China looking to sell unneeded LNG, adding to global oversupply
(Bloomberg; Nov. 18) - U.S. liquefied natural gas producers face an unlikely challenge as they prepare to enter global markets: China’s sale of supply it won’t need. The Asian nation will accept only 77 percent of its contracted cargoes in 2015 as its slowest economic growth since 1990 cuts demand, according to industry consultant IHS Inc. The rest of the supply will be put up for sale amid a worldwide glut that Goldman Sachs says is likely to force U.S. export projects under construction to operate at half capacity.
The U.S. and China are seeking to sell cargoes just as new LNG output equivalent to more than a third of global demand is set to flood the market over the next three years. While producers face more competition, the supply surge is a bonanza for the world’s biggest buyers, including Japan, that are benefiting from the lowest prices since at least 2010. “Chinese buyers have started trying to divert cargoes away from their home market,” James Taverner, an IHS analyst in Tokyo, said by e-mail.
The North American shale boom triggered producers to prepare for LNG exports five years ago, when benchmark U.S. natural gas was as much as double today’s price. Elsewhere, companies sank billions of dollars into new supply from Australia to Africa, counting on Asian demand. LNG producers will increase annual supply by about 90 million tons over the next three years, according to Sanford C. Bernstein & Co., equivalent to about 38 percent of demand in 2014. Meanwhile, China will cut natural gas prices for business and industrial users as it seeks to boost demand for the fuel.
China cuts benchmark natural gas price to spur more demand
(Wall Street Journal; Nov. 18) - China’s government Nov. 18 moved to shore up ailing demand for natural gas across its economy with deep price cuts aimed at spurring more use by domestic industry. The cuts, reported by the National Development and Reform Commission, China’s top economic planner, cut benchmark city-gate prices by $3.10 per 1,000 cubic feet for industry and commercial users. The move had been expected for several months and equals a 28 percent cut in average city-gate prices nationwide.
The cuts are important, not least because they signal Beijing is serious about weaning its reliance on coal as part of cleaning up China’s air and economy. But at the same time, the lower price could slow domestic shale exploration and production in western China, analysts said. City-gates prices refer to the prices that local distributors pay for gas and have a significant impact on the prices that end-users such as factories pay as well as overall domestic demand. The price cut doesn’t apply to residential consumers.
The commission also said it was deepening energy-sector reforms by allowing greater price negotiation between buyers and sellers. With the move, China will allow suppliers to charge up to 20 percent more than the benchmark, based on supply and demand. It set no downward limit for price fluctuations. The price cuts, which will take effect Nov. 20, aim to restore demand growth for gas in China after it soured this year. “China is the most important gas growth market globally, and the LNG industry will breathe a sigh of relief on this announcement,” said Neil Beveridge, a gas analyst at Bernstein Research.
China proposes $7 billion investment in U.S. methanol plants
(Energy Wire; Nov. 17) - China is seeking to tap the flood of cheap natural gas coming from the interior of North America by converting it to methanol at three huge refineries proposed in Washington and Oregon. The plants, collectively called Northwest Innovation Works, have received little attention despite their head-snapping impact: The refineries could increase demand for natural gas in the Pacific Northwest by 40 percent. They would more than triple the size of the fast-growing U.S. methanol industry.
At an estimated $7 billion cost, the refineries would be one of the largest investments ever by China in new U.S. manufacturing. The largest plant, in Tacoma, could use more water than all the residential customers of the public utility district combined. The plan is being viewed warily by Pacific Northwest environmental groups that have been effective at slowing a long list of proposals to deliver North American coal, oil and gas to markets in Asia. Two of the three refineries would sit on the banks of the Columbia River.
The end goal is methanol, a crucial building block of plastic and many other materials of modern life. China would be the sole recipient of the production, which would lower greenhouse gas emissions in China while raising them to a lesser degree on American shores. China is the world's largest producer and consumer of methanol, and it manufactures almost all of it from coal, which creates a great deal of carbon emissions. The three plants would about triple total U.S. methanol production.
British government wants to close all coal-fired power plants by 2025
(New York Times; Nov. 18) - The British government Nov. 18 called for closing all coal-fired power plants in the country by 2025. The move, announced in advance of the U.N. conference on climate change in Paris on Nov. 30, appeared aimed at showing Britain as a leader in reducing carbon dioxide emissions. “It cannot be satisfactory for an advanced economy like the U.K. to be relying on polluting, carbon-intensive 50-year-old coal-fired power stations,” said Amber Rudd, minister for energy and climate change.
The government will publish its detailed proposals in the spring, she said. Rudd wants more gas-fired stations to be built, since relying on "polluting" coal is "perverse.” Coal use in Britain is in decline as utilities close aging plants, but more than 20 percent of the country’s electricity was still being generated from the fuel in the second quarter of this year. By comparison, just over 30 percent of British electricity came from natural gas, 25.3 percent from renewables and 21.5 percent from nuclear plants.
Analysts say most British coal plants are likely to be shut by the mid-2020s anyway, but they add that forcing the closing of all coal plants within a decade could be too hasty. Speaking Nov. 18 to a group of civil engineers, Rudd said Britain should be using gas instead of coal to generate electricity because gas burns cleaner than coal. With the decline in North Sea production, she added, Britain may need to get 75 percent of its gas from other countries by 2030, compared with the roughly half that it now imports.
First Sabine Pass LNG to Europe could go to Lithuania
(Reuters; Nov. 17) - The first export of U.S. liquefied natural gas to Europe will head for Lithuania, two industry sources say, a gesture to the Baltic states that are heavily reliant on Russia for supply, and the first shot in a price war over market share in Moscow's backyard. The February delivery of U.S. LNG will challenge Russia's land-locked pipelines. The Cheniere Energy LNG export plant at Sabine Pass, La., is expected to start shipments early next year.
In addition to Sabine Pass, four other LNG export terminals are under construction on the U.S. East and Gulf coasts. Talks are ongoing on the inaugural U.S. shipment, though Lithuania's state-run Lietuvos Energija wants a discount to Russian piped deliveries, one source said. Most of the output at Sabine Pass is under long-term contract, though the customers are free to deliver the LNG wherever they want. U.K.-based BG Group is an anchor customer for the Cheniere plant.
One question is whether Gazprom will defend market share by upping output and lowering prices or by restraining production, as it did during the last gas market glut in 2008-2009, and waiting for prices to recover, said Stephen O'Rourke, director of gas research at consultancy Wood Mackenzie. Lithuania opened its floating LNG import terminal in 2014.
Partners OK additional drilling to feed Australia LNG plant
(Sydney Morning Herald; Nov. 16) - BG Group and its Asian partners in the $20.4 (U.S.) billion Queensland Curtis LNG venture in Australia have given the go-ahead for $1.7 billion of additional spending for up to 400 new wells to maintain gas supply. Drilling will occur over the next two years. The large investment underscores the ongoing spending commitment required by the coal-seam gas LNG projects in Queensland, which need to keep drilling new wells every year to maintain gas supplies for their export plants.
BG started shipments from the facility in January — the first ever gas exports from Queensland — and has so far delivered 62 cargoes to Asia. As partners in Queensland Curtis LNG, China National Offshore Oil Corp. and Tokyo Gas will fund part of the additional drilling, but the British company will shoulder most of the investment in line with its 73.75 percent stake in the acreage. The work also includes 450 miles of water and gas gathering lines, a compression station as well as other power and water lines.
Chevron reports Gorgon LNG in final stages for commissioning
(Business Finance News; Nov. 16) - One of the largest liquefied natural gas projects in the world, and Australia’s largest ever resource project, the Chevron-led Gorgon project is on its way to make its first LNG shipment in early 2016. In the latest update on its website, Chevron reported the project in its final stages to prepare for commissioning, which would allow start-up of the plant’s first liquefaction train.
An LNG cool-down cargo is expected to arrive in mid-December, necessary to help in cooling down the massive storage tanks in preparation for the start of LNG production at the plant. Gorgon, at an estimated $54 (U.S.) billion, and another Chevron-led project in Australia, Wheatstone, and an LNG export project in Angola are expected to help improve cash flow at the oil-and-gas major after years of multibillion-dollar construction spending on the projects.
The $10 billion Angola plant has been closed since last year for major rebuilding after production problems. Wheatstone, at $29 billion, is scheduled for start-up before year-end 2016. Wheatstone, Angola and Gorgon have all incurred delays and cost overruns.
First Nation considering small LNG plant near Vancouver
(Globe and Mail; Nov. 16) - The Tsawwassen First Nation is considering building a small liquefied natural gas production plant and export terminal south of Vancouver, working in a joint-venture with FortisBC that is expanding its own 1971 liquefaction plant in Delta, also just south of Vancouver. The First Nation proposal calls for producing 3 million to 5 million metric tons of LNG per year, filling several tankers per month. The project would rely on an existing pipeline to deliver gas. No project cost was provided.
Members of the First Nation are set to vote on the proposal Dec. 16. The First Nation has selected industrial property on its land for the LNG site. The FortisBC $400 million expansion is separate from the proposed Tsawwassen project. Expansion work started at the FortisBC Tilbury plant last year, with the additional production to start up by the end of 2016. The Tsawwassen First Nation is among 20 or so LNG plants proposed for up and down the coast, looking to profit from shale gas plays in northeastern B.C.
B.C. official asks LNG opponents to wait for federal review
(Globe and Mail; Canada; Nov. 15) - B.C. Deputy Premier Rich Coleman said plans for a liquefied natural gas terminal near Prince Rupert will be judged on a science-based environmental assessment, urging the project’s critics to wait for details from a federal review. Coleman said critics should allow the Canadian Environmental Assessment Agency to finish its job and study new submissions — notably scrutinizing more details and revisions expected from the company about its plans for building the LNG terminal.
A group led by a Lax Kw’alaams First Nation tribal leader complains that the Pacific NorthWest LNG project will damage juvenile salmon habitat. Donnie Wesley, a hereditary chief of the Gitwilgyoots tribe, argues that no amount of mitigation measures would protect the ecologically sensitive Flora Bank, located next to Lelu Island in the Skeena River estuary.
“They always say it should be based on science, but they’re prepared to prejudge it,” Coleman said of the project’s opponents. Malaysia’s state-owned Petronas heads the venture, one of 20 projects in British Columbia vying to export gas overseas, mostly targeting Asia. Pacific NorthWest LNG is trying to address opponents’ concerns in its project plans. Canada’s environmental agency started its review into Pacific NorthWest LNG in April 2013. It could issue its decision in February.
New report says LNG project in B.C. would not harm salmon habitat
(Globe and Mail; Canada; Nov. 18) - Flora Bank is a resilient area that would emerge unscathed in the event that liquefied natural gas is produced on Lelu Island, B.C., a report commissioned by Pacific NorthWest LNG concludes. Visible at low tide, Flora Bank contains eelgrass that nurtures juvenile salmon in the Skeena River estuary near Prince Rupert. Pacific NorthWest LNG, led by Malaysia’s state-owned Petronas, wants to build an export terminal on Lelu Island, located next to Flora Bank.
“The technical work completed to date indicates that the project is not likely to cause significant adverse environmental effects on fish and fish habitat,” according to the consortium’s 36-page summary of its findings. The findings contrast sharply with research carried out by the aboriginal-backed Skeena Fisheries Commission, which is sounding the alarm about significant risks to Flora Bank.
Pacific NorthWest LNG conducted new studies after the Canadian Environmental Assessment Agency requested more details from the consortium. Pacific NorthWest LNG said it will also have a program to monitor fish habitat and will continue to discuss its plans with groups ranging from Fisheries and Oceans Canada to First Nations. The federal environmental agency is expected to produce a draft report before rendering a final decision on the Petronas-led project by the spring of 2016.
Pakistan looks to convert power plants, boost LNG imports
(Pakistan Today; Nov. 15) - The Pakistan government is considering converting its inoperative electricity generation plants running on diesel or furnace oil in Sindh and Punjab to liquefied natural gas to boost power generation capacity, said Syed Mohammad Ali, CEO of Engro Vopak Terminal and Elengy Terminal Pakistan. Most of the big electricity plants running on diesel and furnace oil are not producing electricity at full capacity because of domestic natural gas shortages or expensive alternative fuels.
“The initial plan of the government is to run the inoperative electricity plants at their full capacity through imported LNG,” Ali said, adding that the plants could make electricity at half the cost of other fuels. On any given day, diesel is more expensive than LNG, he said. LNG prices are down sharply from their peak less than two years ago as new supplies are coming online in an oversupplied market. Pakistan has started importing LNG just in the past year, after domestic gas production failed to keep up with demand.
The country produces about 4 billion cubic feet of gas per day but could use an additional 2 bcf a day, Ali said. “LNG remains a cheaper option (than diesel or fuel oil),” he said. “LNG … is more efficient in power generation, leading to lower operational, management and transportation costs.” According to some estimates, the CEO said, Pakistan could save $1 billion to $1.5 billion per year by importing 1 bcf a day of LNG to replace oil fuels.
TransCanada plans expansion to handle Alberta, B.C. gas production
(Calgary Herald; Nov. 16) - More relief for Western Canada gas producers enduring pipeline bottlenecks is on the way with Calgary-based TransCanada announcing Nov. 16 a $570 million proposal to add capacity for 2.7 billion cubic feet per day of firm contracts on its Nova Gas Transmission system by 2018. Dozens of oil and gas companies operating in western Alberta and northeastern B.C. have reported interrupted production over the summer as natural gas gushing from horizontal, multi-fractured wells overwhelm pipeline capacity.
“There’s a lot of capacity in Alberta but, in many cases, it’s in the wrong place. Horizontal drilling has changed where we drill,” said Jim Evaskevich, chief executive of junior Yangarra Resources, which uses TransCanada to take gas to market from its land base in west-central Alberta. “We lost a lot of production this year, although currently we don’t have much cut back.”
TransCanada said its 2018 expansion program represents the minimum system addition required to cover contracts, and additional expansions may be planned if identified in an assessment this year. It said it intends to make application to the National Energy Board in the second half of 2016 to build the 2018 projects. The expansion would be in addition to $7.5 billion of projects already announced on the Nova system as TransCanada works to handle growing gas production in the region.
TransCanada expands its pipeline work in Mexico
(Bloomberg; Nov. 17) - Days after the U.S. spurned TransCanada’s proposal to expand its Keystone oil pipeline network across North America, Mexico opened its arms. TransCanada won the rights last week for its sixth gas pipeline in Mexico, one of the company’s key targets for growth. The Nov. 10 decision came four days after the U.S. denied TransCanada’s bid to build its Keystone XL oil sands project across the border.
Mexico’s need for foreign investment to help the nation improve its infrastructure is a welcome opportunity for TransCanada after losing its seven-year battle to complete Keystone XL. The Canadian company, which owns pipelines and power plants, plans to invest more than $3 billion in Mexico by 2017, said Robert Jones, president of Mexico operations. Mexico is planning to hold as many as five gas pipeline auctions before the end of January, and TransCanada will “look at them all,” Jones said.
With the latest contract, TransCanada now holds rights to develop and operate more than 1,200 miles of pipelines in Mexico. TransCanada’s expansion in Mexico coincides with the country’s overhaul of its energy industry that ended the state-run monopolies, opening the door to private investment. Mexico plans to expand its pipeline network 75 percent by 2018 and is seeking as much as $10 billion in investment for 24 new projects in the short term, helping to move plentiful U.S. shale gas south of the border.
Flint Hills applies for small-scale LNG exports; targets Caribbean
(Energy Wire; Nov. 18) - Flint Hills Resources has applied to export liquefied natural gas via an expedited pathway that relies on an existing small-scale LNG plant and standard-sized shipping containers and barges to reach Caribbean and other small markets. In a recent filing with the Department of Energy, Flint Hills, a Wichita, Kansas-based Koch Industries subsidiary, requested permission to export up to 120,000 gallons of LNG per day — about 3.6 billion cubic feet of natural gas per year.
The project is tiny by LNG export industry standards, with some Gulf Coast plants looking to export 2 bcf a day. But the Flint Hills project enjoys a benefit the big ones do not: It is exempt from review under the National Environmental Policy Act, potentially saving months or years and millions of dollars. Most liquefaction plants undergo a lengthy environmental review by the Federal Energy Regulatory Commission or Maritime Administration before construction and operation of a terminal.
The FERC process, which covers land-based terminals that serve LNG tanker ships, generally takes at least two to three years and tens of millions of dollars to complete. The MARAD process for offshore plants is designed to produce a decision within one year. But Flint Hills proposes to load up containers at an existing, company-affiliated liquefaction plant in Texas for shipment by barge or containership to buyers. That would be exempt from the stringent environmental review, the company said, because no operations would change at its LNG facility — only the delivery method and destination.
North Dakota oil production down 5 percent from year ago
(Energy Wire; Nov. 16) - Oil production in North Dakota's Bakken Shale formation has begun to coast downward, nearly a year after prices started to crash, and it could keep falling, the state's top energy regulator said Nov. 13. The state pumped 1.16 million barrels a day in September, down about 2 percent from August and about 5 percent below the all-time high set in December 2014.
The number of producing wells fell month over month for the first time since 2003, and the number of wells that have been drilled but not completed, or hydraulically fractured, has topped 1,000, state Mineral Resources Director Lynn Helms said on a conference call with reporters. Companies are "producing only as much oil as they need to make the stockholders and the bankers happy," Helms said.
Drilling is economical in only three of North Dakota's western counties at current prices, and production could drop below 1.1 million barrels a day, Helms said. The average North Dakota price was $31.17 per barrel in September, reflecting the national decline and the higher cost of transporting Bakken oil to refining centers on the coasts. It could take a year for production to recover once prices improve, Helms said.