About 10 years ago there was major buzz and much hand wringing over predictions of big time natural gas shortages for the United States.
Investors at that time lined up to support companies that were working to acquire the needed permits to construct LNG import terminals to ensure future supplies of gas for the country.
Then the shale gas boom got under way, shortly before demand tanked in tandem with the economy.
So, here we sit with natural gas storage facilities brimful and gas prices so low they make you want to cry.
But don’t cry for LNG. It hasn’t gone away; it’s just a different game now.
The EXPLORER talked to Gurcan Gulen, senior energy economist Center for Energy Economics at the Bureau of Economic Geology, Jackson School of Geosciences at University of Texas, Austin, shortly before he presented a talk on the subject at the recent AAPG Annual Convention and Exhibition in Houston.
Gulen provided the skinny on LNG today.
GULEN: The nature of LNG trade has been changing in terms of, traditionally the industry depended on long-term contracts, usually at fixed prices or prices indexed to either crude oil or some combination of oil products.
The most famous is the Japanese crude cocktail. This is a combination of different crudes, and they have a formula they use to determine the price of LNG they import. The idea goes back a long time to when natural gas was much more of a direct substitute for oil products and the oil and gas price relationship was more stable than now. In a country like Japan energy security is of utmost priority, so they may be willing to pay a premium; there was a belief that if you use this formula, you will have secure supplies.
Another reason for long-term contracts is LNG investment. If you look at the value chain, it’s an integrated project and very expensive. It’s a lot of work from a project financing perspective, not to mention developing the resource itself upstream.
But we have observed the increasing share for spot cargoes in the late ‘90s and 2000s. This means there are cargoes out there that are not tied into long-term contracts or, if they are, the newer contracts have some flexibility clauses in them.
For example, if a buyer doesn’t need a supply and the supplier has other markets, there’s flexibility in a contract such that they can agree on a compensation scheme – or the supplier can send the cargo somewhere else. This also can work in reverse should the supplier find another customer and compensate the buyer.
How much of this is going on is debatable. People thought this would change the nature of the markets, but it hasn’t done so to the extent some thought five to 10 years ago. It’s still a very capital-intensive chain where you’re building all those specialty ships and so on. You can’t expose too much of that value to volatility in the marketplace. A part of the volatility comes from the domestic development of natural gas resources; the shale gas situation in the United States is one of the best examples.
GULEN: Ten years ago, when production was declining and prices going up, about 60 LNG projects were proposed. There was a lot of scary information all over the Internet about tankers, regasification facilities and such, and we ended up with a handful of terminals, mostly in the Gulf Coast, Mexico or Canada.
Because of increased production from shales and stable or even decreased demand, these terminals are mostly idle.
Some are talking about exporting LNG from the United States, but this is a tough proposition.
If you look at the global marketplace, Europe and China and others could start developing their own shale gas and change the picture a little bit. The LNG supply capacity is out there, such as in Qatar, Australia and elsewhere, but with demand stagnant since 2008 because of the economic recession, we must ask if there is room for LNG from the United States in this marketplace.
GULEN: The LNG market is two separate markets – the Atlantic and the Pacific.
In the Atlantic market the Europeans are the biggest customers and are getting their LNG now from such places as the Middle East and West Africa.
Can the United States compete with these guys in this market?
When we look at the upstream cost here, how much shale gas can we continue to produce at increasing production levels?
What price does that require?
Some say you can make money at $3 (Mcf), but that’s questionable. I have to say, “show me.” Even if upstream production is at $3, by the time you do liquefaction facilities and things like that, at what price are you going to be able to send that LNG to Europe? Six dollars? Seven dollars?
An important thing happening in Europe is they seem to be weaning off of formula pricing that ties the price of LNG to oil. If they succeed, then LNG prices will drop because of market conditions in the LNG market.
Oil and gas prices aren’t closely related anymore and move to their own tunes now. Oil prices likely will continue to go up, probably for the foreseeable future; production growth is limited because most of the attractive resource places aren’t easily available.
But if shale gas is as successful elsewhere in the world as the United States, we’ll have plenty of supply – not to mention the world has plenty of conventional gas all over the place.
LNG prices on an energy content basis will be much cheaper than oil, and that’s why the Europeans are trying to get rid of oil index formulas – it makes LNG too expensive for them. If that happens, then definitely the Algerians, Angolans, Nigerians, Qataris can sell LNG to Europe much cheaper than the United States. That’s one of the fundamental issues of exporting LNG from the United States. Also, you want to send consistent volume cargoes to customers; you can’t expect to make a lot of money with spot cargoes.
As to the Pacific market, we have the Kitimat terminal in Canada – because we couldn’t build it on the U.S. West Coast. It was originally designed as an import terminal, but now they have the same excess gas situation because of the attractive shale plays in British Columbia.
They use a lot of gas to heat the oil sands in Alberta. They also can send some of that gas to Kitimat if they build liquefaction facilities, and then can send it to the Pacific markets.
In all of North America, there’s only one export facility, and that’s in Alaska. It’s been sending LNG to Japan since the ‘60s. The Pacific market may not let go of the oil price index formulas for LNG pricing, because energy security is the utmost priority for Japan and South Korea.
Today, the nuclear plants are down, and that’s significant capacity they must substitute with something. They will be willing to pay a bit higher prices for LNG than the Europeans, so exporting LNG from Kitimat is feasible.
GULEN: We must be careful about our own needs for domestic gas once the economic recovery takes place.
There are some pressures on coal-fired generators; some are old and have emission problems like mercury, SO2, NOx, CO2. If these shut down, there will be greater gas demand from industrial users, so we’ll need a lot of gas here.
I’m not sure we have enough cheap gas to meet our domestic needs and also export. The nature of these markets is boom-bust, and we should not believe in a new world of $4 gas for the foreseeable future.