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French Major Total Gives Traders Long-Term Insight On Global LNG Markets

TotalLogoThe global LNG industry is in flux. Australia is close to replacing Qatar as the world’s number one supplier with the US also on the way to becoming a major exporter. This greater competition between suppliers has wiped out – at least for now – the premium spot supplies can command in key East Asian markets. But the 50% fall in crude prices over the past six months means that many proposed LNG export projects will be delayed – if not cancelled – as companies struggle to keep healthy balance sheets.

In a wide-ranging interview Total’s Senior LNG Advisor Guy Broggi tells MEES about the challenges and opportunities faced by the French major and its peers in the current market environment.

The global energy industry has witnessed a fall in crude oil prices of more than 50% since mid-June. International oil companies have all announced significant Capex cuts. How is this influencing Total’s LNG global strategy?

Our LNG strategy is to increase our portfolio of LNG. This has not changed, despite the fact that LNG and crude oil prices have been declining very steeply. Because the LNG business is a long-term business, we are still active in the projects we started, including Russia’s Yamal LNG and Cheniere’s Sabine Pass in the US.

What matters for the big names in this business is to have projects sanctioned, as well as projects on the drawing board to be able to offer buyers the necessary LNG when they need it. If you have access to gas reserves, it takes 5-10 years before first LNG production. You have to get prepared in advance to attract markets, be it in Asia, or in Europe. But we are more cautious about the next projects to be sanctioned. These will be under greater scrutiny because of prices.

Which projects are you talking about?

We are evaluating the exploration potential in our block in Papua New Guinea. We first need to confirm the reserves and then make up our mind on exporting LNG eventually. These things take time. And the current situation on energy prices will not divert us from making a decision in the future.

The Yamal LNG project is under construction [but] we are still looking for financing solutions following sanctions imposed by the West on Russia. Each shareholder is financing [their share of] the project so it’s a question of patience until the resolution of the political and military crisis between Ukraine and Russia – we hope that this geopolitical context will change sooner rather than later. We are still hoping for a start-up in 2017-18.

We have already incorporated Yamal LNG output in our portfolio, and we are expecting good news from the US on the Sabine Pass export project, which is expected to start in 2016 and in which we have already committed to take some quantities. In other words, our portfolio will be increased by these two projects.

For the next phase, we still have reserves in Nigeria. Expansion at Nigeria LNG (Train 7) and a grassroots Brass LNG project have been under consideration for several years. A decision on how to proceed may be taken at some point in the near future.

Projects led by competitors have been shelved. When you have been working on a project for years, even if you already found potential buyers and signed MoUs, you still work on the project but you don’t rush to take a decision. The [Chevron-operated] Kitimat LNG project in British Columbia for example and Arrow LNG in Australia [Shell], have just said that time is not right to take a decision. In other words, they appear to be either delayed or cancelled.

Prices for spot LNG – mostly uncommitted LNG – have fallen considerably since last summer, before the fall in oil prices. How is this affecting Total?

The decline in crude oil price is affecting the entire company’s finances. We will start by cutting the Capex and trying to reduce Opex, as previously announced by our new CEO, Mr Pouyanné. Big companies are used to such things. They can weather a short-term reduction in the crude oil price.

As far as LNG prices are concerned, they had been declining even before the oil price fall and for different reasons. The fall in LNG prices was mainly due to an increase in global supply from existing and new projects – like PNG LNG – and slower demand growth. And of course, because long-term LNG contracts are indexed to crude oil, you are witnessing further mechanical declines.

More than 50% of our production is natural gas so of course our finances are impacted. For us, the problem is how to survive in an environment where prices may stay at this level, for a couple of months... or years, who knows. However, it will not change the way we see Total as an energy provider in the future.

So we have to be selective and aim for the best projects in terms of security and location. You can’t go today into countries like Syria and Libya for obvious security reasons. Then you have to consider the quality of reserves you own and how you can adapt to market conditions, by reducing your costs because you know pretty well that your revenues are reduced in such an environment. One potential opportunity for LNG is the transportation and bunkering sector where crude oil products are replaced by natural gas. Our long-term strategy has not changed yet. It may change, if it looked like $50/B were here to stay. This would be a general change for the energy market, not just for Total.

So with an uncertain oil price outlook, what are the main factors driving new LNG projects?

Natural gas is experiencing the same glut as oil. Supply is greater than demand. The culprit is partly the US, which is becoming a big oil and gas producer. In terms of reserves, there is far more natural gas than crude oil accessible on the planet. The race will be between the best technologically available sources of production. The winners will be the less costly, well located projects in terms of security and distance to the final markets.

Having said that, we are in a world where the geo-strategy of hydrocarbons prevails over economic reasoning. Today the war within Iraq and dynamics with Iran are based on who is going to control the energy of the future. North America, Russia and the Middle East are competing for a greater role in supplying the whole world and the best place for “security of supply”.

If you start to threaten people with supply shortage, they walk away and try to find other solutions such as renewable energy, coal, or traditional energy from countries with greater security of supply.

How do you see the role of the Middle East in the global supply picture?

For the time being we are just reacting to political developments in the Middle East. We shut down operations in Libya [see p4], we are no longer in Syria. We have become very concerned in Yemen [see p16]. Qatar remains a big LNG producer, we hope it will remain so because of our involvement there with Qatargas. But the current moratorium means there will be no new LNG from the Middle East in the foreseeable future. It doesn’t mean that the Qataris will stay put. They will do what we do: find better places to do business. The Qataris, with ExxonMobil, will launch the Golden Pass project in the US which will serve their clients especially in Europe.

Aren’t Golden Pass and other projects in the US and Asia Pacific facing uncertainty due to current oil and gas prices?

For me, Golden Pass is not entirely based on pure economics. This project has a strategic importance and Qatar and ExxonMobil will go for it: short-term prices have no relevance when you talk strategy. They have spent billions of dollars on a white elephant in Golden Pass and the best way to use it is to transform it into an export plant. This future LNG could easily go to the UK and the west coast of Europe, while new markets like Pakistan, Bangladesh, Egypt and Jordan will be supplied by quantities diverted from the current UK or European contracts.

New buyers are not where you think they would be: they are in the Middle East and South Asia. Take Egypt, Pakistan and India, they all can be supplied by Qatar LNG.

After the wave of costly LNG projects, like Australia’s Gorgon LNG, Ichthys and Queensland LNG, all the reserves owners waiting for a market will be ready to contract additional trains at somewhat lower prices. Because people will need to work, we may well find ourselves in a low price environment for new projects.

Look at ExxonMobil, they have announced a third train in Papua New Guinea: it will not be low cost but marginal cost; it is well located; the Asian markets will love it.

Alaska LNG will go ahead for geopolitical reasons and sound economics after 2025. In Canada, one or two projects may be sanctioned by the end of next year. Look at who is promoting the project: if you have plenty of buyers owning the gas as well as the project, they may decide to go ahead and take the LNG for themselves, hedging their risks all along the LNG chain.

What minimum oil price would allow these projects to go ahead?

Again, you can’t just look at the price; there are projects which are meant to bring energy into countries like China and Japan where people actually need energy. I don’t want to say that the price doesn’t matter, but it’s about finding a price in line with the entire economics of producing the gas, transporting and liquefying it under conditions that allow their inclusion into existing end-users’ markets.

When it comes to Australia, it’s ‘wait and see’. People will be trying to regroup, try to find the best reserves they have, try to find the best projects for their buyers, and start talking to them.

In Mozambique, Eni, Anadarko and their partners have almost finalized the marketing phase so they may ask themselves twice on whether to go ahead or not. It’s a question of buyers and sellers talking together and agreeing on a time schedule, costs and prices.

Current spot LNG prices are currently around $7/mn BTU for Asian delivery in Asia, down from around $15/mn BTU a year ago and below the UK’s NBP price for the first time since 2010. What pricing trends do you expect in the coming months?

The situation is very simple on the spot market: we have the same price everywhere, from Japan to Brazil. Arbitrage opportunities are very limited. Atlantic basin LNG will be for Atlantic buyers while Pacific Basin for Pacific buyers for the time being.

We know what kind of surplus would be diverted to Europe if Asian buyers don’t take this extra LNG – there is a surplus of LNG coming from many places for different reasons (extra cargos, uncommitted quantities from new projects, quantities released after contract termination, etc...) therefore this situation may last more than six months.

How is your trading business affected?

It is not affected at all because we have hedged our position for the next three years. Our deals for this period are already cashed in and hedged. At present, we are working on deals from 2018 onwards.

What do you do beyond that period?

This is the beauty of a portfolio – if we have some more LNG from Yamal, or US LNG – because we have already some end-users contracts, priced where they were priced, so we will arrange the best supply for these buyers.

Compared with oil-indexed long-term contracts, how much do you expect spot LNG prices to fall and by when?

In Asia, if you assume a price of 14% to 15% of Brent value plus 1, we will have some prices between $7-8/mn BTU if we stay at $50/B. If it comes to $70-80/B, the LNG price will be proportionally higher. LNG contracted on long-term basis will still follow the same formula. But then, on top of that long-term LNG, you have so many offers for flexible LNG, with buyers trying to complement the long-term contract through these spot sales.

Oil indexed long-term contracts give buyers the confidence that they will receive their own base-load quantities and at a price which they know, because the price of oil is factored in the formula with a time lag of three to five months. So the price of April deliveries under a long-term contract is already known by now.

Do you think LNG producers will start wanting to renegotiate their oil-indexed long term contracts with buyers if low oil prices were to persist?

One has to abide by contractual terms. There are times when it is allowed to open the price again via “price reviews”, usually every five years, so some clients in Japan, Korea and Taiwan are always in price reviews. So if they start new renegotiations today for the next five years, of course today’s context will have an influence. There may be a return of the S-curve within contractual formulas. But, remember, in a negotiation both parties have to agree to new pricing.

So what kind of opportunities do current market conditions present?

Now is the time for traders and participants with geostrategic purposes. IOCs are just monitoring the situation, trying to see where their reserves are best located for the best markets. For them, strategy has nothing to do with short-term market considerations.

Because it’s a time for trading, the likes of Vitol and Trafigura are taking big risks, in supplying Egypt [see p6], Argentina, countries where the money supply is not guaranteed.

New LNG candidates say they want LNG, so you have to believe them. If Abu Dhabi says it will build an import terminal in Fujairah, I hope that they mean it! The same applies to Bangladesh and Pakistan. Everybody needs LNG! But are they ready to pay for the necessary infrastructure to receive it? The current conditions might be an opportunity for such candidates.

But there is plenty of LNG around, and there’s even talk of some Asian buyers committing to take too much LNG between now and the end of the decade?

I don’t think Asian buyers have committed too much. Among currently operating LNG plants, some were targeting the US and Europe at their FID time, some years ago. The aftermath of the Fukashima nuclear disaster in 2011 witnessed a shift between the Atlantic Basin and the Pacific region, especially due to an increase in Japanese imports (with a plateau at 88mn tons/year).

A new wave of LNG was contracted and is under finalization in Papua New Guinea and Australia. From these new plants a certain amount of uncontracted LNG will have to find a home at buyers’ terminals. If not in Asia, this extra LNG will have to come back to Europe.

As far as new LNG projects are concerned, they have now to look for 2020+ buyers’ needs, which may come from termination of former contracts and start-up of brand new buyers like Pakistan, Bangladesh and the Middle East.

How much can Middle East countries absorb?

Some Middle East countries have already started importing LNG: Kuwait and Dubai; others have taken the decision to do the same, like Egypt, Jordan and Fujairah (UAE). These imports are starting to become substantial and will absorb quantities initially intended for the US or European markets. Don’t forget, however, that a well-designed pipeline policy could also supply these countries from huge producers like Iran, Iraq, Qatar and to a lesser extent Israel.

What does this mean for the market and potential competition?

Competition now is between suppliers. In Europe, buyers can relax because they don’t need LNG anyway. And in Asia, the traditional buyers have plenty, they have covered their long-term needs [until around 2020 after which some buyers will have to renew some existing contracts]. So now there are opportunistic buyers and they take what is available on the market. They are contracting with suppliers: Aqaba LNG (Jordan) is talking to Shell; Pakistan and Bangladesh to Qatar, and Egypt to Sonatrach, Gazprom and Trafigura, even Vitol for short term supplies. The result of exploration in Egypt shows there is potential for natural gas production in Egypt, but timing is not good for huge investment in Egypt today. So the only thing they can do is import, start building an industry which is reliable and go back to domestic production when times are better. One serious issue here is security: the region is not right for business today.

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