Earnings Call: Q1 2018

May 7, 2018

Great. It's good to see you all here at Von Werften and also a good day to you whoever is watching this out on the web. It's really good to be here today to present the Q1 results of 2018. This has been yet another quarter of high activity and a lot of projects ongoing. In the quarter, we had an average production of 159,000 barrels of oil equivalent. This is the highest so far in the history of the company, but we are by no means done. We are working on a large number of development projects. And I'll change the slides. And the main message is that we are on track. The first quarter was also a good quarter for exploration with an encouraging discovery on Frosk near Alvheim, which I will get back to a bit later on. We have delivered yet another quarter of solid financial results and Alexander will go through them in detail as usual. We continue to generate strong cash flow and the free cash flow in the quarter amounted to $222,000,000 We also successfully issued a new $500,000,000 bond in the quarter with longer duration and lower interest than in the past. And we increased the quarterly dividend to $0.31 per share in the quarter. For 2018, 18, in total, we plan to pay $450,000,000 in dividends, and the ambition is to grow this amount by about $100,000,000 each year until 2021. In addition, we continue to build for the future. As previously announced, we were awarded 23 new licenses in the last licensing round. Based on these awards and a follow-up on the secured additional rig capacity to speed up exploration activity around Alfheim and the Utsira High. I will also get back to this a little bit later on. We are also continuing towards a development solution for the Noaka area and I will spend some time on this towards the end of the presentation. But before we dive into the operation and the projects, Alexander will go through the financial statements for the Q1. And Alexander, the floor is yours. Thank you, Karan. Good morning to everyone. As always, I will take you through the income statement, balance sheet and cash flow for the quarter. This is the Q1 where we are showing the combined operations after the acquisition of Hess Norge. This obviously impacts the financial statements, and we are showing both record high revenues and net income this quarter. So starting with the P and L for the quarter. We recorded income of $890,000,000 based on a production of 158,600 barrels of oil equivalents per day, and we realized an oil price of $69.15 in the quarter. We had production expense of $173,000,000 an increase of $26,000,000 Production cost was $12.10 per barrel. In the Ardham area, we had OpEx per barrel of $6 Ivarossen was $10 Valhall Hod, dollars 18.5 Skarf at $10.8 and finally, Ula Tamper at 46.2%. Other OpEx amounted Other OpEx amounted to 3 point $1,000,000 This includes dry well expense of $14,000,000 stemming from the 3 wells on Kritungen, Ryvodossen and Hufsaheure. Plus, we had seismic acquisitions, which also amounted to $14,000,000 field evaluation costs for yet another $14,000,000 and area fees and other exploration costs of 13,000,000 EBITDA then came in at $658,000,000 for the quarter. Depreciation was $185,000,000 This equals 13 dollars per barrel. This is down from $14.7 in the Q4 last year. As of December 31, we reduced the abandonment estimate on Valhall, which again led to a corresponding reduction in the fixed asset value to be depreciated going forward. This again impacts the depreciation per barrel this quarter and going forward. There were no impairments in this quarter due to the headroom from prior periods as well as positive developments in commodity prices. We had a net financial loss of $47,000,000 in the quarter with the breakdown of these items shown in Note 6 to the financial statements. Profit before taxes was $425,000,000 and taxes amounted to $264,000,000 This gives a tax rate of 62%, which is lower than in the previous quarter. And again, the changes in U. S. Dollar NOK FX rates impact our Norwegian tax returns. The strengthening of the NOK against the dollar from $8,200,000 at year end to $7,84,000 lowered the tax expense this quarter. Payable tax was $215,000,000 and the change in deferred taxes was 49,000,000 dollars We then had a net profit of $161,000,000 this quarter. So turning the attention to the balance sheet. At the end of the quarter, both goodwill and intangible assets were virtually unchanged from year end, standing at $1,900,000,000 $2,000,000,000 respectively. Net of depreciation, the total PB and E balance increased to $5,700,000,000 in the quarter. The net increase of $82,000,000 came as a result of $251,000,000 net of depreciations of $169,000,000 Looking at the book value now of our 6 hubs. Our 4 assets, Vallharl Hod, Alvheim, Ivar Ossen, Johan Sertorp, each now have a book value of approximately $1,200,000,000 Receivables and other assets were $764,000,000 at the end of the quarter, a small decrease from the previous quarter of 11,000,000 dollars This balance was increased with accrued income from sale of petroleum products, dollars 141,000,000 but offset by lower underlift of $40,000,000 and reduced another $119,000,000 related to other receivables from licenses. The short term tax receivable of SEK1.67 billion at the end of the Q1 relates to the tax loss from Hess Norge. The increase of $80,000,000 from the last quarter relates primarily to the currency impact of a strengthening NOK versus the U. S. Dollar. Do note that this FX effect is reflected as other comprehensive income or OCI and not booked in the income statement as the tax loss is still sitting in the legal entity of Aker BP AS, previously known as Hess Norge AS. Cash and cash equivalents were $38,000,000 at the end of the quarter and then we had total assets amounting to $12,000,000,000 at March 31, which is approximately the same as 3 months ago. On the opposite side of the balance sheet, we now have equity of 3 point $1,000,000,000 That's an increase of $121,000,000 from the previous quarter. This reflects the net profit for the period at $161,000,000 We had a currency translation adjustment through the OCI, which I mentioned, of €73,000,000 and then this was reduced for the dividend payments in the quarter of $112,500,000 Other provisions for liabilities stood at $2,960,000,000 That's a small increase, yes, from the previous quarter. Deferred taxes amounted to about $1,400,000,000 That's reflecting an increase of about SEK50 1,000,000 from the previous quarter. Book value of our net interest bearing debt was SEK3 1,000,000,000 quarter end. We now have 3 long term bonds for a total of $1,100,000,000 and our bank debt is now a little under $2,000,000,000 The short term bridge facility related to the Hess acquisition amounts to $1,500,000,000 while the drawings on the RBL amounted to $460,000,000 Tax payable was $554,000,000 at the end of the quarter. Of this, accruals for uncertain tax positions amounted to $217,000,000 20 17 NACS net tax payable was $112,000,000 and 20.18 tax payable made up the remaining balance of 2.25 1,000,000 dollars Other current liabilities decreased from $1,000,000,000 to $923,000,000 in the quarter. This decrease is mainly driven by reduced other current liabilities and short term abandonment provisions, partly offset by increase in trade creditors. Cash flow from operations were $600,000,000 this quarter. Cash flows from investing activities totaled $378,000,000 That's including the capitalized exploration expense related to the Frosk discovery that Karl Erik will come back to in a minute. In addition, investments in fixed assets were in line with previous quarter summing up to €257,000,000 where Johan Sverdrup accounted for €94,000,000 Valhalla Hod, €73,000,000 and Ula Tambor of €40,000,000 We also recorded decommissioning payments of $82,000,000 mainly related to the Maersk Invincible rig running P and A activities at Valhall. Thus, free cash flow was $222,000,000 in the quarter. When it comes to financing activities, we raised $500,000,000 in a new unsecured bond issuance. This exercise was completed in March and it's a 7 year bond, callable after 3 years and has a coupon of 5.7 percent. We subsequently repaid $815,000,000 on the RBL and we now have $3,500,000,000 in committed undrawn capacity on our 4 In addition, we paid out $112,500,000 in dividends during the quarter. So at the end of the quarter, our cash balance was $38,000,000 and book value of net interest bearing debt $3,000,000,000 and net debt over EBITDAX down to 1.3x. The 1,500,000,000 dollars bridge loan is included here in the net debt figure, whilst the 1,600,000,000 tax receivable related to the Hess acquisition and the tax loss there is not included. So we are still expecting to see a disbursement of this tax loss in the second half of twenty eighteen. Then finally, our guidance for 2018. Performance in the Q1 has been in line with expectations. The run rate on CapEx is lower in the Q1 compared to the estimated average for the year. This is due to the phasing of our projects, in particular, the Valhall projects. We still expect CapEx to come in at around $1,300,000,000 for the entire year. For the other 4 parameters, expects, production, production costs, decom costs, we are roughly in line with guidance. So in summary, we are not making any changes to our guidance from January. So with this, I will turn it back to Karl. Thank you, Alexander. Okay. Let's move on to operations. The philosophy and investment hypothesis in Aker BP has always been to maximize value creation through actively managing and investing in our assets. And we are fortunate enough to have an extremely robust portfolio of about $18 breakeven going forward. As a consequence, we have very high activity level across the portfolio as you can see on this slide. We are executing several projects amongst others are 3 field development projects that are currently ongoing which I'll come back to, the Walla West Frank, the Aafugel in the Skow area and the Skogul in the Alvheim area. We've also had a really high MMO activity in the quarter preparing for tie in of these projects, but also extending lifetime in our current assets. And a busy exploration program, which we are further expanding towards the end of 2018. I'll spend some time going through some of these activities in more detail, but I will not necessarily touch on every one of them simply because the time is not sufficient. So let's move on to Alvheim. The Alvheim area has been a great success for Aker BP. With a high quality FPSO delivering world class performance, the challenge is predominantly to continuously feed new resources to maintain high capacity utilization. We have responded to this challenge by drilling infill wells and developing new reservoirs in the area since we took over the field from Marathon. Fields like Waipakobra, infill wells like Wollun infill and most recently the 2 new wells in the Boa reservoir. Looking forward, we are this year planning to drill yet more infill wells, infill drilling on Kamilion and appraisal drilling on the Gekko reservoir. The Skogul development which is also a tieback to Alvheim has been approved by the authorities and the project is moving ahead as planned. But perhaps the most exciting development of Alvheim in this quarter has been the Frosk discovery. Frosk is located in a Beyla license close to existing infrastructure and in particular the Beyla Manif The frost discovery in itself was significantly higher than our pre drill estimates. This is a very positive surprise in itself. The discovery has also increased the attractiveness of other exploration targets in the area. And in order to select the most optimal development in the area, we are therefore securing new and additional rig capacity, this time the Scarabeo-eight, which will be used to drill 2 to 3 wells in the area on prospects named Rumpetrol and Froskelor. I apologize for the names for the non Norwegians out there. As a consequence, we have expanded our exploration program for 2018. And while we are on the subject, it might be a good idea to have a look at this exploration program. There are several changes to this plan since I presented it last time in January. The addition of the new wells in the Frost area comes in addition to the JK project, which is located just north of Johan Sverdrup in license PL-nine sixteen. This is a license which we were awarded in January and the latest ARPA licensing round. And I'm very pleased to see that we are able to plan and drill an exploration well within 1 year after the license was awarded. We have also added an exploration target in Slengvehoe this time in license 915, which is yet another license awarded back in January. This exploration target is located near Hunt's and will be drilled as an extension to the already planned Hunt's appraisal well. 2 of the Barents wells that were originally planned for 2018 have been moved to 2019 to ensure sufficient time for safety preparation and to optimize the rig schedules. The other changes here are mainly optimization driven by rig schedules and rig utilization in the Aker BP portfolio. Again, we believe this to be an extremely attractive exploration portfolio and are excited about the exploration projects on the Norwegian Continental Shelf going forward. Now let me move on to Valhall. At Valhall, the Flank West development project was approved by the authorities in March and the project is now well underway. We have started cutting steel for the jacket and started the modification scope on the field center to prepare for new production platform on the Flank West. We are encouraged by the effects of the field development and expect to see more positive effects from this way of working together with our vendors. In total, we've also made the investment decision on the Flank North water injection project, which is expected to add yet another 8,000,000 barrels of gross reserves through increased recovery in the northern part of Valhall. The drilling will start in Q4 this year and the water injection is expected to start in Q2 'nineteen when pipelines and risers have been installed. The Maask Invincible rig will execute the drilling as it completes its P and A program on the in the Valhall area remains enormous, and we will continue to mature the opportunities in this area. Some of these opportunities are listed on this slide. Another area with high activity is Skow. The Arfel PDO was approved by the authorities in April and the project is now well underway. The main contracts for subsea installation and production systems have been awarded and we are now working with technology qualification for the 2 key technologies, which are planned to and improved production efficiency. We are also working to qualify the vertical Christmas tree solution, which will facilitate direct wellbore access and reduce the complexity and cost of future well interventions. The economics of the Afrold project are extremely robust with a breakeven oil price of $18.5 per barrel. We keep on chasing further upside potential both above and below the surface. In Q1, we drilled an appraisal well on Aufu as a part of the Kuitungen tumbler exploration well. The exploration target was unfortunately dry, but the appraisal results were positive and could potentially lead to a positive revision of the Afl reserves. We are also looking into the possibilities of debottlenecking the SCAR FPSO, which could enable an acceleration of the second phase of the Afuel development. And while we're talking about Afl, it's also worth mentioning that we have now successfully repaired the 2 wells that were shut in last year due to Christmas tree issues. At Ula, we have started production from the new Tamba wells. As you see from the chart on the left, which are weeks and not months when it comes to the X axis, This has made solid contribution to the Ula production in the recent weeks. And when we finalize gas lift and modification in the turnaround later this year, Tambo will be ready for another 10 more years of production life. Tambor is an exciting story in itself. This was a field that was planned to be not that long ago. After joining forces with BP, we turned around quickly and started drilling less than 1 year after the completion of the transaction. In total, the drilling on the Tambo reservoir has added 26,000,000 barrels of oil equivalents on a gross basis. This is a typical example of the investment hypothesis Aker BP when it comes to developing more reserves on our production hubs. The Oda tie in project is also moving forward nicely and remains on track for production start next summer. Oda is important for 3 main reasons. 1, it will produce provide Tamba volumes. And it will provide more injection gas to Ula and thereby increase WAG capacity. Finally, while on Tambo, I'd like to say a few words about the fatal accident on Maersk interceptor on 7th December. The Petroleum Safety Authority has concluded its investigation on the accident and the report is available on the PSA web pages. The report concludes that a raw water pump fell to sea as a consequence of a failure on flat braided sling used in the lifting operation. The lifting operation was a part of Aker BP and Maast Drilling support the findings of the PSA report which are consistent with our internal investigations. In addition, Maast Drilling and Aker BP have conducted industry transfer knowledge sessions in Norway and internationally. Both companies will continue to work on implementing measures that ensure that such incidents do not happen in the future and continue to transfer learnings to the industry. Now moving on to continues to perform well with a plant availability or uptime of 98% in the Q1. Production was, however, somewhat negatively impacted by external conditions related to the availability and the gas export in the Sage pipeline and some operational issues at Edvard Grieg, which as you may remember provides Eeva Rosen with power, processing and export services. We continue to roll out digital operations on a digital operation model at Ivarossen, which amongst other things will involve an onshore control room to be operational later this year. So far, we are extremely happy with the progress and excited about the results we see in the Ivarossen digital operations. We have started drilling again at Ivarossen. First, 2 new water injectors, which will contribute continued high productivity from the field. When we have completed the water injector, the rig will move on to an appraisal well on the Hunt's discovery to test and also test a new exploration target called Slangverheide, which I talked about previously. Slangferhoeda is, as you may remember, located in the license that were awarded in January. Moving on to Johan Sverdrup. The project is progressing like clockwork. And as you can see on this beautiful picture, which says more than a 1000 words, the top side has now been installed. Since our last quarterly presentation, the operator has further reduced the cost estimate for the project and now estimates the breakeven oil price for Phase 1 be below $15 per barrel and below $20 for the full field development. And then last, but by no mean least, the Noaca project. The Noaca project in many ways resembles the Alvheim project in as much as it's a series of discoveries, but without of discoveries, but without infrastructure clear by close by. We have learned through the successful implementation of infrastructure in the Alfa area, the importance of establishing such infrastructure to fully utilize the resource potential in the area. I'd like to remind you that when Aker BP took over Alfheim, we had approximately as many projects on the pipeline as we currently have. Just an example of why an area development in our view is the only way to go. Several attempts have been made and studies have been conducted. And in our view, the PQ solution is the most robust area development. The PQ consists of a central processing and quarter platform and tiebacks either in shape of unmanned installations or substation installations. This solution will cater for field development of all discoveries in the area on the most robust development solution and open up for exploration upside. In addition, it's our view that it's the most economic case that has yet to be studied. Now in terms of execution, we would obviously have liked to progress with the original plan of a concept selection in Q1 2018. However, we have spent the time wisely and have carried out more studies to investigate further upsides. We are now looking at the possibility and with a firm ambition with full electrification, 0 emissions and power from shore in addition to offshore wind that could provide the positive field development on the Norwegian continental shelf. In addition, by utilizing the positive experience from the Eva Boson digitalization project, we could also foresee high degrees of optimization on shore control rooms and possibly also we are looking at the ambition of making the Nuaka project a hallmark project in terms of cost per tons and execution schedule. In total, we believe Noaca could really be the field of the future with 0 emissions, high degrees of digitalization, robust field development utilizing all the resources in the area and high economic performance. It's really exciting to be able to see that such a development could in fact be carried out inside our rather firm investment criteria of $35 per barrel. We really do believe that the NOACO BQ solution could be a role model for Norwegian field developments of the future. Now the priorities going forward are pretty much in line with what we have seen so far. Safe and efficient operations, excellent project delivery, relentless focus on cost reduction and productivity gains and to continue to mature project below the $35 breakeven in addition to executing on the $18 portfolio we are already executing in. And then finally, continue to maximize recovery from our existing resource base and pursue selective inorganic growth opportunities. And yes, one more thing. As you may have seen in the news today, we are pleased to welcome Cattel Dijkra, which was previously the Head of the Johan Sartre field development as the new Senior Vice President of Operations in Aker BP. And with that, I open for questions and ask Alexander to come back on stage. Keiran Niesz, SVB Markets. Three questions actually. First on Sverdrup, positive to seal developments, but could you indicate how much contingency that is left in the current CapEx estimate for Phase 1? And second question on Tamberg. Impressive to see that you actually have been able to increase production. Should we expect that to increase further from out from the chart that you showed? And my last question is, I asked it before, but are you looking at opportunities outside Norway or do you still stick to all the Norway strategy? Okay. When it comes to Johan Sverdrup, there's still a bit of contingency left in the project predominantly related to completion, offshore hookup and remaining construction scope. I'll leave it to the operator to comment on the exact numbers. And then your question on Tamba, the production on Tamba is now in fact constrained by the 8 pipeline from Tamba up to Ula. So while I would love to see increasing production, it's pretty hard physically to push more oil through that pipeline at this point in time. When gas lift comes on stream, we'll have some more well capacity, but we're pretty much producing as much as we can across Tambor at the moment. And then ultimately, Aker BP is firmly grounded in Norway. We have all our portfolio in Norway and we're really focused on the Norwegian continental shelf which we also truly believe holds a lot of exciting opportunities, one of which is the Naka project. Question from the web then maybe? At Nuwaka, what are the next steps to achieve concept selection and then FID? Will Statoil agree to the concept? Brilliant question. Well, there is already established an area forum and we'll continue to work with our partners and the authorities through that area forum to get to a conclusion which we believe will maximize the resource utilization and the economic performance in the area. And then Stottol can comment on whether or not they will agree themselves. You said the Magis Royce. Just if you could just to follow-up on your last answer about Nuaka concept. In terms of total CapEx, is your concept more expensive than Statos? I think that depends a lot on who you will be asking. But obviously, the aim for us is to will increase that will increase the value of our portfolio and meet our investment targets. There are some further questions on Nuwaka. From James Hosey of Barclays. Slide 18 states your PQ concept is supported by the Norwegian authorities. Does that rule out the UPP concept proposed by Statoil? I think the key issue here is that the authority expects us to maximize recovery on the Norwegian continental shelf. And then it's our view that the PQ concept is better than the UPP times do both in terms of robustness, ability to face in new reservoirs and also managing reservoir complications or well chemistry. And then Nicky Kuzmanov from Jefferies. I have a couple of questions. First on Ivar Ossen, the platform efficiency in the Q1 was 98% and so was Edvard Griegs. So could you maybe talk a bit more about how Sage has impacted net efficiency down to 89%? And the second question on the injectors, the Hanse appraisal and the Schlankfer Hoeghde exploration all in Tjoten. So we obviously want some color on the length of the plateau. When it comes to production efficiency, remember production efficiency is a volume over installed capacity measure. So that means that it's in fact possible as is the case here that 2 installations have rather high uptime, but not necessarily the production efficiency follow suit. So the issue here is twofold. The first one is the availability to export gas across Sage. And the second is the 3rd party services provided by Edvard Grieg in terms of power, production capacity in terms of separation and also return of gas lift gas. So in total, the of these reduce the production efficiency from the plant uptime on 88% down to 89%, while not necessarily negatively impacting production efficiency at Edvard Grieg. And then the second question, I think I'll wait until we see the results of and particularly the Hans Appraisal Wall before I guide on the duration of the plateau. Obviously, there are many factors that are now being investigated. But currently, we see no reason to deviate from our previous plans. Nicky also has a question on dividends. Do we see a scope for dividend increase in this new macro environment with oil above $75 per barrel? When we announced the dividend levels and the ambition there, that was at a point in time when the oil price lower than $75,000,000 But then it changes to that. That is something we'll just assess on an ongoing basis. Then Johan Sjarnon Dom from Societe Generale has a question. Could you would you mind providing more color on the expected scheduling of CapEx during the rest of this year? Well, it was a bit lower in the Q1 than averaging out for the year. But we do expect that in the second half of the year to pick up a bit. And in particular, when it comes to some of the ongoing and also the larger projects at Valhall. So still within the full budget for the year, but ramping up probably in the second half of the year. Marius Lundgren from 824. I have questions about Alvheim and Skate, on Alvheim, you talked about 2 unplanned shutdowns. Has this been a result and could it affect production moving forward in the year? And the second question is about Sklariv. In your Q4 report, you mentioned the 3 wells that you had to take down. Now you have 2 back on stream, it looks like. But the third one, do you expect it to be back on track in the first half? Or are you pushing that out now? Yes. So the turnaround, so the discussions on maintenance activities on Alvheim is pretty much as planned. So there are no new issues that have come up and there are no new slowdowns or other turnaround or maintenance activities that are outside our plan. So this is all very much inside our planning for maintenance activities on Alvheim. And then on Skav, yes, you're right. There were 3 wells that we took out. 2 has been reinstated. The third one, we lifted the Christmas tree, but decided not to run the new completion as the reserves in that well will be produced by other wells in the area. Amy Wong from UBS has a a it expected to be received? Yes. So there's really no news on that tax receivable. We are progressing as planned by finalizing financial statements, filing tax returns and having the dialogue with the Oil Taxation Office. So we do still expect that to be dispersed in the second half of 2018, July at the earliest or could be in November, December as well. So things are still progressing as planned on that one. The change this quarter, I suppose, was the currency effect that we saw given the strengthening of the NOK. So that has increased when you look at the balance sheet and book directly to equity. Victoria McCulloch from RBC has three questions. One, are production costs expected to remain at this level throughout 2018? Or are you expecting to see some variances by quarter? Second question, can you remind us what FX hedging you have in place? And are you taking some steps to hedge ahead of the tax settlement, which I guess was partly answered? And then the third question, given the large number of developments ongoing, how much focus remains on acquisitions? And are you still seeing a large number of opportunities being presented to you? So on the first one, production cost, we still believe on an average for the year of 'twelve. We did have some maintenance. And then Carlo talked about the Scar Christmas threes as well. So some additional costs there flowing through in the Q1. Average still for 13 dollars and some maintenance in the second half of the year as well. So it might vary a bit, but still it should be around $12 on an average. When it comes to FX, yes, we've hedged some of this exposure relating to the NOK 12,000,000,000 tax loss that we expect to see dispersed. We've hedged somewhat a combination of forward sales for a little less than NOK8 and also some utilization of options as well. So we've hedged some of that exposure as well. And then finally, the last question regarding M and A. Yes, obviously, This has been the BP. This has been the storyline since the summer of 2014. The only change is that the company has grown significantly larger, of course, and as such so has the activity program. We continue to be disciplined and focused when it comes to M and A. The competition on the Norwegian continental shelf has gone up. And the opportunities may not be that many that they used to be about a year, year and a half ago, but we're still seeing significant and interesting M and A targets being presented on a Norwegian condensate level shelf. Then we have a follow-up question from Nicky on the Nuaka. Any plans changes in partnership equity if Statoil does not agree with Aker BPGovernment Proposed development solution? I think that's something we'll have to come back to when we are more mature in Then we have a question from Karl Friedrich Schott Pedersen in ABG. Do you see signs of cost inflation? And if so, where would that be personnel or any specific services? If by cost inflation, Karl Erik means increasing cost on a unit basis. Yes, there are some signs that the cost is trending upwards. I would say particularly when it comes to high end semisubmersible drilling units, 5th to 6th generation, we see an upward trend in the market and forward contracts are now being closed at higher rates than they used to be. So a little bit of cost inflation, but I think the predominant trend is more optimism, whereas the cost inflation has yet to make itself completely visible. I will also kind of add to that that this is predominantly why we have been so focused on productivity as a driving theme in our improvement program. It's mostly focusing on maximizing the utilization of the assets under our control and not necessarily focusing that much on the unit cost themselves. Yes. And then Alvin Thomas has a few questions. Given the addition and repair of production wells and other favorable operational impacts, should second quarter production be higher than Q1? That's the first question. Secondly, how have you been able to add new exploration wells, but keep the budget the same? What are your views on the rig market and cost environment in Norway? I guess that has been covered. And third question, you've done some M and A in the Frosk area. Should we infer that the results from this discovery led to this M and A? And if successful in your upcoming wells here, will this revise your development concept? Okay. Lots of questions. Let me see if I can remember all of them. Well, first, when it comes to exploration targets, remember that we pushed 2 wells in the Barents Sea from 2018 to 2019 to make sure that we can prepare and plan the wells safely. So that's one measure that allows the budget to stay the same. In addition, we also see more efficient drilling operations, which is about half of the exploration cost, which allow us to enter more wells into the same budget. So in sum, those are the 2 key issues that make us rather confident that our original guiding on expects will remain stable for 2018. On the BD question in relation to that, I mean, we've been active on business development in that area around Alvheim since 2014 when we acquired Marathon Norway. So for us, that's just business as usual being active around the number one core area for the said reasons that Karl walked through earlier today. And this is not singular for the Alfheim area. We've also tried to be active in all the regions that we where we have an operating interest. There was one more question. The first question again. That was given the addition and repair of production wells and other favorable operational impacts, should Q2 production be higher than Q1? I think we'll as Alexander stated previously, we remain stable in our guidance and production. So I think that's where I'll leave it when it comes to production. We truly believe that the guidance we gave out in January is a good representation for the production overall in 2018. Okay. That concludes the questions that we have got from the web audience. Thank you and have a safe journey home for those who are here and a good day to those on the web. That doesn't mean it's not a good day to those who are here. Thank you, guys.