Restarts approved for 5 nuclear reactors in Japan; 21 still pending
(U.S. Energy Information Administration; Sept. 13) - Since the earthquake-and-tsunami accident at Fukushima in March 2011 and subsequent shutdown of all nuclear power plants in Japan, five reactors have received approval to restart operations under new safety standards imposed by Japan's Nuclear Regulation Authority. Only three of those reactors are currently operating and two are under legal challenge. Applications to restart 21 reactors, including one under construction, are under review by the NRA.
Some of the reactors that meet the new NRA safety standards and have been approved to restart continue to face legal or political opposition that may delay or prevent their restart, according to a report from the U.S. Energy Information Administration. After the Fukushima accident, all 54 of Japan's reactors were shut down. Twelve reactors were permanently closed. Restart applications have been filed for 20 reactors and one new reactor under construction. The other 17 reactors have yet to apply to restart.
There is still uncertainty whether some reactors can meet new safety regulations, particularly the ability to withstand severe earthquakes. In addition to NRA approval, the restart of reactors requires the approval of the central government and the consent of local governments or prefectures where the power plants are located. Opposition to reactor restarts has been primarily related to public concerns about seismic risks, the adequacy of regulations, and evacuation plans in the event of an accident.
Producers see future in natural gas, but need to build up demand
(Wall Street Journal; Sept. 13) – Shell’s truck filling station at Rotterdam’s Waalhaven harbor in the Netherlands isn’t your typical fueling spot. Alongside the diesel pumps are fuel tanks with a special nozzle to pump liquefied natural gas — an experiment that Shell hopes can help it stay ahead of shifting trends in energy consumption. The LNG fueling stations in Waalhaven and elsewhere are just one piece in Shell’s strategy to build new markets for its growing natural gas business and get a jump on competition.
Shell is the most active of the international oil companies in LNG for transportation fuel. But all the big oil companies are focusing more on natural gas, jockeying for market position in the expectation that gas will be the world’s fastest-growing fossil fuel over the next two decades due in part to tougher environmental standards around the globe. Natural gas now accounts for about half of the production of most of the world’s biggest oil companies and is expected to dominate new output in the coming years.
These are massive bets on gas at a challenging time in the market. Natural gas prices remain closely linked to oil prices, which have crashed in the past two years. And the LNG market is already suffering from a glut, with a wave of new supply coming. Bank of America Merrill Lynch said start-up LNG projects in Australia and the U.S. are expected to boost global supply by 50 percent. Meanwhile, demand in traditional markets like Japan and South Korea is flat or declining, mostly because of economic weakness.
Rather than focusing on just producing gas to sell to long-term customers, companies are increasingly looking to develop new markets with investments in import terminals and other infrastructure to distribute the fuel more widely. “They have to get more imaginative to create demand,” said Neil Beveridge, an analyst at Bernstein Research.
Japanese utilities plan to replace 3 older LNG, coal power plants
(Reuters; Sept. 14) - Japan's Jera Co., a joint venture between Tokyo Electric Power and Chubu Electric Power, said Sept. 14 that it would replace three older power plants in eastern Japan with state-of-the-art efficient gas and coal-fired power generation units. Jera, the world's biggest importer of liquefied natural gas, said it would operate the units as base-load power supplies. Environmental assessments are currently under way for the Goi (LNG) and Yokosuka (coal) plants, both of which have been mothballed.
The three plants belong to TEPCO, though Jera now handles plant replacement for its parent firms. An environmental assessment will be filed for the Anegasaki (LNG) power plant upgrade, a Jera spokesman said. If the plants start operations, Goi and Anegasaki would together consume more than 3 million metric tons of LNG per year, while the Yokosuka facility would use 3.5 million tons of thermal coal a year, he added. The plants are not switching fuels but the new generating units would be more efficient.
If the plans stay on schedule, the new units would go online in 2022 and 2023.
Osaka Gas will not sign LNG contracts with destination restrictions
(Bloomberg; Sept. 12) - Osaka Gas is in talks with some suppliers to remove restrictions in existing liquefied natural gas contacts that prohibit resale of the fuel amid a global oversupply. The Osaka-based gas distributor will not sign new contracts with destination restrictions, said Sunao Okamoto, Osaka’s LNG trading department general manager.
Among Japan’s biggest buyers of the fuel, Osaka Gas plans to boost its annual LNG fuel purchases to about 10 million metric tons by 2020 and resell about 2.5 million a year, Okamoto said, without providing details. “Everyone is demanding destination-free contracts. When it becomes clear to suppliers they can’t sell LNG with such restrictions, we hope it will become the new paradigm,” Okamoto said Sept. 12 in Tokyo.
“While we want all of our LNG supplies to be destination free, it has to be negotiated with sellers,” Okamoto said. Osaka Gas is among Asian gas consumers that are using a supply glut and price slump to gain an upper hand in negotiations with suppliers. Qatar’s RasGas last year agreed to revise the pricing formula in its 25-year contract with India’s Petronet LNG, cutting the import price by almost half. Jera Co., a Japanese utility joint-venture that’s now the country’s biggest importer of LNG, has also said it will not sign new contracts with destination restrictions.
Qatar may partner with Exxon in Mozambique LNG project
(Reuters; Sept. 12) - Qatar Petroleum is interested in the Mozambique natural gas business of Italian energy group Eni and could opt to join ExxonMobil in buying a multibillion-dollar stake, sources said. State-controlled Eni is looking to reduce its 50 percent stake in the giant Mozambique gas acreage as part of plans to sell 5 billion euros ($5.6 billion) of assets over the next two years. Sources said last month that Exxon had reached a deal that could give it an operating stake in the onshore liquefied natural gas export plant, while leaving Eni in control of the Area 4 gas fields feeding it.
Qatar Petroleum is in talks with Exxon and Eni on Mozambique, a senior Qatar Petroleum source said. "The expectation is that Qatar Petroleum and Exxon will go in on this together," a source said, adding that a Qatar Petroleum delegation planned to visit Mozambique before the end of the year. Located in Mozambique's Rovuma Basin, Eni's Area 4 is one of the biggest finds of recent times, holding about 85 trillion cubic feet of gas. In 2013, Eni sold 20 percent of Area 4 to China National Petroleum Corp. for $4.2 billion, but since then oil and gas prices have dropped by over half.
Exxon and Qatar Petroleum are already close business partners in Qatar, where Exxon's technical know-how helped the Gulf state develop its resources and become the world's biggest and lowest-cost LNG producer. Since then, both companies have jointly moved to exploit global LNG growth opportunities, including plans to build the Golden Pass liquefaction plant in Texas and bidding for exploration leases in Cyprus.
Indian Oil Corp. wants to grow its natural gas business
(Reuters; Sept. 14) - State-run refiner Indian Oil Corp. aims to be one of the top natural gas suppliers in India in the next five years as it bets on growing demand for the fuel for transport and factories. The company is aiming to generate 15 percent of its revenues from its gas supply and distribution business by 2021, Chairman B. Ashok told Reuters on the sidelines of a news conference Sept. 14.
He said the company already has committed about $2.7 billion to building gas distribution infrastructure across India and has booked LNG import and regasification facilities. Currently, the gas trading business contributes less than 5 percent to revenues at Indian Oil Corp. Prime Minister Narendra Modi's government has plans to move India to becoming a gas-fueled economy by boosting domestic production and buying imported liquefied natural gas as the country seeks to cut its greenhouse emissions.
Indian Oil, the country’s biggest refiner and marketer of petroleum products, has lined up LNG supplies from the U.S., Canada and Australia. Analysts, however, are cautious about the plans. "In the LNG business it is important to tie-up with customers so that there is an assurance that the volumes that the company has booked will be sold. In case there are no customers, Indian Oil could be stuck with a take-or-pay clause, which can hit its margins," said Dhaval Joshi, analyst with Emkay Global Financial Services.
Finland officially opens first LNG import terminal
(Natural Gas World; Sept. 13) - Finland’s first LNG import terminal at Pori on the southwest coast officially opened Sept. 12. Finnish gas supplier Gasum said deliveries to customers began the same day. Terminal operator Skangas is 51 percent owned by Gasum. The terminal received its first cargo two months ago, but Sept. 12 marked the end of Pori’s commissioning period. The small terminal, built at a cost of about $100 million, can handle 500,000 tons of LNG per year, about 24 billion cubic feet of gas.
“Pori LNG terminal will develop and diversify the Finnish energy market,” said Gasum CEO Johanna Lamminen. Finland has been heavily dependent on pipeline gas deliveries from Russia. In addition to using LNG to meet domestic power and heating needs, the import terminal provides the option of LNG deliveries to customers beyond the gas pipeline network including industrial, maritime and heavy-truck customers.
Japan’s gas futures market opening pushed back past April 2017
(ICIS; Sept. 14) - The Tokyo Commodity Exchange plans to open a domestic natural gas futures market in Japan, a source close to the exchange said. The futures market would likely coincide with Japan’s liberalization of its retail natural gas market, the source said, putting the opening past April 2017. The market would help companies entering the gas market to compete against the more than 200 established companies, including large regional suppliers such as Osaka Gas and Tokyo Gas.
Details on possible contract volumes are unknown. The futures market comes as importers have been resistant to allow third-parties access to their LNG import terminals — a stipulation of the government’s liberalization plan. Gas companies have also pushed back against the government’s intent that they develop their pipeline networks to better connect different regions. The companies also argue that funding is unclear and that better pipeline connectivity would invite newcomers to intrude on their turf.
Meanwhile, some of the electricity companies rocked by the sector opening up to competition earlier this year plan to claw back market share by starting natural gas retail ventures. Kansai Electric — Japan’s third-largest electricity provider, which lost 340,000 customers to the electricity market liberalization — announced Sept. 13 that it would partner with a consortium of companies to start selling gas into the retail market starting April 2017. The group aims to sell gas to 200,000 customers within its first year.
BP looks favorably at investing in Argentina’s shale oil and gas
(Bloomberg; Sept. 14) - BP would rather invest in Argentina’s shale oil fields than in the Permian Basin in Texas, the U.S. drilling hot spot, CEO Bob Dudley said. The company is seeking to buy more assets in Argentina’s Vaca Muerta (“Dead Cow”) shale oil and gas fields, which have “enormous potential,” Dudley said in a Bloomberg interview Sept. 13 in Buenos Aires. The government there has improved the investment appeal of the country by helping foreign companies cut through red tape, he said.
Argentina has been courting international corporations for the vast investments needed to develop its shale oil and gas deposits. Attractive terms are key to luring companies that have slashed their global spending to weather oil’s two-year decline. BP would make any further investments in Argentina through Pan American Energy, which is 60 percent owned by BP and 40 percent by Bridas Corp., a partnership between Argentina’s billionaire Bulgheroni brothers and China National Offshore Oil Corp.
“I’m not surprised because valuations in the Permian have become expensive,” said Iain Armstrong, a London-based analyst at Brewin Dolphin. “The Vaca Muerta is seen highly prospective.” The Permian Basin’s oil-rich geology, extensive infrastructure of terminals and pipelines and low production costs have lured producers that are competing to snap up acreage there, ratcheting up purchase prices. Permian shale assets are too costly for BP right now, Dudley said.
Lack of pipeline capacity hurts Canadian oil exports, report says
(Edmonton Journal; Sept. 12) - Canadian energy will remain landlocked and the industry will lose potential overseas customers if the country doesn’t build new pipelines, a new DBRS report said. More than 90 percent of Canada’s crude oil is exported to the United States, but America’s demand for imports has been dropping for several years as the U.S. boosts its own production, according to a report Sept. 12 by the Toronto-based credit-rating agency.
With Canadian crude oil production expected to rise to 5.5 million barrels a day in 2030 from 4 million barrels a day last year, the country must increase sales to India, China and other growing Asian markets, the report said. But that requires more pipeline capacity through such projects as the Trans Mountain and Northern Gateway routes to British Columbia’s West Coast and Energy East to Canada’s East Coast, all of which face strong political, environmental and regulatory opposition.
“Energy transportation challenges throw a big question mark over Canada’s energy future, as these hurdles need to be overcome before a successful export push can materialize,” the report said. “If pipeline infrastructure is not built, Canada’s energy sector increasingly risks the eventual loss of global market share and will remain confined to a North American market that is increasingly dominated by U.S. producers.”
Canadian energy companies expand with U.S. acquisitions
(CBC News; Canada; Sept. 12) - When the Canadian dollar started to dive in earnest in 2015, the theory went that the lower-value loonie would make Canada very attractive for U.S. companies looking to buy assets or make deals. After all, Canadian companies were essentially on sale — 30 percent off! Instead, in the past six months, Canada's two largest pipeline companies, TransCanada and Enbridge, have spent nearly $50 billion making acquisitions in the U.S., paying a 30 percent premium over a few years ago.
This follows on two deals in which Canadian power companies Fortis and Emera spent roughly $10 billion each buying U.S. utilities. And while there are multiple reasons behind any large merger or acquisition, analysts are suggesting that if it's too hard for a pipeline company or other utility to build something in Canada, maybe the best idea is to buy it elsewhere. "I think they see more potential in the U.S. I think they see difficulties with regulatory issues in Canada, getting new utilities or pipelines built,” said Barry Schwartz, chief investment officer at Baskin Wealth Management.
Last week, the largest-ever merger in the Canadian energy sector was announced, when Enbridge said it would spend $37 billion to buy Houston's Spectra Energy, a company focused on gas pipelines. It gives Enbridge a way to grow without building new pipelines, since its Northern Gateway Canadian oil sands pipeline project has been stalled for years. "We're starving our transportation and utility companies out of Canada,” said Rafi Tahmazian, a portfolio manager with Canoe Financial in Calgary.
IEA revises forecast, expects oil glut to persist into 2017
(Bloomberg; Sept. 13) - The International Energy Agency has changed its view on global oil oversupply, seeing a glut persisting into 2017. The oil surplus will last longer than previously thought as demand growth slumps and output proves resilient, the IEA said Sept. 12. Oil has fluctuated since rallying in August amid speculation the Organization of Petroleum Exporting Countries and Russia would agree on measures to stabilize the market at a meeting later this month.
All solutions are possible, Algeria’s energy minister said Sept. 9. Rising OPEC production has offset the effect of declining supplies elsewhere, maintaining the oversupply, the IEA said. Meanwhile, global oil consumption growth sagged to a two-year low in the third quarter as demand faltered in China and India, while record output from OPEC’s Gulf members is compounding the glut, the IEA said in its monthly report.
As recently as last month, the agency had expected the market to return to equilibrium this year. “This was a marked shift in outlook by the IEA,” said Harry Tchilinguirian, head of commodity markets strategy at BNP Paribas in London. OPEC’s “long game got a little longer, implying the need for oil prices to remain lower for longer to spur the necessary adjustments in supply for the re-balancing of the market.”
U.S. shale oil output on track to slip for 11th month in a row
(Reuters; Sept. 12) - U.S. shale oil production is expected to fall for an 11th consecutive month in October, according to a U.S. government forecast released Sept. 12, on the back of a two-year global rout in oil markets. October U.S. shale oil production is set to drop by 61,000 barrels per day to 4.41 million, according to the U.S. Energy Information Administration's drilling productivity report, the lowest output since March 2014.
The biggest decline was in the Eagle Ford in Texas, which saw a fall of 46,000 barrels per day to nearly 982,000. In North Dakota, Bakken oil production is set to drop by some 28,000 barrels to 914,000. While oil prices are trading at less than half of their value from mid-2014, they recovered from 13-year lows earlier this year, recently even reaching $50 a barrel. That has allowed at least some production declines to be tempered in the Permian Basin in Texas, the largest U.S. shale basin by production.
Total U.S. shale gas production, meanwhile, is forecast to decline for an eighth consecutive month in October to 45.3 billion cubic feet per day, the lowest level since March 2015, the EIA said. That would be down about 0.3 bcf from September, making it the smallest monthly decline since May, it noted. The biggest regional decline was expected to be in the Eagle Ford in Texas, down 0.2 bcf from September to 5.6 bcf in October, the lowest level of output in the basin since November 2013, the EIA said.