By Janet Plume
Canada’s fledgling LNG sector has spent much of the past nine months reminding investors that history often repeats itself. That’s because until the final quarter of last year, most of Canada’s nearly two dozen LNG projects appeared on track to land Canada a spot in the rarified realm of major LNG exporters, alongside Qatar, Indonesia, Malaysia and Australia. It appeared to be a no-brainer; depending on the author, Canada’s gas reserves rank no. 4 or 5 in the world, and both coasts are close to LNG-hungry geographies such as Japan and Europe.
When investors started developing LNG projects after years of natural gas shortages on the heels of the 1973 and 1979 oil crises, there was encouragement from provincial and federal governments, and a surplus of natural gas existed in North America. Japan felt strapped by Indonesian producers that tied the price of gas to oil, and was looking to Canada for alternatives. But when the bottom fell out of the oil market in 1986 – natural gas prices are indexed to oil in most contracts outside the U.S. – LNG projects tanked.
Canada as a world-class LNG exporter remained a pie-in-the-sky daydream.
When North American shale gas extraction a few years ago once again turned anticipated shortages into surpluses, LNG export projects sprang up on both coasts of Canada. For a handful of years until the last quarter of 2014, Canada’s LNG sector was running on the same euphoric steam that buoyed the market in the early 1980s. Four LNG projects had materialized on the East Coast, 19 formal proposals were registered in British Columbia, and an enduring project in the High Arctic was seeking new investors.
Environmental and other regulatory approvals including LNG export licenses were granted without delay. Last November, B.C. issued Environmental Assessment Certificates for three projects: the Petronas-led Pacific NorthWest LNG export facility at Lelu Island; the Westcoast Connector Gas Transmission pipeline; and BG’s Prince Rupert Gas Transmission pipeline, both at Prince Rupert.
Then as it did in the 1980s, the world of capital energy projects changed dramatically in a few months as the oil-and-gas market flashed from one of global deficit to oversupply. As the price of oil plunged 50 percent in the final half of 2014, so did the price of natural gas and LNG.
A key aspect of the shifting dynamics of the global LNG industry is evidenced in the move to mega-producers and buyers. Royal Dutch Shell’s $85.3 billion acquisition of British Gas (BG) gives Shell control of two of the bigger LNG projects in Canada, and the ability to achieve bigger economies of scale in their development. In Asia, the merger of Tokyo Electric Power Co. and Chubu Electric Power has created the largest buyer of natural gas in the world. Called Jera, the venture will contract about 16 per cent of global demand.
Other buyouts in the global energy industry include: Halliburton’s $42.6 billion acquisition of Baker Hughes and Spanish Repsol’s $10.1 billion buyout of Canada’s Talisman Energy. Many believe more mergers are coming.
An additional daunting challenge to the development of Canada’s LNG sector has emerged as stakeholders realize they need to spend hundreds of millions and even billions of dollars on pipelines and other infrastructure to deliver natural gas from remote areas. One important element that makes many of Canada’s LNG project construction costs so high is that the majority of them are greenfield sites, whereas the majority of LNG projects on the U.S. Gulf coast are brownfield sites, including conversions of LNG import facilities.
As always, geopolitics could further dampen prospects. China, once thought to be a major LNG customer for Australia and Canada, is signing an increasing number of LNG contracts with Russia and Central Asian nations. Also, analysts are uncertain of Japan’s continued construction of nuclear power plants amid deep national stagnation. Japan has been buying up LNG contracts while the plants are under construction.
Tokyo/Chubu and other Asian buyers, thought to be easy customers for BC LNG developers, will soon have access to boatloads of LNG as Australia’s seven greenfield projects, under construction for the past decade, come online beginning next year. Additionally, four U.S. LNG plants under construction will start coming online next year.
Canada’s LNG Future
Since developers of all but the smallest LNG projects in British Columbia have signaled delays in Final Investment Decisions, or FIDs, or postponements in construction starts, LNG analysts have concluded that the viability of the west coast’s major LNG export projects are at risk. All are expensive and challenging, and face murky market outlooks. “The vast majority of North American LNG projects face cancellation,” an announcement from Moody’s Investor’s Service foretold in April.
Shell’s takeover of BG has left in question whether one or both of its BC LNG projects face termination. In February, before Shell announced its acquisition of BG, head of BG Canadian Operations, Madeline Whitaker, vacated her post to take another position elsewhere at BG. The vacancy she left was not filled.
Consolidation among major oil-and-gas producers is a key indicator that new energy exploration and extraction projects may grind to halt, according to Leonardo Maugeri, author of the report, ‘Falling Short: A Reality Check for Global LNG Exports,’ which was published last December by the Geopolitics of Energy project at Harvard Kennedy School’s Belfer Center for Science and International Affairs. “Oil and gas majors clearly believe that in the current low oil price environment, bigger is better.” Mr. Maugeri stated that “Canada’s LNG ambitions are likely to be frustrated in this decade.” He points out the traditional opposition to oil-and-gas projects by environmentally sensitive First Nation communities in British Columbia, noting that in June 2014, Canada’s Supreme Court gave the indigenous tribes unprecedented control over their ancestral lands. Combined with the extra costs of greenfield sites, Mr. Maugeri believes LNG developers in Canada have underestimated the impact of these hurdles on capital costs, and adding inflation, the big LNG projects could easily spiral out of control just as they did in Australia. “Shell’s LNG Canada was originally projected at $14.6 billion for two 6-million tonne/yr production trains,” he said. “More recently, Shell estimated the price had ballooned to $29.2 billion for two trains and $48.7 billion for four trains.”
Neil Beveridge, Analyst at Sanford C. Bernstein & Co., forecasts three of BC’s 19 LNG projects could be completed, but not in this decade. He has forecast that Shell’s LNG Canada project could go online in 2021, Chevron’s Kitimat LNG could start up in 2023, and Petronas’ Pacific Northwest LNG could begin exporting LNG in 2024.
In eastern Canada, four developers are eager to move ahead with LNG projects, which they believe will benefit from ease of access from North America to markets in Europe and India. But they all face a common supply problem; most of the Maritimes and Quebec have imposed moratoriums on hydraulic fracturing amid concerns about groundwater pollution. The developers want to build a natural gas pipeline from Pennsylvania across New England to access the feedstock for their proposed export terminals. Analysts have doubts as to whether the costs and the traditional environmental concerns of New Englanders over gas pipelines can be overcome.
Slumping energy prices made shipping North America’s LNG to Asia unprofitable in recent months, but projects targeting Europe look still viable, in part because of uncertainty about supplies from Russia stemming from the Ukraine crisis.
Harvard Kennedy School’s Mr. Maugeri thinks Pieridae Energy Canada’s Goldboro LNG project in Nova Scotia is the country’s sole LNG project most likely to materialize. “Pieridai has signed a 20-year contract to sell 5 million tonnes of gas per year to Germany’s E.ON, the largest of many European utilities seeking to reduce dependence on Russian natural gas,” according to Mr. Maugeri.
CB&I is working on the project’s Front-End Engineering and Design for the processing plant and facilities for the storage and export of LNG, including a marine jetty. The proposed facility will be designed to produce approximately 10 million tonnes a year of LNG and have on-site storage capacity of 690,000 cubic metres of LNG. The other positive, according to Mr. Maugeri, is that Goldboro is the only Canada LNG project whose selling price formula is not linked to oil.
Mr. Maugeri believes that “Because of these factors, it is highly improbable that Canada will contribute to the growth of global LNG export capacity until after 2020, except perhaps for some volume from Goldboro.”
Since the collapse of oil and gas prices, Canada’s provincial and federal governments have made moves to encourage LNG projects. BC has passed the LNG Income Tax Act, reducing tax rates on LNG production from rates initially proposed. And earlier this year, the federal government established a new Accelerated Capital Cost Allowance for LNG property, which allows developers to write off capital investment in infrastructure sooner, allowing earlier recoveries of project development investments. This temporary accounting practice was extended to oil sands developers. Moreover, in April, the federal government voted to extend natural gas export licenses from 25 years to 40 years.
On May 20, the government of B.C. and Petronas signed a memorandum of understanding outlining steps toward realization of the $36 billion Petronas-controlled Pacific NorthWest LNG project, which would be the largest ever undertaken in the province. More work needs to be done, specifically negotiations with First Nations and securing federal environmental approvals. Many are hoping for a positive outcome, which would herald the arrival of a sizeable new industry, creating opportunities for tens of thousands of workers and substantial new sources of income for provincial and federal Treasuries.