Canadian LNG can compete globally: CERI study


Canadian LNG can be globally competitive and is in a position to benefit from a growing demand for the commodity, according to a new study by the Canadian Energy Research Institute (CERI).

“We found that the growth in the LNG market is exceeding everyone’s expectations,” Allan Fogwill, CERI president and CEO, said in an interview. “The market is poised to absorb new supply because there are a lot of excess regasification facilities globally so it’s really the supply catching up to demand.”  

He also challenged the idea that there is a limited window in which LNG opportunities will be available. “There’s many more players and many more opportunities and many more positions to buy and sell LNG so as a result we are starting to get much more of an ongoing robust market,” said Fogwill. “We are not necessarily talking about reopening existing contracts or when a contract expires; we also are talking about expansion demand and that happens all the time.”

The study, Competitive Analysis of Canadian LNG, concluded that with additional government incentives and certain cost-savings, Canadian West and East Coast integrated LNG projects are competitive and can outperform United States greenfield and brownfield projects.

Provided that specific actions are taken by governments and proponents, the total landed costs for a Western Canada LNG project could be reduced to $7.55/mmBtu from $8.99/mmBtu in the northeast Asia market, said the study.  “The resulting landed cost is recovered by an LNG project with a Brent price of [US] $65 [per bbl] (compared to initial $80),” it says.

“Canada can be competitive on both the West and East Coasts under different conditions but definitely can compete internationally with other jurisdictions, in particular the U.S. Gulf of Mexico and Australia,” said Fogwill.  

The CERI study compared generic Canadian projects in British Columbia (13 million to 26 million tonnes per annum) and Nova Scotia (eight to 12 million tonnes per annum) with counterparts in the United States Gulf of Mexico (Texas and Louisiana) and Australia. (One bcf/d equals about seven million tonnes/annum).

It assumed 70 per cent of the supply for the projects would be subject to long-term contracts and 30 per cent would be sold on the spot market. “There was a lot of talk about people building completely merchant plants but that’s not what we are hearing,” he said. “Most of the plants — if not all of the plants — have some strong element of contracted demand in order for them to move forward.”

The study also reviewed some of the incentives that governments have already implemented or could implement, as well as costs savings measures that are available to LNG producers to improve the cost competitiveness of Canadian LNG. With those actions, the study concluded, Canadian LNG also can reach destination market price levels in Asia and Europe, depending on whether it’s being exported off the West or East Coast.

West Coast advantage

Western Canada LNG has an overall landed cost advantage in the Asian market of US$1.70/ mmBtu compared to U.S. Gulf greenfield projects and of 30 cents/mmBtu versus U.S. brownfield projects, the study found. If supply costs of Canadian LNG are optimized, the difference grows to $3.10/mmBtu and $1.80/mmBtu for U.S. greenfield and brownfield projects, respectively.

“Our [West Coast] advantage comes in terms of the natural gas cost — we are higher in terms of capital costs. We have got an advantage in terms of operating cost and compared to the United States we have got an advantage in terms of shipping costs to Asia,” said Fogwill.

At the same time, U.S. Gulf projects hold an advantage over Marcellus-sourced gas for Eastern Canada LNG in the European market by $1.50/mmBtu for a U.S. greenfield and by $2.90/mmBtu for a U.S. brownfield project. “If supply costs of Canadian LNG are optimized, Eastern Canada LNG edges a U.S. greenfield project by $1/mmBtu but loses to a U.S. brownfield by 40 cents,” said the study.

British Columbia also appears to be more competitive globally than Nova Scotia as the western province has more incentives and lower corporate taxes (26 per cent versus 31 per cent), according to the study. The Asian LNG market also is better priced than European gas markets (a 10-year historical average of $9.20/mmBtu compared to $6.30/mmBtu).

In addition, the cost of Montney gas and transportation to a B.C. facility is half that of an Eastern Canada project that sources gas from AECO-C or the Marcellus.

East Coast LNG implies local supply

The study found that Canadian LNG supply costs (excluding transportation) for Western and Eastern Canada LNG are $8.35/mmBtu and $8.09/mmBtu, respectively, for an integrated model in which LNG facility owners produce the gas. The integrated model for Eastern Canada implies the development of onshore local gas in Nova Scotia which is currently under a provincial ban on hydraulic fracturing.

Eastern Canada integrated projects would hold a slight advantage (36 cents/mmBtu) over Western Canada due primarily to lower capital and transportation costs with an adjacent gas supply while a British Columbia project would have a 93 cent/mmBtu advantage in terms of natural gas cost.

Costs for a merchant business model would be higher by $9.85/mmBtu on the West Coast and $11.17/mmBtu on the East Coast.

Western Canada LNG projects will need an oil price of approximately US$80/bbl WTI  or higher over the life of the project to break even under long-term LNG contracts (11.5 per cent of Brent is used as the benchmark for all project economics) or $8.99/mmBtu on the spot market.

The study found that Western and Eastern Canada LNG landed costs are higher than the current spot price in the United Kingdom. The difference is $2.50/mmBtu for western Canadian gas and $4/mmBtu in Eastern Canada for Marcellus-sourced gas, $4.20/mmBtu for AECO gas and $1.10/mmBtu for locally-sourced shale gas in Nova Scotia.

Eastern Canada LNG projects will need an oil price of approximately $100/bbl over the life of the project to break even under long-term LNG contracts, or $11.60/mmBtu to $11.40/mmBtu or higher in European markets, the study found. The historical average for the last 10 years in the U.K. is $6.30/mmBtu.

CERI said it has not found a viable path to lower the landed cost of Eastern Canada projects below the European market price if the project sources gas from AECO-C or Marcellus. The final optimized landed cost is $8.80/mmBtu while the market price is $7.40/mmBtu. However, if local shale gas was available in Nova Scotia, the optimized cost reduces the landed costs to $7.35/mmBtu from $8.50/mmBtu, making such an option viable under current spot prices, said the study.

U.S. more cost effective

If natural gas costs are not considered, the U.S. is a more cost-effective jurisdiction than either of Canada’s provinces, it found. Total liquefaction costs (all costs except for natural gas) are higher by 70 cents/mmBtu to 80 cents/mmBtu in Western Canada and by $2.80/mmBtu to $3/mmBtu in Eastern Canada. “Thus the costs of doing LNG business is 13 to 41 per cent lower per mmBtu in the GoM than in Western or Eastern Canada inducing further work of business and governments to reduce the deficiency in cost-competitiveness,” said the study.

The recent change in corporate taxes in the U.S. has also given a boost to the U.S.  industry with the corporate tax share per mmBtu of LNG decreasing by nearly 60 per cent to 44 cents/mmBtu from 52 cents/mmBtu, it noted.

Canadian incentives to the LNG industry are estimated at about 51 cents per mmBtu (including increased capital cost allowances, the B.C. government’s Natural Gas Development Framework and the natural gas tax credit), said the study. “Still, even with these measures, U.S. greenfield projects have 27.5 per cent lower taxes per mmBtu than for a large 26 mtpa (million tonnes per annum) project in Canada after all modelled Canadian incentives are applied.”

This leaves room for further improvement of the tax regime competitiveness in Canada, for instance exempting projects from ring-fencing and further increasing the capital tax allowance, the CERI report suggested.

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