EnQuest PLC (OTCPK:ENQUF) Q2 2018 Earnings Conference Call September 7, 2018 4:30 AM ET
Amjad Bseisu - Chief Executive Officer
Bob Davenport - Managing Director, North Sea
Jonathan Swinney - Chief Financial Officer
Rafal Gutaj - Bank of America Merrill Lynch
James Thompson - JP Morgan
Mark Wilson - Jefferies
Chris Wheaton - Stifel
Morning, ladies and gentlemen. Thank you for being with us, joining us today for the 2018 half year results. We're also proposing an acquisition of Magnus, a remaining 75% interest in Magnus, which we'll discuss today.
I'm joined this morning by Jonathan Swinney, our CFO; and Bob Davenport, our Managing Director for the North Sea. We will also talk about our operation in Malaysia. As we've published rights issue prospectus this morning, we have an even longer disclaimer than usual. So I will leave you at your leisure to read these disclosures.
So I'll start off with the first half highlights, and then we'll go on to give you a brief on the acquisition, the Magnus acquisition. Then Jonathan will talk about the first half financials, and then Bob will talk about operations. I'll come back at the end for a summary.
So with that, we'll start with the highlights. We've had a very strong first half with production up about 46% year-on-year, averaging 54,000 barrels a day, which is bang in line with our 50,000 to 58,000 guidance. Revenue is up 86% to $548 million, and EBITDA is up about 107% at $312 million. We've had a material increase in cash generated by operations to $318 million and, our capital expenditures of $126 million continues to go down year-on-year. We're holding our guidance for both our CapEx at $250 million for the year as well as our operating costs at $24 a barrel for the year.
Cash and available bank facilities are $257 million. And our net debt, excluding payment in kind, has gone down to $1.84 billion. Including the payment in kind, it's at $1.97 billion, slightly below the last figure we gave you. Performance is underpinned by our safety culture. I mean, our safe operations is key to us, and we've had a very strong upper quartile safety performance again. We've also started for the first time investing outside our big Kraken investment. We drilled our first well in Heather for many years, the H-67, which came onstream in March very strongly. We've also drilled for the first time in Malaysia, drilling in Seligi 39 and Seligi 40, both coming onstream in July. And they have come at expectation.
We now are planning also additional wells, 2 wells for 2019. We drilled also, after revamping the rig in Magnus, 2 wells, M-62, which came on stream in May. And we've just completed M-63, which should come onstream soon. We're also planning 2 wells in 2019. The wells in Magnus have been able us to understand the reservoir more and, indeed, upgrade the reserves, as I'll talk about in short order.
In Kraken, we finished the DC3 campaign, and we are planning to start the DC4 campaign shortly. And those should be online in 2019. And we are continuing to look at the Western Flank opportunity, which gives us additional STOIIP or oil in place. In terms of asset life extension activities, those remain very strong. As you know those activities go throughout our portfolio. But in PM8/Seligi, we've seen 5 idle wells return to service ahead of schedule and below budget. And in Thistle, we've abandoned 6 wells ahead of schedule and also below budget. So that continues. In Alma/Galia, we replaced the 3 ESPs, electric submersible pumps, and increased production now that we have 5 wells onstream.
I'll move now to the Magnus acquisition, which for us is extremely exciting and compelling. We have now had the asset since December 1, fully operated by EnQuest, and we had a transition year before that. So we're almost 2 years into the asset. We like the asset. It's a compelling asset. We've increased the reserves on the asset by about 1/3 from 60 million to 80 million barrels growth. The 75% will have 60 million barrels of reserves, which would add about 30% of the group 2P users.
The option also is very accretive to us, has about a $500 million NPV 10 value, including consideration and all the cash flows that we'll talk about later. The consideration for this transaction is $300 million, of which $100 million is in cash and $200 million is in vendor loan. The effective date of the transaction was 1/1/17. So some of that vendor loan will be paid down, burn the cash flow in the asset, about $100 million. Half of that vendor loan will be paid back from the cash flow from the assets from effective date.
We see significant benefits from cash generating capacity and capability compared to the original acquisition, and this clearly aligns with our strategies. We understand the asset very well now. We've added reserves to the asset. We've drilled 2 wells. We continue to drill wells, and we see more opportunities going forward.
My family company has irrevocably undertaken to take the full entitlement of the rights issue, which will enable the acquisition. So just a bit more on the transaction, just to remind you, the transaction was agreed at oil price of $50 a barrel. That's why we find it as accretive as it is, adding $500 million in NPV. This is based on a third party competent person's report, which is shared on our prospectus.
The transaction has also the added advantage of tax benefits from the time we complete, and gives us immediate growth, both in production as well as in reserves. We're drilling the first 2 wells. We've now had separate analysis and target 2 more wells for next year. And those wells have very good economic returns, paybacks of above 100% IRRs and significant reserves for the wells, 4 million barrels for Canute and about 2 million barrels for T10 to 11. And we look at very short payback periods of less than a year for one and less than 2 years for the other.
In the meantime, we have talked about the Thistle option, which was part of the transaction we did 2 years ago. And we will exercise at the same time the remaining $20 million additional liquidity for the Thistle option, which should gives us an additional abandonment liability, a small abandonment liability, but allows us also to manage the abandonment on behalf of ourselves and BP.
So the transaction is complementary to our strategy to be operating these mature life assets. And as you've seen, we've been able to increase production and pretty much all the assets we have taken over, both in the North Sea as well as in Malaysia.
Magnus is a very large field. It is now the largest field in our portfolio. 2 billion barrels hydrocarbon is in place, with a recovery factor of about 50% to date. This compares with a recovery factor of 57% for Thistle that we do see significant upside from here. It also compares to our Seligi asset, which is 1.8 billion barrels, and Thistle is about 1 billion barrels in place. So just to give you a feel, this will be the largest field we have in terms of STOIIP.
As you know, we acquired a 25% interest in December, which allowed us to understand the asset. At that time, we booked 14 million barrels associated with that. But you can see now we are 75%, is adding 60 million barrels. So we have been able to add reserves through the last year of operation.
Additionally, the Sullom Voe, this will allow us to take over an additional interest in Sullom Voe of 9%, which we are on track to reduce costs. We have a very significant cost reduction even on one year of taking over, we reduced the cost from GBP 200 million last year to about GBP 150 million this year. And further reductions in costs are planned for the next year.
And we are looking to maximize the value of the Sullom Voe Terminal through looking at new business opportunities, ship-to-ship transfers and storage. And those will reduce our net costs further, allowing us to produce our tail production from our assets even longer.
This slide has a summary of the proposed three-for-seven rights offer. I won't go through the details. Just to say this is a Class 1 transaction, and we'll have an EGM on the 1st of October for our shareholders to vote on the transaction. If approved, we will issue the new shares on the 2nd of October and expect to conclude the rights issue on the 22nd of October.
With that, I will turn over to Jonathan.
Thank you, Amjad, and good morning, ladies and gentlemen. Just turning to Slide 14. Our results today for the first half of 2018 are mainly driven by the material growth and the group's production, reflecting the contributions from Kraken and Magnus and higher market prices, partially offset by our hedging program.
Realized oil price for the first half of 2018 is $59.5 per barrel and reflects the impact of our hedge program. In 2018, we recognized $77.3 million of hedge losses compared to $0.3 million realized in the first 6 months of 2017. The realized price, excluding hedges in 2018, was $68.01 per barrel. And in 2017, the realized price, excluding hedges, was around $52 per barrel.
Salable barrels were less than production, mainly as a result of the enticement of barrels in Malaysia being just over 69% of the working interest as well as shrinkage of around 2%. Revenue also included gas sales of $11 million, mainly derived from Magnus gas sales, and tariffs and other income was $6 million.
Enticement of barrels of PM8/Seligi are expected to be around 70% of working interest barrels in 2018. And there was no material change in the underlift position, which was $8 million. There was increasing cost of sales to $448 million, reflecting the increase in operating and depletion costs due to the increase in production, driven by Kraken and Magnus. The increase in production led to a decrease in operating costs per barrel from $24.09 per barrel to $22.06 per barrel. Depletion costs on a per barrel basis increased due to the increased asset base and a different production mix.
Our EBITDA of $311.9 million and cash generated from operations of $318.3 million reflect the increased production and oil prices I've mentioned previously, both of which were very significantly up on last year.
Our net debt improved slightly to $1.973 billion. Our improved cash generation enabled us to decrease the level of the facility by $75 million, which - through to August. In October, we have a further amortization of the credit facility of $195 million. At the end of June, cash and available facilities totaled $256.8 million, including $24.9 million of cash from the ring-fenced working capital facility associated with the Sullom Voe Terminal. Recently, we reached agreement on $175 million of ring-fenced financing from Och-Ziff, which I'll cover in more detail shortly.
Moving to the next slide. I'd like to highlight a couple of additional items in the income statement. Our net G&A and other income was $4.4 million, with foreign exchange gains from sterling weakening against the dollar, more than offsetting the group's G&A costs.
Net finance costs have increased to $121 million from $35 million, reflecting 2 main areas. One was finance charges on the Kraken FPSO lease of $29 million. And the second was that in the first half of 2018, there was no interest capitalized as part of the Kraken development compared to $42 million in the first half of 2017. Net finance costs also included $79.6 million of bond and loan interest and winding of provisions and liabilities in other facility fees.
For the half year, there was an exceptional post-tax net gain of $35.7 million, with most of them materialized in being the fair value adjustment on the 75% purchase option for Magnus of $41.8 million, reflecting higher oil prices. This is clearly a noncash gain.
Looking a little closer at costs. You'll see the cost of sales, including the DD&A charges, increased as a result of the increase in production from Kraken and Magnus. The benefit of this increased production has led through to a reduction in unit OpEx to $22.06 per barrel.
For the full year 2018, we expect unit OpEx to be around $24 per barrel, including around $1.50 per barrel in relation to the Alma/Galia workover program. We've also applied our cost focus and operating model at SVT, and expect to realize significant reduction in gross terminal costs in 2018. Bob will cover this in more detail shortly.
Cash capital expenditure of the period amounted to $126 million. Kraken continues to be where the vast majority of our CapEx is focused. We continue to work from subsea production system as well as umbilicals, risers, and flowlines for DC4, approximately $25 million related to work in prior periods that settled in the first half.
In the Northern North Sea, most of the costs relates to license our operating expenditure. And in the Central North Sea, the expenditure mainly related to the infield well drilled at Heather, which has been extremely successful. Malaysia capital expenditure reflects the start of the drilling work for the first of the 2 wells. Capital expenditures in line with guidance and continues to be low in prior years, as we transition from the previous period of heavy capital expenditure.
Moving then on to the cash flow. Our net debt position has improved slightly from around $1.99 billion at the beginning of the year to $1.97 billion at the end of June 2018. Cash flow generated from operations totaled $318 million, reflecting the increased production volumes and increased oil prices. We also exercised the first part of the Thistle decommissioning option in January, which contributed an additional $30 million to net cash flows from operating activities.
Cash CapEx of $126 million and net financing and other costs is primarily made up of interest on our bank debt facilities and the payment of the facility waiver fee of $12 million, which had been accrued in previous years. Non-cash items mainly relate to foreign exchange losses on sterling-denominated debt and the capitalization of payment in kind interest on the bonds and the facility. Excluding this payment in kind, net debt was $1.85 billion compared to $1.9 billion at the end of 2017.
As discussed earlier, the group is now well positioned for long-term cash generation, supported by the investments we've already made to date. The group has entered into a financing agreement for $175 million with a wholly owned subsidiary of Och-Ziff Management. The financing is ring-fenced on 15% interest in the Kraken oil field, which is being transferred to a special purpose vehicle. The financing will be paid out of the cash flows of this SPV over a maximum of up to 5 years, and is at a lower cost in the current interest on our existing senior credit facility.
There was a significant interest in the equity farm-out process conducted earlier this year. And having reviewed various the options available to the group, the board approved the financing arrangement as the preferred economic option at this time. The board will continue to keep the future potential of an equity farm-down of Kraken under review. In the meantime, the new financing will continue to support the group in meeting its commitments and decrease the overall net cost of funding.
And then finally moving to the outlook. We're confirming our production guidance for 2018 in the production range of 50,000 barrels to 58,000 barrels per day, and the anticipated average unit OpEx is approximately $24 per barrel. We're also on track to make a significant reduction in gross terminal costs to SVT from around GBP 200 million in 2017 to around GBP 150 million in 2018, benefiting all shippers. We're expecting 2018 cash CapEx to be around $250 million. And the majority of the cash CapEx of just over 50% will be spent on Kraken, which also includes the 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 costs to be in the single-digit millions, and the 2018 depletion and depreciation charge is anticipated to be approximately $22 per barrel. However, that will certainly depend on the production mix, where we end up for the year. We continue to hedge a portion of our production going forward. And as at the half year, we have 5.3 million barrels hedged with at approximately $66 per barrel. Most of these puts have costs associated with them at an average call price of similar to the current oil price or slightly above.
I will now hand over to Bob to take you through the operational highlights.
Thank you, Jonathan, and good morning, everyone. Next, I will summarize the group's operational performance during the first half of this year, along with our plan focus for the second half of the year.
First, our company-wide production summary. Group production for the first half of 2018 was 53,990 barrels equivalent per day. That's a 45.9% increase over the same period last year and at midpoint of full year guidance.
North Sea production increased by about 63% compared to the same period in 2017 to 45,764 barrels equivalent per day. The biggest factors in the North Sea volumes increase were a full 2 quarters of production from both Kraken and Magnus; better-than-expected production from the Heather H-67 well, which we completed earlier in the year; and improved production and injection efficiencies throughout the business. And this was partially offset by earlier scheduling and completion of the maintenance shutdowns at Thistle and Dons, and I'm happy to say these are now complete; and fuel declines, particularly at the CNS fields.
Now we have, by now, reversed the decline at the Alma field in August. As Amjad mentioned earlier, we have now completed successfully the 3 ESP replacements to restore production there. Malaysia production was down 8.3%, primarily from natural decline at the Tanjong Baram field. And so now, I will go through area by area and provide more detail.
Beginning with Kraken. Kraken continues to operate safely, and the team has now worked well over 400 days since the last lost time injury. Average gross production during the first half of 2018 was slightly below our expectations at circa 31,000 barrels per day. Adverse weather in March, which was followed by a lengthy maintenance shutdown, and reservoir under-voidage were the main contributing factors.
Now plant reliability and uptime continues to improve. Water injection rates have increased considerably following the course filter maintenance program and system modifications we completed midyear. This closes down the reservoir-voidage gap at Kraken, which in turn supports higher oil production. So average gross production during the last 2 months was around 33,000 barrels a day.
The field has now produced over 10 million barrels of oil and safely completed 20 cargo offloads, with 16 of those completed in this year. I'm also pleased to report that the installation of the required subsea infrastructure for drilling center 4 has been completed early. And the field is now awaiting the arrival of the drilling rig, which is expected either at the end of this month or early October.
Moving on to Kraken focus for the remainder of the year. Focus will be across 3 broad areas. First, in support of operational delivery, of course, maximizing stability and planned uptimes. I'm pleased to report that final acceptance of the FPSO was agreed this week, and this enables even more focus on those noncritical operational improvements to further enhance reliability and uptime. Also focus on maintaining full reservoir-voidage via high levels of water injection. And as I said earlier, this is ongoing as we've increased the daily water injection rate.
Secondly, the focus will be on the DC4 drilling campaign, and that is to deliver the wells safely and on schedule, with the first oil expected in early 2019. I'm also pleased to report regarding DC4 that based on recognition of good reservoir performance and good internal connectivity, the team has gained approval for developing the DC4 area using 3 wells instead of 4 at a gross savings of about $23 million, with minimum impact to oil rates or recovery.
And finally, the third focus area for the remainder of the year. In support of production and reserve growth, the team will progress evaluation and planning to exploit the roughly 30 million barrels of gross 2C resource, which is in the field's Western Flank.
So in summary, at Kraken, more than 10 million barrels have been safely produced and offloaded. Performance and reliability continues to improve, with recent water injection increases supporting higher oil production. DC4 infrastructure is ready to go, with a drilling rig arriving shortly and new production online in early '19. And finally, the team is progressing future options, including developing the Western Flank area.
Moving on now to the Northern North Sea area. Production there averaged 18,002 barrels equivalent per day in the first half of '18, which was 5.3% higher than the same period in '17. Natural declines were offset by high levels of plant uptime and good water injection efficiency; and of course, the full 6 months of Magnus production, including contribution from Magnus drilling and plant debottlenecking; and as mentioned earlier, also supported by excellent performance from the H-67 well at Heather, which we completed online in March.
As of today, most of the planned shutdown work is complete, finishing a partial outage at Magnus just this week. So the second Magnus well is scheduled to come online at roundabout midmonth. And as Amjad mentioned earlier, we've now actually completed 6 abandonments at Thistle ahead of schedule and under budget.
Focus for the next 2 quarters in the Northern North Sea, completing barrel-adding interventions at Magnus, Heather, Thistle and Dons and planning for the 2 Magnus wells for 2019; preparing for the Dunlin bypass pipeline installation next summer. Again, that's the pipeline which will take the Thistle and Dons production over to the Magnus platform on the way to SVT; and of course, working our long list value-adding options at Magnus, so we can finalize our 2019 execution plan.
I'm also delighted to report in our first year of operation at Sullom Voe Terminal, we're on track to reduce costs by about 25% from around GBP 200 million to about GBP 150 million. And we've done this while maintaining high levels of site availability and, of course, our focus on safety.
These savings are really driven by the application of the EnQuest business model and our capabilities, and have -- primarily have been achieved through 3 main areas. First is a reduction on the number of projects that we've worked simultaneously in the area, allowing us to streamline and simplify our planning and execution of the most important projects first; secondly, a big focus on our spend for fuel gas and diesel fuel for producing power; and third, by leveraging our supply chain, and particularly by leveraging our strong capability elsewhere in our business.
Further savings are planned for 2019 and beyond. And as Amjad mentioned, the team are focused on winning new business, which will benefit numerous stakeholders in the region.
In summary, both Magnus and SVT have been successfully integrated into the EnQuest business and are already benefiting from our business model and focus for creating value at late-life assets. Numerous opportunities at both assets are actively being worked to deliver long-term value.
Moving then to Central North Sea. Production for the first half of 2018 averaged 6,108 barrels equivalent per day, which was 43.7% lower than the same period in 2017. This production decrease was a result of fuel declines, unavailability of some of the ESP pumps at Alma field and some impact from wax restrictions in the Scolty/Crathes pipeline. That's more impact there compared to the first half of 2017. However, production from the area was steady through the period, benefiting from high uptimes. And we did produce about 12% more than in the second half of 2017 from the same well stock.
Going forward and post June 30, as I mentioned earlier, in August, we have completed the 3 ESP replacement workovers at Alma. And aggregate production is now improved as planned, and all major shutdowns have been completed in the DNS area.
Focus for the second half of 2018, therefore, will be on maintaining high uptimes; optimizing production from the 3 new ESP replacements at Alma and Galia and at Scolty/Crathes via lift gas cycling; preparing for the Scolty/Crathes replacement pipeline, which is scheduled for the summer of 2019; and of course, progressing technical and commercial work to monetize the nearby Eagle discovery.
In summary then, at CNS, production is below the same period last year, but steady with high uptime and now higher in the second half following the 3 ESP replacements. Further production growth will come from the Scolty/Crathes pipeline next year and potentially from Eagle.
And finally on to Malaysia. In Malaysia, first half production was 8,225 barrels equivalent per day, which was down about 8.3% from the same period in 2017. I'm pleased to report the region has delivered another excellent safety performance through the period, with, again, 0 lost time injuries.
Production was steady, particularly at PM8/Seligi, which was supported by high planned uptimes, very good gas compression, train reliability and the execution, again, of low-cost, barrel-adding well work.
Looking forward to the second half of the year, I'm pleased to report that, and reiterate what Amjad said earlier, the 2 wells at Seligi, our first drilling in Malaysia, were completed about 12% below AFE cost, and are now onstream producing as expected.
Focus on the next two quarters will therefore be on optimizing production from these new wells; continuing and completing our well work campaign for the year for both barrel-adding and reservoir surveillance work; executing a planned three-week shutdown for maintenance at Seligi field safely and on time; and of course, planning for future drilling, again, a 2-well program in the books again for 2019.
So in summary, for Malaysia, safe, steady and efficient operations, successful delivery of new production from both drilling and idle well work and ongoing technical work to support future drilling, well interventions and reservoir management.
And with that, I'll hand back over to Amjad for a summary.
Thank you very much, Bob. And as you can see, we have steady production and delivering performance in line with guidance. That strong performance in first half affirms our guidance for the second half, both production-wise at 50,000 to 58,000 as well as CapEx at $250 million and the OpEx at $24 million. We continue to prioritize our debt reduction. And as we mentioned, our debt is slightly down, but with the peak is down to $1.85 billion.
And we do see significant potential now with our existing assets, particularly Magnus, 2 billion barrels in place; Kraken, where we've just started that field, and we're looking at the Western Flank with an additional 100 million STOIIP, 30 million possible resources; and then at the starting with PM8/Seligi and the drilling program there, which should make us understand the field better and give us of the ability to add significant reserves there.
I just wanted to remind you. We started this company organically and have grown it organically. And when we started, we were a 10,000 barrel a day company in 2009, just before the IPO. And today, we are at 54,000. And with the Magnus acquisition, that should increase significantly. The reserves, we started with 80 million barrels of reserves, 0 really in 2007. And today, we're sitting above 200 million. And with the Magnus acquisition, that would add an additional 60 million.
The Magnus acquisition is a compelling option for shareholders. That's why I've unwritten my share, and I'm very pleased that we are able to generate $500 million of value by putting out about $127 million. So it's almost 4x the returns on an NPV10 basis, which is really very compelling. That's inclusive of all consideration, loan payments and cash flow. I know the deal is complex, and we're happy to take questions on it, but this was verified, and this is based on a third-party report.
We're expecting to add significant reserves, 30%, to our 2P reserve base. And this is a cash flowing asset, so it's not one we have to wait for development. And it's much better understood, very well understood by us indeed, with the 2 wells that we've drilled. We are also optimizing the recovery method in the field, which I think will move us to more of a water injection secondary and tertiary recovery. It aligns with EnQuest's strategy. Obviously. Running late-life assets has been our key modest operandi, and we have done a very strong job with all of the assets that we've taken in the U.K. as well as Malaysia.
And we're targeting completion of the deal around at the end of this year. The cash flows from Magnus will further facilitate and add to our cash flows, which are increasing significantly, as you've seen up 100% for the first half. They've given the oil prices continue to be strong, and our hedging program, as Jonathan mentioned, is at a higher price, we obviously expect higher cash flows in the future.
With our shareholders' support, we're targeting the completion of this quickly. And then we will be looking at further opportunities within our portfolio, which is a very attractive portfolio, given 3 very strong, very large oil in place assets at Kraken, Magnus and Seligi with very good potential upside.
Thank you very much. We will move now to questions from those in the room first, and then we will go those with the dial-in audience. Thank you.
[Operator Instructions] Thank you.
So EnQuest, you said, did not go for the summer option. I was wondering whether you can comment on this, whether the problem was a defensive expectation on prices or whether it was something different? And if it was on prices, what was the underlying factor? Defensive expectation on the reserve, on production, something else? Second, where would you see now Kraken production stabilizing, I'll say, around next year? Where would you see that going to from the current 33,000 a day? And lastly, on Magnus, so you quoted $500 million, NPV10 cost of $300 million. I want to make sure that we're comparing apple with apples. So are all those numbers based on the first of January '17? Or is the NPV a bit different? Just to make sure that we're looking at the same thing.
Okay. I'll start with the Kraken. So we did get several offers on the farm-out of Kraken and several offers, which are financing-type offers. I think we determined that a ring-fenced 15% interest in Kraken is a better economic outcome for us based on the offers received and giving us the upside because we still retain the upside. The 15% financing is ring-fenced around Kraken. So there is no repayment schedule. There are no loan covenants. It is cash flow from Kraken that comes out, including the reduction of CapEx and OpEx. So this is ownership, the special purpose vehicle is owning Kraken.
Once the loan is repaid, and the loan is at a lower interest rate than our existing facility, then the upside is retained within EnQuest. So based on the offers that we received for farm-out and for financing, we felt this is the best option. In terms of production, as we mentioned, we were at 31,000 for the first half. For the last couple of months, we are at 33,000. Last month, we were at 36,000 in August.
So we continue to improve. We have just issued the acceptance certificate to Bumi Armada, and are hopeful that the production will continue stabilizing and increasing. We are also putting the DC4 wells on, which will give us additional capacity by early next year. So we're hopeful that, that trajectory keeps going on. The other assets have outperformed, which has given us the ability to come in, in line with our expectations on production. On the Magnus question, the effective date is 1/1/18 on the competent person's report.
Unidentified Company Representative
It's actually, the competent person's report was actually 1st of July '18.
I'm sorry. 1st of July '18. And it does include all consideration, the consideration which is $100 million upfront; the vendor loan, which $100 million of which would be paid back, so the vendor loan will actually be $100 million rather than $200 million; and then the profit interest that would be payable after the recovery of EnQuest consideration, plus the return to EnQuest. So all those are included in the NPV $500 million. That's why I think it is a very compelling transaction.
So comparing $500 million to $300 million, the $500 million is net, obviously...
No, the $300 million, yes. $500 million is net NPV10 of all consideration payable upfront and all the CapEx and all of the payments. So it is included in that number.
It's Rafal Gutaj from Bank of America Merrill Lynch. I just had a few, please. Sticking with the Magnus transaction, I was hoping maybe you could illustrate the cash payback for that $300 million consideration effective January 1, 2017 if we assume the forward curve. Secondly, on the Kraken FPSO operating efficiency, maybe if you could just comment on where that fits in the second half versus the first half and what the implications of that are on your day rate. Thirdly, just on that $175 million facility on Kraken, what happens if in the 5-year period, you do not repay that loan? Is that something that would need to be refinanced? Or is there a separate arrangement on that? And then, I guess, just a final one, if I may, on general approach to abandonment in the North Sea. It seems a lot of the provisions are appearing still quite high compared to what it actually cost to abandon. I wondered if this is an angle that you could use in future M&A transactions to try and facilitate those. That's it.
I guess, I'll answer the first question, maybe turn over to Bob for the second, and then Jonathan for the third. And then maybe I'll answer the last one with the first one. So in terms of Magnus, what we can tell you is what we expect up to date obviously because we're not giving forward profit forecast. So from the transaction effective date, which is 1/1/17, so the $300 million consideration, we expect $100 million to be paid back. So we expect the assets, which was cash flow breakeven when we took it over, we expect it to have generated $100 million at the time of completion.
So the vendor loan would then reduce from $200 million to $100 million, would be payable over 5 years. So roughly $20 million per year over 5 years. So that's the expectation. I think Jonathan mentioned the point, which is actually very important, which is there is a notional tax because we have not owned the asset. There's a notional tax of 40% associated with that $100 million payback. And that notional tax will be not there because we have a significant tax carryforward pool. And so we expect our cash flows to be without a tax burden once we complete going forward.
So that just shows you that very strong cash flows even at the prices last year and so far this year. So a very strong cash flow profile. I mean, there's a competent person's report, Rafal, which gives you both the OpEx, CapEx as well as the production. And you could then extrapolate the cash flows going forward. In terms of abandonment, we are very lucky that we have a very small portion of the fixed platform abandonment that we indeed operate and benefit from significant cash flows or working interest. And we are incrementally moving to align ourselves in a small way to manage those abandonments, and hence, the Thistle option, where we received $50 million versus significantly larger than the NPV value abandonment for the ability to manage the abandonment.
We've abandoned wells for our partners, both in Thistle and Heather. And our well abandonment costs are significantly lower than their abandonment costs. And that's why they're very happy with us executing those abandonments. So we've done 3 fixed wells in Thistle, and we have indeed done 3 in Heather so far. We do see the efficiency of doing many abandonment wells. And obviously, the platforms come with a lots of old wells. So I think starting 2 abandoned wells in an incremental manner as well as drilling new wells is probably the right approach.
So we're using the rig and the crude platform to drill new wells, and then move on to abandoning wells at the same team in the same year. So I think that's a very efficient use of time. And so the costs are lower, and we are seeing lower costs on the wells for the abandonment than originally anticipated. And well abandonment is probably around half the cost of the overall abandonment. So I think that is quite significant. So a very, very good point for you to point out. Let me turn first to Jonathan to answer you on the 15%.
Yes. So on the $175 million, which is obviously ring-fenced financing for 15% of Kraken, so the way that, that would work is that it gets repaid out in the cash flow of the asset. We would expect that $175 million to be paid significantly before the 5-year period. However, if it was up until the 5-year period, then, clearly, yes, whatever was left off at the end of 5 years, you would then have to refinance. But we're expecting that to be repaid significantly before the 5-year period.
And Bob can talk a bit about Kraken and the efficiency in Kraken.
Sure, sure. Happy to, Amjad. So with regards to production efficiency, I'm not going to provide a specific number for any asset. But I can tell you that group-wide, we target at least 80% production efficiency for all of our assets, and obviously aiming to go as high as we can. We did not achieve that in the first 6 months in Kraken. But as I said earlier, the production efficiency is improving. And there's 2 main factors impacting the production efficiency of this asset or any asset.
One is the uptime. And in the case of Kraken, or most assets, is also the volume of water injection. So as I mentioned earlier also regarding water injection, we've taken steps to increase the daily water injection rate. So therefore, we're increasing our voidage. That's improving production rates, which will improve production efficiency. And regarding uptime, as I also mentioned earlier, we've now agreed final acceptance of the vessel. That's certainly a signal and an indication that all the main critical work scopes supporting efficient and high uptimes are now complete.
So moving into the second half of the year, we're certainly aiming for and expecting higher levels of production efficiency. With regards to the day rates, I'm not going to comment on specific commercial arrangements, but we have an arrangement in place to set targets on a monthly basis. And there's a sliding scale impact based on our achievement of those targets.
So I mean, just to be a bit more transparent, I mean, there's been no change to the target.
It's James Thompson from JP Morgan. A couple of questions, please. Just really on Magnus. Obviously, you've taken decision to acquire all of the asset. You've been on it for a little while. You've increased reserves. I just wondered if you could talk maybe more about the upside potential beyond that, that you maybe see at Magnus, as you say a very large oil in play. So we're interested to hear your thoughts about what you could maybe squeeze out of the asset over the next few years. And then related to that, in terms of other potential M&A, it's a relatively big transaction. I remember you saying that you struck the deal at $50. How does it compare to other assets you're looking at right now? Do you feel like sellers are asking a little bit more these days with the higher oil price? And related to the higher oil price, and final question, just where do you see the operating environment in the North Sea here? I mean, you haven't changed your OpEx guidance. Clearly, it's been very favorable for operators over the last couple of years. Are you seeing any pressures on the cost sides or on rig rates or anything like that? Just a little bit of an update in terms of where we are operating-wise in the North Sea, that'd be great.
So I mean, we do see upside in Magnus. Obviously, the 2P reserves is significant, and the wells that we've identified are significant. We also see, additionally, $10 million of contingent resources. But we also are looking at, as I mentioned earlier, recovery mechanisms, secondary or tertiary recovery in Magnus and how to optimize those, which hopefully will give us another leg up. But at present, we see a very rich opportunity set of wells. And we have a rig which has been revamped, and is very efficient and is drilling wells at, we mentioned, $13.5 million per well. So we see that.
Our first protocol is the very rich well program that we have in place. In the meantime, we are optimizing the reservoir models to see the secondary and tertiary recovery mechanisms if those can help us increase the recovery. I did mention we're at 50%, and we're hoping to increase that. Obviously, the 50% is in the $60 million numbers. But each 1% is 20 million barrels, and we're hoping to get up to the numbers that we've seen in Thistle and indeed some of the other assets. The M&A transactions, I mean, this is material. And I think getting 4x NPV return on your investment is a very attractive measure by any means.
I don't see transactions that are available for NPV10 values of $500 million, post $100 million investment, $120 million investment. So I think this is a very attractive opportunity by any standards. And I do think it's really favorable because we've been able to add the barrels. And that has adding the barrels by 20 million barrels in such short order and adding the production, increasing the production level, which you'll see from the competent person's report, obviously has immediate accretive impact on the transaction. Your guidance, your issue on or question about OpEx, OpEx guidance. We still see areas. And we have, I think, a supply chain that is extremely efficient.
We do supply chain procurement, both in the U.K., but also internationally. And we have our main procurement office for U.K. operations out of Dubai, where we see the cost of oil and gas inventories are much lower or oil and gas materials are much lower. And that's worked extremely well. We've seen cost reductions, and continue to see reductions of costs in some supply chain areas. Your question about drilling rigs, I mean, I think we are seeing more and more tightness in that space.
And maybe that's one area, maybe some of the vessel areas that are also coming back depending on the best summer windows for vessels. But I still think we are seeing reduction. We are able to reduce cost. SCT is case in point. That has been reduced by 25% in one year, and Bob and the team will look to reduce that even more significantly. And the key for that is that it gives us the ability to reduce cost per barrel. And that cost per barrel for transportation and processing will allow us to produce the tail end barrels and increase reserves. So it's critical for us. It's critical for all the operators in the North Sea to have reduced costs in Sullom Voe.
I'm Pierre Ross [ph] with First Financial Capital [ph]. Just maybe starting with, what would we expect next in the capital structure? Obviously, you have managed to raise financial gains to Kraken at a relatively low cost. But I mean, should we expect further deleveraging into 2019? And so should we also expect that you will start to approaching capital markets to refinance your current RCF and the bonds?
I'll leave that to Jonathan.
I mean, I think what we've said is, clearly, we're looking to reduce debt over the this year and next year. Obviously, that's what we're looking to do. I think we're looking, obviously. There's a repayment coming up of the term loan and RCF the 1st of October. So we'll make that repayment. And then there afterwards, obviously, we've got cash flow from our assets, including Magnus. So we're absolutely focused on reducing our debt. And that's what we're going to be doing over the next year. As you can imagine, I'm not going to comment on what might be next in terms of any transactions to the capital market. And clearly, we're looking to do that to keep our capital structure as efficient and as cheap as possible. And we will continue to do that.
And so should we expect the bonds to be fully cash paid starting October this year?
I think the rate, as you know, is if oil price is about $65 a barrel for the previous 6 months, then that's where we have been. So that's what we would expect to be paying the cash interest, yes.
Okay. And moving on to assets. We have seen quite a lot of transactions, both in the U.K. and in the Norwegian Charlotte [ph] over the last 12 months. Maybe that subsided a little bit more recently, but do you see further deals when you take over maturing assets as of now I understand that Magnus is the focus. But with Kraken under control, Alma/Galia, well, apparently, you found the solution. You seemed to have found solution. You have stalled a credit transfer to Total. But do you see any further assets, any further opportunities in the North Sea or elsewhere?
Well, I guess, I mean, there are further opportunities in the North Sea. I think our primary focus at the moment is obviously cash generation and reducing our debt. That's clearly what we're looking at. I think from our perspective, there are other things in the North Sea. We might look at some, we might not look it out there and say, I think there's thing out there. But our primary focus is clearly on our assets, Magnus, cash generation and reduction on debt.
I think we have a very rich opportunity set. I've talked about that earlier. And the opportunity set that we have, which we haven't been spending capital. We've spent spending capital really on workovers and well interventions. We're able now to spend capital on wells, which is what you've seen this year. We've drilled really outside of Kraken for the first time in a few years. And those are highly accretive and highly paybacks are also very short, some of them a few months and some of them adding a few million barrels as opportunity. So I think we'll continue looking at our opportunity set first to maximize our returns, but also to stem the declines that we have in our assets.
And finally, can you please confirm on the Kraken FPSO? Is it not fair to assume that all the technical issues that you have been trying to resolve over the last 18 months, I think now, that this is now behind you? And now the constraint is on the subsurface and the wells?
I think the wells subsurface and the wells have come in as expected. And the subsea systems have worked very well, and the hydraulic pumps have worked very well. I mean, we're encouraged that the contractor has met the acceptance certificate criteria, which I think is encouraging for us, for them and for all of us. I can't sit here and say that these are very complex processes. And I'm sure there will be problems, just like we have problems on Thistle, just like we have problems on Heather, just like they're just part of the business. As you know, valves leak and things can go badly. Sorry, Bob has the right hair. He has. So...
At least I still have mine.
So I mean, if the question is, will there be any issues in Kraken? I'm sure there will be. But I think, hopefully, they'll be minor. And, we're very comforted that things we have reached the acceptance criteria, which should give us stable production in the future.
Is FPSO right now in line with the original agreement?
I mean, we did mention the voidage. The overall liquids rate are but we still have the voidage, which really emanated from the beginning of the year, when the water injection after the very cold spell had to be revamped. And we have made a lot of progress on recovering that voidage. So I think it's as expected with the voidage being in place.
The day rate in dollars?
No. So the day rate, the contractor still has the same arrangement that we've had in place. So the contract does call out for the production efficiency to be reflected in the rate.
It's Mark Wilson from Jefferies. I'd just like to understand some of the moving parts before we lay it on the Magnus option. You gave your net debt figure, Jonathan, and also this $256 million of available facilities in cash, and that there's an amortization of $195 million in October. I'm assuming that's out of undrawn facilities because if I take that off, and then I layer on the additional Kraken facility, I've got your net debt going up. Just discuss that, please. And does the Kraken facility sit on your balance sheet? Will you show that reflect off them?
Yes, the Kraken facility will sit in our balance sheet, as debt obviously, we will add cash when we draw on it. And then we will repay the $195 million out. Obviously, we've got cash available, and we'll also have the cash from the drawn facility on the $175 million. So that's how we will repay the $195 million.
So that's been paid down out of the drawn facility then?
Well, it'd be paid down out of the $175 million, plus our cash that we have as well. Obviously, it's also significantly more than the $195 million.
And what would be the next material amortization?
The next one is in April next year, which is another $175 million, and then there's another $100 million in October next year.
And then on operations, given what you see on Kraken so far in the uptime, what is your feeling on what the field can do with DC4 on good uptime and/or water injection? What's your expectations on plateau in the future?
We're certainly not going to provide a specific number. What I can say, and what we have said, is the performance is improving. We averaged the lower expectation at about 31,000 first half of the year. Things have improved to where we were about 36,000 barrels a day average for August and all things considered. Water injection has increased that's closing the gap. We have acceptance on the vessel, which is a signal of further improving uptime, and we have 2 new wells coming online in the first part of the year. So we're looking forward to strong performance in production. I'm reluctant to provide a number forecast because things can happen.
I think one thing you can take is for us to get a financing ring-fenced at a very attractive rate for Kraken, shows the cash flow from the asset is extremely significant because they're not looking at payback if it wasn't robust. And so that cash flow has been in place for the first part of the year and last year. And that is reflected by the strong related to ring-fenced financing. And so I think you should just take that as indicative that cash flows are very strong.
Chris Wheaton from Stifel. Two questions, if I may, please. It's nice to see someone looking as they'd like to seem. A follow-up on Mark's on Kraken, please. Do you need DC4 to be working to hit 50,000 barrels a day?
So what we said is 50,000 was a target, and that the well capacity was 50,000. And I think we mentioned in early part of this year that we did achieve that target. This is before we had. This was in February before we had the Beast from East. And so we were operated above 50,000, and we were producing more than 50,000. Since then, we've had problems with the vessel and, hence, the delayed acceptance and delayed issues on production. The biggest issue we've had is we had to prioritize. After that period, we had to prioritize the production and rather than the water injections.
So we started producing, and we had a large voidage without the water injection in place for a while. And now water injection has been rectified, and we have been recapturing the voidage. So I think that's in line with expectations. We also have taken the opportunity to not shut down in September, which we had a maintenance program planned for September for the vessel, which is normally a yearly program. And we did the activities in March, given the extended shutdown that we had because of the cold weather.
Obviously, the heat, and we talked about this earlier, the heat and the viscosity of the crude isn't conducive for the very, very cold temperatures, and that we have added more and more lagging for the vessel. So I think the answer was with the DC3 wells, we did reach our targets. There has been water voidage since then. And with the DC4 wells, we're hopeful that we continue to see more and more productive capacity of the wells.
Now, obviously, as you know, Chris, none of the wells continue and don't decline forever. But this is a different kind of field because it's a field where you're always producing oil and water. You're producing oil and water mixture from day 1. And we haven't seen the injected water finger through. So there's no issue on the subsurface. We've seen that. So far, we have had a couple of wells, but not as unexpected produce some of the condensate water that's in place.
A question then for Jonathan, please, just to understand the cash flow waterfall within Magnus post the deal. For your exiting 25%, I presume the cash flow then gets paid off the vendor loan you already have outstanding in BP first. And then once that's done, it comes to you and issue to the Company?
And then for the remaining 75% you're acquiring, there's the $100 million you've identified that's effectively paid back from the transaction. Sub-question here. Do any of that account against the $500 million, sorry, the $1 billion cap on payments made to BP that you identify in the statement today? But then once the $100 million is paid, is there anything else after that, that stops that payment coming straight back to the Company?
No, no. That money comes back within the waterfall. So that's...
Right. Out of 50% off the 75%?
Yes. So yes. Once we have received our $100 million cash upfront back, then going forward, then, let's say, this is over $20 million a year for 5 years to BP. Then that comes out first. And then after that, then that's the profit share between us and BP.
If there are no more questions from the audience, we can go to the remote questions.
[Operator Instructions] There appears to be no questions over the telephone.
Okay. Thank you very much, everyone, and looking forward to the EGM and the approval of the transaction for Magnus. Thank you.