The United States Is Facing Electricity Famine
This life-threatening energy Holodomor is a direct result of political decisions—and it can be stopped.
There are signs that we are heading towards an electricity famine; a life-threatening energy Holodomor throughout many areas of the United States caused by political decisions. The system is being set up to fail.
This problem this time is not the usual banes of the electric system: kamikaze squirrels that short out distribution lines; the occasional ice storm or hurricane that requires re-stringing power lines. The problem is inadequate resources to generate enough electricity to fill the grid.
The quasi-governmental agency that tracks the health of the electric system, the North American Electric Reliability Corporation, reported in December that Texas, the Midwest, and New England are all at risk of running short of electricity. The coping mechanism? Rotating blackouts. And, NERC says, the story doesn’t look good in the rest of the country either.
The Mid-continent Independent System Operator, which coordinates energy flow in an area running from Minnesota to Louisiana, had expected a “capacity shortfall” in the summer of 2024, but now expects the deficit to arrive this summer. Coal, natural gas, and nuclear generators are being shut down there faster than replacements are being turned on.
New England, which has shut two nuclear plants in recent years, has been trying to run itself on natural gas, but gas demand has gown fast and pipeline capacity hasn’t. Because of the way regulators have structured the wholesale market, generators were very slow to prepare themselves for peak times, like when cold weather drives up home heating demand and not enough gas is left for the electricity plants; more recently, the generators have prepared by stockpiling heating oil, which in a pinch can be burned in gas generators in place of fossil gas. For a region that was paralyzed by oil shocks in 1973-74 and again in 1979, this is hardly progress.
Texas, which has intentionally isolated itself from the rest of the continent, electrically speaking, is prone to extreme weather that can produce variations in peak winter load by as much as 12.5 percent. But the Texas grid has financial regulations that result in an exceptionally lean generating system. Other grids offer payments for keeping generating units available, but Texas pays only for kilowatt-hours sold. The result is intermittent nail-biting episodes as grid operators beseech all generators to be available, and demand creeps up to the limit of available capacity.
So what does this energy shortage spell for the United States? Blackouts.
There are two huge problems with blackouts. One is that they kill people. Winter Storm Uri in February 2021, led to 246 deaths in Texas. There was a widespread perception that the problem in Texas was too much wind and solar hardware on the grid, and not enough conventional, dispatchable power.
One Austin lawyer who practices energy and environmental law traveled around the country with a presentation that said in part, “Wind & solar performed about as well as you would expect during a winter storm” in other words, “ they produced almost nothing when we needed them most.” The lawyer represented an organization funded in part by oil and gas companies and conservative organizations, but regardless of its source, the argument resonated with some voters.
Whether it was true or not, it foreshadowed a wider blame game as the performance of the Texas grid operator, the Electric Reliability Council of Texas, known as ERCOT, became a local joke.
For now, ERCOT is adding a lot of generation resources, officials say, but these are mostly wind and solar, which are not schedulable. They also won’t help much with the big challenges for the grid outside of unexpected disasters: peak summer demand and the winter peak.
Meeting peak summer demand is getting tougher because of a problem directly related to that demand: heat. Hot weather warms up the transmission lines, and operators can’t push as much current through hot wires as they can through cool wires. “Extreme summer temperatures that stress large portions of the interconnection reduce the availability of excess supply for transfer while also reducing the transmission network’s ability to transfer the excess,” said NERC. Clean resources like solar and wind are often produced in places far distant from load, and when they’re needed most, when high temperatures push demand to their highest levels, the grid can’t move the energy where it’s needed.
As system operators across the country have recently encountered, moreover, fossil plants and wind plants often don’t do well in cold weather, which comes to bear on production for peak winter demand. Since the cold weather hits in periods when the sun is up briefly and not very high, solar doesn’t work well either. And as homeowners replace fossil gas furnaces that heat their houses with heat pumps, essentially reversable air conditioners, the cold weather demand peaks are going to get peakier.
And these two cyclical challenges are set to run straight into a big systemic one: “Energy systems and the electricity grid are undergoing unprecedented change on a scope, scale, and speed that challenges the ability to foresee—and design for—their future states,” NERC reported. The transition to a clean system, supposedly now underway, will mean profound things for the grid. If the United States is to reach its goal of net-zero carbon emissions by mid-century, the predominant thinking is that electricity will have to replace nearly all the gasoline and diesel, and it will fill in for all the space heating done by natural gas. All the natural gas burned in industry will have to be replaced, too.
How big an electricity system (how many generators, how much transmission, and how much storage) does the United States need for that?
It depends on the rate of economic growth and whether the United States can make efficiency improvements, but if we assume that these cancel each other out and total energy demand doesn’t change, then the number of kilowatt-hours consumed has to double or triple by mid-century. And of the system we have now, 60 percent of electricity is generated by burning fossil fuels. In other words, the 40 percent that is non-emitting—nuclear, wind, hydro, and solar, in that order—must grow by a factor of 8 to 10.
That seems like a heavy lift for a system that already has trouble keeping the lights on. So what’s next? Potentially, a return to the bad old days of electricity shortages. On a national basis, we haven’t seen problems like this since the late 1960s and early 1970s, when everybody discovered air conditioning at the same time and peak demand started growing by 7 percent a year, which meant that demand was doubling every 7 years or so. (What stopped the trend that time was the Arab oil embargo, which triggered a recession.)
This time the problem is different. Some of the growth in demand is due to new devices, many of them driven by environmental concerns. This includes electric cars and heat pumps replacing natural gas and oil home heating, both of which could help limit global warming. Some of it is just new demand, like data centers churning out cryptocurrency and managing social media posts. And some of it is because of increasing reliance on intermittent sources that are not synchronized with demand.
There’s a good chance that solar and wind aren’t going to rescue us. Leaving aside their dismal inability to time production—solar is like the guest who shows up for cocktails at noon, and wind drops in on a schedule all its own—they are often unwelcome as neighbors. As observer Robert Bryce points out, there has been a revolt against both in rural America. Last year, he counted 40 townships in Ohio alone that prohibited large solar or wind projects, or both. Nationwide, nearly 80 rural governments did the same, according to his Renewable Rejection Database.
Another problem is that it’s getting harder to add anything to the electric system. Lawrence Berkeley National Laboratory reported in January that the cost was soaring for hooking up additional generators to the system. The lab looked at PJM, the nation’s largest power market, which began as Pennsylvania-Jersey-Maryland and now stretches to Delaware and DC, Virginia and West Virginia, Ohio and portions of other states, including the Chicago area.
It found that connection costs are now running $240 per kilowatt of capacity (A kilowatt of power is enough to run a small microwave oven), up eightfold compared to two years earlier. These costs were not simply for stringing wires from a solar farm or wind farm to the nearest transmission line; maintaining grid stability often means shoring up distant connections, as new generation creates new patterns of electricity flow in the wider system. An increasingly heated debate attaches to the question of who pays these costs, which are in addition to the fees, permits, and other “soft costs” of adding generation.
The $240 adds a substantial increment to the cost of the generator itself; solar farms often cost less than $1,000 per kilowatt of capacity.
There are other barriers, too, including lengthy processes by which the market managers, called Independent System operators or Regional Transmission Organizations, decide which projects can connect. And solar energy has been hit hard by a federal law to bar imports of panels made by slave labor in the Uyghur region of China; installations were down 40 percent in 2022 compared to the year earlier. If the solar industry gets serious about cutting human rights abuses from its solar supply chain, as Breakthrough’s Seaver Wang has written, then more disruptions could be to come. Already, the price of solar hardware has jumped.
Meanwhile, wind installations were down by more than 75 percent in the second and third quarters of last year, according to S&P Global. The industry says it has supply chain issues.
At the same time, electricity prices were up 14.3 percent between December 2021 and December 2022, driven by scarcity and by the high price of natural gas, forced up in North America partly because of exports to Europe, which is seeking to get by without Russian supplies. But that was an average; in places that were more dependent on natural gas, price increases were much higher.
In the bad old days, gas supplies were less of an issue. Coal dominated for much of the 1980s and 1990s. It was dirty, but you could ship it where it was needed and build up piles that would last for months. Now coal has largely been replaced by natural gas, which is a just-in-time fuel.
And a lot of the natural gas is burned by “merchant generators,” independent power plants that start up or shut down according to market demand, and whose survival depends on sales revenues. They do not have the incentives that the old, regulated monopolies did to lock in supply contracts, or buy guaranteed capacity on gas pipelines to make sure they have access when demand is high.
This is a byproduct of “deregulation.” (It’s popularly known as deregulation, but “restructuring” would be a better term; bit parts of the country went from monopoly utilities that burned the fuel, transmitted the energy, distributed it and billed for it, to a system where generation was owned by different companies that competed on the grid on an hour-by-hour basis, or even a minute-by-minute basis.) In traditional regulation, state-level public service commissions set rates based on how much a utility company had invested in the system, providing an incentive for the companies to spend money on reliability, and to over-build.
Now, the business is open to everybody, and transmission systems have been taken over by independent system operators, like PJM or MISO. The “merchant generators” that play in those markets—either building power plants or operating them—have a different calculus. They look at how much they are likely to receive in revenue for selling kilowatt-hours. And in most markets, the generators’ customers, i.e., the companies that distribute energy, are also obligated to make payments to reserve “capacity.” That is, they rent generating capacity equal to their peak demand. (Texas has only an energy market, though.)
The result is that potential builders are making decisions not on how much generation will be needed to meet demand, but by whether their revenues will be likely to exceed their costs. The decisions on individual plants ignore considerations that used to be part of the picture in the bad old monopoly days, like fuel diversity. And as Meredith Angwin pointed out in her 2020 book, Shorting the Grid, we have arrived at a point where no one is ultimately responsible for reliability, and where decisions about individual power plants no longer reflect any concern for the system as a whole.
Operating in a “deregulated” market has another effect: It limits what you can build. Long-term thinking, including innovation, is frowned upon. In a system where revenue depends on running in a balanced market, few companies want to build a project that will take eight or ten years, because it’s hard to judge now what the market will be like then. And few want to build a first-of-a-kind project, because its completion schedule is less predictable than a cookie-cutter copy of something that’s already running. Hardly anybody, for example, wants to build the kind of technology that is the most durable and clean: nuclear reactors.
Still, in theory, a deregulated system should produce enough power, because the market will perform the reliability function that monopolies once did. “Scarcity pricing,” episodes where prices run 10 or fifteen times higher than normal, should induce builders to add capacity. (Certainly, scarcity pricing happens; on New Year’s Eve 2022, when several generators broke down in cold weather, prices in New England went over $2,000 a megawatt-hour, compared to an average winter price of $130 a megawatt-hour.
It’s not clear whether scarcity pricing is doing its job, though. Worse, solar and wind are playing unanticipated tricks on the market. The people who conceived the system of independent system operators were not concerned with oversupply; when market prices fell, generators would shut down, to save fuel and reduce operation and maintenance expenses. It was classic Economics 101; high prices induced producers to supply more, and lower prices led them to supply less. But wind and sun don’t fit well into that model.
Solar and wind energy have no fuel cost, and hardly any operation and maintenance cost, so no matter how low prices go, there is little incentive to turn them off. Wind producers get a federal tax credit for every kilowatt-hour they make, so they can be profitable even when prices fall below zero. And wind and solar plants in most jurisdictions generate something called “renewable energy credits,” which they can sell. Entities that are obligated by state laws to meet a renewable energy quota can do so by purchasing the renewable energy credits from solar and wind operators.
As a result, what the industry calls “dispatchable” generators, that is, plants whose output can be dialed up or down as conditions require, find themselves needed less or not at all at mid-day on sunny days, or at night when demand is low and the wind is blowing strong. So their plants run fewer hours of the year. Like a taxi owner who has car payments to make, being shut down for economic reasons during what used to be revenue-producing hours makes it hard to stay in business.
Some nuclear plants have been hit especially hard because they cannot easily reduce their output, and thus may run at full power through hours when prices have reached zero or even lower. The coming predominance of solar and wind generators on the California grid was a factor in Pacific Gas & Electric’s initial acquiescence to the retirement of Diablo Canyon, a decision that many actors are now trying to forestall and reverse.
But the bottom line is that a system designed to minimize electricity costs, and intended to provide adequate service, isn’t always filling the second function and looks hard pressed to accomplish a new one, increasing its carbon-free generation by a factor of eight to ten.
Thus far, the Federal government has tried to shape the electricity system with incentives like production tax credits and investment tax credits, and some help for research & development for new technologies. The states have pushed their favored technologies by setting quotas. (Some, narrowly, with “renewable energy” quotas and others, more sensibly, with quotas for all non-emitting generation.) These policies, especially in California, have led to hard-to-manage surges of generation that come from weather-dependent technologies, and don’t show a clear path towards a vastly expanded, zero-emissions electricity sector. The solution may require more planning—and more emphasis on generation that can be ordered to run when it’s needed, that is zero-emitting, and that is fuel secure. Fossil fuel with carbon capture remains a possibility, but it faces terrific technical and legal problems. The more obvious solution, of course, is nuclear.