Hello, ladies and gentlemen. Welcome to the 2019 edition of the Equinor gas seminar. It's a real pleasure to welcome you here today. Same address as we did the CMD, different venue. Bit like being back at school, but hopefully we can be a bit more interactive than you used to be in those days. For those of you I'd 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 Copthall 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. Also, as we've got no phone lines connected, if you're not here and you're watching on the web and you've got any questions, please send those questions through to Eirik at irpost@equinor.com. We will put those questions through during that session as well. With that, let me ask Irene Rummelhoff, EVP of Marketing, Midstream & Processing, MMP amongst friends, to open the gas seminar. Thank you very much.
Well, thank you so much, Peter. This bit is an awkward stage here, so I'm not sure where to, it's good to see so many of you, quite a few familiar faces, and I think we have a pretty intriguing program for you today, so I hope you enjoy it. 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 new energy business until August this year.
I assume most of you follow the CMU a couple of weeks ago, so I'm not gonna bore you with the details from that, but I'm gonna do 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 rate of 3% towards 2025. We also announced that we increased our quarterly dividend by 13%. I hope we gave you some comfort that we're progressing along our strategy.
Always safe, high value, low carbon, on our 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. 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-, proving that we are, at least for now, in the forefront. The top main topic today gas is absolutely part of that solution.
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 U.K. 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 German 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. Maybe more importantly, we saw Angela Merkel at 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. This is something we have anticipated.
This is something we talked about for quite a while, and now it's happening. Lots of uncertainty around the energy transition. There's one thing I think in all of this that is pretty certain, and that's that demand for energy is growing. The world needs to produce as much renewable solar and wind as quickly as we can. We're part of it. The world also need to develop more oil and gas resources. 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. Something needs to fill that gap. That thing that needs to fill that gap need to be with the lowest carbon footprint available. What does it mean to be a broad energy company?
We talk a lot about that. 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. We're 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 assembled quite a significant asset portfolio. We have seven onshore plants 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 20 and 90 vessels, and we've got something like 1,100 rail cars that allow us to transport our products to premium markets. Last year, we sold 800 million barrels of oil, making us one of the largest net sellers of crude in the world. We sold 100 BCM of gas, putting us in a position as the second-largest gas supplier to Europe. With the Danske Commodities acquisition, we're actually now positioned also as one of the largest short-term traders of power. More surprisingly, maybe, is that we also trade about 10% of all the water-borne LPG in the world, and we are marketing about 10% of the methanol demand in Europe. Martin will come back to more details on how we trade and manage that portfolio.
He has also touched upon Danske, but I'd 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 with the rapid cost reductions in renewables means that renewables are in more and more markets reliant on market prices and merchant risk. 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, no, EUR 400 million for it.
Last year, their EBIT was or are estimated to be EUR 80 million. As the new head of MMP, I've spent most of my time trying to be close to the people and business. I've traveled to all our onshore plants, and I think this is really where you see our strategy always safe, high value, low carbon come to life. Meeting all these wonderful and very motivated people, I think it's. We'd say safety is number-one priority, but when you've met all these people, it just becomes very, very natural that you wanna take care of them. It is no doubt number-one priority. 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 guided you, guys, I guess, on the market and also internally that we think our results gonna be somewhere between $350 million and $500 million on a quarterly basis. We're 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-backed trading strategy. We have Danske Commodities into our portfolio, and so Martin will come back to that later, changing the way we market our gas. 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 $2 something at the Northwestern Europe these days. Not an entirely new guidance, but at least an indication that we think we're gonna be in the upper half of the current guidance. 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. 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 about energy efficiency, so it's a true win-win. Most, well, all of Equinor have gone through a tremendous cost reduction of basically totally reset our cost base over the last three-four years, so have we in MMP.
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 focus a lot on big data analytics, algo trading, blockchains. On the more operational side, we're focused on drones, automations, 3D printing. I'd like to give you a small example. It's a tiny one, but it nevertheless tells you something about the future. On the Kårstø plant, well, some time ago, we needed a new impeller. You might not even know what an impeller is, but it's a kind of a steel beam that you put around some equipment.
You know, we called around and as they said, "Well, it's gonna take us 12 months to get there, and it's gonna cost a fortune." 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. This is today, and can you just imagine the development we're gonna see within 3D printing? If any of you are sitting with shares in impeller business, I'd rather sell them more or less immediately. 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. That's more than $2 billion a month. Quite staggering and a bit scary, I guess. 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 $1.50 per million BTU, and our gas also comes with very low methane emissions, less than 0.3%. We do have reserves to supply Europe for quite some years to come. I think that was announced at the CMD, upped their recovery factor ambitions on our gas assets to 85%. We sanctioned Troll phase III, which will produce gas way beyond 2015 last year. We also put Aasta Hansteen on production late last year.
That's quite an intriguing field because it's opening a new gas province up in the North and Norwegian Sea. If you recall one of the slides from Arne Sigve's presentation at the CMU, where he talked about the largest unsanctioned projects on Norwegian Continental Shelf, 3.5 of those, I guess, were gas assets. Arne Sigve Nylund also talked about an active exploration campaign for gas on Norwegian Continental Shelf. Our gas business is also becoming more international. We're well-positioned in the humongous, I guess, Marcellus field in Northeast U.S. We're seeing that we'll get an enormous amount of associated gas coming out of our asset portfolio in Brazil towards a market with a tremendous potential. Through our LNG business at Snøhvit, we are already selling gas to
Well, last year, I think it was 20 different countries. Interestingly, and this is something I believe we've told you before at these seminars, you no longer need to be in the LNG business to get exposure to LNG prices. With LNG 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. We had very high Asian prices, about 11-ish for a while. European prices were 9.5 at that point in time. More supply came to the market, and unfortunately, Asian prices went down and also European prices went down. Of course, we'd love to have more energy into our portfolio, but we certainly do get quite a bit of exposure to those prices anyway through our gas position.
With more LNG coming into Europe and more and more intermittent renewables, I guess we're seeing and anticipating more volatility in the gas markets going forward. Volatility is always something the traders like. They're excited about it and see that as an opportunity. As a result of that, we are changing our gas strategy. Martin will definitely talk more about that later on. The point is we're moving more towards the shorter indices, and we're gonna have a more active management of the way we market our gas. 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, reduces immediately emissions in the power sector with 50%-60%.
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. In short, we need both electrons and molecules. We believe that we in Equinor are well-positioned and well on our way to developing ourselves as a broad energy company. Now I'd like to leave the word to Eirik, who's gonna talk about the macro picture, and then I'll leave it to Elisabeth after that, who's gonna give us more detail into the development of the gas market. Thank you for the attention.
Thank you, Irene. 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. Towards the end, I'll remind you of what is possible developments in the 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 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. 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. 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. 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. We believe that the gas demand going forward is gonna 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. The slowdown in the advanced economies will hamper growth in these emerging economies. 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. Then that adds to financial stress, given that they already have large fiscal imbalances, large negative trade imbalances. A higher U.S. interest rate, the ongoing trade conflict and policy mismanagement have all contributed negatively to the currency crisis.
The so-called 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. In a situation without trust, that becomes an increasing challenge. Other factors affecting the situation, and that also causes capital flight or at least less capital imports, are the reduced global economic demand or the slightly lower growth in economic demand, in global demand. As a consequence of the foreign exchange movements and increasing burden of their energy bill, because these are energy importing countries. Some examples here. In terms of Argentina, we expect economic contraction this year and, both as a result of last year, but also this year.
There's 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 risk as to how these reform proposals will go through, and what will be the short-term impact on the economy as they change. 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 sentiments.
We don't get the help from some of these large emerging economies in driving overall global economic expansion. We're in a situation of protectionism, increasing protectionism driven by the United States, exemplified by the exits from the TPP, the renegotiations of the NAFTA treaty. Since the beginning of the summer of 2018, trade tensions have intensified and several import duties have been imposed by the U.S. As a consequence of that, tit-for-tat retaliations by some of its trading partners. 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 retaliated by tariffs on U.S. imports of $110 billion, including LNG.
Where the United States is still formally contemplating an increase in tariffs on another $270 billion of imports. At the same time, in December, they agreed a 90-day trade truce, making a shift for the positive. Look, it looks as if it might become slightly less a situation of conflict, where they have plans to reach a deal by the March 1 , 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. Of course, if these trade tensions further escalate, international supply chains and small open economies will experience challenges.
In a worst-case, full-blown trade war scenario, IHS has estimated that economic growth globally could lose as much as two 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. In the case of China, the LNG actually going to China is very low, very small. 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 the this type of trade tension if they were to occur again. As noted by, also by Irene, LNG is now the main mechanism that links global gas markets.
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. We see tendencies of that already in terms of the short-term markets. 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 very dependent on one or two physical pipelines. They, 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 secure, 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. You have the Russian sanctions since 2014 as an example, and the recent U.S. proposal to stop the Nord Stream two investment is an example of the geopolitical aspects now affecting gas markets more than previously. Iran has been subject to sanctions from 2006- 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, tragic example, of course, but it's gas market or a gas supplier that has not delivered since 2015 as a consequence of the war. The U.S. protectionism now calling for increasing LNG deliveries to Europe and Asian markets to improve the U.S. trade balances. At the same time, threatening or putting tariffs on LNG exports to China is an example how the, how these geopolitical developments could affect markets. Brexit, it's a development that would mainly affect U.K.'s trade relationships at an operational level.
Of course, the general uncertainty there has impact also on larger global markets like oil and gas and other types of trade. Finally, on the map, we're in partly on the map here, another uncertainty would be the North African situation where North Africa is an important supplier of gas to Europe. The geopolitical uncertainty 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. 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 neighboring countries is an example of.
Another geopolitical or global issue that Irene Rummelhoff was referring to that affects all international oil companies strategy developments at the moment, the carbon challenge. Now 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 U.K., we have carbon prices in addition to the ETS. In the case of Norway, we experience one of the highest carbon prices in the world with a 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 U.K. power sector, where the carbon price floor has strongly contributed to the reduced coal electricity generation. As Irene said, you're the lowest emission since Queen Victoria. Congratulations. 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 U.S. states. 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.
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. 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. You know, we have three long-term global energy scenarios to 2050 that we publish in our Energy Perspectives report every June. Irene showed at 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 see up to, 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. We will become more electric.
Transport, the dark blue up there, becomes a new visible source of electricity demand due to electrification of light-duty vehicles, et cetera, et cetera. You can see in the middle that new generation capacity will overwhelmingly come, we think, in all scenarios from wind and solar and a slightly some increase also in geothermal. 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. With gas 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.
The decline in gas demand from electricity is less than what the market share would indicate because the market grows by 60%. The gas demand from electricity declines, but not that much, as you can see in the chart. 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. Solid growth has robust growth as I said.
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 Irene Rummelhoff reminded you. In all scenarios, look to the right, we have significant growth in Asian demand. 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. That's even in a world where we actually reach the climate targets.
The consequence, of course, is that there will be large changes in gas transport from surplus to deficit regions, even if China, as an example, also would grow its indigenous production significantly. 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. 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 three very different supply-demand balances in different regions. The United States, and therefore North America, is already well on its way to strengthening 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. The reason is that the indigenous supply is declining. In the case of Netherlands is one of the best examples, and I know, and most recent data now show that the Groningen 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. 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.
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 from other parts of the former Soviet Union as well, and significant need for LNG imports. I mean, the long term, the growing LNG market is absolutely necessary to close these regional imbalances in the same way that oil transport currently does. We see a globalizing gas market. Finally, just to remind you, on the need for new investments in new supply, if you like of gas. Without supply, without investment, supply will fall possibly by 5% per year, 3%-6% per year is what we illustrate here.
That means that the supply-demand gap opens very fast if we don't invest. There's a significant uncertainty in that gap already to 2025, depending on what you think about decline rates, 1,000-1,700 BCM already in 2025. Then as this, as we go further out, the gap becomes enormously big. Then depending on the demand scenario you have in mind, the size of the challenge becomes different. 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%-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.
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 United States over the last 35 years, you have to up that by 60% to get the figure for new, potential new gas supply over the next 35 years in a two-degree scenario. If you don't believe in a two-degree scenario, the challenge is even bigger. Of course, those investments don't come by themselves.
They need capital, and they need price signals to ensure sufficient investments. Those price signals we hope are there. Now Elisabeth will tell you more about at least short-term price signals. Thank you.
Thank you, Eirik, 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. 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. First, I would like to take a look back to refresh what we said a year ago and how that turned out. What did we say last time around?
Well, firstly, we said that gas will be an important flexible source for electricity, both in the U.S. as well as in Europe. In the U.S., 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 U.S. 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. Due to new environmental regulations, we have seen a number of older and less efficient coal plants retire over the recent years. The share of gas in the U.S. 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 U.S. LNG exports. The global demand for LNG in 2018 was driven by Asia and China in particular. China is phasing out coal in favor of gas in some regions to reduce local pollution. Last year, we indicated an expected growth in Chinese LNG import of around eight bcm. The year-end numbers show an increase of more than 20 bcm, and that's three times the new U.S. LNG capacity added last year. 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. 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 per million BTU. Then after a normalization of the price levels in Europe in April, the gas prices continued increasing consistently through Q2 and Q3. This price increase was linked to several factors. Firstly, it was an overall rallying energy complex with coal, oil, and CO2 price 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 a high level of maintenance, both on the NCS pipelines as well as on the Russian pipelines, which limited the gas availability to Europe. Finally, it was due to limited LNG availability in Europe due to the strong Asian demand, which again was supported by weather factors. During Q4, the prices weakened from the unusually high levels in the previous quarters. In Q4, we saw increased LNG availability in 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 U.S., the prices peaked in Q4 due to a cold spell and concerns on low storage levels.
The storage levels in the U.S. entered the withdrawal season nearly 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. Besides such cold periods, the U.S. prices hovered around $3 per million BTU throughout the year. On average, the European gas price for 2018 was very strong. The NBP average was $8 per million BTU, which is close to 40% above the 2017 average of $5.8. 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 German electricity price from around EUR 30 per MWh in May to more than EUR 50 per MWh 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 H2 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. This is another example of the flexibility gas has in the electricity sector, and which is also or which is independent of the price drivers. Let us move to the U.S. and take a look at the supply development and the increasing exports. The first illustration here shows that the U.S. has a very large amount of resources available under $5 per million BTU.
The EIA estimates that at current demand levels, the U.S. has enough technically recoverable resources to last around 90 years. We have seen abundant production growth out of Appalachia with the Marcellus and Utica plays, where Equinor has a large position. Appalachia has one of the lowest breakevens in North America. Additionally, we are seeing more associated gas volumes in the U.S., which is driven by oil and not gas economics, meaning that even more cheap gas has come into the U.S. market. The second illustration shows that 2018 was a record year for U.S. 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 Marcellus and Utica and 30% from the associated gas in Permian. The third illustration shows the growing U.S. exports.
The abundance of U.S. gas supply and lower natural gas prices has increasingly made the U.S. an attractive exporter of natural gas into global markets. U.S. exports have also turned into a crucial source to help balance what would otherwise be an oversupplied U.S. gas market. Since 2005, the U.S. 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 U.S. 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 5 different projects.
That is more than a doubling in capacity from end 2018 capacity levels. The LNG export capacity from the U.S. 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 U.S. 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 U.S. Going forward, there are signs that production growth should slow somewhat from the previous levels. As production growth slows, demand, and especially from export, 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 U.S. exports to the global markets, closing the arbitrage window for the U.S. 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 U.S. 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. 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 flattish import after a few years with reduced LNG as a result of the returning 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 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- 2015.
The market is cyclical, as you can see on the left graph, and the lead time is four-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. 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 NCS 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 U.S. 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' 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, 2023. The right-hand side illustration shows Chinese gas demand predictions from various sources. WoodMac's predictions show a demand growth of 160 BCM or more than 60% in a 5-year period. In addition to increased LNG import, this demand will 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 bands show 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 levels 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. 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- 2020, then dipping below the 100 BCM.
One of the main reasons is the cut in Groningen production based on the earthquake activity in the region. Groningen produced around 20 BCM in gas year 2017, which was below the cap. The cap for gas year 2018 is around 19 BCM, but the target is to produce less, which also Eirik referred to. Further, Groningen production is planned to be reduced to 12 BCM in gas from gas year 2021 and to be closed fully by 2025. In 2018, the production from the U.K. was around 38 BCM, which is about 2 BCM higher than in 2017. The U.K. gas production is expected to be at around this level in 2019 and thereafter decreasing rapidly from 2020 and onward.
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.
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, while 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. Pipeline imports will continue to be strong, providing a negative price pressure. The storage inventories are currently high, which provides some 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 have 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 markets 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 supply, the LNG supply overhang we have predicted for some time. However, this supply overhang came later than assumed due to delays in capacity build-up, 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 falls within the coal switching range, which stimulates demand. Further, we see the forward prices are mostly within the Henry Hub Europe band, which means that the U.S. 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.
Now I would like to hand over to Tor Martin, which would talk about how we create value from our portfolio of gas. Thank you.
Thank you, Elisabeth, and 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 glance 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 honor the commitments we have in the market. Secondly, to ensure that we capture full and fair value of our production. 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.
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. 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 here to you today. There are two, let's see if they both work. Oh, this one didn't. This one did. Thank you. 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. We had high demand, and we had high volatility, which is good from a trading point of view. We also 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. That is a bigger volume than, for example, Shell's global LNG portfolio, just to put it in context of size.
In total, we and the NCS had an export of 114.2 BCM in 2018, which is just shy of the 2017 figures. 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. 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 U.S. 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 coal prices, as Elisabeth just alluded to, high demand from storage and storage injection, and lower LNG supply. In the U.S., our average U.S. 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. As Elisabeth pointed out, there is a possible supply overhang of LNG. I think this is at least the third year that we have cautioned about a supply overhang and what that can do to prices. 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. 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. We do have the most competitive offering of gas into Europe. There's no one can beat us on cost to market, including U.S. LNG. We do that by utilizing the flexibility we have and ability to flow between the main European markets. Lastly, by strengthening our trading capabilities, creating further market opportunities also for our equity volumes. 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, Irene said 10,000 kilometers, I say 9,000+ 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 and 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 sendout at roughly current levels towards 2030. In August, as Irene alluded to, we presented a strategy for more gas exploration.
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 Aasta Hansteen. Don't you just love these Norwegian field names? It sort of 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. It meant we developed our infrastructure delivery system much further North than what we have done previously. It opens up a new province of gas in the North Sea.
The 482 km pipeline that connects this field to the Nyhamna receiving facility on the west Norwegian northwest coast constitutes the northern leg of what then becomes a 1,700 km gas highway from Aasta Hansteen in the North to the U.K. market in the south. 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 Aasta Hansteen. Aasta Hansteen is now at peak production or plateau production, six BCM. But that plateau will increase towards 7.5 over the next few years.
Now, in addition to this, before Christmas, the Norwegian Ministry of Petroleum and Energy approved the plan for development and operation, the so-called PDO, of the T roll phase III development. For those of you who are not familiar with what Troll is, Troll is the biggest gas producer on the NCS, currently providing roughly 7%-8% of total European gas demand. With this, phase III 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. Although, our European, gas market is exposed to the global energy market, we are a small player in LNG per se.
As Irene 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. 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 cargoes. 90% of this came from our Hammerfest and Snøhvit facility. I'm a bit ahead, aren't I? I think the slides are in slightly different sequence there? Okay, anyway. Let's see if it now matches. Yes, now the slide matches the text even. Turning to the U.S. then.
Of course, outside of Norway and the activities we also have in Brazil, U.S. is one of our core production areas. Onshore in the U.S., we operate fields in the Bakken area, the Eagle Ford area, and the Marcellus area. We are now producing roughly one Bcf per day, which equates to roughly 10 BCM annually in the U.S. The positions we have in the Marcellus Utica area alongside the transportation infrastructure we have out of those areas, or the egress we have out of those areas, constitute the backbone of our natural gas marketing operations in the U.S. As the map shows, here we have long-term export capacity to the premium consumption areas, both in around New York, Toronto, and in Eastern Canada.
Starting from Q1 this year, we have also secured new capacity going south, which will secure access to the U.S. Gulf Coast area, a market with industrial growth using gas, exports of LNG, and also exports to Mexico. 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, Asian demand, and also by the intermittency in power generation.
Going forward, 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. We are actively responding to the changes we see in the gas market. Now, as you know, or as I think at least 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. Over the years, of course, we went from long-term contracts with oil indexations to what we have today, i.e., pure gas indexation. 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. As we get towards 2020 and beyond, the realized price should mostly reflect then the short-term market indices. We do this because the demand also for longer-term indices is fading away. 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 send-out 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. 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. Then you will see a gas result in the downstream part of Equinor or the MMP part that largely reflects the deviations we choose to take from those short-term indices, i.e., when we choose to actively manage the portfolio. 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 in the higher end of the value delta we report. Turning now to Danske Commodities, this is something that's sort of on my plate and agenda every day now. It's in a critical phase. We just passed financial close January 1 , and I think it's the most significant step towards further commercial developing further commercial capabilities that we have taken, if not ever, then at least for a long, long time. 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'll dwell a little bit upon that.
Irene gave you the key rationale for why we're doing this, and it is associated with our high ambitions on the new energy side. Our belief that we're 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. What then is it Danske Commodities delivers in terms of this? They have a market presence in basically all European power markets. 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. That is something we will benefit from both in terms of the power trading they do, but beyond that also. I'll turn to that. Of course, this is a company with a proven track record. They've 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 till the end of 2019 before we can say we really had the shared portfolio. It says something about the order of magnitude of this. This acquisition has value to us beyond the strategic rationale linked to power. Again, because they have state-of-the-art systems to support their business, we believe that they can be utilized 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.
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 sort of really look under the hood of this company and what it was, we had already identified EUR 15 million of synergies on the power 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 NESS portfolio, and also before we start factoring in and realizing synergies on the gas side. Then also on the basis of the strong EBIT that this company provides, we are actually very happy with the acquisition price of EUR 400 million that we paid for it.
For those who are concerned about that, Equinor will sort of drown out the unique DNA of a company like this, we are very cautious about that and we'll 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, as 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, among 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.
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. With that, I close, and thank you very much.
Thank you, Tor Martin, and thanks to everybody. I'd like to thank all of the speakers, Irene, Eirik, Elisabeth, and Tor Martin. Particularly like to thank you Glenn, who you may notice is struggling with a cold today. We talk about commitment to our shareholders, and I think here we are in physical form. 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. If we have any coming in from the web as well. We're fairly small here. If any questions, please raise your hand.
I saw you first, Michele, and then Jon, and then we'll go around the room.
Do I have to come up or?
I think it might be if you're able to.
I'm able.
Yeah. Oh, okay.
Yep.
Sorry, I'm standing right in the way there, aren't I? Thanks, Michele.
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 Commodities. 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-fired 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 twelve months forward?
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.
Do you wanna take the last one and I can take the first one?
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. 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 to comment on the physical assets for Danske Commodities, they're actually also trading around physical assets already. One of their main businesses is actually trading around interconnector capabilities. They'll take short-term interconnect capability or capacities and trade on the geographical differences. Going forward, they will trade the power out of our renewable assets. We are certainly hoping to grow that one. I also do think there's a very interesting and emerging scope with the corporate PPAs, selling renewable into which we're hoping they're gonna help us develop such a capability, I think.
Okay. Next question is Jon, then also we've got Frank behind as well.
Thank you. It's Jon Rigby from UBS. Three questions, actually. They are related, though. 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 eight 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 the shortage of gas in the last winter. 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 have 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.
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're all connected with the gas market.
Yeah. There's Elisabeth and, yeah. Who takes Opedal?
Okay, that's fine. No, I think on your first question on how these different regional markets will interact during the season, I think a 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.
What we are seeing is, of course, that to the extent that we have interlinkages between these markets now de facto being established, there will be much less scope for regional price variation at any given point in time. 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 also supply and supply disruptions. 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 U.S. supply.
Depending on how the market actors see that from season to season, you can get surprises. 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, on the U.S. LNG to China, I mean, it's tiny. Has absolutely no impact on U.S. Exports or revenues, and it has hardly any impact on Chinese gas demand or gas costs as well. 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. Relative to the size of the economies, it's, I mean, it's the imports from China into the United States that is sort of the big market here. 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. 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 from.
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 wanna talk about the slowing demand in China?
Yeah, I can touch upon that.
Okay.
Because as I said, last year, we estimated a growth in China of around eight BCM on the LNG side, which is similar size as we also see going forward. I would say that it was a very strong surprise to the upside in 2018 with going to 20. I think 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.
Opedal?
Thank you very much. Yeah, just some of your assumptions. Obviously, with Europe, you're implying a greater import dependency from LNG into Europe. One of the assumptions underpinning that is Russia being stable, you said, at 35%. 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 Ukraine pipeline negotiations at the end of 2019? My second question was more flipping over to Brazil. You talked about this offshore Norwegian gas system, the largest in the world. 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. What steps are you taking? How soon do you think you can do something meaningful with offshore gas monetization in Brazil?
You wanna 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.
Yeah.
So, uh
also just a general comment to Russia.
Yeah.
I guess we've worked alongside them for 50 years, and they've always behaved rationally. They've never had any intention of overflooding the market with gas, and we see no indication of that going forward either. My opinion-
No, I think, I mean, the general story is, of course, that there's a bilateral dependence between Russia and the EU on. They being depending on a market and we 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, With an LNG price and delivering a price level to Europe, it is fundamentally in the interest of economic players delivering gas that we allow that LNG to be part of the market. 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 and increasing import gap? Or do you allow that to be stable?
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 going on somewhere, and then somebody has to step in, and generally that is those players with most of the flexible capacity as well.
I think.
We have an analyst at the back to maybe.
Also with respect to the Ukrainian discussions.
Ukrainian, okay, you wanna take that?
No, I
No.
There is kind of not so many things which I can add on what you'd already said. This doesn't make sense for the Russian supply to just flow a lot more gas just to kind of dip the prices. I think they will then act rationally. Also there is a question of the export capacity available. Even so they want to flow more, there is also a limitation how much they can flow. On the Ukrainian situation, I mean, on the transit arrangement, which expires 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 both parties desperately in a need for this arrangement be in place for, as for Gazprom, also as for the Ukrainian route. It probably will be delayed till the probably last day of this year, but we expect that it will be in place. Maybe not a long-term arrangement, maybe for a year, short-term arrangement with not booking the full capacity, 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 Nord Stream two to come on stream until maybe 2021, so. Y eah.
Yeah, Brazil. We have a significant amount of associated gas with our Carcará field, and we also have a gas condensate discovery in the Pão de Açúcar. I think Margareth said at the capital markets update that for the first phase of Carcará, we're gonna reinject the gas to increase the oil recovery. There's gonna be at least a second phase and maybe even a third phase of Carcará and definitely a BM-C-33. Pão de Açúcar needs gas monetization solutions. We know that Brazil is underdeveloped, I guess, when it comes to utilizing gas in the market. We're almost back to where we were when we started developing the Norwegian Continental Shelf. 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. Chemicals.
Petrochemicals, plants, et cetera, et cetera. We have a strong team. Tor Martin has some people down there. We also have some people who actually were almost part of developing the Norwegian continental shelves. There's some serious competence down there. 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. I have a question mainly about Troll. We talked a lot about in the past, and Equinor have had the mantra value over volume. We also talked a lot about utilizing 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 utilize the flexibility in Troll? By that I mean deferring production from summer 2019 to summer 2020. 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 Tor Martin answered it in a good way, so I'm gonna let him.
I think I have to start, if you will, rather more technically because otherwise I can't follow the logic towards the end. The Troll field is a field that has a given daily production capacity. The Norwegian ministry then has said that you can't utilize that full capacity every day of the year because the outtake from the field then could 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. They said, "You can't utilize 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 oil part of the reservoir. 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 oil fields produce flat out. We are a price taker, but as I also said, that we do have the most competitive gas into this market. If anyone should turn off the taps, it should not be us.
In addition to this flexibility now being reduced, there's still a little bit left, at least for the time being. We operate that flexibility on the basis that you can take out more one year, provided you de-redeliver that flexibility you utilize 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. Don't expect anything big from Troll in terms of additional value from utilizing the swing, unfortunately.
Question from Danny. Alan.
Hi. It's Danny from Barclays. I have got two really quick questions, if I may. Both related to your 2020 ambitions for MMP. The first question is, you talk about a 4% reduction in emissions. Do you think it is enough, given Danske Commodities? The second question is related to the digitalizations. 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. I think there is more to be proud of than just the emissions from our onshore plants, which this target is related to. Because we're doing tremendous work on reducing emissions for instance from the shipping fleet. A lot of our new shuttle tankers or vessels are now running on LNG. That's not counted into that number. There is the potential to electrify some of these plants. We have established a team that are developing an MMP climate roadmap that will look into CO2 emissions from all our assets. Also potentially if we can run our refineries slightly different than, et cetera. I think there is more to be had and more to come on that.
Could I just add on that?
Mm-hmm.
We are the first operator to have actually hired shipping capacity, very large gas carriers fueled on LPG.
Mm-hmm.
That's the first in the world also.
Mm-hmm.
Which will contribute further.
For both LPG and LNG. We're introducing much more batteries, I think.
Mm-hmm.
In some of these vessels as well to reduce the emissions. 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 down at Danske to see how they've actually developed the capability. So you're down there and each trader is sitting there with 15 screens. They're trading at 15-minute intervals. You just understand that the human capacity is not enough to really grasp all this information and act as quickly. Which is something they've taken into account, and they have a very active algo trading system. I was sitting there and they're watching 6 trades come in per second.
That's why they can do 4,000 trades. You know, we have an untapped potential here, or the whole industry, I think has an untapped potential in this respect. Like I also talked about, you know, the plans upping the regularity, getting down the cost, getting down the tariffs, it's significant. Maybe next year I'll have a number, but or even.
They will just have bought the screen.
Yeah.
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'll happen a lot faster due to the fact that we now have Danske Commodities and their capabilities on board.
We also led an industry collaboration, I guess, of starting a startup called VAKT, who's developing a blockchain technology for a trading business. We're in a
Yep.
Very soon we're gonna start implementing, you know, some of the procedures that they are developing.
Another question in the hall from Owen.
Hi. Can I just talk one thing you mentioned on the way you may change your gas realization, due to the new businesses between upstream and downstream, in MMP. Could you just maybe clarify that comment again, how you brought it on your earnings? Then, just to follow up, 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. On the technology side, what you see on the implementation, 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 wanna give
Yeah.
Give it a go on the transfer price? I guess or.
We want to go from passive management of 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 a more active management. 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 realized price is what you will see with the upstream. 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. The weighting will be more towards day ahead than to month ahead.
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. Any deviation from that, and there could still be deviations as a consequence of an active view of the market. That could mean we could convert some shorter indices to longer indices because we believe that is sensible for whatever reason. That's in a sense what I meant by that, if that makes any sense.
Yeah.
Yeah. Okay.
You wanna do the Africa thing?
Yes.
Or
You can or I can.
You can.
I don't know if you were alluding to the Tanzania LNG project or more demand in Africa or?
Oh, I meant more just actual impact of global demand.
Okay. Well, then I'll leave it to you.
Yeah. I guess on Africa you can. 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 new renewables. There should be a lot of potential for modernization, which also would increase the role of gas in the overall energy picture in Africa.
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. 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 Eirik and his team is developing and IEA and everyone, there is a significant amount of carbon capture and storage included to actually meet two degrees, 1.5-degree scenarios. It's not really happening. Why is it not happening? I think primarily because there's no CO2 price to incentivize it. We are, however, working together with the Norwegian government, which is 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 a steel producer and aluminum company don't have alternatives of capturing that. Shipping the CO2, which is key because it allows 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 Teesside or some of these heavy industrialized 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 then potentially allow us to convert natural gas into hydrogen.
Instead of having post-combustion CCS on a gas-fired power plants, we would do pre-combustion CO2 capture, basically, and deliver hydrogen to customers. Whereas that would be a power plant, whereas that will be for industrial use or even in the transport sector. These are things that are not happening, you know, anytime 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 experience in the world with a carbon capture and storage, having stored CO2 at the Snøhvit field, having stored CO2 at the Sleipner field for years. This is what I alluded to that potentially gas can also be a destination fuel, not only a, bridging fuel.
We've been involved in this study.
Yeah.
H21 project in northern England.
Mm.
the potential of hydrogen and
Mm.
also in heating and
Mm.
cooking industry.
It is a good point because as Eirik talked about it in his presentation as well, we tend to think that gas goes into the power sector, but more, at least in Europe and our gas, almost twice as much goes into the heating segment, and it stands for a lot of the emissions. What do you do if you wanna electrify that segment? It's gonna be super costly and very complicated, because, you know, the energy density of gas is so high. If you take Netherlands, for instance, and if you wanna electrify all of what they use gas in the heat segment for, you need to ninefold the investment in the grid. I'm not even sure if it's possible to, you know, have that amount of new cables, et cetera, et cetera.
Where are you gonna look at the windows?
It's quite a challenge and an interesting segment that, you know, the world has only touched the surface on, I guess, how to decarbonize the heat segment, how to decarbonize the heavier transportation, and so on.
Thank you. I think that's questions from inside the hall. Oh, one more, if I may. Just for information, we did have some from the web, but they've all been asked. Apologies for those people who didn't get their questions asked.
Hi. Steve Carter from Citadel. Just a sort of question about some particular fields. Field level data from, forgive me if I pronounce this wrong, Kvitebjørn and Åsgard, show that those fields have produced a little, you know, a little bit less in the last couple of months. Are those fields in any sort of long-term decline, or are they just getting constrained by processing facility capacity?
I see you looking at me. I honestly can't answer. I don't know if anyone,
We could take that up.
Yeah.
Yeah.
I mean, we're not aware of any particular issues there.
No.
I haven't seen the field.
No, I haven't.
Data over the last couple of months.
Just the NPD data that's.
Yeah, yeah.
Publicly available.
I'm not aware of any issues in that one. We can follow up if the, you know, directly just to.
Thank you.
to reassure you on that one. It was Kvitebjørn and Åsgard.
Kvitebjørn and Åsgard.
Åsgard.
Mm.
Yeah. Okay. No worries.
Not bad pronunciation, by the way.
No.
Okay. With that, thank you very much to everybody. Thank you to the speakers. I'd like to invite people through to have something to eat and drink with us. In addition to the presenters here, we've got some analysts as well who can also answer some of your questions. Also at the back is Helge Haugane, who has the privilege of counting the money every quarter as well. You can ask him some questions.
Just ask head of Johan Castberg, who heads up our.
Right
LNG and natural gas activity. We'll be able to answer more specific questions than I am.
Okay.
Well-
Thanks everybody. Thanks to everybody who joined us on the web. As ever, if there's any other further questions, please come through to Investor Relations. Thanks to Eirik and Ida as well for helping to organize this. Thanks a lot. Thank you.