AUSTIN, Texas — The Gulf Coast Power Association’s 33rd Annual Fall Conference & Exhibition attracted more than 640 registered attendees for three days of workshops and discussions on the issues facing the ERCOT market. DeAnn Walker, chair of Texas’ Public Utility Commission, delivered the keynote address, while panels examined the evolution of the wholesale and retail markets, grid resilience, cyber and physical security, renewable generation sources and ERCOT’s fuel mix.

While October marks the beginning of ERCOT’s fall season, many minds were still on the grid operator’s performance during the summer of 2018, Texas’ fifth-hottest on record. The lead-off panel credited ERCOT’s preparedness and engagement with the market, the availability of wind and traditional generating units during peak-demand periods, and the lack of extended extreme heat with overcoming the retirement of more than 4 GW of coal-fired generation in 2017.

ERCOT survived the summer heat without making conservation calls or issuing alerts, despite recording 14 system demand peaks above the previous record set in 2016. All 14 peaks came during the summer’s lone period of extreme heat (July 18-23). (See ERCOT: Market Performed ‘as Expected’ During Summer Heat.)

The grid operator went into the summer with a planning reserve margin of 11%, below its target of 13.75%. Generator outages were half of what staff projected, doubling operating reserves to more than 2 GW, despite a peak demand 552 MW above forecast.

“This summer was a good example, or illustration, of how our expectations are related to ERCOT forecasts,” said former PUC staffer Julia Harvey, now director of regulatory affairs for Texas Electric Cooperatives.

Resmi Surendran, Shell Energy North America’s senior director of regulatory policy, pointed to renewable energy’s capacity contributions, which met peak demand of over 5 GW.

“We were extremely lucky, especially because of the wind generation,” she said. “All the major events happened for only one week; the generators operated throughout July. … If we had had extreme weather in August, I don’t know how that would have affected us.”

Luminant Energy Vice President of Origination and Pricing Claudia Morrow reminded the audience that the company’s Comanche Peak Nuclear Power Plant was offline for several months in the summer of 2017.

“Nobody is more pleased and happy than Luminant that our units were all online and performed as expected,” she said. “That just illustrates everything went really well, as best as could be expected.”

Panel moderator Beth Garza, director of ERCOT’s Independent Market Monitor, said average real-time prices were up 25% over 2017 at $36.2/MWh, but reliability unit commitments were a rarity. “That’s a credit to ERCOT and ERCOT operators,” she said. “It would be easy on some days, to say, ‘Wow, I’m really nervous. It would be great to get more capacity.’”

“Fortunately, we didn’t have to use all those [processes] we practice for,” ERCOT COO Cheryl Mele said.

A second panel, focused on a market design that is supposed to incent generation investments, discussed the grid operator’s ability to manage slim reserve margins and the effect on future decisions.

“This [summer] gave one more reason for the forward market to not price scarcity,” said Orion Energy CEO Nazar Massouh. “We had scarcity, but no forward reaction.”

“The summer of 2018 was not performing in a manner consistent with what people thought from coiling the spring a little tighter” through retirements, Merrill Lynch Commodities Managing Director Mark Egan said. “As prices fall on the spot market and forward market, it does serve to effectively push us down the curve. Some fossil asset investment decisions get deferred.”

Walker Expects 2019 Summer to be ‘More Difficult’

Walker agreed with the lead-off panel, saying everything worked out as well as it could have.

But that said, “Next summer will be more difficult,” she predicted, pointing to the state’s increasing demand and potential retirements and mothballing of aging plants. “What does that mean for 2019? We already know we need to make changes.”

Walker said the PUC and ERCOT are already planning for next summer, rather than starting in early March. The commission has scheduled an Oct. 25 workshop to review the summer’s events and determine improvements for next year. ERCOT hopes to see all plant maintenance completed by May 15.

“I encourage you to offer suggestions on what we could do better,” Walker said, noting final input is due Oct. 18 (Project 48551).

Walker expects ERCOT’s reserve margin to remain tight in the short term. She discovered this year that planning to have units in neighboring regions help the grid operator “in a crunch” is “more difficult than I thought,” so she is working on reliability coordinator agreements to resolve the situation.

“It’s not my intent to have MISO or SPP give those units’ control to ERCOT. My intent is to be more orderly than that,” she said. “We have issues to work through. I would like these processes to be in place by next summer, but it’s going to take some Protocol changes.”

Is There a Place for Distribution Assets in ERCOT?

During a panel discussion on “non-wire alternatives,” AEP Texas President Judith Talavera and NRG Energy Director of Regulatory Affairs Bill Barnes debated AEP’s proposal to install a pair of utility-scale lithium-ion batteries to solve distribution reliability needs in its West Texas service territory.

AEP’s plan to classify the facilities as distribution assets and include them in cost-of-service rates sparked broad opposition within the market. The PUC rejected the proposal in January, but it opened a rulemaking to address “non-traditional technologies in electric delivery service” (Project 48023). (See PUC Opens Rulemaking on Distributed Battery Storage.)

Talavera said the numbers — $2.3 million in costs for the battery facilities, as compared to $11.3 million to $22.5 million for “traditional” wires solutions — “demonstrated a battery was a much more cost-effective solution” in dealing with outages and other reliability concerns in the tiny towns of Woodson (estimated population in 2016: 246) and Paint Rock (287).

“We strongly believe [energy storage] has to be a tool. It’s no different than a transformer or any other distribution asset,” she said. “We view this as a distribution asset we will be adding to our system, and the rules don’t require a [certificate of convenience or necessity] for a distribution asset you’re adding or building.

“When the laws were written, we didn’t have these types of technologies,” Talavera said. “At the end of the day, we have a responsibility to serve everybody on our system.”

“Where we differ is how we see those non-wires alternatives come to be,” Barnes said. He said units that provide ancillary services such as batteries are generating assets. Ancillary services are defined in the ERCOT Protocols as any service needed to serve the transmission of load, he noted.

Barnes proposed extending transmission-level prices to the distribution system, “so you have distribution prices and distribution nodes.”

“That would create incentives for suppliers to locate batteries on the grid where you have reliability problems,” he said. “We create economic signals; we allow private investment to come into the market to solve those problems. For products that might not be priced, like voltage and stability, you create markets for them that ERCOT facilitates, like the existing ancillary services markets.”

“Judith owns the storage,” said panel moderator Bob King, president of Good Company Associates. “It’s not clear [who pays if] she can charge or discharge, but it’s clear she can’t participate in the wholesale market.”

“And we’re not trying to,” Talavera responded.

“The ultimate issue is the cost … is still funded through the rate base,” Barnes said. “If you’re awarded the [project], you’re happy. If you’re everyone else, you’re not. The cost is funded through noncompetitive revenue, and you still have distortion in the market. If customers want that reliability, they can pay for it.”

“Given the declining cost of batteries and the growing maturity of technology over the last few years, we identified two great options to help us provide reliable service,” Talavera said. “We didn’t get the approval, but I do think it helped open the conversation we’re having today. I feel energy storage can provide real, quantifiable benefits for the customer and our distribution system.”

ERCOT’s Retail Market Running Smoothly

Kenneth Medlock primed the pump for a panel discussion of ERCOT’s retail market by sharing the results of a residential pricing study that covered a 14-year span following the onset of customer choice in January 2002.

Medlock, senior director of the Center for Energy Studies at Rice University’s Baker Institute, stressed that sample averages don’t “tell the whole story,” but that price dynamics matter. He said prices fell in the state’s competitive areas but rose in the noncompetitive areas (Austin, San Antonio and other municipalities and cooperatives). Residential rates in competitive areas were 2 cents less than those in noncompetitive areas in 2002, but those rates were on par with each other by 2016.

“If you’re in a system with limited choice because you have one retail provider, then you don’t understand what individual consumer groups prefer,” Medlock said. “If you want to enhance the competitive paradigm, it’s important that you remain transparent and open. That’s the only way consumers can access enough information and data to make decisions in their best interest. Players in the market are forced to differentiate themselves in different ways, which introduces an entrepreneurial paradigm that can lower prices.”

Chris Brewster, a principal with law firm Lloyd Gosselink Rochelle & Townsend, said the retail market’s strength is rooted in the wholesale market.

“That’s what ERCOT, the stakeholders and the PUC want. It works smoothly,” he said. “We have a wholesale market that is very liquid and easy to transact in. It doesn’t impose a lot of administrative requirements. We have a true market. We have a wholesale market that transacts in a commodity, and a retail market that specializes in a customized service for customers.”

Connie Corona, the PUC’s director of competitive markets, said “the consistent small changes made to the market have been critical.”

“There’s a balance in this market between certainty [about how things operate] and the ability of the policymakers, the stakeholders and market participants [to adjust] the Protocols,” she said. “As a market, we’ve taken the opportunity to recognize how this and that could work better. Everyone has been open to examining that, from the Legislature on down to the subcommittee of the working group at ERCOT.”

Future for Quick-start Gas, Utility Solar

Shell Energy North America’s Greg Thurnher, moderating a discussion of ERCOT’s fuel mix, recalled a not-so-distant past when the grid operator had 8 GW of wind, a 15% reserve margin, no major retirements, gas in the $10 to $13/MMBtu range, and construction of new nuclear and coal generation was expected.

Ten years later, ERCOT has 1 GW of solar, 21 GW of wind and another 13 GW planned, while coal capacity has dropped by more than 4 GW, noted Thurnher, Shell’s manager of real-time trading.

“Rather than say the resource mix is changing, it has changed, and the change is here to stay,” Thurnher said.

Clif Lange, manager of wholesale marketing for South Texas Electric Cooperative (STEC), said his business is investing in quick-start gas units, rather than renewables — or rather, because of renewables.

“The ability to be there quickly and, frankly, the ability to shut down quickly has provided a lot of value to STEC and ERCOT,” Lange said. “How do you make a thermal generator effective in a market where you have seen depressed pricing for so long? The ability to react quickly to market signals has provided a great benefit. We can respond very quickly to transmission constraints that pop up very quickly or disappear very quickly. When you’re not in the money, it’s very important to be able to take that unit offline.”

McCall Johnson, senior manager of government affairs for solar developer Recurrent Energy, said utility-scale solar will be essential to the future because of its ability to provide predictable power during the afternoon peak.

“Those [solar] megawatts are not causing a lot of operational issues,” she said. “We see that peak power, which is really cost-effective, driving a lot of interest. Solar … seems a more sophisticated purchase of renewables. You get a peak hedge. We all know when the sun is going to shine, and it’s easy to predict.”

Maura Yates, managing member of the Mothership Energy Group, which calls itself “a boutique group of female-owned energy solutions companies,” reminded the panel and audience to not forget about rooftop solar, “a silent asset happening behind the meter.”

“We have a lot of data in the market, important data driving the generation stack. But you don’t have an idea of how many behind-the-meter rooftop solar systems there are,” Yates said. “It’s a blind spot. It’s really important to get a hold of that data, because it’s driving the wholesale side now. Consumers want to be more involved and engaged. They’re an asset class themselves.”

Opinions Vary on Grid Resilience

Several transmission operators opened their panel discussion by recounting the Department of Energy’s proposal to prop up coal and nuclear generation and FERC’s definition of resilience: “The ability to withstand and reduce the magnitude and/or duration of disruptive events, which includes the capability to anticipate, absorb, adapt to and/or rapidly recover from such an event” (RM18-1).

“It does align itself to the Baskin-Robbins 31 flavors of resiliency,” CenterPoint Energy Associate General Counsel Patrick Peters said of FERC’s definition. “[Resilience] started with solid fuels and nuclear but has now evolved into other topics. The definition covers just the normal day-to-day work of operating the electric grid. When I think of resiliency, I think of out-of-the-box planning to ensure the grid stays reliable if you lose a piece of equipment.”

“One of the things I love about working in this industry is we’re not afraid to take on hard projects, and this is one,” said Southern Co.’s Katherine Prewitt, vice president of transmission. “We need to ensure we don’t have a one-size-fits-all approach. We can’t lose sight of our customers’ needs. We have to talk to them, understand what they need and help them understand the impact of what they’re asking for. There’s always a cost for the ask. We have to ensure we don’t over-engineer it and put ourselves in a position where we have unintended consequences.”

“Our view is the markets work best,” said John Gunn, vice president of regulatory affairs for ExxonMobil’s gas and power marketing unit. “The power industry does have to comply with a whole lot of regulations. We’ve seen that in reliability improvements and [its] ability to respond in natural disaster.”

— Tom Kleckner