In the short term, the minimum levels for LNG are defined by the global LNG availability and the recent history for UK LNG deliveries.
“Indications are that LNG availability is likely to be high, at least until the early 2020s. New liquefaction projects have come on line this year, including four in Australia and the first US export terminal, Sabine Pass.
“There is much speculation as to how much LNG will flow from the US to European markets where it will compete with LNG from Qatar, as well as gas from Norway and Russia,” the report said.
“For continental imports, through the IUK and BBL interconnectors, the minimum supply has been defined by contractual volumes and our assessment of any additional flows which could be expected under the conditions in the scenarios,” it added.
“In all scenarios there is enough infrastructure capacity for the generic import to be all LNG or all continental gas without the need for any new capacity to be built,” it added.
National Grid said its “Consumer Power” natural gas demand scenario is in the middle of the range of market outcomes from 2020 onwards.
LNG is low hanging fruit for any foreign company wanting to tap US gas market. It is for sale if the price is right.
Japan said the price of spot liquefied natural gas cargoes imported into the country in June amounted to $4.50 per million British thermal units, down $3.10 per MMBtu compared with the $7.60 per MMBtu paid in the same month a year ago.
However, the spot price edged up in June compared with the $4.30 per MMBtu companies said they paid in the previous month of May.
The numbers come from the commerce division of the Japanese Ministry of Economy, Trade and Industry and are only issued if a minimum number of two trades are recorded.
They show that Japanese companies are paying half the price for spot cargoes than they are for long-term contract shipments that are linked to the lower oil price and still costing between $8.50 per MMBtu and $9.50 per MMBtu.
The ministry emphasizes that “spot LNG” refers to fuel traded on a cargo-to-cargo basis and does not mean shipments under contracts on a short-term, medium-term or long-term basis.
Prices prior to averaging are all converted into an equivalent Delivered Ex-Ship (DES) basis whereby the seller carries the cost of the shipping.
Japan’s overall LNG imports declined 4 percent in May in the second successive monthly drop as the world’s largest LNG importer opted for coal instead, with shipments of that commodity surging 44 percent.
The May deliveries of LNG to Japan amounted to 5.52 million tonnes compared with 5.75MT in May 2015, according to the trade statistics from the Ministry of Finance.
While LNG imported by Japan for gas-fired power generation and city-gas distribution dropped, the shipments into the country of thermal coal for generating electricity jumped 44 percent to 8.60MT in May compared with 5.98MT in the same month of 2015, even
Brent Crude (bbl) - $46.90
LNG Journal European Spot (MMBtu) Indicator - $4.60
Henry Hub (MMBtu) - $2.85
NYMEX Gas (MMBtu) - $2.76
LNG Journal East Asian Delivered LNG Indicator - $8.90
Chevron has halted loading operations at the giant Gorgon LNG development for the second time this year, following what was claimed to be ‘a minor gas leak’.
Workers at the Barrow Island plant off Australia’s northwest coast, were evacuated.
Chevron said that it will repair the low-pressure flare system and acid-gas removal unit before restarting production this week, Bloomberg reported. Chevron still plans to load an LNG cargo in the coming days, the company said.
One of the largest developments in Australia’s history faced delays, cost overruns and labour unrest during construction. It then started exports to customers in Asia during the worst energy slump in a generation, Bloomberg said.
In April, output was temporarily halted only two weeks following its first shipment, claiming a malfunction in the propane refrigerant circuit, used to cool gas supplied to the plant.
LNG production restarted last week, Chevron said. The 165,000 cu m LNGC ‘Marib Spirit’ had been anchored off Barrow Island since 26th June, according to ship-tracking data compiled by Bloomberg, confirmed by MarineTraffic.
However, she subsequently loaded a cargo and sailed on 4th July bound for Indonesia being only the second cargo shipped out of the plant since it was opened.
The $54 bill plant was closed in April, 2016 following technical problems, shortly after starting up first production. Only one cargo was shipped
Northwest Europe is evolving beyond being ‘a market of last resort’ for US LNG, as rising gas prices on the forward curve are propping up the economics and profit margins for shipping cargoes across the Atlantic. Just short of 70 mtpa nameplate capacity will be commissioned by 2019 from five US liquefaction projects. Over in France, the Dunkirk regas terminal awaits its commissioning cargo by July 8.
“EDF has managed to find an LNG supplier while guaranteeing a competitive price,” Dunkerque LNG Commercial Director Christophe Liaud said, without disclosing the seller or the origin of the gas. The French state-owned utility jointly developed the 13 Bcm/a Dunkirk regas terminal at a cost of 1 billion euros ($1.13bn) with Total and Fluxys, the Belgian TSO which also owns the Zeebrugge LNG terminal.
“The ship will call at the LNG terminal jetty for seven days [rather than the normal 24 hours]. As the equipment will still be at ambient temperature, the LNG will need to be unloaded much more slowly than normal so the process gradually enters its cool state,” Liaud explained, adding the gas quality of the imported LNG will also be checked once the tanker berthed. “A second ship will follow in August to complete testing.”
Forward gas prices in Europe are on the rise, with the NBP winter’16/17 contract up 8% in late June on news about an immediate 42-day restriction on injections into Rough, Britain’s biggest gas storage facility. Should prices stay at, or above $6.41/mmBtu, this would allow US LNG exporters to cover for feedgas – typically around 115% of Henry Hub prices – and pay for liquefaction tolling fees, with $2.25/mmBtu agreed between Cheniere and Shell for their first offake accord from Train 1 at Sabine Pass.
Moreover, current NBP forward prices would also pay for the cost of shipping the LNG over from the US Gulf coast to regas terminals in Britain, or France and the Netherlands for that matter.
Spreads between forward gas prices at the US bellwether gas trading hub and the British NBP or the Dutch TTF give some insight into the profitability of future exports as all contractual cargoes lifted from Sabine Pass are linked to the Henry Hub. Margins will ultimately decide how much LNG will head across the Atlantic, or rather through to Asia through the enlarged – and just opened – Panama Canal.
Yet, despite more favourable economics for shipping US LNG to Europe – it is shipped to destinations like Bahia Blanca in Argentina, Hazira in India or Petrobras’ regas terminals in Brazil that offer US LNG cargoes an even greater return.
US gas prices rebound as shale gale slows
Shale gas production has stopped rising as US developers pulled the plug on costs amid sustained low oil prices. Hence, the supply surplus on America’s domestic market that existed since December 2014 is gradually declining and forecast to move into deficit by November 2016, according to EIA’s latest Short Term Energy Outlook (STEO).
The supply glut has seen Henry Hub spot prices hovering around record lows of $1.99/mmBtu in Q1-2016, but analysts at the EIA anticipate gas prices will rebound to at least $3.31/mmBt by the end of 2017. More bullish traders and analysts see these projections as “far too cautious”, stressing that Henry Hub spot prices averaged at $4.05/mmBtu during the last supply deficit from December 2012 through to November 2014.
Wildcat drillers across the US and Canada are feeling the pinch, and some have already gone out of business; so analysts like Art Berman doubt that they can return to gas drilling at the $2.75 price levels that EIA forecasts for November 2016. He doubts that the oil-field service industry will be able to reassemble drilling equipment and gather crews in less than six to twelve months after demand rebounds.
Reassessing EIA forecast of $3.10/mmBtu gas prices in January and February 2017, and $3.31/mmBtu in December 2017, Berman said he considered “comparative inventories” which result in an overall 15% higher forecast than EIA’s. His peak prices projections are even 20-30% higher, suggesting winter prices in the $4-range for 2016 and 2017.
Should Henry Hub gas prices surge before a similar strengthening of equivalent NBP prices, this might cast a shadow on the profitability of US LNG exports to Europe. Other destinations, like the Americas and emerging Asia would regain attractiveness. Tankers from the US Gulf Coast might have to queue at the expanded Panama Canal, unless more natural gas (and gas liquids) gets used domestically, e.g. by the growing US petrochemical industry and electric utilities.
Spain is scheduled to receive its first liquefied natural gas cargo in July from the new US Gulf Coast export plant at Sabine Pass in Louisiana, with the shipment to be unloaded at the Reganosa import facility at the Port of Ferrol.
The 138,114 cubic metres capacity vessel “Sestao Knutsen” is set to arrive on July 22 at the import terminal, located in the region of Galicia in northwest Spain, according to shipping data.
The first US Gulf Coast cargo was delivered to Brazil in February 2016 and others have been shipped to South America, including Argentina and Brazil, and one has gone to India.
Since it is a small floater built in a shipyard fast. Can be moved like a gas station.
Trinidad has 4 trains and been shipping for years. Same process built by Bechtel.
Import terminals being built more of a future market. Chenier should sell competitors are the majors or Qatar.
Sentiment: Strong Buy
The newly expanded Panama Canal will be able to accommodate 90 percent of the world's current LNG carrier fleet with cargo-carrying capacity up to 3.9 billion cubic feet of natural gas and voyage times cut by up to two weeks in shipping US LNG to Japan, South Korea and Taiwan, the US Energy Information Administration has noted.
Prior to the expansion, which was inaugurated and opened for business on June 26, only 30 of the smallest LNG tankers (6 percent of the current global fleet) with capacities up to 0.7 Bcf could transit the Canal.
“The expansion has significant implications for LNG trade, reducing travel time and transportation costs for LNG shipments from the US Gulf Coast to key markets in Asia and providing additional access to previously regionalized LNG markets,” the EIA said.
A transit from the US Gulf Coast through the Panama Canal to Japan will reduce voyage time to 20 days, compared to 34 days for voyages around the southern tip of South America or Southern Africa, or 31 days if transiting through the Suez Canal.
“The wider Panama Canal will also considerably reduce travel time from the US Gulf Coast to South America, declining from 20 days to 8-9 days to Chilean regasification terminals, and from 25 days to five days to prospective terminals in Colombia and Ecuador,” the EIA report said.
For markets west of northern Asia, including India and Pakistan, transiting the Panama Canal will take longer than either transiting the Suez Canal or going around the southern tip of Africa.
Cramer has adopted Hillary line on HYDRO CARBONS. He was a great admirer of the
former CEO and never mentioned his looting of the company. It broke his heart when Carl
Our Asia-Pacific editor
Japanese liquefied natural gas imports declined 4 percent in the second successive monthly drop as the world’s largest LNG importer opted for coal instead, with shipments of that commodity surging 44 percent.
The May deliveries of LNG to Japan amounted to 5.52 million tonnes compared with 5.75MT in May 2015, according to the preliminary trade statistics from the Ministry of Finance.
While LNG imported by Japan for gas-fired power generation and city-gas distribution dropped, the shipments into the country of thermal coal for generating electricity jumped 44 percent to 8.60MT in May compared with 5.98MT in the same month of 2015, even as coal prices were 10.7 percent higher year-on-year.
Japanese LNG imports had actually risen by a marginal amount in March 2016 for the first time since August 2015, to 8.14MT compared with 8.13MT in March last year, a rise of 0.1 percent.
However, the downward trend resumed in April 2016 when the shipments dropped 3.3 percent year-on-year to 6.38MT.
The latest LNG import figures also illustrated the falling price of LNG with deliveries in May 2016 costing 183 billion yen ($1.75Bln), down 42.0 percent compared 315Bln yen ($3.01Bln) in the year-ago period.
Fewer cargoes were imported from the Middle East while Asian imports rose.
Total shipments of LNG from the Middle East were down 14 percent. Deliveries from countries like Qatar, the United Arab Emirates and Oman fell to 1.24MT in May.
These were partially offset by Asian deliveries from nations such as Malaysia and Indonesia, Papua New Guinea and Brunei which amounted to 1.86MT, a rise of 3.2 compared with the 2015 month.
Russian imports also rose 24 percent compared with the year before to 595,000 tonnes.
The balance of other imports in the preliminary figures amounted to 1.82MT from exporting nations such as Australia and Nigeria as well as the spot market. There were still no imports logged yet in Japan from the United States.
On June 9, Japan said the price of spot LNG cargoes imported into the country in May amounted to $4.30 per million British thermal units, down from $5.10 per MMBtu in the previous month and from $7.90 per MMBtu in the year-ago period.
The spot cargo numbers come from the commerce division of the Japanese Ministry of Economy, Trade and Industry and are only issued if a minimum number of two trades are recorded.
The ministry emphasizes that “spot LNG” refers to fuel traded on a cargo-to-cargo basis and does not mean shipments under contracts on a short-term, medium-term or long-term basis.
Prices prior to averaging are all converted into an equivalent D
Fracking changed everything. Look at these costs.
Alaska LNG has given US regulators a second round of draft resource reports and details of alternatives routes and sites it had previously examined as part of the preliminary environmental review process, with start-up now expected in 2025 and estimated costs still at $45-$65 billion.
The facilities near Nikiski in south-central Alaska will produce 20 million tonnes per annum of LNG from three liquefaction Trains with two huge LNG storage tanks of 240,000 cubic metre capacity instead of three 160,000 cubic metres capacity tanks originally envisaged.
The US Federal Energy Regulatory Commission has given a permit for an extension of the Gulf South Pipeline that will allow Japanese and European customers of Freeport LNG to transport their feed-gas to the liquefaction plant being constructed at Quintana Island in Texas.
The FERC has now issued an order authorizing the construction of the Gulf South Pipeline Company’s extension called the Coastal Bend Header Project.
The pipeline will provide 1.42 billion cubic feet per day of firm gas transportation to the existing Freeport import terminal currently being transformed into an export plant.
Freeport LNG customers who have already signed agreements for the pipeline capacity on the Coastal Bend Header Project include BP of the UK, Germany’s Uniper Global Commodities (previously E.ON) and subsidiaries of Japanese utilities Chubu Electric and Osaka Gas.
US energy tycoon Michael Smith is Chief Executive of Freeport and the project is on schedule to ship its first LNG cargo by the end of 2018.
Gulf South owns and operates around 7,240 miles of pipeline facilities extending from Texas through Louisiana, Mississippi, Alabama, and Florida.
Gulf South estimates the total cost of the Coastal Bend Header Project will be around $545 million.
Each of the three Trains in the first phase of construction at Freeport will produce just over 5 million tonnes per annum of LNG and 13.4 MTPA of the more than 15 MTPA of output has been contracted under use-or-pay liquefaction tolling agreements signed by the European and Japanese companies.
A fourth production Train is also planned. Construction work on the additional Train is expected to begin in 2017 and to be operational in 2021.
The existing buyers of the Freeport capacity have signed contracts for 4.4 MTPA of liquefaction capacity.
“The proposed addition of compression on Gulf South’s existing Index 129 system is designed to enable Gulf South to provide up to 1.4 Bcf per day of capacity to move gas from various supply sources to a new interconnection between Index 129 and the proposed Coastal Bend Header,” according to the FERC statement.
“The new capacity will be divided into two parts: 700 million cubic feet (MMcf) per day will be provided as southbound capacity on the northern portion of Gulf South’s Index 129 and 700 MMcf per day will be provided as northbound capacity on the southern portion,” the FERC explained.
Specifically, Gulf South proposes to construct and operate a 66-mile-long, 36-inch-diameter header pipeline located in Wharton and Brazoria Counties in Texas.
It includes new compressor stations in Texas, consisting of multiple gas-fired turbines and seven new meter and regulating stations at interconnections with various interstate and intrastate pipelines.
“Gulf South proposes to recover costs associated with the additional capacity using incremental rates for firm and interruptible transportation services on the Coastal Bend Header facilities,” the FERC noted.
It added that upstream of the interconnection are links to Tennessee Gas Pipeline Co. (at the Coastal Bend Header’s point of origin), Transcontinental Gas Pipe Line Co. and Natural Gas Pipeline Company of America.
Downstream of the interconnection are links to Houston Pipe Line Co.’s Texas Pipeline and with the Freeport LNG plant which will be the Coastal Bend Header’s terminus.
“Gulf South’s proposal for the expansion satisfies the threshold requirement that Gulf South will financially support the project without relying on subsidization from existing customers.
“Gulf South shall keep separate books and accounting of costs and revenues attributable to the Coastal Bend Header facilities,” the FERC permit stated.
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The US Department of Energy published its export data for April that showed three more cargoes shipped from the Cheniere Energy export plant at Sabine Pass in Louisiana at prices up to $4.10 per million British thermal units for the basic gas and $10 per MMBtu for container shipments from Florida.
The DoE data showed that American LNG Marketing exported two LNG shipments in ISO containers on cargo vessels from Miami, Florida, to Barbados at an export point price of $10.00 per MMbtu.
The April cargoes and prices involved Sabine Pass loading a cargo for Argentina on April 8 on the “Stena Clear Sky” at $4.10 per MMBtu before shipping and other expenses and costs.
The other cargoes were to the Sines terminal in Portugal on April 15 on the “Creole Spirit” at $3.41 per MMBtu and to Argentina on April 25 on the “GasLog Salem” at $3.85 per MMBtu.
Under current plans for Alaska LNG, the three oil companies and AGDC are aiming to construct three liquefaction Trains at Nikiski in south-central Alaska to process up to 20 million tonnes per annum of LNG and with three 160,000 cubic metres capacity storage tanks alongside.
The proposals include delivering the gas from the North Slope region using an 800-mile, 42-inches diameter pipeline with up to eight compressor stations along the way.
The pipeline will have a capacity of 3.3 billion cubic feet of Alaskan natural gas per day.
The four Alaska LNG project partners have been carrying out preliminary engineering and design work on aspects of the liquefaction plant and storage facilities, as well as the pipeline.
This additional information will be forwarded to the US Federal Energy Regulatory Commission as part of the ongoing permitting process.
“Alaska is engaged in one of the largest energy projects in North America. I'm excited by the challenge and incredibly honored by the trust and confidence the board is placing in me,” said Meyer in June.
“I understand how vital the gas pipeline and LNG project are to our Alaskan economy and I'm committed to getting them built,” he had stated.