[NGW Magazine] Equinor Outlines its Strategy
NGW met Equinor's SVP for marketing and trading Tor Martin Anfinnsen, and Peder Bjorland, VP for marketing and supply to ask about the Norwegian company's strategy for marketing its energy.
How do you manage your gas, power and liquids fuels businesses under one roof?
Equinor used to have a range of business activities: but petrochemicals, oil sands, gas infrastructure and shipping have all been lost as time has gone by and we have sharpened our strategy towards primarily the upstream.
Rather than acting as a purely upstream company, we are more a broad-based energy company and that means expanding into renewables.
Several of our peers have compartmentalised their commodity groups. Gas and power trading sits together on either side of the power plants that the utilities operate for example. But there is no conflict between new energies and fossil fuels at Equinor. We see an advantage in having all commodities under one umbrella. You can see the arbitrage opportunities and co-operation across commodities as they are all linked together as parts of the energy complex.
Back in the old days oil indexation was the norm as oil was the anchor. Now we get the pull from power too, as more gas goes into generating power in some markets. It is hard to see whether oil or power influences gas more. It varies from region to region.
How about owning assets mid and downstream, is that a key part of your business?
We go deeper into the market only as required for contractual purposes and we go downstream only when we have to, in order to achieve the full market value. We would consider deliveries of LNG where it would make sense as an alternative to a pipeline and we would consider going into different types of power generation.
It is very clear that renewables has made more space for gas and that gas demand has gone up in Europe. Again the expectation is that there will be a lot of gas around renewables. The value of gas-fired power plants lies more and more in their capacity than the output, so the business model will have to change for anyone in the power generation space.
There is room for combined-cycle gas turbines in Belgium, when the nuclear plants close and baseload demand goes up. Whether there will be new-build generation remains to be seen. Smaller engines that respond faster and are decentralised, will take a larger share.
We invest in assets where we have to in order to realise the full value of our energy, but our preference is to arrange commercial agreements. Even if we went into the investment side, we would stay clear of operating. We are quite a sizeable power generator and have offshore wind too, such as the 420-MW Dudgeon plant and the experimental floating 30-MW Hywind plant, both in the UK. The money might be in other areas, but offshore wind plays to our strengths. We are good at building offshore. What has been considered is to develop offshore wind to power the existing and new offshore oil and gas installations.
The general investment level of Equinor will go up. As our CEO Eldar Saetre said, renewables will account for 15%-20% of capex by 2030. That could be $1-2bn/yr based on today’s level and we will be quite a sizeable power generator.
We own the Aldbrough storage facility in the UK – it mainly holds our gas but there is no physical link between the gas we bring into the UK and what we inject. But there is a functioning market between the injection and the withdrawal. We can turn it round several times in an hour.
We have noticed shorter price spikes and we are far more exposed to winter price spikes when the market is tightly balanced and storage is very important. But we would have liked to have more storage and we would have liked also more seasonality this winter! We also have storage in Germany, Etzel, which is used to regulate gas production and we have long-term capacity contracts.
We do see more links between Europe and the global LNG market as there is very little storage in Asia and we have winters at the same time. That means there should be more seasonality in future.
We also have some flexibility upstream in Troll, but this is less than it was. It has been producing for almost 20 years, and the authorities allow us to produce at maximum on some days as long as we are below maximum on others. The authorities want to make sure we are looking after the reservoir in a prudent way. Troll is close to the maximum output now. [Since the interview, Equinor and partners announced a $1bn recovery project to produce more gas.]
As a company we want to maximise the hydrocarbon recovery from a reservoir – the upstream team sometimes pulls in the opposite direction from the trading floor – but we believe, from a corporate perspective we treat Troll pretty much the same as the government would. We do have some flexibility at Oseberg though. Troll produces about 36bn m³/yr but at maximum it can go just short of 40bn m³ most of which is sold on long-term contracts. But as they are almost all fully linked to traded markets, they add efficiencies to how we market the gas, and we do not put all our eggs in one basket. We do look for opportunities to commit long term gas and we do not need new infrastructure to do this.
The Ormen Lange gas field and the related Langeled line [then Norsk Hydro projects] were only partly underwritten by long-term contracts with Centrica. All the fields since then have depended on the market, which is priced by supply and demand rather than oil products. Equinor has been in the driving seat converting the gas complex to reliance on traded markets. And there is no need for new gas infrastructure to shore; only small pipelines joining up the dots upstream.
So the Baltic pipeline to Poland – or perhaps I should say the Baltic pipeline from Poland, as it is their initiative – can be built but only if Poland wants it, for security of supply to cut its reliance on its major supplier. From our perspective it needs to yield the same netback as any other route, as gas from the Norwegian Continental Shelf could go to Poland by land, across Germany. To ensure as high a netback for Equinor, Poland might have to pay more for the gas than what they pay current suppliers today. From our point of view, that infrastructure is not required. It is a Polish project, not one promoted by us. There is a lot of spare capacity offshore as the lines were built to service long-term contracts which allowed upwards nominations of 10% compared with the annual demand. Now the supply curve is a lot flatter than it was, so there is redundancy. We don’t expect that, even with more output from the NCS, we will need to build more capacity to the market.
What about EU capacity and trade?
The UK-Belgium Interconnector we have looked at it opportunistically but we have our own infrastructure and we can switch gas to the UK or the continent. Equinor can switch between deliveries to the UK and the continent. From the point of view of the UK, and its commitment to leave the European Union (Brexit) next year, our interest is in a level playing field. We have the capacity to flow as much gas as we flow to the UK also to the continent and we want to keep flowing gas in large volumes.
No Brexit solution however should distort the UK. Any barriers between the EU and the UK will influence our commercial behaviour and the British government perfectly understands that the UK will be a very important, long-term market for our gas. A friend in need is a friend indeed. Power cables between the two countries have further strengthened the alliance between the two countries.
The Dutch swing field, Groningen, presents an opportunity for Equinor as the Dutch government is cutting its output back hard. But we are only a price taker. We don’t hold back production to move the market. There is some flexibility in the system, but we are generally running at full operating capacity.
How about business beyond Europe?
Looking at east Africa, Tanzania has a lot of gas which I would love to have in our LNG portfolio; but there still needs to be a lot of work done there politically. The project is looking good, the costs have been cut from original estimates, but there are challenges on the political side: we need a framework that creates conditions for final investment decision.
There is much to be done before we can say this is a project. If Mozambique gas goes forward that would help rather than hinder our efforts: the government would realise that exports are possible. We could say to the government that Mozambique has got it right; so why can’t you? And the Tanzanian government would like to be exporting LNG today. But the mining law has been changed in a way that is completely unacceptable. It is opaque and that makes it difficult to move the project forward. The government understands this and knows the project would benefit both the country and the investors. But there will be other gas, from not just the US but elsewhere too. Competition is always difficult: any new volume will lower prices.
Turning to Brazil, there is limited gas demand there at the moment, but there is a huge amount of gas in the pre-salt. But given all the gas that will or might come in, the country could become a net exporter. The government wants to see that happen, as it is now a net importer.
We expect to have two projects onstream in the mid 2020s: Carcara and BMC-33. These would together bring in 10bn m³/yr, gross. This could possibly be developed as LNG; or the best solution for us and for Brazil would be to pipe it onshore provided regulatory regime makes that economic. It could be used for industrial or domestic supply in Sao Paolo; or for power-generation in the north.
Equinor has also just won some licences which our people there are optimistic about and there could be others in the future which we are very excited about. Whether it all goes to the domestic market or some is sold as LNG is down to the government and the regulatory regime, but we will be a facilitator in helping the market development.
So far we have no exports from the US – but it is more interesting to look at LNG now than it was. We have about 10bn m³/yr of gas production from the Marcellus, but it all goes into the pipeline market. The US petrochemicals manufacturing boom has helped us but only as an outlet to the market. We have capacity to access premium markets in the northeast and a sizeable portion of the 10bn m³/yr output is marketed in eastern Canada and the northeast of the US.