Novatek targets huge Arctic gas resources
The firm intends to become one of the world's largest LNG producers by 2030 via projects in the inhospitable Arctic environment
Russia's Novatek has established itself as a major player on the global LNG stage with its Yamal LNG project. And if its Arctic LNG 2 goes ahead as planned, it will become one of the world's biggest producers, with nameplate capacity of 37mn t/yr, in the first half of the 2020s.
But the firm has ambitions beyond that, as CFO Mark Gyetvay tells Petroleum Economist.
PE: What projects do you see beyond Arctic LNG 2?
MG: We are blessed with a huge conventional natural gas resource base that is relatively easy to extract. Russia's domestic market is not growing, so our monetisation strategy is to export this gas. Gazprom has decided to do it via pipeline. Novatek has decided to move forward with LNG because it allows us to deliver to multiple continents.
The strategy we presented to the market in December 2017 had a target of growing LNG production to 55mn t/yr by 2030. What we have announced in recent weeks is that we will revisit that strategy in the next year or so and probably increase the target to about 70mn t/yr by 2030.
The key word in the strategy is "scalable" — because, ultimately, it depends on market demand. If the market is there, we can build scalable projects on gravity-based structures (GBSs) at 6.6mn t/yr and each subsequent GBS should be cheaper than the previous one, thus reducing liquefaction costs per tonne.
We have immense hydrocarbon resources. We have taken a very active role in the last four years on the Yamal and Gydan peninsulas, acquiring substantial acreage positions. Those licences provide us with an opportunity not only to make the Russian Arctic zone a major producing centre but also to catapult Novatek into becoming one of the top players in the LNG market space.
PE: You and your partners brought the Yamal LNG project on stream a year ahead of schedule, despite the harsh conditions of an Arctic location that some have described as "beyond inhospitable". TechnipFMC, the EPC contractor on Yamal LNG, recently described this as "a feat unprecedented in the LNG industry". To what do you attribute this success?
MG: It is a confluence of many factors. First and foremost was good project management. We had a complex project schedule and there was a strong focus on maintaining work according to that schedule. Secondly, the partners, the subcontractors and the fabrication yards all delivered high-quality products on time.
70mn t/yr — Novatek's 2030 LNG production target
From Novatek's perspective, we had a singular focus. We were not working on a portfolio of multiple projects across multiple geographical zones. Yamal LNG operated 24 hours a day, seven days a week, 365 days a year. Our partner Total has said that what differentiated Yamal LNG from its Ichthys project in Australia was much higher worker productivity. I would agree with that comment.
A lot of people do not appreciate the quality of the Russian oil and gas industry. It's advanced. It has a depth of knowledge and resources and a long history of innovation. Yamal LNG was a new project in a remote area. But this area is where we operate. Every one of our projects in this geographical region is built under the same permafrost requirements.
PE: What special measures did the permafrost environment require?
MG: We precision-drilled around 38,000 pylons with heat exchangers on them. All the equipment was mounted on top of these pylons. Yamal LNG may be unique in the sense that it is the only LNG plant in the world built on pylons but it is not the only project built on pylons. All our projects are built this way because of the permafrost requirements.
PE: What progress have you made with marketing the output of Arctic LNG 2? And when do you expect to reach final investment decision (FID)?
MG: We have been doing pre-marketing over the past year and the feedback we have received has been very positive. The market realises the success of what we have been able to achieve with Yamal LNG — that we can deliver LNG cost competitively around the world, whether we go via the Northern Sea Route or via trans-shipments in Europe. Success breeds success.
FID for Arctic LNG 2 is scheduled in the second half of 2019 and our chairman, Leonid Mikhelson, has said he believes it will be in the "first half of the second half" of 2019.
Breaking new ground: Novatek aims to optimise its fleet of ARC7 ice-breakers
PE: There is huge competition from other LNG liquefaction projects to take FIDs this year. We've seen Golden Pass do so. Venture Global says it is about to start construction on Calcasieu Pass. Qatar appears determined to proceed with its expansion. Is there a point at which you may struggle to take FID if too many other projects have been sanctioned?
MG: Other projects will have no bearing whatsoever on our FID decision. We have already completed front-end engineering and design (FEED) work and contracted more than 50pc of the equipment for Arctic LNG 2. We are already building the LNG construction centre in Murmansk.
Novatek has already made the decision to move forward. We have confirmed capital costs of $20-21bn for the 19.8mn t/yr of production capacity. We are now going through a process of bringing partners on board. We have just closed our transaction with Total, and ongoing negotiations with other interested partners are positive and proceeding favourably.
Potential partner interest in Arctic LNG 2 has been very strong and partners entering the Arctic LNG 2 project will be required to offtake LNG proportionally to their equity share in the project.
"We intend to make the Russian Arctic zone a major producing centre"
PE: But, aside from the deal with Total, you haven't agreed any offtake contracts yet?
MG: No. We have been in discussions, but we have not announced any other offtake agreements yet.
PE: You have previously said you would be happy to proceed with 50pc of your output contracted and 50pc spot and that you would be comfortable with short and medium-term contracts. Isn't that a brave decision in terms of market risk?
MG: Not if you look at the growing liquidity in the market. We are not talking about the project starting up today. We're talking about 2023, four or five years from now. By then, we think the market will be liquid enough. We do not see any problem working with short and medium-term contracts.
A financing structure predicated on a high proportion of bank financing under the traditional model requires you to have a high proportion of offtake agreement. For example, look at US projects such as Venture Global's Calcasieu Pass LNG and NextDecade's Rio Grande LNG. They will require a certain volume of offtake. Shell, on the other hand, has decided to use its balance sheet at LNG Canada, along with its partners.
In our case, we are looking at a higher proportion of equity contributions into the project, relative to debt financing. We do not need a high proportion of offtake contracts.
Another factor is the changing creditworthiness of customers. Buyers such as those in Pakistan and Bangladesh have a lower credit quality than traditional buyers. How does that fit into the traditional project financing model? It probably does not. So somewhere, somebody is going to have to take some risk. That is exactly what is happening, and I believe that is what we will do in our project.
PE: Financing Yamal LNG was tricky because of sanctions. Eventually finance had to come from Russia and from China. How will Arctic LNG 2 be financed?
MG: It will be probably be about 30pc debt, roughly that order of magnitude. Maybe slightly higher but nothing close to the extent that we looked at before: a traditional 70pc model. You are right that because of problems with sanctions, we were unable to use the traditional project finance model at Yamal LNG. Finance for Arctic LNG 2 will come from various sources, perhaps Russian banks, perhaps European and Asian banks.
PE: Perhaps China again?
MG: Perhaps China again, if they're a partner in the project. Perhaps even from the Middle East. We are open to these discussions.
PE: Arctic LNG 2 will be based on very different technologies than Yamal LNG. You're going to have trains on GBSs rather than on permafrost. You're planning to use a different liquefaction process: the Linde Mixed Fluid Cascade rather than Air Products' propane pre-cooled mixed refrigerant (C3MR) technology. Given how successful Yamal LNG has been, why have you chosen to do this?
MG: Gravity-based structures were considered as an option even on Yamal LNG. But the studies were not totally worked out then, so we elected to go with the traditional Air Products technology.
"Potential partner interest in Arctic LNG 2 has been very strong"
Now, with the GBSs, we believe we can significantly reduce the capital intensity by removing the majority of infrastructure that was built onshore, such as the pylon work. By removing that, and thanks to some of the existing work that was done for Yamal LNG — such as the port facility, dredging of the Ob channel and so on — we can reduce capital costs by about 30pc. Equally important, at the same time we can reduce our environmental footprint to about a quarter of the size that we have at Yamal.
PE: Have sanctions been a factor in technology selection?
MG: No. It is all about reducing costs.
PE: How much of a factor is bringing as much of the manufacturing as possible into Russia?
MG: We are setting up a big yard — a centre of excellence for the construction of these LNG platforms. The aim is to localise at least 70pc eventually and build domestic expertise in LNG. But we are being realistic. That will come over time. We will work with our contractors and suppliers to embed as much local content as we can, but we don't want to sacrifice quality and timing.
PE: At a recent conference you expressed frustration with what one commentator had been saying about your capital costs per unit of production. What is the true position?
MG: He had Arctic LNG on the higher end of the cost curve, rather than where it rightly sits, on the lower end. My question to him was: where did you get your information? We never published that sort of number. If we can achieve a $650-750/t/yr liquefaction cost, on top of the $300-350/t/yr field development cost, we're talking about $1,050-1,100 per mn t/yr of production capacity.
PE: Train 4 at Yamal LNG will use your own liquefaction process, Arctic Cascade. Why develop that and what future do you see for it?
MG: We have been able to use existing equipment inside of Russia to develop a technology that is based on an ethane feedstock. That allows us to cool natural gas down to -84°C, on the first stage. This compares with the Air Products process which, on stage one, only gets it down to -36°C. So, we are taking advantage of the low ambient temperature. The idea is to lower the liquefaction cost down to around what we see in the US Gulf Coast.
PE: When will Train 4 be up and running?
MG: The construction is ongoing right now. We plan to launch it by the end of the year but no later than the first quarter of 2020.
PE: Some of the key innovations needed to make Yamal LNG work — and which will also be required for Arctic 2 LNG — concern logistics. By the end of 2019 you will have 15 Arc7 ice-breaking LNG carriers, you are planning a trans-shipment terminal in Kamchatka, another in Murmansk, and you have an ambition to establish a Fob price in Far Eastern Russia. What's the strategic thinking behind all these elements?
MG: Our goal with the trans-shipments is to optimise the use of these Arc7-class tankers. Because why would we want to use a tanker that is built specifically to handle two metres of ice in an area where there is no ice?
"Other projects will have no bearing on our FID decision"
A trans-shipment terminal at Kamchatka — initially with an annual throughput of 20mn t, with the option of going to 40mn t — means that the Arc7 tankers can go across the Northern Sea Route, and unload at Kamchatka. From there the buyer can take the LNG and move it to Japan or South Korea in three days, or to China in six days. At that point, we can then create a potential LNG marker price for an Asian buyer to see if that is attractive for them.
The same thing goes for Murmansk. Once we get to that point of shipment, the sea is ice-free. So why take it to a European trans-shipment terminal, as we are doing today? We've saved seven to eight days on a round-trip voyage by doing ship-to-ship transfers in Norway.
So, how best to optimise the logistics model is one element. The other element is to work with the Russian government to create a nuclear ice-breaker fleet that they want to bring on stream, so that we can open up the Northern Sea Route all-year-round.
PE: How would the Kamchatka terminal allow you to establish a Fob index? What would be the modus operandi of that?
MG: As you know, the Asian market is trying to establish various hubs. Singapore wants to establish a hub, the Shanghai Petroleum Exchange is starting to do something, and we know that the Japanese want to also. What they lack, we have in abundance — we have physical volume. And that is one of the precursors of establishing trading volume. We're talking about a physical trade.
Obviously, we would have to put a trading mechanism in place, but if we can clearly show a Fob price calculated from the liquefaction plant to Kamchatka, then buyers can use that as a reference. But it would have to be market-driven — it would have to be accepted by the buyers in that geographical region.
Delivering low-cost LNG under flexible arrangements will define the emerging winners and losers in this evolving energy landscape.