Yamal LNG says investments reach $15 billion for $27 billion project
(Reuters; Jan. 18) - Total investments in the Novatek-led Yamal LNG project have reached $15 billion, Leonid Mikhelson, Novatek chief executive, told Russian President Vladimir Putin on Jan. 18. Mikhelson reported that Chinese investors had provided about $5 billion and French partners about $3.7 billion, with about $2.3 billion from Russia's National Wealth Fund. “We … continue financing together with partners," he said of the $27 billion LNG project under construction in the Russian Arctic.
Yamal LNG shareholders are Novatek (60 percent), China National Petroleum Corp. (20 percent) and France’s Total (20 percent), with Novatek expected to close soon on the sale of a 9.9 percent slice of its 60 percent stake to a Chinese investment fund. Production is scheduled to start late 2017. U.S. sanctions on Russia have made it harder for Yamal LNG to line up financing.
Statoil sees demand growth in Europe for natural gas
(Reuters; Jan. 18) - Demand for natural gas is expected to grow further in Europe this year, particularly in Britain and Germany, the head of marketing for Norwegian oil and gas firm Statoil said, as countries seek to reduce carbon emissions. European gas industry association Eurogas said last October it expected European Union gas demand to have risen by 7 percent for the whole of 2015. Statoil's Tor Martin Anfinnsen said increased demand on the continent would help support the gas market.
"What you see in the U.K. now is a clear trend there at least for a swing up," Anfinnsen said. "Similarly, although not to the same extent, we believe, based on the government signals in Germany, that there is a potential for a swing up there as well as they strive toward reaching the emission levels." Germany has set a goal of cutting greenhouse gas emissions by 40 percent by 2020 compared to 1990 levels, and by 80 to 95 percent by 2050. Gas-fueled power plants produce about 50 percent fewer emissions than coal.
Norway’s gas exports in 2015 hit a record 3.826 trillion cubic feet, “a result of higher demand from Europe," the Norwegian Petroleum Department said last week. Statoil, which sells about 80 percent of its gas to Europe at prices linked to spot prices on the European gas hubs, plans to move away from oil-indexation completely. Statoil has come under pressure to move away from indexing gas to oil prices, as gas buyers want a pricing system that better reflects the market and higher availability of LNG imports.
LNG market could get worse in 2016
(Reuters columnist; Jan. 18) - In contrast to the carnage in crude oil markets, liquefied natural gas prices in Asia have enjoyed relative stability for the past three months, but it's unlikely the calm will persist much longer. Spot LNG prices in Asia ended last week at $5.60 per million Btu, about 28 percent below late November. In contrast, Brent crude oil has dropped even further — 46 percent from early October.
While both the oil and LNG markets would appear to suffer from excess supply and less than stellar demand growth, LNG has been trading with a lag to crude’s falling price. But the 2016 outlook for LNG looks just as bad, if not worse, than for crude. The oversupply in LNG, particularly in Asia, is set to increase dramatically in the next few months as new projects in Australia ramp up, along with the first U.S. export terminal in the Lower 48 states set to start deliveries — and four more U.S. plants under construction.
All that oversupply will hit an already weak market. Overall, it appears likely that LNG's period of calm relative to oil is poised to end, and spot prices should decline to at least match the plunge in crude, or perhaps even exceed it, especially as the lower-demand shoulder season starts with the end of the northern winter around March.
LNG sales in South Korea continue to decline
(Platts; Jan. 19) - South Korean state-owned Korea Gas Corp.'s LNG sales in December dropped 22.8 percent from a year earlier to 3.49 million metric tons, compared with 4.52 million tons a year earlier, the company said Jan. 19. It marks the biggest-ever decline since the company started gas sales in the local market in 1987. The company's monthly LNG sales have been on the decline almost nonstop since December 2014. KOGAS has an effective monopoly on LNG imports to the country.
KOGAS attributed the decline in LNG sales to higher coal-based and nuclear power generation, as they were relatively cheaper compared with LNG, as well as to the country’s economic slump. Milder winter temperatures in December also contributed to lower LNG use in power generation and heating, a KOGAS official said.
In December, LNG for power generation dropped 31.3 percent year on year to 1.29 million tons, while sales to retail gas distributors for households and businesses dipped 16.7 percent on year. It was the second consecutive year of decline. Last month, the Ministry of Trade, Industry and Energy said South Korea's LNG demand is forecast to fall 5.3 percent over the next 15 years due to a steep drop in consumption for power plants, which it said would not be offset by tepid growth in household and industry use.
China’s gas production and demand growth slows down
(Reuters; Jan. 19) - China's 2015 natural gas production rose by 2.9 percent from the previous year — the slowest growth in at least 10 years — official data showed Jan. 19, amid ample supply and weak domestic demand for the cleaner-burning fuel. Production reached 4.486 trillion cubic feet in 2015, the National Bureau of Statistics said. In 2014, production was 4.36 tcf, Reuters calculations derived from the official data shows. In 2013, natural gas production was 4.07 tcf.
Chinese gas consumption has been hit by slowing domestic economic growth and by state policies that kept prices high for most of the year, even as the global oil prices that underpin long-term gas supply contracts slumped to less than half their 2014 peaks. Still, gas consumption continues to grow, although at a slower pace: 3.7 percent in the first 11 months of 2015, after 5.6 percent in 2014 and 12.9 percent in 2013. China covers about two-thirds of its needs with domestic gas production; the rest is imported.
Gas imports grew 4.7 percent in the first 11 months of 2015 to 1.92 tcf, government data showed. Excess contracted LNG supplies from Qatar and Papua New Guinea as well as piped gas imports from Central Asia have left China with surplus fuel that it has tried to sell off abroad after domestic demand slowed. China's economic growth in 2015 was the slowest in 25 years.
LNG industry must adapt to new market conditions
(Reuters; Jan. 19) - Liquefied natural gas buyers and sellers need to embrace flexible trading practices, including cargo swaps, to cut costs and avert repeated painful boom-and-bust cycles, industry players said at a conference Jan. 19. A wave of new LNG supplies expected to hit the market with the launch of U.S. and Australian projects, weak demand and the high costs of bringing new production online could all combine for an uncertain future, they said.
"Everybody has to change their game," David Ledesma, an independent gas consultant and senior research fellow at the Oxford Institute for Energy Studies, told the European Gas Conference. "If they don't, they are going to get left behind." He added, "Buyers and sellers must work together or we will have boom-and-bust."
Importers are already seizing the chance to wring concessions from existing producers wary of losing market share. Global LNG buyers are seeking changes to the way long-term contracts are structured in the $120 billion annual trade, such as loosening restrictions on cargo diversions and reducing imports below agreed floors. And buyers must meet sellers half way when striking deals in an environment where future market uncertainty could make new projects too costly and risky, the industry players said.
Chinese buyer signs preliminary deal for Gorgon LNG deliveries
(Agence France-Presse: Jan. 19) – Chevron, builder of Australia's largest liquefied natural gas project, Gorgon LNG, has signed a preliminary agreement with China's ENN LNG Trading Co. to supply LNG from the West Australian project starting in 2018. Chevron said that once the deal is finalized, it expects to supply ENN with up to 500,000 metric tons of LNG per year over 10 years (about 24 billion cubic feet of gas per year).
ENN Energy Holdings operates in 146 cities with more than 11.3 million residential and 52,000 industrial and commercial customers. The company's LNG receiving terminal is under construction and expected to start operations by 2018. Gorgon, after delays and huge cost overruns, is expected to deliver its first cargo this year. The plant is designed to produce more than 15 million metric tons of LNG per year.
"Locking in customers is fairly important for these export projects," said ANZ senior commodity strategist Daniel Hynes. "The signing of this suggests there is still demand for LNG shipments into China despite the weak macro environment we're seeing at the moment." While the terms of the deal were not revealed, Hynes said pricing would be based off oil-linked price contracts.
Trinidad wants higher prices from its partners for LNG exports
(Argus; Jan. 20) - The government of Trinidad and Tobago plans to renegotiate its agreements with the shareholders of the country’s liquefied natural gas export project because the state is getting shortchanged, Energy Minister Nicole Olivierre said. Current commercial pricing arrangements for the country's LNG are tied to North America destinations, even though only 16 percent of its LNG exports now go to North America and the rest to higher-priced markets, Olivierre said at a Jan. 18 conference.
"With many of our commercial pricing arrangements tied to a U.S. destination, this country is realizing netbacks well below the actual market price applicable to the true destination of our cargoes," she said. "The only conclusion that can be drawn is that the contractual arrangements for the marketing of LNG are not now working in the best interest of Trinidad and Tobago. … What has happened to the arrangement where the upside was to be shared 50/50 between the LNG partners and the government?”
The plant, with liquefaction capacity of 14.8 million metric tons a year, is owned by BP, BG, Shell, a Chinese fund and Trinidad's state-run gas company. "The 2018 expiration of Atlantic Train 1 LNG contracts is certainly an opportunity for us to begin to recalibrate the LNG industry into one that brings greater benefit to the state,” Olivierre said. The plant had shipped about 70 percent of its output to North America a decade ago, but U.S. shale gas production cut the number to 16 percent by 2015. South America now takes 62 percent of Trinidad LNG, with the rest going to Europe, the Mideast and Asia.
Canadian fisheries agency says LNG terminal would not ruin habitat
(Globe and Mail; Canada; Jan. 17) - Federal scientists say a proposed liquefied natural gas export terminal near Prince Rupert, B.C., poses a low risk to the environment, a crucial ruling that sides with Pacific NorthWest LNG’s contention that its project won’t ruin an ecologically sensitive site. The consortium led by Malaysia’s state-owned Petronas wants to build an LNG terminal on Lelu Island, located next to Flora Bank — a sandy area with eelgrass beds that provide critical habitat for juvenile salmon.
Pacific NorthWest wants to build a suspension bridge and pier to carry a pipeline from Lelu Island to a tanker dock. “The effects of the marine structure on fish and fish habitat have been categorized as having a low potential of resulting in significant adverse effects,” Fisheries and Oceans Canada said in a letter last week to the Canadian Environmental Assessment Agency. The agency is expected to issue a final decision by the spring on the controversial project. Its review started in April 2013, but encountered a series of delays as the regulator asked the consortium for more information.
The conditional support from federal scientists bodes well for Pacific NorthWest, which faces opposition from environmentalists and the Lax Kw’alaams First Nation. The fisheries agency outlined recommendations to reduce the risk of damaging Flora Bank, including monitoring eelgrass beds to ensure the area remains stable and revising construction methods for the bridge and pier because porpoises are sensitive to underwater noise. The project hopes to win approval and start construction this year.
Opponents challenge federal scientists over LNG project site in B.C.
(Globe and Mail; Canada; Jan. 18) - B.C. environmentalists are upset that federal scientists have sided with a consortium’s proposal to build a liquefied natural gas export terminal at a coastal site. The scientists from Fisheries and Oceans Canada agree with Pacific NorthWest LNG’s studies that the terminal would have little impact on Flora Bank, a sandy area with eelgrass that nurtures juvenile salmon. Flora Bank is next to Lelu Island, site of the proposed export terminal in front of Prince Rupert, B.C.
Fisheries and Oceans Canada said a letter last week to the Canadian Environmental Assessment Agency that it agrees with the developer: The project poses a low risk of causing significant harm to the bank in the Skeena River estuary. But Greg Horne, with the Skeena Watershed Conservation Coalition, said a study commissioned by the Lax Kw’alaams First Nation isn’t being given the attention it deserves. The study warns the project would disrupt the system of waves and currents that holds Flora Bank in place.
The consortium, led by Malaysia’s state-owned Petronas, wants to build a suspension bridge and trestle to carry a pipeline from Lelu Island to a dock for loading LNG tankers bound for Asia. “(The analysis) … has shown that if they build the trestle, it will block the incoming waves, which will lead to Flora Bank eroding out to sea and being destroyed,” Horne said. The consortium is aiming to start construction later this year, if the federal environmental assessment agency grants approval.
Calgary company proposes half-billion-dollar propane export terminal
(Calgary Herald; Jan. 20) – Calgary-based AltaGas has proposed a half-billion-dollar propane export terminal on Ridley Island near Prince Rupert, B.C. Ridley Terminals has agreed to sublease lands it leases from the Prince Rupert Port Authority so that AltaGas can build, own and operate the terminal, AltaGas said Jan. 20. The company said the agreement allows it to start the regulatory phases of the project intended to establish new Asian markets for some of Western Canada’s plentiful supplies of propane.
“We anticipate this facility will be the first to export propane from British Columbia’s West Coast,” said David Cornhill, CEO of AltaGas, a gas, power and utility business. The facility would ship up to 1.2 million tonnes of propane per year (almost 14 million barrels) from a site with a marine jetty and deep-water access to the Pacific Ocean. Propane from B.C. and Alberta would be delivered to the site on CN Railway’s network.
Construction is expected to cost between $400 million and $500 million. AltaGas said it will reach a final investment decision this year, with first exports targeted for 2018. Preliminary engineering has been completed and a front-end engineering and design study has begun, the company said. AltaGas owns or has an interest in six large gas processing facilities in British Columbia and Alberta that produce propane, and operates a similar propane export facility in Ferndale, Wash., just south of the Canadian border.
Statoil cuts costs in half for offshore Arctic oil project
(Bloomberg; Jan. 19) - Norway’s Arctic ambitions just got a $7 billion boost from Statoil, which was able to cut in half its expected development costs for the Johan Castberg field in the Barents Sea. The decision comes as welcome news for an industry that’s struggling with a deep plunge in oil prices. Castberg holds as much as 650 million barrels of oil. The find is located in water about 1,200 feet deep, 65 miles north of the Snohvit gas field that supplies Norway’s only liquefied natural gas export plant.
Statoil said the project will proceed after it managed to lower the estimated cost to 50 billion to 60 billion kroner ($7 billion) from an earlier estimate of 100 billion kroner. In part, the 75 percent slump in oil prices over the past 18 months has forced industry suppliers to cut their rates. In addition, the partners, including Norway’s state-owned Petoro and Italy’s Eni, have decided to use a floating production, storage and offloading facility. A final investment decision is planned for 2017 and possible start-up in 2022.
“This is a project that’s starting to get close to what I would call an attractive project,” CEO Eldar Saetre said, adding that Statoil will seek to make the project even cheaper. The decision breaks a string of delays for the project that has suffered from high costs, a tax increase and, most of all, a plunge in oil prices. It goes against a trend of cancellations of energy projects worldwide, not least in the high-cost Arctic, where Statoil and others have abandoned exploration plans from Alaska to Greenland.
World leaders told there is ‘too much oil’ for price recovery in 2016
(Bloomberg; Jan. 20) - The first mantra of the oil crisis was “lower for longer.” Then “lower for even longer.” Now, oil executives are starting to talk — or rather, whisper — about a new nightmare scenario: “A lot lower for a lot longer.” Oil executives, policy makers and bankers reported in the first days of the World Economic Forum in Davos, Switzerland, that an oil-price recovery will remain elusive in 2016 as major producers keep pumping and China’s fuel appetite slackens.
And they fret that prices could take another hit as Iranian crude freed from sanctions flows into the market. “It is the third year in a row we have more supply than demand,” said Fatih Birol, executive director of the International Energy Agency. “Prices will be still under pressure. I don’t see any reason why we have a surprise increase in the price in 2016.” Things won’t get better until markets have weathered the “supply shock,” said Tony Hayward, chairman of Glencore, one of the world’s largest trading houses.
Quite simply, there’s “too much oil,” Hayward said. Unprecedented cutbacks in spending on new supply — a 16 percent investment reduction this year will follow last year’s 20 percent cut — is setting the stage for a recovery, but it will be 2017 before it happens, Birol said. Still, crude won’t recover to levels seen during the boom years, said Daniel Yergin, vice chairman of consultants IHS. Prices will probably be a “good deal higher than they are today” in the second half of 2016, but “not $100, not $70, not $60.”
Oil-price fall pushes some Canadian producers to shut in production
(Bloomberg; Jan. 20) - Canadian oil companies face another round of output cuts as the price of crude sinks below break-even levels for many producers. Operating in one of the most expensive regions in the world, producers are cutting spending or, in the worst cases, halting production. The price rout is compounded by concerns over slowing growth in China and emerging economies as well as interest rates and equity markets, said Martin King, vice president of research at First Energy Capital Corp. in Calgary.
“The latest price moves would seem to suggest that supply shut-ins are needed and that future capex should be trimmed to the bone and beyond,” King said in a note to clients. The Canadian division of China Petroleum & Chemical Corp., also known as Sinopec, may shut in production, Brian Tuffs, head of the Beijing-based company’s Canadian operations, said at an industry conference in Calgary on Jan. 19.
Credit Suisse chief investment officer Michael Strobaek expects crude to reach a low of $25 a barrel. Glencore chairman Tony Hayward, formerly BP’s chief executive officer, said current low prices are here for some time. In Canada, “we can clearly see that no companies are able to cover all cash outflows at current oil prices,” National Bank of Canada analysts Kyle Preston, Dan Payne and Brian Milne said in a note. Oil sands operations are unlikely to be shut in because of the high costs of restarts, King said.
Flint Hills offers $1.50 a barrel for low-grade, high-sulfur N.D. crude
(Bloomberg; Jan. 17) - Oil is so plentiful and cheap in the U.S. that at least one buyer says it would pay almost nothing to take a certain type of low-quality crude. Flint Hills Resources, the refining arm of billionaire brothers Charles and David Koch’s industrial empire, said it offered to pay $1.50 a barrel Jan. 15 for North Dakota Sour, a high-sulfur grade of crude, according to a corrected list of prices posted on its website Jan. 18.
It had previously posted a price of minus $0.50. Flint Hills later said the negative 50 cents price was a mistake. The crude is down from $13.50 a barrel a year ago and $47.60 in January 2014. While the near-zero price is due to the lack of pipeline capacity for a particular variety of ultra-low quality crude, it underscores how dire things are in the oil patch. U.S. benchmark oil prices have collapsed more than 70 percent in the past 18 months and fell below $30 a barrel for the first time in 12 years last week.
High-sulfur crude in North Dakota is a small portion of the state’s production, at less than 15,000 barrels a day, said John Auers, executive vice president at Turner Mason & Co. in Dallas. The output has been dwarfed by low-sulfur crude from the Bakken Shale in the western part of the state, which has grown to 1.1 million barrels a day in the past 10 years. Different grades of oil are priced based on their quality and transportation costs to refineries.