With the future of nuclear-generated power heading for unprecedented scrutiny in the wake of Japan’s calamitous earthquake and tsunami, LNG and oil have seized the limelight as alternatives to meet the stricken country’s energy needs.
Preliminary estimates point to Japan’s possible need for an extra 143,000 barrels per day of fuel oil, 67,000 bpd of crude and 16,400 metric tons of LNG.
Bank of America Merrill Lynch has estimated Japan’s LNG imports could rise to 7.1 million metric tons a year.
Japan has already asked Indonesia to supply more LNG and oil to meet what Japan’s vice minister of foreign affairs Makiko Kikuta said is a “massive shortage of electricity.”
The Asian market is the world’s largest LNG customer, with South Korea’s state-owned Korea Gas Corp., which has a monopoly on domestic gas sales, reporting that its 2010 LNG purchases surged 26.6 percent to 31.20 million metric tons.
Despite reassurances from the nuclear industry that most existing generating stations are designed to withstand major “seismic events” and incorporate redundant safety systems, the events in Japan “make the future of nuclear power highly questionable,” said Tom Adams, an independent Ontario-based energy consultant.
Given that the Japanese industry has long been rated as the world’s gold standard for the sector, “all the questions about reactor safety are back on the table,” he said.
Further prod for exportThat will likely give further prod to those North American gas producers who are shifting their attention to the Asia-Pacific region as an outlet for surplus supplies from shale gas and the Arctic.
John Rowe, chief executive officer of Exelon, whose utility runs 17 nuclear plants plus solar, wind and hydro facilities in the United States, told the CERAWeek conference in Houston earlier in March that natural gas is the cheapest and cleanest of all the options.
He estimated it would take two years to build a 1,000 megawatt gas-fired plant for $1 billion, compared with 10 years for a nuclear plant at a cost of $6 billion.
To fill the void in Japan, Royal Dutch Shell has said it will divert as much LNG as possible to meet that country’s energy needs.
Export partnershipsAlthough it was a coincidence of timing, two partnerships to open the first offshore exports of Canadian LNG have gathered pace in the week ending March 18.
Following a series of broad hints this year, Encana reached a deal to acquire a 30 percent equity stake in the Kitimat LNG project, reducing the interests of the existing partners. Operator Apache will drop to 40 percent from 51 percent and EOG Resources will shrink to 30 percent from 49 percent.
Financial terms were not disclosed, although the latest price tag has been C$3.5 billion for a terminal designed to liquefy 1.4 billion cubic feet per day of gas and ship 10 million metric tons per year, starting at half those volumes in 2015.
Front-end engineering is currently under way for an export terminal and construction could start as early as 2012.
Encana said British Columbia’s Montney and Horn River shale gas plays have capacity to grow to 7 bcf per day — almost half of Canada’s total current gas output — in the next seven to 10 years from the current 2.8 bcf per day. It said those volumes are “more than sufficient” to supply British Columbia, Encana’s current customers and the new Asian markets proposed for Kitimat LNG.
Eresman: ‘continental push’Encana Chief Executive Officer Randy Eresman said the Kitimat LNG investment puts his company in the forefront of a “continental push to deliver exports of abundant natural gas for the first time from Canada.”
Encana has already made progress toward building a customer base in Asia through two joint-venture deals — a $5.4 billion partnership struck in February with PetroChina for 50 percent of its Cutbank Ridge shale and conventional gas assets, 255 million cubic feet per day of current production and 700 million cubic feet per day of processing capacity, and a farm-out arrangement a year ago with Korea Gas Corp., which has pledged to invest $1.1 billion over five years to develop resources in Horn River and Montney.
Encana and Apache are also E&P partners in Horn River, targeting gross production of 300 million cubic feet per day by the end of 2011.
In a recent report assessing the LNG market outlook for 2015-35, international energy advisor Poten & Partners said the Asia-Pacific basin holds promise for Kitimat LNG to enter long-term supply contracts, partly because of concerns over security of supply and the most attractive gas price index formulas in the world.
Encana estimates Asian gas prices currently hover around $12 per thousand cubic feet, compared with $4 in North America.
Second contenderOn a smaller scale, a U.S.-based partnership has become the second contender to export LNG from the British Columbia.
BC LNG Export Co-operative filed an application with the National Energy Board to initially convert up to 125 million cubic feet per day of natural gas into 900,000 metric tons of LNG annually, with shipments starting in 2013 to a variety of Asian countries, including Japan. The proposal allows for a doubling of capacity by at a later date.
The export point would be in the Douglas Channel of northern British Columbia, close to a planned Kitimat LNG terminal.
The new project would be operated by Douglas Channel Energy Partnership which is indirectly owned by LNG Partners, a closely held Delaware limited liability company based in Houston.
DCEP Gas Management Ltd., GML, is designated to operate the liquefaction facility — which could either be based on a barge or land.
GML said it has entered into a firm LNG sale and purchase agreement with BC LNG Export Co-op to purchase the full capacity of the LNG facility for 20 years.
The applicant has yet to put a firm price tag on the project beyond indicating that the cost is likely to range from $400 to $500 per metric ton of liquefaction capacity, or about $360 million to $450 million for the first phase.
DCEP said it has held discussions with “significant producers and marketers of gas” in the Western Canada Sedimentary basin, which is concentrated in British Columbia, Alberta and Saskatchewan.
The application said there have been formal expressions of interest from suppliers who could provide more than enough gas to cover one of the 900,000 metric ton trains.