Genel Energy PLC

LSE:GENL

Earnings Call Transcript 2018-Q4

[Murat Özgül, Chief Executive Officer]

Good morning, ladies and gentlemen. I am Murat Özgül, CEO of Genel Energy. I would like to welcome you to our 2018 full year results presentation. It has been another fantastic year for Genel, and there is a lot more to come. Today, I am joined by Esa, our Chief Financial Officer; and Bill, Chief Operating Officer. Other members of the Executive Committee are also here in the audience. Esa, Bill and I will take you through the presentation. After which, we will open up Q&A.

You may see our usual disclaimers on Page 2. We are a simple business, and we have a clear strategy for value creation. Our producing assets generate a lot of cash, and we use this cash in a disciplined way to invest in our transformational growth opportunities. We still then retain enough cash to progress the return of capital to shareholders. We have delivered on all of these areas.

We generated $164 million in free cash flow, even after making significant investments. We have then added 2 fantastic opportunities in Sarta and Qara Dagh. Both of these offer long-term growth potential. And in line with our strategy, we will invest in them, and we still generate over $100 million in free cash flow in 2019.

Given this free cash flow generation and our willingness to run an appropriate balance sheet, we have today initiated a material and sustainable dividend policy. I believe we are well positioned to offer investors an attractive mix of growth and a material annual cash return.

As you will hear, we are delighted with the addition of Sarta and Qara Dagh. And we now had truly balanced portfolio in the Kurdistan Region of Iraq. We have highly cash-generative production from Taq Taq and Tawke PSCs, and Sarta will add to this production next year. Qara Dagh is an exciting prospect. Bill will talk on this shortly. Bina Bawi Miran also remain high-potential development opportunities in the portfolio.

Before we start discussing the high potential opportunities, it's important to note that our primary focus remains on our producing assets. Cash generation from these assets in is the backbone from which we will grow the Company. Peshkabir was the star in 2018, with production rising from 55,000 barrel of oil per day, ahead of schedule and under budget. While drilling continues on the Peshkabir field, we will focus on -- more on Tawke in 2019, when 10 wells or more will be drilled in order to stabilize the production.

Drilling on the flanks at Taq Taq has also provided very positive results, and there are more opportunities at the field. With the most effective drilling program in the KRI, we expect overall production to increase around 10% compared to 2018. There are early indications that this could be conservative. As you know, this production is highly cash generative. Our focus on costs and the rapid payback from any capital expenditures made on our producing assets led to around 50% of our proceeds being converted into free cash flow.

It is also worth reiterating that we have now had 3.5 years of continuous monthly payments from Kurdistan Regional Government despite the many hardships they have faced in that time period. I am pleased to say that their financial position has now improved significantly. A monthly transfer of funds from Baghdad has further helped their economics. This is a good indicator of much improved political relationship between the federal government and the Kurdistan Regional Government.

We are very happy to deepen our investments in the Kurdistan Region of Iraq. In fact, what we expect to spend in 2019 is nearly the same amount as we spent in 2017 and '18 combined. And we still expect to generate a lot of free cash flow. There are a few areas in the world that can match the low cost environment of the KRI and provide such a material return on investments.

I will now pass over to Esa who will provide further detail on how our recent success has transformed our balance sheet and provides us with the ability to more than fund our growth opportunities. Esa, over to you.

[Esa Ikaheimonen, Chief Financial Officer]

Thank you, Murat. Good morning, all, and thanks for joining us today. Indeed, as Murat already said, we have successfully transformed our balance sheet during the last couple of years. If you look at the chart on the right, you'll see that we've moved from nearly a $0.25 billion of net debt only about 2 years ago to almost $100 million of net cash as per today. And we expect this net cash position to grow materially further in 2019. It will actually grow at any foreseeable oil price, even at $35 per barrel, we will generate free cash flow, whilst also significantly increasing our investment, as Murat said. This, I believe, makes us one of the most resilient companies in the sector.

Even after what will be rather significant investments in Sarta and Qara Dagh, we can look for more growth and also initiate a dividend policy, which we've done this morning. Miran remains a valuable asset, with 6.5 Tcf of gas, but it is currently secondary to the more attractive Bina Bawi development. This has led to added contingencies later first gas and higher risking of the valuation, therefore, a material noncash impairment was considered to be the prudent technical accounting approach at this stage.

We talk a lot about capital allocation. We like to talk about capital allocation. In my mind, it makes sense because we've been quite successful in that area. We like to call it balanced now, and that's because we've added dividend to it. Our dividend policy is a natural extension to our strategy. You think about our strategic priorities, first priority has been, and is, to invest in production where we get near-term, if not immediate, benefits and returns that are exceptional. I'll show you a bit more in a moment.

The second priority has been to invest in growth. And indeed, we are very pleased with the assets that we already have in the portfolio, but obviously, are constantly looking for more. And the third priority is to maintain an appropriate balance sheet, with enough liquidity and debt capacity to take advantage of growth opportunities that match our criteria. When you can comfortably pursue material growth opportunities and simultaneously move fast forward towards $0.5 billion or so of liquidity, the time has come to start returning capital to shareholders through a competitive dividend, and that is where we are today.

Here is an attempt to illustrate why we spend our money, first and foremost, on production. As I said, investment in production has been, and remains, our top priority. The returns are tremendous, with the cost to cover another PSC mechanisms absorbing incremental spending rapidly. Peshkabir offers returns that are pretty much unbeatable from investment anywhere in the industry. We drill a well -- so this line here is Peshkabir. You drill a well, you start producing, you get your costs back entirely in 3 months' time. You get your costs back another time -- another 3 months.

And after nine months from production, you've actually recovered your costs 3x. So not once, not twice, but 3x in 9 months. That's pretty exceptional. Tawke also provides very attractive returns, as I think you all know. But what has changed ahead of 2019 is actually Taq Taq. Wells on the flanks have been more productive than expected. We actually get our investment back a couple of times in about one year from first production also in Taq Taq. That's a big change to what the thinking was about a year ago. Quite exciting actually for a bit of a forgotten-about field of Taq Taq.

Here is a bit more detail about what we spent the money on in 2018. Our focus at Peshkabir was on wells and understanding the structure. And as you know, this was a hugely successful ramp-up in 2018. DNO did a great job; and due to the RSA, the Receivable Settlement Agreement, Peshkabir added already last year about $50 million to our free cash flow, and that's after everything is allocated, everything, including interest expenses, is allocated down to the field level.

At Tawke, the focus was more on workovers and upgrading water handling and will now turn again to drilling in 2019. More than half of our free cash flow came from Tawke. So it makes sense to drill wells, particularly as the remaining reserves in the Receivable Settlement Agreement deal continued to make it very attractive. As you can actually see, if you go back to the previous slide, Tawke is also a very attractive investment for us.

Taq Taq in 2018 was also about stabilizing production ahead of now moving back to growth mode in 2019. As I said, Taq Taq potential has been underestimated and the field has been somewhat ignored due to higher priorities with Peshkabir and Tawke. But it still contributed about $20 million to our free cash flow, and that is without the production we have seen from the last couple of flank wells, which are obviously adding an upside to all that.

The easiest and safest way for Genel to grow is to focus on what we already have. And we have already achieved the 10% year-on-year production increase that we expect to see on a full year basis in 2019. And the 2019 target production indeed may turn out to be a conservative expectation for the full year, but we'll see, time will tell. My view, more upside than downside definitely to our production guidance.

Other investments is what makes the next growth stage very exciting for Genel. You've heard quite a bit about Sarta and Qara Dagh. These are stories that will develop over time. But from portfolio perspective and from financial perspective, Sarta is precisely what we were looking for when adding it to the portfolio. It will move to production in just over a year, and the cost and risk is very low, but the potential upside is huge.

Qara Dagh offers a rare geological opportunity to appraise a significant structure with proven hydrocarbons. And Bina Bawi may yet move up our priority list depending on the discussions with the KRG. Discussions are active and progressing. And as you may know, the CPs under the gas lifting agreement were recently extended to end of April. We believe the negotiations may well take longer than that, but the contracts allow for a further 12 months to find a solution.

A couple of things I can say with certainly -- certainty with regards to Bina Bawi. We like Bina Bawi. We like it a lot. It's a valuable opportunity. The other thing we can say with certainty is that we'll only ramp up spending when there's a firm commercial solution and a visible route to returns with a limited downside. That is very much in line with our capital allocation philosophy, and we will continue in a disciplined manner. But indeed, Bina Bawi offers a great value option for Genel, and we are doing absolutely everything we can to accelerate that.

Somaliland and Morocco are longer-term opportunities, and again, we will spend on them appropriately. Now appropriately in this context means not much. If we believe the geology looks good enough to drill a well, frankly, we expect to find someone else who shares that belief and will fund it. Even more on capital allocation, I warned you, I said we like to talk about capital allocation. We like the portfolio we have, but we are also very much a growth company, so we will continue systematically to add to the story.

We have agreed our growth targets with our board, effectively looking at production or late-stage appraisal with limited downside risk, material potential and a low-cost entry. There is no point in diluting a well developing story. Sarta and Qara Dagh are clearly in the sweet spot. As a matter of fact, ticking all of those boxes that we've illustrated on the slide. But we believe, and we know that there are multiple other deals to be done that fit the strategy in our investment criteria, so I believe there is more to come.

Now getting to the end of my piece of this morning's prepared remarks. And it's time to put it all together. And what is a more exciting way of putting it all together than to show how our liquidity developments, sort of medium term, is starting to look like? Even in a very conservative basis, our liquidity is set to rise materially in coming years. Our base case with oil price at $60 per barrel, with only Sarta Phase 1A and less than the 2P production at our existing producing assets suggest about $1 billion of liquidity by around 2022 around here.

This, by the way, this picture here assumes that we refinance our 2022 bond when it matures. But that's a pretty safe assumption if we want to do so given the strengthening portfolio and improving credit case for Genel. We are convinced that this conservative base case will be outperformed. Even the upside that you can see shooting up like that does not include any blue sky. As a matter of fact, it doesn't even include Bina Bawi. We believe in Bina Bawi, we were just -- are not -- it's not a necessity for us in terms of achieving our objectives. It's not included here.

This liquidity profile illustrates our ability to accelerate growing the Company and still deliver a cash surplus more than enough for a competitive and sustainable dividend. So not surprisingly, I was using that lead into the dividend story. So our plan is to propose a dividend policy to our shareholders. We've announced that intention this morning, starting no later than 2020. Although we've been strengthening our credit status continuously, and we'll continue to do the same, obviously, the noncash impairment of the Miran gas asset means that we need to seek a waiver from our bondholders, as we are also contemplating the possibility to accelerate the distribution to already 2019. This sort of accelerated dividend in 2019 remains subject to exceptional waiver discussions with our bondholders, and we intend to open up such discussions very shortly.

And now over to Bill to show, among other things, how this liquidity is supported by our future production. Bill?

[Bill Higgs, Chief Operating Officer]

Thank you, Esa, and good morning, everybody. So we'll -- as Esa said, we'll now take a look at the performance of the underlying assets that support that very impressive liquidity chart that Esa just showed. So let's start with the production profile. And you can see our dark blue base case is a very conservative case. Upside from Sarta, Qara Dagh, Bina Bawi and even Peshkabir, is not included in that production forecast. There's very limited downside risk, we think, to this forecast, but potentially substantial upside, which Esa already mentioned.

The un-risked production CAGR out to 2025, of the rather disappearing blue bars at the top there, is on the order of 15% per annum, so that potential upside is substantial. Another reason why we're able to talk about the possibility of a dividend is because we've got a much more diverse portfolio, and that's really illustrated in this chart. This is the -- when I joined the Company 16 months ago, most of our supported -- our production was supported from a limited number of high-production wells within the Tawke field.

The chart on the right-hand side shows you 2 things. Firstly, it shows the growing number of wells in the well stock today, which has grown by 50% in that 2 years. And in fact, also, in the colored bars, it shows that the ratio of high-performing wells is now much even -- more evenly distributed across the assets. So we have, rather than 16 months ago when we had all of our eggs in the Tawke basket, we now have a much more diverse source of cash flow. And what we see is that this gives us reliable production, reliable cash flows. And also, with the opportunity to add Sarta production next year and possibly others in the near future, it gives us the sense that this is a much more diverse and reliable performance -- production performance.

When we take a look at the reserves, there is more to come. The success of Peshkabir and the addition of Sarta also helped to give us an impressive reserves replacement ratio of close to 140%. With such an extensive drilling program and commercial opportunities in the portfolio, there's clear potential for us to continue this in the coming years.

As you can see, our contingent and prospective ore resources in the figures are on the right-hand side. And this is -- prospective and contingent ore resources in Qara only, are significant. There are clear time lines to their potential conversion into reserves. Sarta moves through its phases over the coming years, while drilling success at Qara Dagh provides an exciting opportunity for next year.

Reserves are also ready to be booked should we reach agreement with KRG on the development of Bina Bawi. We shouldn't also forget the fact that we have an enhanced oil recovery project at Tawke field, which we'll touch on again in a second, which also has much promise to add reserves in the future. There's still -- in addition, there's still potential to explore further at Peshkabir. Again, the diversity of reserves movement supports the diversity of production and therefore, confidence in cash flows and liquidity.

Taking a look at Peshkabir. The performance has been absolutely exceptional in 2018. DNO has done a phenomenal job. And I think the key thing here is that we've been able, over the year, to successfully drill across the entire breadth of the field. Currently, we're producing high-rate wells in these black -- for these black wells on the chart at the bottom, and there's 0 water production to date. There remains significant room to grow. Working with DNO, we will continue to appraise the full extent of the field, as illustrated by the white dotted lines. We have the opportunity to drill up to 4 wells in 2019.

But the main work would be a reserve for the development of the infrastructure as the -- and in formulating an optimal depletion plan for the field. The central processing facility will be fully operational shortly and the crude pipeline is under construction. Any excess production further to the 60,000 barrels a day of pipeline capacity can be -- continue to be trucked the short way to the export facility at Fishkabur. We're also progressing a flares out initiative, which will utilize the gas at Peshkabir to help increase productivity at Tawke, and we expect that project to be completed early in 2020.

Moving on to Tawke field. As you -- Tawke production continues to come from across the asset. Unlike Taq Taq, there remains a significant production contribution from the matrix. And as DNO stated, there is no material water production situation at Tawke field. A large number of infill well locations have been identified, and progressing the drilling activity will help to stabilize production after a couple of years of relatively low activity at the field.

As it is, there are 30 well locations that have been identified to form part of that asset development plan, with up to 14 wells ready to be drilled in 2019 and more to follow in 2020. We've also upgraded the water handling facilities to exceed forecast demand for the foreseeable future. As already mentioned, 2020 will also see the start of the enhanced oil recovery project, utilizing gas produced at Peshkabir to improve recovery efficiency at Tawke field.

Moving on to Taq Taq. Work in 2018 was very successful at optimizing production from the center of the field, the crest of the structure, and providing the opportunity -- and proving up the opportunity on the flanks. Field production outperformed our expectations by over 1,000 barrels a day without adding any new well stock, which is a great performance.

The production picture is starting to change as we appraise the flanks of the field. As you can see from the diagram on the right-hand side, the production from the latest 2 wells on the northern flank are now amongst the most productive wells in the field, with no water at all. Management of the free water level has also allowed the TT-21 well down to the south to come back on production after it was converted to a water injection well in 2016, which is always a great outcome.

This graphic here illustrates what has happened over the course of the field's history. The initial strategy, the early wells, were all drilled at the crest of the structure, with the expectation that we will drain the field from the center and expecting the free water level in the field would rise uniformly over time. As we can see from the graphic, the blue dotted line is the current view of where the free water level is, and this clearly hasn't happened. That's not a uniform free water level movement.

High vertical permeability of the fractures has dominated, and water encroachment has occurred into the center of the field. We're now targeting the flanks. And as the fluid offtake has dropped in the center, the field is starting to occur to the right. Hence, what happened to TT-21, being converted back to dry oil production of around 750 barrels of oil per day after being shut in for 2 years. This creates opportunity, and we're again talking about production growth at Taq Taq.

Drilling on the flanks will continue in 2019, with the next wells in the program, TT-20z, due to come on production shortly. As Esa mentioned, the economics of these wells have significantly improved and -- which drives us to continue our active drilling program. The initial phase of drilling will shape how many wells we can drill in the coming years and how much production growth can be achieved from the field.

Moving on to Sarta. From Taq Taq, which has produced over 200 million barrels of oil to this asset, which is very much at a different stage. We are delighted to be working with Chevron at Sarta. The asset has the potential to become one of the largest fields in KRI, and we look forward to starting the development journey and understanding the field potential. What we know for certain at the moment is that 2 wells have flowed at commercial rates, with good quality oil, and there are multiple reservoirs offering material potential. Our initial estimates of overall resource is 0.5 billion barrels.

Taking a look at Phase 1A. We estimate that 150 million barrels of those resources are relating to the Mus and Adaiyah reservoirs. And this is where the production is targeted in Phase 1A. We will place the 2 successful wells on production. And then we intend to follow with a third well, and the production will run through a 20,000 barrel a day production facility. Should these wells prove to be successful, we will rapidly appraise the structure. Further production capacity will be then be added as required as the field is developed when production ramps up, with the test spreads being used in a similar way to the way that we have been successful in Peshkabir.

Peshkabir is also a relevant touchstone -- I think I got that right, actually. Peshkabir is also a relevant touchstone for Qara Dagh, where we are again partnering with Chevron, this time with 40% equity and operator. There's been one previous well that's drilled on the license, the yellow dot in the wonderful photograph on the right, and that was drilled in 2011. But like Peshkabir, even though this flowed well -- flowed light oil, we believe it was drilled off-structure, so the opportunity is to find the crest of the structure at depth.

Looking at the cross-section here. This is the reason why we think it missed its target. The well was based on the incorrect structural model, with the axis of the anticline at the surface being offset from the anticline at depth. The QD-2 well, the blue line illustrated on the cross-section on the left, will be drilled in the first half of 2020, on a more crestal location. Work is in progress on deciding the optimum location of the well, and we look forward to keeping you updated as we progress to spud this well.

Moving on to Bina Bawi. It remains a challenge in terms of the commercial terms, but the development is ready to go, both from an oil and gas perspective. We've been able to agree smaller-scale gas facilities as a first step in the project, which can be scaled up using trains of capacity. This reduces cost to first gas. And with the early oil opportunity ready to go, it will help supplement cash generation for this business. We continue to discuss the license with KRG, but the discussions are challenging, as Esa mentioned. Should appropriate commercial terms not be agreed with the KRG, then we'll not be making any significant further investment in the Bina Bawi license, but it does remain a great opportunity, which we believe has been right scaled for both ourselves and KRG.

Taking a look at our African exploration, Somaliland and Morocco on both seismic analysis is progressing, and we're looking to build a prospect inventory. As we focus on prospects, we'll also look to bring in partners to drill a well. We will not proceed at the current equity levels, and so the licenses offer up upside potential with very limited downside, and again, with little impact on our overall liquidity.

With that, I'll hand back to Murat.

[Murat Özgül, Chief Executive Officer]

Thank you, Bill. As you have heard, 2019 will be a very busy year. Our capital expenditure is increasing significantly, but remaining highly disciplined, with activity focused on assets that can deliver shareholder value in the near term.

So here is what this expenditure means. We expect production to grow year-on-year. Our capital expenditure program is more than covered by our cash generation. And we expect to generate over $100 million in free cash flow even if the oil price falls again towards $50 per barrel. And as discussed, this cash flow allows us to return money to shareholders, even while seeking to grow the portfolio, both organically and through M&A.

And with that, we will be very happy to answer any questions that you may have. Thank you.

[Robin Haworth, Stifel]

It's Robin Haworth from Stifel. A question on Tawke, if I may. So I think the current reserves life from the operator implies more or less 0 decline over the remaining license period. So I was just wondering if you could talk about how you're thinking about the drill out there? Is that a feasible objective? And with the quite heavy drilling on the field in the short term, should we be expecting production to go up from the Tawke structure itself or just to stay flat? And then just on -- a follow-up on Sarta, please. If you can truck oil from the Phase 1A production before you have the production facilities in place, is it why -- what's the reason for delaying until 2020 before we'll see first oil from that development?

[Murat Özgül, Chief Executive Officer]

I think, Bill, you can take both of that.

[Bill Higgs, Chief Operating Officer]

Okay. Thank you. So taking the Tawke question first. Obviously, I think that's a question that, to a large degree, is one that's well directed towards the operator on their expectations of activity and production performance. But I think the key observation there is that we've got, as we mentioned, 30 well locations that are locations for the field. We're going to target drilling up to 14 of those this year. That's certainly a level of activity that's manageable when you look at the amount of work that was achieved in 2018 between Tawke field and Peshkabir, so shifting the focus from Peshkabir back towards Tawke for '19.

So from a work rate point of view, I think that's quite achievable. The fact that we haven't drilled on the field extensively for the last 2 years does mean that production has declined, and we would expect, as the operator said, we expect production to stabilize in that 75,000 to 80,000 barrel a day world on the back of this program. If you continue to do that for another year and maybe another year afterwards, then you can see that you can start to project out a flat to potentially growing production forecast over that period of time.

So on Sarta, unfortunately, we do have to process the crude before we truck it. So the CPF enables us to stabilize the crude, take the gas out and before we put it into trucks. So you need the CPF. So our initial production facility will be a 20,000 barrel a day CPF with a crude tanker loading system. And as we prove up more resources, then we can start more reserves. We can start to look at the option for implementing a fixed pipeline for production, in much the same way as we've been doing again at Peshkabir for the last 18 months. We're initially trucking, and now we're going to be moving to pipe.

[David Round, BMO]

It's David Round from BMO. I've probably got 3. The first one, just on Peshkabir. Obviously, the operator has revised the numbers, the reserve numbers there. But again, you've talked about it as upside in quite a few of the slides. So perhaps if you are able, can you -- to the extent you are able, can you talk about the possibility of future reserve additions there? The second one is on Tawke water. So you mentioned Taq Taq water a few times, and that was very helpful. Can you provide any further details about what you're seeing in terms of water at Tawke? And the third one is on Bina Bawi, and just whether you're able to say anything about the stickying points in terms of commercial terms there.

[Murat Özgül, Chief Executive Officer]

Again, I will give the first 2 to Bill, and I will take the last one.

[Bill Higgs, Chief Operating Officer]

Yes. So on Peshkabir, I mean, it's very -- it's been a great program and a fantastic year. Drilling up the structure the way we have has certainly proved up a substantial amount of reserves, and we've seen that movement in the year-end recording -- reporting. As you can see from the diagram, there's a couple -- probably a couple more slots on the outside to drill further to appraise it. And as we get more performance data, then we'll have a better understanding of that distribution of proved versus possible and probable, which is still quite wide when you look at the numbers.

So we'd expect that to tighten up over time. And whether that results in a 2P reserves addition or just a timing of the range between 1P and 2P, we'll wait to see. But there certainly is -- early indications are that the field is very well connected. And it's got -- and that obviously means that there is a potential for the reserves to grow. So the big fields sometimes can get a bit bigger. On Tawke water, obviously, again, discussions about water at Tawke field and how they're handled is really as much for the operator. But probably, we are best placed -- I think we are best placed to talk about some of the similarities and differences between water production at Taq Taq field and Tawke field. And it's clear they are different. And the reason for that is that Taq Taq is dominated completely by fractures.

There's no residual matrix contribution into the performance. As we saw in the diagram that we showed, the water has a very, very strong -- or there's very, very strong vertical permeability because of the fractures, very weak lateral permeability. And so the system tends to draw water very quickly towards the wells -- in the case of the Taq Taq field, in the center -- and has left us with this rim of opportunity around the flanks. What we see at Tawke in comparison is a much stronger contribution from matrix and imbibition from matrix into that fracture network, which acts as a dampener of that high vertical permeability.

So you get a much more even vertical and horizontal permeability. And as a consequence, the water doesn't encroach anywhere near as quickly at Tawke field as it did at Taq Taq field, and so we are getting a much more uniform contribution. Plus also, we're getting a volumetric contribution in terms of reserves from the matrix at Tawke field. So that's the comparison between the 2. We have in place the water handling facilities to manage the water that we get at Tawke, which the operator has talked about for the foreseeable future. Over to you.

[Murat Özgül, Chief Executive Officer]

I think I should start with the history. So initially, we were planning together with KRG, Miran and Bina Bawi together development, and we are looking an opportunity for one facility -- gas treatment facility in between treating around 10 Bcm gas. So after all the engineering studies and the CapEx requirement, we ended up with phased approach in Bina Bawi first, Miran later. Why? Because in Bina Bawi, the light oil development will have the gas development itself first. And also, the huge gas potential is giving us very good comfort on this one.

And on the Bina Bawi itself also, we discussed trains. So a phased approach on the gas development also. The first train, as Bill discussed in his presentation, we are planning around 300 million standard cubic feet capacity, raw gas capacity. So what we are trying now an investable and less CapEx required structures, and we know all KRG's intention to develop this gas as fast as possible. So we are trying reasonable time line together with KRG and also a reasonable commercial structure for the investment for us helping the oil development gas, funding the gas development and moving ahead first Bina Bawi, then apply the same mechanism to Miran. So that's the whole story in recent discussions.

[Dan Slater, Arden]

Dan Slater from Arden. I just wanted to ask about any further acquisitions. Obviously, you've bought Sarta and Qara Dagh in Kurdistan. Are we likely to see anything more like that? Are there any other opportunities? And are you thinking about potentially buying anything elsewhere as well? Or are you sort of done with acquisitions for now?

[Esa Ikaheimonen, Chief Financial Officer]

Yes. Let me take this one. If we had other things to talk about, we would have talked about it already. It's a simple answer, but obviously, that's not a satisfactory answer, so let me try and give you a more satisfactory one. There are definitely other opportunities, I think I mentioned that already in my presentation; multiple similar opportunities actually inside Kurdistan, outside Kurdistan. I think your question is probably slightly referring to the strategy as well.

We are agnostic in terms of whether we grow our business in Kurdistan or outside Kurdistan, and that hasn't changed. If you go back a year ago, and you read pages 10 and 11 in our Annual Report, the glossy one with the covers and everything, it talks about focusing M&A in areas of low to moderate political risk. And a lot of people rightfully read into that and thought that meant a bias towards investing outside Kurdistan. Quite honestly, during the last year or so, the political and economic development in Kurdistan has been remarkable.

And right now, we still say the same thing, we prefer investing in low to moderate political risk environment, but Kurdistan fits into that box now, and hence, Sarta; hence, Qara Dagh; hence, desire to continue to invest there. And I think our track record, particularly recently, in managing those investments and investing smartly in a disciplined manner speaks for itself. And we'll continue the same with Sarta and Qara Dagh. So a summary, we like Kurdistan a lot, but there are opportunities outside Kurdistan, and we'll pursue all of those and tell you more about them as and when we've got something to talk about.

[Al Stanton, RBC]

It's Al Stanton at RBC. Two questions, if I may. I think one's for Bill and the other's for Esa. So with respect to Peshkabir, I mean, the 2P reserve number did go up for the oil, but I noticed the 3P number the operator put out came down. So my assumption is that that's allocated some of the structure to a gas cap. So I'm wondering if, ultimately, the Peshkabir development is a larger more sort of considered development, i.e. it'll be a plateau production rather than a peak in a more complex field with, as you say yourselves, pressure maintenance and other requirements? And then, Esa, I can't remember if you said a discussion or negotiation, but what levers are there to pull with the bondholders? Will they be looking for a higher coupon? What do you envisage that discussion involving?

[Esa Ikaheimonen, Chief Financial Officer]

Shall I start?

[Bill Higgs, Chief Operating Officer]

No. Sorry, I was...

[Esa Ikaheimonen, Chief Financial Officer]

Go ahead, Bill.

[Bill Higgs, Chief Operating Officer]

I was already thinking. I wasn't listening to your second question because you already said that wasn't for me, so I wasn't paying attention to when you were stopping. Al, so Peshkabir, yes, I mean rules of life. Rules of life say that, actually, over the course of time, we would expect the 1P to increase and the 3P to go down towards sub ultimate EUR for the field. So that -- I don't think there's anything particularly surprising in that. As we've talked about before, it was a little bit -- we felt it was a little asymmetric in the booking at the end of '17, the year-end booking at '17, there were a lot of -- where the resource -- or the reserves had been put into 3P because of the way the booking happened, so which I think I've overworked that a little bit. I would say, in terms of complexity that we don't see it as a complex field. We see the field quite connected and the drilling has proven that to be so.

The high-angle wells are performing very, very well. And we had a known gas cap in the asset at the end of '17. So I don't see that as more complex. I think the idea of having a -- taking a breath at the moment and trying to understand what is the optimal depletion plan is a good strategy for the asset given that we're still very early in the production life. But I would expect that, certainly in '19, that's likely to result in more of a plateau-like behavior. And we'll have to see as we go through that analysis whether that becomes true for the remaining field life.

I think also just sort of thinking through that, in some ways, we almost become reg limiter on gas GOR rather than oil and other things as we have to manage the associated gas and make sure we have the facilities in place to take that gas, either back into injection in Peshkabir or take it up to Tawke and inject it as part of the EUR project. So quite a lot of thinking to be done in the short run, but in terms of complexity, I don't see it.

[Esa Ikaheimonen, Chief Financial Officer]

Okay. The levers to pull with the discussions with the bondholders. A little bit of context first. So the board decision was to start the distribution in 2020, so it doesn't really make an awful lot of difference as to whether we distribute the first element of our dividend policy, June, July this year or January, February next. So it's -- it shouldn't be seen as a major issue for Genel. We can defer it a little bit if that's what it takes, and we will potentially compensate the shareholders in 2024 not distributing in 2019. So at the end of the day, a bit of a zero-sum game with some timing issues associated to the distribution. Now in terms of the discussions with the bondholders, again, a little bit of context.

Obviously, our credit worthiness has improved tremendously since December 2017 when the new bond was put in place. And the bondholders actually liked the bond, so I think that's a good starting point for constructive discussions with the bondholders. We haven't started these discussions yet for understandable reasons because we only this morning actually created the need for it. So I can't really comment on what the levers are, other than by referring to what we've seen other companies doing in similar situations.

So I haven't seen anybody actually touching their coupon rate, but I have seen companies being relatively moderate, sometimes a bit higher, but usually a relatively moderate sort of one-off waiver fee, which is simply just the compensation for people to walk to the fax machine and vote yes. I've seen coal premiums being adjusted and some other forms of credit enhancement. So I think our probable approach would be to talk about a moderate waiver fee.

And I'm emphasizing moderate because there is no point in -- for us in paying too much for such a waiver because we can basically kick off the distributions in January next year as well as June or July this, and then perhaps talk about some compensating credit enhancements because, clearly, dividend out of the door, all else equal, is sort of a negative credit event. So that's kind of the levers that I think are worth discussing, but we haven't started the conversations.

[Al Stanton, RBC]

Could you see it possibly morphing into the start of refinancing of the bonds ahead of the 2022 repayment?

[Esa Ikaheimonen, Chief Financial Officer]

It's always a possibility. That's very speculative. So it's a non-call free. So I wouldn't actually be able to call it without an amendment to the bond agreement, we wouldn't be able to call it before December 2020 anyway. So it's part of our capital structure for now, and I think the assumption should be that it's part of the capital structure until 2022 and then we'll do the refinancing ahead of that.

[Duncan Milligan, Goldman Sachs]

Duncan Milligan from Goldman Sachs. I'm just wondering if you could go through the Sarta kind of discovery and talk a little bit about how that varies related to Taq Taq and how that varies related to Tawke? And just give kind of a little color in terms of what we should be looking for as you go through the development program there in the early appraisal wells.

[Murat Özgül, Chief Executive Officer]

Bill, over to you?

[Bill Higgs, Chief Operating Officer]

Yes. So I think probably a good place to start is what have we learned from producing oil fields in KRI? And again, maybe compare and contrast Taq Taq and Peshkabir as part of that learning and then how that has been taken into thinking about Sarta. So Taq Taq, obviously, is sort of building big, central processing facilities early with the expectation that you're going to deliver a 2P reserves outcome. And then the reservoir's being a little bit unforgiving and now we're substantially over capacity. In contrast to that, Peshkabir is this sort of appraised developed strategy of putting in well test spreads to understand what the well performance and deliverability now are in the range of outcomes, start making money and then building rightsized central processing facilities in increments.

And I think it's very good from a capital efficiency point of view. It's very good from an uncertainty management and risk point of view. And so really, what we've done working with Chevron on Sarta is to say that that's -- this is the way to go forwards, and Chevron were already there in their thinking as well. So we take the first 2 wells which have been successfully tested, put them on longer-term production through a rent-to-buy production facility, add a third well to that facility and start stressing the reservoir to see what the reservoir has got. Then drill in 2 or 3 more appraisal and development wells and put those on production probably with separate well test spreads. Then we're starting to get to this point where we say, okay, I can see how much resource, about 150 million barrels, we have within the Mus and Adaiyah, how much of that is actually reserves.

And then we start to again grow the production facilities and the well count consistent with that. So that sort of is this phased journey of development over the next few years that will take us to hopefully an optimal development of around 150 million barrels of just Jurassic oil. And then we have these other opportunities, some heavy oil, some condensate in deeper reservoirs, which we'll then look to optimally bring into that picture. And there's things we're looking at in terms of the relationship between having condensate and having heavy oil, those 2 things can actually work to help each other sometimes. But those are for later. Right now, it's just let's just steadily build up, keep the cash exposure low, start making money and see what the reservoir has to give us.

[Stephane Foucaud, GMP First Energy]

Stephane Foucaud from GMP FirstEnergy. A question again on Sarta. You talked about the need to process the oil because of gas content that need to be extracted. Could you perhaps come back on how much gas we talk about? Whether it's in the 2P? Whether it's on top of the 2P, et cetera? Then again, on Sarta. On the fiscal term, any indication on p ast costs that could be transferred to the farm out to Genel which would be used as cost pool?

[Bill Higgs, Chief Operating Officer]

So the GOR in the oil in the Mus and Adaiyah is around 600 standard cubic feet per barrel. So it's not dissimilar to Peshkabir actually. So it's a reasonably gassy crude. We've seen this elsewhere. The same is actually very similar to Bina Bawi oil, which is actually in the same reservoirs. So therefore, you have to stabilize the crude before you put it into a tanker. So initially, that will be a -- it's basically going through separators and flaring that gas. Ultimately, as we move down this phased development, and we start to see how many -- how much reserves we have at Sarta, we'll start to also look at a gas solution in the way we have at Peshkabir, whether that be processing for export and sale or reinjection, that -- jury is still out on that. But we need to process to stabilize the crude in the short run. 2P? Sorry, Stephane?

[Stephane Foucaud, GMP First Energy]

The 2P, are they purely oil?

[Bill Higgs, Chief Operating Officer]

Yes. Yes, so -- yes, so -- correct. Yes, so the 2P is purely oil. We actually carry in our ledger contingent resources in the ledger that we're publishing that are contingent resources for gas, both at Peshkabir and Sarta.

[Stephane Foucaud, GMP First Energy]

[Indiscernible]

[Bill Higgs, Chief Operating Officer]

We have been given the opportunity to access this substantial cost pool as part of the deal. So we're sharing it, and it's large.

[Stephane Foucaud, GMP First Energy]

[Indiscernible]

[Bill Higgs, Chief Operating Officer]

I'd talk to the finance guy.

[Esa Ikaheimonen, Chief Financial Officer]

I think that is some information for now is not in our power to disclose.

[Thomas Martin, Numis]

Thomas Martin, Numis. Just following on, on Sarta. You've got the cross-section on Slide 25 there. And you've got Mus-Adaiyah colored in and Najmah colored in a bit. I think you said before that you've got -- you got hydrocarbons in every zone that you go through. So can you just talk a bit more about what's driving these bits that you've colored in? Is this areas that have had tests performed on them? And what sort of work program you're -- as I understand, you're mainly focusing on Mus-Adaiyah with the first -- with the Phase 2 program. But will you be looking to, with those wells, target the other zones to understand the resource whilst you're mainly focusing on developing Mus-Adaiyah?

[Bill Higgs, Chief Operating Officer]

Yes. And maybe to help there, Thomas, the diagram on Page 25 probably could do with a key on it, but actually has 4 colors of green on it, believe it or not. What -- the mustardy color of green is also where we've found hydrocarbons in those intervals as well. So when we talk about having drilled the wells and found hydrocarbons everywhere, we pretty much have every one of the reservoirs from the Triassic down -- from the Tertiary down to the Triassic, which are the typical KRI reservoirs; have found hydrocarbons in them.

Obviously, the shallow ones, the Tertiary and the Cretaceous, in this instance, are heavier. So they're heavy oils. And then as we go deeper down into the Triassic, unlike Bina Bawi, actually, we have a condensate in the upper end within the Triassic, the gas in the lower interval. So it looks like a wetter system in that the hydrocarbons are trapped down there. So plenty of things to go after. Obviously, the dark, darkest green is the area for the Phase 1A development. The lighter green are options for subsequent Phase 1B developments. And then the rest is to be thought through.

[Thomas Martin, Numis]

Your 150 million estimate, that is just across Mus-Adaiyah, including the mustard, the light and the dark green?

[Bill Higgs, Chief Operating Officer]

The mustard, the light and the dark green in the Mus-Adaiyah reservoir is the 150 million.

[Thomas Martin, Numis]

And from the 150 million to the 500 million, where on this diagram will that incremental 350 million be?

[Bill Higgs, Chief Operating Officer]

All the other bits in mustard.

[Thomas Martin, Numis]

Okay. So this is just -- this isn't showing gas condensate zones? This is showing oil zones on here.

[Bill Higgs, Chief Operating Officer]

They've been treated as hydrocarbons down in that deeper interval. So it's indiscriminate mustard, I'm afraid. I need to chat with my IR man about that.

[Thomas Martin, Numis]

Sorry, Andrew. I've got a last one then, flipping to Qara Dagh. So you think the initial well was drilled off-structure, you've got the cross section here. You got low rates -- or not you, but the prior operator got low rates on the test. What's -- what do you think is driving that? I mean, it's an anticline structure. Is there something to do with the fracture distribution over in this edge of the structure that you think will be different in the middle, or is it not fractured?

[Bill Higgs, Chief Operating Officer]

As much as I think -- it tends to be well geometry. So it is access to the fractures. This is a share in each reservoir. So the same as Taq Taq, same reservoir type as Taq Taq, so it is about fracture, fracture connectivity and the wellbore connecting to the fracture network that's going to drive deliverability. And I think it will be fair to say that our difference in [indiscernible] by the time they actually got there, we're probably just as happy as anything that they actually got there, have managed to test the well rather than -- because they were -- they would've -- I mean, they sidetracked their wells so many times and they would've been in trouble. So drilling an optimal well, having that knowledge of the first well, we can drill a high-angle well that targets the fracture network and uses our learnings from Taq Taq to hopefully deliver a higher-performing well.

[James Thompson, JP Morgan]

It's James Thompson from JP Morgan. Just in terms of Bina Bawi and your thoughts there. Obviously, you've given us a new view in terms of the phased trains. I mean, I'm sure you don't want to give out too many kind of commercial terms. But can you give us any guidance as to the effective cost per BOE that maybe you might be assuming in there, just so we can think a little bit about the new structure really? And how this phase is going to roll out versus the previous plan?

[Murat Özgül, Chief Executive Officer]

First of all, the raw gas pricing will stay as it is. If you remember, this is 1.2. So we are working on the optimum structure for the midstream bit of the projects. This phased train approach will have the -- a more investable structure for the midstream section. The oil development or raw gas development on the upstream side is not the problem, so a whole reason that we try to develop this as a train approach is the midstream projects, more financeable, more attractive for the new potential partners and less CapEx requirement.

And as I mentioned, the oil will help to develop raw gas easily. But really, I cannot disclose any other figure behind it. If you recall, on the midstream cost for the 10 Bcm which we were talking, around $2.5 billion to $3 billion, let's take rough number, $3 billion. Now we are talking about $300 million raw gas capacity, which is almost 1/5 of the 14 Bcm raw gas. So we are talking about 1/5 or slightly more on the first train for the midstream total CapEx. Anything you would like to add?

[Bill Higgs, Chief Operating Officer]

Just adding to that. To be -- to again, to be clear on that. Commercial structure really, what we're dealing with is a tolling fee arrangement to satisfy the capital for that midstream project that becomes essentially a tolling fee to take raw gas and process it. So you can think about what sort of returns might I want to expect for a tolling fee investment. As Murat said, what we've done is we've -- we think by having a smaller phased development, it can become more attractive to both debt and equity finance in that tricky part. Upstream, what we've done upstream is essentially demonstrated that we'll need less wells than we thought before, so a low well stock. It's a simple system, wells, gathering system, condensate separation and then raw gas to the plant. So from an upstream point of view, it's actually quite a simple project.

[Murat Özgül, Chief Executive Officer]

Okay. I think we are done. Thank you for today, for joining us and sharing your time with us. Thank you so much.