LNG Canada Gets Real With Country’s First Gas Export Facility
Shell Oil and its partners finally have committed to building Canada’s first LNG plant, providing a badly needed export outlet for huge gas plays that have been depending on a shrinking US export market.
It is the biggest LNG project globally since 2016, in a sector that had ground to a halt as new and expanded facilities flood the global market.
It is expected to add a low-cost source of supply near Asian markets in the mid-2020s when demand is expected to outstrip LNG supplies.
Building the two gas liquefaction units in the port of Kitimat, British Columbia, plus the 670-km pipeline will cost more than $20 billion, making it one of the biggest private sector projects ever in Canada.
Wood Mackenzie estimates that the initial production cost will be $18 billion for the LNG plant plus $3.5 billion for the Coastal GasLink pipeline.
For Canadian gas producers, including Shell, this begins to address a pressing problem—creating more demand for its isolated reserves with a development plan that could double the facility’s capacity.
But based on the price assumptions built into the plan, producers need to continue focusing on grinding down prices. While the facility will require a lot of gas—the initial capacity of the pipeline will be 2.1 Bcf/D—that is not a lot more than the drop in Canada’s exports to the US since 2007, during a period when unconventional gas production there has soared.
The new plant is expected to begin exporting 14 million tons per year starting in the mid-2020s. Shell is assuming the average cost of the gas it uses will be $1.50 per million Btu lower than the US Gulf Coast, or about $2.00 per million Btu plus the shipping cost.
“We believe LNG Canada is the right project, in the right place, at the right time,” said Ben van Beurden, CEO, Royal Dutch Shell. “Global LNG demand is expected to double by 2035 compared with today, with much of this growth coming from Asia where gas displaces coal. LNG Canada is well positioned to help Shell meet the growing needs of customers at a time when we see an LNG supply shortage in our outlook.”
When analysts pointed out during the Shell conference call that Gulf Coast LNG plants are being built for about half the $1,000 cost per ton of capacity for the Canadian plan, Shell countered that the lower cost of gas more than makes up for that advantage.
“You cannot find a gulf project that can counterbalance the $1.50 (per million Btu) price advantage,” said Maarten Wetselaar, director of integrated gas and new energies for Shell.
Shell and its partners will each be responsible for suppling gas based on their share of the project. They can produce on their own—Shell has a working interest in 9 Tcf of gas which is estimates it can produce for about $2.00 per million Btu—or buy on the open market in a region with 5 Bcf/D of production.
That is not a high price, and it will be years before they need the gas, but it looks better than the current market. The average price paid for Canadian gas through August of this year is a little more than $1.00 per million Btu, according to the Canadian Association of Petroleum Producers’ (CAPP) website.
Finding new export markets has been a priority because CAPP said Canada has enough gas in the ground to provide the country’s needs for another 300 years, and US exports have shrunk by 1.8 million Btu per day since 2007. Booming shale production from the Marcellus play in the eastern US has reduced demand for western Canadian supplies in the country’s eastern provinces.
Canadian producers have adapted to this hostile economic environment. “Canadian upstream operators have improved productivity and efficiency tremendously over the last few years in the core areas of the British Columbia Montney,” said Dulles Wang, director of North America gas for Wood Mackenzie. He said they have improved their estimated ultimate recovery rates over the past year by “as much as 60%” and lowered their breakeven levels by $0.40-$0.80 per million Btu.
“The majority stakeholders of LNG Canada, such as Shell and Petronas, own some of the lowest-cost acreage in the region but monetisation for the gas domestically has not been very profitable,” Wang said.
Before committing to the project, the partners went to great ends to lock down all the critical deals to reduce the potential for delays and cost overruns which have plagued big LNG projects.
“We worked hard on de-risking the project,” said Jessica Uhl, chief financial officer of Shell. The liquefaction facility will use standard designs for units which will be built in modules in Asian facilities, avoiding the cost and delays that come with trying to build complex assemblies in an isolated spot like Kitimat, with a population of less than 6,400 people in 2016.
Kitimat offers an ice-free, deepwater port with dredging planned to make it deeper, rail and airport facilities, plus a “partially developed industrial site,” Shell said.
The construction cost estimates are increased by Kitimat’s remote location that will require paying a premium to attract workers, flying them in and out, and building a camp to house them.
The companies partnering on the work—JGC, which will supply the modular units, and Fluor, handling the engineering, procurement, and construction (EPC)—agreed to build it for $1,000 per ton of liquefaction capacity, or about $14 billion.
TransCanada has won support from First Nation’s communities along nearly all the route, signing $620-million worth of conditional agreements with First Nation governments and businesses, according to the company. It said it has obtained “major regulatory permits” needed to proceed with construction, which it expects to begin in 2019.
Canada LNG has reached a deal with the provincial government that will defer $6 billion in sales taxes during the construction, which would be paid back during operations, and lower the tax on carbon dioxide emissions from $50 to $30 per ton if the facility’s emissions are extremely low.
Carbon emissions from the plant are expected to be the lowest among Shell’s LNG facilities and “the lowest in the world as far as I know,” said Wetselaar, adding that the carbon tax reduction is “not fully legislated yet. It is still going through channels” and has not been built into the financial projections.
Low-cost gas should allow the partners to earn a 13% internal rate of return, assuming they sell the gas for $8.50 per million Btu, Wetselaar said. He pointed out that this winter, prices should be in the double digits.
Based on an LNG market outlook from Shell, the Kitimat facility could come on line at a time when LNG demand exceeds supply.
While the expected global spending on building and expanding LNG facilities currently drops sharply during the second half of the 2020s, that could quickly change.
“The momentum behind LNG Canada reflects the drastic improvement in the LNG market over the past 12 months, driven by buoyant demand in China,” Wang said.
The projects near a final investment decision (FID) include “four mega trains in Qatar, Arctic LNG-2 in Russia, at least one development in Mozambique, and several US projects. “We believe 2019 could be the busiest year of LNG FIDs ever,” he said,
LNG Canada Facts
Engineering, procurement, and construction: JGC and Fluor
First LNG production: Mid-2020s
Estimated cost: LNG facilities $18 billion; pipeline $3.5 billion
Mammoet Awarded Unloading, Transport, Installation Contract for Arctic LNG 2
The contract is Mammoet’s biggest in terms of aggregate tonnage. The Arctic LNG 2 project reached FID in September 2019.
Cameron LNG Sees First Production from Train 3 In Louisiana
Production from Train 3 comes almost a month after reaching its final commissioning stage. Commercial operations will follow testing and authorization from FERC.
Total Securing $20 Billion in Financing for Mozambique LNG Project
Construction on Mozambique LNG stopped in April due to COVID-19, but Total continues work on the project. Financing follows engineering contracts awarded by Total in the past few months.
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20 May 2020