HOUSTON/DENVER (Reuters) – Texas oilman Mike Shellman has kept his MCA Petroleum Corp going for four decades, drilling wells through booms and busts and always selling his crude to U.S. oil refiners.
FILE PHOTO: The sun is seen behind a crude oil pump jack in the Permian Basin in Loving County, Texas, U.S., November 22, 2019. REUTERS/Angus Mordant/File Photo
But now the second-generation oilman has abandoned drilling any new wells this year and postponed some maintenance amid a sharp drop in global oil prices and brimming storage tanks. He is considering shutting most of his production down, for the first time ever.
Oil fields from Texas and New Mexico to Oklahoma and North Dakota are going quiet as drilling halts and tens of thousands of oil workers lose their livelihood. Fuel demand has plunged by as much as 30 million barrels per day (bpd) – or 30% – as efforts to fight the coronavirus pandemic have grounded aircraft, reduced vehicle usage and pushed economies worldwide toward recession.
“What scares me is not even being able to sell the product,” the grizzled oil hand said from his firm’s San Marcos, Texas, headquarters.
Refiners and other buyers are warning they may refuse his oil once contracts expire this month, he said. Or they may offer to buy at a price below his costs, so he is preparing to dip into retirement savings to pay employees, he said.
The governments of global oil producers and consumers are seeking to make unprecedented cuts to overall supply of some 19.5 million bpd. U.S. President Donald Trump heralded the deal to cut supply as one that would save hundreds of thousands of U.S. jobs.
But oil prices fell again this week, dropping as much as 10% on Tuesday, because even those cuts may fail to stem the glut. Prices remain far below production costs for many U.S. producers, including those in the U.S. shale fields – the scene of a revolution in the energy industry over the past decade that made the United States the world’s top producer.
Across the United States, up to 240,000 oil-related jobs will be lost this year, about a third of the onshore and offshore oilfield workforce, estimates consultancy Rystad Energy.
The U.S. oil boom died on March 6, the day Saudi Arabia and Russia ended a four-year pact that curbed output and gave shale a price umbrella. Shale firms have accrued hefty debt during the years of expansion, leaving them exposed to the price crash that followed.
In March, U.S. oil futures tumbled to $20 a barrel, a third of the January price and less than half what many require to cover production costs. The March drop led dozens of shale producers to cut spending and several retained debt advisors.
“As soon as the virus hit and oil prices dropped, they sent everybody home,” said Joel Rodriguez, chief administrator of La Salle County, home of Texas’s second-most productive oilfield.
Shale oil producers face well closures and “industry wide financial distress” even after the OPEC cuts, said Artem Abramov, head of shale at consultancy Rystad Energy. In some fields, he expects regional prices will hit single-digits per barrel, he said. (For a graphic, click here)
Spending on oil field services will fall 21% to $211 billion this year, the lowest since 2005, according to researcher Spears & Associates.
Unlike the 2014-2016 oil bust, lenders are not making more financing available to producers, said Raoul Nowitz, head of restructuring at SOLIC Capital Advisors. He predicts up to 60 oil producers will seek protection from creditors this year, and many will not emerge under new owners. Some banks are setting up operations to take over and run failed producers.
LAYOFFS AND SHUT-INS
OPEC’s cuts may not be deep enough for oil producer Texland Petroleum, which operates 1,200 wells in the Permian Basin, the top U.S. oilfield. U.S. refiner and pipeline operator Phillips 66 asked President Jim Wilkes to reduce his deliveries by 15%, and another buyer canceled his contract outright.
“We’ve never had a time when we couldn’t sell the oil we produce. And that’s going to happen this time,” said Wilkes.
Average daily U.S. oil production this year will fall 500,000 bpd, to 11.8 million bpd and sink another 700,000 bpd next year, the Energy Information Administration estimated. (For a graphic, click: here)
Production cuts are too late for workers like Jeremy Davis, a 36-year-old who in March lost his business development job at Advanced BioCatalytics, which makes chemicals for hydraulic fracturing.
“They won’t be fracking many wells for the rest of the year,” said Davis, who after 16 years in the oilfield would now consider work outside the oil business. “I can’t wait around for the industry to come back,” he said.
Wall Street investors had already pulled back on the shale sector over the past couple of years because of poor returns, leaving producers with limited options for refinancing, said industry executives and analysts.
“There is no more lifeline,” said Lance Loeffler, the finance chief at top U.S. fracking service provider Halliburton Co.
PayZone Directional Services, a Denver-based driller, threw in the towel last month.
“We could have stayed open and run until the money was gone but sometimes you just have to know when to cash in your chips and leave the table,” said Beth Thibodeaux, chief executive officer.
TIME TO MOVE ON
So much unsold oil is sloshing around that some pipeline operators, fearful of having their lines clogged, are insisting that producers halt connecting new wells and prove they have buyers or storage outlets before oil from existing wells can be put into a line.
They have warned “by mid-May storage is full” and will refuse to take any more, said Scott Sheffield, CEO at Permian Basin producer Pioneer Natural Resources.
He and some other executives in Texas and Oklahoma want state regulators to mandate up to 20% output cuts, sparing only the smallest producers. In Texas, energy regulators on Tuesday heard Sheffield call for a state order to halt 1 million bpd from its shale fields to prevent sale at below production cost.
MCA Petroleum owner Shellman said he tells friends who lost their jobs that it is time to leave the oil business. “It’s not ever going to be like it was.”
Shellman, who as a youngster got his first taste of the oil business accompanying his parents to their own oil wells, has promised to pay his employees from savings even if they have to shut in wells. But the pain goes well beyond Shellman’s wallet.
“From an emotional standpoint, this is killing me,” he said.
Reporting by Jennifer Hiller in Houston, Liz Hampton in Denver; editing by Gary McWilliams and Edward Tobin
U.S. market is so oversupplied with oil that traders are experimenting with a new place for storing excess crude
By NICOLE FRIEDMAN and BOB TITA WSJ
Updated Feb. 28, 2016 9:09 p.m. ET
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 giant oil tankers when inventories run high.
The combination of cheap oil and surplus railcars has created a budding new side business for traders. J.P. Fjeld-Hansen, a managing director for trading company Musket Corp., tested using railcars for storage last year and found he could profit by putting the oil aside while locking in a higher price to deliver it in a later month.
The company built a rail terminal in Windsor, Colo., in 2012 to load oil shipments during a boom in U.S. oil production. Now, Mr. Fjeld-Hansen says, “The focus has shifted from a loading terminal to an oil-storage and railcar-storage business.”
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, says there are so many unused tank cars that he is constantly hearing from railcar owners hoping to put them to use. “We get offers everyday for railcars,” he said.
The use of railcars for storage could be limited by the cost of track space and safety and liability concerns that have followed a string of high-profile transport accidents. Issues range from leaky cars to the risk of collisions and fires.
Federal regulations require railroads that store cars loaded with hazardous materials like oil to comply with strict storage and security measures to keep the cars away from daily rail traffic. Railroads and users face responsibility for leaks, collisions or other mishaps.
“I don’t want the liability,” said Judy Petry, president of Oklahoma rail operator Farmrail System Inc. “We prefer not to hold a loaded car.”
Still, the oil has to go somewhere. The surge in shale-oil production has created a massive glut that the industry is struggling to absorb.BP PLC Chief Executive Bob Dudley joked in a speech this month that by midyear, “every storage tank and swimming pool in the world will be filled with oil.”
Khory Ramage, president of Ironhorse Permian Basin LLC, which operates a rail terminal in Artesia, N.M., said he hears regularly from traders looking to store crude in his railcars.
Crude-storage costs “have been accelerating, just due to the demand for it and less room,” he said. “You’ll probably start seeing this kick up more and more.”
U.S. crude inventories rose above 500 million barrels in late January for the first time since 1930, according to the Energy Information Administration.
The cheapest form of storage—underground salt caverns—can cost 25 cents a barrel each month, while storing crude on railcars costs about 50 cents a barrel and floating storage can cost 75 cents or more. The cost estimates don’t include loading and transportation.
Railcars hold between 500 and 700 barrels of oil, less than a cavern, tank or ship can store.
The use of U.S. railcars to transport large volumes of oil picked up steam a few years ago as a byproduct of the fracking boom. Fields sprung up faster than pipelines could be laid, so producers improvised and shipped their output to market by rail. Companies soon realized railroads offered greater flexibility to transfer oil to whomever offered the best price. Some pipeline companies even joined the rail business, building terminals to load and unload oil. U.S. oil settled Friday at $32.78 a barrel, down nearly 70% from mid-2014.
The plunge in oil prices brought that activity to a halt. Analysts estimate there are now as many as 20,000 tank cars—about one-third of the North American fleet for hauling oil—parked out of the way in storage yards or along unused stretches of tracks in rural areas.
Producers and shippers who signed long-term leases for the cars during the boom are stuck paying monthly rates that typically run $1,500 to $1,700 per car. Traders can pay those prices and still profit. Oil bought at the April price and sold through the futures market for delivery a year later could net a trader $8.07 a barrel, not including storage or transportation costs.
As central storage hubs fill up, oil companies are more willing to pay for expensive and remote types of storage, said Ernie Barsamian,principal of the Tank Tiger, which keeps a database of companies looking to buy and sell oil storage space.
The Tank Tiger posted an inquiry Wednesday on behalf of a client seeking 75,000 barrels of crude-oil storage or space to park 100 to 120 railcars loaded with crude.
Mr. Barsamian likened the disappearance of available storage to a coloring book where nearly all the white space has been filled in.
(Reuters) – JP Morgan will set aside an additional half a billion dollars to cover potential bad loans to oil and gas companies in the first quarter, underlining the sharp deterioration in the U.S. energy sector.
An additional $1.5 billion will have to be reserved if oil prices remain at $25 or below for 18 months.
It’s time for oil investors to start taking electric cars seriously.
In the next two years, Tesla and Chevy plan to start selling electric cars with a range of more than 200 miles priced in the $30,000 range. Ford is investing billions, Volkswagen is investing billions, and Nissan and BMW are investing billions. Nearly every major carmaker—as well as Apple and Google—is working on the next generation of plug-in cars.
This is a problem for oil markets. OPEC still contends that electric vehicles will make up just 1 percent of global car sales in 2040.Exxon’s forecast is similarly dismissive.
The oil price crash that started in 2014 was caused by a glut of unwanted oil, as producers started cranking out about 2 million barrels a day more than the market supported. Nobody saw it coming, despite the massively expanding oil fields across North America. The question is: How soon could electric vehicles trigger a similar oil glut by reducing demand by the same 2 million barrels?
That’s the subject of the first installment of Bloomberg’s new animated web series Sooner Than You Think, which examines some of the biggest transformations in human history that haven’t happened quite yet. Tomorrow, analysts at Bloomberg New Energy Finance will weigh in with a comprehensive analysis of where the electric car industry is headed.
Even amid low gasoline prices last year, electric car sales jumped 60 percent worldwide. If that level of growth continues, the crash-triggering benchmark of 2 million barrels of reduced demand could come as early as 2023. That’s a crisis. The timing of new technologies is difficult to predict, but it may not be long before it becomes impossible to ignore.
Congressional Leaders Agree to Lift 40-Year Ban on Oil Exports
Dec 16, 2015 By Amy Harder And Lynn Cook
Accord is a key component to deal on tax, spending legislation
WASHINGTON—In a move considered unthinkable even a few months ago, congressional leaders have agreed to lift the nation’s 40-year-old ban on oil exports, a historic action that reflects political and economic shifts driven by a boom in U.S. oil drilling.
The measure allowing oil exports is at the center of a deal that Republican leaders announced late Tuesday on spending and tax legislation. However, Democrats haven’t confirmed the agreement. Both the House and Senate still must pass it and President Barack Obama must sign it into law.
The deal would lift the ban, a priority for Republicans and the oil industry, and at the same time adopt environmental and renewable measures that Democrats sought. These include extending wind and solar tax credits; reauthorizing for three years a conservation fund; and excluding any measures that block major Obama administration environmental regulations, according to a GOP aide.
By design or not, the agreement hands the oil industry a long-sought victory within days of a major international climate deal that is aimed at sharply reducing emissions from oil and other fuels, a deal opposed by the industry and one that will arguably require its cooperation.
More than a dozen independent oil companies, including Continental Resources CLR 2.29 % and ConocoPhillips , COP 2.08 % have been lobbying Congress to lift the ban on oil exports for nearly two years, arguing that unfettered oil exports would eliminate market distortions, stimulate the U.S. economy and boost national security.
A handful of Washington lawmakers representing oil-producing states, including Sens. Heidi Heitkamp (D., N.D.) and Lisa Murkowski (R., Alaska), have been working to convince once-wary politicians to back oil exports and allay worries that they will be blamed if gasoline prices were to rise.
Some U.S. refineries oppose oil exports, saying their business would be hit if crude oil is shipped overseas to be refined and warning that higher costs might be passed along to consumers. The U.S. government doesn’t limit exports of refined petroleum products, and those exports have more than doubled since 2007.
To address the refiners’ concerns, expressed most vocally by Democrats from the Northeast where several refineries are located, the spending bill changes an existing tax deduction for domestic manufacturing to benefit independent refineries in particular.
President Barack Obama had threatened to veto separate legislation lifting the export ban, but the White House isn’t expected to oppose the overall spending bill simply because it includes the measure, according to congressional aides.
Congress moved to ban oil exports under most circumstances following a 1973 Arab oil embargo that sent domestic gasoline prices skyrocketing.
With the increased use of fracking and other drilling technologies in recent years, U.S. oil production has shot up nearly 90% since August 2008, helping lower gasoline prices to levels not seen since 2009. Gas prices are less than $2 a gallon in many regions of the country, and the U.S. Energy Information Administration forecasts the price will average $2.04 this month and $2.36 next year.
It took this dramatic drop in oil prices, hovering below $40 a barrel, to catapult the policy change to the top of the Republican agenda. It helped prompt lawmakers of both parties to consider pairing renewable energy support with oil exports, a type of grand Washington deal-making that hasn’t been seen for years on the highly divisive issues of energy and environment.
The same low prices that generated momentum for lifting the ban could reduce its short-term economic impact, however, because the global market is saturated and U.S. oil companies have already slowed drilling in response.
John Hess, chief executive of Hess Corp., said low oil prices have increased the urgency for Congress to lift the ban, but he declined to say whether his company would immediately begin exporting oil if given the opportunity.
“It would be a function of market conditions,” Mr. Hess said in a recent interview. “But I think over time, definitely; If the market signals were there, we would have that option.”
The U.S. is already exporting nearly 400,000 barrels of crude a day to Canada, the biggest exemption under the ban. That is more than nine times as much as in 2008 but still just 3.8% of the U.S. oil produced every day.
A certain type of light oil is also already starting to flow overseas thanks to permission granted in 2014 by the Commerce Department, which allows producers to reclassify a certain type of oil as a refined fuel, similar to gasoline, which is legal to ship abroad.
The logistics of a new surge of oil exports would be relatively manageable, especially compared to exporting natural gas, which takes years of federal permitting and billions of dollars in technology to liquefy the gas.
Extensive networks of oil pipelines and storage tanks already stretch along the Gulf Coast from Corpus Christi, Texas, to St. James Parish, La. Those oil ports, where nearly a third of U.S. refineries are located, are for now geared toward unloading crude from tankers, not loading them. So initially there would be some constrained capacity that caps energy companies’ ability to ship crude out to foreign buyers.
But retrofitting those facilities—adding more deep-water dock space and equipment to load oil tankers—could happen quickly in a place like Texas, where permitting is easy and such projects face little community opposition. The ports of Corpus Christi and Houston are already undergoing dramatic expansions.
Several companies, including Enterprise Products Partners EPD 1.17 % LP, have already been ramping up their ability to export oil from Texas, and Enbridge Energy Partners EEP -0.55 % LP, based in Canada, plans to spend $5 billion to construct three new oil terminals between Houston and New Orleans.
—Kristina Peterson contributed to this article.
Last fall, as oil prices crashed, Ali al-Naimi, Saudi Arabia’s petroleum minister and the world’s de facto energy czar, went mum. He still popped up, as is his habit, at industry conferences on three continents. Yet from mid-September to the middle of November, while benchmark crude prices plunged 21 percent to a four-year low, Naimi didn’t utter a word in public.
For 20 years, Bloomberg Markets reports in its May 2015 issue, the world’s $2 trillion oil market has parsed Naimi’s every syllable for signs of where supply and prices are heading. Twice during previous routs—amid the Asian financial crisis in 1998 and again when the global economy melted down 10 years later—Naimi reversed oil’s free fall by orchestrating production cutbacks among members of OPEC. This time, he went to ground.
At the cartel’s semiannual meeting on Nov. 27 in Vienna, Naimi shot down proposed output reductions supported by a majority of the 12 members in favor of a more daring strategy: keep pumping and wait for lower prices to force high-cost suppliers out of the market. Oil prices fell a further 10 percent by the end of the next day and kept going. Having averaged $110 a barrel from 2011 through the middle of 2014, Brent crude, the global benchmark, dipped below $50 in January.
“What they did was historic,” Daniel Yergin, the pre-eminent historian of the oil industry, told Bloomberg in February. “They said: ‘We resign. We quit. We’re no longer going to be the manager of the market. Let the market manage the market.’ That’s when you got this sort of shocked reaction that took prices down to those levels we saw.”
Naimi, 79, dominated the debate at the November meeting, according to officials briefed on the closed-door proceedings. He told his OPEC counterparts they should maintain output to protect market share from rising supplies of U.S. shale oil, which costs more to get out of the ground and thus becomes less viable as prices fall. In December, he said much the same thing in a press interview, arguing that it was “crooked logic” for low-cost producers such as Saudi Arabia to pump less to balance the market.
Supply was only half the calculus, though. While the new Saudi stance was being trumpeted as a war on shale, Naimi’s not-so-invisible hand pushing prices lower also addressed an even deeper Saudi fear: flagging long-term demand.
Naimi and other Saudi leaders have worried for years that climate change and high crude prices will boost energy efficiency, encourage renewables, and accelerate a switch to alternative fuels such as natural gas, especially in the emerging markets that they count on for growth. They see how demand for the commodity that’s created the kingdom’s enormous wealth—and is still abundant beneath the desert sands—may be nearing its peak. This isn’t something the petroleum minister discusses in depth in public, given global concern about carbon emissions and efforts to reduce reliance on fossil fuels. But Naimi acknowledges the trend. “Demand will peak way ahead of supply,” he told reporters in Qatar three years ago. If growth in oil consumption flattens out too soon, the transition could be wrenching for Saudi Arabia, which gets almost half its gross domestic product from oil exports.
Last week, in a speech in Riyadh, Naimi said Saudi Arabia would stand “firmly and resolutely” with others who oppose any attempt to marginalize oil consumption. “There are those who are trying to reach international agreements to limit the use of fossil fuel, and that will damage the interests of oil producers in the long-term,” he said.
U.S. State Department cables released by WikiLeaks show that the Saudis’ interest in prolonging the world’s dependence on oil dates back at least a decade. In conversations with colleagues and U.S. diplomats, Naimi responded to the American fixation on “security of supply” with the Saudi need for “security of demand,” according to a 2006 embassy dispatch. “Saudi officials are very concerned that a climate change treaty would significantly reduce their income,” James Smith, the U.S. ambassador to Riyadh, wrote in a 2010 memo to U.S. Energy Secretary Steven Chu. “Effectively, peak oil arguments have been replaced by peak demand.”
The Saudis, to be sure, never thought much of peak oil. That’s the theory that global crude supplies, on an upward trajectory for a century and a half, were about to stop rising and could no longer keep up with demand. A faction of geologists and environmentalists made this argument part of the policy debate in the early years of this century. In 2005, when a book by oil analyst Matthew Simmons predicted a drop-off in Saudi output would signal that global supplies were beginning an irreversible decline, Naimi belittled the claims and promised higher production capacity. He won the argument. The Saudis pump more today than a decade ago. Saudi oil fields boast state-of-the-art technology, and at least two of them, in the middle of the desert, have gourmet restaurants. U.S. output has had a stunning rise as well, to more than 9 million barrels a day at the end of 2014 from less than 6 million five years ago. The peak that has the Saudis more worried is peak demand.
Before oil prices tanked last year, Saudi officials were bracing for global demand to level off as soon as 2025, says Mohammed al-Sabban, a senior economic adviser to the Saudi petroleum minister from 1988 to 2013. By letting prices fall, they may have bought themselves some time. At $60 to $70 a barrel, peak demand gets pushed back at least five more years, according to Bank of America Merrill Lynch commodities researchers. Such a delay would be bad news for renewable energy companies and for anyone hoping to bend the demand curve lower—slowing or stopping the relentless rise of global oil consumption that has transformed the planet since the first commercial deposit was developed in Pennsylvania in the early 1860s.
Crude prices above $100 a barrel had been bringing a demand peak closer. “The past four years were a disaster for oil producers in terms of energy market share,” says Sabban, who was also Saudi Arabia’s chief international climate negotiator. “Emerging economies are getting more efficient and diversifying their energy sources. That has definitely impacted oil consumption.”
Saudi officials were in a state of “near panic” last summer, when they recognized how quickly demand growth in China was leveling off, in part because of persistently high crude prices, says Ed Morse, Citigroup’s head of commodities research. “Naimi saw the era of frantic fixed-asset investments in China was over,” says Morse, a former deputy assistant secretary of state for international energy policy, who still communicates regularly with Gulf Arab officials. “That translates to the end of rapid urbanization, the end of doing things in unbelievably energy-intensive ways.”
Substitution of lower-cost fuels is also taking a toll. Chinese diesel demand, after rising an average of 8 percent a year for a decade, actually fell in 2013 and 2014. The International Energy Agency attributes this partly to the country’s rapidly expanding fleet of natural gas vehicles. Chinese demand for oil this year is expected to rise to 10.6 million barrels a day, an increase of 2.6 percent, or half the average annual growth of the past decade and one-sixth the rate in 2004. China’s oil use is still climbing twice as fast as global consumption, but the IEA has in the past year shaved 500,000 barrels from its 2019 China demand forecast. More efficient autos and factories reduced the overall oil intensity of China’s economy—oil burned per unit of GDP—by 18 percent from 2008 to 2014. “If I were in Naimi’s shoes, I’d do exactly what he’s doing,” Morse says.
Naimi, who for the past five years has been telling friends he’s ready to retire, faces big risks as he sees through one more dramatic market realignment. His refusal to put Saudi Arabia and OPEC once again in the swing producer role, cutting supply to balance the market, hurts economically troubled member states that most need a price rebound. In Venezuela, where the economy is teetering and foreign-exchange reserves are depleted, oil’s collapse blows a bigger hole in the government budget and deepens the crisis. Iran, which needs high prices to help offset the effect of sanctions that have choked off its exports, has had harsh words for the Saudi-led policy. Persian Gulf producers should try to halt the decline in prices, a deputy foreign minister said on state-run television in January, and Foreign Minister Mohammad Javad Zarif delayed a meeting with his Saudi counterpart due to the discord. Regional tensions were highlighted in late March, when Saudi Arabia led airstrikes against Yemen’s Houthi rebels, seeking to counter Iranian influence there.
Even Saudi Arabia, with more than $700 billion in reserves, could suffer financial strain if oil prices stay low for several years. The kingdom, with a population of about 30 million, spends lavishly on domestic programs and foreign aid. When King Salman ascended to the throne in January, after the death of King Abdullah, he promised in his first speech to improve education and expand health care. The Saudi budget was in deficit in 2014, despite strong oil prices for most of the year. The government forecasts a 2015 budget gap of 145 billion riyals ($39 billion), and it will be wider if oil prices don’t rebound.
Still, Naimi has said several times since the November meeting that he doesn’t know how low prices might go or when they will recover—and that the Saudis are willing to wait and see. Naimi’s concerns for Saudi Arabia are further in the future.
“Our ultimate aim is to diversify away from our overreliance on oil revenues,” the petroleum minister said at a 2013 seminar in Washington. The centerpiece of that effort is the establishment of the King Abdullah University of Science and Technology on the Red Sea, north of Jeddah. Naimi, who was CEO of state oil producer Saudi Aramco before becoming petroleum minister, recounted how, at a council of ministers meeting in 2006, the monarch took his hand and asked if he could build a university. “I said: ‘Your Majesty, we have built—I mean, Saudi Aramco has built—a lot of refineries, gas plants, pipelines, some housing. But universities? No. But we can, if you want.’ And we did.”
The school’s mission, as Naimi articulates it, is nothing less than to lead Saudi Arabia into the post-hydrocarbon age. The campus, built for 220 professors and 2,000 graduate students, is a bastion of tolerance and religious liberty in a country often criticized for having neither. Heavily armed guards on land and at sea protect the facility, where unveiled women study and work side by side with men, undisturbed by the religious police who patrol Saudi cities. Research there is aimed at scientific and commercial breakthroughs using those things Saudi Arabia has in abundance, such as sun, sand, and saltwater. When he discusses retirement, Naimi says it’s to devote more time to the institution.
While the university is key to Saudi Arabia’s diversification effort, there are other initiatives for the nearer term. The kingdom already is exploiting its huge deposits of phosphates to export fertilizer and is mining bauxite to smelt and roll aluminum. Eventually, Naimi says, Saudi Arabia wants to manufacture finished goods such as car parts. “We are generating job opportunities for our young people, encouraging enterprise, and providing the right environment for innovation and progress,” Naimi said at the Washington seminar. “It’s not easy, and it will not happen overnight. But it is happening.”
How much time Saudi Arabia has to prepare for the eventual decline of the oil era may depend, in part, on how alternatives fare during this period of cheap oil. Will sales of wind turbines and solar panels stay strong? Or will they enter a tailspin like they did during the Great Recession, when project financing dried up? And will sales of electric vehicles continue to climb even as gasoline prices slump?
Adam Sieminski, head of the U.S. Energy Information Administration, said at a Washington forum in late January that lower crude prices wouldn’t slow development of wind and solar power because there’s little direct competition with oil in electricity generation. Electric vehicles, he said, are helped by tax incentives and government policies and perhaps also by the cachet of green technology.
“The Saudis may be once again trying to prolong the age of oil,” says Bill McKibben, the author and environmental activist who has helped lead the campaign to block the Keystone XL pipeline, which would bring oil from Canada’s tar sands to the U.S. market. “But it feels like the steady, relentless fall in costs for renewables may make this different from other cycles.”
Naimi, who carefully manages his public comments the way a central banker or top diplomat might, hasn’t said how close he thinks the world may be to a peak in oil demand. He didn’t respond to requests to be interviewed for this story. But he has articulated his view that the crude market can no longer be understood without considering the effects alternative energy sources are having. “One has to be realistic,” Naimi told the Middle East Economic Survey in an interviewpublished in December. “There are many things in the energy market—not the oil market—that will determine prices in the future. A lot of effort is being exerted worldwide, whether in research or boosting efficiency or using nonfossil fuels.”
Ali bin Ibrahim al-Naimi has lived the post-World War II history of oil—and done much to shape it. Born in 1935 in Saudi Arabia’s oil-rich Eastern Province, he spent his early childhood as a desert nomad, moving from spring to spring with his extended family and their livestock. When Naimi was 8, his Bedouin mother sent him to live with his father in the provincial capital of Dammam. He attended a school operated by Arabian American Oil Co., known as Aramco. The petroleum producer was founded by Standard Oil of California in the 1930s and became Saudi Aramco after its nationalization in the 1970s.
At 12, Naimi became a mail boy at Aramco, taking over for his brother after his sudden death, and he quickly shined as a star typist. One day at the Aramco offices, the American CEO stopped Naimi in the hallway and asked the teenager what he wanted to do with his life, says Peter van de Kamp, who became friends with Naimi at Lehigh University, recounting a story Naimi told their classmates in the early 1960s. “Well, sir, someday I would like to have your job,” Naimi answered. “If that’s the case,” the American said, “you’ll need an education.”
Aramco sent Naimi to school in Beirut and then to Lehigh in Pennsylvania and Stanford University in California, where he earned a master’s degree in geology. At Lehigh, the chair of the geology department assigned the 6-foot-5-inch Van de Kamp to watch out for Naimi, who’s around 5 feet tall. The transfer student from a Mideast country few students had heard of was a good companion, Van de Kamp says, respectful of Christians and Jews, comfortable socializing with women. He was eager to chop firewood and “get his hands dirty” doing chores at the Van de Kamps’ New Jersey home on holidays, he says. Proud of his Bedouin roots, Naimi told stories about tending sheep and goats in a forbidding desert with scarce food or water. He did his senior research project in 1962 on the commercial mining potential of New Jersey’s beach sand. “Ali was a comer; we all could see it,” says Van de Kamp, who’s now a geologist in Oregon.
After returning to Saudi Arabia, Naimi zoomed through a series of oil production and executive positions at Aramco, culminating in his 1984 appointment as the company’s first Saudi president and, four years later, its CEO. At the time, U.S. and European consumption was in decline, due in part to sluggish economic growth and conservation measures adopted after the oil shocks of the 1970s. In response, Petroleum Minister Ahmed Zaki Yamani slashed Saudi oil output from 10 million barrels a day in 1981 to just 3.5 million in 1986. Prices kept falling, briefly getting to around $10 a barrel, as non-OPEC producers and cartel members cheating on their quotas filled the gap. In 1986, King Fahd fired Yamani, and the Saudis flooded the world with cheap oil to seize back market share—and induce Americans to resume their gas-guzzling habits. (The era of big SUVs was just beginning.)
Aramco’s new president saw firsthand what happened when the Saudis cut output and others didn’t, a lesson he cites today. “We will not make the same mistake again,” he said in Berlin in March.
Promoted to petroleum minister in 1995, Naimi spends weekdays working in Riyadh and weekends at his family’s villa or at a small farm near Dharan. He arrives early each day at the ministry, a set of nine-story stone and black-glass blocks. His seventh-floor offices aren’t grand, the decor little changed in 20 years. He leaves in a black Mercedes by 2 p.m., Saudi government quitting time, and works the rest of the day at home.
Naimi’s tenure got off to a rough start. With demand rising in China, he persuaded OPEC to expand production in November 1997, just as the Asian financial crisis was deepening. During the next two years, oil prices fell 50 percent.
He also mishandled Saudi Arabia’s overture to Western energy companies to help develop the kingdom’s natural gas reserves. By 1998, then-Crown Prince Abdullah was trying to lure back foreign firms to tap Saudi gas for industrial projects such as electricity generation, water desalinization, and petrochemical manufacturing. Naimi, however, kept the best gas fields for Aramco while offering Exxon Mobil and dozens of other companies blocks that some Saudi geologists doubted contained much commercial gas, according to Sadad al-Husseini, who led Aramco’s exploration and production operations from 1985 to 2003.
The Exxon Mobil negotiations blew up in 2003, at the home of Saudi Foreign Minister Saud al-Faisal in Beverly Hills, California, according to journalist Steve Coll’s book Private Empire: ExxonMobil and American Power, published in 2012. Exxon Mobil’s then-CEO Lee Raymond informed Faisal and Naimi that the Saudi field on offer didn’t have enough gas to warrant his investment, Coll wrote. Naimi responded that Exxon Mobil’s experts were playing down the block’s potential to get a better deal. At that point, Raymond exploded at Naimi for questioning his people’s integrity, and the deal soon fell apart, Coll wrote. “I was very unhappy,” Raymond says in an interview. “The reality was that there was never access to the potential reserves you would need to support the project.”
Over time, Naimi earned a reputation as a straight talker and a shrewd manager of the global market. Despite the Saudis’ dire warnings to President George W. Bush not to invade Iraq in 2003, Naimi kept markets stable by promising to pump more oil during the war. In 2008, as prices soared to a record $147 a barrel, he resisted intense U.S. pressure to raise output again. Judging shrewdly that market conditions were very different than they were five years earlier, he argued in several contentious meetings with American officials that supply was adequate and that financial speculators were driving up prices. “The line was clear and consistent, even if it wasn’t a message the American administration wanted to hear,” says Ford Fraker, the U.S. ambassador to Riyadh from 2007 to 2009 and president of the Middle East Policy Council.
During the Libyan uprising in May 2011, U.S. officials flew into Saudi Arabia to seek Naimi’s help replacing lost Libyan production. Naimi asked OPEC to expand its output ceiling at the cartel’s meeting that June, but the ministers stormed out of the Vienna secretariat without an agreement. The rebel members, led by Iran, didn’t want to agree to a higher target because they had little excess capacity that could be brought on line. They objected that the only countries with spare oil to sell were the cartel’s richest—Saudi Arabia, Qatar, Kuwait, and the United Arab Emirates.
Afterward, Naimi summoned the press to vent. He’d never seen such unreasonable obstinacy, said the minister, seated in a plush chair in his hotel suite. He’d tried to persuade the others that demand for OPEC’s crude had long since surpassed the recession levels that prevailed when the target was last set in 2008. They wouldn’t listen.
After some dogged diplomacy, OPEC raised the quota at its next meeting. Oil prices spiked early in the Arab Spring, and then they declined through the rest of 2011.
“He’s a man of few words but none wasted,” says Daniel Poneman, the U.S. deputy secretary of energy from 2009 to 2014. “He really came through.”
Naimi was a study in inscrutability when the OPEC ministers gathered this past November in Vienna. That morning, he slipped out the back door of his hotel on the city’s Ringstrasse, trailed by a gaggle of reporters through the medieval backstreets. This brisk morning walk had become known as a moment when Naimi would share his thoughts, but he wasn’t talking. A little later, back at OPEC headquarters, impatient with a television crew’s badgering questions, Naimi lost his legendary cool. “Get the hell out,” he snapped.
Inside the closed-door session, the OPEC ministers sat in alphabetical order around a large rectangular table. Naimi, silver-haired and dressed in a dark suit, blue-purple tie, and matching breast-pocket handkerchief, was seated between Gulf Arab allies Qatar and the U.A.E. Across the table, Venezuela’s Rafael Ramirez opened the proceedings with a proposal for a production cut to be jointly implemented by OPEC, Russia, and Mexico, according to the officials briefed on the proceedings.
Naimi scoffed. He told the ministers that after 60 years in the industry, he knew from experience that Russia wasn’t reliable. In 2008, the Russians pledged to join OPEC’s supply cut during the financial crash, but they never did. And just two days earlier in Vienna, Naimi had attended an awkward meeting at which Vladimir Putin ally Igor Sechin, CEO of oil giant Rosneft, said Russia would agree to cuts, only to be overruled at the same meeting by Russian Energy Minister Alexander Novak.
Naimi next shot down an Algerian proposal, supported by seven member states, for a 5 percent output reduction levied only on OPEC producers. That might boost prices today, Naimi said, but wouldn’t solve OPEC’s longer-term problem with shale producers and declining demand growth. His reasoning prevailed, as usual.
Demand anxiety, always lurking in the Saudi psyche, had surged after U.S. President Barack Obama took office. At first, in 2009, Naimi told American diplomats he wasn’t worried that alternative energy sources would reduce oil use because global consumption was soaring, especially in China and India, according to U.S. diplomatic cables. But six months later, in Ambassador Smith’s 2010 memo to Energy Secretary Chu, the envoy said Saudi leaders “were caught off guard by the strength of the Administration’s initial statements about its desire to move to a post-hydrocarbon economy and end dependence on imported oil.”
Alarm was heightened, the ambassador reported, because the Saudis were just finishing a $100 billion expansion of their production capacity to 12.5 million barrels a day. “Saudi leaders are concerned that this oil may never be needed,” Smith wrote. “They are less concerned about price forecasts than our expectations of the scope and pace of changes globally.”
Other classified cables released by WikiLeaks described the Saudis as “obstructionist” and “schizophrenic” on curbing climate change—launching solar and carbon-sequestration projects at home while impeding multilateral talks abroad. “Part of the explanation for this schizophrenic position is that the Saudi Government has not yet thought through all the implications of a climate change agreement, in part because it may not fully understand the various demand scenarios,” Smith wrote after the 2009 U.N. climate change conference in Copenhagen.
While Copenhagen didn’t lead to any binding agreement, governments have tightened carbon emission limits and other environmental rules in the years since. Efficiency improvements have kept coming. And the Saudi government has been thinking through the implications.
Naimi had put off retirement because King Abdullah asked him to stay. After Abdullah’s death on Jan. 23, King Salman kept Naimi as petroleum minister to signal consistency in Saudi policy during the transition. Still, Naimi is likely to soon have more time to devote to his university and the industrial and technological transformation he envisions for his country. As an Aramco executive and then as a globe-trotting oil diplomat, Naimi has shown great talent for bridging the divide between Westerners and the kingdom’s traditional leaders. And he’s overseen a Saudi industry that is an engine of science and progress.
In 2010, Naimi escorted Chu to visit King Abdullah at his palace in the desert oasis of Rawdhat Khuraim. The elderly monarch was in a philosophical mood and took the opportunity to pose a few questions to the Nobel laureate physicist, says Smith, who went along for the visit.
“Tell me how the universe was formed,” the king asked, in Smith’s recounting. Chu patiently laid out the story of the Big Bang theory. “What does that mean for God?” the monarch said. Chu and Smith conferred for a moment on an appropriate, diplomatic response. “There are some things we know, and for other things, we have God,” Chu replied.
“And tell me, how did we get all this oil?” King Abdullah asked. As Chu described how organisms decomposed over millions of years, Naimi whispered in Smith’s ear, “I’ve told him this a hundred times.”
This story appears in the May 2015 issue of Bloomberg Markets. With assistance from Grant Smith in London.
Tumbling oil prices have exposed a weakness in the insurance that some U.S. shale drillers bought to protect themselves against a crash.
At least six companies, including Pioneer Natural Resources Co. (PXD) and Noble Energy Inc. (NBL), used a strategy known as a three-way collar that doesn’t guarantee a minimum price if crude falls below a certain level, according to company filings. While three-ways can be cheaper than other hedges, they can leave drillers exposed to steep declines.
“Producers are inherently bullish,” said Mike Corley, the founder of Mercatus Energy Advisors, a Houston-based firm that advises companies on hedging strategies. “It’s just the nature of the business. You’re not going to go drill holes in the ground if you think prices are going down.”
The three-way hedges risk exacerbating a cash squeeze for companies trying to cope with the biggest plunge in oil prices this decade. West Texas Intermediate crude, the U.S. benchmark, dropped about 50 percent since June amid a worldwide glut. The Organization of Petroleum Exporting Countries decided Nov. 27 to hold production steady as the 12-member group competes for market share against U.S. shale drillers that have pushed domestic output to the highest since at least 1983.
Shares of oil companies are also dropping, with a 49 percent decline in the 76-member Bloomberg Intelligence North America E&P Valuation Peers index from this year’s peak in June. The drilling had been driven by high oil prices and low-cost financing. Companies spent $1.30 for every dollar earned selling oil and gas in the third quarter, according to data compiled by Bloomberg on 56 of the U.S.-listed companies in the E&P index.
Financing costs are now rising as prices sink. The average borrowing cost for energy companies in the U.S. high-yield debt market has almost doubled to 10.43 percent from an all-time low of 5.68 percent in June, Bank of America Merrill Lynch data show.
Locking in a minimum price for crude reassures investors that companies will have the cash to keep expanding and lenders that debt can be repaid. While several companies such as Anadarko Petroleum Corp. (APC), Bonanza Creek (BCEI) Energy Inc., Callon Petroleum Co., Carrizo Oil & Gas Inc. and Parsley Energy Inc., use three-way collars, Pioneer uses more than its competitors, company records show.
Scott Sheffield, Pioneer’s chairman and chief executive officer, said during a Nov. 5 earnings call that his company has “probably the best hedges in place among the industry.” Having pumped 89,000 barrels a day in the third quarter, Pioneer is one of the biggest oil producers in U.S. shale.
Pioneer used three-ways to cover 85 percent of its projected 2015 output, the company’sDecember investor presentation shows. The strategy capped the upside price at $99.36 a barrel and guaranteed a minimum, or floor, of $87.98. By themselves, those positions would ensure almost $34 a barrel more than yesterday’s price.
However, Pioneer added a third element by selling a put option, sometimes called a subfloor, at $73.54. That gives the buyer the right to sell oil at that price by a specific date.
Below that threshold, Pioneer is no longer entitled to the floor of $87.98, only the difference between the floor and the subfloor, or $14.44 on top of the market price. So at yesterday’s price of $54.11, Pioneer would realize $68.55 a barrel.
David Leaverton, a spokesman for Irving, Texas-based Pioneer, declined to comment on the company’s hedging strategy. The company said in its December investor presentation that “three-way collars protect downside while providing better upside exposure than traditional collars or swaps.”
The company hedged 95,767 barrels a day next year using the three-ways. If yesterday’s prices persist through the first quarter, Pioneer would realize $1.86 million less every day than it would have using the collar with the floor of $87.98. That would add up to more than $167 million in the first quarter, equal to about 14 percent of Pioneer’s third-quarter revenue.
The strategy ensures that the bulk of Pioneer’s production will earn more than yesterday’s market price. The three-ways will also prove valuable if oil rises above the subfloor.
“What they have is much better than nothing,” said Tim Revzan, an analyst with Sterne Agee Group Inc. in New York. “But they left some money on the table that they could have locked in at a better price.”
Noble Energy used three-ways to hedge 33,000 barrels a day, according to third-quarter SEC filings. Assuming yesterday’s prices persist, Houston-based Noble will bring in $50 million less in the first quarter than it would have by locking in the floor prices.
Bonanza Creek, based in Denver, Colorado, set up three-ways with a floor of $84.32 and a subfloor of $68.08, SEC records show. If prices stay where they are, the company will realize $8.1 million less in the first quarter than it would have by just using the floor.
Ryan Zorn, Bonanza Creek’s senior vice president of finance, said that the comparison doesn’t take into account the advantages of the strategy. The proceeds from selling the $68.08 puts helped pay for the protection at $84.32, without which Bonanza Creek would likely have purchased cheaper options with a lower floor.
“The other comparison is if we’d done nothing,” Zorn said. “I view it as being much better than being unhedged.”
Representatives for Anadarko, Noble, Carrizo and Parsley didn’t return e-mails and phone calls seeking comment.
“Because we’ve had high energy prices for so long, it could have given them a false sense of confidence,” said Ray Carbone, president of Paramount Options Inc. in New York. “They picked a price they thought it wouldn’t go below. It has turned out to be very expensive.”
Callon (CPE)’s first-quarter three-ways cover 158,000 barrels with a floor of $90 and a subfloor of $75, company filings show. Callon, based in Natchez, Mississippi, will get $3.3 million less that it would have realized by using the $90 floor, assuming prices stay where they are.
“Certainly, if we’d had the foresight to know prices were going to crater, you’d want to be in the swap instead of the three-way,” said Eric Williams, a spokesman for Callon. “Swaps make more sense if you knew prices were going to go down the way they did, but a few months ago everyone was bullish.”
Crude oil production from U.S. wells is poised to approach a 42-year record next year as drillers ignore the recent decline in price pointing them in the opposite direction.
U.S. energy producers plan to pump more crude in 2015 as declining equipment costs and enhanced drilling techniques more than offset the collapse in oil markets, said Troy Eckard, whose Eckard Global LLC owns stakes in more than 260 North Dakota shale wells.
Oil companies, while trimming 2015 budgets to cope with the lowest crude prices in five years, are also shifting their focus to their most-prolific, lowest-cost fields, which means extracting more oil with fewer drilling rigs, said Goldman Sachs Group Inc. Global giant Exxon Mobil Corp. (XOM ▲ 0.44% 89.41), the largest U.S. energy company, will increase oil production next year by the biggest margin since 2010. So far, the Organization of Petroleum Exporting Countries’ month-old bet that American drillers would be crushed by cratering prices has been a bust.
“Companies that are already producing oil will continue to operate those wells because the cost of drilling them is already sunk into the ground,” said Timothy Rudderow, who manages $1.5 billion as chief investment officer at Mount Lucas Management Corp. in Newtown, Pennsylvania. “But I wouldn’t want to have to be making long-term production decisions with this kind of volatility.”
A U.S. crude bonanza that has handed consumers the cheapest gasoline since 2009 has left oil exporters like Russia and Venezuela flirting with economic chaos. The ruble sank as much as 19 percent on Dec. 16 to a record low of 80 per dollar before recovering to close at 68; Russian bond and equity markets also crumbled. In Venezuela, the oil rout is spurring concern the country is running out of dollars needed to pay debt and swaps traders are almost certain default is imminent.
U.S. oil production is set to reach 9.42 million barrels a day in May, which would be the highest monthly average since November 1972, according to the Energy Department’s statistical arm.
Output from shale formations, deep-water fields, the Alaskan wilderness and land-based wells in pockets of Oklahoma and Pennsylvania that have been trickling out crude for decades already have pushed demand for imported oil to the lowest since at least 1995, according to data compiled by Bloomberg.
Existing wells remain profitable even as benchmark crude futures hover near the $55-a-barrel mark because operating costs going forward are usually $25 or less, Tom Petrie, chairman of Petrie Partners Inc., said in a Dec. 15 interview on the Bloomberg Surveillance television program.
That’s why prices that have tumbled 47 percent from this year’s peak on June 20 haven’t prompted any American oil producers to shut down wells, said Petrie, a U.S. Military Academy at West Point graduate who has advised Saudi Arabia, Alaska and the U.S. government on energy issues.
The average cost to operate an existing well in most parts of the U.S. “is about $20 a barrel,” Petrie said. “It might be $5 higher or it might be $5 lower, that’s the out-of-pocket costs that we’re talking about. Until you dip into that and start losing money on a cash basis day in, day out, you don’t think about shutting in” wells.
Benchmark U.S. crude futures rose 0.3 percent to $56.63 a barrel at 9:55 a.m. in New York Mercantile Exchange trading. The futures are still on track for their fourth straight weekly decline.
Once oil companies sink cash into drilling wells, lining them with steel pipes and concrete, blasting the surrounding rocks into rubble with hydraulic fracturing, and linking them to pipeline systems, they have no incentive to scale back production, said Andrew Cosgrove, an analyst at Bloomberg Intelligence in Princeton, New Jersey.
Those investments, which represent “sunk costs,” are no longer a drain on cash flow, Cosgrove said. Instead, they generate capital companies use to repay debt, fund additional drilling, pay out dividends and buy back shares, he said.
Exxon, the world’s biggest oil producer by market value, is expected to boost crude and natural gas output by 2.8 percent next year to the equivalent of 4.1 million barrels a day, based on the average of eight analyst estimates compiled by Bloomberg.
Paris (AFP) – Global appetite for oil will grow at a slower pace in 2015 than earlier thought despite plunging crude prices, the IEA said on Friday, warning that further drops in prices heighten the risk of social instability in some oil producing countries.
Oil demand for 2015 was now expected to grow by 0.9 million barrels a day to reach 93.3 million barrels, some 230,000 barrels less than the previous forecast, it said.
Crude prices have collapsed by more than 40 percent since June, and are now trading around $60 — levels last seen five years ago, as increased US shale production adds to oversupply.
But the cheap oil was not prompting more consumption.
Market share lost to renewable energy sources was unlikely to be replaced again by cheaper crude, the IEA said.
In the OECD rich countries, “a tepid economic recovery, weak wage growth and … deflationary pressures will further blunt the stimulus of lower prices,” it added.
Any boost that cheaper crude could give to oil importing economies would be offset — if not more than offset — by the damage done to oil producers.
In focus is Russia, which is hammered by the double whammy of sliding oil revenues and Western sanctions.
The IEA said it was making the biggest cut to Russian demand, now expecting it to drop to 3.4 million barrels a day, 195,000 barrels below last month’s estimate.
“Lower oil prices significantly dent potential export revenues in net oil exporting countries, slashing their income streams and in turn denting demand.
“In particularly cash-strapped economies, such as Venezuela and Russia, this impact is likely to be magnified as the risk of default escalates,” said the IEA.
“The resulting downward price pressure would raise the risk of social instability or financial difficulties if producers found it difficult to pay back debt,” it added.
By JOSIE COX WSJ
Updated Dec. 12, 2014 5:46 a.m.
Oil’s persistent slide continued to drive global financial markets Friday, sending currencies in Russia and Norway to fresh multiyear lows, and stocks in energy companies tumbling.
In early trade, the ruble surpassed 57 against the dollar for the first time on record. Norway’s krone hit a new five-year low against the euro and an 11-year low against the dollar as Brent crude slumped to $63 a barrel and West Texas Intermediate settled below $60—both five-year lows.
Russia’s central bank on Thursday raised its key interest rate to 10.5% from 9.5%, and its deposit rate to 9.5% from 8.5%, in an attempt to halt the ruble’s slide, but economists broadly agree that isn’t enough.
“In my view the risk of a full-scale currency crisis is still high and the Bank of Russia may have to use all tools at its disposal to stem ruble rout,” said Piotr Matys, a currency strategist at Rabobank. He said he had been expecting a 2.5-percentage-point increase in the key interest rate. “The decision taken proved insufficient.”
The ruble was battered earlier this year by geopolitical tensions and resulting sanctions, but its decline has been exacerbated in recent months by the oil shock, especially after the 12-member Organization of the Petroleum Exporting Countries last month rejected calls for drastic action to cut their output. Around 50% of Russia’s annual budget revenue stems from oil and gas exports.
Also on Thursday Norges Bankcut its key interest rate to 1.25% from 1.5% to combat slowing domestic growth, specifically citing the tanking price of oil. Norway is Europe’s biggest crude exporter and Norges Bank said in a statement that “activity in the petroleum industry is set to be weaker than projected earlier.”
The Stoxx Europe 600 index was trading 1.5% lower midmorning, with major losers including Afren PLC, Genel Energy PLC, Tullow Oil and Petrofac Ltd.
London’s FTSE 100 index, with a very high exposure to the oil and gas sector was down 1.6%, putting it on track for its worst weekly loss in around two years. In the U.S, the S&P 500 was indicated opening 0.6% lower on the day. Futures, however do not necessarily mirror moves after the opening bell.
The European subindex of oil and gas companies declined 1.8% and economists said that the chills were starting to filter into debt markets, too.
“Falling oil prices have sparked weakness in the U.S. high-yield markets, which amid thin liquidity is intensifying volatility across fixed income assets,” Barclays economists wrote in a note.
The CBOE Volatility Index, commonly considered a fear gauge of financial markets, rose 8% overnight, reflecting investors’ appetite for assets considered safest during times of stress. The yield on German 10-year government bonds hit a record low of 0.652%. Yields fall when prices rise.
Beyond oil, lasting jitters stemming from political uncertainty in Greece additionally pressured equities.
Earlier in the week, the Greek government announced that Parliament would vote on a new president on Dec. 17—two months ahead of schedule—to replace Karolos Papoulias, whose five-year term was slated to end in March.
The move sparked fears that Greece’s radical left opposition Syriza party could win national elections if presidential voting rounds fail to find a solution acceptable to all.
“We wouldn’t rule out the possibility that mainstream parties can cobble together the majority needed to win support for a presidential candidate. Nevertheless, the political outlook for Greece remains highly fraught,” Citigroup economists write in a note.
Athens’s main stock exchanged tumbled 7% on Thursday having already closed around 12% lower during Wednesday’s session. On Friday it opened lower but later retraced some of that move, to climb around 1.5% by midmorning.
The yield on the country’s 10-year government bond stood at 8.9% Friday morning, around 0.08 percentage point tighter on the day. Only earlier this week, however, it was around 7.2%.
Back in currency markets, the euro was marginally higher against the dollar at around $1.243, little changed after figures showed that factory output across the 18 countries that share the euro rose for the second straight month in October, albeit at a modest pace.
Employment and industrial production, however, remain well below their pre-crisis levels and there is no indication that the eurozone’s recovery is set to accelerate to a pace that would quickly create large numbers of new jobs or end a long period of very low inflation.
Many analysts expect the European Central Bank to announce a government bond purchase plan to stimulate the recovery as soon as its Jan. 22 meeting—a forecast that was reinforced by weak demand for the second installment of a four-year lending program for banks. Results for that were published Thursday.