India’s LNG importer wants to negotiate price cut for Gorgon supply
(India Today; Oct. 23) - Petronet LNG, India’s largest liquefied natural gas importer, is seeking at least a 10 percent price cut on the LNG it will buy from Australia’s Gorgon project. Petronet in August 2009 signed a 20-year deal to buy 1.44 million metric tons a year of LNG from Gorgon, at a price equivalent to 14.5 percent of prevailing oil prices. That indexation was one of the highest in the world. "The world has changed since then and LNG deals are being done at much lower indexation," a Petronet official said.
Petronet last year successfully negotiated a lower price under its long-term deal for LNG from Qatar, also agreeing to buy an additional 1 million tons per year priced at 13.05 percent of oil. “The expectation is that Gorgon should lower the indexation to … 13 percent," the Petronet official said. Petronet has written to ExxonMobil, a partner in Gorgon LNG, asking to rework the price. "Negotiations are on,” the official said. Gas, sold in units of 1 million Btu, has about one-sixth the energy value of a barrel of oil.
LNG in the spot market is available at $5 to $6 per million Btu, whereas Gorgon LNG under the 2009 deal will cost Petronet $7.25 at an oil price of $50 per barrel. After adding customs duty, shipping costs and the expense of converting the LNG into a gaseous state, the landed price of the Australian gas in India will be close to $9.50. Petronet expects to start taking deliveries of gas from Gorgon next year. The new plant, operated by Chevron, started production this spring, but is not yet up to full production.
Indonesia’s LNG plants looking to sell 63 uncommitted 2017 cargoes
(Reuters; Oct. 20) - There are currently 63 uncommitted cargoes of liquefied natural gas available for delivery in 2017 from Indonesia's Tangguh and Bontang projects, Wiratmaja Puja, the country's Director General of Oil and Gas, said Oct. 20. "We want these to be sold to committed buyers," Puja said, noting deals for 13 of the cargoes were currently being negotiated. "It would be real pity if we had to cut production."
The two liquefaction plants, with a combined 10 production trains, are capable of 30 million metric tons of annual output — more than 400 cargoes of LNG. Looking ahead to 2018 production, there were still "more than 60" uncommitted cargoes, Puja said. "We are still oversupplied.” Though most of the plants’ output is committed under long-term contracts, additional gas is available in the spot and short-term markets.
Floating LNG import facility could add to Turkey’s gas supply
(Daily Sabah; Turkey; Oct. 20) – A floating liquefied natural gas import terminal off the Yalova province coast in Turkey's Marmara region is expected to ease the energy supply for the region, which hosts more than a quarter of the country's population and industry. According to an article in Turkish business daily Dünya, a company named Maks Enerji has applied to the Energy Market Regulatory Board to operate a floating storage and regasification unit near the southern shores of the Gulf of Izmit.
It would allow LNG imports into Turkey for the first time. The LNG, delivered by tankers, would be warmed back to a gaseous state and supplied to the gas distribution grid of the national pipeline company BOTAŞ. The facility would be able to handle an average of more than 500 million cubic feet of gas per day. Turkey currently imports an average 4 billion cubic feet of gas per day by pipeline from Russia, Iran and Azerbaijan.
Shell pitches floating LNG import facility in the Philippines
(Manilla Bulletin; Oct. 22) – Shell’s Philippine subsidiary is dangling a cheaper and quicker-to-develop floating storage and regasification technology as a viable alternative to an onshore liquefied natural gas import terminal. Floating import facilities are a lower-cost option to onshore LNG terminals — at under $400 million, less than half the cost of building onshore. And while an onshore plant could take four years to design and build, a floating answer could be at work in two to three years.
Shell Philippines Country Chairman Edgar O. Chua said the company is exploring the viability of a floating receiving, storage and regasification facility for the country’s gas needs. The Philippines meets its small gas demand — about 116 billion cubic feet per year — with domestic production. But that production is in decline, and the country is eager to grow its use of natural gas. Energy companies have been talking of building an LNG import terminal in the Philippines the past couple of years. Chua said the size of the proposed floating import facility “will depend on demand that we see in the market.”
Extending life of Australian LNG plant may be best option
(Interfax Global Energy; Oct. 21) - Low prices for liquefied natural gas are forcing Australian exporters to switch their focus from building costly new LNG plants to prolonging production at the older, less expensive North West Shelf LNG project, which could keep operating for another 20 years or more if enough feed gas is discovered.
Western Australia’s five-train North West Shelf project was built in 1989 and expanded in 2004, 2005 and 2008. Its capacity is listed at 16.3 million metric tons per year. With the investment largely sunk and the facility near an established gas-producing region, the project is well-placed to keep supplying gas to the Asian market at a competitive rate. Partners in the five trains include Chevron Shell, BP, BHP Billiton, Woodside, Mitsui and Mitsubishi. Australia-based Woodside Petroleum is the plant operator.
Latest proposal would boost output at proposed Indonesia LNG plant
(Gulf Times; Qatar; Oct. 21) - Indonesia expects to decide within “one or two weeks” on a plan by Japan’s Inpex Corp. to increase proposed output from the Masela natural gas field to nearly four times the level originally slated, a senior energy official said Oct. 20. “We are still discussing the capacity of Masela” to between 7.5 million and 9.5 million metric tons per year of LNG, said Coordinating Maritime Minister Luhut Pandjaitan, referring to discussions between the government and Inpex along with its partner Shell.
“There are several conditions we need for this project to be investable,” an Inpex spokesperson said of the proposed liquefied natural gas venture. This would be the second time that Inpex, Japan’s biggest energy developer, and Shell, the world’s top LNG trader, have proposed an increase in output from the deep-sea field in eastern Indonesia that was initially expected to produce 2.5 million tons per year of LNG.
Indonesia President Joko Widodo in March rejected a $15 billion plan by Inpex and Shell to develop the world’s largest floating LNG facility to process gas from Masela, saying an onshore plant would benefit the local economy more. The move was a blow to both companies and pushed the anticipated start of production into the late 2020s. An onshore plant is now the plan, Pandjaitan said, intended to spur construction of petrochemical and fertilizer plants in the impoverished area.
Work set to start Nov. 1 on small-scale LNG export plant in Georgia
(Reuters; Oct. 19) - Kinder Morgan will begin construction on its Elba Liquefaction project near Savannah, Ga., on Nov. 1, ahead of a final ruling from federal regulators on a rehearing request by environmental activists, the company said Oct. 19. The company received approval for the liquefied natural gas export project from the Federal Energy Regulatory Commission on June 1, but the Sierra Club and associated individuals have since filed a request for a rehearing, which is still pending at FERC.
The $2 billion project, which is supported by a 20-year contract with Shell for all of the plant’s output capacity, will be constructed and operated next to the underutilized 40-year-old Elba Island LNG import terminal and will have the capacity to produce and export 2.5 million metric tons of LNG per year (equivalent to about 350 million cubic feet of natural gas per day). The project design includes 10 small-scale liquefaction units, coming online throughout 2018 if the project stays on schedule.
The Elba LNG project has approval for exports to countries covered by free-trade agreements with the United States, while its application for exports to non-free-trade nations is still pending at the Department of Energy. In addition to the Elba Island terminal, Kinder Morgan owns an interest in or operates approximately 84,000 miles of oil and gas pipelines in the U.S.
British Columbia official in Asia, talking up LNG projects
(Calgary Herald columnist; Oct. 19) - British Columbia Deputy Premier Rich Coleman is busy traveling in Asia this week to promote LNG export projects in the province. It will be a more pleasant trip than the one he made this spring. Back then, questions were flying over why federal approval for the Pacific NorthWest LNG project was taking so long. But last month’s federal approval has breathed new life into the dreams of building liquefied natural gas export facilities in the province, Coleman insists.
This week’s trip to Asia includes meetings in Kuala Lumpur with senior officials from Petronas, Malaysia’s state-owned energy company and the main proponent behind the Pacific NorthWest LNG development at Prince Rupert, B.C. “The (federal) permit itself was an important thing to get,” Coleman said. “This is the one everyone globally was looking at saying, ‘How long is it going to take?’” Petronas and its partners are reviewing the permit conditions and project economics before announcing an investment decision.
“When I was in Asia (in May) it was really a question about … are you guys open in Canada for business,” Coleman said. But as the B.C. government has learned, large-scale energy developments are incredibly complex, affected by volatile commodity prices, evolving government regulations, increasing environmental oversight, concerns about greenhouse-gas emissions and intense competition for capital. Some projects have already been put on hold due to low LNG prices amid a global oversupply.
First Nations divided over benefits vs. risks of LNG projects
(Alaska Highway News; Fort St. John, BC; Oct. 20) - For some First Nations people in northeastern B.C., liquefied natural gas means jobs and opportunity. For others, it means a threat to lands, animals and traditional food sources hammered by decades of oil and gas development. The federal decision last month to approve Pacific NorthWest LNG, the Petronas-led proposal to ship gas from B.C. to Asia, highlighted those disagreements among coastal First Nations near the proposed terminal on Lelu Island.
If Petronas decides to build the plant, there would be a ramp-up in drilling in the opposite corner of the province, on the territories of indigenous groups that have already seen their traditional lands and ways of life transformed by steadily increasing oil and gas production. Some First Nations are critical of the project and the 550-mile pipeline that would carry gas to the coast. Others welcome the potential jobs, while others are still figuring out what LNG would mean for their communities.
“We’ll see a lot of areas that have already been heavily hit, hit even harder with more wells, more roads, more access, more water usage — all the things that go along with fracking,” said Saulteau First Nations Chief Nathan Parenteau. Opinion on LNG varies among First Nations on the coast. Some have signed benefits agreements with the company, while others say the project poses an unacceptable risk to the environment and the Skeena River salmon fishery. The First Nations LNG Alliance said 16 of 19 First Nations along the pipeline route have reached benefits agreements.
First Nation at odds over gas pipeline to proposed LNG plant
(CBC Canada; Oct. 20) - Members of the Gitxsan First Nation opposed to pipeline development in British Columbia are outraged that nine unelected hereditary chiefs are working on a deal with the province for a gas pipeline to B.C.'s North Coast. The documents were leaked and posted online, prompting an emergency meeting to discuss next steps. "We had a full room speaking totally against what they've done," said Norman Stephens, a Gitxsan member opposed to the development.
The agreement is connected to the Prince Rupert Gas Transmission Line, which would supply the Pacific NorthWest LNG project. The project, which received federal environmental approval this fall, is waiting on an investment decision by sponsors Malaysia’s Petronas and its partners. Stephens is particularly upset by conditions in the deal that promise the Gitxsan will not be allowed to block construction work.
The deal says: "Gitxsan agrees not to support or participate in any acts that frustrate, delay, stop or otherwise physically impede” the pipeline or LNG development. Gordon Sebastian, one of the hereditary chiefs to sign the document, said the agreement is not carte blanche for the project. This is not the first time the Gitxsan have been divided. Some of the confusion stems from the complex leadership system of the Gitxsan, which has dozens of hereditary chiefs and multiple house leaders, as well as elected officials.
Propane extraction plant would feed export terminal on B.C. coast
(The Canadian Press; Oct. 20) - AltaGas has decided to go ahead with construction of a propane extraction plant in northeastern British Columbia to supply the company’s proposed Ridley Island export terminal near Prince Rupert, B.C. The Calgary-based company said the North Pine processing facility, 25 miles northwest of Fort St. John, B.C., is designed to be developed in two phases, with a total capacity of up to 20,000 barrels per day.
Site preparation for the first phase is expected to begin in the first quarter of 2017. Commercial production is expected in the second quarter 2018. AltaGas estimates the first phase will cost between $125 million and $135 million. The $500 million propane export terminal on the coast would be capable of filling 20 to 30 tankers a year, taking delivery of the fuel by rail, storing and loading the propane for overseas shipment. The propane would come from gas production regions in northeastern B.C. and Alberta. Pending regulatory approvals, AltaGas is looking to start exports in 2018.
Opponents continue fight against small LNG plant in Tacoma, Wash.
(Tacoma Weekly; Oct. 20) - More than three dozen critics of Puget Sound Energy’s plans to build a liquefied natural gas production, storage and marine fueling depot on the Tacoma tideflats flooded a city council community forum last week. The project is in its final permitting stages. The proposal started after the utility landed a contract with Totem Ocean Trailer Express to provide its ships with cleaner-burning LNG. TOTE has since put those plans on hold, leaving the fueling plant without commercial customers.
“At this juncture, we do not have an exact date for when we will convert the Orcas (the class of ships TOTE would retrofit) to run on LNG but will keep you updated as our program planning progresses,” TOTE announced in a release this summer. The utility would, however, store LNG on the site for use during extreme cold weather. Critics say the $300 million plant would create undue safety conditions so close to populous areas.
Puget Sound Energy has said the risks are overblown, but has blocked the release of detailed safety reports which the company said show that any disaster would be contained within the site. Tacoma Mayor Marilyn Strickland at the meeting voiced her frustration over the company’s handling of community concerns. Meanwhile, the Puyallup Tribe continues to fight to have the plant’s shoreline environmental review reopened, asserting that the review did not properly address impacts on the waterway.
Italy’s Eni scores exploration success offshore Egypt
(New York Times; Oct. 19) - A drilling ship working about 120 miles off the Egyptian coast for Eni, the Italian oil company, bored into a giant trove of natural gas in July 2015 that turned out to be the largest discovery ever in the Mediterranean Sea and by far the largest by the global petroleum industry that year. The find, called Zohr, meaning “noon” in Arabic, was the source of enormous relief and elation at Eni, which had risked $70 million to drill in an area where Shell had previously drilled 10 wells without success.
Eni’s chief executive, Claudio Descalzi, let the drilling go ahead — despite serious misgivings inside the company — because some of his geologists were convinced that Shell and other rivals might have missed something big. “It was a very emotional moment,” Descalzi said. In a series of recent interviews, Descalzi and other Eni executives reflected on the ramifications of the discovery, which has reignited the industry’s flagging interest in Egypt and the entire eastern Mediterranean region.
Not only have they found as much as 30 trillion cubic feet of gas, but the rock is very porous and the fuel comes rushing out. Gas is expected to begin flowing to the Egyptian market by the end of next year. Zohr and earlier big finds in Mozambique, Ghana and Venezuela have rewarded Eni’s push into exploration. “We certainly would rank them as the best explorer of the majors on a five- to 10-year view,” said Andrew Latham, of U.K.-based consultants Wood Mackenzie. Zohr’s gas is contained in limestone, a first for the eastern Mediterranean, rather than the sandstone of previous discoveries.
Oil-price recovery to $50 starting to bring back some investments
(Wall Street Journal; Oct. 18) - The prospect of rising oil prices has the global energy industry considering a strategy that has been unthinkable for much of a two-year-long market slump: Making new investments. Big oil companies are moving ahead with new spending again, said BP CEO Bob Dudley on the sidelines of the Oil and Money conference in London Oct. 18-19. The company has taken final investment decisions on a handful of projects this year and is expected to approve more in 2017, he said.
“Investments are back,” Dudley said. “But it’s only going to be the very best.” Dudley’s comments highlight a pervasive sentiment among industry executives and government officials that there is light at the end of the tunnel as they grope through one of the industry’s darkest periods. For the past two years, the industry has been roiled by oil prices that collapsed to under $30 a barrel from 2014 highs of $114. Industry leaders say they have a sense of guarded hope as prices hover around $50 to $52 a barrel.
A rising oil price would allow the energy industry to make needed investments and restore some of the tens of thousands of jobs cut in the past two years. But OPEC and other oil producers must be careful, said Fatih Birol, executive director of the International Energy Agency. Pushing prices too high would boost output and put a brake on fragile oil demand, he said. However, warned John B. Hess, CEO of oil company Hess Corp., without new investments, the world’s balance of supply and demand would turn quickly from a glut of oil to a shortage in the future.