U.S. gasoline demand hit record levels in March. Government estimates released Wednesday show consumption averaged more than 9.4 million barrels a day in the four weeks that ended Friday. That is a level usually found only during peak summer driving season, and it compares with roughly 8.8 million barrels a day in March of both 2014 and 2015.
Drivers’ rising fuel consumption wasn’t enough to halt a retreat when oil prices dropped by more than 7% from a recent peak on March 22. And gasoline demand alone is unlikely to be enough to spark another oil rally. Gasoline matters less for market sentiment than news about crude supply, said investors, some of whom already have factored strong gasoline demand into their oil forecasts.
But gasoline demand may be the most stable contributor to oil prices. A preliminary deal among Saudi Arabia, Russia and other major oil-producing nations to cap output was the biggest catalyst for crude’s recent surge, many analysts said.
Yet, that production freeze has yet to materialize, and Kuwait’s announcement this week that it could restart production at another oil field cast further doubt that a deal can come together.
Even if it does, Iran’s plans to increase production by 500,000 barrels a day could mean global supply increases. Moreover, U.S. producers have spent seven months holding output steady at about nine million barrels a day, defying the conventional wisdom that low prices will force domestic producers to throttle back substantially.
Gasoline demand, meanwhile, is proving a reliable contributor to the supply-demand equation for oil.Bloomberg reports that the US is a big importer of oil ... again:
In the three months since the U.S. lifted its 40-year ban on crude oil exports, a curious thing has happened. Rather than flooding global markets, U.S. crude shipments to foreign buyers have stalled. At the same time, imports into the U.S. jumped to a three-year high in what looks to be a reversal of a yearslong decline in the amount of foreign crude brought into the American market.As of March 25, the four-week average of imports was running at 7.9 million barrels a day, 9.8 percent higher than the year before. “That’s not a one-week blip,” says Tim Evans, an energy analyst at Citi Futures. “We’re seeing a consistent pattern.”
During the early years of the U.S. shale boom, the millions of barrels of light, sweet crude had one big problem: no affordable access to refiners on the coasts of Texas and Louisiana. To tap into the cheaper oil pooling in Oklahoma, pipelines that used to bring imported oil up from the Gulf were reversed to take shale oil down to the coast. Refiners in Philadelphia and New Jersey also began buying North Dakota crude instead of foreign oil, moving it by train across the country. By October 2014, U.S. imports had fallen by about 40 percent from a high in 2006.
Analysts say that West Texas Intermediate crude has to be $3 to $5 cheaper than imported oil to pay for those pipeline and transportation costs. From 2011 to 2014, U.S. oil was on average $12.61 cheaper than equivalent foreign oil. The discount slowly narrowed as pipeline projects were completed and U.S. crude began to flow more freely from the middle of the country down to the Gulf Coast. A week before the Senate approved lifting the export ban on Dec. 18, WTI traded around $3 below Brent. Over the next month, the discount disappeared, and, for the first time in six years, WTI traded at a premium to Brent for a few days in January. WTI is now less than a dollar cheaper than foreign barrels available on the Gulf Coast.
So refineries along the coasts are choosing to buy imports instead of WTI. One of the biggest winners is Nigeria, which is regaining lost market share. Imports from Nigeria surged to 559,000 barrels a day in mid-March, compared with an average of 52,000 for all of 2015. Refiners are also taking more heavy oil from Mexico and Venezuela. Not only is it about $9 a barrel cheaper than WTI, it’s also what U.S. refineries prefer to handle.
The irony of the shale boom, and all the light crude it unlocked, is that it came just as U.S. refiners were spending billions to process heavy oil.
And, of course, the writer of that article conveniently forgets to mention why the US did not have a North American source of heavy oil.
Back To The Bakken
The drop in the number of active rigs between now and the next six may or may not be due to spring thaw / "road restrictions." If due to "road restrictions," the number of active rigs could drop more than expected, but for a relatively short period of time.
Four wells coming off confidential list Friday:
- 30969, SI/NC, EOG, Van Hook 47-3626H, Parshall, no production data,
- 31628, SI/NC, XTO, Ames Federla 31X-13B, Grinnell, no production data,
- 31699, SI/NC, Statoil, Shorty 4-9F 4TFH, Stony Creek, no production data,
- 31849, SI/NC, MRO, Ronald 34-33TFH-2B, Reunion Bay, no production data,
- Operator: BR (3), EOG
- Fields: Camel Butte (McKenzie), Parshall (Mountrail)
- BR (3), one Gudcadia and two Gudmunson permits, all three in McKenzie County
- Whiting (2), one Skunk Creek and one Two Shields Butte permit, both in Dunn County
- Sinclair, a Nelson permit in Mountrail County
- Twelve (12) oil and gas wells were transferred from North Plains Energy, LLC, to North Plains Energy II, LLC.