Great. It's good to see you all here at Fornebuporten, 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 first quarter 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 equivalents. 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. I'll change the slides. 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, Alexander will go through them in detail as usual. We continue to generate strong cash flow, the free cash flow in the quarter amounted to $222 million. We also successfully issued a new $500 million bond in the quarter with longer duration and lower interest than in the past. We increased the quarterly dividend to $0.31 per share in the quarter. For 2018 in total, we plan to pay $450 million in dividends, the ambition is to grow this amount by about $100 million 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 Frosk discovery, we have secured additional rig capacity to speed up exploration activity around Alvheim 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, I will spend some time on this towards the end of the presentation. Before we dive into the operation and the projects, Alexander will go through the financial statements for the first quarter, Alexander, the floor is yours.
Thank you, Karl. Good morning to everyone. As always, I will take you through the income statement, balance sheet, cash flow for the quarter. This is the first quarter where we are showing the combined operations after the acquisition of Hess Norge. This obviously impacts the financial statements, we are showing both record-high revenues and net income this quarter. Starting with the P&L for the quarter. We recorded income of $890 million based on a production of 158,600 barrels of oil equivalents per day, we realized an oil price of $69.15 in the quarter. We had production expense of $173 million, an increase of $26 million. Production cost was $12.10 per barrel. In the other area, we had OpEx per barrel of $6. Ivar Aasen was $10. Valhall/Hod, $18.5. Skarv at $10.8. Finally, Ula/Tambar at $46.2. Other OpEx amounted to $3.6 million this quarter.
We expensed exploration costs in the first quarter of $55 million. This includes dry well expense of $14 million stemming from the three wells on Kvitungen, Raudosen, and Husa referred. We had seismic acquisitions which also amounted to $14 million. Field evaluation costs for yet another $14 million. Area fees and other exploration costs of $13 million. EBITDA came in at $658 million for the quarter. Depreciation was $185 million. This equals $13 per barrel. This is down from $14.7 in the fourth quarter last year. As of December 31st, 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 million in the quarter, with the breakdown of these items shown in note six to the financial statements. Profit before taxes was $425 million, taxes amounted to $264 million. This gives a tax rate of 62%, which is lower than in the previous quarter. Again, the changes in US dollar NOK FX rates impact our Norwegian tax returns. The strengthening of the NOK against the dollar from 8.2 at year-end to 7.84 lowered the tax expense this quarter. Payable tax was $215 million, the change in deferred taxes was $49 million. We had a net profit of $161 million this quarter. 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 $1.9 billion and $2 billion respectively. Net of depreciation, the total PP&E balance increased to $5.7 billion in the quarter. The net increase of $82 million came as a result of additions of $251 million, net of depreciations of $169 million. Looking at the book value now of our six hubs, our four assets, Valhall Hod, Alvheim, Ivar Aasen, Johan Sverdrup, each now have a book value of approximately $1.2 billion. Receivables and other assets were $764 million at the end of the quarter, a small decrease from the previous quarter of $11 million. This balance was increased with accrued income from sale of petroleum products, $141 million, offset by lower underlift of $40 million, reduced another $119 million related to other receivables from licenses.
The short-term tax receivable of $1.67 billion at the end of the first quarter relates to the tax loss from Hess Norge. The increase of $80 million from the last quarter relates primarily to the currency impact of a strengthening NOK versus the US 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 million at the end of the quarter. We had total assets amounting to $12 billion at March 31st, which is approximately the same as three months ago. On the opposite side of the balance sheet, we now have equity of $3.1 billion. That's an increase of $121 million from the previous quarter.
This reflects the net profit for the period at $161 million. We had a currency translation adjustment through the OCI, which I mentioned, of $73 million. This was reduced for the dividend payments in the quarter of $112.5 million. Other provisions for liabilities stood at $2.96 billion. That's a small increase, yes, from the previous quarter. Deferred taxes amounted to about $1.4 billion. That's reflecting an increase of about $50 million from the previous quarter. Book value of our net interest-bearing debt was $3 billion at quarter end. We now have three long-term bonds for a total of $1.1 billion, and our bank debt is now a little under $2 billion. The short-term bridge facility related to the Hess acquisition amounts to $1.5 billion, while the drawings on the RBL amounted to $460 million. Tax payable was $554 million at the end of the quarter.
Of this, accruals for uncertain tax positions amounted to $217 million. The 2017 net tax payable was $112 million, 2018 tax payable made up the remaining balance of $225 million. Other current liabilities decreased from $1 billion to $923 million in a 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 million this quarter. Cash flows from investing activities totaled $378 million. That's including the capitalized exploration expense related to the Frosk discovery that Karl will come back to in a minute. In addition, investments in fixed assets were in line with previous quarter, summing up to $257 million, where Johan Sverdrup accounted for $94 million, Valhall Hod, $73 million, and Ula Tambar of $40 million.
We also recorded decommissioning payments of $82 million, mainly related to the Maersk Invincible rig running P&A activities at Valhall. Thus, free cash flow was $222 million in the quarter. When it comes to financing activities, we raised $500 million in a new unsecured bond issuance. This exercise was completed in March, it's a 7-year bond, callable after three years, it has a coupon of 5.625%. We subsequently repaid $815 million on the RBL. We now have $3.5 billion in committed undrawn capacity on our $4 billion RBL facility. In addition, we paid out $112.5 million in dividends during the quarter. At the end of the quarter, our cash balance was $38 million and book value of net interest-bearing debt, $3 billion, and net debt over EBITDA is down to 1.3 times.
The $1.5 billion bridge loan is included here in the net debt figure, whilst the $1.6 billion tax receivable related to the Hess acquisition and the tax loss there is not included. We are still expecting to see a disbursement of this tax loss in the second half of 2018. Finally, our guidance for 2018. Performance in the first quarter has been in line with expectations. The run rate on CapEx is lower in the first quarter, 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 $1.3 billion for the entire year. For the other four parameters, OpEx, production cost, decom costs, we are roughly in line with guidance. In summary, we are not making any changes to our guidance from January.
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. 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 three field development projects that are currently ongoing, which I'll come back to. The Valhall Flank West, the Ærfugl in the Skarv 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 this project, but also extending lifetime in our current assets. 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, I will not necessarily touch on every one of them, simply because the time is not sufficient. 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 in 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 Viper-Kobra, infill wells like Volund Infill, and most recently, the two new wells in the Boa reservoir. Looking forward, we are this year planning to drill yet more infill wells. Infill drilling on Kameleon and appraisal drilling on the Gekko reservoir.
The Skogul development, which is also a tie-back to Alvheim, has been approved by the authorities, the project is moving ahead as planned. Perhaps the most exciting development of Alvheim in this quarter has been the Frosk discovery. Frosk is located in the Bøyla license, close to existing infrastructure, in particular, the Bøyla manifold. The Frosk discovery in itself was significantly higher than our pre-drill estimates. This is obviously a very positive surprise in itself. The discovery has also increased the attractiveness of other exploration targets in the area. In order to select the most optimal development in the area, we are therefore securing new and additional rig capacity. This time the Scarabeo 8, which will be used to drill two to three wells in the area on prospects named Rumpetroll and Froskelår. I apologize for the names for the non-Norwegians out there.
We have expanded our exploration program for 2018. 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 Frosk area comes in addition to the JK project, which is located just north of Johan Sverdrup in license PL916. This is a license which we were awarded in January in the latest Aker licensing round. I am very pleased to see that we are able to plan and drill an exploration well within one year after the license was awarded. We have also added an exploration target in Slangførhøyden, this time in license 915, which is yet another license awarded back in January.
This exploration target is located near Hans and will be drilled as an extension to the already planned Hans appraisal well. Two 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 utilizations in the Aker BP portfolio. We believe this to be an extremely attractive exploration portfolio and are excited about the exploration projects on the Norwegian continental shelf going forward. Let me move on to Valhall. At Valhall, the Flank West development project was approved by the authorities in March. 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 alliance and expect to see more positive effects from this way of working together with our vendors. We have also made the investment decision on the Flank North water injection project, which is expected to add yet another eight million barrels of gross reserves through increased recovery in the northern part of Valhall. The drilling will start in Q4 this year. The water injection is expected to start in Q2 2019 when pipelines and risers have been installed. The Maersk Invincible rig will execute the drilling as it commences or completes its P&A program on the Valhall field center expected in Q4 this year. The resource potential 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 Skarv. The Ærfugl PDO was approved by the authorities in April. The project is now well underway. The main contracts for subsea installation and production systems have been awarded. We are now working with technology qualification for the two key technologies, which are planned to be implemented on Ærfugl. One of these technologies is the electrical heated trace pipe-in-pipe, which prevents hydrate formation and hence allow for longer distance tiebacks 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 Ærfugl project are extremely robust with a break-even oil price of $18.50 per barrel. We keep on chasing further upside potential, both above and below the surface.
In Q1, we drilled an appraisal well on Alfhild as a part of the Kvitungen/Tumler exploration well. The exploration target was unfortunately dry, but the appraisal results were positive and could potentially lead to a positive revision of the Alfhild reserves. We are also looking into the possibilities of debottlenecking the Skarv FPSO, which could enable an acceleration of the second phase of the Alfhild development. While we're talking about Alfhild, it's also worth mentioning that we have now successfully repaired the two wells that were shut in last year due to Christmas tree issues. At Ula, we have started production from the new Tambar 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.
When we finalize gas lift and modification in the turnaround later this year, Tambar will be ready for another 10 more years of production life. Tambar is an exciting story in itself. This was a field that was planned to be decommissioned not that long ago. After joining forces with BP, we turned around quickly and started drilling less than one year after the completion of the transaction. In total, the drilling on the Tambar reservoir has added 26 million barrels of oil equivalents on a gross basis. This is a typical example of the investment hypothesis of Aker BP when it comes to developing more reserves on our production hubs. The Ula tie-in project is also moving forward nicely and remains on track for production start next summer. Ula is important for three main reasons. One, it will provide additional production volumes.
It will contribute to lowering the OpEx per barrel at Ula in addition to the recent Tambar volumes, and it will provide more injection gas to Ula and thereby increase WAG capacity. Finally, while on Tambar, I'd like to say a few words about the fatal accident on Maersk Interceptor on 7th of December. The Petroleum Safety Authority has concluded its investigation on the accident, and the report is available on the PSA webpages. The report concludes that a raw water pump fell to sea as a consequence of a failure on a flat braided sling used in the lifting operation. The lifting operation was a part of the installation of a raw water pump, and the incident resulted in one fatality and one person seriously injured. Both Aker BP and Maersk Drilling support the findings of the PSA report, which are consistent with our internal investigations.
In addition, Maersk 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 Ivar Aasen. Ivar Aasen continues to perform well with a plant availability or uptime of 98% in the first quarter. 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 Ivar Aasen with power, processing, and export services. We continue to roll out digital operations on a digital operation model at Ivar Aasen, which among other things, will involve an onshore control room to be operational later this year.
We are extremely happy with the progress and excited about the results we see in the Ivar Aasen digital operations. We have started drilling again at Ivar Aasen. First, two new water injectors, which will contribute to continued high productivity from the field. When we have completed the water injector, the rig will move on to an appraisal well on the Hans discovery and also test a new exploration target called Slangførhøyda, which I talked about previously. Slangførhøyda 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 thousand 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 break-even oil price for phase 1 to be below $15 per barrel and below $20 for the full field development. Last, but by no mean least, the NOAKA project. The NOAKA project in many ways resembles the Alvheim project in as much as it's a series of discoveries, but without infrastructure close by. We have learned through the successful implementation of infrastructure in the Alvheim 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 Alvheim, 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, 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 the shape of unmanned installations or subsea installations. This solution will cater for field development of all discoveries in the area on a 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, with a firm ambition, with full electrification, zero emissions, and power from shore in addition to offshore wind, that could provide the first energy positive field development on the Norwegian Continental Shelf. In addition, by utilizing the positive experience from the Ivar Aasen digitalization project, we could also foresee high degrees of optimization, onshore control rooms, and possibly also new business models for the project execution. Finally, by including the alliance effects, we are looking at the ambition of making the NOAKA project a hallmark project in terms of cost per tons and execution schedule. In total, we believe NOAKA could really be the field of the future with zero 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 criterias of $35 per barrel. We really do believe that the NOAKA BP solution could be a role model for Norwegian field developments of the future. 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 break even, in addition to executing on the $18 portfolio we are already executing in. Then finally, continue to maximize recovery from our existing resource base and pursue selective inorganic growth opportunities. Yes, one more thing.
As you may have seen in the news today, we are pleased to welcome Kjetil Digre , which was previously the head of the Johan Sverdrup field development, as the new Senior Vice President of Operations in Aker BP. With that, I open for questions and ask Alexander to come back on stage.
Ted Anilis, RBM Markets. Three questions, actually. First on Sverdrup. Positive to see the developments, but could you indicate how much contingency there is left in the current CapEx assessment for phase 1? Second question on Tambar. 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? My last question is, I asked it before, but are you looking at opportunities outside Norway or do you still stick to only 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 the remaining construction scope. I'll leave it to the operator to comment on the exact numbers. Then your question on Tambar. The production on Tambar is now in fact constrained by the 8-inch pipeline from Tambar 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 Tambar at the moment. 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 NOAKA project. Question from the web, maybe.
Yeah. It's a question from Alvin Thomas in Exane BNP. At NOAKA, what are the next steps to achieve concept selection and FID? Will Statoil agree to the concept?
Brilliant question. Well, there is an already established 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. Statoil can comment on whether or not they will agree themselves.
Harry Sidomunis Rogers. Just to follow up on your last answer about NOAKA concept. In terms of the total CapEx, is your concept more expensive than Statoil's?
I think that depends a lot on who you will be asking. Obviously, the aim for us is to maximize the resource utilization in the area and to ensure that the total investment will stay within our criteria of $35 per barrel. As you've seen from our other investment opportunities in the existing production hubs, Aker BP does not necessarily shy away from investing if we see that there is good business opportunities that will increase the value of our portfolio and meet our investment targets.
There are some further questions on NOAKA from James Hosie 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. It's our view that the PQ concept is better than the UPP times two, both in terms of robustness, ability to face in new reservoirs and also managing reservoir complications or well chemistry.
Nikki Kuzmanov from Jefferies. I have a couple of questions. First, on Ivar Aasen, the platform efficiency in first quarter was 98%, and so was Edvard Grieg's. Could you maybe talk a bit more about how SAGE has impacted net efficiency down to 89%? The second question on Ivar Aasen, plateau duration expected currently post the two water injectors, the Husa appraisal and the Slangførhøyden exploration all in 2018. We obviously want some color.
Yeah
length of the plateau.
When it comes to production efficiency, remember production efficiency is a volume over installed capacity measure. That means that is in fact possible, as is the case here, that two installations have rather high uptime, but that not necessarily the production efficiency follows suit. The issue here is twofold. The first one is the availability to export gas across SAGE, and the second is the third-party services provided by Edvard Grieg in terms of power, production capacity, in terms of separation and also return of gas lift gas. In total, the sum 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.
The second question, well, I think I'll wait until we see the results of, in particular, the Hans appraisal well before I guide on the duration of the plateau. Obviously, there are many factors that are now being investigated. Currently, we see no reason to deviate from our previous plans.
Yeah. Nikki 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?
Obviously when we announced the dividend levels and the ambition there, that was at the point in time when the oil price was lower than $75. Any changes to that is something we'll just assess on an ongoing basis.
Johan Scharer from Société Générale has a question. Would you mind providing more color on the expected scheduling of CapEx during the rest of this year?
It was a bit lower in the first quarter than averaging out for the year. We do expect that in the second half of the year to pick up a bit. In particular, when it comes to some of the ongoing and also the larger projects at Valhall. Still within the full budget for the year, but ramping up probably in the second half of the year.
Marius Lorentzen from E24. I have questions about Alvheim and Skarv. On Alvheim you talked about two unplanned shutdowns. Has this been resolved, and could it affect production moving forward in the year? The second question is about Skarv. In your Q4 report, you mentioned the three wells that you had to take down. Now you have two 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?
The turnaround, the discussions on maintenance activities on Alvheim is pretty much as planned. 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. This is all very much inside our planning for maintenance activities on Alvheim. Then on Skarv, yes, you are right, there were three wells that we took out. Two has been reinstated. The third one we lifted at 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 question. Can we get an update on the $1.5 billion tax receivable acquired as part of the Hess transaction, and when is it expected to be received?
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 old taxation office. We do still expect that to be dispersed in the second half of 2018. July at the earliest, or it could be in November, December as well. 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. 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. 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?
Production cost, well, we still believe on an average for the year of $12. We did have some maintenance, and Carlo talked about the Skarv Christmas trees as well. Some additional cost there is flowing through in the first quarter. Average still for $13, and some maintenance in the second half of the year as well. It might vary a bit, but still, it should be around $12 on an average. When it comes to FX, we've hedged some of this exposure relating to the NOK 12 billion tax loss that we expect to see dispersed. We've hedged somewhat a combination of forward sales for a little less than a USD NOK eight, and also some utilization of options as well. We've hedged some of that exposure as well.
Finally, the last question regarding M&A. We have a large degree of organic growth opportunities and are pursuing a lot of those. That's actually nothing new to Aker 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&A. The competition on the Norwegian Continental Shelf has gone up. The opportunities may not be that many that they used to be about a year and a half ago. We're still seeing significant and interesting M&A targets being presented on the Norwegian Continental Shelf.
We have a follow-up question from Nikki on NOAKA. Any plans for changes in partnership equity if Statoil does not agree with Aker BP/government proposed development solution?
I think that's something we'll have to come back to when we are more mature in our discussion.
We have a question from Karl Fredrik Schjøtt-Pedersen in ABG. Do you see signs of cost inflation? If so, where would that be? Personnel or any specific services?
If by cost inflation, Karl Fredrik 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 semi-submersible drilling units, 5th to 6th generation. We see an upward trend in the market, forward contracts are now being closed at higher rates than they used to be. 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 would also add to that this is predominantly why we have been so focused on productivity as a driving theme in our improvement program. It is mostly focusing on maximizing the utilization of the assets under our control, not necessarily focusing that much on the unit cost themselves.
Yes. 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 first quarter? That is 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. Third question, you have done some M&A in the Frosk area. Should we infer that the results from this discovery led to this M&A? 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. First, when it comes to exploration targets, remember that we pushed two wells in the Barents Sea from 2018 to 2019 to make sure that we can prepare and plan the wells safely. That is 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. In sum, those are the two key issues that make us rather confident that our original guiding on expense will remain stable for 2018.
On the BD question in related to that, we've been active on business development in that area around Alvheim since 2014 when we acquired Marathon Norway. For us, that's just business as usual, being active around the number 1 core area for the said reasons that Carlo walked through earlier today.
This is not singular for the Alvheim area. We've also tried to be active in all the regions where we have an operating interest. There was one more question.
What was the first question again?
That was given the addition and repair of production wells and other favorable operational impacts, should second quarter production be higher than first quarter?
I think as Alexander stated previously, we remain stable in our guidance and production. 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, 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.