13 Feb Canada’s LNG projects: Another year, another delay
When might Canada’s LNG projects get sanctioned? Potentially sooner than conditions suggest, with a good overhaul. Here’s why.
LNG: a study in patience
The future of the LNG industry will be the subject of my presentation at the CERI summit in Calgary later this year. Having spent 4 years in Queensland Australia working around the 4 big projects there (three now into production, the fourth stalled on the drawing board), I have a view as to what conditions need to line up for projects to proceed.
Frankly, conditions are still sufficiently murky that Boards will likely wait to see how markets evolve before sanctioning any of the Canadian projects. Meanwhile, a dose of digital thinking will help get costs in line.
Prices are down
Boards like to see strong pricing forecasts, but LNG prices have been down for some time, with no turnaround in sight. Prices for contract LNG (that is, not spot LNG) are linked to the price of oil in a formula agreed by the buyer and the seller. Canada’s LNG shipments would most likely head to Asia, where LNG prices are determined with reference to the average price of the top 20 crude oil imported to Japan’s refineries. This price index is called the Japan Customs-cleared Crude (or JCC), affectionately called the Japan Crude Cocktail.
In case you’ve been off planet for the past 36 months, you know that the price of crude oil has tumbled from a high of $100/bbl in late 2013, to just above $50 today. The JCC has not been immune to these market forces and Japan is paying much less for crude oil as a result. By extension, LNG prices are down, not by the same 50% (LNG contracts frequently have a floor price), but still enough to throw the profitability of these projects into doubt.
Contract LNG prices therefore await a turnaround in oil prices. Latest forecasts are for oil prices to hover in this $50-$60 range for the next 24 months.
Spot LNG prices could offer some respite, but it’s unlikely that Boards will be able to sanction a $20B capital project that is solely exposed to a highly volatile spot market. Project financing lenders will want some certainty that they’ll get paid, and too much spot exposure makes lenders nervous.
BTW, contract LNG prices in Japan in December were around $8/mmBtu, with spot prices a little above at $8.50/mmBtu. Assume it takes about $2/mmBtu to ship LNG to Tokyo, another $2/mmBtu to recover liquefaction facility costs, and $1/mmBtu in energy costs at the plant. That leaves $3/mmBtu to be split by the gas supplier, the toll to ship gas to the coast, and the royalty take. Margins are going to be razor thin for everyone in this scenario.
Eight bucks is actually a generous price. Last fall, contract prices were just $6, and spot was down to $4.50.
Supply is about to balloon out
Markets look to be drowning in LNG supply. Back in 2012, LNG trade was 327 million tons. Starting in 2015, and continuing through 2017 (and into 2018), one new 4 million ton LNG manufacturing plant comes on line every other month or so. This equates to an incremental 1200 cargos of 150,000 cubic meters of LNG, over and above the 2012 supply. You have to ask where all this supply will go. It hasn’t hit the market yet, and still prices are down.
All this new supply coming to market has to go somewhere. Some will replace existing contracts that come to an end, or to replace the supply from retiring LNG plants (although I’m not aware of any LNG plants that have been mothballed).
LNG demand appears flat starting in 2011 when 330m cubic meters of LNG exchanged hands. Fast forward to 2015, and trade is still just 338m cubic meters. Since a cubic meter of LNG is about one half ton, trade appears to have increased by only 4 million tons.
Trade is not demand, of course, because trade is capped by supply (LNG can’t be stored for long, and it degrades during transportation), and few new LNG plants came on stream between 2011 and 2015. So we can’t really tell what the true demand for LNG might be. Presumably all those LNG cargoes are accounted for, but perhaps not.
LNG demand is driven by the addition of new burner tips (that is, whole new markets of consumers), or burners running longer in existing markets (look for cold weather, or hot weather). There’s the occasional announcement of new regasification plants but nothing close to enough for the tidal wave of supply.
Costs too high
The cost of delivering an LNG project in Australia has been very sobering for the Boards that have to sanction the Canadian projects.
While in Australia, I had opportunity to benchmark global LNG projects to understand their break even costs. We concluded that the Queensland LNG projects require a 20 year average market price of $16/mmBtu in Tokyo to break even. The Western Australian projects were not much better, ranging from $12 to $16.
Compare that to a market price today of $8.
We broke the LNG project costs down into upstream capex (drilling gas wells, building gas plants, building a pipeline), downstream capex (building the LNG plant, jetty and tanks), upstream operating costs, downstream operating costs, and shipping costs. We wanted to zero in on specific changes that an LNG project would need to execute to reduce the break even cost.
One of our calculations showed that to reduce the lifetime break even cost by just $1 required far more efficient capital execution in Australia. The capital investments (plants, pipelines) would need to be built 25% faster. Another calculation revealed that upstream operating costs (maintaining wells, flow lines) would require a 75% reduction from expected over 20 years to reduce the break even costs by a further $1.
The large Canadian LNG projects look suspiciously like the Australian projects. They have the same owners, same development models, same overall designs (large megaton tidal plants, big transcontinental pipelines, green-field gas, harsh locations). The Canadian projects, unless they do many things radically differently, are going to have broadly the same cost profiles. Applying digital technologies to this challenge will make a considerable dent in project economics.
My conclusion is that supply, demand, pricing and costs do not favour expansion of the industry at this time.
Signposts to watch
Meanwhile, I’m keeping an eye on a number of developments in the global oil and gas sector for clues about the timing of Canada’s great LNG hope.
OPEC’s agenda to reset oil prices higher by constricting supply, and the degree to which the members comply. So far, it’s working, but OPEC has proven itself incapable of holding the line on production for long.
The level of cooperation between OPEC and Russia. The Russian oil and gas industry can be cajoled by the Kremlin to work with OPEC and trim production a bit (Russian oil reservoirs aren’t as easy to swing as OPEC). Russia can use the revenues too.
The success of Saudi Aramco’s IPO and potential to boost pricing. The Saudis want Aramco to have a strong IPO to maximise the treasury, so trimming supply helps. Afterwards, however, I wonder how responsive Aramco will be to market pressures. Today they need only respond to the King.
The amount of oil in storage and the pace by which it is monetised which keeps pricing down. Something like a 300m barrels of oil are in storage, a volume which is material to the overall market.
The activity in the US and Canada to complete the big inventory of drilled wells. The North Americans have thousands of wells that need fracking services to get into production. Incremental oil volumes may boost supply and depress prices.
The level of light tight oil drilling activity in North America, a resource that has transformed capital velocity and intensity. These wells are faster and cheaper to get into production, unlike a big off shore resource that can take years and billions to bring on line.
The success in the North Sea to reset its costs and keep the basin active. OPEC’s price management agenda is actually aimed at killing off big additions to base supply, like the North Sea and Canada’s oil sands.
The moves by Japan to force its LNG contracts to be renegotiated. Japan needs to unwind its long LNG contracts to better match its shrinking demand.
The activity levels in Korea’s ship yards that are building floating regasification ships for new markets. Many new markets will want faster, cheaper and flexible floating facilities rather than large fixed plants.
Help wanted ads by Canada’s LNG projects.
The success of Japan, Korea and China to deregulate their gas and power sectors which could open up fresh gas demand. The big Asian markets need to reduce carbon emissions and deregulating gas and power markets are key to getting consumers to switch to cleaner fuels.
In a follow up article, I’ll outline all the ways that digital technologies could move the costs of these projects in the right direction.