Two catalysts just ratcheted up investor interest in west coast LNG—Liquefied Natural Gas.

One was the re-election of the centre-right Liberal party in British Columbia in May.  The second catalyst came in mid-June, when Malaysia’s Petronas announced it wants to spend $16 billion—as fast as government approvals will allow—to ship LNG to Asia.

Newswires are full of LNG talk, and it’s great to see excitement running high.  The stocks of some of the service companies that will receive a piece of those billions of dollars—drillers, frackers, construction companies—are already starting to run.

But what’s the reality?  There needs to be a lot of consensus building and government approvals before the infrastructure building begins.   The first LNG shipment off Canada’s west coast is now forecast to be 2015, but that’s from the smallest proposed facility.  The next one isn’t set to start up until 2018—and a lot can happen between now and then.

Great strides have been taken, but some key questions remain completely unanswered—When will any of the big consortiums actually ink a supply deal, and at what price?

So with a focus on reality, I updated the development status of today’s key LNG projects…

Let me first give you a context for the many numbers I’ll be talking about below.

At the start of 2013, the world’s LNG facilities could produce 290 million tonnes per annum (mtpa), or 38.6 billion cubic feet of gas per day (very roughly, 1 bcfpd=7.5 mtpa)—just enough to meet global demand of 250 mtpa, or 33.3 bcfpd.

As background, the US right now is producing 65 bcfpd—so all the LNG in the world today would meet half the US daily requirements—so it’s still small. But that is a four-fold increase in 20 years…and demand forecasts from here continue in just one direction: up.

What’s more, the International Energy Agency (IEA) predicts LNG demand could double by 2030.

Whether the world will have enough LNG facilities to meet that demand remains to be seen. A staggering 480 mtpa (64 bcfpd) of new capacity has been proposed, but most of that will never make it off the page.

Australia leads the pack in terms of facilities already under construction: the Land Down Under is now producing 2.5 bcfpd, but seven onshore and five floating centers will boost output to 15 bcfpd by 2018. That ramp-up will push Australia past Qatar into top spot in the global LNG producers list.

But the achievement is coming at a cost. Development costs have ballooned on many projects, propelled upwards by a strong Australian dollar and high labour and material costs. For example, the price tag to build the Gorgon LNG project has climbed from $39 billion to $52 billion – and the project is still 18 months from completion.

Gorgon is a large LNG project – it will produce 15.6 mtpa (just over 2 bcfpd) – but almost every LNG facility is a multi-billion dollar dream. To access that kind of capital, would-be LNG producers have to lock down buyers—they have to ink offtake deals with set pricing for most of their product to assure lenders that the billions loaned to build the plant will be repaid.

Of course, producers want high prices, buyers want low prices…and that’s where the story sits today. Asia consumes three-quarters of the world’s LNG and strong demand has pushed Asian prices way up. Asian buyers are sick of it – they want to pay reasonable rates and, knowing that a flood of LNG is coming, they are waiting as long as possible to sign on for new supply.

Their patience is developers’ pain. Almost a dozen consortiums are vying to build LNG facilities on BC’s coast but only one – the smallest by far – has locked in a buyer for a significant proportion of its production. That means all the rest are still facing the huge hurdles of securing LNG buyers and finding project financing.

The 4 Main Players in British Columbia, Canada’s West Coast

The field of BC LNG players includes several of the world’s biggest energy companies, a handful of mega national energy firms, and the biggest LNG buyers in the world, all in a race with each other and with similar projects around the world.

Of the nine LNG facilities proposed for BC’s West Coast, four are much more advanced than the rest.

1. Douglas Channel LNG

The smallest and most advanced LNG project, Douglas Channel, differs from the rest of the LNG pack in not involving a major energy company. Instead, the project is a partnership between the Haisla First Nation and LNG Partners, a private Texan energy fund that funds First Nation’s participation in projects.

The project is planned for the west bank of Douglas Channel, within the District of Kitimat and on land controlled by the Haisla First Nation.

The Douglas Channel project is small enough that is doesn’t have to go through the environmental assessment process. The operation would produce just 0.7 mtpa or 0.09 bcfpd – and the project boasts a secure buyer for that output. Golar LNG, one of the world’s largest independent operators of LNG carriers, and LNG Partners will buy all of Douglas Channel’s product.

Golar, along with an as-yet unnamed Asian investor, also bought a 25% stake in the project for an undisclosed sum—so they’re not just the LNG shipper. The new project partners will also provide the $500 million needed to get the project built and into operation.

The project has a National Energy Board (NEB) export license and expects to be in service by 2015. Gas will flow to the facility through the existing Pacific Northern Gas pipeline. The ducks are all lined up on this one and a final investment decision is expected within a few months.

2. Kitimat LNG

The second-smallest and second-most-advanced LNG proposal, Kitimat LNG, is backed by energy giant Chevron and oil and gas major Apache. They want to build a 5-mtpa or 0.75-bcfpd facility to process gas from their joint shale gas properties in the Horn River and Liard Basins up near the Yukon border.

In fact, the entire process will be a joint venture, from producing the gas to piping it to the coast and liquefying it. The project has NEB approval, as well as an environmental green light from the BC and federal governments.

Also approved: a 463-km long connecting Kitimat to the Spectra Energy gas transmission system near Summit Lake. And the existing transmission line serving Kitimat would suffice to power the project.

All that’s needed now is a final investment decision. That may depend on locking in a buyer, something this project has not yet managed.  Chevron has said if it doesn’t get oil-linked pricing, it will likely not proceed.

3. LNG Canada

LNG Canada is at the other end of the LNG spectrum: it’s big and it’s being advanced by an almost ridiculous list of energy and LNG giants.

Partnering on the project are Royal Dutch Shell, Korea Gas, Mitsubishi, and PetroChina – in other words, an energy giant and leading LNG producer, the world’s largest LNG importer, Japan’s leading LNG importer, and China’s largest oil and gas producer.

The partners want to build a liquefaction facility and loadout terminal in Kitimat. At maximum capacity the facility would produce 37 mtpa or 5 bcfpd and the terminal would accommodate two LNG carriers. It’s the largest proposed facility to date.

It’s big enough to require some big infrastructure, including a bigger power line from Prince George in central B.C. to Terrace near the coast—AND a new pipeline. TransCanada (TRP-TSX/NYSE) has signed on to build that pipeline, a 48-inch, 650-km project running from the shale fields of northeastern BC to Kitimat. Neither the powerline nor the pipeline has entered the environmental assessment process.

The LNG facility itself has started that process, recently submitting a Project Description to the Canadian Environmental Assessment Agency (CEAA) and the BC Environmental Assessment Office (BC EAO). The assessment process usually takes about two years.

The NEB already granted the project approval. No suppliers have signed on to buy LNG Canada’s output, but does have a distinct advantage on that front: two of the project partners are major LNG buyers. As such, a deal will likely be made at the boardroom table.

4. Pacific Northwest LNG

The main proponent behind this proposal is Malaysia’s national oil company, Petronas. Until late last year Petronas was partnered with Progress Energy on the proposal, but that ended when Petronas bought Progress for $6 billion. Shortly after the company signed Japan Petroleum Exploration on as a 10% partner, and Petronas is apparently in talks with other interested parties.

Petronas wants to build an 18 mtpa or 2.4 bcfpd liquefaction plant in Prince Rupert. The company wants to start building in late 2014, but that might be tight given that the project has not won environmental, NEB, or pipeline approval.

What it lacks in authorization Petronas is making up for in publicity. In January the company trumpeted a deal that will see TransCanada design, build, own, and operate the gas pipeline needed to feed Petronas’ plant.

Then in mid-June, a few weeks after the pro-LNG Liberal Party returned to power in BC, Petronas outlined its spending plans: the company expects to drop between $9 and $11 billion on the LNG facility, plus $5 billion on the pipeline and “several billion more” on upstream operations.

Petronas has not locked down a supply deal, though Japex’s arrival as a 10% partner points the finger at one likely buyer.

In the end, what does it all mean?  The excitement is a little ahead of reality right now—but only a little.  Golar and the LNG Co-operative are looking like a sure bet to ship LNG out in 2015, and everyone is rightly enthused.

And an ocean of money is waiting to come with all the other projects.  But there is a Big Dam—a long-term contract with an end user.  However, two of the four other proposals have end users as part of their group, so that should only be a matter of time.

For Western Canadian service companies and gas producers, that time can’t come soon enough.

by +Keith Schaefer

Japan spent US$75.4 billion on LNG last year, paying an average price of US$16.60 per million BTU—while gas prices in the United States averaged just US$2.75. No Japanese politician, economist, or grocer thinks that makes sense. So Asia is trying to lower prices for Liquefied Natural Gas (LNG) as fast as they can.

Basic supply-demand theory says the pending flood of new supply from around the globe will push prices down over time. But lower prices aren’t just about supply-side growth.

They’re also about transparency.

LNG prices have long been linked to the price of oil—with gas priced at roughly 13% or 1/8th the price of Brent, with the details determined in confidential contract negotiations. Asian consumers are tired of this linkage, especially since it has meant prices that are four times higher in Asia than in North America.

It’s a fact that de-linking LNG prices from oil to Henry Hub makes a BIG difference for Asian buyers. For example Cheniere agreed to sell 1.6 to 1.8 mtpa to Korean Gas for US$3 per MMBTU plus a 15% premium to Henry Hub prices.

Context: On April 30, 13% of Brent would equal $13.47/mcf. On the same day the Cheniere deal would have Korean Gas paying ~$7.51/mcf. That’s a big difference! Cheniere has signed similar Henry Hub-indexed deals with three other buyers.

But Asia doesn’t just want lower prices in individual deals. No, Asian buyers want the market to determine how much LNG is worth –they are convinced the market will push LNG prices down fast with waves of new supply on the horizon.

They may or may not be right on this one.

Futures contracts are the way markets determine how much a commodity is worth. For LNG such a system would also improve the credibility of pricing information and act as a valuable hedging tool.

Japan is pushing for a futures market for LNG—and the potential Canadian supply could be the first to get priced this way.

It’s not just talk. In March Japan’s Ministry of Economy, Trade, and Industry (METI) announced plans to launch the first LNG futures contract at the Tokyo Commodity Exchange in two stages starting in 2014.

The first step would be a cash-settled contract, with settlements based on the spot price on the last session of the month. These cash-settled futures could be sold up to one year forward and would be based in US dollars and metric tonnes.

When I heard this, I called Dan Dicker in New York, former floor trader and author of Oil’s Endless Bid—the best book I ever read about the financialization of commodity prices and what it means for retail consumers (it means higher prices and more money out of our pockets).

My overall question was—would a futures market lower prices? Or would the financialization of LNG do what it did for oil: create endless bids and higher prices? The short answer on both was no.

“Creating a futures market won’t help create a cheaper pricing mechanism,” he told me. “Yes, it’s going to be less related to Brent and more to nat gas—but more to local/Asian nat gas, where prices are high—not North American natural gas. If I was trading physical, that’s how I would expect the new market to react.”

Dicker is the kind of trader who would play in a LNG futures market – and he thinks Asian prices would stay high.

The problem is that a commodity market needs a full complement of players. Producers, wanting high prices, are already long in an emerging futures market. To counter, LNG buyers are naturally on the short side. Then traders enter the scene, playing the difference and speculating on the actual supply-demand situation.

Dicker says it took years for this financialization of natural gas to take hold in the US and it was the investment banks who added enough outside players to make that happen.

Japan may want free market LNG, but to financialize LNG it will need a bigger playing field.

Japan has a natural market of LNG buyers—the country’s utilities. What Japan doesn’t have is a natural market of sellers – they don’t have a large homogeneous group of providers, like the United States has with its oil producers.

So the question is: Could financialization of LNG give rise to an endless bid cycle?

Might Japan be putting the cart before the horse?

Not only are the players lacking, but Japan’s proposal has some gaping holes. For one, the futures LNG market it imagines would be for true physical delivery— buyers would actually want to take possession of LNG.

In the US, the futures almost never become physical – which is the case with most futures markets. So they – Henry Hub and Japan’s LNG proposal – are very different markets. And there’s little in the way of a blueprint for Japan’s version.

That doesn’t mean we don’t need a better pricing mechanism for LNG. The growing spot market desperately wants one.

The spot LNG market is growing, and fast. Spot trades grew from 10% of global LNG trade in 2003 to 25% in 2011, and volumes continue to climb.

There’s a good reason the spot market is hopping – buyers and sellers want more options. A natural disaster here, a hurricane there – LNG needs can change quickly and so supply flexibility is an increasingly important concept in the LNG world.

For a spot market to hop, however, requires a recognized and reputable spot price…such as a futures market.

It’s a chicken-or-egg scenario, for sure.

While Japan’s futures market could start next year, it will still take years for global LNG prices to break free from oil indexes and secretive long-term contracts. The next wave of LNG supply to come online will be in Australia, in 2015—and they have sold their gas in long-term contracts at oil-indexed prices.

But the system will change, eventually, because LNG is outgrowing its pricing and trade systems. Such is the cost of success.

It will be very interesting to see how it all pans out – and how LNG proposals in Canada react.

by +Keith Schaefer