Genel Energy PLC (OTCPK:GEGYF) Q2 2016 Earnings Conference Call July 28, 2016 4:00 AM ET
Phil Corbett - Head of IR
Murat Özgül - CEO
Paul Schofield - COO
Ben Monaghan - CFO
Rafal Gutaj - Bank of America
James Thompson - JPMorgan
Thomas Martin - Numis
Robin Haworth - Stifel
David Mirzai - Deutsche Bank
Justin Teo - Credit Suisse
Dan Ekstein - UBS
Good morning and welcome to the Genel Energy 2016 Half-Year Results Conference Call. I will pass you over to Phil Corbett, Head of Investor Relations at Genel. Please go ahead.
Good morning everyone and welcome to Genel Energy’s 2016 interim results conference call. We note a busy morning for results in the wider sectors, so we appreciate you joining us. On the call, the management team will be taking you through the results presentation which was published a short time ago on our website at generalenergy.com. After that we will open up for Q&A.
I will now hand you over to Murat Özgül, our Chief Executive.
Thank you Phil, and good morning everyone. This morning’s presentation focuses on three key areas; regular payments and recovering the receivable, maximizing the value of our KRI oil assets, and deriving the gas business forward. I will talk you through the first of these before introducing you to Paul Schofield, our Chief Operating Officer who will detail our strategy to maximize the value Taq Taq and Tawke. After this, I will provide an update on the gas business. Paul will run through an exploration update, then Monaghan our Chief Financial Officer will update on our financial performance. Let me start on the slide 4, the key positive in the first half of 2016 was continued payments for our [indiscernible] oil production and recovery of the receivable. The KRG has made nine consecutive payments between September 2015 and June 2016, which is delivering US$193 million in gross proceeds for Genel. You will see a further payment for Taq Taq was announced yesterday, of which, our share is around 14 million. We also expect a Tawke payment shortly. These payments have been made against the difficult financial background for the KRG with the low oil prices and pipeline downtime creating an economic hardship. KRG has responded to this situation by pushing through reforms which are designed to reduce the region's cost and increase revenues.
A key area of focus has been on reducing the monthly payroll cost through salary costs. Reforms to petroleum product and electricity sector subsidizes are also hurting. These efforts are already having an impact with KRG announcing earlier in 2016 the monthly budget shortfall had been reduced from US$400 million to US$100 million. International aid most recently in the form of direct help from the US to pay Peshmerga salaries is also helping the KRG addresses the current budget deficits. We believe that there are a number of factors which will have reduced and potentially eliminate the budget deficits. Oil price recovery, increase in KRI production, further cost reduction initiatives and also further international loans or aids to KRG. Recently the KRG and World Bank launched a roadmap for KRI economic reform, a positive step towards the longer term budget stability and growth. As the restructuring of the economy progresses and the KRG moves towards a budget surplus, we remain confident that KRG will deliver on its promise to accelerate the recovery of IOC receivables for cost production.
While continued payments payments and receivable recovery will incentivize further IOC investment in the KRI’s upstream sector which in turn will increase KRG income. The resumption of activity at both Taq Taq and Tawke in 2016 is already positively impacting production levels at both fields. I would also like to make a comment on the recent incident in Turkey. We are monitoring the situation but there has been no impact on Turkey installations with KRI. Oil flows through KRI Ceyhan pipeline and lifting in Ceyhan are unaffected. We believe our gas assets have a key role to play in Turkish stated strategy to diversify energy imports and lower costs. This strategy has not changed in recent weeks.
Slide 12 illustrates the KRG oil export track record over the past 18 months, which has delivered over 600 million proceeds for Taq Taq, Tawke and Shaikan fields in September 2015. Oil exports from the KRI were sustained at around 600,000 barrels per day until February of this year, and pipeline downtime impacted flows. Exports resumed in March and since then have averaged around 500,000 barrels per day. This production is due to north oil company starting exports from the fields in the South [indiscernible] area. We are encouraged by the reports in the recent weeks that both Baghdad and Erbil are taking positive steps to retail sales from this field which will generate additional revenue for all the Iraqis. Before the Taq Taq and Tawke asset review, I would like to publicly welcome Paul Schofield to our Genel team. He has a long track record in the oil industry and his short time with us has already made a positive impression with this experience of managing carbonate reservoirs. His primary responsibility will be focused on the oil operations at Taq Taq and Tawke while gas business development and ensuring continuity payment and receivables recovery.
Now, let me hand over to Paul.
Thank you Murat and good morning everyone. I joined the company early in May after a 34 year career in the industry working for Shell International, Enterprise Oil, Tuscan Energy and Hess. I've had experience of both onshore and offshore oil and gas field operations including significant experience with carbonate reservoirs. I look forward to meeting many of you in due course. I've been fortunate enough to join Genel at a time of continued payments from the KRG, which have underpinned a pickup in operational activity. Firstly, the central processing facility number two has successfully been bought on stream at Taq Taq. Secondly, rig activity has been reactivated with sidetrack drilling at Taq Taq, multiple work-overs and drilling for development wells at Tawke and exploration drilling at Chia Surkh. We have also commenced Pre-FEED and gas development plan for the KRI gas project. And planning has began for exploration activities in Africa. Along with increased activity comes a challenge to maintain the excellent Genel HSC record. In this respect so far I've been very impressed with both TTOPCO and DNO both from an occupational and process psyche aspect.
Now, let me move on to the status of our oil assets by drawing your attention to slide 7. This chart illustrates the actual production achieved during the first half of 2016. The key takeaway is that that the decline seen at both fields since the second half of 2015 have been arrested. The resumption of investment of both fields has had a positive impact with production stabilizing at both fields since April 2016. The declined experience may largely be attributed to the suspension of investment following intermittent payments for oil production. I would like to emphasize that continued investment in these fields will be required in order to compensate for the natural field decline and sustained production levels. Slide 8, is an updated version of the Taq Taq slide we have shown before illustrating the well locations in the top Shiranish reservoir, the main producing Cretaceous arising in the field and grouping those wells by location on the crests or flanks of the field. On the right-hand side is a bar chart illustrating the distribution of cumulative oil from the field since the onset of productions and how that compares to the past six months. You can see that the majority of Cretaceous production is currently being sought from the crest of the field with seven wells currently accounting for over three quarters of total oil production. It is not unusual in my experience for an oilfield to be reliant upon a small proportion of its wells for the bulk of daily off take. However, it does emphasize the need for further investment in increasing the well-stock to spread production over a greater number of wells and to more widely distributed oil offtake points throughout the reservoir flanks.
This leads us on to slide 9, where I have set out the different elements of the Taq Taq forward work program and what impact we expect them to have. We will increase the number of active producing wells at the field to allow for more expected management of the reservoir. Furthermore, new data gathered by drilling new wells will allow us to address widespread between 1P and 3P reserve estimates at the field. We would do this by targeting areas of unswept oil in the Shiranish and possibly bypassed oil in the deeper Qamchuqa and Kometan horizons. We may also work over and\or recomplete existing wells as well as install ESP electric submersible pumps if appropriate. But we need to be clear as already indicated that forward activity at the field will aim to offset declines rather than deliver production growth. Looking ahead, I would like to emphasize that Taq Taq and Tawke are likely to need intensive drilling in order to maximize gross ultimate recovery. Again, it’s not unusual that fields of this nature but it does underline why it is crucial to keep receiving payment for our oil. An added benefit of uninterrupted drilling operations is that wells can be drilled more efficiently and most cost effectively thus enhancing value. This is allied with the advantageous PSC terms which allow for immediate recovery on capital and operating costs which remain very low by any industry standard.
I would like to pre-empt any questions on Taq Taq reserves, we have only recently resumed drilling activity at the field but so far we have seen nothing either in terms of pressure data or water levels across the reservoir to contradict the assumptions underlying the McDaniel CPR published earlier this year. We will commission an update of the CPR in quarter one in 2017 as part of our annual reporting cycle. Moving to slide 10, this provides further detail on a number of the recent production wells drilled at Taq Taq field. The Taq Taq 27x sidetrack well was the first in 2016 program and was a sidetrack of a well in a location on the field, we encountered the mechanical difficulties while drilling this well and hence it has to be sidetracked a number of times before we penetrated the reservoir. This well was attempting to emulate the success we had with the Taq Taq 24 well which I currently the best producer in the Taq Taq field producing in excess of 10,000 barrels of oil per day. Given the drilling difficulties we encountered at Taq Taq 27x we may not get the flow rates on this well we have seen at Taq Taq 24, but we have approval the concept of the appropriately designed horizontal wells coming to effect fracture networks and add to the producing well stock on the field.
The Taq Taq 7z well is presently being drilled at a slant well to provide information about the fracture development in the Shiranish and also to test our theory that there might be bypassed oil in the Kometan and Qamchuqa matrices. After thoroughly evaluating this well it will either be maintained on production or sidetracked once more as a horizontal Shiranish producer later in the year. The Taq Taq 16z will be drilled in the north-east of the field, in an area not previously targeted in the Shiranish reservoir. Slide 11 summarizes the work program for the remainder of 2016 at both assets. At Taq Taq, the 7z well will be followed by a horizontal sidetracked of the 16 well which in turn may be followed by a sidetrack of the 20 well. Looking forward into 2017, we will likely continue to drill development wells while payments continue. At Tawke, DNO’s work program will continue, eight operations have been taken place so far this year with another three planned, a water injector and produces our plans for the shallower [indiscernible] reservoir with the Cretaceous producer planned in quarter three 2016 to be followed by the two Peshkabir-2 well later in the year.
Now let me handover to Murat to take you through the KRI gas business on slide 13.
Thank you Paul, year-to-date in 2016 we have made progress on the KRI gas business development. We have awarded the midstream Pre-FEED to Flour, and Gas Development Plan to both Miran and Bina Bawi to Baker Hughes. In parallel, we are evaluating whether any further grade development subservice activity may need to be undertaken at both fields. We had targeted completion of the definitive agreements for the upstream gas business by the middle of this year despite our best efforts progress has been slower than we are anticipated. We recently received the next version of the key upstream agreements which are in good shape. We hope to make further progress and finalize in the second half of 2016. In parallel, we expect to make further progress on bringing an anchor Turkish partner to KRI gas business for both upstream and midstream. We understand that the development of Miran and Bina Bawi is not moving forward quickly as market would like. The fields are significant gas resource and important to the energy security and longer-term economic development in both KRI and Turkey. As such, progress on the project is subject to both political and commercial discussions and milestones before it can progress to FID. The nature and timing of this is difficult to accurately forecast, otherwise you be assured that we continue to engage with all stakeholders to move the project forward.
Now, I will hand back to Paul to run you through the exploration appraisal activity.
Slide 15 provides an update on our KRI appraisal programs, Chia Surkh-12 wells spudded in late March 2016 and was drilled to a appraise discovered Miocene hydrocarbons and test the potential of the deeper Eocene Oligocene targets. The well was drilled to target that ahead of time and budget, the deeper objectives proved to be water bearing at this location. And hydrocarbons were tested in the previously proven Miocene section. After the testing program completes, we will need to sit down with our partner to fully evaluate the CS12 results, clarify the potential of the license and agree next steps, accounting for the discovered and prospective resources. The Peshkabir-2 appraisal well remains on track to commence drilling later this year. The well will appraise the Jurassic discovery in addition to targeting the Cretaceous in an optimal location. DNO has estimated 32 million barrels of reserves and 63 million barrels of oil equivalent of contingent resources in the Peshkabir structure. Slide 16 provides an update on our Africa exploration portfolio. Offshore Morocco, the focus is on Sidi Moussa license is bringing the partner ahead of the well commitment in 2017. The emphasis has moved from the Jurassic carbonate played targeted by the Sidi Moussa-1 to the low Jurassic clastic play which we believe has both better reservoir potential and closer proximity to the source rock. The farm out process is ongoing and we are in the final stages of negotiating a license extension. Our maximum future spend associated with Sidi Moussa license is around $30 million. Onshore Somaliland progress has been made which should pave the way for the start of 2D seismic acquisition around year-end 2016. The government will contract with an international seismic provider and Genel will purchase the data from the government. This is an exciting medium-term opportunity in Genel's portfolio with the prospectivity on block analogous to the proven oil province in Yemen to the north.
Now let me hand over to Ben.
Thank you Paul, let me start with some commentary on the key financial figures from the first half of 2016. As you will see the income statement reflects declining production and oil price. The cash flow reflects regular payments and the balance sheet is broadly stable. In the income statement, the impact on EBITDAX was mitigated by further cost reductions, particularly in G&A which totaled $10 million in the period, down from $18 million in the first half of 2015. OpEx also fell with production as well as cost control to $17 million in the period from $24 million a year earlier. As Murat highlighted in his opening comments, we also saw a sustained and regular flow of payments from the KRG, with $119 million of gross proceeds received in the first half of 2016 compared to $50 million in the first half of 2015. In turn, this led to a significant increase in operating cash flow which combined with reduced capital expenditure to generate $33 million of free cash flow before financing costs. Cash on balance sheet at the end of the period was $407 million compared to $455 million at the end of 2015. The reduction in cash balances can be explained by the outflow of the bond buyback in March 2016 and the exclusion of restricted cash balances relating to the Morocco work commitment.
Slide 19 sets out our usual cash waterfall chart. As I mentioned just now gross proceeds of $119 million received the period on which $12 million of related capacity building payments have so far been paid to the KRG. OpEx, G&A, working capital and Africa spend are deducted to deliver operating cash flow of $80 million. $32 million of CapEx was spent tangible asset additions at Taq Taq and Tawke and a further $50 million outflow was in respect to the capital approvals from earlier periods paid out in the first half. $27 million of bond interest resulted in cash balances of $462 million, a $7 million increase on the starting balance. Deducting the $35 million outflows for the bond buyback and excluding the restricted cash relating to Morocco commitment resulted in a cash balance of $407 million at the end of the period. Slide 20 gives further detail on revenue, proceeds and the receivable in the first half of 2016. Revenue in the period has been accrued according to our view of the PSC terms and is based on the export netbacks agreed with KRG under 1st of February 2016 payment mechanism. Proceeds in the first half of the year were invoiced and paid according to the simple proxy formula agreed with the KRG in February. This proxy formula was based on budgeted cost for the year rather than actual cost incurred and there is also a difference in interpretation of the OpEx calculation. Any difference between net proceeds and revenue is discounted to reflect the estimated time to receipt. First half revenues were discounted by approximately $2 million and it is likely that in the second half revenues will be discounted by $5 million to $10 million to reflect these differences.
We've gone into some detail on the assumptions underlying the receivable in the interim statement, so I will summarize briefly here. The reported receivable of $412 million reflects cumulative unpaid revenue recognized using the price assumptions prevailing at the time. The nominal receivable of $468 million reflects our latest view of the amounts owed for those same sales as of today. Incorporating the current views on improvement netbacks as well as the accrued interest for the PSC. The difference between the reported and the nominal receivable will be unveiled through finance income. The notes to the accounts also set out management's current judgment but an increase in the monthly payments potentially combined with an alternative method of delivering value for the receivable will result in the receivable being recovered by the end of 2019. Slide 21 provides a breakdown of capital expenditure in the first half of the year. The majority of spend was on the Taq Taq and Tawke programs as activity restart. The majority of the full-year 2016 spend will be incurred in the second half of the year given the phasing of activity. And we now expect total Taq Taq and Tawke development spend in the year to be towards the upper end of the previously communicated range as Tawke activity has been moved into the firm budget from contingent.
Note that Taq Taq and Tawke CapEx guidance for the full year now includes our share of the Peshkabir-2 well currently estimated at $5 million. Total spend on the KRI gas business is reaffirmed at $20 million which primarily reflects engineering studies and gas development plan and capitalized costs. KRI and Africa exploration and appraisal spend is budgeted at approximately $5 million. Given spend already incurred and our current activity outlook, we have narrowed the 2016 CapEx guidance to $ 90 million to $110 million from the previous $80 million to $120 million range. Slide 22 provides a brief summary of our financial position. Monthly cash spend in the first half, which incorporates interest charges, OpEx, CapEx, G&A and working capital, averaged around $17 million compared to $18 million of average monthly net proceeds. Average monthly spend for 2016 is expected to be less than $20 million, rising from the first half figure, given the CapEx phasing on Taq Taq and Tawke development spend in the second half. Cash balances at the end of the half year were $407 million. We successfully repurchased some of our bonds following a tender offer earlier in the year, buying back 55 million of nominal at 63% at par plus accrued interest. Net debt at the end of the period was $237 million, using the IFRS debt figure from the accounts of 643 million. At the end of the period, we had significant headroom on our debt covenants.
The final side in this section, slide 23, provides an update on 2016 guidance. Production guidance was recently revised to a range of 53,000 to 60,000 barrels a day, and is maintained. Revenue guidance continues to be given on a $45 per barrel average 2016 Brent price and it narrowed to $200 million to $230 million range from $200 million to $275 million, given where we are in the year and also the recent revision in both production guidance and capital spend.
As the calibration guys, for every one dollar move in Brent away from a scenario based on the $45 for the full year results in approximately $4 million sensitivity on revenues at the midpoint of the production guidance. Production cost guidance has been narrowed to $1.50 to $1.75 a barrel, given the impact of the revised production guidance over relatively high proportion of fixed costs of the fields. We expect G&A expense to be approximately $25 million for the full year. As already discussed, CapEx guidance has been narrowed to $90 million to $110 million.
Now, let me turn over to Murat to summarize.
Thank you, Ben. During the first half of the year, we generated $119 million of gross proceeds from the KRG, bringing $193 million to total proceeds, net to Genel received between September 2015 and June 2016. We remain confident that payments will continue and KRG can accelerate the repayment of the receivable when its budget is in surplus. Continuous payments has given us the confidence to invest in our oil assets and maximize the remaining reserves in both Taq Taq and Tawke, in particular payments of those allow us to drill more res at Taq Taq, which in return will help us narrow the existing wide strip between the 1P and 3P reserve figures.
On the KRI gas business, I'm pleased that we've been able to award the Midstream profit and upstream gas development planned contracts. We will continue to engage with the KRG on the completion of the definitive upstream agreements in the second half of the year and in parallel, to progress forward a Turkish anchor farm-in partner. We will continue to look at opportunities to grow our existing resource base, in particular, we're looking to forward the drilling of Peshkabir-2 well in the second half of 2016.
We retained significant financial flexibility with cash balances in excess of $400 million and forecast 2016's funding and proceeds balances.
Finally, reiterate the key takeaways this morning. We are confident that payments will continue and that recovery of receivables would accelerate when the KRG's budgets reach surplus. Secondly, regular payments will allow us to continue activity at both Taq Taq and Tawke with a goal to maximize the value of the fields. Finally, we expect to complete the definitive upstream agreements for the KRI Gas business project in the second half of 2016 and in parallel to progress on the anchor Turkish farm-in partners.
Now, I will hand back to operator for Q&A session. Thank you, all.
[Operator Instructions] We shall take our first question from Rafal Gutaj of Bank of America. Your line is open. Please go ahead.
The question on the Taq Taq 27 well, I was wondering if you could give a little bit more granularity on the impacts of the sidetrack on flow rates before and after that sidetrack was completed.
And then secondly, just on water cuts across the Taq Taq field, I know you're saying it's now around 10%. Just wondered how that compares to or you saw earlier in the year in January, February before you commence the kind of water management program. I'll leave it there, yeah.
Okay. I'll take that one. It's Paul speaking. As far as the 27x well is concerned, we have obviously, prior to the sidetrack, it was producing nothing. This is a sidetrack of an existing well. What we're actually doing now is a stable production of just under 1800 barrels of oil per day. That's within our range of expectation for this well of between 1500 and 2500, 1000 [ph] barrels in the mid case. In the high case, it can go as high as 5,000 barrels. We have actually produced it as high as 4,000 barrels. What we're trying to do now is cut off some of the water from that well. It is producing some water as well and we have a program in place to isolate the water. We hope to get that back up to 4,000 barrels a day in due course.
As far as the water cut in the field, we are running as you say at 10% and it's pretty much running at that level throughout the year and the efforts that we carry out to stick there or thereabouts, that 10% for the rest of this year.
Okay. Perfect, thanks. And just in terms of next two sidetrack wells that you plan for the -- or are currently drinking one and plan for the remainder of the year, should we take that 1,500 to 2,500 as I guess your range of expectations for those wells?
Yeah. The full range of expectation with those wells we use is between 1,500 and 5,000 barrels a day.
Okay. Perfect. Thank you.
We shall take our next question. Your line is open. Please go ahead, Mr. Thompson.
Good morning, guys. Just two questions from me. Firstly on the recovery of the receivable, you’ve laid out a plan, which seems that you can recover it or expect to recover it by 2019. What do you think are the sort of levels, the oil price levels we need for the KRG to consider changing from the 5% to another level?
And then secondly, Murat, in terms of what you’re hearing on KRG and getting those southern fields back online, do you have a sense of when they may come back on line, is there something that might happen over the next couple of months?
Okay. Let me answer the question like that. Rather that oil price recovery, we have lots of factors, affecting the KRG is reaching the positive cash flow and monthly surplus in their budgets. But answering your question exactly, I think if we take only the oil price, we may reach around 60, I think they will be in positive cash flow. But rather than oil price, we have near term expectations in the region. The first one, as you ask the production, maybe in the system soon, because I think you’re also reading lots of articles on this one. The production over that that we cannot utilize today is that on 120,000 and 130,000 barrel per day. So, which is that when they take this one into account, and agree on a sharing mechanism on this oil between the three parties, Baghdad, Erbil and Turkey, so which will immediately take the KRG’s budget to almost the balance, monthly balanced budget, because the 100 million that I provide you was excluding the recent [indiscernible] which is around $40 million per month. So what we’re talking about, around $50 million, which is representing around 10% of the KRG budgets.
Okay. Great. Thanks. And just simply on Taq Taq, you mentioned on the call here that the plans are to maintain production or steady production, how long do you think that you’ll be able to do that, Paul?
Provided we continue with the payments and we can keep on the activity, we can continue at this level for the foreseeable future, which runs into next year.
Okay, great. Thanks very much.
We shall take our next question from Mr. Thomas Martin from Numis. Your line is open. Please go ahead.
Hi, good morning. I was wondering if you could just provide a little bit more detail for us around about the technical data that you received from Taq Taq to date and CPR and clearly, production rates that you’re achieving haven’t matched what was in the CPR, can you help us understand a little bit about, around about what is driving the production and where the data specifically is in line, how much of this year’s amount is in your sales and how much of it is perhaps really to the timing of activities versus what was in the CPR?
Second question if I could as well, you’ve noted the completion of additional price increase oil and water handling capacity, just to be clear, I mean you spoke about maintaining I think the 10% water cut. Was water handling a limiting factor to date in your reservoir management and [Technical Difficulty] alter your options when it comes to reservoir management? Thanks.
Maybe, I should take the last one first. The previous processing was not a major blocker in terms of our ability to produce from this field and going forward, we’ve just got the ability to more effectively handle the fluid flow and separation and that is proving to be the case. So I don’t think there is any major bottleneck in the system. We have the capacity to produce 45,000 barrels a day and -- of water and that’s what we -- that gives us a lot of sum to work with basically. It’s very difficult to predict exactly where the water profile is going to go, it’s a complicated reservoir as you’re probably well aware, these fractured carbonates are very difficult to model.
So I think we, going back to the CPR, you’ll recall that in the 2P case in the CPR, the production rate for 2016 was reported at being about 80,000 barrels a day. We are operating just under 70,000 at present and so, I think the point that I’m trying to make here at the moment is that, the nature of this reservoir is such that the shape of the profile in the CPR is somewhat more aggressive than I think it will be and should be with the current well count that we have and we had a lower off take this year, which I think is commensurate with my view that we will have a profile that is a -- we cover these same level of reserves, but over a longer period of time.
And then as far as the other side of things are concerned, in this year, the impact of the shutdown and we’re not actually running any ESPs. All the wells are flowing on natural flow and two such time that we required to run the ESPs, we will not actually take that decision at this point. Does that help?
That’s great. Thank you.
We shall take our next question from Robin Haworth from Stifel. Your line is open. Please go ahead.
Good morning. Just a question on the OpEx calculation, you mentioned on the impediments and that the, there was a difference of opinion between the company and the KRI about how that works. I was wondering if you could explain that comment at all please. Thank you.
Yeah. At a high level, the difference is that the MNRCs and this is the encapsulating the R factor that it should be calculated based on the revenues of the field, we’re saying it should be based on cash received. So that is something that unwinds overtime with the receivable. It’s a timing difference from anything else. This is not a negotiation we’ve had, this was just a discussion setting the proxy. If you say, if the bottom line of your question is kind of how much difference does this make and coming back to some of the comments on discounting, if you’re trying to match the proceeds in the period with the revenues accrued during the period to kind of see what’s the calibration area between the proxy and the actuals.
In the first half, it was about $9 million, which causes the discount of revenues by about $2 million. And as I said in the second half, that gap could increase and that’s really down to the CapEx at that point is why we’re spending more CapEx in the second half than in the first half and the proxy has a standard cost if you like in it. So in the second half, that difference could widen from 9 to 25 or so and therefore, the discount as I said, could be in a range of 5 to 10 in the second half
That’s great. Thank you very much. And just a follow-up if I may, on the final terms for the gas sales and agreement and could you just illustrate or highlight if there are any items that are up for negotiation and what they are and how material they may be? Thank you.
Let me answer this one. The recent stuff that we received for the PSC amendment on gas lifting agreements is in good shape as I said, which means they’re in line what we announced with term sheets.
Okay, that’s great. Thanks very much.
We shall take our next question from David Mirzai from Deutsche Bank. Your line is open. Please go ahead.
Hi, good morning, James. First question on Peshkabir, you’re drilling an appraisal well in second half of this year, could you just split that 32 million barrel resource number between the Jurassic and the Cretaceous and also when you say can be tied back quickly, give me some indication of what’s required to bring that into production?
As far as the question on reserves, I think that’s the question for the operator. All we have, as you see in the presentation, we refer to the operator’s annual statement of reserves lifting and I refer you to that. As far as the timing for tieback, I think it’d be two to three months will be reasonable, we’re looking essentially for low line back to existing facilities.
Okay, great. And then just secondly, in terms of the most, for the gas businesses here, is the next news that we expect to hear from you regarding the pre-FEED and the development study by Baker Hughes or should we expect to hear more economical or financial milestones being passed in the second half of this year?
I think second half of the year, the news will be the completion of this engineering, early engineering studies, early pre-FEED and also the gas development plan by end of the year and also the business point of view, full return agreements, we are expecting to complete and sign on this PSC amendment and gas lifting agreements at the upstream side. And making some progress on the bringing of Turkish anchor partners.
So bringing the partner in is probably more likely once you have the project pretty much set in stones, once you have all of the moving pars now done?
First, the completion of the agreements and then we will be making a considerable progress on bringing the partnership.
That’s great. Thanks very much, gens.
We shall take our next question from Justin Teo from Credit Suisse. Your line is open. Please go ahead.
Hi, guys. I just had a question on Taq Taq sort of flowing up in terms of the profile compared to say the CPR, I think the CPR probably has a lot of the highs, you mentioned 80 today and then maybe declines of 8%, 9% per annum, sort of going forward. Do you sort of see, I guess, more as a 65 sort of per annum and the more contents that are there and a lower decline going forward?
Yeah. Basically, I think -- we see, as I said, lower production in 2016 and a shallower decline, which is with the continuing investment of having more holes and work-overs to manage the water.
Great. Thanks. And I mean, I guess, the CapEx rolls off very quickly in the CPR, would that mean that that gets obviously extended then for a longer period of time?
Yes. The CapEx is a bit of a wash as the payment system is working.
We shall take our next question from Dan Ekstein from UBS. Your line is open. Please go ahead.
Thank you. Good morning, everyone. Couple of questions on Miran and Bina Bawi, I guess given some of the reserve downgrades we’ve seen across [indiscernible] over the past four or five years, potential partners in new projects, again, I want to be very confident on the underlying geology of any project they get involved in, do you feel Miran and Bina Bawi is efficiently well appraised at this stage, both across the oil and the gas resource to attract the level of capital required or do you think there might be further work [Technical Difficulty] substantive discussions with anchor partners ongoing, whilst the final term sheet would be KRG, I think, discussed?
Okay. This is Murat. Let me take the question. First of all, the Miran and Bina Bawi gas 2P reserve level is -- once we are talking with the gas sales agreement between Turkey and KRG, I am talking on P50s, so after reaching 10 BCM, we are also planning some additional subsurface activities. This will give us additional information for the upside potential. If you recall in Turkish GSA, there is a room between 10 BCM to 20 BCM. It’s an option for Turkey to take more gas from KRG. So for attracting investors with the current commercial discussion is fully available and for the upside site, we will be to add on to the project what we are discussing.
On the second part of your question, the partners, as I said in our discussion, year results in March, we will be talking and giving the priority to Turkish government energy entity. So we will be talking and continuing with them. As I explained also, this project for Turkey is important in two aspects. First, to diversify the current gas import portfolio. We will be, we are buying currently more than 50% from Russia and secondly, all of these three countries, Russia, Azerbaijan and Iran, KRG Gas’s agreement is giving Turkey the cheapest best available gas price.
As there are no further questions that concludes today’s call. Thank you for joining.
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