LNG producers work at building demand to match new supplies

 

(Wall Street Journal; Oct. 15) - After spending hundreds of billions of dollars to transform themselves into global natural gas giants, some of the world’s biggest energy companies face a new challenge: generating more demand as supplies threaten to balloon and prices languish. Producers are promoting the use of LNG for industrial trucking and shipping. Companies also say they are considering building the power plants and infrastructure necessary to provide gas and electricity in developing markets.

 

“We have to ultimately help the end customer,” said Peter Mackey, an executive at GE Power, which designs LNG facilities. After the energy industry spent $725 billion from 2007 to 2016 on LNG projects, according to consultant Wood Mackenzie, large new supplies are coming online in the U.S., Russia, Australia and Qatar. The opportunities and challenges of developing more demand will be a focus for energy companies gathering this week in London at an industry conference. LNG prices are mired at about half their 2014 peak, with LNG delivered to Asia trading around $8.70 per million Btu.

 

So far, companies have found customers for much of the new LNG, mostly because it was inexpensive and technological innovations cut the cost of building import terminals. The number of countries importing LNG has risen to 40, from 17 a decade ago. After building so much new LNG production capacity, companies now are forced to look to less-developed and potentially riskier markets. “The next wave of LNG consumers are less creditworthy, less experienced, less organized, and politically less predictable,” said Jason Feer, head of business intelligence at consultancy Poten Partners.

 

Japan will promote new effort to invest in LNG import facilities in Asia

 

(Nikkei Asian Review; Oct. 16) - The Japanese government will unveil a $10 billion public-private initiative aimed at tapping increasing demand for liquefied natural gas infrastructure as the fuel is increasingly adopted throughout Asia. The Japan Bank for International Cooperation and Nippon Export and Investment Insurance will be among the players in the effort to enlist Japanese companies in investment plans to build such LNG infrastructure as offloading terminals and power plants throughout Asia.

 

Hiroshige Seko, minister of economy, trade and industry, will announce the initiative Oct. 18 at Japan’s annual LNG Producer-Consumer Conference. Top government officials, including the prime minister and other cabinet members, would be involved in promoting particular projects to nations in the region.

 

The effort is also designed to strengthen Japanese-U.S. ties. Shale gas production has taken off in the U.S., and finding customers for the fuel has become an issue. An agreement to expand American shale gas exports to Asia is expected at the U.S.-Japan economic dialogue meeting on Oct. 16 in Washington, and the Japanese LNG infrastructure initiative is likely to be part of achieving that goal.

 

 

Low-cost producer Qatar can handle LNG competition, analysts say

 

(Arab News; Oct. 14) – A big question in energy markets is how Qatar will handle the glut of liquefied natural gas as the era of favorable long-term supply contracts comes to a halt. When Qatar came to prominence as the world’s largest LNG exporter in the early 2000s via a series of mega investments in resource-rich gas fields, it was a seller’s market. Favorable 20-year contracts were par for the course and a seller’s dream.

 

Today, the globe is awash with gas as U.S. shale and new Australian LNG gatecrash the market for the first time — throwing down the gauntlet to Qatar. And buyers have become less accommodating. In 2000, only about 5 percent of LNG deals were linked to spot prices or short-term contracts. By last year that had risen to 28 percent, said Luis Barallat, gas and LNG leader at Boston Consulting Group. Ten years ago, he said, the average length of an LNG contract was 17 years; in 2016 it was seven years.

 

Against this background, Qatar in June said it would lift its moratorium on new North Field development. Most gas analysts will tell you Qatar, as the world’s lowest-cost producer, remains a price setter. In any price war for market share, Qatar could more than hold its own. Chris Young, of the oil and gas team at KPMG UK, said Qatar has traditionally had a favorable cost position, “which should allow it to maintain market share with key buyers, with the flexibility to lock in longer term volumes.”

 

 

Cheniere nears completion of fourth LNG unit at Sabine Pass, La.

 

(Reuters; Oct. 13) - Cheniere Energy said Oct. 13 that the fourth train at its Sabine Pass liquefied natural gas plant in Louisiana was substantially complete, which will boost output from the first LNG export terminal in the United States by a third. Offtake from the train, which has a 4.5 million tonnes per annum nameplate capacity, is contracted to GAIL (India) for a 20-year period, with shipments to commence in March 2018.

 

Until then, LNG produced from the train will be sold by Cheniere into the open market, spokesman Eben Burnham-Snyder said. A fifth train is under construction at the facility, which will further boost capacity at the export terminal from 18 million tonnes per year to 22.5 million by the second half of 2019. The initial train at Sabine Pass loaded its first LNG for export in early 2016.

 

At least five other export terminals are set to come online in the United States over the next few years, including Cheniere's Corpus Christi facility in Texas.

 

 

Oil price recovery should help LNG prices, says head of gas exporters

 

(Platts; Oct. 12) - Efforts by OPEC and non-OPEC producers to curb oil output and stabilize global markets should also help restore balance in the natural gas market by around 2022, earlier than previously expected, Seyed Mohammad Hossein Adeli, secretary general of the Gas Exporting Countries Forum, told S&P Global Platts. As gas prices, especially liquefied natural gas, largely remain linked to oil prices, increased and stabilized oil prices should be reflected in rising natural gas prices, Adeli said.

 

"If oil exporters and producers do their best to help stabilize the oil price, this will help the gas price as well, because whether you like it or not, gas and oil are two substituted fuels, and there are lots of (gas) contracts that are oil-indexed," he said. Oil hit a two-year high last month, rebounding from the 2014-2015 crash. "If it continues like this, it may have a positive impact … and eventually help investors decide on investments."

 

Liquefied natural gas markets have suffered a sharp drop in investment the past two years because of the overall economic situation, a decline in gas prices due to too much supply, and a shift to short-term and spot trading that has increased uncertainty for producers, Adeli said. But that should change around 2022 as underinvestment leads to gas shortages, he said. Certainly, a revival in popularity of long-term contracts would give producers more security, encouraging investment. The favoring of spot and short-term deals in recent years "has not been helpful for the stability of the market,” he said.

 

 

Tokyo Electric, Chubu Electric will integrate power plant operations

 

(Reuters; Oct. 13) - The Japan Fair Trade Commission has approved plans by Tokyo Electric and Chubu Electric to integrate their fossil fuel power plants under their JERA Co. joint-venture, an official with the anti-monopoly regulator said Oct. 13. The trade commission gave the green light after determining that the deal, involving Japan’s biggest and third-biggest regional power utilities, would not have an impact on fair competition in the industry, the official said.

 

The pair have agreed to combine the businesses, forming a company that will oversee 68 gigawatts of domestic power capacity, nearly half the country’s power generation. Tokyo Electric and Chubu Electric set up JERA in 2015. It now handles all of the two companies’ upstream energy and fuel procurement business and is the world’s biggest liquefied natural gas buyer with annual intake of about 35 million tonnes.

 

The integration of fossil fuel plants is the last of a three-step plan for JERA, which also handles fuel transportation/trading, upstream energy assets and overseas power generation. The integration of the JERA parents’ domestic plants will propel it to become one of the world’s major power utilities by installed capacity.

 

 

Oregon landowners continue fight against LNG project in Coos Bay

 

(The News-Review; Roseburg, OR; Oct. 13) – Several Oregon residents whose land would intersect the proposed Pacific Connector pipeline filed a letter Oct. 3 asking the Federal Energy Regulatory Commission to deny the gas pipeline and Jordan Cove LNG project. Veresen, Jordan Cove's Calgary-based parent company, and Pacific Connector have filed an application for a 232-mile gas pipeline to cross four Oregon counties to the costal port city of Coos Bay, where the gas would be liquefied and shipped overseas.

 

FERC denied the application last year but Veresen has reapplied, making changes to the pipeline route and project plans. In last year’s denial, federal regulators said Veresen showed no buyers for the LNG, no market need for the project. Opponents raised the same issue in their Oct. 3 letter. “(Veresen) is asking once again to be given permission to build a speculative project on the backs of landowners and communities who oppose the project and who will be threatened by the exercise of eminent domain.”

 

Jordan Cove LNG spokesman Michael Hinrichs disagrees, and said Japanese buyers JERA Co. and Itochu are committed to buying half of the plant’s output. “We continue to advance negotiations with additional customers and are confident we will reach commitments for 100 percent of our capacity." The letter asserts, "FERC has a responsibility to ensure that the 'benefits' outweigh any adverse effects to landowners and communities. That hinges entirely on the economic benefits test of weighing benefits tied to firm markets versus adverse effects of landowners."

 

 

LNG projects helped boost Australia’s gas supply, columnist says

 

(The Australian columnist; Oct. 10) - Shell Australia’s new chair, Zoe Yujnovich, has injected what for some will be an uncomfortable dose of reality into the debate about the role of the three big Queensland LNG export plants in the East Coast energy crisis. In an address at an energy summit Oct. 9, Yujnovich took issue with the widely accepted narrative that exports from the three plants off Gladstone have created a gas shortage and driven a spectacular surge in gas prices for local households and manufacturers.

 

While there’s a strand of truth to that storyline, it is based on the false premise that had there been no LNG export plants built in Queensland, gas would have been available at a much lower price to the domestic market. In reality, if the three LNG development ventures had not invested more than $US60 billion to build the gas liquefaction plants, it is unlikely the gas reserves that feed them would ever have been developed.

 

The feedstock for those plants is coal-seam methane, which is more complex and more expensive to extract than conventional gas. Without the huge investment in the LNG plants and the long-term sales contracts to customers in the Asia-Pacific to underwrite the spending, those reserves may never have been economic because of the scale of expenditure required to exploit them. In other words, those three LNG plants have made more gas available to the domestic market than had they not been developed.

 

 

China buys first spot cargo of Norwegian LNG since last December

 

(Reuters; Oct. 12) - China has bought a rare cargo of liquefied natural gas from Norway, Reuters shipping data shows, the latest sign that the world’s second-largest economy has rushed to increase spot purchases to ensure fuel supplies ahead of winter. Trade flow data on Thomson Reuters Eikon shows the LNG tanker Grace Cosmos loaded up from Norway’s Snohvit project and is heading to China for delivery Oct. 30.

 

It’s the first LNG cargo China has bought from Norway since December last year and one of only six in the past 3½ years. While only a small portion of the gas that China imports each year, the deal represents a growing need as Beijing intensifies its war on the choking smog that shrouds the north of the country. This winter, China will use gas to heat millions of homes across the north for the first time, as the government tries to wean the nation off its favorite fuel, coal.

 

That effort will add an estimated 365 billion cubic feet to China’s gas demand, about 5 percent of last year’s consumption. Concerns have grown about adequate supplies for such an ambitious project, said a gas researcher with an energy think-tank: “We should see more buying on the spot market.” China bought 22 million tonnes of LNG in the first eight months of the year, equivalent to more than 1 trillion cubic feet of gas, up 44 percent from a year ago. Almost half of that came from Australia, followed by Qatar.

 

 

Chevron drops oil exploration plans in remote Australian waters

 

(The West Australian; Oct. 12) - Chevron has abandoned oil exploration plans in the Great Australian Bight, citing a focus on more commercially viable North West gas. Chevron follows BP in exiting the remote and environmentally sensitive region off South Australia, where it holds offshore acreage of more than 12,000 square miles. The company acquired the two deepwater exploration permits off South Australia in 2013, spending hundreds of millions of dollars on development costs.

 

Chevron said that while the bight was one of Australia’s most prospective regions, it could not compete for capital in the company’s global portfolio under low oil prices. “This is a commercial decision and was not due to government policy, regulatory, community or environmental concerns,” Chevron Australia managing director Nigel Hearne said.

 

The decision follows the company last week bolstering its North West gas acreage by acquiring three exploration blocks spanning 9,000 square miles in the Northern Carnarvon Basin. BP a year ago called off nearly $1.4 billion of drilling in the Great Australian Bight. Much of the area marked for exploration in the Bight, which stretches about 1,000 miles between the states of South Australia and Western Australia, lies in a marine reserve, home to whales and sea lions. It’s a rich fishing ground and lures tourists who come to view great white sharks from diving cages.

 

 

Pipeline outages pushed Alberta natural gas prices to go negative

 

(Financial Post; Canada; Oct. 12) - Pipeline outages and maintenance work have caused volatile swings in Alberta natural gas prices, even pushing them into negative territory recent days. In the past few weeks, Alberta’s benchmark prices have fallen into negative territory — meaning producers have had to pay customers to take their gas — on multiple days. Data from Gas Alberta Inc. show prices fell to negative 7 cents from Oct. 5 through Oct. 9, and were also negative on Sept. 25.

 

“We’ve never seen negative prices before this year,” GMP FirstEnergy analyst Martin King said, adding that he’s been following Alberta hub gas prices since 1993. On Oct. 12, the price of natural gas in the province jumped to about $1.80 per 1,000 cubic feet, but, “It could crash again tomorrow,” King warned.

 

“The volatility has been ongoing for quite a few weeks and a lot of it is related … to field maintenance TransCanada has been doing on the Alberta (pipeline) system,” King said. Service has been interrupted for maintenance on gas gathering and transmission pipelines. TransCanada has been working to expand its system ahead of new service agreements coming into effect on Nov. 1. The extreme price swings have forced Alberta producers to make a difficult choice between selling their gas for nothing, or less than nothing, and shutting in their wells, Auspice Capital founder officer Tim Pickering said.

 

 

Major French bank will no longer finance shale oil and gas projects

 

(Wall Street Journal; Oct. 12) - French lender BNP Paribas said Oct. 12 it will no longer finance shale and oil sands projects, in one of the clearest signs yet the banking industry is reevaluating its relationship with the oil sector amid mounting pressure from investors and top financial institutions. France’s largest listed bank said it would stop working with companies whose main business is the exploration, production, distribution or marketing of oil and gas from shale or oil sands. BNP Paribas has already made moves to reduce its financing of coal mines and coal-fired power plants.

 

BNP Paribas will not finance oil or gas work in the Arctic either, the bank said. “These measures will lead us to stop financing a significant number of players that don’t further the transition toward an economy that emits less greenhouse gas,” CEO Jean-Laurent Bonnafé wrote in a post on LinkedIn. BNP Paribas is one of the first banks to eschew parts of the oil sector. Many governments are taking steps to curb emissions, and investors have been increasing pressure on firms over their environmental footprints.

 

"The writing is on the wall over the medium term for the most carbon-intensive fossil fuels,” said Mark Lewis, a member of a panel of top financial institutions and companies that published a series of guidelines for businesses to disclose more about the impacts of climate change. “Banks will adapt like all other companies to changing economics and changing investor preference,” Lewis said. Still, there is little sign the industry has difficulty raising money. The shale sector has boomed over the past three years, despite a fall in prices, and U.S. companies have access to a deep pool of investors and banks.

 

 

Dakota Access oil pipeline adds value to Bakken shale production

 

(EnergyWire; Oct. 11) - The Dakota Access pipeline has begun to improve oil prices in North Dakota, bringing tens of millions of extra dollars into state coffers and potentially making the Bakken Shale field more viable. North Dakota oil sold for about $5.61 less than West Texas Intermediate, the U.S. benchmark, during the first three months after the pipeline opened, said Justin Kringstad, head of the North Dakota Pipeline Authority. That's an improvement of about $2.10 per barrel compared to the same period in 2016.

 

As recently as June, the differential was about $10 a barrel and it wasn't clear if the pipeline was having an effect on North Dakota prices. The pipeline became operational June 1. "We still may see some ups and downs as the market continues to adjust with this new service in place," Kringstad said. The price improvement means North Dakota will gain about $6 million a month in additional state tax revenue, Kringstad said.

 

North Dakota oil historically has sold below the national price because the state is so far from refineries in the Midwest and on the coasts. The region also lacked major pipelines for years, which forced companies to use more expensive transportation, including rail and trucks. The controversial 1,172-mile Dakota Access pipeline can carry 570,000 barrels a day — more than half of North Dakota's output of about 1 million barrels a day.