China moving more to gas, but lower prices are important for growth

 

(Bloomberg; May 24) - Though natural gas remains a small and expensive component in China’s coal-heavy, air-polluting fuel mix, demand is rising faster than expected for domestic and imported gas. In April, consumption was 22 percent higher than the same month in 2016, and total consumption for the first four months of the year is up more than 12 percent, data from the National Development and Reform Commission show.

 

The results are encouraging analysts to upgrade their demand forecasts and may signal that the Chinese government is on track to reach its goal of getting as much as 10 percent of the country’s energy from gas by 2020. It’s also bolstering the outlook for hundreds of billions of dollars in possible investments by companies to build pipelines and liquefied natural gas export infrastructure to feed the growing Chinese market.

 

“China’s targets are looking more and more achievable,” said Laban Yu, head of Asia oil and gas equity research at Jefferies Group in Hong Kong. “It has nothing to do with China’s economy, or natural gas and coal prices. It’s policy driven, and it’s about whether the government is serious about doing what it says it will do.” China’s domestic gas costs more to produce and government-set prices are among the highest in the world, leaving no incentive to switch unless pushed by regulation.

 

China’s gas demand must grow 13 to 15 percent annually through the end of the decade to meet the upper end of the government’s target. But without more aggressive policies or lower prices, gas may end up a smaller part of the energy mix than forecast. “High gas prices are the root problem,” said Tian Miao, a Beijing-based analyst. “Barring extreme policy enforcement, the only way to consistently boost use is to lower prices.”

 

 

Newest LNG buyers in China join move toward shorter-term deals

 

(Natural Gas Daily; May 22) - China’s new LNG buyers are joining their global peers in seeking more flexibility and lower prices under shorter-term supply contracts, delegates heard at the China LNG & Gas International Summit & Exhibition in Beijing last week. A global oversupply of liquefied natural gas production capacity has caused upheaval in the decades-old trade of long-term contracts that link LNG prices to the cost of a barrel of oil and include destination restrictions to prevent reselling of contracted cargoes.

 

A string of private Chinese firms and smaller state-owned companies have emerged in recent years to import LNG cargoes independently of the state-run national oil and gas companies, adding to the changes underway in the marketplace. Among the budding importers in China are city gas distributors and power utilities, which have sought better prices and greater control over supply.

 

 

Sinopec starts work on China’s largest gas storage operation

 

(Reuters; May 24) - Sinopec said May 24 it has started building China's largest natural gas storage and logistics center, with the capacity to store up to 350 billion cubic feet of gas underground in Henan province in the central part of the country. The world's second-largest economy is investing heavily in infrastructure from pipelines to storage tanks as Beijing prepares to switch from coal-fired boilers and heating systems to gas or electricity in 28 of its smoggiest cities by October.

 

The storage facility is expected to open in May 2018, Henan's official government newspaper the Puyang Daily reported last week. Though the largest in China, almost doubling the country’s gas storage capacity of salt cavities and depleted gas reservoirs, the country lags far behind the United States, which has almost 4.4 trillion cubic feet of gas storage capacity. The new gas storage operation will be connected by pipelines to serve central China demand centers including Beijing and Tianjin.

 

 

India’s gas utility trading out its oversupply of U.S. LNG

 

(The Economic Times; India; May 22) - State-owned gas utility GAIL India has signed a first-ever time-swap deal to sell some of its contracted U.S. liquefied natural gas cargoes as it adjusts its supply portfolio to fall in line with domestic demand. Against a contracted annual supply of 5.8 million tonnes of U.S. LNG, the utility has been able to create a market for just under 4 million tonnes in India — and wants to sell the surplus gas to other buyers.

 

GAIL Chairman B.C. Tripathi said May 22 the company is to start receiving LNG from U.S. export projects next year. GAIL has a deal to buy 3.5 million tonnes a year for 20 years from Cheniere Energy’s terminal in Sabine Pass, La., and also has booked capacity for 2.3 million tonnes a year from Dominion Energy's terminal on Chesapeake Bay, Md. It has, however, time-swapped some of the cargoes to match its local needs.

 

Under the swap, it will take about 0.8 million tonnes of LNG from an unnamed trader this year to meet its needs, and in return will sell to the trader 0.6 million tonnes of its Sabine Pass gas next year when it does not need its full contracted volume. GAIL also signed a deal with Shell to take 0.5 million tonnes of its U.S. LNG, and is renegotiating price and timing of the 2.5 million tonnes a year it agreed to buy from Gazprom. GAIL is saddled with long-term deals for U.S. and Russian gas after it went on a contracting spree between 2011 and 2013 when the fuel was scarce and prices kept rising.

 

 

Sri Lanka will join growing list of LNG importers

 

(Hindustan Times; India; May 24) - India and Japan will join hands to set up a $250 million liquefied natural gas import terminal in Sri Lanka, the first collaboration between the two countries to counter China’s growing influence in the Indian Ocean island nation. Petronet LNG, India’s biggest gas importer, last year proposed setting up an LNG import facility on the Sri Lankan coast — the country’s first such terminal. Sri Lanka, however, wanted Japan to have a role in it, too.

 

“An agreement has been reached between the governments of India, Sri Lanka and Japan to set up the LNG terminal as a 50-50 joint venture by Petronet and a Japanese company,” Petronet CEO Prabhat Singh said. Japan has not identified the company that will form the joint-venture. Sri Lanka plans to build a 300-megawatt gas-fired power plant and also convert an oil-fired plant to gas after LNG imports start to arrive. LNG has become significantly cheaper in the past year and countries are switching their power plants to gas. Singh said the LNG terminal could take three years to build.

 

 

The Philippines continues move toward LNG imports

 

(The Manila Times; May 24) - The Philippines’ natural gas supply from its largest field is projected to last until 2024, pushing the country to join the growing list of liquefied natural gas importers, Energy Department Undersecretary Jesus Cristino Posadas said May 23. “We are working closely with legislators [to enact] a law declaring energy projects as projects of national significance and for the Philippine Department of Energy to develop a program for LNG infrastructure,” he said at an Asian oil and gas forum.

 

“We are also looking at LNG importation as an option to supplement or replace our local gas to ensure sustainable supply for power and eventually non-power applications,” Posadas said. The Philippines has talked for years of importing LNG to supplement domestic gas production to meet growing demand. The Malampaya field, which produces the majority of the country’s gas, started production in 2001 and has peaked at about 400 million cubic feet a day, 98 percent of which goes to power generation.

 

LNG-supplier Shell, Philippines power provider First Gen and other companies have been working toward development of LNG import terminals, and though Shell, in particular, is in the front-end engineering and design stage, none of the proposals have gone to construction.

 

 

Nova Scotia LNG hopeful sees stock sale as path forward

 

(Calgary Herald columnist; May 23) - For a ray of hope in Canada’s liquefied natural gas future, it might be best to look east rather than west. Last week, privately held Pieridae Energy announced a takeover of Quebec-based energy company Pétrolia, becoming the first publicly traded LNG hopeful in Canada. It’s a move intended to do two things: facilitate access to capital, while also giving Pieridae a gas-producing asset base.

 

Pieridae has the regulatory approvals for its proposed Goldboro LNG project in Nova Scotia. The plan all along was to become a fully integrated project, with gas-producing assets and an LNG export terminal. What sets Pieridae apart from other hopefuls is that it has a 20-year offtake deal with Germany’s largest utility Uniper, as well as a US$3.5 billion loan guarantee from the German government. If anyone doubts Europe’s interest in decreasing its dependence on Russian gas, this is a very good example.

 

Also in Pieridae’s favor is the transit time to Europe is six days shorter than from LNG export projects on the U.S. Gulf Coast. In addition to needing sufficient pipeline capacity for feed gas, what has been missing in Pieridae’s equation is money. Rather than try to raise funds as a private company, Pieridae saw publicly traded Petrolia with its gas assets and decided it was a winning combination. The plan is to raise $50 million from selling shares, with a final decision expected on the project in the first quarter 2018.

 

 

Anadarko gets out of the dry gas business

 

(World Oil; May 18) - Over the past year and a half, Anadarko has sold every dry gas property the company had in its portfolio, including tracts in the Marcellus Shale and East Texas. The company is officially done with dry gas, said CEO Al Walker. “We have felt for some time now that natural gas onshore in the U.S. is fairly abundant, to the point where we can’t see in our own portfolio how that competes with [investments in] oil,” Walker said at the International Petroleum Negotiators summit May 17 in Houston.

 

Walker said the U.S. gas market is oversupplied and will not move beyond $3.50 per thousand cubic feet, except during occasional periods of peak demand during cold winters. “I think I can say with some confidence that we’re as big a bear on gas that you can be in North America.” Although the company will not focus on producing dry gas, it will remain a heavy gas producer with associated gas production from its oil plays.

 

Walker said he disagrees with growing sentiment in the U.S. that the North American Free Trade Agreement should be dissolved, as it could be devastating to natural gas prices. “We send about 4 billion to 5 billion cubic feet of gas to Mexico every day. If that doesn’t flow to Mexico, you can shake hands for sub-$2 natural gas for quite a while,” he said. “It’s just a good example of how the U.S., working with Canada and Mexico, needs to be one energy market, and I’m hopeful our administration recognizes that.”

 

 

Power plant construction exceeds electricity demand in East, Midwest

 

(Bloomberg; May 23) - The glut of cheap natural gas from a single, gigantic shale basin straddling the Northeast, mid-Atlantic and Midwest has sparked a massive construction boom of power plants. Dozens have been built in the past two years alone. There’s just one problem: There isn’t nearly enough electricity demand to support all the new capacity. And as wholesale electricity prices plunge, industry experts are anticipating a fire sale of scores of plants in the region. Many, in fact, have already been sold.

 

“Everything in fossil fuels is for sale,” said Ted Brandt, CEO at Marathon Capital, a mergers-and-acquisitions adviser in Chicago. Drawing from abundant and cheap gas in the country’s most prolific shale field, the new plants are adding a gigantic amount of power generation — more than 20 gigawatts — to a region that arguably has more than it needs. The new gas-fired plants are also coming online at a time of market turmoil of departing Obama administration policies and incoming Trump administration policies.

 

Calpine — the highly leveraged power producer with 17 plants in the 13-state grid from Virginia to Illinois — is exploring a sale of its facilities. Advances in efficiency, reducing demand for electricity, are converging with the gas glut to depress the industry. Add in wind and solar, which are providing ever more energy, and the demand for new power plants looks even shakier. “It’s a gas-driven apocalypse in the power market,” said Toby Shea, a New York-based analyst at Moody’s Investors Service.

 

 

BP and partners plan $5.7 billion North Sea investment

 

(Bloomberg; May 22) - BP has started a project in the U.K. North Sea that will restore production halted since 2013 and help double the company’s output in the area by the end of the decade. BP and its partners budgeted $5.7 billion for the Quad 204 project, which involves building a new floating production facility and redeveloping the aging Schiehallion and Loyal fields. Output from Quad 204 will ramp up to 130,000 barrels of oil a day this year, the company said in a statement May 22. The producer plans to double its U.K. North Sea output to 200,000 barrels of oil equivalent a day by 2020.

 

Volumes from the region, one of the world’s most expensive areas for finding and extracting oil, have shrunk in the past decade as older fields deteriorated and exploration spending dropped with crude’s three-year price decline. The Schiehallion and Loyal fields stopped production in 2013 as the sites needed redevelopment, new wells, replacement of infrastructure on the seabed and a new production vessel.

 

The new ship, the Glen Loyal, is 36 percent owned by BP, which is the operator, 54 percent by Shell and 10 percent by partner Siccar Point. The partners intend to drill 20 new wells in the fields. Quad 204 is the third of seven new projects BP plans to start this year. The company will restore its total oil and gas production to about 4 million barrels a day by the end of this decade, a level it was at before the disastrous Gulf of Mexico oil spill in 2010 forced it to sell a third of its assets, CEO Bob Dudley said May 17.

 

 

Australia’s tax case against Chevron could go global

 

(Wall Street Journal; May 23) - A tax dispute between Australia and Chevron could cost the company billions of dollars and open a new front in global efforts to crack down on aggressive tax strategies used by multinational firms. The case deals with Chevron’s practice of financing its Australian operations by giving loans to its in-country subsidiary at interest rates much higher than its cost of funds. The arrangement, which Australia’s tax office says is illegal, boosts costs for Chevron’s Australia unit, reducing its tax bill.

 

Chevron will appeal last month’s court ruling upholding a 2015 order in favor of the Australian Taxation Office. If the ruling stands, Chevron would owe about $250 million in taxes, including penalties, for 2004 to 2008. But the ruling could cost Chevron far more if the principles are applied to the company’s more recent LNG export investments in the country, where it and several partners have spent more than $80 billion since 2009. Australia’s tax office is auditing Chevron over similar issues during that later period.

 

Should the same principles apply in more recent years, Chevron’s tax bill could jump by $150 million to $300 million a year, according to a Wall Street Journal analysis. Over a decade, that could reach $2 billion to $3 billion, depending on a number of factors, such as oil and gas prices and how long Chevron takes to repay the loans. “There’s an awful lot at stake with this ruling, not just for Chevron but for any intercompany lending in Australia and … around the globe,” said Pat Yarrington, Chevron’s chief financial officer. Several experts said this was the first tax ruling on this scale that they could recall involving the interest rates an international company charged to a subsidiary.