by Jeff St. John
May 15, 2020

Texas grid operator ERCOT is unique in the United States in using an “energy-only” market to keep supply and demand in balance, without a market to secure future grid capacity. That’s often seen as a risky way to run a grid, particularly one rapidly adding intermittent wind and solar power, and it comes with drastic price spikes during times of peak stress like last summer’s heat wave. 

This unique approach is working well for Texas, which continues to absorb more renewable energy while maintaining grid stability, according to a new report from the Environmental Defense Fund. Texas has been able to avoid the over-procurement of largely fossil-fueled generators, a major downside to capacity markets run by grid operators in other parts of the country.

But if ERCOT is going to keep its energy-only approach, it’s going to have to turn to the as-yet-neglected opportunities on the demand side of the supply-demand equation, report author Alison Silverstein says. Her list of recommendations ranges from strengthening the state's weak efficiency standards and tapping the flexibility of loads to respond to pricing signals, to opening markets for distributed energy resources like rooftop solar, behind-the-meter batteries and electric vehicles. 

“Texas has done a good job on the supply side,” says Silverstein, a former senior adviser at the Federal Energy Regulatory Commission and the Public Utilities Commission of Texas. “However, competition and true market prices are determined by the interaction of supply and demand. It seems to me that the next step is to start to make demand a lot more effective.”

Making the case for an energy-only market 

Can Texas continue to manage its rising summer peak demand under its current market structure? The simple answer is yes, Silverstein says. “I believe the energy-only market in Texas has effectively delivered on resource adequacy and can continue to do so.”

That finding may seem to be undermined by ERCOT’s experience last summer, when record-high temperatures forced ERCOT to issue its first “energy emergency alert” in five years calling on customers to curtail consumption, and when spot electricity prices spiked to their maximum of $9,000 per megawatt-hour, as compared to average real-time wholesale prices of about $39 per megawatt-hour last year. 

But while prices like these are problems in markets that use capacity regimes to limit them, they're actually a part of how Texas encourages the market to provide the resources it will need to cover those peaks, Silverstein explains.

That’s a marked contrast with the approach of capacity markets, which pay generators today for promises to remain available for peak grid needs years in the future. As Silverstein argues, many capacity markets are instead paying power plants for capacity far in excess of true needs.

In the country’s biggest such market, run by mid-Atlantic grid operator PJM, these extra costs have equated to as much as $4.4 billion a year in extraneous charges, most of it going to fossil-fueled power plants, according to a March analysis by the Natural Resources Defense Council and the Sierra Club. 

In Texas, by contrast, “merchant owners are quick to retire a plant when it becomes uncompetitive,” Silverstein wrote in the Environmental Defense Fund report, while newer and cheaper resources — including wind and solar power — can come online quickly to replace them.

ERCOT had 23.8 gigawatts of wind capacity and 2.3 gigawatts of PV capacity and installed and operational at the end of 2019. The state’s current boom in utility-scale solar could boost the latter figure to 8 gigawatts by the end of 2021, alongside up to 500 megawatts of battery storage.

This growth in renewables and batteries is expected to amply supply this summer’s peak electricity needs, Silverstein says, a finding backed up by Wednesday's release of ERCOT’s Seasonal Assessment of Resource Adequacy report for this summer. 

The coronavirus pandemic has muddied ERCOT's forecast, with uncertain impacts on its oil industry and the economy at large. Since March, ERCOT has reduced its peak load forecast by 1,496 megawatts to a total of 75,200 megawatts due to COVID-19 impacts, increasing its summer 2020 reserve margin from 10.6 percent to 12.6 percent. 

However, even that new forecast is still higher than ERCOT’s all-time peak demand record of 74,820 megawatts set on August 12, 2019, at the height of last year’s price spikes. High summer temperatures are the driving force.

As ERCOT President and CEO Bill Magness said in Wednesday’s news release, “there is a lot of uncertainty in today's world, but we are confident that Texas will still be hot this summer.”

What’s missing on the demand side of the equation 

Magness' simple observation underscores the key warning in Silverstein’s report: Climate change, and the consistently higher temperatures it will bring to Texas, is a significant and growing threat to its long-term grid stability. Over half of ERCOT’s peak summer loads are driven by air conditioning; the grid operator's future weather projections are based on historical data and could fail to fully capture the warming to come.

Likewise, ERCOT’s demand forecast “assumes no significant changes" from historical trends in energy efficiency, price-responsive loads, distributed solar and electric vehicle usage, Silverstein wrote. This represents both an error in capturing the likelihood of increasing levels of distributed solar, and a lack of effective mechanisms to enlist demand-side resources to serve grid needs, she says. 

“We should be planning ERCOT’s supply and operations around that — and we should be working as a matter of public policy to facilitate and foster demand-side resources with the same enthusiasm and rigor we’ve used for the past two decades to foster the supply side,” Silverstein said. 

First of all, improving Texas’s weak energy efficiency standards could yield huge benefits in managing demand, Silverstein said. Beyond that, energy efficiency measures could include a lot more automated communications and controls to support grid operations while saving money for customers. 

Texas price spikes force the retail energy providers that serve most of the state to come up with creative ways to shape customer consumption to match the true price of supplying electricity. “I am absolutely a fan of high prices as a way to discipline demand and to reward providers who are taking risks,” Silverstein said.

Much of the effects of this demand-side “discipline” are hard to see, because “most of [the providers] won’t tell you, because of competition — it’s a commercial secret." But behind the scenes, these time-of-use rates and free smart thermostat offerings “are using my demand reduction, and that of 100,000 of my neighbors, in a way that improves the reliability of the market.” 

At the end of 2018, more than 1.2 million ERCOT end-use customers were enrolled in some type of retail time-of-use or price-responsive rate, representing up to 1,415 megawatts of load.  

Connecting distributed energy to the grid at large 

The same incentives could help bring distributed energy resources into a more active grid-balancing role. 

Texas had about 577 megawatts of distributed solar PV across nearly 60,000 sites in the third quarter of 2019, according to Wood Mackenzie Power & Renewables, with an estimated 90 percent of that within ERCOT. By 2024, that figure is forecasted to reach 2,580 megawatts, Silverstein wrote.

Backup generators installed after the state’s hurricanes are another significant resource, making up a large portion of the more than 1,300 megawatts of distribution-connected generation installed at the end of 2018.  

But ERCOT stakeholder efforts to expand market access to distributed energy resources have stalled in recent years. Even locating and classifying DERs is a challenge for ERCOT, as for many other grid operators. 

Batteries paired with distributed solar could help smooth PV’s impact on grid stability and shift solar generation to later hours in the day when air conditioning loads peak, Silverstein says. But Texas lacks the market mechanisms to allow behind-the-meter batteries to earn revenue from performing grid services, while investor-owned transmission and distribution utilities have been barred from rate-basing grid batteries by court challenges from generator groups that see them as unfair competition. 

"Virtual net metering” solar offerings from MP2 Energy — now owned by Shell Energy North America, which also owns behind-the-meter battery provider sonnen and EV charging startup Greenlots — are applying this concept to distributed renewable growth in Texas. 

“I’m a big fan of MP2 and some of their peers, which are being very aggressive and creative in terms of packaging multiple technologies,” Silverstein says. But to fully capture the benefits of DERs, Texas needs to make regulatory changes, she says.  

“Behind-the-meter storage and distributed generation improve energy self-sufficiency; they improve the state’s resilience against storms and extreme weather; they improve the state’s resilience against dependence on fossil generation and production,” she says. “We need to recognize and reward all of that.”