Enquest Plc. (OTCPK:ENQUF) Q4 2017 Earnings Conference Call March 20, 2018 5:30 AM ET
Amjad Bseisu - CEO & Executive Director
Bob Davenport - MD of North Sea
Jonathan Swinney - CFO & Executive Director
Richard Hall - Head of Major Projects
Rafal Gutaj - Merrill Lynch
Stephane Foucaud - GMP FirstEnergy
Niki Kouzmanov - Jefferies
David Round - BMO
Michael Boam - Sona
Okay. Good morning, ladies and gentlemen, and thank you for joining us today for the EnQuest 2017 Full Year Results. So, I will start with an overview, and then turn over to Jonathan Swinney, our CFO, for a review of financials. And then Richard Hall, who has been heading our major projects and principally the key driver on Kraken and responsible for Kraken, will then take us through an update on Kraken, which I am sure is very topical. And then Bob Davenport, the Managing Director for North Sea, who has come from Malaysia, used to be running our business in Malaysia and was the ex-Apache in the North Sea, ran Apache's assets in the North Sea, will then talk about UK and Malaysia. And then I will come back in the end and summarize before we open it up to questions, first, from those here in the room and then remotely.
So, I think 2017, as we all have seen, has been a transformational year for EnQuest. We have delivered Kraken on time and significantly below budget. We have highlighted an additional reduction in cost of about $100 million to $2.3 billion. And that, taking into account starting off at $3.2 billion, is obviously a very significant 25% reduction in cost.
I am very proud that we were able to execute a project like Kraken. It is a project for majors, heaviest oil in the North Sea, quite a complex system with long horizontals. Richard will talk more about that, but a world-smashing experience on the long horizontals, gravel pack that is the longest in the world and a record for the world. And also, the process plant, has two trains, which can process up to 480,000 barrels of liquid a day nameplate capacity. So again, I am very proud this is a project that majors will be extremely proud in executing, and we have been able to execute that on time and significantly below budget.
The acquisition of interests in Magnus and Sullom Voe, I think, was extremely innovative, which was a cashless transaction, a riskless transaction. And it has allowed us to add 15 million or 14 million barrels of reserves for 2017, but also allows us an option to exercise to take an additional interest there, which I think is important for growth. We have the Sullom Voe Terminal, which we completed the acquisition of operatorship in December, and I think this is very synergistic with our assets and our future extension of our assets.
Our group production was 37,400 in 2017, in line with the revised update in August. Well, obviously, we were disappointed to have revised the production target down. Cash expenditure on capital was below the range expected at $368 million. And then bank facilities and cash at the end of the year were healthy, $244 million, excluding the payment in kind that was $1.9 billion. And our audited 2P reserves were 210 million barrels, slightly below the 216 million level. This is primarily due to some change in long-term assumptions as well as some underperformance in Alma, countered by the acquisition for Magnus and some additional reserves booked in Malaysia.
We still have a 17-year life, reserve life on our assets. And our production of existing reserves when we started the company of 80 million barrels almost expunged. So, we have seen a 13% rise in our reserve base on a compound basis over the years since start-up.
For 2018, we are well-placed to deliver growth. We have a very significant increase in our guidance range from 50,000 to 58,000, driven obviously by Kraken. Kraken production has actually averaged around 38,000 barrels a day gross in the first two months of 2018.
Our OpEx is $24 a barrel, including some planned workovers. And cash CapEx continues to come down and expected to be around $250 million. But this also includes now some CapEx programs in areas outside of Kraken, including drilling in Heather, which we have completed a well there. We are going to be drilling in PM8 Seligi. And we will continue finalizing and finishing the drill centre for Kraken development, which would happen in the second half of the year.
We have also hedged and continuing our hedging program. We have hedged 7.5 million barrels of oil at an average of $62 a barrel. And this increased cash flow, which comes from increased production and better prices, should help us reduce our debt this year significantly.
Beyond 2018, we see significant potential in our portfolio, particularly in Kraken where we see the Western flank as a possible additional development and also additional reserves coming out of Kraken once now that the infrastructure's in place. We see Magnus, with the drilling ongoing there, as quite exciting, and our ability to exercise the option in Magnus is quite exciting. And then for the first time, we are able to drill in PM8 Seligi. And with that, PM8 Seligi drilling hopefully converts some significant 2C resources into 2P.
As I said, the acquisition, I think, of Magnus and Sullom Voe aligns very well with the group. It allows us to reduce costs on a very important terminal following in the footsteps of what BP was doing. And that allows all the fields, including our field, to have extended life. And then Kraken, we do see, as I mentioned, some significant upside and some significant opportunities, and we would be looking at monetizing those opportunities longer term.
So, I think, just as we did the Magnus and SVT deal, I think the key for us is the operational excellence and differentiability, which allows us to access these opportunities. I think we are well-positioned to take advantage and increase life of these late-life assets and undeveloped fields, as we have proven over the first eight years of our existence.
At this point, I will turn it over to Jonathan Swinney.
Just turning to Slide seven. Our results for today, our results for 2017 reflect the lower realized oil price combined with the lower production performance, as Amjad has just outlined. Realized oil price for 2017 is $52.2 per barrel and is a function of the forward oil prices available at the time at which commodity hedge program was implemented. The realized price, excluding hedges, in 2017 was $54 per barrel, so very close to our overall realized price. In 2016, the realized price, excluding hedges, was $44 per barrel, some $20 per barrel lower than the price we realized including hedges of $64 per barrel that you see there.
In 2017, we, therefore, recognized $20.6 million of hedge losses in the year compared to $255.8 million of gains in 2016. Over the last three years, the hedge program has been very successful, and we continue to hedge a portion of our production going forward, as you will have seen from our guidance. Salvable barrels were less than production, mainly as a result of the enticement of barrels in Malaysia being just over 65% of working interest as well as shrinkage of around 1.5%.
In addition, total volume sold were reduced as we unwound the over lift position that was built up by the end of 2016. And indeed, we ended the year with a net under lift position. This movement resulted in a $20 million credit to cost of sales compared to a small charge in 2016.
On the balance sheet, you will see a net $23 million over lift being reduced to a net $9 million under lift at the end of 2017. Revenue also included tariff and other income of $16 million. Enticement barrels at PM8 Seligi are expected to be around 70%, 75% of working interest barrels in 2018.
Cost control is always a primary focus for us as well as the management of our commercial agreements. And overall, there was a 13% reduction in cost of sales to just under $570 million. Operating costs were marginally down, although the reduced volume led to a slight increase in OpEx a barrel from $24.6 per barrel to $25.6 per barrel.
Depletion costs on a per barrel basis were 2% lower than 2016, due mainly to the different mix of production. Our EBITDA of $303.6 million and cash generated from operations reflect the lower revenue I mentioned previously.
The investments EnQuest has made to develop its assets, notably Kraken during the year, was the most significant driver of EnQuest net debt increasing to $1.991 billion as at the end of the year. At the year-end, total cash and available facilities totalled $244.4 million, excluding $26.5 million of cash from the ring-fenced working capital facility associated with the Sullom Voe Terminal.
Turning to the next slide, I would like to highlight a couple of additional profit and loss items. G&A and other expenses were $18.4 million compared to income of $41.1 million in 2016, primarily reflecting overhead recovery from previous years and continued cost focus. Going forward, we would anticipate only low levels of G&A in single-digit millions. And the 2016 income was largely made up of foreign exchange gains.
Net finance costs were higher than 2016, in part reflecting high levels of borrowings, but also $31 million of interest charges on the Kraken FPSO finance lease and $13 million lower capitalized interest related to the Kraken development following first oil in June 2017. Net finance costs also included $11.5 million of unwinding of the discounts on decommissioning costs. Tax credit mainly relates to Ring Fence Expenditure Supplement.
Now just highlighting a couple of the exceptional items. We incurred post-exceptional loss of $27.3 million -- sorry, we have incurred a post-tax exceptional loss of $27.3 million. This is made up of post-tax impairment of oil and gas assets of $107.2 million resulting from changes in assumptions combined with lower production performance in the North Sea. This is partially offset by the benefits of accounting entries as a result of the [indiscernible] transaction. These accounting entries were in relation to the initial 25% of the acquisition of Magnus of $10.3 million, the benefits of the Thistle decommissioning option and, finally, the value of the option to purchase the additional 75% in Magnus. Much of the value of this option is higher value, and you will, therefore, see this revalued at the half year, and any reduction will pass through the profit and loss account.
Having a closer look on costs. You will see our cost of sales included the DD&A charges down 13% compared to 2016. Unit OpEx has increased slightly in 2017 as a result of reduced production volumes, although remain significantly below 2014 levels. In 2018, we expect unit OpEx to be around $24 per barrel. Ordinarily, this would have been below 2017 levels, but this year includes around $1.50 per barrel in relation to the Alma Gallia workover program. So, with the $20 per barrel you see there for the production cost, we have included the Alma Gallia workover costs.
Moving to Slide 12. Cash capital expenditure for the year amounted to $367.6 million. Of this amount, Kraken accounts for over two third of the total, with around $175 million spent on drilling and the remainder on Subsea Umbilical's, Risers & Flowlines as well as the production systems. This is still materially lower than the prior year as we progress towards a conclusion of the original field development plan and transition from the previous period of heavy capital investment.
In the Northern North Sea, spend is largely late-life extension and license to operate spend on items such as Dons water injection. In the Central North Sea, cash capital expenditure is primarily payment of invoices in respect to the Alma Gallia and Scotty Crathes developments, which were originally incurred in 2016 and also included the Eagle discovery. You will also see the balance sheet fixed assets have increased by a greater amount as a result of recognizing $772 million for the Kraken FPSO finance lease.
Moving on to the next slide. As you can see from this chart, CapEx is reducing significantly. Our current program in 2018 includes spending on DC4 at Kraken, two wells in Malaysia and 1 well at Heather as well as from work undertaken in 2016, primarily on Kraken. Our guidance of cash CapEx of $250 million for 2018 does not include capital expenditure on Magnus, which includes the three wells on Magnus, as these will be paid out of the field cash flows as part of the transaction mechanism.
Moving briefly on to tax. As you can see from this table, UK tax losses, excluding allowances carried forward at 31st December 2017, were $3.1 billion. At current oil prices, we do not expect to pay any material UKCS CT or SCT. And we expect to pay Malaysian tax on our producing assets in PM8 and Seligi, we will expect to pay cash tax throughout the CST term.
Turning on to the next slide. This slide outlines how our net debt has evolved from around $1.8 billion at the beginning of the year to $1.99 billion at the end of December 2017. Cash flow from operations was $302 million, reflecting the reduced production volumes and lower contribution from hedging. Cash CapEx is $368 million, as outlined previously. And net financing and other costs is primarily made up of interests on our bank debt facilities.
Noncash items include foreign exchange losses on sterling-denominated debt and the impact of including the capitalization of interest payments. That is the payment in kind, payments on the bonds and the bank debt as a result of oil prices being less than $65 per barrel for the six months period to the month before any bond interest is due. Excluding this payment in kind interest on the bonds, net debt was $1.9 billion.
Moving then on to the outlook. We are confirming our production guidance for 2018 in the range of 50,000 to 58,000 barrels per day. And the anticipated average unit OpEx is approximately $24 per barrel. We are expecting 2018 cash CapEx to be around $250 million. The majority of the CapEx, so just over 50%, will be spent on Kraken, including deferrals, with the remainder spent on wells in Malaysia and at Heather as well as license to operate CapEx.
We anticipate 2018 net G&A cost to be in the single-digit millions. And 2018 depletion and depreciation charge are anticipated to be approximately $22 per barrel. The 2018 hedge program covers approximately 7.5 million barrels for the year, hedged at approximately $62 per barrel.
And finally, for me on my last slide. I am taking part in a CEO sleepout. They had to allow CFOs to take part as well. Amjad is not taking part, I am afraid. But I will be sleeping on the street from the 22nd of March, so in a couple of days. And given the cold snap, I think any of our seeds or our kids who are in the streets in this kind of weather would be unconscionable. There are 83,000 kids on the streets any one time, so I will be taking a part in sleeping on the streets in a couple of days' time. So, if anybody has anything to spare, it would make a difference to me and also make a difference to helping these kids. So, we have a couple of URLs there. If you could follow those, I would be eternally grateful.
With that, I will hand over to Richard.
All right. Morning, everyone. Thanks, Jonathan. [indiscernible] update, I am sure you are interested. When we were last together during the half year results for 2017, we said we were going to focus on crew familiarization, process control instrumentation and plant stability as well as throughput. And I am pleased to say we have focused on all those issues, and we have improved in each and every one of them. And performance of facilities and the reservoir has been now very good, particularly in January and February, which I will go into in a second.
The project gross CapEx has now been further reduced. As Amjad has already said, we are now at $2.3 billion. That is including what is to come on DC4, which is 28% lower than the original sanctioned cost of $3.2 billion. That is a function of the excellent delivery of our third drill centre drilling program. We have negotiated very good rates for the remaining subsea element of the projects on DC4. And we have also managed to renegotiate in our favour the drilling contract with Transocean for the Transocean Leader. Still to come, we have got the drill centre four subsea infrastructure, which we will need to put in place this summer, quarter three. We are scheduled to commence drilling on that in the fourth quarter, and production will commence in the first quarter of next year, 2019.
So just moving on with the performance. On a safety note, we had a very good run of 240 days since our last lost time incident. And the injection and process facilities uptime has been very strong in January and February, with average water injection rates for February around 66,000 barrels of water per day, which more than compensates the oil that we have been extracting at 40,000 barrels of oil a day average, with peaks of over 50,000 barrels of oil a day on certain days. The wells are performing well. And we are now into understanding the reservoir with using chemical tracers to map the performance of each zone of the reservoir.
So, the FPSO itself has seen three severe storms during this winter, and I am pleased to say it is come through relatively unscathed. So that is good from a motion characteristic and process point of view, although we did take a hit in the extreme cold temperatures that the Beast from the east brought in early March, and that did cause us to shut down. So, at that point, we thought we would take advantage of the situation and all of the work sketch from our planned shut down, which was due to happen at the end of April. So, we now no longer need to do the shut down in April. Overall, I am pleased to say that we produced more than 4.5 million barrels of oil from the field so far and had nine successful cargo offloads.
In terms of the subsurface, it is a very productive reservoir from Heimdall sands, its beach sand, if you like, and we have got a very good understanding of this productive reservoir. Now we have 21 of 25 development wells drilled and onstream. That is 11 producers and 10 injectors, four to come on DC4. We are using tracers, as I've just said to you, to confirm inflow performance along the wells, it is very long horizontal sections. And I am actually very pleased to say that the wells are producing along the whole of their length, which is very unusual.
Pressure communication has been confirmed between the producers and the injectors, which is fundamental to the line drive, which is how we extract the oil from Kraken. And we do have further upside, which is not in the current development plan. As you can see on your slide there, the Western flank there is looking very prospective and contains, in our view, about 30 million barrels, that is on a gross basis, of 2C that is contingent resource. So that provides an opportunity for the future.
In terms of the wells, again, exemplary drilling performance in a phased manner. The third drill centre beat the other two in terms of total footage, gross reservoir interval drilled, et cetera. You can see there's some impressive statistics there, including, and as Amjad mentioned, the world record on the Opti Pac gravel pack, which was over 4,300 feet of drilled horizontal section with the gravel pack installed. On our original prognosis, we are actually 300 days ahead of schedule, and we have used a very collaborative approach between all the staff and contractors and all the stakeholders. The batch drilling philosophy has been very important to us. And we continue to drive costs down through our supply chain management and effective logistics.
I think that pretty wraps it up. In summary, we are extremely proud of the company to deliver this landmark development. It is one of the largest in the North Sea in the last 10 years. And it is, indeed, the heaviest, that is the densest oil produced offshore UK Operations continue to improve, and it continues to underpin our confidence in delivering on our targets.
So, with that, I will hand over to Bob Davenport. Thank you.
Thank you, Richard, and good morning, everyone. First, let me say how very pleased I am to be here today representing the North Sea business at a very interesting and pivotable time in EnQuest history. And this is after spending the last 2.5 years in Kuala Lumpur, working with the team there to build a very strong base for the high-value business back in Malaysia.
I will start first with a company-wide production summary. So, group production for 2017 was just over 37,400 barrels a day, and that is about 5.9% below the prior year. While Malaysia was essentially flat at just under 9,000 barrels a day, North Sea production fell by 7% year-on-year to just under 28,500 barrels a day. Main drivers for the reduction were ESP failures and storm-related outages early in the year at Alma and Gallia; some reduced water injection volumes at Dons, Thistle and Heather through the year; more plant maintenance shut down days at Heather and Kittiwake; and of course, natural field declines. Now this was partially offset by Kraken online during the year, by some minor volumes from Magnus in December and by Scotty Crathes field being online for the full year.
Now I will go through each area and provide a little bit of colour for each, beginning with the Northern North Sea area. Production declined about 17% year-on-year to about 15,600 barrels a day in 2017. While ops efficiency was very strong in the mid-80s percent overall, production failed due to, as I mentioned earlier, the reduced water injection volumes at Thistle, Dons and Heather; some additional plant shut down days at Heather; and natural field declines through the year.
Production did improve in the second half of the year as we fixed the water injection issues, and these were injection pumps, some vibration issues, pipework and subsea injection lines at Dons. So, we were able to restore the injection back to targeted volumes by the end of the year. We also completed a series of four barrel-adding interventions at Thistle, which added about thousand barrels a day of gross production at the very end of the year. And during the year, as in previous years, we completed campaigns of idle well abandonments at Thistle and Heather. These are done safely and under budget and aiming to reduce integrity risk.
Moving in to 2018, we have, as Amjad mentioned earlier, a 3-well drilling campaign at Magnus. This is already under way, and these wells are due to come online sometime in the second quarter. We have already drilled the Heather infill well, and I am very pleased to report that the well is down, it is online and already producing at above expectations. And we will continue our idle well abandonments at Thistle and Heather throughout the year.
And we are very excited about the opportunities for significant value and growth as we actively evaluate the Magnus asset and the reservoir, including, for this year, shorter-term production adds opportunities from plant debottlenecking and well work. And at the Sullom Voe Terminal, we are excited to continue working together, and that includes the team on site at Sullom Voe, our partners at Sullom Voe Terminal owners, the Shetland Islands Council and other key stakeholders to drive further efficiency improvements and explore options for potential new business there in the future.
So, in summary, for the Northern North Sea, drilling is under way in 2018. We are actively evaluating Magnus for growth and driving further improvements at Sullom Voe for long-term value.
Moving next to the Central North Sea. Here, production declined about 30% year-on-year to just over 8,100 barrels a day. The main reasons for the decline in Central North Sea was the failure of three Electric Submersible Pumps at Alma field, along with storm-related shut downs early in the year. We had increased planned shutdown days at Kittiwake, and we also had an unplanned 20-day shut down at the very end of the year along with the rest of the Fortis pipeline system entrance; and of course, some natural field declines through the year. While this decline was partially offset by Scotty Crathes production for the full year, Scotty Crathes failed to deliver optimum volumes due to pipeline wax restrictions. On the positive side, Kittiwake had good levels of uptime. Alma Gallia was much steadier in the second half of the year. And we employed chemical and lift gas treatments to stabilize and increase the Scolty Crathes production during the year.
Moving ahead to 2018, we have a 3-well workover campaign planned for this summer to replace the failed ESPs at Alma field. And technical work is ongoing together with our partners to develop and implement a solution long term to the wax issues at Scolty Crathes. Opportunities, therefore, in Central include optimizing the Greater Kittiwake Area. That includes debottlenecking Scolty Crathes, and it includes progressing options to monetize the nearby Eagle discovery, which was announced in 2016.
In summary then for the Central, production is currently constrained from the ESP failures and the Alma wax issues, but solutions are under way.
And moving finally to Malaysia. Malaysia, production there was just over 8,900 barrels a day for the year, down about 2% from the prior year. And the region delivered another excellent safety performance, again with 0 lost time injuries. I believe that is something like seven years on the fly now without a lost time injury in the Seligi asset, which is phenomenal. Solid production there was supported by high planned uptimes, improved compression reliability and another successful well work campaign, which added over 2,000 barrels a day of average production for the year.
In 2018, I am pleased to say we are going to drill our first two new EnQuest wells in Malaysia. Those will spud in Q2 and will be online in Q3. And of course, we will continue our asset rejuvenation work programs of inspections, maintenance and minor facilities mods. And in this year, those mods will be to improve our well testing accuracy, which will help us optimize production. And we will complete another low-cost well work campaign in 2018 to add further production and collect critical reservoir surveillance data.
Opportunities going forward, over the medium and longer term, remembering that Seligi field has in excess of 1.8 billion barrels in place with only about one third of that oil recovered to date, we have ample options to extend field life there to increase reserves and production from new drilling, workovers, well work, injection optimization and continuing to work on the facilities upgrades.
So, in summary, for Malaysia, drilling begins this year, steady and efficient operations and plenty of running room for the future.
So, with that, I will hand back over to Amjad for a summary. Thank you.
Thank you very much, Bob. So, in summary, I think feel we are well placed to deliver a very long-term sustainable growth. We have talked about a significant increase of production guidance for the year, up between 33% and 55% to 50,000 to 58,000 barrels a day. I do think we have seen the transformation in 2017, and I think now we are on track really to deliver significant sustainable cash flows and growth in the company.
The increased cash flow should enable us to reduce our debt. And the potential with the existing portfolio, as Bob mentioned, Malaysia, PM8 Seligi, Kraken and Magnus, I think, will allow us visible growth over the next few years. And also, Sullom Voe is an important part of the equation. Our ability to turn that into a long-term sustainable business, but also look at the synergies in reducing costs, which will allow us also to increase the life of our field as well as all users of Sullom Voe.
The key for us is continuing the operational excellence, the differential capability, which will allow us access to further opportunities. We are differentiated in this space to operate mature assets. We have increased production on all the assets. We operate 13 fields in the North Sea. And we operate, obviously, PM8 Seligi, which has 14 platforms in Malaysia, and those are all operating assets. We have been able to increase production on all operated assets since we have taken them over.
With 2017 being a transformational year, I think we look forward to growth in 2018 and beyond. And as you can see, we have had a compound growth rate of 16.5% since our inception in 2010.
Thank you very much. And we will move to questions here from the audience first and then looking for those who have dialled in.
Q - Rafal Gutaj
It is Rafal Gutaj from Merrill Lynch. Just a quick question on the West flank on Kraken, is that something you'll be able to access from drill centre 4? And how does that fit with your thinking of farming down Kraken? Would you sell that as upside? Or would you look to appraise that before you look to farm down a 20% stake?
You answer the first one there [indiscernible].
Yes, sure. In answer to your question, we currently have all four well slots designated for DC4 in terms of the main field, but we are looking at options of maybe reducing that well count, but still exploiting the same reserve base and using the other two well slots at the Western flank. So that is early days. It is embryonic, but it is possible to reach from the DC4 location.
The Western flank is just an example of the reserves in a field which is new and obviously have opportunities in Kraken, which we will look to exploit at very economic rates because now the infrastructure is obviously in place. But incremental cost is cost of drilling, and I think that, we will have plenty of opportunities that we can look at in Kraken. In terms of farm-out, we are not looking to carve that out. But obviously, we will be looking for value for 2P and 2C reserves. And 2C reserves are, in our numbers, both for an increased recovery factor in Kraken, but also for areas around Kraken, which are obviously prospective like the Western flank. Stephane?
Stephane Foucaud, GMP FirstEnergy. A few questions on Kraken. So now that you have a few months of historical production, what's your latest view on the stabilized average plateau production area? Would you include shut down, et cetera, as we reach a stabilizing rate? Second, the FPSO, has it now been accepted? And when will the full rates be applying, if at all, assuming that the average plateau is perhaps lower than what the contractor has signed for? And lastly, the $24 per barrel OpEx, does that include the FPSO rate for Kraken? not but checking.
Okay. Yes, I will answer maybe the first and last question, and then...
Maybe Richard will answer the second one. So, in terms of stabilized rates for Kraken, our plan is to reach 50,000 barrels a day, which we have reached. As you can calculate between January and February, we had a rate of 40,000 barrels a day in February. There obviously is uptime and planned workover, and we do risk the production over the year. So, I think we have risked, not only Kraken, we risked all of our portfolio both for downtime as well as for workover. So, yes, we continue to risk Kraken from what the expected maximum rates are that we see. In terms of the OpEx, the lease is excluded in this. But we do have in that $24, I think as Jonathan showed, the workover program. And that adds another $1.5 goes about to the workover program. And on the second question, I leave it to Richard.
Yes, in terms of acceptance, the FPSO isn't formally accepted yet, but we are making good progress, and I don't think it'd be too far off. We are working very closely with Bumi Armada on this, but we have some very explicit acceptance criteria. So, we are working towards that in collaboration with them.
And in terms of the rates, we have said we have an internal arrangement on the rate. And so, when the boat is not producing, we pay zero. And we pay the full rate at the time that it is producing at full capacity. So that will continue to be the case until formal acceptance.
Full capacity is defined as 50,000 a day stabilized?
No, it is defined as the capacity of the wells and whatever the wells can produce.
Okay. And coming back to the risk factors...
Because we have not publicly stated.
If we put ourselves, let's say, in 2020, what sort of risk factor would you then take on this 50,000-full production for Kraken? It is for modelling purposes and see what would be reasonable to...
So, we have a couple of years of plateau. So, I think if you go through our FTP you saw a couple of years, then you saw a decline from that rate.
So that is 50,000 multiplied by 80% risk factor?
I mean, we have shown our production efficiency factors for the older assets this last year was in the middle 80%, and so we would expect this one to start off low. As we get the systems working, we hopefully will get it higher than that.
It is Niki Kouzmanov with Jefferies. Maybe just a generic question on how group production is doing year-to-date. You mentioned Kraken at 38,000, but just wondering the rest of the portfolio. And then looking at the free cash flow for this year and potentially next, what are sort of your thoughts on priorities versus reducing debt by a certain amount or maybe exercising the Magnus option or other growth opportunities and the associated additional CapEx?
Jonathan, do you want to take the first question, and I will take the second one?
First of all, on group year-to-date production, I can't.
So, we just talked about Kraken, and we said we are in line for the 50,000 to 58,000, which we have highlighted for the year. And...
Yes, I mean, in terms of reducing debt, I mean, you made the point as well that the focus of the group is to reduce debt overall. That will continue to be our focus for this year and into next year. I think where we have opportunities to spend money to get the right returns on that money plus give payback periods. So, for instance, we have drilled the well on Heather. That is being a very good start. So, we will still look to drill wells. We are drilling those wells in Malaysia this year as well, and we will see production coming through that in the second half of this year. So, we absolutely will still be doing work on those kinds of things. But our primary focus is to reduce debt for this year and for next year.
And then on the Magnus option, that is due for early next year, and we are drilling a well in Magnus as we speak. And hopefully, based on the results of production and what we see, we are very hopeful that we can move forward on that option.
[Indiscernible] from Cantor Fitzgerald. On Kraken, how many days the production will be halted? And has operation started already? And on Magnus, how much is the gross CapEx? And do you expect any cash from Magnus in 2018?
Yes. So, when you said how many days...
Yes, Kraken, has the production restarted already?
Yes, the production is back online.
And how many days was the production stopped then?
Just over two weeks, yes.
And then, Jonathan?
Yes, I mean, gross CapEx on Magnus is around $50 million, $70 million range, which is net to us below $20 million. And to answer your question, because of the way the mechanism works on the cash waterfall, we wouldn't be getting any cash out on Magnus for 2018.
It is David Round from BMO. Can I firstly ask on Alma? Looking ahead, the question is, what levels of production do you feel you can get back to their once you resolve the ESP issue? And just to follow on, sort of what reserve are you carrying for that asset at the moment? And the second one is, the CapEx guidance you put out there, does that include the deferrals from prior year? And what is the overall cash outflow in 2018 that we should expect? And then just back on Alma, can I just ask about [indiscernible]. I presume they haven't recovered their costs. So, what's the situation with them? Do they have any recourse over and above the revenue stream that they're entitled to?
On Alma, we did issue our field development plan. Once that was approved, we issued a production profile. And we have three wells working in Alma Gallia now, and we are working over three wells, which will get us back to 6. And we are hoping to get back to that profile, which is in our field development plan. In terms of the reserves, I mean, I think we don't discuss field-by-field reserves. I think we have it kind of on a business unit basis.
And CapEx is actual CapEx, including all deferrals and flow-through 2017 and 2018 are the expected cash CapEx numbers. I mean, I can't comment on [indiscernible]. I mean, there is obviously a mechanism for additional recovery based on the deal we have with them, which we are exercising or putting in place. But I can't comment any further on their numbers.
Okay, if there are no further questions from the audience here, we can take some remote questions.
[Operator Instructions] And we will take a question from Michael Boam from Sona.
I just want to push you a little further on the sign-off for the FPSO. What remains to be completed in your eyes before that sign-off can take place? And how far through the entire project would you say you are now, 95% or more?
Yes, there's various things to sign-off on. We have got a very comprehensive contract. I think we are, yes, we are well into the project. There's still a project team assigned from the FPSO contractor. But like I said before, I don't think we are too far away. One of the big things we have to do is optimize not just on the performance of the plant but on our OpEx as well, so we want all the equipment working so that we can optimize both OpEx and production.
Okay. I mean, are we talking three months? six months? Do you have any sort of indication?
Well, I mean...
Hopefully, short term, but we are not going to be more explicit than that.
There are no further questions on the telephone.
Okay. So, thank you very much, everyone, for attending and hopefully seeing you in August for our midterm results.