Ladies and gentlemen, welcome to Statoil's first quarter 2018 analyst call. I'm Peter Hutton, Head of Investor Relations. I'm pleased to welcome Hans Jakob Hegge, our CFO, who will run through the results and key issues for around 10 to 15 minutes, then we will open up for questions and answers. We expect this call will finish within the hour. I'm also joined on the call by Svein Skeie, Head of Performance Management, and Ørjan Kvelvane, Head of Accounting. With that short introduction, I hand over to Hans Jakob. Thank you.
Thank you, Peter. Good morning, everybody, and welcome. We present solid results and a very strong cash flow of more than $6 billion after tax in the quarter. IFRS net operating income was $5 billion and adjusted earnings $4.4 billion in the first quarter. IFRS net income was $1.3 billion. Cash flows from operating activities before tax and working capital amounted to $7.1 billion. The net free cash flow in the quarter was $1.5 billion after dividend and the Martin Linge payment. This is the strongest cash flow from operations after tax since the first quarter 2014, when the oil price was around $100 per barrel. We clearly see the results of the improvement projects over the last four years. From a lower cost base, we have created more value at higher prices.
The first quarter is characterized by solid operational performance, record high international production, and our projects are progressing according to plan. Before we review the results in more detail, take a look at this picture of Aasta Hansteen, the world's largest spar platform. Arrived Monday at its final position, 300 kilometers west of my hometown, Fauske, in northern Norway. It will produce gas from a water depth of 1,300 meters, Statoil's deepest field development on the NCS to date. In the quarter, we continued to develop our industrial position in Brazil and Gulf of Mexico, where we secured new acreage. We had two commercial near-field discoveries on the NCS. Furthermore, Statoil increased its offshore wind portfolio through a 50% farm-in with a local company with plans to develop two offshore wind projects in Poland. Before I continue with the results, some reflections on the macro.
We have seen a strengthening of oil and gas markets, with oil closer to rebalancing even with increased U.S. shale oil production. We expect price volatility will continue going forward. Still, Statoil's fundamental market view has not changed, and this is reflected in our long-term price assumptions. Statoil's adjusted earnings of $4.4 billion with a very strong cash flow and a reduced net debt ratio to 25.1% in the quarter are a strong group delivery. This was achieved through solid operational performance, high production capturing higher prices, maintaining our cost discipline. The projects are progressing according to plan, and we are on track to deliver on our guidance and targets presented at the CMU in London. We have made Statoil a more resilient company and better positioned to capture value.
The Statoil Board of Directors has decided that the cash dividend for the first quarter 2018 stays in line with the proposed increased dividend in the fourth quarter 2017 at $0.23 per share. To safety. Statoil's serious incident frequency the last 12 months was 0.5 million hours worked, the best we've had so far, down from 0.8 in the same quarter last year. Safety is and will always be Statoil's top priority. I am safety is the name of a safety culture program that we introduced last year to make safety even more personal and with strengthened personal accountability. We never stop searching for better and safer. We believe that our strong push on digitalization can assist us in further improving Statoil's safety record, as well as making us even more efficient. Let's now have a look at the financial results in more detail.
We deliver $4.4 billion in adjusted earnings before tax this quarter. This is up from $3.3 billion, or 33% from the same period last year, while Brent has increased 24%. Strong operating results were high production, higher realized prices, and sustained cost focus are the key contributions. Adjusted earnings after tax was $1.5 billion compared to $1.1 billion in the first quarter of last year. The tax rate in the quarter was 66.6%, reflecting low effective tax rates in EPI and MMP, offset by increased provisions at a group level. We realized an average liquids price of $60 per barrel in the quarter, up 23% compared to the first quarter last year. Realized European and North American natural gas prices were also higher, up 26% and 5% respectively year-on-year.
Statoil's OpEx and SG&A cost per barrel, measured in underlying currency, remained relatively stable with a small increase of 3% due to new fields on stream compared to the same period last year. Depreciation is down 1%, and the main driver is increased reserves. However, a change in the depreciation basis for one particular NCS field increased the depreciation charged by more than $100 million in the quarter, and normalizing for this, the DD&A would have been down 5%. Let's have a look at the segments. E&P Norway delivered adjusted earnings before tax of $3.4 billion. This is an increase of 29% compared to the same period last year. Our improvement agenda, together with strong cost focus, is delivering sustained results. The total NCS production at 138.1 million barrels of oil equivalents per day is roughly flat.
Underlying OpEx and SG&A measured in NOK was also relatively stable, with a slight increase as a result of new fields coming on stream. Depreciation is up as previously mentioned. Achieved liquids price in the quarter was 22% higher than the same period last year. To E&P International, that delivered adjusted earnings before tax of $638 million, which is more than a double compared to the same period last year. E&P International delivered a record-high equity production of 799,000 barrels of oil equivalents per day. Adjusted for portfolio changes, this is up 9% from the same period last year. The main contributor was U.S., both onshore and offshore. The underlying OpEx and SG&A per barrel was flat. The cash flow per barrel after tax from E&P International is strong, at around $25 per barrel.
Our MMP segment delivered pre-tax adjusted earnings of $454 million compared to $500 million in the same quarter last year. The MMP results are characterized by a strong result from the natural gas business, both in Europe and the U.S., high regularity at our plants, lower refinery margins, and a lower liquids trading result. During the first quarter, Equinor's total average liquids and gas production was 2.18 million barrels of oil equivalents per day, an increase of 34,000 barrels compared to the same period last year. This is the highest production since first quarter 2012. E&P International delivered record-high production in the quarter. On the NCS, uptime was high as new fields like Gina Krog and Wisting contributed positively. E&P Norway continues to offset the natural decline with IOR projects near field tiebacks and infill wells. To the strong cash generation.
We deliver a very strong cash flow from operations of $7.1 billion before tax and a free cash flow of $1.5 billion after dividends, tax, organic investments, and after paying $1.6 billion for Martin Linge. Combined with a reduction in working capital of $1.1 billion and stronger equity, we reduced our net debt ratio further by four percentage points to 25.1%. Let me close with a few comments on our guiding, which is unchanged. We maintain our CapEx guiding for 2018 at around $11 billion. 2018 exploration expenditure guiding at around $1.5 billion. 2017 to 2018 production growth of 1%-2% and 3%-4% for 2017 to 2020. Key takeaways are: Equinor delivers a strong quarter with a very strong cash flow. We continue to deliver on our guidance presented at the CMU. A quick reminder.
Equinor will be arranging its first SRI day in London on May 4th. We hope to see many of you there. Thank you for the attention. Now I'll give the word to Peter, who will guide us through the Q&A.
Thank you, Hans Jakob. With that, I hand you over to the operators to open for questions. Thanks very much.
Thank you. If you would like to ask a question, please signal by pressing star one on your telephone keypad. If you are using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. Again, press star one to ask a question. We shall take our first question from Biraj Borkhataria from RBC. Please go ahead.
Hi, Hans Jakob and Peter. Thanks for taking my question. Just going back to your comments on being on track to hit your target. I wanted to take you back to what you said at the CMU, which was that the scope for buybacks was emerging. At that point, you talked about the balance sheet being the number 1 priority. Obviously the macro situation is better than you planned, both in oil and gas, and gearing has come down quite a bit. The question is, what more do you need to see to start the buyback program from here? The second question, just a quick clarification. You talked about lower liquids trading. Q1 is typically quite a strong quarter for trading. I was wondering if you could just give a bit more color on what drove that weaker result. Thanks.
Thank you, Biraj. On the buybacks, if I take you through to the CMU, we talked about an emerging scope, as you said, and that was based on a macro environment and the portfolio developments, and a near-term priority to reduce the gearing. We have been doing, reducing it by 4 percentage points. The macro has been positive, but we also have seen volatility with prices down in the 60s and then above 70. We expect also volatility going forward. In terms of priorities, it remains a near-term priority to strengthen the balance sheet. We still have some payments on the acquired assets to be done. No news on the share buybacks. On the lower liquids trading result, overall the M&Ps within the guiding and in the higher range.
It's moderate on the liquids, We have seen a backwardation market, and that is a bit tougher to make the huge profits.
Great. That's very helpful. Thanks.
Our next question is from Oswald Clint of Bernstein. Please go ahead.
Hi. Good morning. I'd like to ask a question on the OpEx, please. You've obviously indicated underlying OpEx remains stable, which is good and obviously in line with your plans. I do remember Torgrim talking about embedding some pretty material OpEx inflation assumptions into his business for this year. I guess the question is he seeing those numbers within the U.S. business, and is there an offsetting decline in OpEx somewhere else within the business so that the overall number is flat? That would be my first question. Second question, just really a bit of an update on the Roncador transaction. Any update on when that might actually close, please? Thank you.
Thank you, Oswald. On the cost, one step back, we have seen a very positive trend over time, NCS being at a 10-year low, and we see improvements paying off. We are still within the guiding. If you look at the adjusted OpEx SG&A, it's plus 11% year on year, and 50% of that is currency. Then we have new fields like Gina Krog on the NCS, the Byrding. In East Coast Canada, we have Hebron, and we have Stampede in the U.S., and we have new onshore wells in the U.S. As prices move upwards, royalty and production fees increase in line. This is partly offset by a positive operational and production cost improvements. Specifically on Torgrim's comment on inflation in the U.S., we have taken into account a 20%-25% cost increase.
This is related to the drilling on well area and completions, and that is taken into account in our numbers. On the project sides, outside U.S. and in our global portfolio, we have not seen this cost inflation. That's the status on the cost. To Roncador. The completion mid-year, that's the latest update. I could elaborate on Roncador. This is an IOR value-enhancing motivated transactions. We did NOK 2.35 billion at closing, and there will be NOK 550 million related to paying for IOR projects not expected during 2018. We'll come back to that.
Super. Great. Thank you.
We shall take our next question from Anne Desrum of Handelsbanken. Please go ahead.
Thank you. A question related to how much remains for the remainder of the year to be paid after acquisition is done. I see that in the first quarter, you paid NOK 1.56. How much remains in the second quarter to fourth quarter? A question related to this, just the depreciation in Norway of $100 million. I know that you're not willing to comment on the specific field as such, what is the reason? Is it lower reserves?
Okay. I'll take the second question, and then Svein will do the payments. On the depreciation in Norway, as you correctly stated, Anne, we have NOK 100 million. It is related to a change of estimate on one field, where we are moving from expected to proved reserves. Going forward, we expect high depreciation on this field for the rest of this year. Overall, on the DD&A in Norway, we are at NOK 82 per barrel, which is plus 11% underlying. This is due to production mix, investments, and changes in the depreciation estimate. On the payments, Svein?
Yes. Thank you. On the payment, the main payment is related then to the Roncador field in Brazil, as Jakob said. On the NOK 2.35, that is expected to be closed then towards mid-year this year. There, we will then pay the outstanding issues, NOK 2.35. We will then, since we have effective date as of 1st of January, we will deduct the value of the production up until closing. That will be deducted. Also later this year, we will also then pay for the exploration licenses that we acquired in Brazil now, announced recently during Easter. That is also an important thing coming up then later this year.
Thank you.
Our next question is from Rob West of Redburn. Please go ahead, sir.
Thank you very much. I'd like to ask two. The first one is about the rig rates coming through in Norway. There are some reports of some of those rates going back up a little bit this year. I was wondering if you could comment on what you're doing to protect against that coming through, and just how much of your drilling is already locked in. The second question would be on Oseberg, and if you could comment on the recent liquids production there. It's been a little bit lower than previous quarters in terms of the decline. Do you see the Vestflanken project stabilizing that or bringing it back up again? Thank you.
Thank you, Rob. On the rig rates in Norway, overall, we see at the NCS, an increase in tendering is observed. The rig rates are in the range of NOK 150-NOK 300. We see that we actually could enter into better rates than the average rates that we have if we did the new contract signings today, because the market is still oversupplied, and that is expected to remain for some time. On the overall Oseberg production, we have quite strong production on Oseberg on the gas side. On the liquid side, there will be variations, I know from the past. You're absolutely right that the Oseberg Vestflanken coming on stream mid-year will also contribute positively to the development of the liquids production.
Okay, thank you.
Our next question is from Halvor Nordlie of SEB. Please go ahead.
Hi, guys. Regarding the U.S. production, we saw quite a large jump in the Marcellus production, while Bakken in Eagle Ford was slightly lower compared to Q4. Is this a deliberate choice to not grow in these areas? Is it due to logistical issues on the completion side, or is it other factors? Secondly, on CapEx, Q1 organic CapEx at NOK 2.1 billion. Can you say something about the distribution of CapEx through the year? Will it be very back-loaded?
Thank you, Halvor. On the U.S. production, it's record-high production overall, onshore, offshore, 358,000 barrels per day. Main explanation for this is well productivity, more completions. We also have low break-even on these wells and increased realized prices on the gas side by five percentage points. This is about strong cash generation. On the Appalachian basin operated, we have high productive gas wells, not high drilling activity as we only had one rig. We completed many wells. The Utica wells have solid economics. Compared to last year where we had some weather, that also makes this quarter's production relatively stronger. On the overall activity level, we are talking about four operated rigs, two in the Eagle Ford, half in the Bakken, and one in the Appalachian operated, plus the non-operated. Three completion crews.
Forecast, the beauty of onshore is that we can scale it up and down with changes in prices. Everything equal might see a slight increase versus 2017 due to more completions. On the CapEx, we started the year on NOK 2.1 billion. That is not affecting our around NOK 11 billion for the full year, maintaining strict cost and capital discipline. Going forward, we have an increased Martin Linge. We have Johan Sverdrup activity passing at 72% completion as of today. We have Johan Castberg, we have Peregrino. In addition, the completions of Aasta and Mariner.
All right. We shouldn't read anything into the fact that Marcellus is very much up, but Bakken and Eagle Ford is down.
There will be variations, but on the Eagle Ford, as you know, we are working on pilot well spacing. We do technology application and we have renegotiation, so we have improvement work going on there. There will be seasonal variations between the three basins.
All right. Thank you.
It appears there are no further questions at this time. I would like to therefore turn the conference back to you for any additional or closing remarks.
Lovely. Thank you, everybody. Short and hopefully sweet. As always, I am available for any questions or follow-up. As Hans Jakob mentioned, we will have an SRI day in London on the 4th of May, and I look forward to seeing many of you there. Until that point, many thanks and have a good day.