Another summer, another nail-biter for the Texas power market.
The dog days of August saw grid operator ERCOT’s reserve generating margin melt to nearly nothing amid a heat wave, as record power demand drove wholesale prices to an eye-watering $9,000 per megawatt-hour. (Average real-time wholesale prices in 2018 were about $36 per megawatt-hour.)
Texans were asked to turn down their air conditioners — never a popular request — and ERCOT issued its first “energy emergency alert” in five years.
These are edge-of-your-seat events for an American grid operator, even one as big as ERCOT, whose 75-gigawatt peak-demand record set last month is 30 percent higher than peak load for the whole of the U.K.
“We had what I’m calling ‘the five days of August,’ of high loads coupled with not-unexpected lower wind output,” explained Beth Garza of Potomac Economics, which acts as the independent market monitor for ERCOT. “We found ourselves at the very edge of that demand-supply balance.”
Texas may be the country’s leading state producer of oil and gas, but thanks to its vast fleet of wind farms, it now generates nearly as much of its electricity from wind and solar as green-minded California, at around 20 percent. That number will rise rapidly over the next few years, potentially overtaking the Golden State.
Largely cut off from the rest of the North American grid, ERCOT is an important testing ground for a high-renewables, hands-off model run on price signals alone. But the stakes are high: Any time the grid operator for 25 million people skates close to the edge, it will face tough questions.
Texas’ enormous fleet of wind farms has taken heat for not cranking out more power during August’s sweatiest hours. Then there are the perennial calls for ERCOT to ditch its “energy-only” market and embrace a capacity market, in which generators are paid to keep idle plants online as backup. Such a switch could have the effect of keeping aging conventional plants online for longer.
With cooler months mercifully on the horizon, some experts are looking back at the summer not as a source for concern, but rather a vindication of ERCOT’s cutthroat deregulated design — and the ability of variable renewables to succeed within it.
August was “nerve-wracking,” said John Hall, who leads the Environmental Defense Fund’s efforts to promote clean energy in Texas. “If we were to have blackouts or brownouts, we’re concerned it could be very detrimental” to conversations about renewables.
“But we’ve now had two years in a row where the fossil guys projected brownouts and blackouts, and they didn’t occur,” Hall said. “The competitive market is working.”
Don't blame wind
Texas’ wind boom is key to understanding the summertime drama in ERCOT.
It’s difficult to overstate the magnitude of the boom. Texas’ 26 gigawatts of wind turbines make it a top-five global market in its own right. India has slightly more installed capacity, but then it also has a billion more people.
Put simply, there are few options for generating cheaper electricity anywhere in the U.S. than a wind farm in West Texas, where power-purchase agreements regularly come in around $15 per megawatt-hour. (Developers can claim the federal Production Tax Credit on top of their PPAs.) That’s a problem for anybody else producing electricity in the state, and for many coal operators, it’s devastating.
With high fixed but low variable costs, coal plants need to run as often and long as possible to remain viable. But ERCOT’s explosion of zero-marginal-cost wind farms has made that all but impossible in many cases.
Wind is expected to generate 20 percent of ERCOT’s total generation this year, rising to 24 percent in 2020, the U.S. Energy Information Administration says. At times of maximum output, wind farms now meet half of ERCOT's demand.
With fewer hours to make money, more coal-plant owners are simply flicking off the lights for good. “The problem,” Garza said, “is that set of capacity is gone, and it’s not fully replaced by wind during those peak periods.”
Critics point to Texas’ wind boom as a problem for the grid, especially during peak summer demand. But wind farms’ weak summer output is a feature rather than a bug: No one, least of all ERCOT, expects them to be spinning at full clip on a stagnant August afternoon.
While West Texas wind farms are prone to summer doldrums, developers are increasingly targeting the Gulf Coast region, where the wind is a bit weaker but blows more often during daytime hours.
Duke Energy’s 912-megawatt Los Vientos complex — one of the largest U.S. wind farms — was completed several years ago along the Gulf. Avangrid’s new Karankawa project in the region will sell some of its power to Nike.
Still, while more Gulf wind farms will help smooth out generation, many experts believe the glaring solution to ERCOT’s tight summer margin is more solar — lots and lots of it. The question is whether it comes soon enough.
Best. Price signals. Ever.
Texas’ solar market is in its early years compared to wind, with around 3 gigawatts of installed capacity. But big changes are underway.
Texas is the leading state for solar megawatts under development, according to Wood Mackenzie — and that was true even before this summer’s “scarcity pricing” events, when any power plant online could claim $9,000 a megawatt-hour.
"Generally speaking, wind is an off-peak product — it tends to blow more at night," said Colin Smith, senior solar analyst at WoodMac. "So of the two technologies, solar benefited from those [scarcity] prices a lot more than wind did."
The events of August “reinforce our belief that solar is going to be really big in Texas," Smith said.
EDF’s Hall agreed. “The solar [industry] won big,” he said. “Solar developers got the best market signal they’ve ever gotten anywhere.”
For all the optimism around solar in Texas, developers still face challenges. "There’s a misconception that Texas is an easy market for solar developers because of loose permitting requirements and a relatively quick interconnection process," said Clay Butler, CEO of Austin-based developer 7X Energy.
Transmission congestion and curtailment risk — long a headache for wind developers — can “erode any merchant upside,” he said.
“To use oil and gas lingo, a lot of developers are learning that projects they thought were good projects are really just dry wells, due to congestion or curtailment or both,” Butler said.
Texas’ transmission constraints represent a big opportunity for energy storage, said WoodMac’s Smith. Well-sited batteries could soften demand peaks and ease congestion on power lines.
“The more we see problems like [August’s price spikes], the more it’s going to push storage toward the forefront,” Smith said.
Can the energy-only market endure?
Beyond solar and storage, August’s price spikes should be an incentive for developers to build more fast-ramping gas capacity. But while Texas has seen some new gas peaker plants come online in recent years, they haven’t been enough to keep ERCOT’s reserve generating margin from wilting.
Going into the summer, ERCOT’s margin had shrunk below 9 percent, well off its targeted 13.75 percent. By comparison, grid operator PJM — which, unlike ERCOT, runs a capacity market — went into this summer with a reserve margin of 28 percent.
Even an unusually intense string of high-priced days “doesn’t mean that all of a sudden generators’ checkbooks get opened and new gas turbines get bought,” said Potomac Economics' Garza.
The anticipated flood of new renewables capacity in Texas as the federal tax credits phase down could weaken peak summertime pricing in the years ahead, undercutting the investment rationale for gas plants.
ERCOT, for one, is hoping to see more fat built into the system. New solar projects are likely to shore up the reserve margin, helped by coastal wind projects.
Even so, “there’s a school of thought that says the kind of installed reserve margins we’re looking at now — basically in the high single digits on a percentage basis — is the new normal,” Garza said.
According to this line of thinking, “6 percent, 7 percent, 8 percent is what we should be expecting going forward, rather than the 13 to 15 percent kinds of numbers those of us who have been around a long time have come to be used to,” she said.
Despite the thin reserve margin, there's no serious discussion taking place about implementing a capacity market in ERCOT right now, Garza said. The last such discussion happened years ago, she said.
As long as ERCOT manages to keep the lights on, its energy-only market looks like a bargain for consumers compared to some grids with capacity markets, said Eric Gimon, a technical advisor at research firm Energy Innovation.
Plant owners love those scarcity-pricing events, but there aren't many of them in a year, and they don't last long. "Even though they're eye-popping numbers for a short period of time, when you add it all up, it's not that much money," Gimon said.
"When you take what people spend in capacity payments and then ask how that would affect the price if you only paid it for 20 or 50 hours, you see these scarcity prices end up being a pretty good deal."
So what's in store for Texas as the U.S. moves into what are expected to be its biggest-ever years for wind and solar installations?
Gimon said ERCOT will operate in a "three- to four-year cycle," with coal plant retirements triggering a wave of new renewables and "maybe some gas," which in turn will lead to more coal closures.
"How do you know if the market is functioning well or if you're flying a little too close to the sun? That's a difficult question to answer."
But seismic changes to ERCOT's design are unlikely. "I think this will be a lot more incremental than people think," Gimon said.
"It’s like almost everything: There’s a lot less change happening over to two to three years than you realize, and a lot more over five to 10 years."
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