LNG spot-trade volumes increased in 2016
(Platts; March 27) - Pure LNG spot trading — trades where cargoes are delivered within three months of the transaction date — comprised 18 percent of total imported LNG volumes in 2016, an increase from 15 percent the year before, an industry group said March 27 in its latest annual review. Spot-trade volumes were estimated at about 47 million metric tons last year, up from 37 million in 2015, with the main buyers being China, India and Egypt, the International Group of Liquefied Natural Gas Importers said.
“Signs indicate an evolution toward a greater flexibility in [LNG] trade, and the commercial patterns are evolving as destination-free volumes increase and as new buyers and sellers join the market," the group said. With many longer-term LNG supply contracts due to expire in the coming years, the move toward more spot trading is likely to gather pace, industry group president Jean-Marie Dauger said.
"In order to respond to market changes and cope with the uncertainty of future supply and demand, LNG contracting strategies have grown in importance," he said. "In this respect, most buyers pay particular attention to flexibility … and price competitiveness," he said. "In a well-supplied market and given the significant quantities under long-term contracts that are due to expire in the medium-term, particularly in Japan, the share of spot and short-term volumes could increase further in coming years."
UAE sees renewable power as reducing need for LNG imports
(Bloomberg; March 27) - The United Arab Emirates forecasts that savings generated from switching half its power needs to renewable energy by mid-century will outweigh the investment costs. The Persian Gulf state plans to invest $150 billion in renewable power to 2050, weening the country in stages from its dependency on subsidized natural gas-fired power, Minister of Energy Suhail Al-Mazrouei said at a conference in Berlin. Clean energy sources will help it save $192 billion by 2050, he said.
The UAE leadership is “bullish” about achieving the goal after realizing that the nation can forgo subsidies in the switch to clean power from liquefied natural gas imports to fuel its power plants, Al-Mazrouei said. Sticking to the strategy will “save the environment and at the same time save us lots of money.” As the costs for solar power fall rapidly, Gulf and Middle East states are re-evaluating their power strategies, which currently rely subsidiaries for electricity generated with imported LNG.
In September, Chinese panel maker JinkoSolar and Japanese developer Marubeni won a tender for a solar plant in Abu Dhabi with a record-low bid of 2.42 U.S. cents a kilowatt hour. About $1 billion has been invested in utility-scale solar in the UAE since 2007. Middle East states need to break their reliance on subsidized gas power, where inefficiencies are endemic in the Middle East, Al-Mazrouei said. In future, the UAE will review every proposed LNG power project as a project that’s not subsidized, he said.
Anadarko looks to sign up customers this year for Mozambique LNG
(Upstream; March 27) - Anadarko Petroleum hopes to sign up customers for its proposed liquefied natural gas export facility in Mozambique by the end of this year as it eyes a possible global LNG supply gap after 2022. "We think [we have] the ability to potentially get the sales-and-purchase agreements we need done this year, and that would lead us into a market for project financing that could be quite strong later this year or next," Anadarko CEO Al Walker said at an energy conference in New Orleans.
Walker said those contracts would propel the project forward and pave the way for a final investment decision. "Consequently, today I feel more likely than not that we have market opportunities that we didn’t see a year ago for how we might see final investment decision being taken in what I call the intermediate future in Mozambique.”
Anadarko drilled the play-opening Windjammer discovery well offshore Mozambique about seven years ago. Since then, the company and partner Eni have discovered an estimated 190 trillion cubic feet of gas in the Rovuma basin. Eni recently brought in ExxonMobil as a partner in its development but investors have been frustrated with the slow pace of progress on commercializing Mozambique's gigantic gas reserves.
Gorgon starts production at third liquefaction train
(Reuters; March 28) - Chevron has started production from the third liquefaction unit at the Gorgon LNG project located off Western Australia, the company said March 28. Chevron is the operator of the $54 billion project that has three liquefaction trains with a combined production capacity of 15.6 million tonnes per year. First production from Gorgon began in March last year, but the plant has been plagued by numerous unplanned outages since then.
The Train 3 start-up could add to the existing supply glut in the Asian LNG spot market because some of the production volumes are not committed to buyers, common for plant start-up, a trading source said. Asian spot LNG prices have fallen 45 percent since early January to $5.40 per million Btu amid new production coming on stream in Australia and the United States.
Chevron holds a controlling stake of 47.3 percent in the project, while ExxonMobil and Shell each at 25 percent. The remaining stakes are held by Osaka Gas, Tokyo Gas and Japan’s Jera Co.
Kansai Electric will set up LNG trading unit
(Reuters; March 27) - Japan's second-biggest power utility, Kansai Electric, said March 27 it would set up a trading unit in Singapore next month to reinforce its trade of liquefied natural gas and win better deals. The move comes as Japanese utilities ditch older, long-term gas and coal supply contracts in favor of more short-term, opportunistic trading to offset a shrinking customer base.
"We've been considering to create a structure with more flexibility to be able to buy LNG at low prices and sell LNG when needed as spot trades are becoming more important to reflect change in demand in an era of real competition," Kansai Electric said in a statement. By building a foothold in Singapore, the center of Asian LNG sellers, buyers and traders, Osaka-based Kansai Electric wants to gather information and increase direct trades to strike deals at right prices and at right timings, the company said.
Japan's Jera Co., a fuel joint venture of Tokyo Electric and Chubu Electric, already has a coal-trading unit in Singapore, and the unit is set to buy the coal and freight trading business of French state-controlled utility EDF by early April.
U.S. LNG exports could top 6 bcf a day by end of 2018
(Reuters; March 29) - The last time the United States was a net exporter of natural gas was in 1957, when Dwight Eisenhower was president. That should change in 2018 when the country is expected to become the world's third-largest exporter of liquefied natural gas. By the end of next year, U.S. LNG export capacity in the Lower 48 states will top 6 billion cubic feet per day, or 8 percent of the country's domestic consumption, up from zero at the beginning of 2016 — enough gas to fuel 30 million U.S. homes.
That growth in U.S. LNG exports is set to transform world markets. Just a decade ago, before the shale revolution, the U.S. was expected to become a growing LNG importer, not an exporter. Instead, the U.S. will become a competitor to the global gas powers by offering cheaper and more flexible cargoes and a more politically palatable supplier for buyers than Russia. The increased supply of North American LNG could bring more predictability to pricing through the development of more transparent trading markets.
The U.S. started to export LNG from the Lower 48 states when the Sabine Pass terminal in Louisiana, built by Cheniere, opened in February 2016. Five additional terminals are expected to open by 2020. Analysts said surging LNG exports — the biggest driver of North American gas demand — could boost U.S. natural gas prices, which have been low in recent years. However, higher prices would also encourage energy firms to boost production to record levels, which could keep any price hike small.
ConocoPhillips sells off most of its Canadian assets for $17.7 billion
(The Canadian Press; March 29) – Calgary-based Cenovus Energy said it will spend $17.7 billion to acquire most of ConocoPhillips’ Canadian assets, making the Houston-based company the latest international player to reduce its exposure to the oil sands. The deal includes ConocoPhillips’ 50 percent interest in the FCCL Partnership, an oil sands venture between the two companies in northern Alberta, as well as the majority of ConocoPhillips’ Deep Basin conventional assets in Alberta and British Columbia.
The price includes $14.1 billion in cash plus shares of Cenovus stock, making Conoco into Cenovus’ largest shareholder with about a 25 percent stake. Acquisition of the ConocoPhillips Canadian assets will more than double Cenovus’ daily production of barrels of oil equivalent, which last year totaled about 270,000 barrels a day from the oil sands, conventional oil and gas. The acquired ConocoPhillips’ assets are forecast to produce approximately 298,000 barrels of oil equivalent per day in 2017. The deal will turn Cenovus into Canada’s third-largest oil sands producer.
“Given that we already fully operate the (joint-venture) assets, we are effectively doubling our oil sands exposure with no integration risk,” said Brian Ferguson, president and CEO of Cenovus. “This is an easy fit," said Michael Kay, an analyst at Bloomberg Intelligence in New York. “ConocoPhillips is focused elsewhere, and Cenovus has made it a priority to expand in the oil sands. It’s mostly a domestic industry now."
Maryland Legislature approves statewide ban on fracking
(EnergyWire; March 28) - The Maryland Senate approved a statewide ban on hydraulic fracturing for natural gas March 27, virtually guaranteeing it will become state law. The state House of Delegates approved the bill earlier this month, and Republican Gov. Larry Hogan said March 17 that he approves of the idea after previously saying he wanted to allow gas development under tight controls.
The 35-10 vote will make Maryland the second state in the Marcellus Shale gas field to ban hydraulic fracturing, the technique that made it possible to produce oil and gas that is trapped inside dense underground rock. New York Gov. Andrew Cuomo used an executive order to block fracking in 2014. Environmentalists cheered the Maryland vote, while the oil industry said it was misguided and would hurt the state's economy.
Maryland consumers have benefited from the big increase in gas production in the Marcellus Shale, which has turned Pennsylvania, Ohio and West Virginia into gas-producing powerhouses. Maryland’s gas consumption has risen 16 percent since 2006, while the price for consumers has fallen 26 percent and emissions of carbon dioxide fell 39 percent between 2006 and 2014, according to the American Petroleum Institute.
B.C. makes progress on pipeline deals with First Nations
(Platts; March 27) - The British Columbia government has entered into 64 gas pipeline benefits agreements with 29 eligible First Nations — more than 90 percent of the agreements that are needed along the routes of four pipelines that would carry gas to proposed liquefied natural gas export terminals along the province's western coast. The agreements are part of the province's effort to partner with First Nations on LNG opportunities, the Ministry of Aboriginal Relations and Reconciliation said March 23.
The four pipeline projects are: Prince Rupert Gas Transmission Pipeline, Coastal GasLink Pipeline, Westcoast Connector Gas Transmission and the Pacific Trail Pipeline. Under the agreements, the First Nations would allow the pipeline to traverse their traditional territories, to which they hold aboriginal rights and title. In exchange for entering into agreement with the province, each First Nations group would receive "milestone" payments at certain points along the process, a ministry spokesman said.
The payments would include an initial payment and subsequent payments when the pipeline starts construction and when it goes into production, as well as ongoing benefit payments for the life of the project, a provincial spokesman said. None of the pipelines, however, have started construction as none of the proposed LNG export terminals have received an investment commitment by developers. LNG project developers, the province and hopeful pipeline builders continue waiting for investment decisions.
First Nation agrees to benefits agreement for proposed LNG terminal
(Platts; March 27) - The Huu-ay-aht First Nation and Steelhead LNG on March 27 agreed to develop and co-manage Steelhead's proposed Sarita LNG project on Vancouver Island. The agreement was reached after a referendum held among Huu-ay-aht members on March 25 passed with a 70 percent vote in support. The project, however, is still in the preliminary engineering and conceptual design stage. It’s one of several LNG export terminals proposed for the British Columbia coast.
In a conference call with reporters, Steelhead LNG CEO Nigel Kuzemko said gas for the plant would be sourced from Western Canada, with an undersea pipeline needed to move the gas from the mainland to Vancouver Island. Although the parties did not make the details of the pact public, they said that under the development agreement the Huu-ay-aht, a First Nation band of about 750 people, would have an equity stake in the LNG project on the western shore of Vancouver Island, about 85 miles northwest of Victoria.
In addition, the Huu-ay-aht would have a seat on a board that will oversee the development to ensure the construction and related facilities are done in a way that respects the land and environment and the cultural values of the people, said Derek Peters, head hereditary chief of the Huu-ay-aht First Nation. On Feb. 19, Huu-ay-aht members approved the purchase of the Sarita Bay lands, owned by Western Forest Products, providing a site for the LNG project.
Columnist explains Australia’s low tax revenue from LNG projects
(Bloomberg columnist; March 26) - Between Australia’s liquefied natural gas exporters that want high prices for the best profit margin and domestic consumers that want cheaper electricity bills, something's got to give. It's left to government — which relies on the first group for revenue and the second for votes — to divide the baby. The government is holding an inquiry into how tax revenue on some oil and gas production has slumped even as output has soared with years of an LNG investment boom — while all that gas going out as exports has pushed up prices for domestic consumers.
Low global prices have caused energy companies to book huge write-downs on LNG projects, and the debacle provides a good test case of what's gone wrong. Australia’s Petroleum tax and royalty revenues per oil-equivalent barrel came to about 4.2 percent of the local price of crude — the lowest share since 1990, and well below the 25-year average of 10.4 percent. The dip is unlikely to be a blip. Due to the way the government allows capital expenses to be deducted before a project makes a taxable profit, it could be decades before the country starts to receive a better return on its mineral wealth.
Australia is unusual in choosing to take a cut of petroleum wealth not through royalties levied on production, but through taxes on income. The explicit intention is to encourage companies to develop fields that would otherwise be too marginal, by promising a more lenient floating charge on profits rather than a fixed charge on output. Australia's high costs and distant location mean it wouldn't be an attractive investment destination if not for these incentives. By transferring a share of risk from petroleum companies to its own budget, Australia appears to have done a favor to big business.
Saudi Arabia cuts tax rate on its national oil company
(Reuters; March 27) - Saudi Arabia's government has cut the income tax rate paid by national oil giant Saudi Aramco to smooth the company's initial public offering of shares next year, expected to be the world's largest equity sale. A royal decree on March 27, retroactive to Jan. 1, set a tax rate of 50 percent for Saudi Aramco. Previously, Aramco had paid an 85 percent tax plus a 20 percent royalty levied at a different stage. The royal decree did not mention the royalty.
The step appeared likely to reduce Aramco's tax burden by as much as tens of billions of dollars, which could make the firm’s stock offering much more attractive to private investors. Saudi authorities had been considering such a change for months, sources told Reuters. "It shows the Saudi government is serious about the IPO of Saudi Aramco, and this is a very strong message to those who doubted that the government will follow through on taking Aramco public,” an oil industry executive said.
The government aims to sell up to 5 percent of Aramco, listing the shares in Riyadh and at least one foreign exchange, to raise cash for investment in new industries as the kingdom seeks to diversify its economy beyond oil in an era of cheap crude. Saudi Arabia, which is struggling to close a budget deficit due to cheap oil that totaled $79 billion last year, obtains more than 60 percent of its income from oil, so the tax change could affect its finances. However, analysts said the change might not have a big impact since tax revenue was expected to be replaced by dividend payments from Aramco.
Some Mideast producers raise money by pledging future oil output
(Wall Street Journal; March 27) - Some Middle Eastern oil producers are considering taking money upfront against future production, as the fall in oil prices pushes them to look at new ways to plug budget holes. In this type of pre-export finance, companies or countries pledge revenues from future sales to banks and trade houses that lend money to them. Oman recently closed its first crude-export finance, in which banks paid the country $4 billion in exchange for revenues from future oil production over five years.
Saudi Arabia also is considering such finance, bankers said. Mideast governments have spent extravagantly for years with high oil prices. But after almost three years of weaker prices, governments now need to borrow. Bankers say there has been an increase in interest for such finance. “Ten to 15 years ago, you didn’t see Middle Eastern producers coming into the structured trade commodities finance market to raise financing, but now they are,” said Irfan Afzal, a director of syndication at the African Export-Import Bank.
Still, some countries may be reluctant to use this type of finance because it entails handing over future royalties from a national resource. “It’s the crown jewels of the country, and you don’t pledge your crown jewels as a matter of principle,” said Kris Van Broekhoven, head of commodity trade finance at Citibank. Such financing, however, tends to be cheaper than an unsecured bond. That is because banks can typically take comfort in a producer’s record of exporting fuel. The risk to the borrower is that if oil prices fall dramatically, they may have to extend the repayment term or pump more oil.
Russia wants higher oil prices before resuming Arctic exploration
(Bloomberg; March 28) - Russia can wait for a sustained recovery in oil prices before drilling again in Arctic waters, relying for now on less costly regions even as rival producer Norway accelerates development of its northerly fields. “We estimate production costs for the Russian Arctic offshore in the range of $70 to $100 a barrel,” Energy Minister Alexander Novak said by email. These reserves “are our backup stock,” he said March 28 at the International Arctic Forum in Russia’s Arkhangelsk.
As Russia waits, Norway’s Arctic waters may host a record number of wells this year following recent discoveries, new government license awards and efficiency gains. Russia plans to boost exploration in the Arctic Barents and Kara seas from 2019, according to Novak. In the meantime, the cost of offshore development could fall as Russian companies adopt new technologies, he said.
“Offshore Arctic is interesting but it needs to be commercially competitive,” David Campbell, president of BP’s Russia business, said in an interview at the Arkhangelsk forum. “Its reserves, I am confident, will be there for future generations,” he said, commenting on the general prospects for development. Russia has almost 60 percent of its known hydrocarbon resources in the Arctic and has spent about $100 billion on energy projects in the region over the past decade.