Floating LNG

One of the main challenges of LNG has been the massive related infrastructure.  First, you need a natural gas field that can deliver enough gas to justify building pipelines, ports, liquefaction and storage facilities, etc., etc.  These projects cost not billions of dollars, but tens of billions of dollars "all in".

What if you could do the liquefaction on a ship?  Then you could locate the ship near an offshore LNG field, load the cargoes directly onto LNG tankers, and when the gas field is tapped out, move the plant. 

I attended part of METI's annual LNG Producer-Consumer Conference yesterday, November 6, 2014.  In the "new technology" panel, I was expecting a lot of discussion about gas-powered fuel cell generators, compressed gas vehicles, etc.  The head of Tokyo Gas did discuss these things, at a very high level, but others focused on upstream developments.  Someone from Anadarko just talked up their Mozambique project -- a sale pitch and not much about technology.  The President of Chiyoda gave a general corporate presentation on their track record in LNG.

But representatives of both Shell and JGC did at least spend most of their presentations on new technology -- in this case, floating LNG.

An image of Shell's floating LNG concept

Shell's Prelude LNG facility, whose hull launched in 2013, will weigh five times as much as a U.S. nuclear-powered aircraft carrier when in operation, and be almost 500 meters long.  The cost?  Guesstimated to be over US$10 billion.

The hull of its first FLNG, launched and in the water.

JGC and Samsung Heavy Industries have been selected to build another floating plant, for Petronas, (the national oil company of Malaysia).

These facilities could significantly reduce the cost of opening up new gas fields for LNG shipment, and could allow LNG to flow from fields that otherwise would not justify the investment for pipelines and an onshore plant ...  Of course, this will increase already intense competition among producers for support from major LNG consumers in Japan, Korea, China and India.

Of course, just as with Enron's infamous barge-mounted power plants (infamous because they were the assets involved in a dodgy asset sale/buy back at the end of a financial year that resulted in several investment bankers going off to prison, if memory serves), a floating LNG liquefaction plant also helps with political risk.  In case of war or threat of expropriation ...just sail away and moor at some other gas field. 

Energy Options for Japan -- Alaskan LNG

Is the glass half full, or is it half empty?

When the GOJ began pushing for a nuclear restart in late 2012/early 2013, Japan's energy options looked fairly bleak.  A real glass half empty situation.

Imported oil and gas had pushed Japan into its first trade deficit in many years. Anticipated summer/winter peak electricity demand could only be met with "command and control" efforts to shift factory production, combined with the restart old oil-fired generation online, deferral of maintenance on other plants, and a significant boost in consumer electricity rates (again).  The renewables feed-in-tariff was resulting in lots of applications for "expensive, unreliable" (according to the powers that be) solar PV, but almost no baseload geothermal or biomass on the horizon.

Now, one cannot help but feel better about the situation.  Let me again highlight one (of many) areas.

Alaska LNG

The main bright spot is LNG.  New LNG sources have come online, and will continue to come online.  

The Exxon-led Papua New Guinea (or "PNG") project's first LNG train started producing this Spring, almost a half year ahead of schedule, and pushed down prices in the (relatively thin) spot market dramatically.  There are plans to ship LNG from Russia part of the year via the Arctic Ocean within the next 3-4 years.  U.S. LNG exports will begin in 2017 or 2018, and the amount of exported LNG -- even if most of it ends up going into the Atlantic rather than Pacific basin -- should have a big impact on pricing.  Japan's total annual LNG imports run at around 90 million tonnes.  US export permits have been approved for something in the range of 70 million tonnes annually. The price moderating impact is especially large since the U.S. "lower 48" gas and LNG businesses are less vertically integrated than elsewhere, so we will see gas cargo destinations shifting based upon price and demand factors.

Now, this week, some focus on another exciting potential source.  Alaska!  That's right, Alaska has a huge, cheaply accessible gas resource in the same Prudhoe Bay area as the oil reservoir that has fed the oil pipeline over the past 30-35 years.  This does not require building in a wilderness reserve such as ANWR.  Rather, it just involves taking gas out of the existing area where oil is being extracted, instead of re-inserting the gas.  And a new gas pipeline would be built adjacent to the existing oil pipeline along much of its route, to minimize environmental impact.  

The project has been on the drawing board in one form or another since the 1990s, and was making good progress toward being realized (in a different form--primarily for distribution via pipeline into the Lower 48 states via Canada) when the shale gas boom set it back.  Indeed, in 2004, just before the shale gas boom, Congress had established a special coordinating agency to ease the permitting process for the project.  Now the project is back and making real progress.

Map of the potential pipeline route, from website of the Office of the Federal Coordinator for Alaska Natural Gas Transportation Projects

The State of Alaska and companies involved -- 3 oil "majors" and a pipeline company (Exxon, BP, Conoco-Phillips and Trans-Canada) signed an MOU in July to do the front-end engineering and other preparatory work on this project.  Earlier this month they filed FERC applications (and according to press reports FERC will "fast track" the project given its limited impact on domestic U.S. gas markets).  JBIC is studying the project for potential financing.  And this week METI's Energy and Natural Resources Agency signed an MOU with Alaska's Department of Natural Resources to cooperate in various preliminary activities -- information exchange, potential financing and subsidy arrangements for participation by Japanese entities, etc.  Not coincidentally, BP arranged a trip to Japan and Korea this week together with State of Alaska officials to meet with potential LNG buyers.

The project, which would take more than a decade to realize, could supply over 20% of Japan's current LNG requirements, provide a huge economic boost to Alaska, diversify Japanese LNG supply with LNG from a political ally and stable source -- thus dramatically increase Japan's economic security. This LNG could help fuel new, extremely efficient gas-driven generation methods (including fuel cell generation such as Bloom Energy's current/future products and GE's potential "hybrid fuel cell" generator) and ease Japan in its transition from imported fossil fuels to a future driven by renewable energy and a "hydrogen-based economy".

A description by the project sponsors can be found here.

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So even if the legacy participants in Japan's electric power industry face a relatively bleak future -- with trillions of yen of stranded assets, decades of decommissioning costs and a clean up at Fukushima that will take the rest of my lifetime and beyond, it is difficult not to be optimistic about the energy transformation that can and should occur over the next decade or two.

Japan LNG spot market prices drop like a rock

Nikkei reported this morning, July 5, that LNG spot market prices have fallen rapidly over the past 3 months and are now lower than any time since 2011 before the Fukushima accident, around US$11 per MMBTU, down 40% from their peak in February.

Why the drop?  First, LNG inventories of the Japanese utilities and of KOGAS (Korea's public gas utility) are now at high levels, with Japanese utilities inventories 13% higher than last year at 2.44 million metric tonnes.  Second, gas demand in Japan this March-May was lower than last year, supposedly reflecting warmer than usual late winter/early spring weather, and the start up of a large new TEPCO coal-fired plant.

But most important, the first "train" of a new LNG source came online in Papua New Guinea in May, a few months earlier than expected.  The new LNG infrastructure was developed with Exxon Mobil in the lead (and Japanese participation, of course) at a cost of US$19 billion.  Eventually, it will more than double the GDP (and export volume) of Papua New Guinea.  There are apparently has spot cargoes available, at least for now.

How much does this lower gas price help Japan?  Not a lot yet.  Currently 80% of Japanese LNG is imported under 10-20 year long term contracts priced off of middle Eastern crude oil.  Gas under those contracts is at around $15-16 per MMBTU, only down slightly from its peak.

But over the medium term, this can be a huge positive. Almost no Japan LNG imports were done via spot or shorter-term purchases prior to the Fukushima accident, and the fact that 20% of purchases are now under short-term contracts (defined as less than 4 years) is helping to develop a market.  The existence of functional, deep and broad wholesale markets is an essential step to creating competition in not only the gas and LNG business but also downstream electricity generation in Japan.

LNG and Gas Market Developments

With Japan's nuclear reactor fleet shut, much of the focus on reliable, affordable generation over the decades required to transition away from nuclear will be on LNG.  The press is full of reports of developments in Japan relating to new gas-fired generation, changes in the gas markets, and liberalization efforts.  Japan pays $15-20 per MMBTU for its LNG upon import, whereas gas trades for 20-25% of that price within the U.S.A.  A crucial item for Japanese energy policy is thus to obtain cheaper, diversified sources of LNG supply.  A few reports:

November 8.  Tokyo commodities exchange announces a plan for LNG commodities trading market, to support the move away from oil-linked long term pricing structures -- currently over 80% of Japanese LNG is purchased based upon 10~20 year oil-price-linked agreements.  This is the first step to a futures market in LNG in Japan.

November 13.  TEPCO announces it is considering outsourcing some fuel procurement activities to reduce its LNG acquisition costs.

November 28.  Tokyo, Osaka and Toho Gas companies announce support for full retail price liberalization and competitive schemes.

November 28.  Japanese shipbuilders have a huge increase in orders for LNG tankers -- 90 ships on order now for delivery by 2020.

November 29.  The Tokyo commodities exchange reports negotiations with the CME (Chicago Mercantile Exchange) for a business tie-up in the area of LNG trading.

LNG Prices go ... EVEN HIGHER in Japan this summer

According to press reports, spot LNG import prices into Japan are reportedly back about US$16 per MMBTU (million BTUs) since May, as increased demand for summer electricity generation pushes up the prices.

South Korea also is now in a partial nuclear shutdown/suspension mode, because of safety concerns about faked certificates and suspect equipment, and this has further added to demand, together with extreme, protracted hot weather.

The $16 per MMBTU price is a 10% increase from the lows reached in springtime, but down from the nearly $20 peak reached in January/early February.  US Henry Hub gas prices in recent years have been between $2 and $4.  Add another $3 or $4 for liquefaction and transport, and the obvious question is why Japanese prices should ever exceed the $8-$10 range over the medium/long term?

This situation highlights the need for Japan to diversify its sources of LNG supply, and to take advantage of potential increased lower-priced natural gas availability all around the Pacific Rim (starting with the U.S. and Canada), if it is to manage a transition away from nuclear power.

End Global Warming in Two Easy Steps

As stated by Noah Smith in The Atlantic last fall.

1.  Transition with natural gas.

U.S. CO2 emissions are declining rapidly with a shift from coal to natural gas.  Down over 10% since 2007, and continuing to decline even as the U.S. economy has grown back since the financial crisis.  Shift from coal to gas is made possible as a result of the shale gas boom and massive new gas supplies coming on line.

2.  Solar (and other renewables)

Solar PV pricing is following its own sort of "Moore's Law" -- 7% annual decline in costs annually for MANY years past, and likely to continue at the same rate for the next 20 years at least.  Increasingly available and cheaper electricity from renewables will allow a transition to electric vehicles and gradual shift away from oil and coal entirely.

Short term -- shift from coal to gas.

Longer term -- shift entirely to renewables.