuts and cost reductions there. We will issue the detail in due course, but it's already clear that some drilling activities will be postponed in 2020. Two rigs will remain in situ on warm standby, and this clearly shows a commitment by the operator, to get back into gear quickly once conditions allow. In a worst case no further activity scenario for 2020, we expect Genel's net daily production to average around 30,000 barrels a day, which is about 5,000 barrels a day below the [ WP and P ] that we had a few weeks ago before the crisis hit. You have already heard that our financial modeling mix wielded from the offset affect production and revenue against cost savings, we maintained positive liquidity of $30 and neutral liquidity at $40. As is already made clear that our low-cost base and our flexibility around capital renders is better able than some others to get through a difficult period that lies ahead. Bill's mentioned our resilience several times, but that doesn't mean that we're being complacent or resting. Our teams in Genel and DGO who are working hard on 2 fronts. Firstly, we're examining how we might be able to reduce costs and capture the deflation that will accompany the drop in oil price and the reduction in activity levels. We are looking at the size and shape of the team, and we're studying all the contractual commitments and procurement we have in place or have planned to see for the room we have there. Secondly, we're working hard in the engineering and operational space to progress proprietary work, get engineering done, improve scope definition, get contracts repaired and establish improvements to our operational processes so that when work resumes, we can move forward as clearly and efficiently as possible. It's early days, but these will be the key focus areas for us. At that, I will hand you over to Mike now to take you through the pre-production.

Thank you, Paul, and good morning, everyone. So let's look at how we're going about diversifying our KRI production. Starting with what we've described as first cab off the rank at last half year, but is now more of a train that has left the station, a startup Phase 1A development. So to recap, Phase 1A is a low-cost pilot development for 34 million barrels of 2P reserves from the Mus-Adaiyah reservoir, initially by 2 existing wells, S-2 and S-3, combined with crude processed in a leased, operated, maintained CPF prior to being trucked the 100 kilometers or so to Khurmala from the export pipeline. The cover shot shows how the site looks at the time of the investor visit in early October last year. So the before, ahead of the after, you will see in the coming slide. So let's see where we've got to on our journey to first oil at Sarta from an action tracker. Having executed the lease operated maintained CPF contract with oil served in August last year, the flowline construction between Sarta-2 and Sarta-3 and the CPF site has been completed. And the construction of the 20,000 barrel per day facility as a whole is on track, approximately 60% complete versus its schedule. Next up, once we have contracted a workover rig for which we are about to award a contract, will be to work over the S-2 wells ready for hookup, along with the S-3 well to the CPF. Then closing in on the finish line, commission the facility and confirm our operational readiness ahead of production start-up in late summer. So whilst clearly cognizant of the evolving COVID-19 situation, the impacts of which remain somewhat unquantifiable at this stage, we are, at this point, on track to start at first oil. Taking a drone's eye view now of the Sarta site, the story starts at the top end of the spine you see running down the center of the image. Crude enters through those flowlines from S-2 and S-3, then worked its way down through the separation and treatment process, right to left if you look to the 315,000 barrel storage tanks and tanker loading pumps at the bottom of the image. Before exiting stage right to the truck loading bay for transportation to Khumala, injection into the export pipeline and monetization. Production remains on track for summer 2020 from 2 wells, both of which flowed 7,500 barrels of oil per day on well test, with an initial production rate in the realm of 10,000 to 12,000 barrels per day anticipated and reflected in our production profiles. With first oil imminent, our thoughts and planning are already with 2021 and our 3-well campaign, aiming to prove up our resource base and provide the catalyst for production expansion. So what does that resource base consist of? In short, rather a lot, an ERCE audit of Genel's internal estimates concluded that the gross mid-case resource base at Sarta down to 593 million barrels, half of which is discovered. We have consequently been able to add a material volume of 264 million barrels of gross 2C contingent resource to our year-end 2019 reserves and resources ledger. The bulk of these contingent resources, 250 million barrels, sit in 3 Jurassic reservoirs owned alone, the Mus Adaiyah, the Najmah and the Lower Sargelu. FID on the pilot development of the Mus Adaiyah at 1A converted 34 million barrels of that resource to reserves. However, as the barrel demonstrates, we believe 1A at the top is just lifting the lid on what has the potential to be a material oil-producing cash-generating asset. Converting this contingent resource stacked around the commerciality and reserves, commencing soon in 2021, with a 3-well campaign, largely focused on that soon 250 million barrels of Jurassic contingent resources. The S-5 and S-6 appraisal wells alone target the volumetric and deliverability contingencies across multiple reservoir intervals. So extremely cost-efficient appraisal, maximizing the information gathered versus capital outlay. The wells [ separated in light volumes ] so updip barrel extend and downdip vertical extend and then reservoir deliverability in support of a series of investment decisions on commerciality; i.e., looking to tick all the boxes in the manner of Phase 1A down, as we stand today. Likewise, our 3-well 2021 program will also inherit a respective portion of our gross resources, with a need to moving more to well volumes into the discover category. Options for accelerated production and expanded development of these resources are already under consideration. And in keeping with our appraise while we produce velocity, depending on the reservoir fluid in question, would once again utilize pilot schemes in a continuous drive towards efficiency of capital investment. Okay. Moving on now to Qara Dagh. It does appear increasingly likely that the coronavirus pandemic will cause some delays to the planned second quarter spud. The good news, though, is that civils work has continued at pace, courtesy of a kind winter and tremendous civil method, such that armed with the necessary environmental permissions, we have completed the well site construction on time and on budget. We chose what was deliberately a naturally flat and relatively open area quite deliberately to limit the amount of civil work as far as possible and be environmentally as light as possible with our touch. Having secured a rig, the bulk of the current ongoing effort is procurement-related as we contract for the eclectic mix of associated drilling services. But whilst COVID likely causes the execution of such contracts and the project as a whole to remain at the younger traffic light a while longer, we will be extremely well placed and ready to go when the coronavirus clouds lift, in a position to move quickly to mobilize the rig and services onto location and spud that duty to appraisal well. At which point, we begin our quest to answer the key commercial questions associated with this potentially giant resource. Further good news is that the rocks aren't going to change overnight and the compelling bottom-up geological rationale for Qara Dagh will remain. So to recap, what is the nature of this beast and why are we drilling this appraisal well structure? The structure is more than 50 kilometers long. So essentially, the length of the block can around a kilometer wide, but with only one well previously drilled on it, Qara Dagh-1. That vertical well, whilst beset with drilling problems having been drilled downdip off structure on what we now understand to be the footwall side of the anticline, was nonetheless a discovery having tested sweet light oil from fractured cretaceous carbonates. So on to those legacy learnings, we're now going to drill an appraisal well, Qara Dagh-2, in a more optimal crestal position, 10 kilometers from Qara Dagh-1, with much of our drilling techniques, and probably most importantly, with a trajectory which is designed to maximize the contact with those productive fractures. As the schematic zoom shows the vertical to sub-vertical nature of the fracture networks means that a well like Qara Dagh-1 will have limited intersection with those fractures, whereas the QD-2 well is designed to maximize such connections by drilling at 40 to 50 degrees through the reservoir section. Damaging those fracture conduits whilst drilling, as was the case in QD-1, will be limited through the use of managed pressure drilling. Proving up deliverability is the primary objective, and we are giving ourselves every chance of succeeding in doing so. Without getting ahead of ourselves, the ultimate size of the property could, as we've always said, be potentially very large. So 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 Qara Dagh-1 well. And a high case touching 1 billion barrels, supported by the aerial size comparison between Qara Dagh and Taq Taq you see on the slide. So the picture clearly paints a thousand words. The same reservoir and similar fluid as Taq Taq also gives us a tremendous advantage in terms of optimal development of the broader Qara Dagh resource base. Finally, in Africa, we are a step further back on our road map of converting resources to reserves, but nonetheless, very much part of the opportunity set open to us within our existing portfolio to deliver long-term organic growth, but at lowest possible capital outlay. In Somaliland, the technical case remains compelling, high-impact resource potential in multiple stack prospects with the opportunity to target more than 500 million barrels of prospective resource with one well at the Toosan prospect. Initial response from a farmout process initiated late last year endorses that subsurface case, while the political landscape inevitably begs questions, yet continues to surprise potential investors with its long-standing stability. The strategy remains to bring a partner ahead of drilling a noncommitment. In Morocco, we have the block formerly known as Sidi Moussa, new name, new seismic image, but essentially the same game from a Genel business perspective. We have been able to leverage our outstanding relationship with the Moroccan government to achieve additional time to finish the seismic processing and integration work and to do a farm-out campaign, due to kick off around the middle of this year, ahead of making any future well commitment. So once again, together with Somaliland, the exploration for these legacy African exploration assets remains optionality for long-term organic reserve replacement and upside exposure, but at lowest possible capital outlay. Back to you, Bill.

Thanks, Mike. We are well aware of the challenges ahead, but we are confident we have the right business model to face them and then grow as the environment improves. As the year progresses with a fair wind, we'll be able to progress some of our major share price catalysts and fulfill our stated goal of creating material shareholder value. I'm now happy to open up to questions.

[Operator Instructions] The first question comes from the line of David Round from BMO Capital Market (sic) [ BMO Capital Markets ].

I've got 3 actually. The first one you talked about scaling down CapEx at Tawke, both in response to the virus, but also in response to payment. Could you, therefore, then please comment on how the payment situation is also impacting how you're thinking about future CapEx at Sarta? And if we were to think about the more significant 2C number, how much of the required CapEx could be phased like you've done for the initial 30 million barrels? Second question on the gas reinjection project, I'm just interested in whether you're able to quantify what we could see and expect from both recovery factors and production. And the third, just you've flagged the logistical issues you're experiencing. I'm just wondering how you're actually managing to keep production running if contractor rotations are such a big issue and whether a full shut-in is a possible scenario.

Thanks, David. I'll take this one at a time. The payment situation Paul has alluded to is, I don't think is -- isn't the primary driver for why we're dialing back on CapEx. But it certainly is a message -- in the announcement as people have messaged that for the industry, the payments are obviously a big part of the reason we're doing this. We've got -- we expect to get paid for what we do, and we expect -- and it's an important part of KRG's economy certainly, the oil production. So we're confident that we are going to get paid. I think at Tawke, the -- I guess, what we're seeing, and maybe it's linking to your third question, what we're seeing is that it's much harder to get the facilities and equipment and people in to do the drilling activities than it is to keep a production operation running with a sort of a stable team in place. And that's clearly what's happening at both Tawke and -- both Tawke, Peshkabir and Taq Taq is that we have teams on the ground that are committed to keeping production operations going and are able to sustain that operation for the foreseeable future. So it's not a likely risk that we see at this time. The -- in terms of the gas reinjection and maybe also -- on the Sarta CapEx, it will be a very sustained no-payment world that will warrant us to not progress our Sarta development plan with the 2021 program, which is the key next step, as Mike said, towards progressing the development of those assets. And as we've continued to do, and again, as Mike said, this sort of appraise to produce strategy that we've developed in KRI enables us to start making very rapid returns on successful wells even in that program. In terms of the gas reinjection, you can actually pick the numbers by looking at the Golar Norton report and probably comparing it to our numbers that were published yesterday. Essentially Golar Norton have at 23 million barrels in the 2P, so we have it in 2C and 45 million barrels in the 3P, which we have in our 3C category.

Okay. That's really helpful.

There's just one caveat to the Sarta CapEx situation detailing what Bill just said. Sarta investment well underway, progress, great. And I didn't really specify what the top capital allocation priorities for us are and what is included into this $100 million-or-so Capex, which we consider to be the right-ish number in the $30 per barrel world. Sarta is included in that. So it is part of our top capital allocation priorities sort of alongside the dividend and the care and maintain CapEx that we consider being the bare minimum of our CapEx program.

Maybe I can just add to Esa's add to Bill's, which is, at Sarta, we're about 75% through the CapEx and on Phase 1A. So we actually have a relatively limited amount of CapEx ahead of us before first oil. And then, of course, we're into a model, which is a least operated maintained facilities that were [ into the well ] after that point with respect to that 1A pilot development.

The next question comes from the line of Robin Haworth from Stifel.

A couple, if I may. Firstly, just on payments. I know you've -- thanks for the color that you've provided around the Lebanese banking system and so on. I'm sure you're in discussions with the KRG regularly. So I was just wondering if you could know what the status is. Have you received kind of any kind of assurance to whatever degree of binding that you will be paid this month, next month into the first half of the year? And second question is around Tawke field decline rates. So conscious this might be a question for the operator. But would you expect the field to continue to decline at sort of the same percentage rates and throughout the rest of the year as we've seen in Q1, especially given that you're going down to one rig? And then just to sort of follow-up on Dave's question about the gas injection. Do you see -- do you expect to see any benefit to production rates at Tawke in 2020? Or is it just the reserves that you've quantified and in a late life -- later part of the field's life?

Okay. Thanks, Robin. On the payments, as I said, it's -- there have been a series of events that have happened around the end of last year and the beginning of this year, sort of external events that have caused delays to the payment, initial delays and then making good and then subsequent delays. We're 2 payments behind. As you quite rightly pointed out, it's a continuing and active conversation with KRG on the need to get up-to-date on payments. And while there's no hard assurance in place, we are confident that we'll be paid or back on track on payments in the coming weeks. In terms of Tawke field decline, probably yes is the right answer to the question, but it is, talking to the operator, that the decline rate is around 20% a year, which I think is the numbers you've sort seen there. The EOR project, again, as Paul explained, we've left that out of the reserves because of the need to see the impact. That impact may well be seen within 6 to 12 months, particularly as a pressure front in the well data. And obviously, that would become part of the signaling that we would have confidence in moving those contingent resources to reserves. But I would expect that the -- sort of the impact -- the true impact of enhanced recovery and production rate performance in the production world in those patent gas floods will actually probably more likely be in that sort of year to 18-month plan.

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

I was just wondering if you could give a bit more detail on Tawke. And we've had quite a bit already, but any more you can say on this 75 million barrels technically recoverable downgrade that we had yesterday? I notice from this end of the production tail, how do you get those resources you expect to recover in the next 2 years. But if you can just talk about that, about what's changed and to mean that, that number has come down, that would be great.

Daniel, I think I guess what it is, is a continual process to look at the reserve ledger at the end of the year and taking the performance of the asset on an annual cycle, which we've seen -- we saw last year. We had a technical revision downwards. I think we've probably all seen that the overall production performance of Tawke has not been able to deliver the 2P profile that you would need to hold the reserves at the level they were at. But notwithstanding that, what we have seen is, in this technical revision, that the -- so this is the late in life downwards assessment of the production performance. And it's -- I guess, as Paul also explained, then maybe I'll open up to Michael, Paul may add any additional comments. But as Paul also explained, what we are being able to see now is the characteristics of the performance of the Tawke field in terms of the onset of inhibition from the matrix into the fractures and the benefit that gives in terms of enhancing recovery, which I think from a point of view of forecasting our year-to-year production and near-term performance, gives us good comfort that we're in the right place. Michael?

Yes. And I think, just to kind of reiterate that, I think at a field level, Tawke is behaving relatively predictably and in a conventional reservoir manner. We certainly are starting to see the effects of matrix inhibition, so matrix contribution to production. But I think it's really a case that we clearly continue to monitor production performance going forward and the operator continues with their best practice reservoir management. But I think the build is behaving in a pretty predictable.

The last question comes from the line from Thomas Martin at Numis.

Could I just ask 2 things? I think one on debt purchases. Talking about buying back bonds at value-accretive prices, is value-accretive simply below par? And are there any restrictions on the timing or the amounts of such debt purchases? And secondly, just on the sort of upside case you have with Bina Bawi. You know that the legal documents are sort of held up by the ongoing transition. So does that mean that the -- you're looking for the new head of the MNR to draw up these legal documents? And you've touched on it before, the termination auctions. And is there any feeling that the KRG might be looking to exercise those? Or do you have any reason to think they might be looking to exercise those?

Maybe what I'll do is I'll take, Thomas, I'll take the second question and hand the first one back to Esa. Clear, clear -- as I said, clearly frustrated at the fact that we haven't got the documentation in our hands the day after making such good progress in the last one, last year in reaching fundamental agreement on how to move Bina Bawi forward, which means that we've been negotiating with the KRG on a smaller initial phase -- a downsized phase that we think is fundable even in the current climate and then allows us to progress the necessary engineering work and would allow us to -- for the gas project to allow us to progress the Bina Bawi oil project to the -- for the mechanism of securitizing the gas development and keeping the capital cost down. The -- it's clear also in the interactions that we've had with them and I'll -- which have been extensive in the period between then and now that those documents are being very actively worked, and we've remained hopeful that we will get those documents in the short term. But the -- it's also clear that those documents are complicated by some of the changes that we've negotiated commercially in terms of rescaling the development, in terms of having the oil and gas in there. And that that's been part -- and because we're not at FID, we're at pre-FID state, I think all of those things have created complexity in those [indiscernible]. And so we see that there's a very strong and clear commitment from the highest levels within the Kurdistan regional government to continue with the gas projects and continue with Genel in developing that project. So we don't see that as a significant risk today. Maybe on the debt, Esa?

Yes, Thomas. Thanks. Good question. I think buying back bonds, you can have 2 very extreme perspectives on that. One is that the bond actually currently fits into our capital structure probably better than before. But it's quite obvious that, in this environment, everybody needs to be ultra super prudent about the liquidity runway and how to manage that, how to weather the storm. As we've tried to argue, we obviously are currently in a quite a strong position, and that means that we've got some flexibility in terms of how we want to develop that capital structure. The bond pricing appears quite attractive at this moment in time, pricing driven by macro events rather than company specifics, which creates an opportunity for value creation. Having said that, the volume is not very great. So there isn't like an abundance of these bonds available in the marketplace. So put these 2 things together, we're basically following the situation and during the next days and weeks and probably months considering what the options are, what the right course of action would be. And obviously, getting paid is an important part of that equation. And so that's all I can really say about it. Otherwise, I'll probably step out of the box in terms of specs and speculating.

Thank you. We have no further questions, so I will hand you back to your host for any concluding remarks.

Great. Thank you very much, ladies and gentlemen, for listening into the good results today, and we look forward to talking to you more about the progression of the businesses through the year.

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