Japanese utilities look to nuclear and coal to cut electricity rates
(U.S. Energy Information Administration; Sept. 9) - As Japan's electricity generation mix shifted away from nuclear energy toward increased use of coal and natural gas after the 2011 Fukushima nuclear plant accident, Japan became increasingly reliant on imported coal and liquefied natural gas. However, even as the imported cost of coal and LNG declined into 2015, Japan's electricity price increased.
According to data from Japan's 10 major utilities, the average retail electricity price rose for four consecutive fiscal years (2011-2014) as the utilities had shut down all of their nuclear capacity and turned to costly fossil fuel imports. But in fiscal year 2015, as LNG prices fell 37 percent and coal prices fell 19 percent, Japan's retail electricity price fell by only 2 percent, according to the U.S. Energy Information Administration. Because Japan has little or no domestic gas or coal, the country relies heavily on imports.
As low coal prices led to increased imports of coal, LNG imports in 2015 fell for the first time since 2009. The global oversupply of LNG and lower oil prices pushed down the price of LNG in 2015, but not enough to make LNG more economic than lower-priced coal, particularly as Japanese utilities dealt with stagnant or declining electricity demand, the U.S. agency reported. Meanwhile, Japan is looking to restart a portion of its nuclear fleet and boost coal capacity in order to further reduce its electricity prices.
Freeport LNG in Texas requests increased export authority
(LNG World News; Sept. 8) - Freeport LNG has requested permission from the U.S. Department of Energy to increase the export volumes from its $12.5 billion terminal under construction near the city of Freeport, in Brazoria County, Texas. Freeport LNG is seeking permission to engage in additional long-term, multi-contract exports of LNG to non-free-trade countries of up to 340 million cubic feet per day of natural gas, about 3 million metric tons of LNG per year, for 20 years.
The additional volume would be above the 1.8 billion cubic feet of gas a day (about 14 million tons of LNG per year) allowed under previous Energy Department export authorizations. Freeport LNG is seeking to align its authorized export volumes with the increased production capacity design of the facilities approved by the Federal Energy Regulatory Commission. Freeport opened in 2008 as an import terminal and, like other U.S. Gulf Coast facilities, its owners later decided to add LNG export capabilities.
Approximately 1.7 bcf a day of liquefaction capacity at Freeport’s three production trains have been contracted under use-or-pay liquefaction tolling agreements, according to the company’s website. The first two trains are on schedule to commence operations by September 2018 and February 2019, respectively. The third train is expected to be in operation approximately six months following the second train, about August 2019. Freeport LNG is also planning to add a fourth LNG unit, pending regulatory approvals.
More than half of Sabine Pass LNG has gone to South America
(ICIS; Sept. 8) - Europe has received just 8 percent of delivered volumes of U.S. LNG since Cheniere Energy’s Sabine Pass export terminal in Louisiana came online in February, according to ICIS shipping platform LNG Edge. The majority of cargoes have instead found a home in South America, where markets have offered exporters a more favorable return than that available based on recent, sagging European prices. Forward prices suggest the trend of low flows to Europe may persist into the winter as well.
As of Sept. 6, ICIS LNG Edge data showed that 26 cargoes were loaded and sent out from Sabine Pass, with a little more than half the total exports delivered to South America. Chile has been the single biggest recipient, taking more than a quarter of all the cargoes — all delivered by Shell, which took over the large-volume BG Group contract for Sabine Pass liquefaction capacity when Shell bough the U.K. company.
Europe’s 8 percent share from Sabine Pass represents one cargo each to Portugal and Spain. The destination of the first cargoes is not surprising as South American markets have consistently offered exporters the best returns on a netback basis. ICIS models netback prices for key LNG-producing regions by deducting shipping costs. The first production train at Sabine Pass has started operations and the second unit is scheduled to begin production by the end of this year, followed by two more trains next year.
Alberta clean-energy think tank recommends against LNG project
(Business in Vancouver; Sept. 9) - The Pembina Institute, which was part of the B.C. Climate Action Leadership Team that concluded the province could develop a liquefied natural gas industry and still meet its greenhouse-gas emission targets, now suggests that those two goals are mutually exclusive. In a letter to federal Environment Minister Catherine McKenna, the Calgary-based sustainable energy think-tank has urged the minister to reject Petronas’ proposal to build the Pacific NorthWest LNG project.
Had the government implemented recommendations in its updated Climate Action Plan last month — raising the carbon tax and committing to electrification of the gas fields in northeastern B.C. — the Climate Action Leadership Team concluded that LNG could fit within the province’s greenhouse-gas limits. But the government deferred on raising the carbon tax until other jurisdictions catch up, did not adopt mid-term emission reduction targets, and committed only to electrifying the gas-producing region with federal aid.
Without those key policies in place, the Pembina Institute calculates that greenhouse-gas emissions from the Pacific NorthWest LNG project proposed for near Prince Rupert, B.C., would consume three-quarters of the province’s total emissions target in 2030, the institute said. “It is for these reasons the institute recommends the environmental certificate for the project be rejected,” Matt Horne, Pembina’s B.C. director, wrote to McKenna on Sept. 7. McKenna’s decision on the LNG project is expected next month.
Tribe loses in court, but federal agencies put stop to oil pipeline work
(Wall Street Journal; Sept. 9) - The federal government ordered a halt to work on a $3.8 billion, four-state oil pipeline in the Upper Midwest on Sept. 9, handing a temporary victory to the Standing Rock Sioux Tribe and other opponents of the project. The unusual move by three federal agencies immediately followed a federal judge’s ruling denying an injunction sought by the tribe to stop the project that would help move Bakken oil from North Dakota to market.
The U.S. Army Corps of Engineers said it would not authorize construction near Lake Oahe, a culturally important location to the tribe, until the agency determines if it needs to reconsider previous National Environmental Policy Act approvals. “This case has highlighted the need for serious discussion whether there should be nationwide reform with respect to considering tribes’ views on these types of infrastructure projects,” the Corps and the departments of Justice and Interior said in a joint statement.
A spokeswoman for Energy Transfer Partners, which is developing the Dakota Access Pipeline, declined to comment. David Archambault II, chairman of the Standing Rock Sioux Tribe, praised the agencies’ intervention and said it was a historic moment for Native Americans. U.S. District Judge James Boasberg ruled Sept. 9 that he wouldn't grant the stop-work injunction sought by the tribe because he didn’t agree that the federal government failed to consult with the tribe as required by law and or that the pipeline would cause irreparable harm to the tribe’s heritage.
Young Sioux activist helped mobilize opposition to oil pipeline
(NBC News; Sept. 9) - Gracy Claymore remembers when the message flashed across her laptop screen. Texas-based Energy Transfer Partners sent her and all members of the Standing Rock Sioux Tribe a 48-hour construction notice Aug. 3 for the controversial Dakota Access Pipeline — a 1,170-mile oil line from North Dakota to Illinois. Part of the pipeline would traverse the Sioux's sacred, ancestral lands and run under the Missouri River, the tribe's sole water source. The pipeline would run just a half-mile from the Standing Rock reservation, which straddles the North and South Dakota border.
For Claymore, a 19-year-old student who along with dozens of her peers had protested the pipeline for months, warning of "the potential catastrophic environmental damage" an oil spill would bring for their people, it was the time for action. She corresponded with fellow members of the Oceti Sakowin Youth Group, a support network of student activists on the reservation. In July, the network organized a 2,000-mile-long run from North Dakota to Washington, D.C., to bring awareness to their efforts to stop the line.
They agreed to head to the site the day after the Aug. 3 construction notice and set up human barriers to block the road. More than a month later, their numbers swelled to thousands. Claymore and her fellow activists had sparked a movement. And that movement is now at a crossroads: A judge was expected to rule Sept. 9 on the fate of the pipeline. The Dakota Access Pipeline, which is more than half completed, is a $3.8 billion project that would move 470,000 barrels of oil a day from Stanley, N.D., near the Canadian border, to Patoka, in southern Illinois, to link up link with existing pipelines.
Court refuses to stop work on LNG project in Tacoma, Wash.
(The News Tribune; Tacoma, WA; Sept. 9) - A Washington state appeals court has rejected the Tacoma News Tribune’s request to halt permitting and construction of a liquefied natural gas production, storage and marine fueling facility on 30 acres of the Tacoma Tideflats until its safety studies are made public. In a ruling handed down Sept. 9, the court said it could find no authority to grant the paper’s request, which would have held up work on the project while courts decide if the reports should be released.
Puget Sound Energy is partially through permitting for its $275 million project, which would produce 250,000 gallons of LNG a day from gas piped to the site, storing the LNG for peak-demand utility needs and fueling vessels, including TOTE’s Alaska-route roll-on, roll-off vessels. Though the court denied the request to stop work, it agreed to speed up consideration of whether to order release of the safety reports. The company plans to build an 8-million-gallon storage tank nearly as tall as the Tacoma Dome.
The studies requested by The News Tribune, and two activists who have a similar case under appeal, look at what happens if LNG in the storage tank was to leak, become a vapor cloud or catch fire. The studies also include computer models of the damage radius. The studies have been submitted to public agencies in charge of reviewing plant safety and permitting. The company is in court to block release of the studies, arguing that publication is a security risk. Puget Sound has said the plant could start up in 2018.
Eni having problems with new Arctic oil platform in Norwegian waters
(Wall Street Journal; Sept. 8) - Norway is pressuring Italy’s Eni to improve operations at the world’s northernmost offshore oil platform after the Arctic development was shut down and evacuated over a power failure last month. The project, known as Goliat, is testing a new circular-platform concept in a development 300 miles north of the Arctic Circle in the Barents Sea. It is partially run by hydropower via a cable to the mainland, a mandate imposed by the Norwegian government to reduce the platform’s emissions.
The 100,000-barrel-a-day field started pumping in March but has been plagued by problems. The Aug. 26 shutdown was the second in three months, causing the evacuation of dozens of workers. In April, Eni reported a gas leak at Goliat. A month later, it reported that smoke had been detected in a generator. And in June, the government launched an investigation into an accident where a worker was injured.
“Over time there’s been disturbing information about repeated errors and a lot of incidents at Goliat,” said Anniken Hauglie, Norway’s minister of labor and social affairs. "We don’t accept any slack in oil-industry safety, despite a downturn and falling revenues,” Hauglie said. Norway’s Petroleum Safety Authority said Eni must prepare a plan to fix the problems at Goliat before the rig could be restarted. Goliat is 65 percent owned by Eni, with Norway’s Statoil holding a 35 percent interest.
Norway’s Statoil buys up stakes in Arctic prospects
(Wall Street Journal; Sept. 6) - Norway’s Statoil said Sept. 7 that it was pushing deeper into the Arctic, shopping for Barents Sea drilling licenses in a bid to add resources and maintain output over the coming decades. The 67 percent state-owned company said it had acquired stakes in four licenses in Norway’s far north from London-based Tullow Oil after entering or boosting its holdings in five other Arctic licenses in the past months, through deals with companies including Vienna-based OMV and ConocoPhillips.
“We’re doing this in a very countercyclical manner, meaning that we were able to pick up these licenses at what we consider to be very attractive terms,” Jez Averty, Statoil’s head of exploration in Norway and the U.K., told The Wall Street Journal. “What we’re looking to do is to establish ourselves as one of the leading companies in that area.” As production in the mature North Sea depletes, the Barents Sea may hold the key to maintain Statoil’s output in the coming decades.
The Arctic basin has been drilled since the 1980s, but at a slow pace. Companies are still hoping for huge finds in the Barents Sea, unlike in the North Sea where they are now mainly looking for smaller discoveries near existing infrastructure, Averty said. Despite a disappointing drilling campaign in 2013 and 2014 to find additional resources near the Johan Castberg discovery in the Barents Sea, Statoil is pushing ahead with a significant drilling campaign in the area next year.
Australian oil and gas producer picks up assets while prices are low
(Wall Street Journal; Sept. 5) - Backed by robust balance sheets, some of the world’s leading energy companies are laying down ambitious bets on longer-term demand, even while oil and gas prices languish. On Sept. 5, Woodside Petroleum, Australia’s largest oil and gas producer, said it had agreed to pay as much as $400 million for half of Anglo-Australian mining and petroleum giant BHP Billiton’s interests in a remote natural gas field off Australia’s western coast.
That followed a deal by Woodside in July to buy undeveloped oil assets in Senegal from ConocoPhillips for about $430 million. The same month, ExxonMobil agreed to buy Papua New Guinea-focused gas explorer InterOil for about $2.5 billion. There have been few big energy-sector mergers since Shell’s roughly $70 billion acquisition of BG Group was unveiled in early 2015. Instead, companies have been selling assets and acreage piecemeal to cut debt to cope with the slump in oil prices the past two years.
“Like the recent Senegal acquisition, it shows that Woodside is not afraid to make significant countercyclical investments at this point in the cycle,” said Neil Beveridge, senior analyst at Sanford C. Bernstein in Hong Kong. Beveridge said the structure of the deal, with a contingency payment based on a final investment decision for the gas field, suggests plenty of uncertainty over whether the project will move forward. “But clearly, Woodside is betting that the risked return is worth it,” he said.
Imperial oil puts historic Norman Wells oil field in Canada up for sale
(Bloomberg; Sept. 9) - Imperial Oil is looking for a buyer for its historic Norman Wells operations in Canada’s Northwest Territories as the producer focuses on its larger business operations. Imperial, majority owned by ExxonMobil, plans to market the 11,000-barrel-a-day oil field this quarter, the company said in a statement Sept. 9. The assets also include a fuel distribution center, Imperial said, without providing further details.
Imperial began drilling for oil in Norman Wells, a town about 100 miles south of the Arctic Circle, in 1920, followed later by a refinery that supplied military operations in Alaska and Canada’s Yukon Territory during World War II. Decades later, the company expanded production and connected the field to other markets with a pipeline to Alberta. About 250 million barrels of oil have been extracted from the field, according to the company.
UPS among the leaders in converting trucks to natural gas
(Chicago Tribune; Sept. 4) – Looking like giant white lozenges and sticking out above the vast parking lot at a UPS facility a few miles west of Chicago are tanks for liquefied natural gas. The gas is used to fuel UPS trucks instead of diesel, part of a 10-year-old company program to try alternatives for part of the delivery company's fleet. Americans have been enjoying low gasoline and diesel prices over the past two years, which has led to both an increase in driving and a drop in sales for fuel-efficient cars.
But fuel-dependent companies like UPS and transit agencies have not forgotten the pain of $4-plus diesel. Aided by government grants and other incentives, commercial and municipal fleets are adopting alternative fuels — like propane, compressed natural gas and electricity — more quickly than the public, say industry experts. The fuels also can cut emissions, though there is debate on how much better they are. For commercial and municipal entities, economics and the environment both factor into the choice.
Two of the most commonly used alternatives to diesel are compressed natural gas or CNG (gas stored at high pressure) and liquefied natural gas or LNG (stored at extreme low temperatures). CNG and LNG conversions by commercial fleets paused with the drop in diesel prices, said Don Ake, an analyst for FTR, a Bloomington, Ind.-based transportation forecasting firm. The investments will make sense again as diesel prices climb, Ake said. "In the long run, it's going to be cheaper and cleaner.”