Kuwait’s LNG imports up 17% for 2015
(Reuters; Dec. 4) – Kuwait’s liquefied natural gas imports are on track to rise by 17 percent to 3 million metric tons in 2015, boosted by the fuel's increased competitiveness with oil, an executive from Kuwait Petroleum Corp. said Dec. 4. The Gulf state imported about 2.5 million tons in 2014 via its floating import terminal, which it leases for the peak energy demand from March to November, with an option to extend additional months.
Speaking on the sidelines of the CWC World LNG Summit, Khaled Al-Sabah of Kuwait Petroleum said the option to extend the lease on the floating import terminal, due to expire in 2019, was being "explored". This would be on top of a land-based LNG-terminal due to start up in 2020. "The option to have both is still being studied," Al-Sabah said. "There is an ambitious plan to expand the power (capacity) in Kuwait."
Kuwait is a seasonal LNG importer, leasing a floating storage and regasification unit from Norwegian shipping company Golar LNG over the warmer months. Al-Sabah said the lease had been extended to the end of December this year and there was potential it could be a full-year lease in the future due to growing demand. The Mideast and North Africa have been the biggest growth markets for LNG demand in 2015, led by recent entrants Egypt and Jordan, with lower prices helping stimulate offtake from new buyers.
Qatar appears ready to reduce LNG price to India
(Bloomberg; Dec. 4) - Petronet LNG, India’s biggest natural gas importer, is in talks with Qatar’s RasGas to work out a new pricing formula for an existing 25-year contract. The revised price will be based on a three-month average price of oil, replacing a five-year average, according to two sources who asked not to be identified because the talks are confidential. The new formula could immediately cut the price of liquefied natural gas cargoes by about 50 percent starting next month, according to Bloomberg calculations.
Terms being discussed include Petronet buying an additional 1 million metric tons of LNG a year from RasGas for the remaining years of the deal, the sources said. Petronet had originally agreed to buy 7.5 million metric tons a year under the Qatari contract ending 2028. The initial years included low prices for LNG delivered to India, with the price linked to oil starting in 2009. As oil prices spiked, so did LNG prices to India. The five-year average delayed today’s low oil prices from showing up in the LNG invoices.
In addition to shortening the pricing period to three months, the new formula will be pegged to Brent crude rather than a basket of crudes imported by Japan that has been traditionally used in LNG contracts. The trailing three-month average Brent price is about $48 a barrel, while the average of Japan Crude Cocktail for the five-year period ended Sept. 30 was $100, according to data compiled by Bloomberg.
Panelists say lack of new LNG supply could create shortage in 2020
(Rigzone; Dec. 3) - Concern is growing in the liquefied natural gas industry that low prices could delay sanctions for new export projects, potentially leading to a supply bottleneck in 2020, panelists said at the Gastech 2015 conference in Singapore. “When we asked ourselves what will be the impact of lower oil and LNG prices for the next five years, the answer might very well be that no new LNG projects are sanctioned,” said Pierre Breber, Chevron’s executive vice president for gas and midstream.
“But that’s not the best outcome for buyers and sellers. Getting that best outcome will require keeping a long-term perspective,” Breber said. “If LNG suppliers fail to develop resources required to meet forecasted longer-term demand growth at the right time and in the right place, there will be a supply-and-demand imbalance with longer-term implications for LNG prices,” said Qatar’s RasGas CEO Hamad Mubarak Al Muhannadi.
While low prices have dampened interest in new projects, a buyers’ market is providing some optimism in a beleaguered sector, panelists said at the October conference. “We are seeing new customers for LNG across parts of Asia, the Middle East, Eastern Europe and Central and South America,” Breber said. RasGas, too, has noted the entry of new customers. “This year alone, we have witnessed new markets emerging in Lithuania, Egypt, Jordon and Pakistan. And we anticipate other new markets to continue to develop such as Bangladesh and the Philippines,” the RasGas CEO said.
Oversupply of LNG looks to get even worse in 2016
(Reuters; Dec. 4) - Asia's liquefied natural gas glut is set to deepen in 2016 as long-planned new production comes to the market just as demand from top buyers Japan and South Korea as well as China wanes. While analysts say that new-buyer demand may offset dwindling purchases from established buyers, new supplies will outweigh overall orders, resulting in a low LNG price outlook for years to come.
"From having been an import basin, Asia will next year be going to excess supplies and worse so in 2017," said David Hewitt, co-head of global oil and gas equity research at Credit Suisse. While most volumes from Australia's 13 new LNG trains will be delivered to long-term buyers, the commissioning cargoes over the next two years totaling 14 million to 15 million metric tons will go into the spot market, knocking down prices.
Hewitt said he expected Asian LNG spot prices to fall to "eye-watering low" levels of below $5 per million Btu in early 2016 and to hit a low of $4 during the year. Because of the emerging glut, Asian spot prices have already plummeted by almost two-thirds since 2014 to about $7.30. With a wave of supply coming, even a rise in demand from new customers will not be enough to balance the market.
Japan imported 6.06 million tons of LNG last month, down 12.8 percent from a year ago, while South Korea's average monthly LNG imports this year of 2.7 million tons is the lowest since 2009, customs data showed. While a dozen new buyers — including Morocco, Poland, the Philippines and Bangladesh — are expected to start importing LNG by 2020 with some 13 million tons a year of new demand, this will be outpaced in the next two years alone by the volume of commissioning cargoes from new projects.
Nigeria, Algeria say gas producers should form OPEC-style group
(Wall Street Journal; Dec. 4) - Some of the world’s biggest natural gas producers are trying to seize on changes in how the fuel is bought and sold to create an OPEC-style group to influence prices. Leaders of Nigeria and Algeria, at a recent forum in Tehran, said gas producers should come together and intervene in prices. Nigeria’s President Muhammadu Buhari called for “the formulation of a sustainable pricing mechanism that will guarantee fair and reasonable prices for both producers and consumers.”
Opening and shutting the spigots at relatively short notice to influence prices has been long-standing policy for OPEC, where most oil cargoes are sold on a spot basis. But it’s a novel idea for gas producers, where long-term contracts dominate and therefore supply cannot be altered easily by coordinating producers. But that’s changing with the increasing role of short-term sales in liquefied natural gas. Last year, almost 30 percent of LNG was traded on a short-term basis, compared with 5 percent a decade ago.
“Long-term contracts with fixed prices [are] going to be abandoned,” Iran’s oil minister Bijan Zanganeh said at the Gas Exporting Countries Forum last week — the countries control two-thirds of global reserves. The calls for intervention come as prices have tanked. Asian LNG spot prices are at $7 per million Btu, crashing from the record high of $20 in February 2014. But there are hurdles to creating a gas cartel. First, two of the biggest gas producers — Russia and the U.S. — wouldn’t be involved. And OPEC has demonstrated how difficult it is to have influence when the market is well-supplied.
Europe’s biggest gas producer, the Netherlands, comes up short
(Bloomberg; Dec. 2) - The European Union’s biggest natural gas producer has joined most of the rest of the 28-nation bloc and become reliant on others for some of its fuel. The Netherlands brought in more gas than it exported in the third quarter, with imports rising to a record in September, Statistics Netherlands said Dec. 2. The nation of almost 17 million has capped gas extraction from Europe’s biggest field, Groningen, in its north, by more than a third because of tremors linked to production.
It now has to turn to other producers such as Norway and Russia to meet some of its demand as it honors export contracts to supply customers in Germany, Belgium and France with gas from Groningen. “They are going to be buying much more from others than they have been accustomed,” said Trevor Sikorski, an analyst at Energy Aspects in London. EU gas production has dropped 42 percent in the decade to 2014 as the Netherlands has curbed its output and North Sea fields continue their depletion.
The production decline comes as EU demand is set to rise 7 percent in 2015, the first increase in five years, according to Brussels-based lobby group Eurogas. The Netherlands pumped 1.5 trillion cubic feet from Groningen in 2014 with production capped at just over 1 tcf this year, according to the Shell-ExxonMobil venture that operates the field. That compares with annual domestic consumption of more than 1.1 tcf, according to BP’s Statistical Review.
Anadarko, Eni agree to coordinate drilling offshore Mozambique
(Bloomberg; Dec. 3) - Anadarko Petroleum and Italy’s Eni have agreed on a plan to develop adjoining natural gas areas offshore Mozambique as the East African nation moves toward getting its first liquefied natural gas export project off the ground. The two companies will drill the reservoirs in a “separate but coordinated manner,” they said in separate statements. The agreement, targeting 24 trillion cubic feet of gas from the areas combined, is subject to government approval.
Mozambique has attracted international energy companies to exploit huge gas finds in the northern Rovuma basin that could help turn the country into the world’s third-biggest LNG exporter in a decade. Texas-based Anadarko has said it is waiting on government approvals to reach its investment decision on an LNG plant. The agreement with Eni will allow the companies to develop the fields more efficiently and capitalize on economies of scale, said Mitch Ingram, Anadarko’s executive vice president of global LNG.
Requiring U.S. ships to move U.S. LNG would add costs, report says
(EnergyWire; Dec. 4) - A congressional proposal to export U.S. liquefied natural gas only on domestically built ships could cause costs to go up nearly 25 percent and cut into U.S. markets for the fuel, federal analysts said. A U.S. Government Accountability Office study, released Dec. 3, looks at a proposal to require that U.S. LNG be shipped only on tankers that bear U.S. flags and, over time, are built in the United States.
The analysis found that such a requirement could support the maritime industry with new jobs through a need for as many as 100 new LNG tankers to serve the five U.S. export facilities currently under construction. But it risks lessening the global appetite for domestic LNG if buyers are on the hook for the higher costs that come with U.S. construction and American crews. Today, there are no U.S.-flagged LNG tankers. The last ones were built in the late 1970s and were later reflagged.
House Republicans in January blocked a proposal by California Democrat John Garamendi — whose district includes major shipping interests — that LNG exports be limited to U.S. vessels. But a measure was passed calling for the GAO review. In its assessment, GAO found that a U.S.-built standard would support maritime interests, but the overall impact would depend on whether demand for U.S. gas fell due to higher shipping costs. The report said using more expensive U.S. ships could add 73 cents per million Btu to the cost of moving LNG from the U.S. Gulf Coast to Asian markets.
Drop in Marcellus drilling could help boost U.S. natural gas prices
(Reuters; Dec. 2) - The Marcellus Shale drilling boom has lessened, although the region still produces a fifth of U.S. natural gas supply. Now, exclusive data made available to Reuters points to a slump in drilling that could hit production next year, defying government and industry expectations of a further rise in output. Preliminary figures provided by DrillingInfo, which monitors rig activity, shows drilling permits issued for the 90,000-square-mile reservoir beneath Pennsylvania, Ohio and West Virginia slumped to 68 in October. The number was more than 600 a month at its peak in 2010.
A retreat of such magnitude, combined with falling output from older wells, would mark a turning point for the Marcellus — and the entire U.S. market. The Energy Information Administration forecasts U.S. gas output to hit a record in 2016 for the sixth year in a row, but a drop in Marcellus production could snap that streak and help prop up prices that have fallen by two-thirds since 2010. U.S. gas production has risen 30 percent since 2008 when the development of hydraulic fracturing and horizontal drilling unlocked vast shale gas reserves, swamping the market and causing a price collapse.
Energy firms hold out little hope for a near-term rebound, bracing for a longer rough patch. Justin Kastner, a manager with Global Land Partners, a company that secures leases for oil and gas companies, said his Pennsylvania staff has halved this year from 16 to eight. "There is just too much gas," he said. The local economy is feeling the pinch too. Foreclosures filed in Pennsylvania’s Lycoming County from January to October hit their highest since the data was first collected in 2006, according to Realty Trac.
Oil and gas land sales in Canada lowest in 17 years
(Globe and Mail; Canada; Dec. 2) - Oil companies have slammed the brakes on bidding for new prospects in Canada. Sales of drilling rights on government land across the West are headed for their lowest level in at least 17 years, as cash-strapped companies forgo amassing new acreage. The National Energy Board said Dec. 2 that land sale revenue in the western provinces totaled $322 million with a month to go in the year — about a third of the 2014 figure and a fraction of the 2008 record of over $7.4 billion.
Major energy-producing provinces all suffered big drops in land sale revenue, despite warnings among some executives and analysts that the Alberta government’s reviews of carbon costs and royalties would result in a disproportionately large hit to that province. “Everything becomes equalized in this low commodity-price environment. Natural gas is in the toilet. Oil’s in the toilet and nobody cares about increased regulatory risk,” said Martin Pelletier, portfolio manager at TriVest Wealth in Calgary.
Oil prices have hung below $50 a barrel for much of this year, well under the $100 level of mid-2014, and natural gas markets have also been under pressure as a result of oversupply. The downdraft in prices has pressured finances at energy companies, which typically bid on government lands to bulk up on acreage for future operations. Complicating matters in British Columbia, no prospective developer of a liquefied natural gas project has started construction, despite more than 20 being proposed.
Australia winds down construction boom as LNG projects finish up
(Bloomberg; Dec. 3) - Australia’s $170 billion liquefied natural gas construction boom is winding down, and the hunt for new work is picking up. As plants owned by companies including ConocoPhillips and Chevron prepare to start production, workers and engineering firms that helped build them, including San Francisco-based Bechtel, are looking for new contracts. That’s proving tough at a time when commodity prices are putting future energy and mining developments in doubt.
The decline highlights the challenge facing a resources-driven economy adjusting to the end of a decade-long bonanza. Australia has seen a “dramatic collapse” in work as LNG plants finish, according to consultant Deloitte Access Economics. The expected start this month of an LNG plant led by ConocoPhillips and Origin Energy is a sign that construction on the East Coast is nearing an end. It’s the last of three LNG projects on Curtis Island, near Gladstone, where BG and Santos are already producing the fuel.
The workforce on Curtis Island has halved from a peak of 14,500 at the end of last year and will keep falling into 2016 as the three facilities move into full operation, according to Bechtel. The plants have employed more than 26,000 people over the past five years, everyone from welders to crane operators and boilermakers. About 2,000 workers have gone from the island to Chevron’s Wheatstone project in Western Australia, which is still under construction. But the last of Australia’s giant LNG plants could be done by 2017.
Yergin says oil markets will begin to balance by 2017
(CNBC; Dec. 4) - The next two quarters will be tough on crude prices, but 2016 will be a year of transition for oil markets, IHS Vice Chairman Dan Yergin said Dec. 4. Yergin told CNBC's “Squawk Box” that he expects oil markets to begin to balance next year or in 2017. "The oil market can't stay low like this because you're not going to have the investment you need," he said." "By 2020, the world oil market is going to need another 7 million barrels a day of production."
"Right now, the whole mantra is slow down, postpone, cancel projects," he added. Multinational energy companies and U.S. shale oil producers have slashed capital spending in order to protect their balance sheets as their revenues plummet and cash flow dries up. Crude prices began to sink from historic highs last fall, and the downturn accelerated after OPEC announced it would not cut supply to balance oil markets.
Despite expectations that high-priced U.S. crude production would collapse at $70 a barrel, U.S. producers can perform well at $55 to $60. However, current prices in the $40 to $50 range are creating "great pain," Yergin said. Kurt Hallead, co-head of energy research at RBC Capital Markets, said oil prices may be range-bound for years. The market could perform like it did 1991 to 1994, “where you had about a three-year period of capacity absorption before the supply and demand lines kind of crossed again," he said. In his scenario, prices would move up and down between $40 and $60 per barrel.