AUSTIN, Texas — Infocast’s annual ERCOT Market Summit last week brought together nearly 300 industry representatives and policymakers to discuss the Texas grid and the challenges it faces.

ERCOT CEO Bill Magness keynoted the Feb. 25-27 event, cracking wise as he reviewed the system’s performance during a pair of summers with record demand and tight reserves, while offering his 2020 vision.

“I get to talk about that a fair amount, as that’s a characteristic of the ERCOT market these days,” he said. “It always starts with, ‘Tell me about this summer. I know what you did last summer.’ So I soldier on.”

Magness said he and his staff knew that the summers of 2018 and 2019 would be “pretty challenging” when more than 4.1 GW of the market’s coal capacity was retired in 2017.

“Now that we’ve gone through both [summers], we know how the system performs with tight reserves,” he said.

Despite a reserve margin of just 8.6% last summer, ERCOT was able to meet a record demand of 74.8 GW in early August, breaking the mark set in 2018 by more than 1 GW. The real problem came later in August and September, two of Texas’ hottest months on record, when West Texas wind production dropped during the early afternoon hours. That created a trough of wind energy before coastal wind production picked up, forcing ERCOT to rely on emergency response service to meet demand.

The grid operator called two energy emergency alerts to address the loss of production. Prices, meanwhile, soared during the scarcity conditions, hitting their cap of $9,000/MWh.

“We saw a real solidifying of what’s become a pattern, with the resource mix driven in large measure by the wind,” Magness said. “Most of my mid-afternoons are spent watching the charts, to see if the wind catches up to the load or not. Consequently, we tend to see that our tightest reserves are during those times when we’re in that trough of wind generation.”

Staff are projecting an additional 7.6 GW of new capacity will come online for summer 2020, much of it renewable energy or smaller gas-fired peakers. The grid operator expects a reserve margin of 10.6% this year — still 3 points below its planning reserve margin target of 13.75% — and 18.2% in 2021.

“It’s nice to see double digits, but that’s not materially different from an operations perspective,” Magness said. “People ask me, ‘Are we out of the woods yet?’ And I say, ‘We have become skilled forest creatures.’”

ERCOT and its stakeholders are following the same playbook as they did in preparing for the last couple of summers: limiting transmission and generation outages, strengthening communication with market participants, setting up emergency transfers with neighboring grids, and calling on emergency reserves.

“We’re fully engaged at ERCOT to facilitate whatever shows up,” Magness said.

Participants Offer Kudos to ERCOT’s Market Design

A panel of market participants followed Magness to the stage and added their insights on the ERCOT market’s performance last summer and measures being taken to strengthen it.

Shell Energy North America’s Resmi Surendran suggested the market might have been lucky last year, pointing out the heat didn’t reach 2011 levels, when Texas recorded its hottest summer on record.

“It could have been much worse. If we had had 2011 weather, the peak would have been 78 GW, not 74 GW,” Surendran said.

Katie Coleman, legal counsel for the Texas Industrial Energy Consumers trade group, responded that some of the credit for ERCOT’s energy-only market must go to the market itself.

“We’ve been hearing for the past three summers how lucky we are,” she said. “At some point, you have to start chalking it up to good market design and good market incentives.”

As did other speakers, the panel lamented the lack of pricing signals incenting new baseload generation. Intermittent renewable resources continue to provide much of the new construction and capacity in ERCOT, but they also add more risk.

Referencing a 2014 Brattle Group study on an “economically optimal” reserve margin that suggested a 10.2% reserve margin would lead to a loss-of-load event (LOLE) once every three years, Lower Colorado River Authority’s John Dumas highlighted the potential danger.

“Having a good market design is good. You can be a good driver, but your reaction time at 110 mph needs to be a lot quicker than at 65 mph,” Dumas said. “When you’re shrinking those reserve margins, you’re taking on a lot more risk.”

“The best way to describe the ERCOT market is that it works in practice, but not in theory,” Coleman said. “We’ve gone from planning to a one-in-10 year [LOLE] standard and never had an event, to an event in three years, and we’ve never had it. I think the world is watching what the market is doing here, because consumers are paying less and because of the incentives we’ve created so that resources show up when they’re needed the most.”

The Public Utility Commission and ERCOT continue to tweak the market. The commission in January 2019 directed the grid operator to change its operating reserve demand curve, which provides a price adder during periods of generation scarcity, by combining its curves into a single curve and shifting the standard deviation in its LOLE probability.

Coleman said the standard deviation shift means “prices get higher and stay there longer.” She said the curve combination is more significant because “it says how variable your reserves are year-round, and we’re just going to peanut-butter that across all hours.”

“It is certainly increasing pricing,” she said. “The issue is not a matter of how much you increase prices … you’ll still get the most economic resources. Right now, that’s not thermal generation. If you incentivize thermal resources, I don’t know anyone who thinks that’s a good idea.”

“You may not see any new build announcements from us, but we are putting in $100 million into our Texas fleet,” said Calpine’s Brandon Whittle, noting the upgrades will “capture extra megawatts” and provide more generation for the grid this summer.

ERCOT Works to Stay Ahead of Oil & Gas Growth

ERCOT is conducting its biennial long-term system assessment (LTSA) of the 345-kV system, which it is required to file with the state legislature each even-numbered year. Examining a 10- to 15-year planning horizon, the LTSA uses a range of scenarios to identify upgrades that are robust over a number of the scenarios or more economical than upgrades found in near-term assessments.

The 2018 LTSA report projected a significant amount of additional solar generation and transmission improvements needed to export solar and wind output from West Texas. Not mentioned in the overview is the load growth fueled by the petroleum-rich Permian Basin and other western plays.

“Oil and gas load has been a struggle for us,” said ERCOT’s Jeff Billo, senior manager of transmission planning. “New wires take four to five years to get constructed. The commitments of new growth we’re getting from the oil and gas sector are only one or two years away.”

“Oil and gas load continues to migrate further and further west,” Magness said. “There wasn’t much grid out there too long ago; it was pretty much the end of the system. Where there wasn’t much grid before, we’ll have to muscle it up pretty fast.”

Billo said ERCOT has undertaken a number of initiatives, at the direction of PUC Chair DeAnn Walker, to review its processes and try to stay ahead of the load growth.

“Two things: Can we identify the need for new transmission to serve oil and gas customers sooner, and secondly, can we speed up our process?” Billo said. “Can we get the engineering, the planning done quicker so we can start the construction quicker?”

“It’s pretty clear that new construction [in West Texas] is the No. 1 priority of this current commission,” Electric Transmission Texas President Kip Fox said. “Oil and gas is the lifeblood of Texas. Getting power to those locations is important to the growth of Texas.”

Potential Solar Projects Pose Challenges

ERCOT’s generator interconnection queue numbered 613 requests as of Jan. 31, with a staggering total of 119.4 GW of capacity under some form of study. Solar requests account for more than half of that (73.6 GW), doubling wind requests (30.6 GW).

Tuan Pham, CEO of solar developer PowerFin Partners, said there’s a reason for the massive amount of solar capacity in the queue: the $15/MW application price.

“A structural problem at a high level is that the cost … is extremely low,” he said. “It takes $15/MWh to get into the ERCOT queue, but the cost to build a solar project is about $1 million/MWh. [The application fee] might as well be zero. I don’t believe the [numbers for] future buildout and supply of solar in the state.”

“I’ll take the heavy under [bet] on everything that’s in the queue,” said Brandon Wax, executive director of commodities for J.P. Morgan. “What the market needs is dispatchable generation, and that is going to be really tough to build. The reserve margin I’m interested in is the reserve margin on those low-wind days. The next three to four years, you’ll see a lot of solar, the occasional peaker and behind-the-meter generation.”

Solar energy has been concentrated in the solar-rich areas of barren West Texas. However, with transmission congestion becoming a factor, developers are now eyeing locations closer to load centers.

“We’re seeing an unprecedented growth on the transmission system of renewable energy, but the great locations have all been sucked up,” Fox said. He referenced the Competitive Renewable Energy Zones (CREZ) project that resulted in the construction of 3,500 miles of transmission, capable of carrying 18.5 GW of capacity, in illustrating today’s problem.

“Build it, and they would come. They just didn’t think they would come as much as they did,” said Fox, whose joint venture between American Electric Power and Berkshire Hathaway Energy was responsible for 20% of the CREZ build. “There’s a lot more requests for interconnections than the CREZ lines are capable of carrying.”

“Transmission planning is a very complex thing. Not only are you planning for reliability, but you’re planning for the future,” said Swaraj Jammalamadaka, vice president of transmission for Apex Clean Energy. “The biggest change is the economics of renewables. There’s demand for cheap, renewable resources. As Kip said, you build it and they will come. They’ve been waiting for a long time. It’s not about congestion today, but forecasting tomorrow. Is the market actually responding to it? It’s very complex to get market design and transmission planning right to ensure the right resources are being used.”

“As a wind or solar developer, you’re trying to get your project online however, whenever,” Wind Works Power CEO Ingo Stuckmann said. “If you look at the system, there’s two elephants in the room. The first elephant is getting the transmission out in the West. We had this CREZ I system built, but where’s our second CREZ system? I don’t think there’s an appetite for another CREZ system.

“The second elephant is the August summer scarcity pricing. How do you meet these prices? In Germany, they’ve designed a system that can be 100% renewable. That’s the cheapest source of remediating all these peaks immediately.”

Is Too Much Demand Response Too Much?

Potomac Economics’ Steve Reedy, acting director of ERCOT’s Independent Market Monitor, said the Monitor is a “pretty big fan” of demand response, be it emergency response service, charges during the four 15-minute coincident peak events during the summer months and “plain old” DR.

Reedy said while the first two DR schemes account for much of the response, he finds “plain old” DR the most exciting.

“That’s what really helps the market become a market, where you actually have buyers and sellers meeting in the marketplace and responding to prices,” he said. “You can respond to the shortage by building more generators, investing money in plants to make them more efficient, investing in tools and procedures to look at prices … that’s the beauty of the energy-only market. The high prices we get during shortages sends price signals to the market, and the market determines the most efficient way to get energy to where it’s needed.”

Billo offered a transmission perspective on DR.

“You can’t count on demand response for transmission,” he said. “Demand responds to systemwide scarcity conditions, but that may or may not be when a local area is experiencing a transmission constraint, so it may not respond when you need it for transmission.”

Scarcity Pricing Likely Again in 2020

Claudia Morrow, vice president of commercial pricing for Vistra Energy, had a simple answer when asked whether the market would see another round of $9,000/MWh scarcity prices this summer.

“Until someone can forecast when the wind is going to blow and the sun is going to shine, that’s going to be a challenge for the market and market participants,” she said. “The answer is to invest and spend capital on plants, to be sure they’re there when needed.”

“The volatility will continue this summer,” said Michael Enger, Austin Energy’s energy market manager. “Our weather will determine whether we see the same magnitude of prices.”

Fellow panelist Brad Richter, Citigroup Energy’s origination director, cautioned against expecting any help from new baseload generation.

“The forward curves do not support additional generation. The market isn’t sending price signals to give us more generation,” he said. “We’re increasingly in an environmental market. It’s all sunshine and wind, and it’s going to keep happening because the forward curve is not incenting new generation.”

What will it take to incent new generation?

“Brownouts … that’s the kind of signal the market’s going to need to wake up and have assets in place to support the market,” Richter said.

— Tom Kleckner