EQNR | Equinor ASA | earnings call 2026-05-14
Verbatim transcript (source: faster-whisper-small.en)

Ladies and gentlemen welcome to the 2019 edition of the Equinor Gas Seminar. It's a real pleasure to welcome you here today. Same addresses we did the CMU, different venue, bit like being back at school but hopefully we can be a bit more interactive than it used to be in those days. For those of you and also like to welcome everybody on the web as well, it's good to be able to connect for those of you who can't make it live. For those of you who are here today I'd like to start with a brief but important safety announcement. If the building needs to be evacuated the fire alarm will sound. On hearing the alarm security and support staff will be on hand to direct you to the nearest emergency exit and to the assembly point. The assembly point is Cople Close which is next to the Apex London Wall Hotel, i.e. just across the street from this venue. After the presentations we'll have the normal question and answer session in the hall and also as we've got no phone lines connected if you've got if you're not here and you're watching on the web and you've got any questions please send those through those questions through to Eric and he's urgon at equinor.com and we will put those through questions through during that session as well. So with that let me ask Irena Rummelhof, EVP of Marketing Midstream and Processing, MMP amongst friends, to open the gas seminar. Thank you very much. Well thank you so much Peter. It's a bit of an awkward stage here so I'm not sure where to. It's good to see so many of you, quite a few familiar places and I think we have a pretty intriguing program for you today so I hope you enjoy it and I'm certainly looking forward to engaging with you in the Q&A session later as well. As Peter said this is our fourth gas seminar but it's my first. Just took on the job as head of MMP I guess this August and some of you might recognize me as heading up the energy business until August this year. I assume most of you followed the CMU a couple of weeks ago so I'm not gonna bore you with the details from that but I'm gonna share with you a few highlights. After a very strong 2018 we come up with some pretty strong and impressive promises. We said that we're gonna increase and deliver a 14 billion free cash flow towards 2021. We're gonna grow our return on capital employed up to 14% by 2021. We're gonna continue to invest in world-class development projects which will allow us to grow our production with an annual weight of 3% towards 2025. We also announced that we increased our quarterly dividend by 13% and I hope we gave you some comfort that we're progressing along our strategy always safe high value low carbon on a way to transitioning to a broad energy company. I think you're supposed to or someone is supposed to click but maybe I'll do it myself. Yeah I'll give it to you. We do believe that our low carbon strategy increasingly will become a competitive advantage for us going forward. Climate change is happening, it's real and the energy systems need a comprehensive transitioning and our industry needs to be part of that. We in Equinor we aim to be in the forefront of that transition and we're quite encouraged by the recent CDP rating A minus and proving that we are at least for now in the forefront. And the main topic today gas is absolutely part of that solution and you don't have to look any further than outside these windows to see what gas in combination with renewables can actually do for CO2 emissions. You guys here in the UK are at the lowest emission level since the Victorian era I've been told. We're also very encouraged by what we've seen in Germany lately. The coal Commission just a couple of weeks ago came out with a report announcing that coal will be phased out of the power sector in Germany by 2038 but starting with a significant amount already in 2022. And maybe more importantly we saw Angela Markellet-Davos saying that if we're gonna do this we cannot hide it. The fact that there is only one alternative and that is gas needs to be out there. So this is something we have anticipated, this is something we talked about for quite a while and know it's happening. Lots of uncertainty around the energy transition but there's one thing I think in all of this that is pretty certain and that's that demand for energy is growing. So the world needs to produce as much renewable solar and wind as quickly as we can. We're part of it but the world also need to develop more oil and gas resources. And why do I say that? I say that because in any two degree scenario that I've ever seen decline from existing oil and gas production is always falling more rapidly than demand. So something needs to fill that gap. But that thing that needs to fill that gap need to be with the lowest carbon footprint available. So what does it mean to be a broad energy company? We talk a lot about that and I actually think that my business or our business unit MMP sort of embraces the whole element of being a broad energy company. We are designed to capture additional margins from everything that we produce in Equinor. Gas and oil and solar and wind. We've set up an extraordinary commercial organization currently including the Danske commodities where about 3,600 people. We're located in 20 different locations and 10 different countries and we're working within all time zones. To allow us to capture maximum value from our products we have a sample quite a significant asset portfolio. We have seven onshore plans that allow us to upgrade the quality of the products that we're selling and trading. We have something like 10,000 kilometers of pipeline. We've got at any given time I think between 90 and 20 vessels and we got something like 1100 rail cars that allow us to transport our products to premium markets. Last year we sold 800 millions of oil, barrels of oil, making us into one of the largest net sellers of crude in the world. We sold 100 BCM of gas, putting in us in a position as the second largest gas supplier to Europe and with the Danske commodities acquisition we're actually in no position also as one of the largest short-term traders of power. More surprisingly maybe is that we also trade about 10% of all the waterborne LPG in the world and we are marketing about 10% of the methanol demand in Europe. Tomartin, welcome back to more details on how we trade and manage that portfolio. He has also touched on Danske but I just like to say a few words around that acquisition. It might not be the largest acquisition that Equinor has ever made but I think it can easily turn out to be one of the most strategic acquisitions that we've ever made. Why do I say that? I say that because the rapid cost reductions in renewables means that renewables are in more and more markets reliant on market prices and merchant risk and to have someone capture that additional margin on top of the power prices similar to what we're doing in oil and gas is gonna make us much more competitive. I think also it's gonna be a value-accretive transaction. We paid about 400 million US dollar, no euros for it and last year their EBIT was estimated to be 80 million euros. As the new head of MMP I've spent most of my time trying to be close to the people and business. I've travelled to all our onshore plans and I think this is really where you see your strategy always safe, high value, low carbon come to life. Meeting all these wonderful and very motivated people I think it's you would say safety is number one priority but when you've met all these people it just becomes very very natural that you want to take care of them and it is no doubt number one priority and I think in MMP we can only have one target and that's zero serious incidents because if we can do more we just have to do more to take care of our people and our assets. On value we've guided you guys I guess on the market and also internally that we think we're gonna make our results gonna be somewhere between 250 and 500 million US dollar on a quarterly basis. We keep coming out of a pretty disappointing 4Q. Nevertheless I do see that we're making a lot of progress on our strategy. We're following and quickly developing our asset back trading strategy. We have Tonsky commodity inter-portfolio and we are and Tomahty will come back to that later changing the way we market our gas. So I dare I guess to stay here in front of you today and say that going forward we aim to be in the upper part of that range given that refinery margins recover at least from where they are today. I think they're at around two dollars something at the Northwestern Europe these days. So not entirely new guiding but at least an indication that we think we're gonna be in the upper half of the current guiding. On low carbon I see a lot of good work and a lot of motivated people working on this. Last year we reduced our emissions with 100,000 tons and a low carbon business is also a better business because every ton we reduce we save CO2 tax and also power prices typically because this is a lot of energy efficiency so it's a true win-win. Most well all of Equinor have gone through a tremendous cost reduction and basically totally reset our cost base over the last three to four years so have we in MMP. But we need to continue that journey and to really move up to the next level I think digitalization is gonna help us a lot. On the commercial side we focused a lot on big data analytics, algo trading, blockchains on the more operational side we focused on drones, automations, 3D printing and I'd like to give you a small example and it's a tiny one but nevertheless it tells you something about the future. On the course of the plant a couple of weeks, well some time ago we needed a new impeller you might not even know what an impeller is but it's kind of a steel beam that you put around some equipment and tip you know we called around and they said well it's gonna take us 12 months to get there and it's gonna cost a fortune so we decided to go ahead and 3D print it. It took us four months to get it and get organized but we saved 50% of the cost. Next time around we think we can get it in six weeks and save 67% of the cost. So this is today and can you just imagine the development we're gonna see within 3D printing. So if any of you sitting with Sherry's in a pillar business I'd rather sell them more than gas immediately. Then to the core of our business I guess the Norwegian gas machine as you know we're supplying 25% of Europe with reliable, sustainable and affordable gas. In 2018 we sold gas for about 26 billion US dollar that's more than 2 billion US dollar a month quite staggering and a bit scary I guess but this just goes to tell that Norwegian gas is very well positioned. We're producing our gas short distance from the big markets we have a very competitive transportation cost less than a dollar and a half per million BTU and our gas also comes with very low methane emissions less than 0.3% and we do have reserves to supply Europe for quite some years to come. We just and I think that was announced that the CMU updated our recovery factor ambitions on our gas assets to 85%. We sanctioned all phase 3 which will produce gas way beyond 2015 last year. We also put us to Hahnstein on production late last year and that's quite an intriguing field because it's opening in new gas province up in the north on Norwegian Sea. If you recall one of the slides from on the SIGVEST presentation at the CMU where he talked about the largest unsanctioned projects on Norwegian continental shelf, three and a half of those I guess were gas assets and on the SIGVEST talked about an active exploration campaign for gas on Norwegian continental shelf. But our gas business is also becoming more international. We're well positioned in the humongous I guess more cellars field in northeast US. We're seeing that we'll get an enormous amount of associated gas coming out of our asset portfolio in Brazil towards market with the tremendous potential and through our L&D business at Snurvy we are already selling gas to well last year I think it was 20 different countries. But interestingly and this is something I believe we've told you before at these seminars, you no longer need to be in the L&D business to get exposure to L&D prices. With L&D being the marginal supplier to Europe we're seeing that in 2018 the gas prices in Europe were correlating almost one to one with Asian prices. So we had very high Asian prices about 11 ish for a while European prices were nine and a half at that point in time. More supply came to the market and unfortunately Asian prices went down and also European prices went down. So of course we'd love to have more L&D into our portfolio but we certainly do get quite a bit of exposure to those prices anyway through our gas position. With more L&D and coming into Europe and more and more intermittent renewable I guess we're seeing and anticipating more volatility in the gas markets going forward. Volatility is always something the triadors like. They're excited about it and see that as an opportunity and as a result of that we are changing our gas strategy. Tomahdin will definitely talk more about that later on but the point is we're moving more towards shorter indices and we're going to have a more active management of the way we market our gas. So let me round off where I started. The world needs more energy but less emissions. We believe gas is very well positioned. The most effective climate initiative you can do is to switch from coal to gas, reduce this immediately. Emissions in the power sector with 50 to 60 percent. Gas can enable a higher penetration of renewables and will be needed as backup capacity. We also do believe that gas has a future as a destination fuel. If you transform gas into hydrogen, store the CO2. We're in a position to actually offer our customers an emission free gas. So in short we need both electrons and molecules and we believe that we in Equinor are well positioned and well on our way to developing ourselves as a broad energy company. So now I'd like to leave the word to Eric who's going to talk about the market picture and then I'll leave it to Elise but after that who's going to give us more detail into the development of the gas market. So thank you for the attention. Thank you Elena. Thanks for the introduction and thanks for the overview of our big gas business and our transformation to become a broader energy company. Good morning everyone. It's nice to be back in London and it's nice to see so many of you again. I'll give you an update on the macroeconomic situation that's affecting all our energy markets. Focus on some of the geopolitical trends and variables and uncertainties that will affect both macroeconomics but also energy markets going forward and then towards the end I'll remind you of what is possible developments in global regional gas markets as we go beyond 2025 and towards 2050. You have to remember that this is a long-term business. We're in it for the long term. Global economic growth performed well in 2018, slightly above the historical average growth and that's in spite of this being an extremely tumultuous year in many ways with increased trade tensions, growing signs of lack of international trust and volatility in financial and commodity markets. The current situation is that global economic policy uncertainty is very high. Investment and trade growth are weaker than many anticipated. The imbalances in some of the important emerging markets are significant. I'll come back to that. As a consequence, most of us who are in the business of forecasting, we expect global economic expansion to slow down and the growth to be lower this year than it was last year and the year before. We have all of us downgraded growth in 2019 relative to 2018, one exception being the United States, which is in a sense a special situation. Our forecast in terms of global economic expansion this year is slightly lower than that of the IMF. We're at 2.8% this year and 2.7% in 2020. Of course, one of the key uncertainties is the ongoing short-term development in China. But note that we believe in continued growth. There are some people that talk about the possibility of a recession. That's not in anyone's base case, I think. There might be some countries that go into recession, but global economic recession is something very different. On the energy side, global energy demand, as we show in this chart, has grown steadily since the financial crisis. And it's important to note that we demand 30% more energy now than we did in 2000. And energy was a large part of the global economy then as well. Gas demand has increased more than overall energy demand and also more than oil demand since 2000. And the reasons, of course, is competitive supply costs, and as a consequence, low prices, in particular in the United States, development in infrastructure, and the fact that gas is a versatile and clean fuel. And we believe that the gas demand going forward is going to be relatively robust in our central case. And I'll come back to the longer-term uncertainties. As I mentioned, key emerging economies that we use to deliver growth and help the global expansion struggle now with key economic imbalances, and in particular trade deficits and fiscal deficits. And the slowdown in the advanced economies will hamper growth in these emerging economies. And several of these emerging economies have seen their currencies fall significantly during 2018. Argentina and Turkey are examples of countries that have been particularly hurt. The depreciation of these currencies against the dollar and the euro has increased their debt burdens. And then that adds to financial stress, given that they already have large fiscal imbalances, large trade, negative trade imbalances. And a higher US interest rate, the ongoing trade conflict, and policy mismanagement have all contributed negatively to the currency crisis. And these show emerging economies we have here, they have the twin deficits adding to the economic burden, and it increases their dependency on a continued flow of foreign investments. And then in a situation without trust, that becomes an increasing challenge. And then other factors affecting the situation, and that also causes capital flight, at least less capital imports, are then reduced global economic demand, or the slightly lower growth in global demand. And also as a consequence of the foreign exchange movements, an increasing burden of their energy bill, because these are energy importing countries. And some examples here. In terms of Argentina, we expect economic contraction this year, both as a result of last year, but also this year. And I'll say significant uncertainty about the result of the election and the subsequent economic policies. In Turkey, they're in a currency crisis with marginal to negative growth this year, and risking a debt default. In terms of Brazil, Bolsonaro's proposal are very ambitious, radical change and simplification of several parts of the framework conditions in Brazil, but with significant implementation risks as to how will these reform proposals go through, will they go through, and what will be the short-term impact on the economy as they change. And even the fastest growing G20 country here, India, has its challenges, with a trade deficit that reached a five-year high in July, and with a policy rate now from the central bank at 6.5%, which is cooling down both business and consumer sentiment. So we don't get the help from some of these large emerging economies in driving overall global economic expansion. And then we're in a situation of protectionism, increasing protectionism, driven by the United States, exemplified by the exits from the TPP, the re-negotiations of the NAFTA treaty. And since the beginning of the summer of 2018, trade tensions have intensified, and several import duties have been imposed by the US. And then as a consequence of that, tit-for-tat retaliations by some of its trading partners. And examples that you all know is import tariffs on steel and aluminum from both the EU, Canada and Mexico. Tariffs on imports from China worth some $250 billion, where China then re-italiated by tariffs on US imports of $110 billion, including LNG. And where the United States is still formally contemplating an increase in tariffs on another $270 billion of imports. But at the same time, in December, they agreed a 90-day trade truce, making a shift for the positive. It looks as if it might become slightly less a situation of conflict, where they have plans to reach a deal by the first of March, we'll see, to avert the escalation of tariffs. They're also talking now with the EU on regulatory hurdles, where the outcome would depend on how much extra goods the EU buys from the United States, as an example being LNG. But of course, if these trade tensions further escalate, international supply chains and small open economies will experience challenges. In the first case, full-blown trade war scenario, IHS has estimated that economic growth globally could lose as much as 2 percentage points. That means we're close to a global recession, if that happens. In terms of energy and these trade protectionism efforts, if you like, LNG flows are so far very, very marginally impacted by the tariffs. And in the case of China, the LNG actually going to China is very low, very small. So there's no immediate impact. But of course, going forward, as gas markets continue to globalize, as I'll come back to, these markets will be more exposed to geopolitics and this type of trade tension, if they were to occur again. So, as noted by, also by Renne, LNG is now the main mechanism that links global gas markets. And it's that mechanism, as we've spoken about in all these gas seminars, it's that mechanism that opens up for a global price formation on gas. And we see tendencies of that already in terms of the short-term markets. And then various gas markets around the world are relying on one or two physical pipeline gas sources. Those are indicated in red and yellow countries that are dependent, very dependent on one or two physical pipelines. To some extent, some of these countries, to the extent they have a coastline or a good neighbor on the other side, are able to rely then on increased LNG imports to increase the security of supply. On the other hand, the growth in LNG then, as I said, means that gas flows become more exposed to geopolitical risks that traditionally has only troubled the oil market. And you have the Russian sanctions since 2014 as an example, and the recent US proposal to stop the Nord Stream 2 investment is an example of the geopolitical aspects now affecting gas markets more than previously. Iran has been subject to sanctions from 2006 to 2015 and again from now, from November. That will affect their strategic financial energy, petrochemical and automotive sectors. Turkey is still buying Iranian gas, but payments and currency issues in such a situation pose a challenge. We have Qatar, cut off by the rest of the Middle East, if you like, and going out of OPEC. Any escalation of that rivalry in the Middle East will have serious impacts on the global gas market, as Qatar is the largest LNG exporters in the world. We have Yemen, a tragic example, of course, but it's a gas market or a gas supplier that has not delivered since 2015 as a consequence of the war. And the US protectionism now calling for increasing LNG deliveries to Europe and Asian markets to improve the US trade balances. At the same time, threatening or putting tariffs on LNG exports to China is an example of how these geopolitical developments could affect markets. Brexit is a development that would mainly affect UK's trade relationships at an operational level, but of course the general uncertainty there has impacts also on larger global markets like oil and gas and other types of trade. And finally, partly on the map here, another uncertainty would be the North African situation, which in North Africa is an important supplier of gas to Europe and the geopolitical. And certainly there is primarily impacting the supply from Libya through pipelines, but could also in a given situation affect at least the notion of secure supplies from Algeria, both in terms of pipelines and LNG. And of course, the flip side of that increased uncertainty is that there are business opportunities for companies or countries that are stable and work in a predictable policy and regulatory regime, as one of your good neighbouring countries is an example of. Then another geopolitical or global issue that Irena was referring to that affects all international oil companies' strategy developments at the moment, the carbon challenge. And that requires a global cooperation at scale. And we're not there at all. We need a price on carbon. That's very simple, being an economist, extremely difficult, being a politician. More and more countries and regions introduce carbon taxes or emission trading type of systems to put a price on carbon, and the EU ETS is one of them. In the case of Norway and the UK, we have carbon prices in addition to the ETS. And in the case of Norway, we experienced one of the highest carbon prices in the world, with the Norwegian carbon tax on top of the ETS price for our emissions, as an example. A local regulatory drive, not a global, but a local one, in many places seem to be relatively efficient and relatively successful. A good example could be the UK power sector, where the carbon price floor has strongly contributed to the reduced coal electricity generation. And as Irena said, you're the lowest emission since Queen Victoria. Congratulations. And you're a strong example relative to your German friends. Unfortunately, the Germans now seem to come after you. Another example of these local regulatory changes are the drive that is happening in some of the US states. And the EU ETS system is, of course, an interesting example, where the supply side is basically a policy instrument used to achieve climate policy ambitions, and where the demand side then fluctuates with economic activity and policy changes and expected policy changes. And the rapid increase we saw in the ETS price last year is an example of how political changes on the supply side affect the markets in a given situation. And then for global climate collaboration, the story is more complex and less positive. There's still a significant gap between lofty, optimistic targets and the ability to implement measures that would contribute to achieve those targets. Unfortunately, with all that uncertainty, moving towards the long-term energy future, I wouldn't be honest or serious if I say that you can foresee several different outcomes for the global energy system going forward, depending on which of the key drivers on the supply and demand and the policy side you decide to assign weight to. As an example here, I illustrate potential outcomes for electricity generation going from now to 2050. And you know we have three long-term global energy scenarios to 2050 that we publish in our Energy Perspectives report every June. Elena showed in her, at the start of her presentation, a few of the outcomes of that from last year's publication. And here's another one. What will electricity generation look like going forward? One key is, of course, that electricity generation will grow significantly. We will become more electric. We will not become electric. Still, at the lowest level, 65% of our primary or final energy consumption will still not be electrons. It will be molecules in the two-degree scenario. But we will become more electric. Transport, the dark blue up there, becomes a new visible source of electricity demand due to electrification of white-duty vehicles, etc., etc. You can see in the middle that new generation capacity will overwhelmingly come, we think, in all scenarios, from wind and solar and slightly some increase also in geothermal. So new renewable electricity will be the new generation. There will be some new gas-based generation, both in what we call the reform case, the central case, and the rivalry case, where gas is then keeping its market share in those two scenarios in a very significantly growing electricity market. In the renewal case, the middle one, the gas share in the electricity generation goes down, but in a market that is almost 60% larger. So the decline in gas demand from electricity is less than what the market share would indicate, because the market grows by 60%. So the gas demand from electricity declines, but not that much, as you can see in the chart. Then, in terms of overall gas demand, as you know, gas is not only about electricity. Electricity is only 25-30% of gas demand, the rest is transport, manufacturing, heating and cooling. The long-term outlook for gas is solid, and you can see that by 2025 we don't see a lot of difference between these scenarios. We saw a robust growth, as I said. But even in a two-degree world, the blue line there, with 8-10% decline in overall gas demand to 2050 from now, that calls for massive investments to keep pace with demand. The difference between decline rate and potentially, moderately declining demand is important to keep in mind, as I reminded you. In all scenarios, look to the right, we have significant growth in Asian demand, and even in a two-degree scenario, the gas demand growth in China and India is equivalent to a new Europe, up to 500 BCM in Asian gas demand growth from now to 2050. That gas demand has to be satisfied, and that's even in a world where we actually reach the climate targets. The consequence is that there will be large changes in gas transport from surplus to deficit regions, even if China, as an example, also will grow its indigenous production significantly. And then showing you some examples of that. These are regional gas balances illustrated in the reform case. They're important. We have some surplus, some deficit regions, based on these two factors. And then, as I said, this is in the reform case. And the global gas demand forecast that I just showed you, as an example here, it hides very different supply-demand balances in different regions. The United States, and therefore North America, is already well on its way to strengthen its export capacity and will have a large gas surplus that has to or could go somewhere if somebody wants to pay for it. Europe will need additional imports despite a likely very moderate demand development or a significant decline in the case of the two-degree scenario. It will still need growing or constant imports. And the reason is that the indigenous supply is declining. In the case of...Nederlands is one of the best examples. And most recent data now show that the Honingan field falls even more than expected down to 16 BCM next year. And declining supply elsewhere. Here we include Norway as an indigenous source of supply. And in this case, we've assumed that the Norwegian supply is flat until 2030. And growing imports. And then Asia is in need for increasing imports, as I mentioned, significantly. In spite of China, for instance, more than doubling its own gas supply from now to 2040. And then, of course, that would partly be pipeline supply from Russia. As an example, the power of Siberia pipeline from 2020. But also other sources of pipeline supply. Other parts from other parts of the former Soviet Union as well. And significant need for LNG imports. So, therefore, consequently, I mean, the long-term, the growing part of LNG is absolutely growing. And the LNG market is absolutely necessary to close these regional imbalances. In the same way that oil transport currently does. So we see a globalizing gas market. And then finally, just to remind you, on the need for new investments, investments in new supply, if you like, of gas. Without supply, without investment, supply will fall possibly by 5% per year. 3% to 6% per year is what we illustrate here. So that means that the supply demand gap opens very fast if we don't invest. And there's a significant uncertainty in that gap already to 2025, depending on what you think about decline rates. 1,000 to 1,700 B.C.M. already in 2025. And then as we go further off, the gap becomes enormously big. And then depending on the demand scenario you have in mind, the size of the challenge becomes different. But even in a two degree scenario, which is the bottom of the demand range, when you get up to where the global demand by 2050 is 8 to 10% lower than today, we might have to deliver 70 trillion cubic meters, 70,000 billion cubic meters of new gas from now to 2050 to satisfy demand. So new gas from something that does not produce today and that needs investment. 70 trillion cubic meters, very few of us have an intimate relationship to a trillion cubic meter of gas. Is that a lot? Well, it is 60% more, as an example, 60% more new gas than what has accumulated, been delivered, combined from the United States, Russia, and the Middle East over the last 35 years. If you add the combined gas deliveries from all of the Middle East, Russia, and the United States over the last 35 years, you have to up that by 60% to get the figure for potential new gas supply over the next 35 years in a two degree scenario. And if you don't believe in a two degree scenario, the challenge is even bigger. And of course, those investments don't combine themselves. They need capital and they need price signals to ensure sufficient investments. And those price signals we hope are there. And now Elizabeth will tell you more about at least short term price signals. Thank you. Thank you, Eric. And good morning, everyone. I am head of the Equinor Market Analysis Group, and we are responsible for analyzing all the commodity markets for oil, gas, and electricity. And we look both at the short term as well as at the long term. And today I would like to focus on the latest developments in the global gas markets, and I will also touch upon the electricity market. I will take a closer look at some of the key supply and demand regions for gas, and I will round off by focusing on Europe. But first, I would like to take a look back to refresh what we said a year ago and how that turned out. So what did we say last time around? Well, firstly, we said that gas will be an important, flexible source for electricity, both in the US as well as in Europe. And in the US, gas has gained market share for two main reasons. It's due to lower natural gas prices, and it's due to coal retirements. The reduced gas prices are linked to the strong growth in US gas production, with more than 50% growth since 2010. These lower gas prices have made gas-fired generation more competitive relative to coal, leading to significant coal-to-gas switching. And due to new environmental regulations, we have seen a number of older and less efficient coal plants retire over the recent years. And the share of gas in the US electricity mix is now above 30%, and the share of coal is below 30%. Secondly, we said that Asia will be the engine for global gas demand growth, and that China's gas demand growth will substantially exceed the growth in the US LNG exports. The global demand for LNG in 2018 was driven by Asia and China in particular. China is phasing out coal in favour of gas in some regions to reduce local pollution. And last year, we indicated unexpected growth in Chinese LNG import of around 8 BCM. The year-end numbers show an increase of more than 20 BCM, and that's three times the new US LNG capacity added last year. And finally, we said that Europe is increasingly reliant on gas imports and will face competition to attract the required LNG. Through the first three quarters of 2018, we witnessed high competition for LNG supply between Europe and Asia. Asia absorbed most of the incremental LNG supply due to the high LNG prices in Asia in that period. However, in fourth quarter, this trend shifted, as you can see on the final illustration. In fourth quarter, the European LNG import increased by more than 40% versus fourth quarter of 2017, or a volume of 8 BCM. So I think it's fair to say that the market delivered on all of these three key messages from last year. Let us now take a look at the price movements in 2018. In Q1, we saw significant strengthening of the European prices. A cold spike in end of February brought the European demand to between 700 and 800 million cubic meters a day, which is significantly above the average seasonal level of 550. In addition, a number of unplanned production outages in the UK and on the NCS provided further volatility and support to prices. In March, an unusually cold weather in Europe supported gas demand in the residential sector and also led to strong storage withdrawals. As a result, the storage levels in Europe approached the lowest level ever seen, and the prices moved towards 9 US dollars per millimeter. And then, after normalization of the price levels in Europe in April, the gas prices continued increasing consistently through Q2 and Q3. And this price increase was linked to several factors. Firstly, it was an overall rallying energy complex with cold, oil and CO2 prices increases. Secondly, above average storage injections to refill the historic low storage levels. Thirdly, a strong call for gas to power due to a warm summer and need for cooling. Number four was due to high level of maintenance, both on the NCS pipelines as well as on for Russian pipelines, which limited the gas availability to Europe. And finally, it was due to limited LNG availability in Europe due to the strong Asian demand, which again was supported by weather factors. And then during Q4, the prices weakened from the unusually high levels in the previous quarters. In Q4, we saw increased LNG availability to Europe in parallel with warmer than normal seasonal weather, reducing the need for heating. In total, this resulted in falling prices. In Q4, also the Asia LNG spot prices gradually weakened due to ample supply of LNG from new facilities and comfortable inventory levels in the Far East. In the US, the prices peaked in Q4 due to a cold spell and concerns on low storage levels. The storage levels in the US entered the withdrawal season not only 20% below the five-year average, but the market had yet to react to the deficit because it was confident that record production could make up the difference. The arrival of such extreme cold so early in the winter season briefly frightened the market. And besides such cold periods, the US prices hovered around three US dollars per millimeter-year throughout the year. On average, the European gas price for 2018 was very strong. The NBP average was eight US dollars per million BTU, which is close to 40% above the 2017 average of 5.8 US dollars. Due to the increasing importance of electricity in the future global energy mix and also in our portfolio, I here illustrate the electricity price development in Germany as one of the large European electricity markets. During 2018, we saw a significant increase in Germany electricity price. From around 30 euros per megawatt hour in May to more than 50 euros per megawatt hour in July. This increase can mainly be explained by looking at the drivers behind the short-run marginal cost of electricity generation, namely the fuel costs for gas and coal and also the CO2 costs. In this period, the prices for gas, coal and also CO2 all increased as you can see on the right-hand side. Prices for both German electricity and the drivers of short-run marginal cost remained at a high level throughout the second half of 2018. The average prices in this period were much higher than the average prices in the same period the previous year. 62% higher for German electricity, 40% higher for gas, 7% higher for coal and close to 200% higher for carbon. During the summer, lack of rain lowered the water levels in major rivers as you can see on the photo here. Such low water levels limited the delivery of coal to thermal power plants, which again resulted in larger coal and gas in the power sector. And this is another example of the flexibility gas has in the electricity sector and which is also not, or which is independent of the price drivers. Let us move to the US and take a look at the supply development and the increasing exports. The first illustration here shows that the US has a very large amount of resources available under $5 per million BTU. The EIA estimates that at current demand levels the US has enough technically recoverable resources to last around 90 years. We have seen abundant production growth out of Appalachia where the Maussellus and Utica plays where Equinor has a large position. Appalachia has one of the lowest break-evens in North America. Additionally, we are seeing more associated gas volumes in the US, which is driven by oil and not gas economics, meaning that even more cheap gas has come into the US market. The second illustration shows that 2018 was a record year for US production, totaling 830 BCM, growing by more than 90 BCM year on year, or 12%, which is the highest growth ever. Nearly 50% of this growth came from Maussellus Utica and 30% from the associated gas in Permian. The third illustration shows the growing US exports. The abundance of US gas supply and lower natural gas prices has increasingly made the US an attractive exporter of natural gas into global markets. US exports have also turned into a crucial source to help balance what would otherwise be an oversupplied US gas market. Since 2005, the US turned from being a small pipeline exporter to Mexico with 8 BCM, to last year being a major pipeline and LNG exporter, with total export volumes reaching 77 BCM. That's a 69 BCM increase in export level in only 13 years, or it's about the same size as the total Italian gas market. This year should be another large year for US LNG exports, with a number of new terminals scheduled to start over the course of the year. We expect another 40 BCM of capacity coming online this year from five different projects. That is more than a doubling in capacity from end 2018 capacity levels. The LNG export capacity from the US is expected to further grow to around 90 BCM in 2020 and to above 100 BCM in 2025. My key message here is the power of low prices. Low prices spur demand and that's what we are seeing in the US. Even in a year when we saw record production growth, we saw relatively tight market balances late in the year. This shows how strong demand growth has been in the US. Going forward, there were signs that production growth should slow somewhat from the previous levels. As production growth slows, demand, and especially from exports, will continue to grow with the continuous expansion of LNG export capacity. This leads to tighter balances and consequently higher prices, which will impact the competitiveness of US exports to the global markets, closing the arbitrage window for the US LNG exporter. Now let's take a look at the global LNG market. In 2018, we saw an LNG capacity build-up globally, totaling 56 BCM by the end of the year. This is one of the largest yearly capacity build-ups ever. However, please be aware that LNG capacity does not equal LNG production. The yearly LNG production was lower than this, as the capacity was not available throughout the year and also that LNG production may be limited by other factors. New capacity additions are illustrated on the middle graph. New capacity for 2019 is expected to be around 45 BCM, of which 40 BCM is from the US. In 2020, we expect additionally 28 BCM. This additional capacity will contribute to the increasing globalization of the gas markets, but is still a small part of the total gas capacity globally. And in context, it means that the LNG share of the global gas capacity increases from around 10% in 2015 to around 14% in 2020. The global LNG demand will continue to be driven by Asia. We anticipate some slowdown in the growth from China based on the assumption on slower economic growth, slightly relaxed policies on coal, as well as on import capacity constraints. In Japan, we expect flatish imports. After a few years, we reduced LNG as a result of the return in nuclear reactors. At the same time, we expect LNG demand growth in countries like Pakistan, India and Bangladesh, which need to reduce their energy deficit. In 2019 and 2020 will be a good period for these countries with a lot of new supply coming online, providing affordable price levels, which then again is expected to spur the demand for global LNG. This softer period has been expected for some time, which I also have referred to in previous gas seminars. However, the LNG overhang has been pushed out in time due to both delays in LNG capacity build-ups, as well as surprisingly strong demand growth. Our current assessment is that we will face a shorter period with softness than previously expected. The strong capacity build-up we are currently experiencing is originating from the investment decisions taking in the high price environment from 2012 to 2015. The market is cyclical, as you can see on the left graph, and the lead time is four to five years from FID to production. From around 2022 and not 2025, which I have said earlier, we expect demand to have caught up with supply, consequently leading to higher prices. And the lower the price drops in the short term, the sooner the market will rebalance and the sooner the price will recover. On the right-hand side, you can see our assessment of which regions that will absorb the incremental LNG in 2019. We expect Asia to absorb around 75% of this, leaving around 8 BCM of LNG to fill the increasing gap in the European balance, which I will come back to. As illustrated in the global LNG balance, the development in China is key. In 2017, the Chinese gas demand was just above 240 BCM, which is roughly twice the NCR's gas exports. In 2018, the gas demand in China is estimated to be around 280 BCM, corresponding to a growth of 17%. In a global context, this means that China is the third largest gas market in the world, following the US and Russia. In China, the air pollution control policies from 2017 continued to support the gas through the first three quarters of 2018, in addition to high demand from the industrial and residential sectors, a hot summer and storage build-up. In Q4, the gas demand growth was reduced due to softening air pollution control policies that allow the use of cleaner coal. In the context of domestic energy use, gas demand is small, with just 7%. Chinese authorities want the gas's share of the total energy mix to grow to 10% by 2020 and towards 15% in 2030, which means a healthy growth rate going forward. LNG growth is expected to be somewhat lower than last year, but still significant in absolute volumes, and it will grow to above 100 BCM in 2022-23. The right-hand side illustration shows Chinese gas demand predictions from various sources. Woodmax predictions show a demand growth of 160 BCM, or more than 60% in a five-year period. In addition to increased LNG import, this demand would be covered by increased pipeline imports and domestic production. Now, let us move to our home turf and take a look at the development of gas demand in Europe. The first graph shows how the short-run marginal cost of coal fired electricity generation, which is the black band here, has jumped to a much higher level as a result of the increase in CO2 costs, of nearly 200% as I referred to earlier in my presentation. The commodity forward curves indicate that gas fired generation, which is here in the blue band, will be increasingly competitive to coal in the medium-term outlook. The band shows the span from the most efficient plants at the lower end of the band to the least efficient plants at the higher end of the band. Further, the second graph illustrates how gas consumption in the electricity sector is expected to continue to trend upward in the medium-term, with higher utilization of gas turbines at the expense of coal plants. We anticipate a gas demand increase in power generation for all of EU of around 12% or 17 BCM in 2019 from the level of 2018. This is based on significantly higher prices for CO2 together with outlooks for somewhat lower gas prices compared to 2018, which makes the gas-fired generation more competitive relative to coal. From 2020, we expect a gas-to-power demand level of around 166 BCM in Europe or an additional growth of 8% from 2019. Looking at the total gas demand in Europe in the third graph, the observations are, firstly, EU gas demand has experienced a strong recovery in the last years. However, we expect the demand to remain below the 2010 level going forward. In addition to the gain from coal to gas switching, the strong economic recovery in the Eurozone has also pushed up gas demand in the manufacturing industry sectors. And further, more normal winter temperatures has also led to increased consumption from the heating sector. Going forward, we expect a flattish demand in Europe with a slight decline in residential, commercial and industry segments due to efficiency gains, but that is combined with an increase in gas-to-power. Let us now look at the supply side in Europe and how the demand will be filled going forward. As can be seen from the left-hand side illustration, the European domestic production is declining and is expected to decline 10% from 2019 to 2020, then dipping below the 100 BCM. One of the main reasons is the cutting running in production based on the earthquake activity in the region. Groeningen produced around 20 BCM in gas year 17, which was below the cap. The cap for gas year 18 is around 19 BCM, but the target is to produce less, which also I refer to. Further, Groeningen production is planned to be reduced to 12 BCM from gas year 2021 and to be closed fully by 2025. In 2018, the production from the UK was around 38 BCM, which is about 2 BCM higher than in 2017. The UK gas production is expected to be at around this level in 2019 and thereafter decreasing rapidly from 2020 and onwards. The NCS gas supply going forward will continue to be strong at levels slightly above the recent levels, and this is illustrated in the bar diagram on the right-hand side. North Africa is expected to be stable at current levels around 38 BCM and start declining from 2020s. Supply from the Caspian region will arrive to Europe around 2020, primarily to Italy and with a slow build-up. The balance for Europe shows an increasing import dependency with Russian gas and LNG filling this gap. The Russian gas supply is expected to remain at 2017-2018 level, which means a market share of around 35%. This means that LNG import to Europe needs to grow to above 70 BCM by 2022, representing a growth of more than 40% from the current level. And this fits well with the increase in global LNG coming on stream and that will find its way to Europe. In 2018, Europe absorbed around 10% of the global LNG capacity, whilst in 2020, Europe will need to attract 15% of the available global LNG capacity to cover their supply gap. To sum up my presentation, I will illustrate the various drivers with some symbols to show their impact on the prices in Europe for this year and also for the developments beyond 2022. Domestic production will continue to decline and puts an upward pressure on the prices in both these time periods. And pipeline imports will continue to be strong, providing a negative price pressure. The storage inventories are currently high, which provides a negative pressure on the prices. However, going forward, we assess storage to have a neutral impact on price. The demand is expected to be flat and consequently has a neutral impact throughout this time horizon. As the marginal source of supply, the development of the global LNG supply and demand balance will impact the European market's prices. In the short term, we expected the supply to grow somewhat faster than the demand, putting a downward pressure on the prices from the very strong level we have seen in 2018. We are now facing the LNG supply overhang we have predicted for some time. However, this supply overhang came later than assumed due to delays in capacity builder and it will last shorter due to the continued growth in demand. There is still significant uncertainty and we will experience volatility going forward. Also, when taking into account weather factors that influence strongly on the gas market. The lower price level is a temporary effect as low prices will stimulate the demand and by 2022, the global balance looks tighter. If the prices drop further from the current level, the price will recover earlier as the market rebalancing will be accelerated. On the right hand price graph, you can see that the European forward pricing fall within the cold switching range, which stimulates demand. Further, we see the forward prices are mostly within the Henry Hub Europe band, which means that the US LNG producers do not have full cost recovery with such prices. We believe the situation will not last beyond the next couple of years and prices will start to recover from early 2020s. And now I would like to hand over to Tom Martin, which will talk around how we create value from our portfolio of gas. Thank you. Thank you. Elisa, good morning ladies and gentlemen. I'll spend the next few minutes taking you through our gas marketing and trading activities in 2018 and also gaze a bit forward for the next couple of years. Now as head of Equinor's marketing and trading unit, my main priorities are first to bring whatever we produce to market and to honour the commitments we have in the market and secondly, to ensure that we capture full and fair value of our production. Then lastly, and you could call it the icing on the cake, is to trade for additional margins on top of that, but also to trade to support the value of our equity production. Now in the presentation I have for you here, I will address primarily how we provide competitive and reliable gas to the market in 2018, how we now prepare for future deliveries of gas, and how we sell the gas and how we also reinforce and strengthen our commercial capabilities going forward. But before I start, I just want to remind you that the volumes we market on the gas side as one portfolio comprises of Equinor equity and also the Norwegian state equity, just to avoid any misunderstandings, I talk about that combined portfolio when I present it to you today. So there are two, let's see if they both work. I hope this one didn't. This one did, thank you. So looking back at 2018, and what a year that was, prices were exceptional. I can hardly remember, and I've been at this for quite a few years, that we had price levels as we saw in 2018. And we had high demand, and we had high volatility, which is good from a trading point of view. And also we saw LNG continuing to drive the commoditization of natural gas, moving from regional to an increasingly global market for gas. We responded to the market by selling more than 100 BCM of gas and some third party volumes into this market. And that is a bigger volume than, for example, Shell's global LNG portfolio, just to put it in context of size. And in total we and the NCS had an export of 114.2 BCM in 2018, which is just shy of the 2017 figures. And this gas ends up in all the main markets in Northern Europe. This was enabled by high flow levels to our customers, supported then by good regularity on the NCS and in the delivery system to the market. So as compared to 2017, the results within trading and marketing and trading improved significantly, supported also by high LNG prices and cold spikes in the US last winter. Now looking at the last quarter of 2018, our average invoiced, not the market price as observed, but our invoiced European gas price increased by 22% compared to the same quarter the year before. This was very much related to the increasing cold prices as Elisabeth just alluded to, high demand from storage and storage injection and lower LNG supply. In the US, our average US invoiced price increased by 42% in the same period, again mainly due to an increase in the Henry Hub prices. For 2019 and for 2020, what we need to prepare for is continued strong demand for gas in Europe, but as Elisabeth said, more volatility, primarily driven by LNG demand in Asia and the increasing share of intermittency or intermittent power generation here in Europe. The dark horse in all of this will be Asian demand for gas, in particular Chinese demand. And as Elisabeth pointed out, there is a possible supply overhang of LNG. But I think this is at least the third year that we have cautioned about a supply overhang and what that can do to prices. And we've been surprised, if you will, on the positive side every single year. New supply is much more easy to predict than new demand. The bottlenecks on demand are unplugged more quickly than the bottlenecks, if you will, on supply. So I lean heavily on and trust Elisabeth's analysis, but I just remind you, we have been surprised on the upside previously. Anyway, we need to be prepared for all different outcomes. And we do so primarily by preparing new and competitive supplies of gas into the market. And we do have the most competitive offering of gas into Europe. There's no one can beat us on cost to market, including US LNG. And we do that by utilizing the flexibility. We have an ability to flow and flow between the main European markets. And lastly, by strengthening our trading capabilities, creating further market opportunities also for our equity volumes. So our Norwegian gas continues to be well positioned to supply competitively into the European market. Through the flexible gas machine, as we like to call it, it is 10,000 kilometers, I say 9,000 plus kilometers of integrated pipeline system, where there are 40 producing fields bolted onto this integrated system. It's the world's largest offshore integrated delivery system for gas. We can provide gas to all the main markets, and we can shift between these markets as the demand slash pricing signals dictate. In 2018, we took further steps to maintain the competitive position of the NCS. And we are on track to maintain a very high and profitable send out at roughly current levels towards 2030. And in August, as Irena alluded to, we presented a strategy for more gas exploration. And over the next 10 years, we are planning on drilling up to 3,000 production and exploration wells on the NCS to deliver on this ambition. Also late last year, just before Christmas, we had a new field starting up. The field is called Ostahans. Don't you just love these Norwegian field names? It rolls so easily off the tongue. This is a remarkable field in many ways. It's very deep water. It's very far up north. So it meant we developed our infrastructure delivery system much further north than what we have done previously. So it opens up a new province of gas in the North Sea. Then the 482 kilometer pipeline that connects this field to the new Havanagh receiving facility on the West Norwegian northwest coast constitutes the northern leg of what then becomes a 1,700 kilometer gas highway from Ostahans then in the north to the UK market in the south. And once you've taken these fundamental investments in infrastructure, it means it's much easier to bolt on new reserves that lie close to this pipeline tranche at very competitive terms. Furthermore, before Christmas, the Norwegian ministry... Oh, no, just before I quit on Ostahans, Ostahans then is now at peak production or plateau production, 6 BCM. But that plateau will increase towards seven and a half over the next few years. Now, then in addition to this, before Christmas, the Norwegian ministry of petroleum and energy approved the plan for development and operation, so-called PDO of the TROLL Phase 3 development. And for those of you who are not familiar with what TROLL is, TROLL is the biggest gas producer on the NCS, currently providing roughly seven to eight percent of total European gas demand. And with this Phase 3 development, this will extend the productive life of TROLL to beyond 2050, at which time I can guarantee you I will not be standing at this podium. Turning to LNG. Now, although our European gas market is exposed to the global energy market, we are a small player in LNG per se, but as Irena said, we do live with the exposure of LNG, even if we have a low LNG share through the interconnectivity now or the interlinkage of the markets. However, the flexibility of our LNG portfolio provides us with quite a lot of optionality, commercial optionality, that we utilize quite extensively. And as for natural gas, we add some third-party trading to support the equity portfolio we have. We delivered LNG to most continents in 2018. We had 58 cargos. 90 percent of this came from our Hammerfest and Snervit facility. I'm a bit ahead, aren't I? I think the slides are in slightly different sequence there. Okay, anyway. So let's see if it now matches. Yes, here. Now the slide matches the text even. Turning to the US then. Of course, outside of Norway and the activities we also have in Brazil, the US is one of our core production areas. And onshore in the US we operate fields in the Barkan area, the Eagleford area, and the Marstellis area. And we are now producing roughly one BCF per day, which equates to roughly 10 BCM annually in the US. And the positions we have in the Marstellis-Yutica area alongside the transportation infrastructure, we have out of those areas, or the aggress we have out of those areas that constitute the backbone of our natural gas marketing operations in the US. And as the map shows, here we have long-term export capacity to the premium consumption areas, both around New York, Toronto, and in eastern Canada. And starting from Q1 this year, we have also secured new capacity going south, which will secure access to the US Gulf Coast area, a market with industrial growth using gas, exports of LNG, and also exports to Mexico. And our production, then combined with the long-term transportation we have into this region, enables us to take out the full value also of these premium markets. I'll be excited to see what comes up. Yeah, okay. That looks good. Back to Europe. We just heard Elisabeth say that 2018 was a very volatile year. We saw gas prices moving a lot by factors like weather, radiation demand, and also by the intermittency in power generation. And going forward, and as gas in the power sector increases, this volatility might very well increase further by the increase in intermittency that will need a gas response, so to speak. And we are actively responding to the changes we see in the gas market. Now, as you know, or as I think Elisabeth, most of you know, our gas sales today are based on a basket of different indices, mainly to reflect the demand we see in the market. And over the years, of course we went from long-term contracts with oil indexations to what we have today, i.e. pure gas indexation. And at every turn when we made these changes, we've also realized further commercial potential in our portfolio. Now we're changing how we price into the market again. We will be through 2020 now, tilting our gas sales towards day ahead and month ahead indices with a weighting on the former over the latter. And then as we get towards 2020 and beyond, the realized price should mostly reflect then the short-term market indices. And we do this because the demand also for longer-term indices is fading away. But we also do this because this gives us the flexibility to manage our portfolio differently. It gives us the possibility now to have a larger share of our total gas sendout benefit, for example from events like the Beast from the East that we saw last winter, and also from spiking in the market for other reasons. It also enables us to actively risk-manage the total portfolio we have better through hedging positions and otherwise taking active positions in the market also. So what you will see in our reporting is a gas result through the realized prices in our upstream unit that largely reflects volume times short-term indices. And then you will see a gas result in the downstream part of Equinor or the M&P part that largely reflects the deviations we choose to take from those short-term indices when we choose to actively manage the portfolio. And that is an important change to us. Don't expect that this will create massive windfalls, but it contributes, if you will, to what Irene just said about expectations to be at the higher end of the value delta we report. Turning now to Danske commodities. And this is something that is sort of on my plate and agenda every day now. It is in a critical phase. We just passed Financial Close first of January and I think it is the most significant step towards developing further commercial capabilities that we have taken, if not ever, than at least for a long, long time. And this is an acquisition of actually one of Europe's largest short-term power traders, but they also have a significant gas trading activity as well. I will dwell a little bit upon that. Irene gave you the key rationale for why we are doing this and it is associated with our high ambitions on the new energy side and our belief that we are not able to deliver fully on that unless we also have the full commercial capabilities to take this out to the market and also take the margin that lies beyond, if you will, the power purchasing agreements. And what then is it Danske commodity delivers in terms of this? They have a market presence in basically all European power markets. So they have a scale of operation. That means that anything we do in Europe, we can more or less bolt on to the capabilities they have and the existing presence they have. They have competence that goes much deeper than what we have had in Equinor within this space ourselves. That also enables them to be, if you will, the leader of the pack today out in the European power trading scene. They have state-of-the-art systems to manage their power portfolio. And that is something we will benefit from both in terms of the power trading they do but beyond that also. I will turn to that. And of course this is a company with a proven track record. They have demonstrated year after year after year that they are able to turn healthy profits and have actually grown profits quite consistently. When we combine then the power portfolio of Danske commodities and Equinor and all this, by the way, all the power we handle will be handled by Danske commodities going forward. We marketed and traded 300 terawatt hours in 2018. Now, we have to wait until the end of 2019 before we can say we really had the shared portfolio. But it says something about the order of magnitude of this. But this acquisition has value to us beyond the strategic rationale linked to power. Again, because they have state-of-the-art systems to support the business, we believe that they can be utilised also for the main part of our gas business. They are very advanced in algorithmic trading, use of machine learning, and through that can also contribute to the rest of our business, including the gas business. We say jokingly that what we have acquired is really an IT company with traders. So they place that much emphasis on technology and to be in the technological lead, if you will, or vanguard of the trading business. So far, and this is before the financial close, before we could really look under the hood of this company and what it was, we had already identified 15 million euros of synergies on the Paris side alone. This is before we factor in, they call it the strategic value of having this capability in terms of future projects in our NAS portfolio, and also before we start factoring in and realising synergies on the gas side. And then also on the basis of the strong EBIT that this company provides, we are actually very happy with the acquisition price of 400 million euros that we paid for it. And for those who are concerned about that, that Equinor will sort of drown out the unique DNA of a company like this. We are very cautious about that and will be very nimble in our approach. We want this to be something that we can learn from in the rest of our commercial activity, rather than something we drown out. Now to conclude, I was responsible then for trading and marketing of natural gas and power. In Equinor, my focus this year will be to develop our capabilities further by, amongst other things, capture the synergies related to our acquisition of Danske commodities, to implement the new pricing benchmark and our revised approach to risk management, and to continue our progress within ALGO assisted trading and machine learning. And all this to support our main priorities to end off where I started, which is to bring our production to the market on time and in accordance with our commitments, to ensure that we capture full and fair market value of this production, and lastly to trade, to generate additional margins and to support the value of the equity portfolio. And with that, I close and thank you very much. Thank you to Martin and thanks to everybody. I'd like to thank all the speakers, Irena, Eric, Elizabeth and to Martin. Personally, I'd particularly like to thank Irena, who you may know, she's struggling with a call today. So we talk about commitment to our shareholders and I think here we are in physical form. So thank you very much for being able to do that today. Now, we'll do some questions around, there's an opportunity in this session here and also afterwards as well over a drink and an expensive sandwich. And also if we have any coming in from on the web as well. So we're fairly small here. If any questions, please raise your hand. I saw you first, Michaeli and then John and then we'll go around the room. I think it might be if you're able to... Yeah? Oh, okay. So I'm starting right in the way there. Thanks, Michaeli. Thank you. Thank you for the presentation. Two questions, if I may. The first one relates to your power trading capability, which you are now building up with the acquisition of the Danske Trading. Historically, you have always had trading around physical assets in oil and in gas. Do you think to be successful in power, you will need physical assets as well and not just some of the renewable power that you're building but also gas fire power stations. Secondly, on the long-term versus short-term selling of gas, could you lay out for 2019 how much effectively is the split between what you will sell on a one day, one month forward versus what you sell effectively six to 12 months forward. And given that you lay out a short-term bearish view on gas for 2019, would it be rational to assume that you sold more long-term in 2019 than what you intend to do longer term? Thank you. Last one, and I can take the first one. Yeah. So, the basket of indices we have will roll off through this year, as you realize every day of the year. To the extent we hold on to some of those indices beyond 2019, that is because we will then have an active market view on longer indices being better than shorter indices. But we won't do that for all the portfolio. You will see that rather on the margin than you will see it as shifting the entire portfolio onto longer indices. Just a comment on the physical assets for Danz Kukomoda. They're actually also trading around physical assets already. One of their main businesses is actually trading around interconnector capabilities. So, they'll take short-term interconnector capability or capacities and trade around the geographical differences. Going forward, they will trade the power out of our renewable assets. And we are certainly hoping to grow that one. And I also do think there is a very interesting and emerging scope with the corporate PPAs. Selling renewable into which we're hoping they're going to help us develop such a capability, I think. Next question is John, and also I've got to try and go behind as well. Thank you. It's John Rigby from UBS. Three questions, actually. The first is on... Sorry. They are related. The first is just on the structure of pricing as we move forward. I mean, you alluded to the increase of U.S. export capacity rising, but also indicated and flagged up that Europe has effectively traded against Asian pricing, and therefore, by virtue of that, really oil prices, I think. And that was sort of implicit in that chart that you showed. Do you think as we move forward, we're going to start to see a sort of bifurcated year where Asia influences sort of winter pricing in Europe, and the U.S. influences summer pricing in Europe because of the nature of exports and seasonality of demand, or do you think there's a seasonality of supply as well? The second is just on China, into your demand numbers. Do you get nervous in terms of China? You, I think, alluded to an 8 BCM expectation and a 20 BCM outcome. A lot of that's driven by policy. Even within the year, demand was driven by, I think, inventory buying in the summer, which I think the Chinese did in reaction to a shortage of gas in the last winter. So, again, I think people got carried away with demand rolling through 2018 and were disappointed in the 4Q. And then just one sort of more philosophical question is, you talked about trade disputes and highlighted the fact that the Chinese had put tariffs on U.S. LNG, but U.S. LNG is just a commodity like any other and therefore can be substituted by supply from somewhere else. So do you think that's all a bit of a sort of a sham and a hoax and actually is that kind of thing doesn't really affect either oil markets or gas markets in the medium term? Thanks, and thanks, Peter, for your indulgence. Well, they all connected on the gas market. Yes, they need some weather and you take the cosmon. Okay, that's fine. No, I think on your first question on how these different regional markets will interact during the season, I think part of the story here is it's difficult to say something systematic about that because the seasonal variation will depend on the local weather every season and the local expectations for weather. And what we are seeing is, of course, that to the extent that we have interlinkages between these markets, now the fact of being established, there will be much less scope for regional price variation at any given point in time. And then you can have during some periods of the year, it's the impact of the Asian prices that comes into Europe because of differences in weather conditions, et cetera, et cetera, and supply disruptions. So I think the main story is that it's difficult to see anything systematic here happening due to the fact that we suddenly are more closely interlinked with Asia and have access to US supply. But then, of course, depending on how the market actors see that from every season to season, you can get surprises. And to be prepared to be surprised is a general piece of advice, I guess. On the trade protectionism and the signals in terms of tariffs, et cetera, et cetera, on the US LNG to China, I mean, it's tiny, has absolutely no impact on US exports or revenues, and it has hardly any impact on Chinese gas demand or gas costs as well. So this is part of politics. It's an important signal to the extent that it signals a greater concern on the Chinese side and potential for more tariffs on other types of trade. As I showed you in the chart, I mean, there's a massive imbalance here in terms of how much the United States imports from China and vice versa. So relative to the size of the economies, it's the imports in the United States from China that is sort of the big market here. And then, of course, any kind of tariff, as you say, it's a global commodity, and if LNG as a consequence of higher tariffs doesn't become competitive in China, that LNG will move elsewhere. So it's at the margin will then contribute to a slightly weaker global market, in a sense, but a more tight market in China, and they have to get their gas elsewhere. But the general worry is, of course, that this protectionism movement that we see now will increase risk premiums, it will increase or decrease consumer and business sentiment, and it will lower economic growth compared to what we otherwise would have. Do you want to talk to the slowing demand in China? Yeah, I can touch upon that, because as I said last year, we estimated a growth in China for around 8 BCM on the LNG side, which is similar size as we also see going forward. So I would say that it was a very strong surprise to the upside in 2018 with going to 220. So I think it's, I'm not too nervous on the growth, it will be muted compared to 2018, but that was really exceptional with the growth we saw then. Odo? Thank you very much. Yeah, just some of your assumptions, obviously with Europe, you're implying a greater import dependency from LNG into Europe, and one of the assumptions underpinning that is Russia being stable, you said, at 35%. So I just wanted to understand why you think Russia will just allow that to happen. It's obviously that perennial question, will they remain with a stable position? What intel do you have that leads you to believe that will be the case? Perhaps just linked to that, what do you expect for the Ukrainian pipe negotiations at the end of 2019? Now, my second question was more flipping over to Brazil. You talked about this offshore Norwegian gas system, the largest in the world, but you also said significant gas offshore Brazil. I remember BG talking about this 10 years ago, a BCF of gas for every billion barrels of oil, and maybe they weren't the right company to develop that. So what steps are you taking? How soon do you think you can do something meaningful with offshore gas monetization in Brazil? You want to take the last one? I can definitely take the last one. I can take the first one, and we have an expert in the back doing the second one. So just a general comment to Russia. I guess we worked alongside them for 50 years, and they've always behaved rationally, and they've never had any intention of overflowing over flooding the market with gas, and we see no indication of that going forward either. I think the general story is, of course, that there's a bilateral dependence between Russia and the EU, and they've been depending on the market, and we're depending on supply as Europeans. We don't have any specific intelligence, but there's something about being, at least if you look at this as an economist, it's with an LNG price, delivering a price level to Europe, it is fundamentally in the interest of the economic players delivering gas that allow that LNG to be part of the market. And then the question is, of course, to what extent, what are the short-term costs of potentially increasing your exports if you see a market that is growing an increasing import gap, or do you allow that to be stable? And then in the balance of our analysis, we assume that the Russian exports will be relatively stable, and then the LNG takes the swing. If you have supply disruptions coming out somewhere, then somebody has to step in. In general, that is those players with most of the flexible capacity. You have an analyst at the back to maybe... But also with respect to Ukraine and discussions. No, I... There is kind of not so many things which I can add on what you already said, so this doesn't make sense to afford the Russian supply to just flow a lot of more gas just to kind of dipping the prices. So I think they will then act rationally. Also, there is a question of the export capacity available, so even so they want to flow more, there is also limitation how much they can flow. On the Ukrainian situation, I mean on the transit arrangement, which has expired by the end of this year. There has been quite a few rounds already. There is also a new expected round of negotiation, which is going to be in May. What we think at the end of the day, maybe the parties will agree because the both parties desperately in need for this arrangement being placed, for gas problem, also for the Ukrainian route. So it probably will be delayed till probably the last day of this year, but we expect that it will be in place. Maybe not the long-term arrangement, maybe for a year, short-term arrangement, with different... Not booking the full capacities, but we expect that it will be in place. Because if not, there will be a serious disruption of gas coming into Europe because we don't expect the North-term tour to come on stream until maybe 2021. Yeah, Brazil. We have a significant amount of associated gas with our Caracara field, and we also have a gas condensate discovery in the Pou de Sucre. I think Margaret said at the Capital Market Update that for the first phase of Caracara, we're going to re-inject the gas to increase the oil recovery. But there's going to be at least the second phase and maybe even the third phase of Caracara, and definitely a BMC 33, Pou de Sucre, needs gas monetization solutions. And we know that Brazil is underdeveloped, I guess, when it comes to utilising gas in the market. So we're almost back to where we were when we started developing the Norwegian Continental Shof. We need to develop infrastructure from the offshore installations to shore, and we might even have to stimulate, I guess, demand through investments or partnerships with gas to power plants, petrochemicals, plants, etc., etc. And we have a strong team, and to Martin have some people down there. We also have some people who actually were almost part of developing the Norwegian Continental Shof. There's some serious confidence down there. So we remain optimistic and see this as an opportunity to add value to the Brazilian assets. But it's not straightforward. Question at the back, and then we'll come forward. Hi, my name is John Toomey from Bloomberg, and I have a question mainly about troll. So we talked a lot about, in the past, Econor have had the mantra value over volume, and also we talked a lot about utilising the flexibility in portfolio. The second thing we talked about is a particularly bearish outlook potentially for European gas prices this summer with high storage and lots of LNG. My question is, what are the kind of economics that you're thinking about to utilise the flexibility in troll? And by that I mean, deferring production from summer 19 to summer 20. What type of rate of return would you be motivated to think about that decision? Seems like the Bloomberg colleagues are well coordinated because we had that question earlier, and Tomohdin answered it in a good way, so I'm going to let him. So I think I have to start, if you will, rather more technically because otherwise I can't follow the logic towards the end. But the troll field is a field that has a given daily production capacity. But the Norwegian Ministry then has said that you can't utilise that full capacity every day of the year because the outtake from the field then could then undermine or reduce the oil outtake, not on a day-by-day basis, but the total oil we could get out of the reservoir. How much interconnection is there between these reservoirs? So they said, you can't utilise the daily, Max. We'll give you an annual production quota, but you can swing within the day as long as you don't exceed the annual quota in total. Now, over time, as we've gained experience, there's less and less concern that there is, if you will, this link between gas outtake and what you can get out of the old part of the reservoir. So over time, the Ministry has granted us a higher annual take out of troll to the limit where there's now very little, call it flexible capacity left. Our default is always to, on all fields, produce flat out. We are a price taker, but as I also said, we do have the most competitive gas into this market. So if anyone should turn off the taps, it should not be us. And then in addition to this flexibility now being reduced, there's still a little bit left, at least for the time being. But we operate that flexibility on the basis that you can take out more one year, provided you redeliver that flexibility you utilise another year. We are now in a redelivery year, so you will see that the technical flexibility we have is even more reduced than it would have been otherwise. So don't expect anything big from troll in terms of additional value from utilising the swing, unfortunately. Question from Danny. Hi, it's Danny from Barclays. I have got two really quick questions, if I may. So both related to your 2020 ambitions for MMP. So the first question is, you talk about a 4% reduction in emissions. Do you think it is enough given dense commodities? And the second question is related to the digitalisation. So I'm wondering, could you please talk about potential cost savings from this? Thank you. I inherited the 4% emission reduction when I came into MMP. I think there is more to gain. And I think there is more to be proud of than just the emissions from our own short plans, which this target is related to. Because we are doing tremendous work on reducing emissions from the shipping fleet. A lot of our new shuttle tankers are now running on LNG. That's not counted into that number. There is the potential to electrify some of these plans. So we have established a team that are developing an MMP climate roadmap that will look into CO2 emissions from all our assets. But also potentially if we can run our refineries slightly different, etc. So I think there is more to be had than more to come on that. Could I just add on that? We are the first operator to have actually hide in shipping capacity very large gas carriers fueled on LPG. So that's the first in the world also, which will contribute further. So both LPG and LNG. And we are introducing much more batteries in some of these vessels as well to reduce the emissions. Then on digitalization, what are the numbers? We have not quantified what we think the numbers are as of today, but they are significant. I was quite impressed when I was on a dance skit to see how they have actually developed the capability. Did I have that picture? So you are down there and each trader is sitting there with 15 screens. And they are trading at 15 minute intervals. And you just understand that the human capacity is not enough to really grasp all this information and act as quickly. Which is something they have taken into account. And they have a very active algo trading system. So I was sitting there and they are watching six trades come in again. So that's why they can do 4,000 trades. And we have an untapped potential here. Or the whole industry I think has an untapped potential in this respect. But like I also talked about the plans, opting the regularity, getting down the cost, getting down the tariffs, it's significant. But maybe next year I will have a number. They will just have bought the screen. But I guess it's fair to say that whatever the synergies we can get out of this, or the benefits we can get out of this, it will happen a lot faster due to the fact that we now have dance skit commodities and their capabilities on board. We also led an industry coalition I guess of starting a start-up called VACHT who is developing a blockchain technology for a trading business. So very soon we are going to start implementing some of the procedures that they are developing. Another question in the hall from Arlan. Hi, can I just talk, one thing you mentioned on the way you may change your gas realisation due to the new businesses between upstream and downstream, sorry an MMP. Could you just maybe clarify that comment again? Have you put it on your earnings? And then just to follow up, a couple of questions. The one area that wasn't really discussed very much today was Africa. So I was kind of interested to get your thoughts looking forward there. And on the technology side, what you see on the implement, how you think the effect of or possible implementation of carbon capture and storage will impact the markets over the next 20 or so years. Thanks. Do you want to give a go on the transfer price? So we want to go from passive management or the portfolio, i.e. you get the value of the gas with the indices you have chosen to have and then that's it, to more active management. And that means that the active part of this handling will be sitting in our unit. They call it the passive indices and the result of that in terms of realised price is what you will see with the upstream. So you will see in the upstream a volumes times price and price then being a combination of day ahead and month ahead. You know what you get, if you will, as an analyst there. And the weighting will be more towards day ahead than to month ahead. And without being able to give you a precise number, we said roughly two-thirds on the day ahead and one-third on the month ahead. And then any deviation from that, and there could still be deviations. Those will be deviations as a consequence of an active view of the market. And then that could mean we could convert some shorter indices to longer indices because we believe that is sensible for whatever reason. And that's in a sense what I meant by that, if that makes any sense. Yeah, okay. Yes, you can or I can. I don't know if you were alluding to the Tanzania LNG project or more to band in Africa or... Okay, well then I'll leave it to you. Yeah, I guess on Africa you can take one look at the supply side. There's potential for new gas coming out of there, Tanzania being one example. It's bound to be much slower than it would have been in many other regions if you look at Africa as a whole because of lack of infrastructure and a lot of uncertainty, lack of regulation. On the demand side, Africa is still extremely small, unfortunately. It will double its population over the next decades. Strong economic growth but from very low levels in terms of energy demand. You'll see significant electrification hopefully with a lot of decentralized renewables. Should be a lot of potential modernization which also would increase the role of gas in the overall energy picture in Africa. But also that there's an enormous potential for increased energy efficiency and that will then limit the demand growth for primary energy if you like, if they're able to realize that because it's an extremely inefficient use of energy as they have today. So you won't see Africa making a big dent in global primary energy demand anytime soon. Unfortunately. A few comments I guess on CCS. In any of the scenarios that Eric and his team is developing and IAA and everyone, there's a significant amount of carbon capture and storage included to actually meet two degrees, one and a half degree scenarios. But it's not really happening. Why is it not happening? I think primarily because there's no CO2 price and incentivize it. We are working together with the Norwegian government, which are intent on developing a full-scale CCS project in Norway with the intention to capture CO2 from industry, not from a power plant in any form or kind. Because the industry doesn't really have an alternative, a power plant you can exchange with renewables, at least in an ideal world. But the industry, like a fertilizer company or steel producer, an aluminum company don't have alternatives with capturing that. Shipping the CO2, which is key because it opens up for flexibility and then storing it under the Norwegian continental shelf. The intention is also to further develop this as a third-party storage, meaning that you could go to Rotterdam, you could go to Teeside or some of these heavy industrial-relized areas and pick up CO2, ship it and store it in the same location. This has not been decided, but it's actively worked and we are partnering up with Total and Shell. Taking it one step further, this will also potentially allow us to convert natural gas into hydrogen. So instead of having post-combustion CCS on a gas for our power plants, we would do pre-combustions CO2 capture basically and deliver hydrogen to customers. Whereas that would be a power plant, whereas that would be for industrial use or even in the transport sector. These are things that are not happening any time soon, but these are things that we feel as part of our expansion into a broad energy company, has to take a lead in. Because we have significant and probably the most experienced in the world with a common capture and storage, having stored CO2 at the Snovid field, having stored CO2 at the Slapenov field for years. So this is what I alluded to, that potentially gas can also be a destination fuel, not only...