Low oil prices steal market share from natural gas in Asia
(Nikkei Asian Review; Feb. 23) - International prices for crude and heavy fuel oil used in power stations and industrial plants are on the decline. And as they become cheaper, they are stealing market share from natural gas in Asia. The spot price of Indonesian Minas, a type of crude used in power plants, has fallen by almost half in the past year. This has narrowed the price gap between Minas and natural gas. In response, Japan, India and other countries in Asia are switching from gas to crude and other alternatives.
This development could dampen demand for gas, which had been expected to rise. The price of heavy fuel oil is already the equivalent of $1 a barrel cheaper than liquefied natural gas, excluding the cost of transport. Last March, heavy fuel oil prices were higher than those for LNG. The spot price for heavy fuel oil, used in thermal power generation and for industrial purposes, is hovering around $4 per million Btu, according to Tokyo-based energy information provider Rim Intelligence.
In January, Japan's 10 major power companies' crude oil consumption rose, year-on-year. Their LNG consumption fell for the 11th straight month to around a five-year low for January. An official at a major Japanese utility said the company's consumption of heavy fuel and crude oil has risen, as it works to obtain cheaper fuel. Tokyo Electric Power and other utilities are likely switching to Minas from natural gas. In South Korea, cement makers and other industries are also switching from gas to heavy fuel oil.
LNG surplus could peak in 2019, analysts say
(Sydney Morning Herald; Feb. 24) - Coal's demise could be even more brutal than analysts currently anticipate, with LNG delivering the hammer blow. The global drive toward cleaner energy, falling power intensity and increasing power plant efficiency are among the factors weighing on thermal coal, consumption of which may have already peaked, Macquarie analysts said. "Our coal price forecasts all the way out to 2020 are thus below current spot prices," the global investment advisers wrote clients this week.
Australian thermal coal prices are down two-thirds from the 2011 peak of the commodity boom. The World Bank forecasts Australian thermal coal to nudge up a bit by 2020, but the outlook for one of Australia's biggest export items may be even gloomier — and a massive liquefied natural gas oversupply is the culprit. Oil and gas explorer Oil Search said Feb. 23 the global LNG market was already oversupplied as new projects in Australia and the U.S. ramp up exports and was only likely to return to balance in 2020.
Macquarie predicts the LNG market will be in surplus for the foreseeable future, rising to a peak oversupply of 70 million metric tons a year by 2019. "If a meaningful portion of surplus LNG manages to displace coal in regions with spare capacity (mainly Europe), coal's demise might even more brutal than we currently anticipate," the analysts said. The question is what happens to the surplus. One solution, Macquarie suggests, would be for some LNG ramp-ups not to happen or existing capacity to be shut in.
Eni plans investment decision this year on Mozambique LNG
(Reuters; Feb. 24) – Italy's Eni said Feb. 24 it has won approval from the Mozambique government to build its planned floating liquefied natural gas plant. The company, which aims to sell all the LNG to BP, is expected to make its investment decision this year, but has now overcome one of the biggest hurdles. The pace of developing giant gas export plants has slowed globally as liquefied natural gas prices have plummeted with oil, prompting many companies to delay funding decisions until market conditions brighten.
Eni is moving ahead in Mozambique despite the added challenge of using a relatively untested technology to ship the gas. Its floating LNG export plant would be moored above the Coral gas field, containing 5 trillion cubic feet of gas, in resource-rich waters off Mozambique. One of the world's poorest countries, Mozambique is hoping to pay for future prosperity with revenue from an estimated 180 trillion cubic feet of offshore gas in several fields.
Eni's plans include drilling six subsea wells and anchoring a floating LNG facility with a production capacity of about 3.4 million metric tons a year. The vessel would house gas production, liquefaction and storage, offloading the LNG to tankers that tie up alongside. Anadarko plans to build a larger onshore LNG export plant in Mozambique. Meanwhile, regional LNG rival Tanzania has struggled to match Mozambique's pace in getting its own industry off the ground, hamstrung by regulatory uncertainty and other factors.
First cargo leaves Cheniere LNG plant in Louisiana for Brazil
(Reuters; Feb. 24) - The long-awaited first liquefied natural gas exports from the Lower 48 states left Cheniere Energy's Sabine Pass export terminal in Louisiana on Feb. 24, a senior company executive said. That first cargo of about 3 billion cubic feet of gas will go to Petrobras in Brazil, Meg Gentle, executive vice president of marketing at Cheniere, said on the sidelines of the CERAWeek energy conference in Houston.
The cargo from the first liquefaction train at Sabine Pass is a test cargo. Gentle said the company was still commissioning the facility. "It's under Bechtel's control, they drive the schedule," she said, referring to the construction firm in charge of building the plant. “We'll be loading vessels over the next couple months," she said, noting the company has six LNG vessels under charter. Gentle said the average cost of chartering the tankers was about $45,000 per day. Liquefaction trains Nos. 2 through 5 are still under construction and will enter service between 2016 and 2019.
Gentle said start-up at Sabine Pass will help create a liquid and transparent global market for LNG. The fuel is typically bought and sold under long-term contracts or limited short-term markets at prices linked to oil. But with a large amount of new supply coming online from the U.S., Australia and elsewhere, LNG will increasingly be sold in expanded short-term markets, Gentle said. “I’m a believer that by 2020 we will see the industry sell … 50 percent on a short-term basis compared to 30 percent today.”
Energy secretary says U.S. LNG exports ‘a very big deal’
(CNBC; Feb. 24) - Amid the upheaval in the energy sector, natural gas is doing well while coal is struggling. You could say the natural gas market is flourishing, U.S. Secretary of Energy Ernest Moniz told CNBC on Feb. 24. "We are now perhaps at the 10-year mark of what has been a real natural gas revolution in this country," he said. "Gas is now the biggest supplier, [the] biggest fuel for electricity, overtaking coal … now getting into the [liquefied natural gas] export market."
U.S. coal production dropped 32.5 percent year over year in the week that ended Feb. 13, according to the Energy Information Administration. As to LNG exports, the secretary thinks the United States may be on its way to "probably … being among the very biggest exporters of natural gas in the world." The first shipment from a Gulf Coast plant pulled away from the dock this week. Moniz said he regards the start of U.S. LNG exports from the Lower 48 states as "a very big deal."
The surplus of U.S. shale gas production created the opportunity for multibillion-dollar liquefaction plants and export terminals to ship the gas to overseas buyers, though current market conditions are poor with too much gas chasing weakened demand.
B.C.’s Montney Shale play waits out improved market prices
(Alberta Oil; Feb. 22) - The liquids-rich Montney Shale gas play is already a fairly large player in Canada’s natural gas market, producing around 3.5 billion cubic feet of natural gas per day, or 25 percent of the Western Canadian Sedimentary Basin gas production. But it has the potential to be much larger. A recent joint study by the National Energy Board, Alberta Energy Regulator, B.C. Oil and Gas Commission and the B.C. Ministry of Natural Gas found that the Montney in northeastern B.C. holds about 449 trillion cubic feet of marketable gas and nearly 15 billion barrels of marketable natural gas liquids.
Major players like Shell, ExxonMobil and Malaysia’s Progress Energy have bought sprawling plots of land in the Montney in the hopes that new LNG export facilities on British Columbia’s West Coast would eventually provide access to higher international prices for their product. Actually building those facilities has been slow, however, amid regulatory delays and worries over a glut of new global gas supplies and low prices. But whatever gets built likely will be sourced almost entirely by Montney gas.
Meanwhile, Canadian producers are expecting low prices for an extended period under a flood of shale gas from the Marcellus in the northeastern U.S. With per-well costs between $4 million and $10 million in the Montney, compared to $6 million to $8 million in the Marcellus, according to a report from the Royal Bank of Canada, analysts believe the Montney will remain competitive despite an extended low-price environment. In the absence of any meaningful price-boosting volumes of LNG exports, the biggest threat to the Montney is medium-term low prices, which show no sign of lifting any time soon.
B.C. website lacks any LNG project work for contractors
(CBC News; Feb. 23) - It's an LNG opportunities website with no opportunities. The opposition party in British Columbia said the government has spent more than a million dollars to launch the LNG-Buy BC campaign and website — with nothing to show for it. "The website is very pretty," says New Democratic Party Leader John Horgan. "It's populated with pretty images, but when you click on any of the links you get zero."
LNG-Buy BC is supposed to connect people and business looking for opportunities in the LNG sector. The website was created at a cost of over $850,000, and former politician Gordon Wilson was appointed LNG-Buy BC Advocate at an annual salary of $150,000. LNG-Buy BC touts itself as "a platform that helps businesses discover new opportunities and partnerships," and promises to "takes the heavy lifting out of searching for business opportunities."
There is a long list of business that have registered on the site looking for work, but not a single company looking to hire or contract. The provincial natural gas minister, Rich Coleman, said although there are no LNG projects currently underway there are 20 being discussed. The government said Wilson has been working at connecting people to the LNG industry by touring communities that are proposed sites for gas projects.
Proposed Yukon Territory mine would run on LNG
(Mining.com; Feb. 21) - The proposed Casino copper-gold mine in Canada’s Yukon Territory passed a major milestone Feb. 18 with the announcement that the project will move to a higher level of environmental assessment. The open-pit mine would be the largest in the territory and would be powered by a 150-megawatt generating plant, fueled by liquefied natural gas trucked to the site from a liquefaction plant proposed in northeastern British Columbia.
The mine’s developments costs were estimated at $2.5 billion in 2014. In a press conference, the Yukon Environmental and Socio-economic Assessment Board said it will send the project on to its highest level of review. It's the first time that has happened in the 10 years the board has been in existence, CBC News reports. A panel of board members will evaluate the impacts on caribou, as well as tailings and waste management plans.
Owned by a subsidiary of Vancouver-based Western Copper and Gold, the mine is expected to produce over 400,000 ounces of gold per year and more than 200 million pounds of copper. Molybdenum and gold-silver bars would also be produced. A 2013 feasibility study said the mine could produce an average of 15 million pounds of molybdenum and 1.8 million ounces of silver per year during the first four years of production.
Qatar and Shell agree to joint venture to produce LNG as marine fuel
(Reuters; Feb. 22) - Qatar and Shell have agreed to develop liquefied natural gas as a marine fuel for use by the world's largest container shipping company, Moller-Maersk, Qatargas announced Feb. 22. Qatargas, the world's largest LNG producer, said the companies signed a memorandum of understanding that calls for the Qatargas 4 plant, a joint venture between Qatar Petroleum and Shell, to produce the fuel for Maersk Line.
Most shipping companies currently use heavy fuel oil, or bunker fuel, to run their ships, although LNG as marine fuel has been used by some ships in the past decade. LNG is being used more, in part because it more easily meets current and proposed emission rules. In a 2015 report, Norway-based DNV GL said 63 LNG-fueled ships were already operating globally with an additional 76 vessels being built that would use the fuel. In contrast, Maersk has about 600 ships, including some of the world’s biggest.
"This cooperation between Qatargas, Maersk Group and Shell represents an important step in developing LNG as a viable fuel for maritime transportation," Maersk's chief executive, Nils Smedegaard Andersen, said in a statement issued by Qatargas.
IEA predicts global oil surplus will not start decline until late 2017
(Wall Street Journal; Feb. 22) - New data from the International Energy Agency show that even if U.S. shale oil production is cut this year as expected and big oil nations are able to strike a deal to cap their output in the coming weeks, it could take years for the current crude glut to disappear. In its medium-term report, the agency — which tracks the global oil trade on behalf of industrialized nations — said the oversupply that has pumped up inventories worldwide will continue until at least the end of 2017.
It also predicted that U.S. shale oil production would drop sharply this year, which could lead to the glut shrinking in 2017. Crude prices have dropped by about two-thirds since 2014 on the back of rising U.S. production and a refusal by big producers like Saudi Arabia to curb supply. Low prices have driven U.S. producers to ease drilling, and members of the Organization of the Petroleum Exporting Countries and other producers are discussing measures to cap their production.
“Supply and demand will gradually rebalance by 2017, with a corresponding recovery in oil prices,” the IEA said. The agency said U.S. shale production is set to fall by 600,000 barrels a day this year and by a further 200,000 barrels a day in 2017. The IEA said that because of an expected global slowdown in production growth, worldwide oil inventories will increase by 100,000 barrels a day next year and fall by about 400,000 barrels a day in 2018. That compares with a build-up of 2 million barrels a day in inventories last year.
IEA warns investment cuts could mean oil supply risk in the future
(Financial Post; Canada; Feb. 21) – Growth in Canada’s oil sands is likely to stop after the projects under construction come online as heightened environmental concerns, lack of pipeline access and policy changes slow investment, the International Energy Agency warned. “We are likely to see continued capacity increases (in) the near term, with growth slowing considerably, if not coming to a complete standstill” after projects under construction are finished, the IEA said in its medium-term market report Feb. 22.
Canada is expected to raise its oil production by around 100,000 barrels per day this year with additional quantities of 285,000 and 220,000 barrels per day coming online in 2017 and 2018, respectively, as oil sands and East Coast projects start production. But beyond projects planned during the era of high oil prices, 2019 and 2020 will each see Canadian crude output rising by a mere 35,000 barrels per day.
The slowdown in Canadian production growth is part of a bigger global squeeze that poses supply security risks for the world as investments dry up. “It is easy for consumers to be lulled into complacency by ample stocks and low prices today, but they should heed the writing on the wall: The historic investment cuts we are seeing raise the odds of unpleasant oil-security surprises in the not-too-distant-future,” said IEA executive director Fatih Birol, launching the report at IHS CERAWeek event.
Deloitte calls 2016 ‘year of hard decisions’ for oil companies
(Oil & Gas Financial Journal; Feb. 16) - With more than $150 billion in debt on their balance sheets, nearly 35 percent of pure-play oil exploration and production companies listed worldwide, about 175 companies, are at high-risk of slipping into bankruptcy in 2016, according to a new Deloitte study. The outlook is almost equally alarming for 160 other companies that are less leveraged but cash-flow constrained.
“2016 will be the year of hard decisions. We could see E&P bankruptcies surpass Great Recession levels as companies struggle to remain solvent,” said John England, vice chairman and U.S. oil and gas sector leader at Deloitte. “Access to capital markets, bankers' support and derivatives protection, which helped smooth an otherwise rocky road for the industry in 2015, are fast waning. A looming capital crunch and heightened cash-flow volatility suggest that 2016 will be a period of tough, new financial choices.”
Seeing the cash crunch, exploration and production companies worldwide have saved or raised $130 billion since the oil price crash. Much of that has come from asset sales and issuing more stock. One of the key ways companies have managed to stay viable has been through reducing their production costs. Today, about 95 percent of production costs (lease operating expenses and production taxes) of U.S.-origin players is below $15 per barrel-of-oil equivalent, versus 65 percent in the second quarter 2014.
OPEC doesn’t know ‘how we are going to live together’ with shale
(Bloomberg; Feb. 22) - So what do the world’s elite energy minds talk about when they gather at Houston’s IHS CERAWeek energy conference? Here are some snippets from the first day, Feb. 22: “Can’t we all just get along?” Maybe not, said OPEC Secretary-General Abdalla Salem El-Badri. The group is struggling to co-exist with U.S. shale. "Shale oil in the United States, I don’t know how we are going to live together," El-Badri said. Shale drillers can boost output in response to price increases faster than anything OPEC has ever seen, he said. That complicates the group’s ability to prop up prices.
But there was some good news: Oil’s going back to $80 a barrel! The bad news: Not until 2020, according to the International Energy Agency’s medium-term outlook released Feb. 22. Meanwhile, low prices and investment cutbacks will take a toll. “The historic investment cuts we are seeing raise the odds of unpleasant oil-security surprises in the not-too-distant future,” IEA head Fatih Birol said.
Want to know why the acquisition boom hasn’t taken off in the oil and gas industry, weakened by low prices? Look to the heavy debt load, said Occidental Petroleum CEO Stephen Chazen. Under so-called change-of-control provisions, the debts of many U.S. drillers would have to be paid off by any company that acquires them. The specter of those large, upfront costs are discouraging takeovers, he said.