Canadians like to think of themselves as the small exporting nation that could, plying their natural resources to a world of benevolent and willing customers.
In the Canadian trading narrative, markets are always free, trade is left to its natural course and governments never impose import restrictions or back state-owned enterprises. But the global liquefied natural gas (LNG) market has none of these characteristics, and Canada’s competitors are not much interested in change.
LNG and the natural gas market at 10,000 feet
All the hype about the natural gas market being global does not depict the current state of affairs. Trade is currently within and between geographical regions, dominated by North America, Europe and Asia. The LNG market is a small subset that accounts for just 10% of total natural gas trade.
LNG is also a far different market than what Canadian natural gas producers are used to.
In Canada, natural gas is shipped from wellhead to end-user via common carrier pipelines. Spot and futures contracts are entrenched. Prices are transparent. Bilateral long-term contracts abhorred.
In the LNG market, these rules don’t apply. Technically there are more steps (liquefaction, ocean transport, regasification), but it is the commercial realm that really matters. Long-term contracts are standard. Prices are confidential and pegged to the price of crude oil.
On top of all this, the LNG market is dominated by a handful of players. Ten companies supply almost 70% of capacity (see chart).
Buyers in name are more numerous, but in reality they are a conglomerate of Asian utilities from Japan, South Korea and China. Together, they buy almost 60% of supply.
Economists have a word for such markets: oligopoly. Or, more precisely, oligopsony. These are the markets where suppliers (or in the latter case buyers) have enough market power to dictate price. Think OPEC.
“When you have an oligopoly on the selling side and an oligopsony on the buying side, one does not come up with a ‘unique’ solution – a price and a quantity that falls out of the modelling exercise,” said William A.Kerr, senior associate at the Estey Centre for Law and Economics in International Trade and professor of economics at the University of Saskatchewan. “Instead, what one gets is a range of possible prices – upper and lower bounds – with the actual price being determined by the relative bargaining power of the two sides.”
Up until 2011, things ran fairly smoothly. But then the Japanese tsunami hit and the Fukushima Daiichi nuclear power plant’s cooling systems failed. The nation’s entire nuclear fleet – some 30% of electrical generating capacity – was taken off-line. Imports of fuel oil, coal and LNG skyrocketed. Asian spot prices almost doubled. Overnight, Japan went from being a market maker to a market taker.
Asian buyers could see that they were paying a significant premium, much higher than what the sellers’ costs plus a profit would reasonably allow. They started calling for change.
“We have to expand upstream businesses to provide more liquidity,” Naomi Hirose, president of Tokyo Electric Power Company told delegates at the 2nd LNG Producer-Consumer Conference in Tokyo last September. “We are looking to create gas-to-gas convergence.”
In other words, the buyers are looking to make the LNG market look more like North America’s natural gas market.
The race to 2020
LNG demand is expected to grow. The multibillion-dollar question is how much and how fast.
Industry experts expect LNG demand to be between 450 million and 470 million tonnes per year in 2030. Projects in operation and under construction globally have the capacity to provide about 400 million tonnes per year, with 50 million to 70 million tonnes per year unspoken for. According to the International Gas Union and globallnginfo.com, 62 projects with a capacity of 300 million tonnes are under consideration. A first-mover advantage may well be the deciding factor.
But LNG projects are gargantuan undertakings, costing tens of billions of dollars. It’s enough to make even an oilsands producer blush. Few nations have the infrastructure and workforce to support several of these projects at once. Australia, the United States and Canada are thought to be in the lead, followed by Russia and East Africa.
Australia
Most LNG projects under construction today are in Australia. By all accounts, the experience has been a boom: Australian $190 billion ($188 billion Cdn) in investments. Seven plants are under construction. Many jobs have been created. An Australian LNG player of global stature (Woodside Petroleum Ltd.) has been spawned. When all is said and done, Australia will be the world’s largest LNG exporter.
But Australia has done it by playing by the oligopoly’s rules, that is, by encouraging investment from the dominant players, with their facilities underpinned by long-term contracts and prices pegged to crude oil.
But all this progress has come at a significant cost. Projects are over budget. Labour productivity has dropped sharply. In a 2013 report, McKinsey & Company estimated that unless something changes, new projects will cost 20% to 30 % more to deliver LNG from Australia to Japan than for a competing project in the United States or Canada.
And concerns about domestic-gas-price increases (now tracking international prices) and the environment are rising. A 2011 inquiry into domestic gas pricing in Western Australia found that the market had become highly concentrated, raising “legitimate concerns about the level of competition and effectiveness of the market.” More recently, a fracking ban in the state of Victoria was extended until mid-2015.
Meanwhile, from a gas-on-gas competition perspective, Australia remains a backwater. Onshore pipeline infrastructure is limited and disjointed, and there is almost no junior or intermediate exploration and production industry. Barriers to entry are just too big.
But clearly, all that Aussie LNG investment has given it a first-mover advantage. The potential to expand an LNG facility by adding another production train or two is potentially easier than having to build a new one from scratch (as will be required in Canada). So, despite all the challenges, its potential to add additional and more flexible LNG capacity remains.
The United States
The U.S. natural gas market is completely different. It’s supplied by North America’s vast interconnected pipeline system. LNG’s share of this market is a drop in the bucket, and its contribution has been historically capricious.
Less than a decade ago, most forecasters were heralding a huge natural gas supply shortfall. Imports from Canada and Mexico were also dropping. American companies tooled up to import LNG, building regasification facilities in abundance: 17.4 billion cubic feet per day (132 million tonnes per year) of capacity.
Then along came Texan shale gas pioneer George Mitchell and the Barnett Shale. Other shale basins, in particular the Marcellus, followed. Almost overnight, talk of shortage turned to talk of surplus.
By the time the newly built import facilities came online, the United States was awash in natural gas. In 2012, the regasification plants were turned on only 3% of the time.
Obviously, the owners of the regasification terminals were losing money. But one entrepreneur’s writeoff is another’s sunk capital. The idle regasification facilities are now being transformed into bidirectional plants with the capability to export. These brownfield sites have already been cleared and levelled, and a significant amount of the required infrastructure – LNG ship loading, pipeline and utility interconnections and storage tanks – is in place. All this means that these sites can potentially be developed quicker (three-and-a-half to four years compared with five to six years) than competing greenfield proposals in Canada.
The major challenge now appears to be transportation. If only all those facilities in the Gulf of Mexico were closer to Japan, South Korea and China. Cue the music for the renewal of the Panama Canal.
Back in 2006, Panama’s electorate approved the expansion of the Panama Canal. The estimated US$5.2 billion project will add a third set of locks that will be big enough to allow the passage of 80% of LNG carriers (only the Q-Max and Q-Flex LNG carriers will be too big to pass through). Construction is well underway and the new locks are set to open in 2015, just in time for the potential conversion of all those import facilities.
With the expansion of the Panama Canal, the shipping distance from the Gulf Coast to Japan will be reduced to about 8,100 nautical miles (15,000 kilometres) from around 16,000 nautical miles (about 29,600 kilometres). This is still about twice the distance of LNG going to Japan from Australia and Canada, but it is close enough to be competitive.
Silvia de Marucci, leader of bulk liquids for the Panama Canal Authority, is well aware of the pivotal role the canal might play in the future of U.S. LNG development. She and her team have been consulting with potential shippers for over a year and will be putting the proposed LNG toll structure out for public comment in the first quarter of 2014.
“We think that LNG shipped through the Panama Canal will be about 20% cheaper than competing routes,” de Marucci said.
And U.S. players have been receptive to Asian buyer demands for more flexible contracts and pricing, preferring merchant business models (anchored with fixed cost payments, regardless of whether LNG is taken) with LNG prices pegged to Henry Hub natural gas prices.
Michael Smith, chairman and chief executive officer of Freeport LNG Development LP, told the Tokyo LNG conference, “We have added a whole new way of contracting for LNG that was not available before.”
If he and the other new incumbents are successful, they could give U.S. LNG a price advantage over supply from Australia and Canada.
And if they do, they have the potential to supply most, if not all, of the incremental demand. As of the end of 2013, the United States has approved more than 40 billion cubic feet per day (312 million tonnes per year) of LNG export capacity. Of this total, about 6.4 billion cubic feet per day (50 million tonnes per year) may be exported to countries that don’t have a free trade agreement with the United States, namely Japan and China.
Canada
In many ways, Canada’s LNG future looks much like Australia’s. Northeastern B.C. natural gas supplies are somewhat isolated. Of the nine projects that are most talked about, most are led by members of the LNG oligopoly. The only new entrants are AltaGas Ltd. (TSX:ALA) and the backers of the Douglas Channel LNG project, which is currently caught up in bankruptcy proceedings in the B.C. courts. (Pieridae Energy Ltd. has applied to export LNG from its Goldboro, Nova Scotia, import facility, but that facility has more in common with the U.S. Gulf Coast projects than its counterparts in Western Canada.)
A glimpse of one potential future comes from reading the National Energy Board export licences granted to the Petronas-led Pacific Northwest LNG project and CNOOC Ltd.’s Aurora project. Both will be fed by new, dedicated pipelines. Both will be filled by “proprietary gas reserves” sourced from their subsidiaries (Progress Energy Canada Ltd. in the case of Pacific Northwest and Nexen in the case of Aurora). Sinopec Canada Energy Ltd.’s executive vice-president, Cameron Proctor, told an audience at a University of Calgary School of Public Policy event in December that his company is looking at a similar strategy with its (as yet undisclosed) LNG partner.
There is nothing necessarily wrong with this scenario. With initial export volumes of 4.6 billion cubic feet per day (35 million tonnes per year) or more, these projects would deliver significant economic benefit. Canadians will be employed. Royalties and taxes will be paid.
But if only these projects go ahead (a possibility given the stiff competition from Australia and the United States and limited demand), other Canadian producers would be frozen out of the market. Before Canada carves out this export bonanza from the rest of North America, it needs to think about what it is and what it wants to be.
Canada is a small exporting nation. Historically, its exports have gone to the United States. It knows what it’s like to be a captive seller to a powerful buyer.
Diversifying the natural gas market is in Canada’s national interest. So too is advocating for the things that have levelled the playing field in North America: an open and competitive market, common access to pipelines and pricing that is open and transparent. •
This first instalment of a three-part series examining Canada’s future role in the global LNG industry was initially published in Oilweek’s February 2014 edition.
