FERC rejects application for LNG project in Coos Bay, Ore.
(The Oregonian; Portland; March 11) - Federal regulators have rejected plans for a liquefied natural gas terminal in Coos Bay, Ore., and an accompanying gas pipeline. The Federal Energy Regulatory Commission on March 11 denied applications for the Jordan Cove Energy Project, about 100 miles north of the California border, and its feeder gas pipeline. FERC said the line would have “adverse effects” on landowners: “The more adverse impact a project would have on a particular interest, the greater the showing of need and public benefits required to balance the adverse impact.”
The pipeline would run 230 miles across Oregon to Coos Bay, enabling the delivery of U.S. and Canadian gas to the plant for liquefaction and loading aboard tankers for shipment to overseas buyers. Building the pipeline would affect nearly 160 miles of private lands and 630 landowners, FERC said. Multiple landowners have voiced worry about losing property value and business productivity to the pipeline. The commission worried some lands would need to be acquired through eminent domain.
FERC’s rejection came with a caveat: The project sponsors are free to reapply and the commission would consider the plans if they can demonstrate "a market need" for their product. The project's supporters touted the $7 billion economic boost it could bring to Oregon, while opponents voiced environmental and safety concerns. FERC approval is required to build and operate the LNG plant and gas pipeline.
Developer has no customers for LNG project in Oregon
(Financial Post; Canada; March 10) - A Canadian company working toward building a liquefied natural gas export project on the U.S. West Coast has yet to sign up its first customer for LNG cargoes. Calgary-based Veresen executives said during a March 9 earnings call that the company continues working to find customers for its Jordan Cove LNG project in Oregon, which would liquefy Canadian and U.S. gas for export.
“We won’t be in a position to go to notice to proceed (until after the middle of) this year,” Veresen CEO Don Althoff said on the company’s fourth-quarter conference call. He did not say when the company would sanction its multibillion-dollar project. Meanwhile, the Federal Energy Regulatory Commission on March 11 rejected the project’s application. The plant is designed to produce 6 million metric tons of LNG per year at a site in Coos Bay, Ore., about 100 miles north of the California border.
In February, AltaGas announced it was shelving its Douglas Channel LNG plant indefinitely because the company was unable to find customers in Asia for the gas. The small plant — 550,000 metric tons of LNG per year — was proposed for Kitimat, B.C.
Osaka Gas says its LNG demand will remain flat the next five years
(Platts; March 10) - Japan's Osaka Gas expects its annual LNG consumption to remain virtually the same at around 7 million metric tons for the next five years due to growing competition in the retail market and limited gas sales growth going forward, the gas utility said March 10. In its five-year supply plan, Osaka Gas said its LNG use is expected to be at 6.997 million tons in the fiscal year 2020-2021 (April through March).
Consumption is expected to come in at 7.033 million for 2016-17 and 6.756 million tons in FY2015-16, which ends this month. A spokesman for Osaka Gas said the limited consumption growth underscores declining population in the Kansai area it serves and the planned deregulation of the retail gas market due in 2017. Osaka Gas expects an average annual growth of just 1 percent in its gas sales the next five years.
To offset its slowing domestic gas sales, Osaka Gas is gearing up for overseas energy businesses including investments in upstream projects. It also plans to boost its electricity business. Osaka Gas last month announced that it plans to jointly build with Idemitsu Kosan a 1.8-gigawatt, gas-fired power plant in Himeji, Hyogo prefecture. It aims to start operations in the early 2020s.
Natural gas liquids allow Qatar to make money at low LNG prices
(Forbes; March 11) - More evidence came this week that liquefied natural gas markets are undergoing profound and permanent structural changes amid an ongoing global supply glut for the fuel. China National Petroleum Corp. Chairman Wang Yilin on March 9 said his company is looking to renegotiate the pricing method on its LNG long-term supply contract with Qatar. Wang’s comments offer growing evidence that LNG markets are in a state of change for which there will be no turning back.
These changes come amid two important developments. First, the plunge in global oil prices of around 70 percent since June 2014. Since most LNG in the Asia-Pacific region is linked to the price of oil, the bloodbath in global oil markets has hit LNG hard. Of course the other major driver is the ever-increasing LNG supply glut. Global LNG output last year reached 250 million metric tons per year and is projected to reach 330 million tons by 2018, mostly from new projects coming online in Australia and the U.S.
However, one should not feel too concerned for the Qataris: They produce the cheapest gas in the world. The break-even price for their gas is zero. They can sell LNG virtually for free and still make a profit. Qatar mostly produces wet gas, with an abundance of natural gas liquids, including propane and butane, that allows them to make the bulk of their profit from these NGLs. Admittedly NGL prices, which largely track the price of oil, have also fallen substantially, but not so much that Qatar isn’t still making a profit.
Novatek says Yamal LNG can finish first train without more financing
(Reuters; March 10) – An executive at Russia's Novatek, lead partner in the Yamal LNG project, said the gas producer plans to launch the Arctic plant’s first liquefaction train with 5.5 million metric tons of annual LNG capacity in 2017. Completing construction of the first of three trains proposed for the project will not require any additional financing, Stanislav Shevkunov, a department head at Novatek, told reporters March 9.
The Yamal LNG venture of Russian, French and Chinese partners is trying to raise about $10 billion in external financing, mainly from China, to complete the $27 billion project. It would be Russia's second LNG plant — the first is on Sakhalin Island in the Far East, and has been operating since 2009.
The Russian government has helped with financing and building the Yamal project, including the port and airport and providing icebreakers for when deliveries start. But Western sanctions over Russia’s role in the Ukraine conflict have made it difficult for the partners to raise the financing needed to finish the development.
Thailand plans to buy more LNG, cut back on costlier domestic gas
(Interfax Global Energy; March 11) - Thailand has announced plans to cut domestic gas production and import more low-cost spot-market LNG in a move to conserve its waning gas reserves. The government aims to reduce output from the Gulf of Thailand by 10 percent to 2.5 billion cubic feet per day by next year, director general of the Mineral Fuels Department Veerasak Pungrassamee said in a note earlier this month. This will help extend flows from fields in the gulf until 2025.
At $4 to $5 per million Btu, spot-market LNG can be imported for less than the cost of gas production in the Gulf of Thailand. At those low prices, state-backed energy company PTT could look to optimize its finances by producing less gas at home, Zhi Xin Chong, an LNG expert at energy researcher Wood Mackenzie, told Natural Gas Daily.
Thailand’s sole LNG import terminal will run at capacity in 2016 to help offset the planned domestic gas production cut. The facility will be expanded in 2017 to handle double its existing capacity. PTT recently announced it would delay its long-term LNG buying plans, opting instead to buy cargoes on the spot market to take advantage of lower costs in the oversupplied market. Thailand has long-term LNG supply deals with BP, Shell and Qatargas, but PTT is in talks with BP and Shell to delay the import deals.
EIA forecasts U.S. gas production to hit another record high in 2016
(Reuters; March 9) – Average daily U.S. natural gas production in 2016 is expected to reach a record high of 79.68 billion cubic feet, the U.S. Energy Information Administration said March 8. The forecast would top 2015's all-time peak production of 79.13 bcf and would be the sixth consecutive annual record high for U.S. gas production, according to the EIA's Short-Term Energy Outlook in March.
The EIA also forecast U.S. gas consumption would edge up to 76.79 bcf a day in 2016 from76.44 bcf forecast in February, due to increasing expectations of gas use by the electric power sector. That would top the 2015 record high for demand and would be the seventh annual record high in a row. For 2017, the agency forecast more record highs, with production expected to rise to 81.36 bcf and consumption growing to 77.31 bcf.
In addition to power-sector demand, the EIA also said gas consumption in 2016 and 2017 would rise as new fertilizer and chemicals projects that use gas as a feedstock come online. In 2017, the EIA expects production growth will reduce demand for gas imports from Canada and support increasing exports to Mexico.
Pipelines may carry more surplus U.S. gas into Canada
(Bloomberg; March 11) - U.S. natural gas drillers battered by the lowest prices in 17 years have found another release valve for their output: Canada. Over the past five years, the shale boom that unlocked vast supplies of gas across North America has tripled pipeline shipments from the U.S. to Mexico, and spurred the first liquefied natural gas exports from the Lower 48 states. Now, pipeline companies led by Spectra Energy, TransCanada and Energy Transfer Partners are gearing up to more than double the flow into Canada by 2027, according to the Canadian Energy Research Institute.
The push begins next year, with plans to open or expand at least three major pipelines and reverse the flow northward on a fourth. The efforts come as gas stockpiles have reached historic highs, prices have fallen almost 40 percent since the end of 2011, and the fuel is the Bloomberg Commodity Index’s worst performer. All of that has spurred a desperate drive by producers to expand their markets. Last year, Canada produced about 12 billion cubic feet a day of gas, compared with almost 80 bcf a day in the states.
“There’s so much supply growth in the eastern U.S. that producers are seeking any and all outlets to get the gas to market,” said Martin King, an analyst at FirstEnergy Capital in Calgary. “It’s another obstacle for Canadian producers.” Calgary-based producers Birchcliff Energy and Encana are already feeling the heat. Nine years ago, supplies from Canada met 16 percent of U.S. demand for gas. By 2014, as U.S. output rose to a record for a fourth straight year, Canadian supplies had slipped under 10 percent.
Consultants see future growth for LNG delivery by 40-foot container
(Logistics & Materials Handling; March 8) - The commonly recognized 40-foot-long shipping container is set to widen the market for LNG over the coming years, according to Baker Botts, an international consulting firm in the energy and technology sectors. Baker Botts believes the use of insulated containers is emerging as a cost-competitive transport solution for bringing natural gas to isolated markets that lack access to pipelines or local gas production and are too small for bulk LNG carriers.
“This has created gas ‘islands’ by nature of their geographic isolation, or location on a mainland not connected to natural gas sources,” said Steven Miles, Baker Botts’ energy sector chair. “These pockets are typically left to use coal, petroleum or other energy forms that are more expensive and less environmentally friendly than gas or LNG.
“However, emerging commercial, legal and technological developments are now allowing LNG in ISO (insulated) containers to be delivered to these previously inaccessible LNG market destinations,” Miles said. “The containers … can be loaded with LNG and shipped by freighter, rail or truck and delivered to a power plant.” The LNG is warmed up, regasified and fed to generators or added into a pipeline system.
LNG supply glut could push coal out of Europe, analyst says
(Platts; March 10) - The thermal coal spot market is likely to face increased competition from liquefied natural gas in the future, as global LNG supply increases and coal import taxes work in favor of gas, sources say. According to market participants, a large supply of LNG going forward could "compete aggressively" with coal in the spot market. The 15- to 60-day thermal coal spot price for cargoes to Europe was assessed by Platts at $47.50 per metric ton March 8, down from $61.40 around the same time last year.
A Northwest European utility trader remarked that "the expected glut of LNG supply in the next few years" should dampen gas prices. Macquarie analyst Stefan Ljubisavljevic told Platts that U.K. utilities were already using gas over coal, with switching "not too far away" in Europe either, which would further pressure coal prices. "Looking at the environment ... fossil fuels are competing for favor and demand in a small competition space," he said. "Coal demand has already peaked and looks to decrease further."
According to Platts data, the average for spot LNG to Europe has fallen 43 percent to $4.10 per million Btu in February compared to $7.23 a year ago. This was largely the result of stable-to-weak global demand as new production comes online. "The net result is that by 2019, LNG could be oversupplied by about 70 million metric tons per year, which is about 190 million tons of coal equivalent," with Ljubisavljevic adding the majority of that LNG could come to Europe and displace a vast amount of coal.
More bankruptcies possible as oil companies miss debt payments
(Bloomberg; March 10) - Investors are facing $19 billion in energy defaults as the worst oil crash in a generation leaves drillers struggling to stay afloat. The wave could begin within days if Energy XXI, SandRidge Energy and Goodrich Petroleum fail to reach agreements with creditors and shareholders. Those are three of at least eight oil and gas producers that have announced missed debt payments, triggering a countdown to default.
"Shale was a hot growth area and companies made the mistake of borrowing too much," said George Schultze, founder and chief investment officer of Schultze Asset Management in New York, which has been betting against several distressed energy companies. "It’s amazing that so many people were willing to lend them money. Many are going to file for bankruptcy, and bondholders and equity are going to get wiped out."
Bondholders are paying dearly for backing a shale boom that was built on high-yield debt. Since the start of 2015, 48 oil and gas producers have gone bankrupt owing more than $17 billion, according to law firm Haynes and Boone. Fitch Ratings predicts $70 billion of energy, metal and mining defaults this year. "Asset managers bought the story that we’d have $100 oil forever," said Tim Gramatovich, chief investment officer with Peritus Asset Management in Santa Barbara. "Bondholders are left holding the bag."
IEA says prices may have bottomed out; U.S. oil up to $38.50
(The Associated Press; March 11) - The organization representing major oil-consuming nations said March 11 that signs are emerging the market has bottomed out. “For prices there may be light at the end of what has been a long, dark tunnel,” the International Energy Agency said in its monthly report. The U.S. oil benchmark rose March 11 to $38.50 a barrel on the New York Mercantile Exchange, while the global Brent contract climbed to $40.39 a barrel. Both contracts are up more than 40 percent from lows set earlier in the year, but remain down by over half since the price collapse began in 2014.
Oil-producer cutbacks may finally be translating into a reduction of the massive and global oversupply of oil, the IEA said. The number of oil and gas rigs active in the U.S. fell for the 12th consecutive week, down to 480, according to Baker Hughes. That's the lowest level in decades, and perhaps the fewest since the earliest days of the oil drilling industry. And companies continue to cut spending and staffing. Texas-based Anadarko Petroleum said it would cut 1,000 workers, 17 percent of its work force.
OPEC production tumbled by 90,000 barrels a day last month, the IEA said. U.S. production that had surged due to new drilling technology is expected to fall by almost 530,000 barrels a day this year, according to the IEA. The Paris organization, however, said the recovery in crude prices in recent days from multi-year lows does not mean that there will be a significant and sustained rebound in the short-term. There have been sharp declines in demand, particularly in the United States and China, it said.
Analysts warn U.S. producers could overreact to oil-price bump
(Wall Street Journal; March 13) - The slide in oil prices has paused after crude fell more than 70 percent from its 2014 peak. Now the question is whether the recent rise itself could spark another downward spiral. U.S. oil prices are up more than 45 percent — to $38.50 per barrel — from a 13-year low in February, boosted by talks among Saudi Arabia, Russia and other producers about capping their output. A temporary reduction in global oil supply following outages in Nigeria and Iraq also helped buoy the market.
But this rally could lead to its own demise, many analysts warn. Higher prices will likely encourage shale producers to ramp up output, muddying any forecasts for shrinking U.S. supply. Shale wells can be drilled and fracked within a matter of months, much faster than other types of wells that can take years to complete. “My concern is if the market surges right back to $50 a barrel … we just end up with another problem six months from now,” said Jeffrey Currie, Goldman Sachs’ head of commodities research.
Stored supplies of crude and refined products need to fall from current elevated levels before any sustained rally can take place, Goldman Sachs said March 11. Many investors say they are still looking for more evidence of a fundamental rise in demand for commodities or a significant drop in production to justify further price increases.