Market factors may keep U.S. Gulf Coast LNG out of Asia
(Bloomberg; July 13) - Asia’s going to have to wait a little longer for the flood of U.S. shale gas to reach its shores. A global glut of LNG has cut price differences between regions worldwide, leading traders to ship cargoes shorter distances to save on freight costs, Citibank analysts including Anthony Yuen said in a July 13 report. That means U.S. gas may stay in the Western Hemisphere for the near future, even with the Panama Canal expansion that can cut two weeks off journeys from America to Asia.
The canal expansion “was once expected to be a game changer for U.S. LNG exports to Asia,” the report said. “But against the backdrop of this major transition in the global LNG market, the prospects for U.S. LNG into Asia via the expanded canal look less promising, at least in the short-term.” While lower transport costs to Asia might help in the long term, currently the savings aren’t enough to make up for the compression of global prices. In October 2014, LNG in Singapore was $5 per million Btu more than in the U.K., which was $5 more than in the U.S. Now all three are within $2 of each other.
The price convergence is a result of a supply glut, as new production projects start up in Australia and the U.S. while demand shrinks in South Korea and Japan, the world’s largest LNG importer. The narrower differentials are encouraging trade to remain more regional, according to Citigroup. That means the only Pacific market the Panama Canal might open for U.S. exporters is the west coast of South America. The first LNG cargo set to transit the expanded canal is a BP-owned tanker hauling from Louisiana to Chile.
Federal court rejects another challenge against LNG export plants
(The Hill; July 15) - A federal appeals court has rejected environmentalists’ challenge to a liquefied natural gas export facility under construction in Maryland. The July 15 decision from the Court of Appeals for the D.C. Circuit is the third time in recent weeks that the court has rejected arguments against an LNG export project. The opponents, led by Patuxent Riverkeeper, argued that the Federal Energy Regulatory Commission did not properly consider the overall environmental impacts of the Cove Point project.
The opponents said FERC should have considered impacts of increased gas production and consumption, including climate change and the effects of hydraulic fracturing. The same court rejected those arguments in June when the Sierra Club used them against FERC approval of two other LNG facilities. The court ruled in those cases that since the Department of Energy is responsible for approving exports, and FERC is responsible for facilities, the department would be the one to look at environmental impacts of exports.
Deborah Goldberg, an attorney with Earthjustice who represented the environmentalists in the case decided July 15, disagreed with the ruling. The environmental coalition involved in all three cases has already sued the Department of Energy over all three export authorizations (projects under construction in Maryland, Louisiana and Texas). Goldberg predicted the Department of Energy could be in trouble in those cases, since the court implied the department was responsible for evaluating far more than it did.
U.S. needs higher natural gas prices to pay for more production
(Reuters columnist; July 15) - The U.S. natural gas market is on an unsustainable course as low prices stimulate strong growth in consumption while production is flat or falling. U.S. power producers burned a record amount of gas last winter despite mild weather as cheap prices and stricter environmental regulations encouraged a shift away from coal. Power producers burned 2.238 trillion cubic feet of gas between December and February, an increase of more than 11 percent compared with the previous winter.
Power generators are on course to burn a record amount of gas in 2016, according to the Energy Information Administration. The power sector accounts for around one-third of gas consumption in the U.S. and its gas use is set to rise by nearly 5 percent in 2016. At the same time, gas production is flat, or even falling slightly, as drilling falls to the lowest level in more than 30 years. Gas production this winter was just 2.6 percent higher than a year earlier and the growth rate has slowed further in the first half of 2016.
Rapid growth in consumption is inconsistent with flat production. But the imbalance has been masked by the engorged stockpiles carried over from 2015 and a mild winter. Prices will eventually have to rise to encourage more drilling and moderate further growth in power combustion. Futures prices for gas delivered in March 2017 have risen from less than $2.50 per million Btu in February to around $3.25, and it seems likely prices will need to be higher in 2017 than in 2015 and 2016 to rebalance the market by restraining consumption growth and encouraging faster production increases.
ExxonMobil winner in bidding for Papua New Guinea gas assets
(Platts; July 18) - ExxonMobil has been confirmed as the spoiler to Australian independent Oil Search's $2.2 billion plan to acquire LNG hopeful InterOil and its gas assets in Papua New Guinea. InterOil has notified Oil Search that it has received a "superior proposal" from ExxonMobil, Oil Search said in a statement July 18. As a result, InterOil plans to withdraw its recommendation of the proposed merger with Oil Search, first unveiled in May, in favor of an agreement with ExxonMobil.
InterOil is in play due to its stake in the Elk and Antelope gas fields, which are being eyed for development to supply the proposed Papua LNG project, led by France's Total, but which could also support expansion of ExxonMobil's Papua New Guinea LNG project that started up in 2014. Elk and Antelope hold proven and probable contingent resources that last week were certified at 6.43 trillion cubic feet of gas.
ExxonMobil is the operator and 33.2 percent stakeholder in the PNG LNG project, and has been looking at expansion options through addition of a third production train. The $19 billion project has been producing at well above its nameplate capacity of 6.9 million metric tons per year, achieving output of around 8 million tons per year in the first three months of this year. The project partners are Oil Search (29 percent), Australia’s Santos (13.5 percent), the government's National Petroleum Co. (16.8 percent), JX Nippon Oil & Gas Exploration (4.7 percent) and local landowner MRDC (2.8 percent).
B.C. LNG developer disputes that new gas wells would be needed
(Squamish Chief; Squamish, BC; July 14) - The Pembina Institute, a Canadian environmental policy think-tank, took aim at Woodfibre LNG in its latest release — and the company is none too pleased about it. The July 7 infographic calculates the projected upstream impact of the liquefied natural gas facility slated for southwest of Squamish, B.C., on Howe Sound, about 30 miles north of Vancouver. The Pembina Institute created the infographic for the anti-LNG group My Sea to Sky.
According to the Pembina Institute’s graphic, 24 additional natural gas wells would need to be drilled per year to support the export facility. It would contribute 0.81 million tonnes of carbon pollution per year and use 132 million gallons of freshwater per year. The figures are based on the $1.6 billion Woodfibre LNG plant’s proposed capacity to make 2.1 million metric tons of LNG per year, according to the Institute. Byng Giraud, a Woodfibre LNG vice president, called the numbers “disappointing” and “inaccurate.”
“The notion that a small facility like this would cause new wells to be drilled is false,” Giraud said. “It is a cause and effect that can’t be shown.” A facility the size of Woodfibre LNG will not send someone out to drill new wells, he added. “These are things that already exist.” Woodfibre LNG was granted its federal environmental assessment in March, with the developer is working toward an investment decision within the next year, Giraud said.
Argentina wants to boost local production to replace LNG imports
(Platts; July 13) - Argentina plans to discontinue LNG imports as domestic gas production increases over the next few years, President Mauricio Macri said July 13. "It's going to take five to six years for us to stop importing gas by tanker, which is very expensive," Macri said at the opening of an expanded port in Buenos Aires province. Energy Minister Juan Jose Aranguren set the same target for ending LNG imports, saying it costs $100,000 a day to rent two floating import and regasification plants.
Argentina started importing LNG in 2008 to plug a widening gas deficit as demand surged and domestic production fell. It now relies on imported gas supplies from Bolivia, Chile and from the LNG market to meet a third of its demand of 4.6 billion to 6.35 billion cubic feet of gas per day. This year, the country is paying an average of $6.50 per million Btu for 85 to 90 LNG cargoes. The price is more than the average $5.20 wellhead price for domestic production and the $3 price for gas piped in from Bolivia.
However, the LNG price is less than in previous years, when Argentina paid $16 and more for supplies because of higher global prices at the time. Another reason for the inflated prices was corruption, Macri said. "We are negotiating much better prices than previous ones because there is no hidden 'bonus'," Macri said. To reduce imports, the government doubled wellhead gas prices to an average $5.20 to encourage investment in boosting production and extended an incentive price of $7.50 for new developments.
Egypt could return to LNG export market by end of decade
(Interfax Global Energy; July 15) - Industry sources are confident Egypt can resume exporting LNG by the end of the decade. The country’s two liquefied natural gas plants, which both opened in 2005, have essentially been closed the past two years due to lack of feed gas. A source from Egypt’s Ministry of Energy said occasional cargoes — such as the two sent this year from the only Idku production train that remains operational — would continue, but they would not be regular.
Ahmed Moaaz, former deputy chair at Egyptian General Petroleum Corp., said that increased volumes from Eni’s Zohr field — estimated to hold almost 32 trillion cubic feet of gas — would eventually return Egypt to being a net LNG exporter, as would other new production. However, "between 2017 and 2019, we are not in a position to be a net exporter." Egypt produced no LNG in 2015 because of technical problems and a lack of feed gas; it shipped five cargoes in 2014. The country started importing LNG in 2015.
Any move to restart LNG exports will be a balancing act between meeting rising domestic demand and satisfying gas companies’ desire to export the fuel as their production rises. Eni expects to be producing 2 billion cubic feet of gas per day from Zohr alone in 2019, while BP is anticipating its Egyptian output will hit the same level.
French company may build small gas-fired power plants in Indonesia
(Bloomberg; July 11) - The world’s biggest independent power producer is taking its cue from the neighborhood milk man as it expands in Asia. French energy giant Engie is developing a project for Indonesia using small gas-fired power plants on islands throughout the archipelago country, said Jan Flachet, the company’s Asia-Pacific president. Small liquefied natural gas tankers would feed the plants from a central hub, similar to how milkmen would fill bottles at a processing plant for delivery to homes.
“We call it the milk run, like … when you had the delivery of milk to your doorstep,” Flachet said. “You build a power plant of, let’s say, 100 megawatts, then build a small regas facility and feed it with small LNG tankers.” Engie has issued bids for the project that are due back in August and would work with Indonesia energy firms on gas supply, he said. The company, formerly known as GDF Suez, is also developing renewable energy projects as it tries to supply Asian economies without relying on new coal plants.
Wood Mac says shale oil producers have adapted to lower prices
(Wall Street Journal; July 13) - U.S. shale oil drillers have made big strides in adapting to lower prices by cutting costs and improving productivity, said a report released July 13. Energy consultancy Wood Mackenzie said shale now makes up the bulk of the 9 million barrels a day of new oil it considers commercially viable — assuming Brent oil prices average about $60 a barrel. That is 1.5 million barrels of oil a day more than last year, and higher than at any point since 2009, the report said.
Shale drillers have cut the costs of producing new supplies of oil by as much as 40 percent in the past two years by pushing for lower rates from the firms that provide equipment such as rigs, pipes and other services. The companies have also improved productivity at the wells themselves by better locating drilling sites to make the most of “sweet spots” in the reservoirs and other initiatives.
The big winners will be operators in the key shale oil patches in the Lower 48 states, such as in the midcontinent and Permian Basin, including independents Pioneer Natural Resources, EOG Resources, Continental Resources and Apache, as well as oil giants ExxonMobil and Chevron, the report said. The cost reductions highlight how the industry has changed since the advent of U.S. shale oil in 2009 led to a global supply glut that upended markets and changed the traditional routes of supply and demand.
Chinese owner will review viability of oil sands operation
(Wall Street Journal; July 14) - Three years after spending $15 billion on an ambitious bid to revitalize a troubled oil sands project in northern Alberta, one of China’s largest state-controlled oil companies is rethinking its plans. CNOOC’s Canadian subsidiary on July 12 raised the specter of abandoning a core part of its oil sands operation, after an investigation into two major accidents uncovered a series of managerial and safety lapses at an already-troubled plant.
That marks a dramatic shift from 2013 when CNOOC bought Calgary-based Nexen — following two other billion-plus-dollar oil sands deals by state-controlled Chinese oil companies — and points to how far short the Nexen deal has fallen from expectations. “The deal has turned out to be a bit of a dud for them,” said Gordon Houlden, a China expert at the University of Alberta.
Last summer, a pipeline burst at Nexen’s Long Lake facility, spilling 31,500 barrels of oil. The company said July 12 the 6-month-old pipeline hadn’t been properly moored and its leak detection system failed. Then in January, an explosion at the plant’s crude-processing unit killed two workers. Nexen Energy CEO Fang Zhi said the two accidents revealed deep flaws in the company’s ability to safely run the facility. He said that before deciding whether to repair the Long Lake unit — which would cost an estimated $100 million — Nexen would review the long-term viability of its Alberta operations.
The Long Lake crude-processing unit turns cheap heavy crude from its nearby wells into premium lighter oil. But it has been plagued with glitches and cost overruns for years, and has never reached its intended production capacity of 72,000 barrels a day.
Analysts warn oil could slip back to $40 a barrel
(Bloomberg; July 15) - As oil’s upward climb runs out of momentum, more and more analysts expect the market’s next move will be back down toward $40 a barrel. Brent crude prices almost doubled between January and June, signalling that markets were finally healing as falling U.S. output, rising demand and disruptions from Nigeria to Canada all helped eliminate a global production surplus. Now, as consumption falters and halted supplies return, analysts warn prices may sink once more.
While there’s still a consensus that the worst of the oil glut that sent prices to a 12-year low is over, the International Energy Agency cautioned this week that “the road ahead is far from smooth.” Inventories are brimming after two years of surplus production and U.S. demand for gasoline — the key driver of prices in summer — is proving to be disappointing. As unwanted barrels pile up, traders have been forced to hoard the most crude at sea on tankers since 2009, according to the Paris-based agency.
“For the time being, the path of least resistance for oil prices is lower,” said Mike Wittner, head of oil market research at Societe Generale in New York. “Unplanned supply-side factors brought the market near balance in the second quarter, and it is again supply-side factors that will hinder that balance in the near term,” said Harry Tchilinguirian, head of commodities research at BNP Paribas in London. “We are looking to return to $40 or below” for the U.S. benchmark, West Texas Intermediate.
It’s not only oil production that has analysts concerned. There is an “epic overhang” of gasoline after refiners built up stockpiles of the fuel at the beginning of the year when crude was cheap, said Amrita Sen, chief oil analyst at London-based Energy Aspects.