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INTERVIEW: Inpex Boss Sees Clear Role for LNG in Transition Strategy

Copyright © 2021 Energy Intelligence Group
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As well as facing greater environmental, social and corporate governance pressures, the LNG industry is having to cope with extremely volatile spot prices. Inpex President and CEO Takayuki Ueda tells the Energy Intelligence Forum 2021 about the Japanese firm's energy transition strategy and its plans to supply cleaner LNG.

Q:  Inpex has set a net-zero target for its Scope 1 and 2 emissions by 2050. How has that changed the way you make strategic decisions?

A: We have announced two targets. The first is to achieve net zero in absolute terms by 2050. This includes Scope 1 and 2 emissions. The second is to reduce our net carbon intensity 30% by 2030. First, we will reduce carbon dioxide emissions from existing assets in the short term by increasing energy efficiency and net-zero flaring. Long term, we will introduce CCS [carbon capture and storage] and CCUS [carbon capture, utilization and storage]. Next, a gas shift. Currently gas accounts for 40% of our total oil and gas production. We aim to change this to 50-50 by increasing gas production in the near future.

We are going to pursue new energy such as hydrogen and ammonia. But at the same time during the transition, LNG will play a very important role. So our core business is still oil and natural gas. We will continue to explore and develop oil and gas during the transition.

Q: LNG is a key component of Inpex’s portfolio. What will be Inpex's most important tool for carbon reduction? Will it be CCS/CCUS at Ichthys in Australia and the future Abadi project in Indonesia?

A: Our challenge is to reduce CO2 emissions from upstream assets using CCS and CCUS. CCS requires deep knowledge and experience of geology and drilling, where Inpex has a technological advantage over other companies. For Inpex, CCS and CCUS are the most important decarbonization tools.

Q: Some critics say CCS has been oversold. What are the factors necessary to make CCS work, such as an appropriate carbon price?

A: For upstream companies, it is essential to introduce CCS into many projects, including Ichthys. To be consistent with our commitment to net zero, we have to consider introducing CCS in various projects, including Ichthys, irrespective of the carbon price.

Having said that, a certain level of carbon price is ... very much essential to make CCS a real big business. CCS is very expensive. Usually the cost of CCS per ton of CO2 ranges from approximately maybe $50 or $60 to around $200.

Q: Inpex and Abu Dhabi National Oil Co. are exploring blue ammonia opportunities in Abu Dhabi. Could you tell us about the opportunities in Asia? Would you consider producing ammonia or hydrogen at Ichthys or maybe even Abadi in future?

A: Hydrogen is a kind of evolution of the natural gas business. Since we have natural gas in Asian countries and also CCS technology, it is not difficult for us to produce blue hydrogen. At the moment we are working towards an integrated natural gas-based blue hydrogen business project in Japan. If there is a lot of demand for clean hydrogen in future, we can certainly consider producing hydrogen overseas, including Ichthys or maybe Abadi.

Ammonia seems unique. It is seen as one form of transportation of hydrogen. Now electric power utilities are seriously considering using ammonia as a future fuel. Considering the difficulties of shipping hydrogen, I think ammonia could be a unique and important fuel for the future. We are now conducting a feasibility study with Adnoc with a view to produce ammonia in the near future.

In terms of which is the priority — ammonia, hydrogen or CCS — the three businesses are equally important. We will use all three technologies to reach our net-zero target.

Q: The Japanese government has set a target to import 3 million tons of ammonia by 2030. Do you think this is achievable?

A: To meet the government target, we need technological development, especially in cost reduction. Liquefying hydrogen is still very, very difficult and costly.

Another important aspect is focusing on the user side. The government usually talks about the supply side. But the demand side is different — users, companies, individuals. If they really want hydrogen and ammonia, I think the government target may be realized. But it seems at this moment that it is a really, really extraordinary high-level target. We'll do our best to reach that target, but it really depends on technological development and customer behavior.

Q: Another technology much talked about in Japan is methanation for producing synthetic methane. Can you tell us how you plan to scale this up and how you see the business model developing?

A: Carbon recycling, including methanation, is another important component. We have been working on methanation for a long time and we have already constructed and operated a small demonstration plant in Niigata, Japan. We are now planning to expand the scale of this plant by around 50 times.

The next stage is to put the synthetic methane produced in our plant in a national natural gas pipeline, maybe around 2030. We are evaluating opportunities on the practical applications of methanation technologies in Australia.

In Japan, the government has a target to use synthetic methane amounting to 1% of Japan's entire natural gas usage by 2030. We will contribute to that. As for the question of where we produce synthetic methane, we started this in Japan and are considering doing so abroad and shipping it back to Japan.

Q: Given the availability of gas infrastructure in Japan, might synthetic methane get commercialized before hydrogen?

A: It really depends on the regulatory framework and maybe carbon pricing. One advantage of synthetic methane is we can put it into our natural gas pipelines. So we have the infrastructure.

However, if we have carbon pricing in the future, we will also produce a lot of hydrogen. Hydrogen can be used as a combustion fuel directly. It’s difficult to say which one will be first. Hydrogen may be difficult to transport. If you consider the liquefaction of hydrogen, the temperature is minus 253°C, compared with LNG at minus 162°C. So to handle liquefied hydrogen seems difficult. But as we deal in LNG, we may overcome such difficulties. Perhaps in the near future, maybe around 2030 or 2035, Japan and Inpex will handle the real hydrogen as a fuel.

Q: The Japanese government has a plan to launch a carbon exchange in 2022. What is Inpex's view?

A: The government has invited the private sector to conduct emissions trading on a voluntary basis. The objective is not merely to trade in emissions, but to encourage companies to invest in climate change response measures. If the regulatory scheme is well designed, it will really boost our efforts such as CCS and hydrogen.

Q: What impact might current high LNG prices have on the outlook for LNG use in Japan and other Asian markets?

A: LNG prices of around $50 [per million Btu] are unusual and will not continue for long. But considering the current supply and demand situation, the LNG market will continue to be tight for a couple of years ... [and] $50, $60, $40 is too expensive. However, we will not see the very low price we saw last year like $2 — more like $20-$30 for the medium term.

Q: Are such high prices worrying for the LNG industry in terms of creating new demand in emerging markets?

A: No one can afford LNG at $50-$60. Downstream, Inpex has been pursuing opportunities such as LNG-to-power and receiving terminals, LNG bunkering and small-scale LNG in South and Southeast Asia, but progress has been slower than expected. We see some serious issues. One is the strengthening of financial restrictions on hydrocarbon projects. If this continues, I think this will continue to hamper progress … insufficient investment upstream as well as downstream may result in shortages of gas and power in those countries. This is not a good thing.

However, considering the environmental advantages of LNG during the transition period, LNG is a realistic and practical solution for both advanced and developing countries. We would like to cooperate with developing countries to come up with upstream and downstream solutions so that demand and supply will match and we can see a relatively stable and acceptable price.

Q: In the latest draft of Japan’s sixth basic energy plan, the government reduced LNG's share of the energy mix from 27% in the previous plan to 20% by 2030. How would you describe LNG's future role in Japan?

A: When we consider the energy transition, the realistic solution is natural gas, especially LNG. If you look at LNG demand in Japan, I believe it will grow steadily towards 2040. I firmly believe that LNG will continue to be a key component of Japan's energy mix in 2030 and beyond. I would also add that at least 55 million-60 million tons of LNG will be required in Japan from our perspective in 2030. So LNG will continue to be an important source of energy for Japan from a security perspective and as a backup energy source for renewables and nuclear power, which have their own problems.

Our company's role for LNG is simple — stable supply or necessary LNG to Japanese customers and making the LNG much cleaner.

Q: Most of Japan’s LNG supply contracts with Australian projects will end in the 2030s, including those with Ichthys. How confident are you about renewing the Ichthys contracts?

A: LNG demand in Asian countries will increase in the future. And now we are experiencing very high spot prices, long-term contracts are still the basis for LNG trading. I will talk with our customers on what kind of LNG contracts they really want. If they prefer spot markets that is OK. But I think we can provide stable supply with sustainable pricing, and I think that's the benefit of a long-term contract. So that really depends on the customers' behavior and attitude.

Q: Given the high spot prices, do you expect buyers to become more interested in signing up for term contracts?

A: That's a very difficult question. Last year we saw very, very low spot prices compared with very high long-term contract prices. At that time, there were many complaints about term prices. Now the situation has completely changed. The LNG market is getting tighter, so we are experiencing two extreme cases last year and this year. The experience will be a good lesson for suppliers and users. I think we will have constructive discussions with buyers based on those experiences.

Q: Hopefully that will provide momentum for the Abadi project in Indonesia and a possible brownfield expansion at Ichthys. Is that under consideration?

A: The operation of Ichthys is very, very good at the moment and we plan to ship about 120 cargoes to the world. We believe LNG demand in Asia will increase and we will develop CCS for Ichthys and make clean LNG in the future. If there is demand for Ichthys, why not expand it in the near future? We are really seriously considering [expansion].

For Abadi, unfortunately due to Covid-19, the site survey is now suspended. But we will discuss when we can restart research and consider introducing CCS to Abadi. Producing ammonia or hydrogen at Abadi is an issue to be discussed in the coming couple of years.

Q: Inpex has been active in selling carbon-neutral LNG and gas to Japanese buyers. Do you expect Japan to become a key market for carbon-neutral LNG?

A: Decarbonization seems a priority for our customers and their end-users. Many companies need to move towards the net-zero target, so we expect demand for clean products to continue to grow in future. As for the development of universal standards, we understand that industry players have discussed the measurement and verification of greenhouse gas emissions on various occasions, and this is a work in progress.

Q: For carbon-neutral LNG transactions, some sellers have said they can bear the costs of Scope 1 and 2 emissions but Scope 3 emissions should be borne by buyers. Is that a fair basis for commercial discussions?

A: I have heard the same thing. I think the issue is pricing. We usually use offsets by acquiring credits from the market. Our effort is to try to reduce the price of the credits. To do so, we will discuss with our customers what is the appropriate price for them and then the price will be decided. I cannot agree with the conceptual notion that Scope 1 and 2 should be borne by upstream producers and Scope 3 by customers. We would usually discuss with customers without differentiating Scope 1, 2 and 3 emissions.

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