FERC issues final EIS for Texas LNG project, owned by Exxon/Qatar
(Beaumont Enterprise; Texas; July 29) - Golden Pass obtained its final environmental impact statement from federal regulators July 29, a significant step in its quest to secure government approval to add natural gas liquefaction and export capabilities to its underused LNG import terminal in Sabine Pass, Texas, across the waterway from Louisiana. The environmental clearance boosts the prospects for the $10 billion project. The company said it is on track to obtain full federal clearance by next year.
The Federal Energy Regulatory Commission concluded the project would result in "some adverse environmental impact," but noting it "would not be significant with implementation of Golden Pass' proposed mitigation and the additional measures recommended." For example, it notes that construction would impact about 388 acres of wetlands, while operation would require filling in 376 acres, according to the EIS. The project would create 721 acres of new wetlands in a wildlife manage area in Texas.
Golden Pass, jointly owned by Qatar Petroleum and ExxonMobil, has sought federal approval to expand its LNG import facility at Sabine Pass into an export facility since 2013. Golden Pass is aiming to start exporting LNG by 2021 and ramping up to full capacity of 15.6 million tons per year by 2022. Golden Pass LNG, which has spent more than $200 million readying the project, won't make a final decision on whether to build until it gets federal approval, which might not happen until next year.
Indian LNG importer wants to renegotiate lower price for Gorgon LNG
(The New Indian Express; July 31) - Emboldened by successful renegotiation of its liquefied natural gas supply deal with Qatar, India is trying to do an encore and lower the price of liquefied natural gas it is contracted to buy from Australia's Gorgon project. India’s leading LNG importer, Petronet, in 2009 signed a 20-year deal for 1.44 million metric tons of LNG a year from Gorgon at 14.5 percent of prevailing oil prices (1 million Btu gas at 14.5 percent of the price of a barrel of oil, which has about six times the Btu value). The indexation was one of the highest in the world, says India’s Oil Ministry.
At the ministry's insistence, Petronet has written to ExxonMobil, a partner in Gorgon LNG, for reworking the price. Even though oil prices have fallen, a source said, “as a matter of principle, the indexation should be lowered,” noting that other LNG contracts around the world are priced at 12 to 12.5 percent of oil. At current global oil prices of about $45, Gorgon LNG would cost Petronet about $6.50 per million Btu, while gas is available on in market-priced spot sales at $5 to $6.
Adding India’s Customs duty, shipping costs and regasification expenses, the landed price of Gorgon LNG will be closer to $9 per million Btu at the Kochi port where it is supposed to be delivered. Deliveries are expected to start late this year. Chevron, Shell and Exxon are the major partners in Gorgon. Sources said the case of renegotiating the Gorgon deal has strengthened after Petronet last year successfully got RasGas of Qatar to lower the price for LNG it supplies under a 25-year long term.
Tokyo Electric profits down; Japan’s power usage lowest since 1988
(Bloomberg; July 28) - Tokyo Electric Power Co. Holdings Inc., Japan’s largest utility and operator of the wrecked Fukushima Dai-Ichi nuclear plant, said first-quarter operating profit plummeted 37 percent as sales declined amid faltering demand and new entrants into Japan’s power market. Revenue fell about 18 percent as the company’s electricity sales dropped and rates were automatically lowered by the nation’s price adjustment system. The system adjusts monthly electricity rates for each utility based on a three-month average of import prices for LNG, crude oil and coal.
Japan’s regional utilities are getting squeezed by new entrants after the country liberalized its retail power market in April, allowing consumers to choose their electricity providers for the first time. TEPCO hopes to boost its profits by expanding its domestic gas sales when the gas market fully opens up next year, and increasing its foreign investments and restarting its operable nuclear reactors. Power usage in Japan dropped last year to the lowest level since 1998 as households and businesses conserved electricity amid a stagnant economy and shrinking population.
Japanese utilities lose customers to deregulation
(Platts; July 29) - Japan's Tokyo Electric Power, Chubu Electric and Kansai Electric saw up to 3 percent of their household users switch to other power providers after the country's retail electricity market became fully liberalized in April, the three utilities said this week. Attention has been focused on the progress of deregulation and its impact on Japanese electricity utilities' use of fuels, including liquefied natural gas.
About 760,000 users within the TEPCO Power Grid's service area requested to switch as of June 30, according to the Organization for Cross-regional Coordination of Transmission Operators, Japan. This represents about 3.3 percent of the utility's total household users of 23 million as of March. As for Kansai Electric, about 260,000 switching requests were made by June, against the utility's 11 million household users. Similarly, Chubu Electric saw around 80,000 switching requests made by June.
Exxon LNG project in B.C. receives 40-year export license
(The Mirror; Dawson Creek, BC; July 29) - A liquefied natural gas export facility that's being jointly pursued by ExxonMobil and its Canadian affiliate Imperial Oil on July 28 received a 15-year extension to its export license from Canada’s National Energy Board. The project is proposed for Tuck Inlet, a deep-water port near Prince Rupert, B.C. The 15-year extension to the project’s export authorization is allowed under 2015 legislation. The previous limit had been 25 years, which the project received in 2013.
The project, known as WCC, for West Coast Canada, is the second LNG license to receive a 15-year extension. The Shell-led LNG Canada project, proposed for Kitimat, B.C., gained approval for its 15-year extension in January. The Petronas-led Pacific NorthWest LNG export terminal, proposed for near Prince Rupert, has applied but has not yet received approval to extend its 25-year permit to 40 years.
Exxon and Imperial said the longer export authorization will help the project better compete for customers, providing greater certainty of supply. Both Exxon and Imperial hold drilling rights in northeastern British Columbia. The companies have not publicly stated a definitive timeline for project development, an investment decision or first gas. The WCC LNG project is one of more than a dozen proposed for B.C.’s West Coast.
Exxon in talks for minority stake in Mozambique gas discoveries
(Bloomberg; July 28) - ExxonMobil is in advanced negotiations with Italy’s Eni over acquiring a minority stake in gas discoveries off Mozambique, according to two people with knowledge of the talks. ExxonMobil CEO Rex Tillerson discussed the plan with Mozambique President Filipe Nyusi last week in Maputo, the African nation’s capital, according to one of the sources. The U.S. oil major’s participation would potentially accelerate development of one of the world’s largest liquefied natural gas projects.
Exxon is also in talks with Anadarko over acquiring a stake in the adjacent Area 1 in Mozambique’s offshore Rovuma Basin, sources said. Exxon, Eni and Anadarko declined to comment on the discussions. The talks underline Exxon’s focus on gas assets after the company last week agreed to acquire explorer InterOil Corp. for as much as $3.6 billion to add gas discoveries in Papua New Guinea, where Exxon opened an LNG plant in 2014.
Eni CEO Claudio Descalzi said May 12 the company is in talks on selling a stake in its Mozambique discovery and expects to reach a final investment decision on a liquefied natural gas project this year. Exxon is already focused on Mozambique after winning three exploration licenses in October for offshore blocks to the south of the Anadarko and Eni discoveries. It has teamed up with Qatar Petroleum to look at assets in the country, people familiar with the plans said earlier this month. Exxon also has a working interest in Statoil’s Block 2 in Tanzania, north of the Rovuma Basin.
Canadian fisheries regulator says LNG plant poses low risk to salmon
(Globe and Mail; Canada; July 28) - Fisheries and Oceans Canada has told the federal environmental regulator that Pacific NorthWest LNG’s plan to build a liquefied natural gas terminal near Prince Rupert, B.C., poses a low risk to juvenile salmon habitat. Environmentalists and some First Nations argue that the construction activities would devastate Flora Bank, a sandbar with eelgrass that nurtures young salmon. The LNG joint venture, led by Malaysia’s state-owned Petronas, is seeking to build an export terminal on Lelu Island, located next to Flora Bank in the Skeena River estuary.
Fisheries and Oceans said that based on its analysis of scientific studies provided by Pacific NorthWest, potential threats to salmon are manageable. “Construction-related impacts to fish and fish habitat can be mitigated and subsequently has a low probability of resulting in significant adverse effects to fish and fish habitat,” the federal department said in a recent letter to the Canadian Environmental Assessment Agency, which is reviewing the project’s application for its recommendation this fall to the federal Cabinet.
The Petronas-led consortium believes that a suspension bridge and trestle-supported pier — carrying a pipeline from Lelu Island to a berth for LNG carriers on Agnew Bank — would protect juvenile salmon habitat on Flora Bank and harbor porpoises nearby. Environmentalists, however, said the pier in particular would threaten to disrupt a complex system that effectively holds Flora Bank in place. The federal Cabinet is expected to decide by early October whether to approve Pacific NorthWest LNG.
Hong Kong could join list of LNG importers
(Bloomberg; July 29) - Hong Kong is thirsty for cheap liquefied natural gas, and the two companies that supply power to Asia's third-richest city are jointly conducting a study to build an LNG import terminal that could be anchored off the coast. Units of Power Assets Holdings, owned by billionaire Li Ka-Shing, and CLP Holdings, owned by fellow Hong Kong billionaire Michael Kadoorie, are aiming to have the country’s first LNG terminal operating by late 2020, according to a CLP spokesman.
Offshore terminals are among the hottest assets in energy. Known as floating storage and regasification units, they allow buyers fast access to an oversupplied LNG market that has pushed down spot prices in Asia by more than half since October 2014. Energy companies adding LNG production plants in places like Australia and the U.S. have helped push down the price of spot LNG in Singapore from more than $14 per million Btu in October 2014 to $5.65 this week. Spot prices will fall to $3.80 by 2018 as more production capacity comes online, BMI Research said in a July 12 research note.
Greater LNG imports could help Hong Kong reduce its reliance on coal and reach its goal of increasing the proportion of gas in its energy mix to about 50 percent by 2020. The companies are conducting an environmental impact assessment, which will take 12 to 18 months. They would then apply for government approval and make a final investment decision. Hong Kong generated about 53 percent of its power from coal as of 2012, compared with about 22 percent each for nuclear and natural gas.
Flexibility of U.S. LNG contracts a big change in global market
(Bloomberg; July 27) - Shale drillers from Pennsylvania to Texas flooded the U.S. with so much natural gas over the past decade that prices slid to a 17-year low. Now they’re going global, with the potential to upset markets from London to Tokyo. The U.S. began shale gas exports by sea this year and is projected by the International Energy Agency to become the world’s third-largest liquefied natural gas supplier in five years. Gas will challenge coal at European power plants and become affordable in emerging markets.
LNG became the world’s second most traded commodity after oil last year and demand will keep growing, Goldman Sachs said. U.S. gas is adding to the glut triggered by new Australian supply and weaker Asian demand. U.S. shale gas also is having an outsized impact on how LNG is sold, prompting spot trading in lieu of long-term contracts. “The U.S. clearly changed the picture,” said Costanza Jacazio, with the International Energy Agency. “It’s going basically from zero to the third-largest LNG capacity holder in the space of five years and it brings a new flexible dimension to the market.”
With supplies growing, some Asian nations are contracted to buy more than they can consume, leaving surpluses to be sold. While U.S. supply is still relatively small, it’s having an impact because the contracts are flexible. Australia and other suppliers have long-term agreements to send gas to specific buyers only, such as Japan and China. Asian buyers have contracted for more than half of the U.S. supply, but the contracts allow them freedom to ship the fuel to anywhere in the world, encouraging spot trading.
Gazprom wants to help China create more demand for natural gas
(Platts; July 25) - Russia's Gazprom is continuing its efforts to push for increased gas demand consumption in China as part of its plans for supplying the country with gas by pipeline after 2018. The prospects for Chinese gas demand growth are not as strong as they were a few years ago, which has dampened Beijing's appetite for increasing its options for Russian gas imports.
Now Gazprom is pushing to help create more demand, signing last month a new agreement with state-owned China National Petroleum Corp. on building gas-fired power stations in China. At the end of last week at a meeting in St. Petersburg, the two sides approved steps needed to implement the deal, which also includes cooperation on gas storage in China. Gazprom also said it wants to help boost the use of gas as a fuel for vehicles in China.
Gazprom looks into small-scale LNG plants to serve China
(OilPrice.com; July 28) - Gazprom is looking into constructing small-scale liquefied natural gas plants in eastern Russia to serve the Chinese market. Igor Maynitskiy, head of the LNG export division for Gazprom Exports, said in the latest issue of Gazprom’s corporate magazine that the company is carefully examining development of the small-scale LNG market in China. If the market is promising, Gazprom could build small-scale LNG projects in Russia’s Far East, which shares a border with China.
According to Gazprom’s website, the Far East region is vital to the company’s “strategic interests.” Gazprom has no small-scale, export-oriented LNG plants in the Far East. It’s only LNG project in the region is the large-volume LNG export plant on Sakhalin Island.
Sinopec counting on profits from shale gas production
(Wall Street Journal; July 31) - A global natural gas glut has slowed the U.S. shale boom, but in the Yangtze River town of Fuling, a Chinese one is just starting. China’s state-owned energy companies, their profits decimated by the global commodities bust, are pushing ahead with billions of dollars in new investment to extract gas from shale. Leading the charge is China Petroleum & Chemical Corp., or Sinopec, which aims to double domestic gas production within five years.
Sinopec’s push amid a global oversupply of gas presents an unpleasant surprise for an industry in turmoil. If it succeeds, China’s need for imported liquefied natural gas might dwindle — potentially jeopardizing tens of billions of dollars in planned investment. China has huge shale gas reserves, but challenges from complicated geology to an inadequate pipeline network long made tapping them elusive. But with stifling pollution in many cities, gas offers a cleaner alternative to coal.
Much of the planned expansion will come from the Appalachia-like region near Fuling, in central China, where underground rock formations hold some of the biggest reserves of shale gas outside North America. Production in Fuling will top 175 billion cubic feet this year, up from 105 bcf in 2015. By 2017, Sinopec aims to reach almost 250 bcf a year. The shale push is helped along by government subsidies and political support. Sinopec touts gas as crucial to its future as its aging oil fields become more expensive to pump.
Lack of New England pipeline capacity keeps natural gas prices high
(Canada Free Press; July 26) - New Englanders have a problem. They are using more and more natural gas for electricity generation and home heating. In fact, they are the only region of the country where natural gas is increasing as a heating fuel. They can get inexpensive U.S. natural gas by building pipelines or they can buy imported expensive liquefied natural gas from the Caribbean to fuel their generators and homes. Unfortunately, anti-pipeline activists are winning the fight.
Kinder Morgan had to scrap its proposed $3.3 billion Northeast Energy Direct project in April due to a lack of customers. The Constitution Pipeline that would bring Marcellus gas from Pennsylvania is being held up because New York denied it a water permit, citing concern about contamination of the city’s supply. As a result, three or four times a month, giant ships are escorted through Boston Harbor, delivering LNG from Trinidad. The terminal supplied 11 percent of the region’s gas in January‚ the most since 2012.
Gas-fired plants are now providing over half of the Northeast’s electricity, up from 15 percent in 2000. Even during a normal winter, New Englanders pay more for gas than elsewhere. For example, gas for next January via Spectra Energy’s pipeline now costs $8.46 per million Btu, compared with $3.16 for Pennsylvania Marcellus shale gas. The high prices are due to a lack of infrastructure to move the gas the 300 miles, while environmental protests are hindering an expansion of pipeline capacity to New England.
U.S. oil companies may wait for $60 oil before return to drilling
(Bloomberg; July 28) – For U.S. drillers, $60 is the new $50. Earlier this year, oil and gas companies facing the worst slump in a generation said they’d need crude to reach $50 a barrel before resuming drilling. This week, despite higher prices and lower costs, the industry has raised the bar, signaling it will take $60 or better before meaningful production can resume. “The industry doesn’t want to ramp things up until they are fairly confident prices will hold up,” said Brian Youngberg, energy analyst at Edward Jones. “The industry has learned that it needs to get away from this boom-bust scenario.”
Anadarko CEO Al Walker is one energy industry leader waiting for that $60 mark. "The more we feel comfortable about that sustained $60 price environment, the more likely you will see us increase capital," he said July 27. Hess Corp. has cited the same tipping point before it adds rigs. Oil companies remember last year’s false starts, when prices rose and drillers began to resume activity, only to see oil crater again as too much supply came online, Youngberg said.
With banks more cautious about lending to drillers, “the pressure is on for these companies to improve their balance sheets, so you can’t just ramp things up too quickly,” he said. "We’re not going to get excited and rush out there and add rigs every time the price bumps up," said Alan Hirshberg, ConocoPhillips executive vice president of production. Below $55 a barrel, about half of U.S. production is “uneconomic," said Fadel Gheit, an Oppenheimer & Co. energy strategist in New York. Among drillers, “there is a lot of hope, but hope is not a plan," Gheit said July 29 on Bloomberg TV.