Excess supply expected to hold back global LNG prices
(Western Australia Business News; Feb. 26) - The global LNG market could soon be in sharp oversupply, with Australia contributing about a third of that excess in what will be a buyers’ paradise. LNG spot prices could fall dramatically over the next few years, said Fereidun Fesharaki, who has led his own international energy consulting firm for more than three decades. He made his comments at the International Association for Energy Economics Asian conference at the University of Western Australia.
A key driver, Fesharaki said, was that although the vast majority of LNG due to come on stream was currently contracted, most of those contracts are not to end users. Instead, a large portion is contracted to companies that built production portfolios to deliver to clients, acting as intermediaries, some of which do not have buyers for all of their gas. That LNG would then be dumped into the spot market, leading to a substantial fall in world prices, he said.
Fesharaki estimated that almost 60 percent of the volume under construction in the U.S. was not contracted to end users — up to 40 million tons a year. Australia’s excess could range up to 32 million tons. Fesharaki said he did not expect demand growth to have much impact in absorbing the excess. Demand in Japan was declining, he said, as in South Korea, while China was flat. There is modest growth in India. “Very bad things will happen in the next two or three years,” he said. “In this market, something has to give. … Until you get to the late 2020s, you won’t have any kind of supply issues.”
Anadarko slows down spending on Mozambique LNG
(The Mozambique Natural Resources Post; March 2) - Texas-based Anadarko said Feb. 26 it will slash its 2016 capital spending by almost 50 percent and expects minimal funding for its proposed Mozambique LNG project during the year as it works toward a final investment decision on the venture. The company still needs to secure legal and contractual frameworks with the Mozambique government, long-term sales contracts and project financing, the company said in a statement.
Anadarko has said it will allocate just minimal funding this year to the $20 billion Mozambique development, which includes huge offshore gas reserves and an onshore liquefaction plant and export terminal. The company has already selected an engineering and construction consortium consisting of U.S.-based CB&I, Japan’s Chiyoda and Italy’s Saipem for initial development of the LNG plant with two liquefaction trains and 12 million metric tons per year of output capacity.
Last quarter, the company spent $21 million in Mozambique. Anadarko made its first discovery in the Offshore Area 1 of the deepwater Rovuma Basin in 2010. Together with its partners Anadarko has discovered more than 75 trillion cubic feet of recoverable gas resources in Offshore Area 1.
Chevron reports Angola LNG shipments to restart second quarter
(Natural Gas Africa; Feb. 26) – Angola’s sole LNG plant is expected to ship its first export cargo in two years during the second quarter of 2016, operator Chevron reported in a filing with U.S. stock regulators. Angola LNG opened in mid-2013 at a cost of some $10 billion but shut soon afterwards for repairs due to a series of technical faults. Then a rupture in its flare line forced a lengthy shutdown in April 2014. Work on plant modifications was completed early this year and re-commissioning of the plant began.
The project is owned by Chevron at 36.4 percent; Angola’s Sonangol, 22.8 percent; and BP, Italy’s Eni and France’s Total at 13.6 percent each. Neither Chevron nor Angola LNG have divulged the cost of repair work undertaken since 2014. At full capacity, the plant would be capable of producing about 5 million metric tons of LNG per year from its single liquefaction train (almost 250 billion cubic feet of natural gas).
Tokyo Gas signs up for more from Cameron LNG in Louisiana
(Reuters; March 2) - Tokyo Gas, Japan's biggest city gas supplier, said March 2 it has signed an agreement with a unit of Mitsubishi to buy about 200,000 metric tons of liquefied natural gas per year from the Sempra-led Cameron LNG export project in Louisiana for 19 years starting in 2020. Prices for the three cargoes per year will be linked to the U.S. natural gas Henry Hub index, plus a liquefaction charge. Mitsubishi is a partner in the Cameron project and an original customer for plant capacity.
This marks the second purchase of Cameron LNG for Tokyo Gas, which has already agreed to buy 520,000 tons per year from Mitsui & Co., another of the plant’s equity investors. Mitsui and Mitsubishi each hold a 16.6 percent stake in Cameron project, which is under construction and scheduled to start operations in 2018. The three-train liquefaction plant will have a maximum capacity of 12 million metric tons per year, of which the two Japanese partners will control a combined 4 million tons.
LNG needs different pricing mechanism, Platts columnist says
(Reuters column; Feb. 29) - In theory, these should be great days for the liquefied natural gas industry as new plants start up to supply the clean-burning fuel to energy-hungry markets across rapidly developing Asia. But in reality the industry is facing uncertainty as low prices damage the economics of multibillion-dollar investments and the expected demand growth fails to materialize. There is no single villain. Rather, there are several factors hurting the industry's fortunes and casting doubts over whether natural gas and LNG will ever see the golden age predicted a few years ago.
The main obstacle for LNG in Asia appears to be price, not just that it's higher than competing fuels but also the way it's calculated. Most of the LNG supplied into Asia is priced on long-term contracts, indexed to an average price of oil. What this means is that LNG prices take longer to adjust to changes in the prices of oil and coal, providing a head start to those competing fuels when utilities make purchasing decisions.
Japan's LNG imports, including term and spot cargoes, landed at an average cost of $7.78 per million Btu in January. This was down 48 percent from a year ago, which looks like a big drop versus a 34 percent drop in oil over the period. But oil's big price decline was in 2014, when it plunged 48 percent. In contrast, Japan's LNG prices fell a mere 9.9 percent in 2014. This shows that the drop in the price of LNG took far longer to come through than it did for oil. What is becoming increasingly clear is that LNG needs a different pricing mechanism to be viable in the longer term.
Chinese buyer signs second non-binding deal for Australia LNG
(Sydney Morning Herald; March 1) - Origin Energy has struck a preliminary deal to sell liquefied natural gas to emerging Chinese buyer ENN Energy Holdings, looking to maximize production from its share of the $24.7 billion Australia Pacific LNG venture in Queensland. The non-binding agreement for the sale of 500,000 metric tons of LNG a year to ENN's trading arm for five years would start in 2018 or 2019, after completion of a gas import terminal being built by ENN, Origin said March 1.
It marks the first deal Australia-based Origin has signed to sell LNG as a stand-alone company, outside the sales contracts struck by the APLNG venture (a partnership of ConocoPhillips, Sinopec and Origin). APLNG shipped its first cargo in January. Origin said that as LNG markets strengthen in the future, it has the option of bringing forward the development of its East Coast resources such as the Ironbark coal-seam gas field in Queensland, which could be processed through existing infrastructure.
ENN, one of China's largest distributors of natural gas, in January signed a similar non-binding deal to buy LNG from Chevron's Gorgon LNG project in Western Australia, which is in the process of starting production.
Natural gas sessions at conference focus on hope for demand growth
(Calgary Herald; Feb. 27) - Oil prices dominated hallway chatter at the IHS CERAWeek conference in Houston, and there wasn’t much hope expressed for a lift in natural gas prices, either. The only difference relative to oil-weighted producers might be that natural gas-focused companies have had more time to become accustomed to operating in a low-price environment.
And though the first cargo of liquefied natural gas left the U.S. Gulf Coast last week, destined for Brazil, LNG exports will not be enough to boost natural gas prices in North America. That must come from increased use of natural gas for power generation, transportation and petrochemical manufacturing. It’s therefore not surprising that natural gas sessions at CERAWeek were mostly focused on the consumption side of the equation and how the commodity will fit in the transition to a low-carbon future.
Following the agreement reached by 190 countries last December to decrease global carbon emissions, gas is set to play a critical role in that effort. “Gas is becoming a hot commodity, gaining a bigger share of power generation,” said Alexander Medvedev, deputy chairman of Russia’s Gazprom, who called it a triple-A commodity: abundant, available and affordable. “Gas is still seen as the fuel of the new century.” Short term, however, things are tough, as the oversupplied market is knocking down prices.
LNG project cancellation in B.C. ends hopes for lower local gas prices
(Terrace Standard; Terrace, BC; Feb. 29) - While the cancellation of the Douglas Channel LNG project proposed for Kitimat, B.C., will have an economic impact on its partners and on the overall prospect of the province’s energy industry, local natural gas consumers will take the biggest hit, said Robin Austin, member of the legislative assembly for Skeena. That’s because there is now no relief in sight to the high prices charged to deliver gas to local businesses and homes.
Those prices would have come down if Douglas Channel LNG began operations, as it would have used all of the surplus capacity of the Pacific Northern Gas pipeline that serves the region. Douglas Channel LNG’s payments to the pipeline operator would have reduced the prices the local gas utility charges its business and residential customers. “When I tell people down here in Victoria what we pay for gas … they just can’t believe it,” Austin said.
The elected officials said he sees no solution to high gas prices because Pacific Northern Gas must pass along its maintenance and other costs to its limited customer base. PNG’s rates in this region are higher than anywhere else. The most current residential delivery rate in the area is about $13 per 1,000 cubic feet of gas. On the lower B.C. mainland, FortisBC, that region’s gas utility, charges residents about $5.
More than half of public comments back LNG project at Prince Rupert
(Vancouver Sun; Feb. 29) - More than half of the 600 people who have commented on a draft federal review of the proposed Pacific NorthWest LNG project are in favor of it being built. Comments have poured in on the report, which concluded last month the project near Prince Rupert, B.C., would result in an increase in greenhouse gases and would harm porpoises, but not adversely affect salmon.
The public has until March 11 to comment, after which the Canadian Environmental Assessment Agency will produce a final report and recommendations. The federal government has the final say on the project, which has an estimated cost of $36 billion if its pipeline and development costs to produce gas in northeastern B.C. are included in the price tag. The project sponsor, a consortium led by Malaysian state-controlled Petronas, has not yet made a final investment decision on the LNG export project.
A tabulation by The Vancouver Sun found that 57 percent of those who have submitted comments support the project, while 40 percent were opposed or had major concerns about environmental effects of the project, particularly on salmon. In some cases, opposition was centered on the project’s Lelu Island location. Lelu Island has been a particular contentious aspect of the project over concerns the development will harm juvenile salmon that use eelgrass beds on Flora Bank, adjacent to the island.
Industry turns to unused rail tank cars to store surplus oil
(Wall Street Journal; Feb. 28) - The U.S. is so awash in crude oil that traders are experimenting with new places to store it: empty railcars. Thousands of railcars ordered up to transport oil are now sitting idle because current ultralow crude prices have made shipping by train unprofitable. Meanwhile, traditional storage tanks are running out of room as U.S. oil inventories swell to their highest level since the 1930s. Some industry participants are calling the new practice “rolling storage” — a landlocked spin on the “floating storage” producers use to hold crude on oil tankers when inventories run high.
Energy Midstream, a trading company based in The Woodlands, Texas, stored an ultralight oil known as condensate on Ohio railcars last month for about 15 days before shipping it to a buyer in Canada. Dennis Hoskins, a managing partner at Energy Midstream, said there are so many unused tank cars that he is constantly hearing from railcar owners hoping to put them to use. “We get offers every day for railcars.”
The use of railcars for storage could be limited by the cost of track space and safety and liability fears. Railroads and users face responsibility for leaks or other mishaps. “I don’t want the liability,” said Judy Petry, president of Oklahoma rail operator Farmrail System. Still, the oil has to go somewhere. The cheapest form of storage — underground salt caverns — can cost 25 cents a barrel each month, while railcar storage costs about 50 cents a barrel and floating storage can cost 75 cents or more. The cost estimates don’t include loading or transportation. Railcars hold between 500 and 700 barrels of oil each.
Global oil glut fills tankers waiting offshore Europe
(Wall Street Journal; Feb. 29) - Up to 50 oil tankers are waiting to unload cargo in the port of Rotterdam, the highest number since 2009 and another sign that, amid a glut, crude is struggling to find a home. The unusually high number of ships idling outside of Europe’s busiest port comes as onshore tanks around the world brim with crude and products like fuel or jet oil. That has sent buyers and sellers scrambling to find storage, using tankers and even empty railcars in the U.S. to stash the surplus.
The glut is affecting shipping in other ways, as producers send tankers carrying oil and oil products from the Middle East on longer routes to Europe to give their cargoes more time to find buyers. That is bad news for the oil market, adding further pressure on a commodity that has fallen to around $30 from more than $100 a barrel in 2014. There are currently between 40 and 50 tankers anchored in the waters outside Rotterdam, more than twice the usual number, said Sjaak Poppe, spokesman for the Dutch port.
Despite signs that consumers are taking advantage of low prices and using more oil products, analysts say the world is still producing more than a million barrels above demand a day. The glut in Europe is diverting ships to take longer voyages, according to the U.S. Energy Information Administration. Ships coming from the Middle East and India can take a 15- to 20-day transit through the Suez Canal or a 30- to 40-day journey around Africa’s southernmost point. With onshore storage near its limits and traders needing more time to find buyers, cargoes are increasingly opting for the longer route.
Quebec goes to court for provincial review of TransCanada oil line
(Montreal Gazette; March 1) - The Quebec government filed for an injunction March 1 to press TransCanada to follow the province’s environmental process as it works toward its Energy East pipeline. Environment Minister David Heurtel announced the filing in a news conference, saying the province will ask the court to order the company to halt its pipeline project until it has complied with the environmental laws in place. The 2,800-mile line would move Alberta oil sands production to Canada’s East Coast.
The court action doesn’t indicate whether the province agrees with the project or not, Heurtel said. Back in 2014, the government asked TransCanada to submit a pre-project proposal for evaluation by the Quebec Ministry of Environment. As part of that process, the company is supposed to conduct environmental impact studies. But TransCanada said it doesn’t need to follow the province’s rules since the line is a cross-Canada project and it will follow federal rules set out by the National Energy Board.
Heurtel said he has sent two letters to TransCanada since 2014, asking it to comply with the province’s request, but has not received any communication from the company. Regardless, Quebec will hold environmental hearings into the project starting next week, without the impact studies usually required. The $15.7 billion Energy East project would serve refineries in Montreal East and south of Quebec City on its way to an export terminal on the Atlantic Coast.
B.C. holds monthly oil and gas lease sale — but no one bid
(Alaska Highway News; Fort St. John, BC; Feb. 26) - The B.C. Ministry of Natural Gas Development put up two drilling licenses and three parcels of land at its monthly petroleum and natural gas rights public tender Feb. 24 — and not one sold. For the first time in history, the B.C. government is walking away from an oil and gas land sale with $0 on the ledger. It's another sign of the dire toll that low prices and market uncertainty are exacting on the B.C. oil and gas industry.
"I can't find anyone who can remember a zero-dollar land sale," said Energy Services BC director Art Jarvis. "It's very indicative of what 2016 is going to be like. There's all sorts of indicators in the last little while that have been frightening people in business." Rights to drill for gas are leased for terms of five to ten years. The land sale typically accounts for the majority of the province's oil and gas revenues, with gas royalties making up the balance.
Ten of B.C.’s top 25 sales came in 2008 — a banner year for the industry. The best-ever sale was July of that year, when the province leased $610 million in land and drilling rights. In January of this year, the sale netted just $200,000, continuing the trend of 2015 which was among the worst years on record. Income from earlier sales continue to prop up the province's oil and gas revenues, but those funds are projected to shrink unless significant progress is made toward B.C.’s liquefied natural gas export industry.