In the first quarter of 2017, it seems like the activity program is continually ramping up. Now, production in the first quarter was up about 15% compared to the previous quarter to 145,000 barrels of oil equivalents per day. The main contributors to this performance was solid production from the Alvheim area and ramp-up ahead of expectation on Ivar Aasen. Now, first quarter EBITDA landed at US $487 million, equivalent to an earnings of about $0.20 per share. The free cash flow in the quarter was $168 million or roughly $0.50 per share. The board has resolved to disperse a quarterly dividend of NOK 62.5, which is equivalent to NOK 0.185 per share, which will be paid out in May. This is in line with the previously communicated strategy of an annual dividend of $250 million.
Now, on operations, I must say that both operations and projects are progressing very well. Ivar Aasen ramp-up is ahead of expectations. The redevelopment of Tambar has recently been sanctioned, we have passed concept selection and are on track for PDO submission for Snadd, which is a tie-back to Skarv, for the Valhall Flank West, and for Storklakken later this year. Finally, in February, the license announced an oil discovery at Filicudi in the Barents Sea. I will now, as usual, turn over to Alexander to take you through the financials.
Thank you, Karl. Good morning, everyone. As usual, I will take you through the income statement, the balance sheet, and the cash flows in the quarter. We recorded petroleum revenues of NOK 647 million this quarter on a production of 145,300 per day. We realized an oil price of $54 per barre l, we had a gas price of NOK 0.21 per standard cubic meter. Out of the NOK 647 million in revenues, NOK 547 of this stems from oil sales, NOK 94 million from gas, six million in tariff income. Production costs were NOK 121 million this quarter. This equals to $9.20 per barrel , and this includes a shipping and handling costs of $2.70. When looking at the various hubs this quarter, we have production costs at Alvheim for NOK 4.30 per barrel. We have Ivar Aasen of around NOK 9 per barrel.
We have Skarv at around NOK 10 per barrel, Valhall/Hod at NOK 17 per barrel. Other OPEX, which includes costs such as preparations for operations at Ivar Aasen and corporate overhead costs, amounted to NOK 8 this quarter or NOK 0.60 per barrel. We expensed some exploration costs this quarter, NOK 30 million, this reflects acquisitions of seismic for NOK 10. We had dry hole costs and area fees collectively for NOK 6 million. This includes the dry Tonje well. We had other exploration expenses, including field evaluation costs of NOK 14 million. We had EBITDA come in at NOK 487 million.
Depreciation was NOK 184 million this quarter. This equals around NOK 14 per barrel in line with previous quarter. Also in this quarter, we recorded an impairment of NOK 30 million. This mainly relates to impairment of technical goodwill booked to Valhall/Hod and Ula-Tambar. EBIT was NOK 273 million.
We had net financial items of a negative NOK 47 million in the quarter. We had accretion expenses of NOK 32 million, while net interest expenses were NOK 30 million. This is around NOK 10 million higher than in previous quarters. This is perhaps not a surprise as we, for accounting purposes, are capitalizing less interest in the first quarter compared to previous quarters since Ivar Aasen started production at the end of last year. Since the U.S. dollar NOK FX rate has been unusually stable during this quarter, we have limited currency effects or movements in the valuation of our FX derivatives. Profit before tax was NOK 227 million. The tax expense for the period was NOK 158 million. This equals a tax rate of around 70%. Out of this, tax payable estimated at NOK 39 million, while change in deferred taxes was NOK 120 million.
Net profit for the quarter therefore was NOK 69 million or NOK 0.20 per share. Our balance sheet has not changed materially during the first quarter of 2017. At the end of the quarter, we had goodwill booked at NOK 1.82 billion. This is just a net decrease of NOK 30 million due to the aforementioned impairments of technical goodwill. Other intangible assets, NOK 1.66 billion. This is also just a net decrease of NOK 64 million from the previous quarter. This decrease is mainly related to depreciation of software and the fact that a concept selection was passed at Storhøggen, which means that we have moved all costs booked on Storhøggen into PP&E. We had capitalized some exploration on Gohta and Filicudi, which partly offsets that effect. Moving to PP&E, that balance increased NOK 158 million during the quarter.
The most significant investments this quarter were Johan Sverdrup of around NOK 100 million, Ivar Aasen at NOK 45 million, and we spent around NOK 40 million in the Alvheim area. Receivables and other assets were NOK 678 million at the end of the quarter. This is a decrease of about NOK 44 million from the previous quarter. This decrease is mainly due to timing on payments on petroleum sales, and this gives a decrease in accounts receivable this quarter. We recorded a short-term tax receivable of NOK 395 million. On the other side of the balance sheet, we have an accrual for tax payable of NOK 120 million. The receivable relates to an expected payout of tax losses carried forward in BP Norge once petroleum activities have ceased in that legal entity and also an exploration refund for 2016.
The accrued tax payable on the equities and liability side is related to all tax cases and payable tax recorded during the quarter. Cash and cash equivalents were NOK 183 million at the end of the quarter. Quickly on the other side of the balance sheet, equity NOK 2.45 billion at the end of the quarter, in line with previous quarters, just reflecting the net profits, but also being reduced with the dividend paid in the quarter. The book equity is stable at 26%. Other provisions for liabilities were NOK 2.33 billion at the end of March. This is also in line with previous quarters. Deferred taxes increased with NOK 119 million during the quarter. Book value of our interest-bearing debt was NOK 2.51 billion at the end of the quarter.
This is made up of $2 billion on the RBL and $513 million on the DETNOR02 and DETNOR03 bonds. Other current liabilities decreased to $760 million at the end of the quarter. This reflects decrease in accounts payable, but partially offset by an increase in abandonment liabilities and current liabilities. On the back of a strong production this quarter, we generated cash flows from operations of $438 million. Cash flow from investing activities was $270 million. This reflects investments in fixed assets of $232 million. We have investments in intangible assets of $30 million, and we had decommissioning expenses of $8 million. Thus, free cash flow from the quarter was $168 million. We repaid around $35 million on the RBL during the quarter for cash management purposes, and we paid out $62.5 million in dividends.
The end of March cash balance was $183 million, and we had net interest-bearing debt of $2.33 billion, down almost $100 million from the end of last year. At the end of the quarter, we had net debt over EBITDAX decrease from 1.6x at the end of the year to 1.3x at the end of this quarter. We also had available liquidity of $2.6 billion, which provides us with ample financial flexibility going forward. The board has declared a dividend to be paid out in May, $62.5 million again, and this implies an annualized dividend yield of around 4.5%. Finally, a look at the full-year guidance for 2017. We make no changes to the guiding parameters that we provided at the Capital Markets Day back in January.
CapEx for the first quarter amounted to NOK 214 million, whereas we expect the total spend this year still to be in the NOK 900 million-NOK 915 million range. Cash spent on exploration was at NOK 59 million in the quarter, with a run rate below our full-year guidance at NOK 280 million-NOK 300 million. This is driven by the fact that we have a higher equity in the wells planned during summer in the NOAKA area. Despite the high production in the first quarter, we keep the full-year guidance of 128,000-135,000 barrels per day. Q1 production was partially driven by high production from Viper-Kobra, as well as a strong ramp-up at Ivar Aasen. During this year, however, we expect a decrease in production from Viper-Kobra, which will likely bring down the production from the greater Alvheim area compared to the first quarter.
There is also planned maintenance at Valhall and Skarv in the third quarter. Therefore, we make no changes to the full-year production guidance at this point. Based on the high Q1 2017 production, we do see the possibility of production coming in towards the high end of the guided range. Production cost was $9.20 per barrel in the first quarter, below the $11 we guided. As a large portion of the production costs are fixed, the lower cost per barrel was driven by the high volumes produced in the quarter and the fact that we did not have any maintenance work carried out this quarter. As for decommissioning costs, cash spend was only NOK 8 million this quarter.
Also here, we are keeping our guided range of NOK 100 million-NOK 110 million for the full year as we are about to take over the Maersk Invincible rig, which will then conduct P&A activities at Valhall. That concludes my financial section, and Karl will walk you through the operational section.
Thank you, Alexander. I'll walk you through the operations and the assets and the production and the projects going forward and try to provide some color to both the activity program and the production set that we've seen so far. If we start with the oil and gas production in the quarter, as this graph illustrates, we've had a significant increase in production from the previous quarter, approximately 15%, to a total production of 145,000 barrels of oil equivalents per day. Predominantly, this production increase over the expectation is driven by extremely strong production from Viper-Kobra and ramp-up of Ivar Aasen ahead of expectations. The Viper-Kobra story is all about rapid decision-making and turnaround capabilities.
As you may recall, these are tie-ins to the Alvheim field where we changed the well concept, extended one well, and changed one well from a single lateral to a dual lateral. The last design change process was done in a week. That ability has had a tremendous impact on the production in 2017 in the first quarter and underlines our focus strategically on execution capabilities. The oil was sold at $54 per barrel, and gas was sold at an average price of $0.22 per standard cubic meter in the first quarter. I'm actually also quite pleased to see that we are continuing to deliver high uptime across our assets, supporting the strong production this quarter. I'm particularly proud of the operations team alongside our many vendors who are working diligently to execute an ever-growing activity program while maintaining high uptime and high production efficiency.
This is at the core of our execution strategy. Moving into the assets and starting with the Alvheim area. The Alvheim FPSO and the area, in particular, continues to deliver stable and high production, particularly the contribution from Viper-Kobra, as previously stated. Was a big part of the increased production in this quarter compared to the previous quarter. Transocean Arctic is currently drilling infill wells at Valhall, and the team has completed the first well and are now drilling the second well at trilateral once again. We expect drilling operations to continue towards the summer, and then subsequent offshore diving and hookup campaign to be able to put the two wells in production towards the back end of the summer. The results of the drilling operations at Alvheim so far is in line with our expectations.
Following the completion of the Valhall wells, Transocean Arctic will move on to drill the West Valhall exploration well before continuing the infill campaign with the two Boa wells. You may recall that we drilled a well called Boa Come North with two targets being vectored in by pilots. These two targets are now being drilled out, again, underlying our ability to turn around quickly and implement changes to increase production. Our subsurface team is also continuing to mature new drilling opportunities in the Alvheim area to fill the FPSO in the years to come, and the data collection strategy in the area has paid off its dividends and are continuing to do so. In the surrounding area, the Storhalken project passed concept selection in March, and we are further maturing this project to a PDO towards the end of 2017.
Storhalken will be developed as a subsea tieback to Alvheim via the Vilje template with expected first oil in 2020. In March, Aker BP sold 35% of its own interest in Storhalken, which was previously 100%, taking us down to 65% and in line with our ownership on Alvheim. Moving into Ivar Aasen, you've heard me talk about Ivar Aasen in just about every quarterly presentation I've had so far. It's with extreme pleasure, I can say that we have started up Ivar Aasen and production performance is strong. Uptime is extremely good. Following the Ivar Aasen startup at Christmas Eve, we have seen continued strong performance in operations. The current production efficiency for the first quarter landed at 91%, and if we exclude downtime related to issues with third parties, we're seeing a production efficiency of 96% in the first quarter of production.
In my mind, that's a pretty reasonable result. The production ramp-up has broadly been in line with the delivery agreement with Edvard Grieg, and therefore ahead of our expectations, which was more dominated by lower production efficiency in the early stages of the ramp-up. Remaining project scope will include commissioning work on water injection, which is now about to be completed, but the facility as such is handed over to operations. In March, Maersk Interceptor commenced drilling of the remaining drilling scope following a period where it's functioning as an accommodation unit for the commissioning personnel. The remaining scope consists of five wells, including completion of the West Cable oil producer. The drilling team at Ivar Aasen continues to impress. In April, the drilling team set a new record of 17,242 meters drilled in the 12 and a quarter-inch section in 24 hours. That's more than a meter a minute.
That's quite a significant achievement. The whole section was completed in less than a week, underlying strong well operation performance on behalf of the Maersk Interceptor team. Johan Sverdrup is progressing according to plan. Platform construction is ongoing and progressing well. The pre-drilling campaign is ahead of schedule with drilling of the first water injectors ongoing. During the first quarter, the cost estimates for both phase I and the full field development continued to come down with break-even prices below $20 and $25 respectively. Concept selection of phase II was improved in March, and the project is on track to deliver the phase II PDO at the second half of 2018. Moving on to assets that we're currently working on to release the upsides. At Valhall, we are moving ahead with several projects to increase both production and recovery in line with our improvement strategy.
At Valhall Flank West, the project has passed concept selection and will be developed as an unmanned wellhead platform with 12 well slots tied back to the Valhall field center. PDO is planned towards the end of 2017, with production expected to start up in 2020. Valhall North flank water injection is being accelerated currently towards a planned concept selection in the second quarter, and we're currently carrying out data acquisition activities on that project. Following a two-year drilling break at Valhall, we have just started up the Valhall IP drilling program with seven wells to be drilled in the first phase, of which three is expected to be drilled and completed in 2017. The first well has just reached the reservoir and is significantly ahead of schedule.
The Maersk Invincible jackup has arrived in Norway, and we expect that the rig will be mobilized to the field shortly to commence operations and continue the P&A campaign on the drilling platform at Valhall. Now, moving on to the Ula-Tambar complex. The Tambar redevelopment has been improved and production increased at Ula-Tambar in the first quarter compared to the fourth quarter last year. The main drivers for the increased production was increased water alternating gas. We're injecting gas and water alternating to increase recovery at Ula, and then two wells rather than one available for production at Tambar. The recently approved redevelopment project of Tambar consists of drilling of two new infill wells and installation of gas lift at the existing wells. The license target an expectation of 27 million barrels in gross additional recovery reserves over the Tambar license.
The drilling will be utilizing the Maersk Interceptor and is expected to commence in fourth quarter this year, with first oil expected in first quarter 2018. The break-even price for this project is estimated to be below $20 per barrel, and with first oil already in 2018, the payback for this project is short. Again, in line with our strategy to execute and improve the assets that we're working on. Now, moving on to the north, there's another value-increasing project ongoing, which is the Snadd tieback to the Skarv field. The production performance at Skarv in the quarter has been solid with a production efficiency of 98% in the quarter, and therefore increased production compared to the previous quarter. The partnership has agreed to collect additional data for this area and shoot new 4D seismic during the summer.
The Snadd project, which I initially started on, is progressing according to plan, with concept selection being completed in March and continues to be matured towards the PDO in the fourth quarter of 2017. The development consists of six subsea wells tied back to the Skarv FPSO and first gas is expected in 2020. As presented at our Capital Markets Day in January, we have a quite extensive exploration program for 2017, and so far, we have received the results for Filicudi in the Barents Sea, which was a discovery, and I will come back to Filicudi for more detail shortly. In addition, Statoil drilled Tonje prospect in the Johan Sverdrup area, which was evaluated to be non-commercial. In addition, the appraisal drilling at Gohta is currently ongoing, and we expect results shortly.
We are not only investing in exploration wells, we are also investing heavily in other data acquisition activities. I'll draw your attention to recent seismic activities. Yesterday, we announced that we had entered into a two plus two years frame agreement with WesternGeco for 4D seismic data collection. Four surveys will be collected this year with Alvheim, Bøyla, Skarv, Snadd, and Ula being the focal points. The contract also covers 3D data collection should that be required. In addition, we have acquired 3D seismic from PGS and TGS covering 12,000 and 7,000 sq km respectively. Also please note that we have now put a name to the wells we plan to drill in the north of Alvheim area. In the third quarter, we are planning to drill the Nordfjellet prospect and then a subsequent sidetrack to the Delta discovery in Production Licence 442.
The Nordfjellet prospect, as it's shown on the slide, is evaluated as a standalone basis. However, the prospect may be in communication with other prospects in the area that will result in an additional upside. The goal of the appraising at Delta is to reduce uncertainty and influence mean volumes and is a part of the data acquisition program moving forward to DG2 in the NOA area towards the back end of 2017. In February, we announced that together with Lundin as an operator, we had made a discovery in the Filicudi prospect in the Barents Sea. The well encountered sandstone of 129 meters in vertical thickness in Jurassic and Triassic targets with high quality. The gross estimate is currently assessed to be in the range of 35-100 million barrels. Probably the most interesting is that this discovery de-risks other prospects in the 533 license.
Prospects with a gross prospective unrisked resource potential of up to 700 million barrels. We are currently evaluating whether to drill up to two additional targets this year, named Hufsa and Hurri. I apologize for the names. These prospects will continue to work and in our mind have been de-risked by the previous Filicudi discovery. We continue to work the improvement program and continue to follow our strategy of reorganizing the value chain, focusing on alliances as key measure to increase flow efficiency and reduce waste. As you may recall, we previously engaged in an alliance on subsea with Subsea 7 and Aker Solutions. We are continuing this strategy now with the long-term frame agreements with key suppliers of engineering services, construction, [electro IT] control room systems, as well as transport and installation for fixed facilities offshore, and thus complementing the same strategy on subsea.
Duration is fixed at six years with options to extend for four more years, so a total capability of 10 years. The intent of the frame agreement is that Aker BP in the company's field development projects will develop and execute a much more integrated project delivery model. We call this a platform alliance for each project. The Valhall license has approved already the use of the alliance model for the Valhall West Flank development. Again, this is fully in line with Aker BP strategy to increase flow efficiency and reduce cost, cut bureaucracy, and increase quality. You may also recall that we previously stated a target to reduce engineering hours per ton by 50% and reduce execution time by 25%.
This applies about a reduction of about 190 man-years for a 5,000-ton topside, which is approximately what we target at the Valhall Flank West, thus giving you an idea of the value creation potential in this kind of process alone. Now, moving on to summary. Our focus and strategy remain firm. We are continuing to work on the execution, our improvement, and our growth agenda, as I think you can now see, as we're moving these strategies into tangible activities. We will continue to mature and subsequently drill new infill opportunities at the Alvheim area. We will continue to focus on safe and efficient ramp-up of production at Ivar Aasen and completion of the drilling program. We are going to continue the drilling program at Valhall and add new production over the next years, both from infill drilling and from new projects.
We are going to commence and continue P&A operations in Valhall as soon as we take over the Maersk Invincible rig. We are going to continue our strategy to collect data to support production enhancement operations wherever we can. We are going to collect four 4D surveys over Alvheim, Bøyla, Skarv and Snadd, Ula, and Valhall this year. We are going to continue to mature the projects and have been through Snadd, Valhall Flank West, Storklakken towards PDO in year-end. The quarterly dividend at $62.5 million or equivalent to $0.185 per share will be paid out in May. We are maintaining our strategy of $250 million as a floor for dividend until the commencement of production at Johan Sverdrup. We continue to assess the capital structure to improve flexibility and support further organic or inorganic growth.
Lastly, not to be mistaken, we are still pursuing M&A opportunities to enhance production and increase dividends going forward. That concludes our first quarter presentation of 2017. We'll now open up for questions. I ask Alexander to join me so he can take all the difficult ones.
Hi guys from ABG. I was just wondering if you could elaborate somewhat on the scope and the production shortfall in Q3 from the Valhall and Skarv maintenance.
Elaborate on the production. Well, both these areas will need turnaround at Q3 which means that we will shut down these assets for a period of time, impacting production. The drivers are a little bit different. In Valhall, we need to do brownfield work in order to tie in the West Flank project, and in Skarv, we are preparing for further maintenance and integrity work. That's why these two assets will be impacted production-wise in Q3.
In terms of, it's a full production shortfall during the entire quarter or for
No. It's a few days at both assets.
Okay. Yeah. Thanks.
Anders Holte from Danske Bank. Few questions, if I may. First, on the Filicudi discovery. Just wanted to know your thoughts on what you see as the key risk in that area and what you're looking for to advance the drilling plans further. Second, we have seen for quite some time now that you have your capital structure under review. Just wanted to see if we could get a bit more color on that. Lastly, there's been a lot of, I guess, meetings of, and opinions in the press on the M&A side. How you see the movements from the seller side, and if you also see an increase in deal availability or a decrease. Thank you.
Okay. Let's start with Filicudi. You want to do Filicudi, and I can do capital structure?
Yeah.
Okay. Let's start with the Filicudi discovery. I think the key assessment that we're doing now is which target to drill first, and where to place the wells. I think so far it's quite clear that there is oil migration into the area. We have proven reservoir quality both in Jurassic and Triassic. We are highly supportive of further drilling activity in the area. It's more a decision of operational planning from my perspective. Then maybe you can dive into capital structure.
Yeah. On capital structure, nothing has really changed from previous quarters. We're still sticking with the dividend level that we've said. We are just evaluating what the various options are, what's the right structure, mix between secured, unsecured debt. How do we factor in organic or inorganic opportunities and what's the right flexible structure for the company? We don't necessarily feel very rushed, and we're just taking the time that we feel is appropriate to assess these options.
A few comments maybe on the M&A side. There is definitely a lot of activity out there. I think previously we have been quite clear that the lenses which we view the M&A through is quite selective. To repeat, we are looking for more oil than we are looking for gas. We are looking for operational assets rather than non-op assets. Most importantly, we are looking for financial accretive transaction, increasing our production and our dividend levels. If you put that on a backdrop of where we are in terms of production level, production cost, and financial efficiency, it is quite clear that the number of these transactions would not make sense for Aker BP to do. Hence we have not done them. We will continue to work this space. We are continuing to be selective in the transactions we carry out.
Have I seen increased activity? I think the answer is generally yes. Probably more tire kicking than actual getting results. There has been a couple of transactions that I closed previously.
Halvor Nygaard from SEB. Following up a bit on the last questions. A month ago, we saw Point buying an asset package from Exxon. I am curious to hear your reflections on that specific deal. Was it the assets, the price, or the combination of the two that didn't make Aker BP the highest bidder on those?
Well, first of all, I am really happy that Point won. I am looking forward to the competition. I truly believe that the increased competition on the Norwegian Continental Shelf is a positive for all parties, and we really welcome that competition. There was a number of factors that made that acquisition not the right acquisition for Aker BP, but I will not dive into details on our assessment of neither the field nor the acquisition target.
All right. On Filicudi you said the Hufsa and Hurri have lower COS after the Filicudi discovery. Can you say something about the risk, or the chance of success you're putting on those two prospects?
Well, I think our interest in drilling those wells indicate that we are optimistic as to the chances, chance of discovery, then I'll leave it to the operator to communicate the facts and figures surrounding those. We are clearly more optimistic now than we were previous to the Filicudi discovery.
Higher COS, not lower.
Yeah. Sorry about that.
CoS. Yeah.
Lastly, on DD&A. Last few quarters, we have seen DD&A per barrel of around NOK 14 per barrel. Should we expect the same level going forward or any changes to that?
Yeah. No, we would expect to be in that neighborhood going forward. Yeah.
Thank you.
Taylor Wilson. One question on production. You clearly underlined that the first quarter production was very strong, and also that you expect the production to come in in that current guiding. What kind of production do we need to see in the second quarter to trigger increased guiding?
This is a difficult question, so this is one for you, Alexander.
Yeah. No. Hard to say, and it would depend on which fields you would see higher or lower production. Obviously, the strong production has been from the Alvheim area predominantly, and the Viper-Kobra wells have been producing tremendously. That is the big reason for the high. Will you see a decrease in production or increased water in that field? Monitoring that will be important. Also, we still have when maintenance season is coming up and how many days we will be shut down on Valhall and Skarv in the third quarter are still uncertain factors. Hard to say, Taylor, on which fields to what level and what will that mean in terms of updating the guidance. It's hard to give an answer today on that one.
Let's say it will be 145,000 barrels in the second quarter as well. Could that justify to increase the guiding?
Yeah, that would be a good argument for increasing the guiding if we can stick with the same production in the second quarter, obviously.
Okay. Thank you. Then on the Gohta well currently being drilled, do you think you will be in a position to provide an updated resource estimate after that well, or do we need more wells to see a new resource estimate?
Well, that definitely depends on the results on the Gohta exploration well. The target, of course, with an appraisal is to reduce the uncertainty level in the estimates. It's definitely my hope that after the results of these wells, we'll see a reduction in uncertainty levels at Gohta.
Okay. Then finally from me, you mentioned that you're currently acquiring a lot of seismic. Just to put that in perspective, how much seismic did you acquire last year in terms of kilometers compared to what you acquired year to date?
Last year, we did not acquire seismic on Aker BP [Kiel]. We did acquire seismic as part of group shoots, and I think this is about three times as much this year as last year.
Okay. What do you pay compared to what you did last year?
That's a good question. Significantly less is the generic answer.
Okay. Thank you.
Okay. We'll take questions from the web, starting with Rafal Gutaj at Bank of America Merrill Lynch. Can you comment on the progress around capacity testing on the Edvard Grieg facilities and how much of a factor this was in your strong production from the Ivar Aasen field? Secondly, can you comment on what is impacting your operations efficiency on some of the assets like Valhall, Ula, and Ivar Aasen?
Okay. When it comes to capacity testing at Edvard Grieg, I'll leave that to the operator of the Edvard Grieg field, but there are obviously activities ongoing. When it comes to being ahead of schedule on Ivar Aasen, it's not much of an impact so far, as we've currently filling the contractual obligation and contractual relationship between Ivar Aasen and Edvard Grieg. The increase in ramp-up has been more due to much higher production efficiency in the quarter than we assumed. What is impacting operational efficiency? Well, both on Valhall and at Ula, we are carrying out a lot of well work, particularly related to on Ula to reclaim WAG efficiency, which have had a positive impact on production and get gas injectors back on production and also to get high-pressure gas producers into the facility.
That has meant that we've had to do significant testing on the facilities and thus reducing the production efficiency but increasing production. On Valhall, it's also impacted by significant well work. Again, this is related to shutdown activities or wells that are meant to increase production in the quarters to come. I think it's important to say that when we guard production efficiency, there are basically four chokes. You've got the well, you got the transport systems, you got the production facility, and the export. We are carrying out a significant amount of well work in order to increase production and thus impacting production efficiency. Operational efficiency in these two assets are on the rise and will continue to be on the rise in the years to come as we are honing the operational discipline and operational efficiency in these two assets.
We are going to continue well work activity, and we are going to continue modification and maintenance activity where we can see a value-increasing potential.
I think those were the two ones
Yep. Then we'll move on to Nikolay Kuzmanov at Jefferies. Question number one, Volund. What has been behind the 85% sequential decline quarter-on-quarter? What is the scope to increase production post the two infill wells offsetting some of the expected Viper-Kobra declines?
Volund and Viper-Kobra is produced through the same manifold. They are two different licenses, so there exists a contractual right of production between the Volund license and the Alvheim license owning the Viper-Kobra. The reduction is due to an increase in production capacity on behalf of Viper-Kobra across the Volund manifold. It's a pure contractual production optimization scheme and not related to reservoir performance across that pipeline. That is the expectation for why the Volund production has decreased significantly. Then, of course, as the Volund infill wells come on stream and are able to backfill the production pipeline with oil rather than water, we will optimize the situation across the Volund manifold to make sure that production is as high as possible.
Obviously, new wells at Volund will increase the Volund production potential and decrease the water cut at Volund, allowing optimization across the Volund manifold. That's a good catch.
I guess a question on capital structure again, what are the main drivers behind your thoughts on forward capital structure and increasing the $250 million per annum dividend floor? Effectively, what are the things that you're waiting for before committing to a capital structure in the interim before Johan Sverdrup? Questions about oil prices, Ivar Aasen ramp up, inorganic opportunities, and so on.
Yeah. I think it would be pretty much the same answer as Anders to his question. Not waiting on anything specific, but again, it's about finding the right capital structure, which has that flexibility. Then Nikki mentioned many of the items that impacts the thinking around that. Not waiting for something specific in that regard, no. The dividend floor, I think we've commented on before as well. For now, it's a floor that's set. It was set before Christmas and the thinking hasn't changed around keeping that floor.
Okay, one more question from Rafal Gutaj at BofAML. Regarding Sverdrup, could you comment on what you're seeing from the vertical well penetrations on Johan Sverdrup? Are these showing you any potential for reservoir volume uplift?
Okay. Well, I think I'll leave it to Statoil to comment on performance from the well penetrations at Sverdrup. I'll just leave a general comment that we're quite pleased with both the drilling performance and the results from the well.
A question from Alwyn Thomas at Exane, related to Ivar Aasen and Grieg capacity again. The question is, how is the capacity sharing with Edvard Grieg working so far, and is there any opportunity to reach plateau earlier?
Well, generally, we have an excellent relationship between Edvard Grieg and Ivar Aasen. From an operational perspective, I think this is as good as we can hope it to become. There's almost a seamless process between the two offshore operations. We are continuing to participate and work on production optimization of the total process scheme across the two platforms. We'll see towards the after summer whether or not we're able to increase production above the contractual ramp-up that are coming now in 1st of October 2017. I'll come back to that question towards the end of the summer.
Okay. I think the other questions have been answered around those themes, that concludes our web questions.