A single electric-car battery weighs about 1,000 pounds. Fabricating one requires digging up, moving and processing more than 500,000 pounds of raw materials somewhere on the planet. The alternative? Use gasoline and extract one-tenth as much total tonnage to deliver the same number of vehicle-miles over the battery’s seven-year life.
When electricity comes from wind or solar machines, every unit of energy produced, or mile traveled, requires far more materials and land than fossil fuels. That physical reality is literally visible: A wind or solar farm stretching to the horizon can be replaced by a handful of gas-fired turbines, each no bigger than a tractor-trailer.
Building one wind turbine requires 900 tons of steel, 2,500 tons of concrete and 45 tons of nonrecyclable plastic. Solar power requires even more cement, steel and glass—not to mention other metals. Global silver and indium mining will jump 250% and 1,200% respectively over the next couple of decades to provide the materials necessary to build the number of solar panels, the International Energy Agency forecasts. World demand for rare-earth elements—which aren’t rare but are rarely mined in America—will rise 300% to 1,000% by 2050 to meet the Paris green goals. If electric vehicles replace conventional cars, demand for cobalt and lithium, will rise more than 20-fold. That doesn’t count batteries to back up wind and solar grids.
Mineral rights-owning companies aren’t without risk. Royalty payments are tied to both production levels and commodity prices, neither of which mineral owners typically control. Many shale companies have cut spending on drilling this year, while oil prices have hovered around $60 a barrel. Less production paired with lower prices means the value of royalty payments will drop.
“Part of the risk associated with the investments is you are a passive investor,” said Justin Stolte, a partner at law firm Gibson, Dunn & Crutcher.
Still, the value of large mineral owners such as Texas Pacific Land Trust, formed after Texas and Pacific Railway went bankrupt in the late 1800s, has soared as the booming Permian Basin of West Texas and New Mexico transformed the U.S. into the world’s top oil producer. The price of shares in the trust has more than quadrupled in the past five years to more than $760.
They forgot management agency risk…
Frackers in the region pay an average 50 to 75 cents for a barrel of water, according to Bluefield Research, a water advisory firm. That amounts to more than $200,000 a well. Supplying water for fracking in the Permian is a roughly $1.2 billion industry annually, and including transportation and other costs, water spending for fracking there will surge to as much as $54 billion over the next decade, the firm said.
By the 1980s, Mr. Williams had amassed about 18,000 acres above a number of aquifers, deep deposits trapped in a natural underground dam some scientists believe an asteroid impact formed millions of years ago. The aquifers are valuable because they fill every winter from nearby mountains. The Williamses are Texas’ largest private water owners, some hydrogeologists estimate.
Decent use of seven minutes on a Friday morning. Nothing you probably don’t already know but it is a good zoom out to the big picture.
Shale was largely behind the glut of American oil that flooded the market more than four years ago, leading oil prices to fall to $30 a barrel from more than a $100 a barrel in late 2014.
U.S. shale production in 2018 grew faster than it did during the boom years of 2011 to 2014, the IEA said last year.
The U.S. last year surpassed Russia and Saudi Arabia to become the world’s largest producer of crude oil, with output currently hovering around 12 million barrels a day.
U.S. crude production is expected to rise to 13.7 million barrels a day by the end of its five-year forecast period, the IEA said Monday.
“Annual gains will boost the U.S. to levels never seen in any country, in excess of maximum capacity in both Russia and Saudi Arabia,” the report noted.
In the next five years, Chevron expects to more than double its production in the Permian Basin in Texas and New Mexico to 900,000 barrels of oil and gas a day, the company announced at an investor event Tuesday. That’s a nearly 40% increase from its previous forecast.
“The shale game has become a scale game,” Chevron Chief Executive Mike Wirth said in an interview. “The race doesn’t go to the one who gets out of the starting blocks the fastest. The race goes to the one who steadily builds the strongest machine.”
Not to be outdone, Exxon on Tuesday announced plans to increase its Permian output to 1 million barrels of oil and gas a day by as early as 2024, a day before it was expected to disclose growth at its own investor meeting Wednesday. BP PLC,Royal Dutch Shell PLC and Occidental Petroleum Corp. are also focusing on the region.
Five years ago, Exxon, Chevron, BP, Shell and Occidental collectively made up about 9% of crude production from modern fracking techniques in the Permian. In October, the latest period for which relevant figures are available, they made up about 16%, according to data on ShaleProfile, an industry analytics platform.
Meanwhile, the big companies are just getting started. Exxon is now the largest operator in the Permian, with almost 50 rigs. The company estimates its Permian wells can generate a 10% rate of return at an oil price of $35 a barrel. While many companies reduced fracking activity in the fourth quarter of last year, Exxon increased it significantly to over 80 wells, more than double the total in the fourth quarter of 2017, according to Rystad Energy.
Chevron is raising its production guidance to 900,000 barrels of oil and gas a day by 2023. Last year, it predicted 650,000 barrels a day by 2023. The company is boosting production without adding to its rig count, a testament to how size can lead to greater efficiencies.
Chevron employed what could be described as a tortoise-and-hare strategy in the Permian. While smaller companies at times paid more than $40,000 an acre to gain rights to prime drilling opportunities, Chevron held on to land it already owned in the region, which decades ago was one of the world’s biggest traditional oil fields, without having to join in the buying frenzy.
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Within hours of each other on Tuesday, the two largest energy companies in America announced they want to pump almost 2 million barrels a day combined in the Permian Basin of west Texas and New Mexico, a higher amount than most OPEC nations. Chevron plans to reach 900,000 barrels a day by 2023, while Exxon aims for 1 million by 2024.
“Our position in the Permian just continues to get better and underpins our resource base,” Chevron Chief Executive Officer Mike Wirth said in New York. The value of the company’s Permian position has doubled over the past two years with reserve additions, he said.
Good read on technology and science at play in the Permian. This is a reminder that a great deal of what is happening (in my estimation) is still experimental.
Known in the industry as the “parent-child” well problem, the issue is surfacing in shale hot spots across the U.S. as companies ramp up production. Most of the tens of thousands of planned new wells will be child wells—wells drilled close to an already producing well.
It is one of the primary reasons why thousands of shale wells drilled in the past five yearsare producing less oil and gas than companies forecast to investors, a Wall Street Journal examination of drilling data has found.
Shale producers across the country are finding “you can get a lot of interference, one well to the other,” said billionaire Harold Hamm, who founded shale driller Continental Resources Inc., in an interview last year. “Laying out a whole lot of wells can get you in trouble,” he said. Mr. Hamm was discussing other companies, not Continental.
Many of the largest shale producers, including Devon Energy Corp. , EOG Resources Inc.and Concho Resources Inc., have disclosed they are facing the problem. Some have begun drilling wells farther apart to get around it, which means they have fewer total wells to drill on their land.