AUSTIN, Texas — Infocast’s annual ERCOT Market Summit once again drew ISO staff, market participants and others for panel discussions on market reform, grid resiliency, resource adequacy, transmission constraints, wholesale price volatility, and integrating utility-scale solar power and battery storage.
Participants Caution Against Market Changes Before Summer
Some of ERCOT’s more vocal members urged caution as the market approaches a summer with projected record demand but with almost 8 GW less in generation after a wave of retirements and delays in planned projects.
The Public Utility Commission of Texas is considering withdrawing reliability unit commitments (RUCs) and reliability-must-run capacity from the operating reserve demand curve (ORDC), a real-time price adder that reflects the value of available reserves and is intended to incentivize resources to produce more energy and reserves. PUC staff said this would ensure that scarcity pricing is accurate and reflective of market dynamics. (See “Commissioners Delay Action on Removing RUCs from ORDC,” Texas PUC Briefs: Feb. 15, 2018.)
But that would be a mistake, said Katie Coleman, legal counsel for Texas Industrial Energy Consumers. “Since 2012, we have spent a lot of time and effort designing the ORDC. We specifically discussed including RMR and RUC capacity. Ideally, the ORDC values should reflect the actual amount of reserves, which accurately reflects the likelihood of load shed. We did a bunch of other things instead, to try and put more money in the market,” she said, referring to RUC’s $1,500 price floor — “which is higher than any unit’s actual cost” — and pricing RMR at the $9,000/MWh cap.
“We’ve built this machine, and we’re about to have a summer where it’s tested. Let’s see how it goes, then come back, and see if there are areas that really need refinement.”
“Part of the problem the last five years is we have never really defined what we are solving for from a reliability point of view,” said Barksdale English, Austin Energy’s interim chief of staff. “What is important to us? Is it short-term interval-to-interval reliability? Is it long-term five-, 10- or 15-year reliability? Until we figure out what we are solving for, having proposed solutions sort of seems like having the cart before the horse.”
English jokingly referred to his “multiple personality disorder” as a generation-owning municipality competing in ERCOT’s wholesale market. “I can get really excited about $9,000/MWh for wholesale generation, but then — oh my gosh — what about my consumers? Then, my City Council gets mad at me because I’m paying too much money.”
Beth Garza, director of the ERCOT Independent Market Monitor, cautioned against blurring the difference between a load-shed event and a blackout. “That’s a very important difference. Those loads are being paid to provide a service,” she said.
“I fully expect many of those services will be called on this summer that have never been called on before. If those services are called on, they’ve been curtailed or are no longer consuming, but they’re being paid for providing a service,” Garza said.
“At what levels does ERCOT take emergency actions? When does load shed begin?” asked Strasburger & Price’s Mark Walker, before answering his own question (when operating reserves reach 1,000 MW). “Hitting the offer cap with only 2,000 MW of available capacity left is sensible. If you look at actual prices when RUC resources are deployed by ERCOT under pressure from load, congestion and intermittent resources swings, the prices today really don’t reflect that we’re in an emergency situation or a serious reliability condition.”
Role-playing Reveals Markets Concerns
In a discussion on how low power prices are affecting the strategies of plant owners in ERCOT, summit organizers asked the panelists to role-play the different aspects of generation investment.
Federal Power Co. CEO Steve Gilliland, filled his natural role as a developer, and Tom Rose, CEO of Clean Energy Technology Association, played the investor. That left Cratylus Advisors’ Mark Bruce, who represents Southern Cross Transmission in its bid to become the ISO’s first DC tie operator, to play the regulator.
Asked what kind of signals the ORDC was giving investors, Gilliland said, “It’s not giving signals big enough and substantial enough.”
“What drives the financier and developer is cash and cash flow,” he said. “I don’t believe that system is giving a clear enough signal for a long enough period of time that convinces me new generation is warranted. I don’t believe it will be allowed to be a significant enough number. It’s going to like moving the deck chairs around on the Titanic.”
“As the regulator, that statement scares me because that ship didn’t make it,” Bruce deadpanned. “The ORDC was not intended to be a substitute for scarcity pricing. It is a construct intended to correct the anomalies in pricing that result from out-of-market actions of the grid operator.
“I applaud the Texas commission for resisting the call to pad the ORDC,” Bruce continued. “That doesn’t help the fundamentals. We’ve had significant periods of time where the system is overbuilt, and the prices will be, and should be, in the dirt during those periods. And that’s the rub, a political rub. The economically optimal reserve margin is quite a bit smaller than the official, cushy planning reserve margin. We’re about to live in the gap between the two, and the political leadership of the state is going to have to decide whether to let the market speak. The economics will reveal in themselves, and then the politics will play catch-up.”
Rose, reminding the audience that he was playing the financier, said, “All this is fairly interesting. Existing generators are going to have a great Christmas this August, but I am going to hold off on new investment until we see how the summer works out.
“I don’t think anyone will argue we’re moving into unchartered waters. That excites me. It might be a risk to some, but it’s a reward to me. If there are involuntary disconnections or if prices go up or down, you’re going to see a governmental reaction,” Rose said. “Reliability the last 10 years has been taken for granted. I already hear people talking about reregulating the market. Mark and I know that’s not going to happen. As he said, ‘There is no Plan B.’”
Generators: ORDC Won’t Incent New Generation
Generation owners in ERCOT debated the effectiveness of the ORDC, one of several pricing mechanisms the ISO says will help respond to tightening reserve margins this summer. (See ERCOT: Tight Summer Margins No Cause for Alarm.)
“The ORDC, which is a scarcity pricing mechanism, is absolutely working as designed,” said Dynegy’s Bob Helton during a panel discussion on resource adequacy. “The question is, is it getting us to where we want to be, which is reliability equilibrium and economic equilibrium?”
The Lower Colorado River Authority’s Randa Stephenson said the ORDC should not be seen as a signal for additional generation development. Continued growth in wind generation is expected to pick up much of the slack for recent retirements of baseload generation, and while 2018 futures are trading around $140/MWh, the market has already considered the plant closings by Vistra Energy and others. (See Vistra Energy to Close 2 More Coal Plants.)
“Is there enough scarcity to signal a generation buildout? No, not even a peaker,” Stephenson said. “If you look out into the future, the market knew Vistra was going to happen. Summer of 19, 20 prices didn’t move up that much. I don’t think the signals are out there to justify new build.”
Stephenson said demand response mechanisms are having a greater effect on the market.
“As a generation owner … ORDC is icing on the cake,” she said. “You see a lot of demand response looking at chasing those high-demand periods. You see a drop of 2,000 MW, and that takes away the scarcity prices you were anticipating.”
“ORDC was never introduced, never is and never will be a resource adequacy tool,” Helton said. “It’s for scarcity pricing, a poor man’s co-optimization. It does help with missing money and equilibrium in the market. The correct place for reserves to be is an economically optimal reserve margin. You will likely have load-shed events, but that’s the economical thing to do.”
Coauthor Behind Market Reform Report Highlights Tx Costs
Susan Pope, managing director of FTI Consulting’s economic practice, told attendees during her keynote address that she and her coauthor on a report recommending ERCOT market reforms believe that the state’s transmission planning policies have “materially” raised costs.
Pope said Texas’ Competitive Renewable Energy Zones (CREZ) initiatives, a $7 billion program that built 2,800 miles of new transmission to deliver West Texas wind energy to the state’s urban centers, was an out-of-market investment “not being made by at-risk investors who need to recover the full costs of their investment.”
CREZ was part of more than $10 billion in transmission investments that have been added to total system costs over the past five years, she said.
“ERCOT regional transmission planning favors transmission for reliability problems, using very conservative assumptions for new generation,” Pope said. “The analysis only includes resources that have committed to construction. Transmission investments will be identified and will pre-empt market-based generation solutions driven by energy-only prices, that could be alternatives to solving reliability problems.
“The over-investment in transmission is partly because of the long lead times to build transmission,” she said. “Those planning can end up with extremely expensive solutions to solve reliability. Continuing to build this transmission reduces energy prices because it resolves all the congestion before it has a significant effect on prices.”
NRG Energy and Calpine commissioned Pope and William Hogan, research director of the Harvard Electricity Policy Group, to write a report assessing ERCOT’s energy-only design. The report asserts that subsidized renewable resources, socialized transmission costs and the lack of local scarcity pricing have “exposed areas where there is a need for adjustments” to ERCOT’s pricing rules. The Texas PUC held two workshops last year to discuss the report and other potential market reforms. (See ERCOT, Regulators Discuss Need for Pricing Rule Changes.)
During a discussion on transmission congestion constraints and how to address them, Brad Schwarz, Hunt Power’s director of system planning, described the CREZ initiative’s unintended consequences.
“CREZ was building transmission ahead of the generation, in the hopes the generation would come. It has happened,” Schwarz said. Then came the state’s oil and gas boom in recent years, he said.
“We would have been struggling to serve those loads without the CREZ,” Schwarz said. “We were able to serve more oil and gas load and bring more economic development to the state of Texas. You never really undervalue a transmission line. Once it’s out there, it finds value.”
Energy Storage Offers Solution to Congestion Issues
Kip Fox didn’t hide his disappointment over Texas regulators’ recent rejection of an American Electric Power request to connect a pair of utility-scale battery facilities to the ERCOT grid. AEP’s application ran into opposition from consumer organizations and market participants who argued that allowing the assets to be included in the regulatory base would harm competition. (See “Staff Opens Battery-Storage Rulemaking,” Texas PUC Briefs: Feb. 15, 2018.)
“We had an alternative to building a long distribution line. It was a $1.6 million solution to a $12 million problem,” said Fox, president of Electric Transmission Texas, a joint venture between AEP and Berkshire Hathaway Energy subsidiaries. “Unfortunately, since those [applications] were denied, without prejudice, we’re kind of back to square one.”
He said with batteries’ ability to provide frequency support and resolve overloading problems, “it makes more sense to run a battery eight to 10 times a year, rather than building a line.” Fox suggested Fluence Energy’s use of a portable battery in downtown Indianapolis presents a possible solution to congestion issues.
“We would like to move a battery around and solve that problem,” he said. “When the congestion is gone in five years because a transmission line hasn’t been built, we will have saved the ratepayers a lot of money.”
Tim Ash, Fluence’s market director for the eastern U.S., said other RTOs are wrestling with the same concerns over battery storage ownership and its effect on markets.
“There’s a much, much bigger market for energy storage,” Ash said. “It solves a reliability issue, which occurs maybe 10 times a year. The economic benefits are there today. The question is how to get the rules to unlock those benefits.”
FERC last month directed RTOs and ISOs to allow energy storage resources full access to their markets, an order that does not apply to ERCOT (RM16-23). (See FERC Rules to Boost Storage Role in Markets.) Asked if FERC’s directive might influence the PUC, which regulates ERCOT, to follow suit, Fox said, “Hell, yeah!”
“I’ve seen many times where the commission defaults to where FERC opens up the rules,” Fox said. “I find those rules are sometimes a little behind, sometimes a little ahead. There will be some pressure at all levels of the [state] government.”
Jack Farley, CEO of Apex Compressed Air Energy Storage, pointed to a 2012 PUC order that allows energy storage resources in ERCOT to pay wholesale prices for recharging, with no retail or transmission or distribution fees. “The energy market averages 40,000 MW and the ancillary services market is about 5,000 MW. In terms of participating in ERCOT energy and ancillary service products, I don’t think there are barriers today for energy storage resources,” he said.
“We will see energy storage adopted early,” said a more optimistic John Bonnin, vice president of energy supply and market operations for San Antonio’s CPS Energy. “As the technology improves, we will see it displace other applications in other parts of the market. If we meet again in five years, every one of us around here will have some sort of storage on their system. We all have to get smarter about the effect all that capacity will have on pricing, fuel and dispatch. It’s going to be disruptive.”
Developers See Bright Future for Texas Solar
A panel of solar developers gave high marks to the Texas market, which could see up to 8 GW of solar growth over the next few years.
“Texas is attractive because of low pricing. Wind is the headline, but at the same time, if the load continues to grow, we can make the case that there’s a match there for solar too,” said Andrew Fay, origination manager for First Solar.
Shalini Ramanathan, vice president of origination for RES Americas, said price pressure “is the reason we’re seeing so much development in West Texas and with large projects. If we can be competitive, we can do more 20-MW projects in other parts of the state. I think there’s a bias to larger West Texas solar.”
Spivey Paup, Recurrent Energy’s development director, said even West Texas, with its oil and gas infrastructure, can pose challenges.
“But once you get out of the Permian Basin, that complication goes away,” Paup said, referring to Texas’ rich petroleum fields. “We need to find a balance between strong resources and development complications. Renewables and solar were born and bred in California, but we can blow them up to scale and send California packing.”
Charlie Hemmeline, executive director of the Texas Solar Power Association, said current rules have resulted in “steady interest” in sun-powered generation in the state.
“We’re not going to ask for new polices or mandates or incentives,” he said. “We want it to work the way Texas wants it to work. ‘Don’t do anything bad to us’ is the primary policy ask.”
EVs, With or Without Drivers, are Coming
During a discussion of changing perspectives among end-use customers, Rob Threlkeld, General Motors’ global manager for renewable energy, noted he had driven from Detroit to Lansing, Mich., without once touching the steering wheel of his Cadillac CT6, thanks to its Super Cruise semi-autonomous driver-assistance system. The car comes in a plug-in version in addition to four- and six-cylinder engine models.
“In a year, the driver will touch the steering wheel much less,” Threlkeld predicted.
He had a believer in Champion Energy Services CEO Michael Sullivan, who owns a Tesla. He said the more mainstream CT6, which starts at about $85,300, will be more broadly available and easier to purchase than the special-order Tesla models.
“When you order Tesla, it’s like ordering an Italian shoe from a cobbler in Milan,” he said.
Both Threlkeld and Sullivan agreed that electric vehicles pose a sea change for the electric industry.
“We have been working closely with a lot of utilities, especially those progressive ones that are really interested in this space. It’s load growth, and that interests them,” Threlkeld said.
“If the projections are right, my teenage kids will never drive an internal-combustion car,” Sullivan said. “If everybody’s driving an electric car, that’s a major change to the industry, especially if somebody can capture storage in a really dense way.”
— Tom Kleckner