AUSTIN, Texas — Infocast gathered industry experts in the Texas state capital to share their insights on the “challenging times that lie ahead for ERCOT.” Panelists examined changing market rules, the impact of gas prices on generators, how the delivery of new wind and solar power will change market dynamics, and the revamping of ancillary service market rules during the sessions Feb. 27-March 1.
Donna Nelson, chairman of the Public Utility Commission of Texas, said the state’s competitive market has benefited from lessons learned in California, which opened its electric market to choice in 1998, four years before ERCOT did the same. That has helped the PUC, which oversees the Texas grid operator, to prepare for the 28.6 GW of wind capacity sitting in ERCOT’s interconnection queue.
“Right now, I’d say our market is working because we have a healthy reserve margin and we have fossil-fuel generation to cover [wind energy’s] variability,” Nelson said. “Over time, if that [wind] generation is built, we’ll have to look at what it takes to keep the fossil fuels on. There’s a tension between the workings of the competitive market and reliability. We’ve made a lot of adjustments to the market over time — we want to keep the lights on too — but we have to look at reliability from a short-term to long-term perspective. That’s something the commissioners will continue to watch.”
Nelson recalled a time when integrating 10,000 MW of wind power into ERCOT was considered an “iffy” proposition. “So here we are at 18,000 MW,” she said. “That’s a lot of investment, but lest you label me a renewable hater, it’s made because of the [Production Tax Credit]. When you see other forms of fossil fuel generation is not invested, you ask, ‘Why is that the case?’
“The PTC provides an incentive of $23/MWh. When you look at the average price of power in the ERCOT market, you can see an incentive of $23/MWh has the potential to distort the market,” Nelson said, noting the ERCOT market prices energy based on the amount of generation needed. “If wind bids in at a low price at night, that sets prices in the early morning hours. It’s gotten to the point where [the fossil-fuel plants] generate all their revenue in the summer. You’re going to see less and less of that. You’ll see wind lowering the price in the summer, as well.”
Over time, she said, that will lead to further retirements of fossil-fuel plants. “We won’t have the fossil-fuel generation to back up wind’s variability.”
Dealing with Low Gas Prices in the ERCOT Market
Several panelists discussed ERCOT’s low power prices, their effect on the generating fleet, and forecasts for the future. The ISO’s $24.64/MWh average price in 2016 was the lowest since the market opened in 2002. Natural gas accounted for almost 44% of ERCOT’s power last year, with coal accounting for 29%, wind 15% and nuclear 12%.
Bob Helton, Dynegy’s director of market design and policy for Texas, said he doesn’t expect to see much of a rise in natural gas prices any time soon. “We know the administration is not going to stop fracking … take that for a given. We’re going to have low [gas] prices in the future,” he said.
That will put further economic pressure on ERCOT’s coal units, which have been struggling to compete in the market.
“If prices are low, it’s cheaper to buy off the market … than burn our coal plants,” said John Bonnin, vice president of energy supply and market operations for San Antonio’s CPS Energy, which plans to retire 950 of its 2,300 MW of coal capacity in 2018. “We went through 54 days without burning a single lump of coal last year.”
While Bonnin also said “there’s still a place [for coal capacity] in the summer,” Potomac Economics’ Beth Garza, director of the ERCOT Independent Market Monitor, pointed out much of Texas’ coal fleet was built between 1975 and 1980.
“We’re now in 2017. That would seem to be an economically rational life span for many of these assets,” Garza said. “They’re going to run until something big breaks, and it just won’t get fixed.”
Manan Ahuja, senior director of North American power for S&P Global Platts PIRA, said nuclear units are also at risk in the ERCOT market. “Would these potentially be retired?” he said. “These nuclear units have not made money in the last couple of years. Reliability issues apart, we think the economics are certainly under threat, though they are down in the pecking order as compared to some coal and gas-peaking units.”
ERCOT: Not Really that ‘RUCed Up’
Garza’s recent comment that the Monitor considered 2016 to be “all RUCed up” came up again during the week, once by Garza herself. But were ERCOT’s reliability unit commitment activities — a near quadrupling to 269 “unit days” — last year really that egregious? (See “IMM Year in Review: Low Prices, Windy, Lots of RUC,” ERCOT Board of Directors Briefs.)
“I don’t get bent out of shape about the RUC activities,” said ERCOT COO Cheryl Mele. “I think the operators are doing a good job” reducing the impact on market prices.
“A lot of RUC is a sign the market is working very effectively,” said ERCOT’s Resmi Surendran, senior manager of wholesale market operations and analysis. “If we give the [RUC] instructions, we’re looking more holistically at the whole system. The ERCOT market design gives the right incentive to participate in the day-ahead market.”
Surendran said the ISO’s total net make-whole payments for the last five years has been almost $40 million — the same amount as PJM’s monthly make-whole payments. (However, PJM’s energy and capacity market has a peak load of 165 GW, more than double ERCOT’s energy-only 69 GW.)
Last year, $1.2 million in make-whole was paid to entities that were short generation and another $1.4 million clawed back from generators with offers in the day-ahead market.
While the number of RUC events still concerns Garza, she agreed the financials tell a different story. “Even with the [RUC activity] increase, the cost of doing that … seems to tell me that, yeah, we had a bunch of RUC activity, but I don’t think it was all that inefficient,” she said.
Wind Subsidies Distorting the ERCOT Market?
Appearing on a panel addressing “collapsing” power prices, NRG Energy Director of Regulatory Affairs Bill Barnes said ERCOT’s market is “energy-only in theory” and that “subsidized wind generation” is a problem.
“What we have in ERCOT is very different [from energy only]. It’s been released into the wild, and a lot of things are exerting influence over it,” Barnes said. “NRG invests in renewables. We believe in renewables, but those that stand on their own two feet. We’re beginning to see the impact of those subsidies on the market today.”
Hannes Pfeifenberger, a principal with The Brattle Group, argued combined cycle plants with low heat rates and improved technology have done more to depress prices than wind energy.
“We’ve seen technology costs being reduced so quickly that by the time the PTCs expire, these technologies will be in the market no matter what,” he said. “One thing we have to realize is that baseload will be less valuable in the future, no matter whether the PTC expires or not. More flexible plants will be a market outcome. We will see more retirements because gas prices will remain low.”
“There aren’t price signals right now to build [baseload] generation because we have excess reserves. That’s market 101,” said Katie Coleman, a partner with Thompson & Knight. “I agree with Bill that the PTC and the proliferation of wind is a problem. Anytime you introduce subsidies into a market, you have distortions. Potentially assigning some transmission costs to wind, assigning ancillary costs to wind … those are things I think merit further conversations.”
“This market can solve its problems,” said Philip Moore, vice president of development for Lincoln Clean Energy, who linked the low prices to natural gas and wind. “ERCOT has shown an amazing ability to address the oncoming wind and its own transmission problems very efficiently. ERCOT will find ways to accommodate the energy-only market.”
Solar Envy
While a potential flood of new wind energy has grabbed much of the attention, additional solar power is coming over the horizon, too. Charlie Hemmerline, executive director for the Texas Solar Power Association, said 2016 was the solar industry’s best yet, with 14.8 GW of additional installed capacity creating a 42.4-GW total nationally. Texas ranks ninth nationally with 1,215 MW of capacity.
ERCOT, which almost doubled its solar capacity to 556 MW last year, could see another 2 GW come online by 2021. “Twenty other states have significant solar activity, which means there’s heavy competition attracting people to the state of Texas,” Hemmerline said. “We’re in the mix, but we’re not leading the pack. Our real focus as an industry is to make sure we can make that happen. Our legislative ask of folks is to do no harm. Let’s not do anything to stop this investment or remove anything that would harm us along the way.”
Much of Texas’ utility-scale solar can be found in the wide-open spaces of West Texas.
“The thing we like at ERCOT about West Texas solar is it’s a time zone away from our load centers,” said Paul Wattles, the ISO’s senior analyst for market design and development. “If you’re generating in Pecos County at 2 or 3 in the afternoon, it’s serving peak load in Houston,” he said. “I think you will see more intelligent siting. I think you will see them to where they can make a lot of money during the critical part of the day.”
Residential solar is playing an increasingly large role in the market as well. Wattles said Oncor just passed 10,000 rooftops, thanks in part to what he calls “solar envy.”
“I hear Plano is going crazy” with installations, he said, referring to the Dallas suburb. “Those numbers are dwarfed by California, but it’s something that wasn’t there 10 years ago.”
“Solar envy is definitely a thing,” Hemmerline said. “As people see it, they want it too. [Residential solar] has been here a long time as a someday concept, but when you’re seeing more of your neighbors doing it, it’s propagating to where the costs make it a reasonable decision.
ERCOT is paying attention. “Solar is going to start commanding a larger share of the [distributed generation] fleet,” Wattles said. “My group is concentrating on the big stuff right now, but the little stuff is coming really fast.”
CREZ Project has Benefits, but Stability Issues
ERCOT’s Competitive Renewable Energy Zones (CREZ) project resulted in 3,600 miles of transmission carrying 18.5 GW of West Texas and Panhandle wind energy east to urban load centers at a cost of $6.9 billion. The wind industry’s growth also led to $38 billion in investment across 60 Texas counties and almost 23,000 jobs, according to Susan Williams Sloan, vice president of state policy for the American Wind Energy Association.
“It’s a testament that CREZ brought a lot of benefits to the state,” Sloan said, adding it has also yielded $60 million in annual lease payments to rural Texas landowners. “It’s a new crop for landowners, and allows them to have a passive income. Over the years, there’s even been some landowner wind associations formed to attract wind to their community.”
“We don’t have all our wind in West Texas anymore,” said Sharyland Utilities’ Bill Bojorquez. “We have wind in the south, in the Panhandle and coastal. We don’t have wind peaking at the same time of the day.”
Increasingly, that remote wind generation has led to some stability problems on the ERCOT grid.
“Traditionally, we saw thermal issues. That was the main thing we had to operate and plan around,” said Jeff Billo, ERCOT senior manager of transmission planning. Now, he added, “We’re seeing generation that’s more removed, and we’re seeing more asynchronous generation.”
Fossil Fuels Still Viable Alternatives
Golden Spread Electric Cooperative COO J. Jolley Hayden said his company is moving away from power purchase agreements to quick-starting gas units because of market dynamics. “As the markets get more robust, that’s the resource we’re looking at,” he said.
Using aircraft carriers (coal plants) and PT boats (quick starters) as images, Hayden said, “The big aircraft carriers … if they’re in organized markets, they’re struggling right now. They’re running, and they’re out of the money. The PT boats’ flexibility is essential. The more dynamic the market is, the more flexible you have to be to keep your costs low.”
Coal resources still have their supporters, however. Ingmar Sterzing, vice president of power supply and energy services for Pedernales Electric Cooperative, said coal plants “absolutely” still provide a benefit and their potential value is not priced in the market.
“It’s physical fuel that’s available at the plant, with a supply of 45 to 60 days. That’s unlike any other resource in ERCOT except nuclear,” Sterzing said. “If you’re really in a pinch, coal is there and it’s available. It’s very reliable. Once those coal plants are gone, it’s going to be very difficult to bring them back. You try permitting a new coal plant, and it’s eight to 12 years. You’re going to be stuck with a limited set of options.”
Customers More Informed, Still Hard to Move
Mark Bruce, one of the architects of Texas’ competitive market and principal with Cratylus Advisors, said he is “tickled pink” to see his vision become reality. “The stakeholders wanted to empower customers to become more efficient and make their own decisions,” he said.
But challenges remain.
“We’re seeing sluggish [load] growth. Efficiency is creeping in as customers get more information. They are putting their own generation behind the meter, using storage, getting familiar about time of use. There are more bears in the woods. Our old models don’t fit with the way this is going.”
Michele Gregg, director of external relations for Texas’ Office of Public Utility Counsel, reminded attendees not to forget about retail customers. “We need to remember customers want to spend very little time on electricity,” she said.
“We spend a lot of time in industry meetings talking about what innovation they need … what the customers want and reducing load. The average customer has no idea what load is. They get a bill once a month, they know that bill is too high. In the retail market, the [retail electric provider] is the only one they want to do business with.”
The bills may be high, but the customers still tend to stick with their legacy providers. TXU Energy, which dominates north and central Texas, has seen its rate of departing customers drop from 8% in 2010 to 1% in recent years.
Asked how he would crack the TXU and Reliant Energy legacy markets, Andrew Elliott, director of supply and portfolio management for ENGIE Resources, did not have a ready answer.
While the residential market is not his primary focus, Elliott offered up a story involving his mother-in-law. He said he tried to explain to her she had her choice of retail electric providers, but she would have none of it. “‘This is my electric company. I’ve always paid them.’
“We would love to have the rollover customers,” Elliott said, before repeating the original question. “So how do you crack the TXU-Reliant legacy customers? I don’t know.”
Ancillary Services’ Future in ERCOT
Austin Energy’s commitment to participate in ERCOT’s ancillary services market is a challenge because of the ISO’s average prices, said Kahlil Shalabi, the municipality’s vice president of energy market operations and resource planning.
“[ERCOT’s] pricing is … much different than any other market,” Shalabi said. “If you look at the past month here in Austin, the price dips down close to zero in the morning, then goes all the way up to $18 [per MWh] in the afternoon. If you’re lucky, it goes up to $500 once a month for 15 minutes.
“We’re not looking at future ancillary services pricing for future resource decisions,” he said. “We do see price separation between our load zone and the rest of ERCOT. We want to use our generation to protect our customers when those price spikes happen.”
“The robustness you see in Cal-ISO and PJM with advanced technologies and storage is due more to acceptance by those markets, rather than prices,” said John Fernandes, who left RES for Invenergy after the summit as its director of regulatory affairs. “Those ISOs are setting up constructs that draw developers to those markets. When a system operator chooses to modernize the system to play to the strength of advanced technologies, that generates as much interest as price alone.”
That is why Duke Energy Renewables’ Thomas Paff, manager of RTO/ISO coordination, said his company is not yet buying storage in the ERCOT market.
“We do have some battery systems in PJM where it’s totally different than the outlook here,” he said. “We are making money, but it’s really not that much.”
