Tokyo Gas – Diversifying to adapt to a new energy order
These are tough times for Japan’s gas and electricity utilities, who together make up the world’s largest national group of LNG buyers. Post-Fukushima, the nation’s LNG imports have soared. Gas prices, still mainly oil-linked, have been stubbornly high, significantly higher than in Europe and much higher than in North America. Meanwhile, huge uncertainty hangs over the fate of the nation’s fleet of nuclear reactors, with only two out of 50 currently in operation. In this exclusive interview, Shigeru Muraki, Executive Vice-President at Tokyo Gas Company – Japan’s largest city gas company – explains how his company is responding to the ongoing challenges of meeting the nation’s energy needs while helping to reduce the impact of energy imports on the burgeoning trade deficit. Interview by Alex Forbes
Japan currently faces a very difficult energy situation, with most of the country’s nuclear reactors closed, LNG imports at all times highs in order to compensate, and most of the LNG going into Japan indexed to high oil prices. What plans does your company, Tokyo Gas, have to respond to this in the short term, medium term and long term?
We are already secure in short-term LNG supply for our demand increase. Medium and long term we are looking at different opportunities, from different sources and under different conditions. One good example is US shale gas with price linked to Henry Hub. Other potential sources could be the combination of Henry Hub and oil indexation, or NBP. What we’d like to do is diversify our portfolios. That could minimise the risk of volatility and increase the competitiveness of natural gas.
We use natural gas in the traditional city gas market as well as power generation. The pricing and competitiveness of the city gas and power markets are different. So we are exploring portfolio management of the LNG supply, the gas supply and the market, and how to link and optimise our assets.
A number of Japanese companies have taken stakes upstream in, for example, shale gas plays in the US. What is your company’s upstream strategy?
What we have been doing is taking small upstream positions in some projects, mostly in the Australian projects. We are participating in BG’s coal-seam gas project, Queensland Curtis LNG. And we will purchase LNG from that project.
We are also investing in shale gas basins in North America, first in Cordova in Canada, and then in the Barnett shale basin in Texas.
Japan has a gas quality specification for gas that is relatively rich, whereas some of the new sources of gas – such as coal-seam gas in Australia and pipeline gas from North America – will be much leaner. In February the Tokyo Electric Power Company announced it was preparing itself to import up to 10 mtpa of lean LNG, around half its requirement. Is this the start of a trend for the wider gas and power industry in Japan?
We already have some capacity to receive lean gas – and we can increase that capacity. So we are ready to take a certain amount of US shale gas. We do not see any big problem with taking lean gas at this moment. We have already contracted 1.4 mtpa of US shale gas from the Cove Point export project. And the volume from Queensland Curtis LNG is 1.2 mtpa. So a total of 2.6 mtpa. It can be easily handled.
In recent years LNG buyers and politicians in Asia – especially in Japan – have been expressing dissatisfaction with the rationale behind current oil-indexed LNG pricing in an era of cheap and abundant shale gas. For example, at the Producer-Consumer Conference held in Tokyo last September, at Gastech in London in October, and more recently at LNG 17 in Houston. How do you see LNG pricing evolving in Asia in general and Japan in particular?
The oil-indexed formula remains, but the formula itself will be somehow adjusted, by introducing gentler slopes or re-introducing S-curves. Some of the new contracts have S-curves. That will minimise the risk of volatility of oil. So that will be an advantage. When the oil price goes high we can limit the increase of the cash outflow from Japan to buy energy resources. That will help the trade deficit.
The Henry Hub price at this moment will have an impact on the pricing of LNG in Asia because the expected delivered price is much lower than the current oil-indexed LNG price. That will put big pressure on existing and potential LNG suppliers. That is one of the advantages of taking US shale gas to our market. Another is flexibility – free destination.
That will create more liquidity in the market and could create an opportunity to establish traded markets in Asia. That kind of opportunity to trade or arbitrage will not necessarily lead to convergence to one price but we can utilise different types of prices for portfolio management.
There has been talk recently of trading hubs and futures markets being established in Asia as part of the process of reforming how LNG is priced. In particular there’s a proposal to develop a futures market in Japan. How realistic are these proposals and what kind of timeframes would it take for such initiatives to have a real impact?
The Japanese government now wants to create a futures market within two years but such a market needs liquidity for more LNG to be traded. Otherwise it cannot function. At this moment it’s not clear how quickly that liquidity will be developed. One possibility is US LNG, but that will be from 2016 or 2017 onwards. So it will take a few more years. That kind of timeframe could be a realistic goal for a trading hub and the futures market to start.
Where do you think a hub might be established? Some people have mentioned Singapore, some have mentioned Shanghai. Could we possibly see a trading hub established in Japan?
The potential locations are Japan and Singapore. I don’t think Shanghai is a potential location because transparency is important for a hub. The Chinese market is very controlled by the government.
One of the big game-changers in the gas business over the past five or six years has been the rise of the shale gas boom in North America, not just in the US but also in Canada. One of the results is that there are moves to develop large-scale LNG exports from the Lower 48 states. Alaska could be very important – the stranded North Slope gas. And then also the projects in Canada. How much of an impact could LNG exports from North America have on gas pricing and liquidity in Japan?
US shale LNG will have a big impact on liquidity and pricing. But we do not know what kind of terms and conditions will be loaded on the western Canada LNG and the Alaskan North Slope LNG. At this moment the major players in western Canada and Alaska are the major oil companies. So I think they will try to utilise the current indexation or at least a combination of Henry Hub and oil indexation – to maintain the current pricing level of the market. So it is not easy to see the impact of LNG from Canada and Alaska.
But what about the Lower 48? Presumably there you would follow the kind of model that has been followed already where you sign a tolling agreement . . .
. . . yes, a tolling agreement and so definitely a Henry Hub-linked price based on FOB.
How much cheaper would you expect LNG bought on that basis to be than the oil-indexed prices you’re paying now?
Now we pay $16/MMBtu. Henry Hub is $4/MMBtu, plus liquefaction and transportation costs will be about $7/MMBtu. So that comes to $11/MMBtu. That’s a substantial difference.
But it’s possible that the Henry Hub price could go up to $6-7/MMBtu and oil price could go down to $70-80/barrel – which would change the game. It is a risk, but as I said it’s all about portfolio. We don’t want to have one price – it’s a risk management strategy.
Another thing that’s been talked about a lot recently – in the context of the shale gas revolution, and particularly in the heated debate going on in the US over how much gas should be exported – is that we are seeing something of an economic and manufacturing renaissance in the US because gas prices are very low, so electricity prices are consequently very low, and indeed much lower than the prices that are being paid in Europe or especially in Japan. How concerned are people in Japan about the impact that this wide differential in energy prices has on the nation’s competitiveness?
The manufacturing industry using energy and competing in the global market is concerned about the price difference of the gas. However, there are some manufacturers that could benefit from the shale gas revolution.
If that shale gas revolution spreads to other countries, steel mill companies may have an opportunity to ship out more pipe for pipelines. Now the Japanese steel mill companies cannot export their pipes to the United States. But they could do to other countries.
The shipping industry may also have an opportunity because quite a few ships will be required to transport LNG from the US to Asia because of the distance – 60-70 vessels will be required. The Korean shipyards are very strong but I think the Japanese shipyards will have opportunities to build ships.
What we are trying to do is achieve a reasonable level of pricing. We have to pay liquefaction costs and transportation costs – so that is the reasonable difference for gas prices. And between Europe and Japan, if the gas price to Japan goes down to $11-12/MMBtu it is almost equivalent to the European gas price. That is the goal we want to achieve.
If we had shale gas resources in Japan we could produce shale gas and then gas price would become more equivalent to the US. But it cannot be.
Looking further ahead to possible resources that Japan does have, another development that’s caused a lot of excitement recently – because of an announcement by JOGMEC – is methane hydrates, which until recently were considered too difficult to develop to be a realistic resource. It seems that some breakthroughs have been made that have got people talking about the possibility of methane hydrates being the next source of unconventional gas – beyond shale gas, beyond tight gas. What’s the soonest that methane hydrates could have a significant impact?
It’s possible that methane hydrates will be the next unconventional gas. The prospect drilling we did last year gave us good information to develop the technologies. But still it will take time. There was another prospect drilling in Alaska – a joint venture between the US and Japan – and that also gave us good information. JOGMEC is involved in both projects.
So Japan will continue to work on methane hydrate production – that is the only resource that we have in Japan. But the timeframe is very difficult. The earliest case I anticipate is 2025 – so I say 2025 onwards. But we should not underestimate the technological innovations needed. With continued effort we can make it, hopefully between 2025 and 2030.