Outlook for Oil Prices ‘Only Getting Murkier,’ Energy Agency Says
By Stanley Reed, April 15, 2015Royal Dutch Shell is expecting prices to recover much of their recent drop over the next few years. It projects prices to hit $90 a barrel in 2018. Chris Ratcliffe / Bloomberg
LONDON — The outlook for oil prices is still uncertain after the sharp fall that began last summer, the International Energy Agency said on Wednesday.
Given the price collapse, “one might be hoping for more clarity on supply and demand,” the agency acknowledged in its monthly Oil Market Report, which was released on Wednesday. “Yet in some ways, the outlook is only getting murkier.”
Oil prices, which have fallen about 50 percent since June, rose after the report and a separate United States government report that said that American crude stockpiles had risen less than expected.
The international benchmark, Brent crude, was up about 3 percent on Wednesday, to $60.35, while its American counterpart jumped more than 5 percent to about $55.97.
The agency’s report reflects a broad debate inside and outside the oil industry about where prices might eventually settle.
Citigroup, for one, expects prices to continue falling in the coming months, as output remains high, supply is building up and investors who had helped prop up prices begin to sell.
“While prices have held relatively firm, there are significant signs of weakness ahead,” Citigroup said in a note to clients on Tuesday.
Royal Dutch Shell, the oil giant that announced an almost $70 billion takeover of the British oil and gas producer BG Group last week, is expecting prices to recover much of their recent drop over the next few years. It projects prices to hit $90 a barrel in 2018.
As the International Energy Agency noted, competing forces are still playing out in the market, making the direction difficult to discern. Low prices have stimulated higher-than-expected demand for oil products in China, India and even Europe, which has been plagued by lethargic economic growth, the agency said. But whether that increased consumption is a “temporary aberration” remains to be seen, it added.
There is much uncertainty, for instance, over future crude demand from China, which on Wednesday reported economic growth of 7 percent, the weakest rate since early 2009.
Supply is also hard to gauge. While there are signs that low prices are beginning to have an impact on the production of oil from shale rock, overall oil output in the United States is expected to grow this year, the agency said.
In addition, the Organization of the Petroleum Exporting Countries is showing no signs of backing away from the policy, backed by Saudi Arabia, of holding onto market share regardless of falling prices. OPEC production rose almost 900,000 barrels a day in March from a month earlier, the agency said, as Saudi Arabia increased production to more than 10 million barrels per day.
Among the uncertainties in the market is the potential effect on oil supplies of a proposed nuclear accord with Iran, a major producer, the agency said. International sanctions have sharply reduced the country’s sales of oil, and an accord is expected to ease, or lift, those sanctions.
While it would take time for Iran to organize the enormous investment that would be required to sustainably bolster its production capacity, the agency said that the country might be able to make short-term changes to increase output and exports relatively quickly.
For instance, the agency said, Iran has 30 million barrels of oil stored on tankers, which could quickly feed an increase in exports. The agency also estimated that Iranian oil fields could ramp up production to as much as 3.6 million barrels a day, a 29 percent increase, within months of sanctions being lifted.
Specialists have been working at some of those sites, and “some of Iran’s core fields,” which were run down, may already have been revived, the agency said.
Under the pressure of sanctions, both Iranian production and exports have been curbed. Exports are down about 50 percent since 2012, to an average of around 1.1. million barrels a day, though they rose to 1.3 million barrels a day in March on high demand from China.
In California, Farmers Rely on Oil Wastewater to Weather Drought
By Zoë Schlanger / April 6, 2015 6:54 AM EDT
Overlooking Chevron’s Kern River oil field with the Sierra Nevada in the background, March 30, 2015. Percy Feinstein/Corbis
The wet, white noise of gushing water rises above a background track of twangy guitar. Water is tumbling out of a pipe into a holding pond that looks as though it has sat nearly empty for ages, its sandy sides the color of parched desert. It looks like the California of recent headlines: drought so bad the ground is blowing away. Except now, here, in this promotional video for Chevron, there is water. Lots of it.
“The sound of that water is music to my ears,” David Ansolabehere, the general manager of the Cawelo Water District in Kern County, says in the video, gazing out over the rapidly filling pond. “Chevron is being environmentally conscious, and this is a very beneficial program, and it’s helped a lot of our farmers, helped our district, tremendously.”
The oil fields of Kern County, where Chevron is the largest producer, pump out more oil than those of any other county in the United States. It also happens to be one of the country’s most prolific agricultural counties, producing over $6 billion in crop value every year. But after three years of strangling drought, all that agriculture is on life support.
That’s where Chevron comes in. For every barrel of oil Chevron produces in its Kern River oil field, another 10 barrels of salty wastewater come up with it. So Chevron is selling about 500,000 barrels of water per day, or 21 million gallons, back to the Cawelo Water District—the local water district that delivers water to farmers within a seven-mile slice of Kern County—at an undisclosed amount, but “essentially ‘at cost,’” according to Chevron spokesman Cameron Van Ast. In a time when freshwater in the Central Valley is selling at up to 10 times the typical cost, it’s a good deal for farmers.
The wastewater Chevron is selling flows, without municipal treatment (though the oil products are removed), to 90 local farmers who spread it on their citrus, nut and grape crops. The Cawelo Water District might first mix the wastewater with freshwater, or it might not, depending on what crop the wastewater will be used on—and on how much freshwater is available at the time. In the midst of a drought, there is less freshwater, so the water the farmers get is saltier than in a wet year. But the farmers understand that using the salty wastewater on their crops is an emergency measure. If all goes as planned, when the rains come back the excess salt will be flushed through the soil.
But it’s a risky dance; over time, high sodium can change the properties of the soil, making it impermeable, unable to take in any more water. Trees would start to get “salt burn.” Their leaves would turn yellow, and yields would decline. Eventually, the soil becomes barren.
Ansolabehere says the wastewater mixture sent to farmers is rigorously monitored to keep from salting the soil to that degree. It is tested quarterly for salts and boron, he says. “The only reason this program works is because [Chevron’s] production water is of very good quality,” he says. “So maybe we’ll have a little salt buildup. But the next rain will flush it out.”
But the National Weather Service doesn’t foresee much rain in the immediate future. In fact, drought conditions may “intensify.”
For local farmers, dwindling water is a noose slowly tightening. Most take relief wherever they can get it, but not Tom Frantz. “I would rather let my trees die” than use the Chevron water, he says. Frantz is a small-time almond farmer who lives about six miles from the oilfields where the wastewater is pumped into mixing basins. His 36 acres are a speck in the shadow of much larger operations; vast orange groves, pistachio trees, rows and rows of almond trees. But Frantz knows farming. He’s been in Kern County, just west of the town Shafter, for all of his 65 years. His grandparents were farmers a few miles away. His parents farmed, too. There’s a generation below him, he says, who look as if they’ll take it up soon.
In normal years, Frantz depends on groundwater pumped from wells, as well as “surface water,” the water held in municipal reservoirs that flows in frigid streams from the melting snowpack in the Sierra Nevada mountains. But with the Sierra snowpack this winter at a paltry 6 percent of its typical heft, there won’t be much to melt. Chevron’s wastewater is an option, but Frantz knows what all farmers know: You can’t grow food with salty water for very long.
Irrigation water runs along the dried-up ditch between the rice farms to provide water for the rice fields in Richvale, California, May 1, 2014. Jae C. Hong/AP
“It’s just not sustainable at all to use salty water, no matter how much you dilute it…. We can farm here a long time, if we’re careful about the salts that we apply,” he says. “I’ve seen the farms that have saltier groundwater, and they have severe difficulties after 50 years. That’s very low levels of salts that’ll do that.”
Frantz has little confidence in how oil industry wastewater is regulated in his area, and he is concerned by what still isn’t known about the contents of the wastewater. Recently, there was a scandal over news that state oil and gas officials for years let oil companies inject drilling and fracking wastewater into hundreds of wells in protected aquifers. The water was laden with the benzene, a carcinogen, according to a Los Angeles Times investigation. “What it shows me is that we have to look out for ourselves,” Frantz says.
California doesn’t have statewide regulations for recycling wastewater for agriculture. Instead, nine regional water boards issue permits to local water districts. Once a year, the Cawelo Water District is required to send data about the salt and boron content to the Central Valley Water Board, according to Clay Rodgers, the board’s assistant executive officer. But the district isn’t obligated to test for other components, like heavy metals, arsenic, radioactive materials and chemicals that might be used in the drilling process. Ansolabehere says Cawelo has tested for radioactive elements “a couple of times” over the past 20 years, since “it’s very expensive” to test for, and it isn’t required by the board. Those tests have not turned up any positive results.
Chevron, for its part, says testing last month showed no heavy metals or chemical toxins were present in the water above maximum allowable levels. The arsenic levels were high, however, but “issues related to the arsenic concentrations in the water were fully addressed in the process of obtaining the permit from the Central Valley Regional Water Quality Control Board,” Chevron said in a statement. “Protection of people and the environment is a core value for Chevron, and we take all necessary steps to ensure the protection of our water resources.”
The Central Valley Regional Water Quality Control Board came to the conclusion that the high arsenic in the waste water was acceptable because most of the arsenic appeared in models to get “tied up” in the soil as it made its way down to the water table, says Rodgers. In other words, the Board sees no threat of tainting the groundwater with arsenic, because it largely stays in the soil. But no monitoring is in place to see if that arsenic is building up to unsafe levels in the agricultural soils themselves.
Little to no independent scientific research has been done on this type of water and how it interacts with crops, soil and surrounding bodies of water. Some scientists say there are too many unknowns associated with the wastewater from oilfields. If it is being used on food, and to irrigate land that lies above drinking water aquifers, we need to know more about it, they say—especially in light of the fact that, as Rodgers notes, the Central Valley hopes to expand its use for farm irrigation during the drought.
“There might not be a single risk out there with this practice. But the biggest risk that we have right now is that we just don’t know,” says Seth Shonkoff, an environmental public health scientist and a visiting scholar at the University of California, Berkeley. “So until we know, we definitely have reason for concern. We know that there are compounds being put down oil and gas wells that you would not want in your food.”
To Shonkoff’s knowledge, no scientist has ever published a study on what compounds from the oil development process—examples he gives are methanol, biocides and surfactants—might be in oilfield wastewater used on crops. Chevron says these constituents are kept separate from the water delivered to farmers.
Avner Vengosh, a Duke University geochemist, is serving on an expert panel for the U.S. Geological Survey while it begins to look into the quality of produced oil-field water from Kern County. His data are “only preliminary,” but he has found “high levels of vanadium, chromium and selenium” in the samples of wastewater he has tested (although he was unable to say if the water was produced from Chevron’s operations or another of the many operators in the area). Those levels are consistent with data from oil- and gas-produced water from other basins in the U.S., according to Vengosh.
Vanadium, a metal, is classified as “possibly carcinogenic” by the International Agency for Research on Cancer. Certain forms of chromium and selenium, both heavy metals, are associated with myriad health problems, including cancer, from chronic high exposure. Ansolabehere says the Cawelo Water District tested for chromium and selenium once, last year, and found none. It has never tested for vanadium. None of these metals are required to be tested for by the Central Valley Water Board.
Could the crops be absorbing these metals? The California Department of Food and Agriculture says it doesn’t have the jurisdiction to look. The Central Valley Water Board doesn’t sample crop residues where the water is used, either.
For Vengosh, what is most worrisome is the possibility that the water is seeping through the farmland into the water table. “It would end up in underlying groundwater. If the groundwater is moving to a drinking water source, you would end up with that in the drinking water eventually,” he says.
No matter how tough the drought gets, Frantz says, he won’t be taking the Chevron water. “It just doesn’t make sense to ruin something,” he says. “To get through years like this, we have to take some land out of production.”
But for Roy Pierucci, a farmer who manages a 160-acre pistachio farm that falls within the Cawelo Water District, the unknowns about the Chevron water won’t deter him from using it. If the water contains some as of yet unknown elements, “it would be a risk we’d be willing to take,” he says, without hesitation. He’s been using the Chevron water for 10 years and has never seen a problem with his crops. (Pierucci was featured in the Chevron promotional video, though he wasn’t paid for the appearance—he says he participated because he values what the company does for the water district.)
“I’ve really never asked what the analysis of the water is. I just know it’s available. There hasn’t been any complaints about it. I don’t think they recommend drinking it,” Pierucci says. “If [the drought] keeps up year after year, I think it would be a concern. I think the salt levels would be higher. They blend it for a reason.”
The Chevron water is vital to Pierucci’s operation, but it isn’t a game changer. “It’s not going to save us,” he says. Three years of brutal drought have left his pistachio trees teetering on the edge of survival. If the drought persists another two or three years, he says, he’ll have to start ripping out his trees and reducing the number of acres he irrigates. On another property he manages, where there is no pumping well on-site, he imagines he’ll be pulling out trees within a year. “You can’t chase water forever. Sooner or later you’re going to lose.”
This article has been updated to include a statement from Chevron regarding their internal water testing processes and results, as well as information about arsenic monitoring from the Central Valley Regional Water Quality Control Board.
By Alison Sider, April 6, 2015 3:30 p.m. ET
In March, oil-train traffic was down 7% from a year earlier. The slowdown comes amid safety concerns. Photo: David Paul Morris/Bloomberg News
The growth in oil-train shipments fueled by the U.S. energy boom has stalled in recent months, dampened by safety problems and low crude prices.
The number of train cars carrying crude and other petroleum products peaked last fall, according to data from the Association of American Railroads, and began edging down. In March, oil-train traffic was down 7% on a year-over-year basis.
Railroads have been a major beneficiary of the U.S. energy boom, as oil companies turned to trains to move crude to refineries from remote oil fields in North Dakota and other areas not served by pipelines. Rail shipments of oil have expanded from 20 million barrels in 2010 to just under 374 million barrels last year, according to the U.S. Energy Information Administration.
About 1.38 million barrels a day of oil and fuels like gasoline rode the rails in March, versus an average of 1.5 million barrels a day in the same period a year ago, according to a Wall Street Journal analysis of the railroad association’s data.
Oil-train traffic declined 1% in the fourth quarter of 2014 as crude-oil prices started to tumble toward $50 a barrel. More recently, data from the U.S. Energy Department show oil-train movements out of the prolific Bakken Shale in North Dakota have leveled off as drillers there have begun to pump less, though oil-train shipments from the Rocky Mountain region have risen.
The slowdown comes as federal safety experts call for stronger tank cars. On Monday the National Transportation Safety Board recommended an aggressive five-year schedule for phasing out or upgrading older railcars used to haul crude-oil. A string of oil train accidents in recent months have resulted in spills, intense fires and community evacuations. The NTSB said railcars in use today rupture too quickly and aren’t fire-resistant enough.
A few incidents have involved more modern tank cars—the CPC-1232 model. The NTSB also said the new railcar’s design isn’t sturdy enough. “We can’t wait a decade for safer rail cars,” said NTSB Chairman Christopher A. Hart Monday in a letter to federal transportation regulators.
Opponents of a fast phaseout have said that if tougher standards are introduced too quickly it will create a railcar shortage and make some oil train operations unprofitable.
Many refiners, including Philadelphia Energy Solutions, say they are still committed to shipping oil on trains. Chief Executive Phil Rinaldi in December said he likes that railroads don’t require long-term contractual agreements the way pipelines do. That allows his plant managers to buy crude only when it’s needed.
With pipelines, “you have to pay for that transit whether it makes sense or not,” Mr. Rinaldi said. “With rail, that’s not the case.”
Railroad operators have warned investors that their outlook for transporting crude is slightly weaker than it was last year, said David Vernon, a rail analyst at Sanford C. Bernstein & Co.
BNSF Railway Co., which is responsible for about 70% of U.S. oil-train traffic, operated as many as 10 trains a day last year, but is averaging nine a day now, a spokesman said.
Repost from UPI Business News [Editor: Significant quote: “Dalrymple said rail traffic may drop off once new pipeline infrastructure comes online. Three pipelines — Sandpiper, Dakota Access and Upland — should be in service by 2018” – RS]
North Dakota reviews oil-train safety
About half of the oil produced in the state is delivered by rail.
By Daniel J. Graeber | March 19, 2015 at 9:40 AM
North Dakota Gov. Jack Dalrymple calls for tighter rules to ensure safe transport of crude oil from state’s Bakken shale reserve. Photo by Steven Frame/Shutterstock
BISMARCK, N.D., March 19 (UPI) — There’s no way to offer a single solution that would allay concerns about the safety of crude oil transit by rail, North Dakota Gov. Jack Dalrymple said.
Dalrymple spoke with U.S. Transportation Secretary Anthony Foxx to discuss efforts to improve the safe transport of crude oil by rail from the state. The Republican governor said he called on the secretary to adopt new standards for rail cars carrying crude oil as soon as possible.
“Secretary Foxx and I agree that there is no single solution to improving the safety of rail transportation,” Dalrymple said in a statement Wednesday.
North Dakota crude oil production is more than existing pipeline capacity can handle, forcing many in the industry to use rail as an alternative transit method. The increase in rail traffic has in turn led to an increase in derailments involving trains carrying crude oil, a situation compounded by federal reports showing oil from the Bakken reserve area in North Dakota may be less stable than other types of crude oil.
A 200-page proposal from the Department of Transportation last year called for the elimination of older rail cars designated DOT 111 for shipment of flammable liquid, “including most Bakken crude oil.”
A February derailment in West Virginia involved a train carrying Bakken oil. At least 40 people were killed in Lac-Megantic, Quebec, in the 2013 derailment of a train carrying tankers of crude oil from North Dakota to Canadian refineries.
Dalrymple said rail traffic may drop off once new pipeline infrastructure comes online. Three pipelines — Sandpiper, Dakota Access and Upland — should be in service by 2018 and provide 895,000 barrels per day in new capacity.
North Dakota produces about 1.2 million bpd and about half of that is shipped by rail.
The state government in December approved a new measure that requires oil producers in North Dakota to install equipment at their facilities that would reduce the volatility of Bakken crude.
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