Certain rule changes would enhance price signals in the Electric Reliability Council of Texas, according to stakeholders gathering in Austin on Aug. 10 at a workshop hosted by the Public Utility Commission of Texas.
William Hogan, a power market expert at Harvard University's Kennedy School of Government, and FTI Consulting Inc. managing director Susan Pope kicked off the workshop by summarizing market policy recommendations they made in a May paper they co-authored.
Much of the discussion centered on a proposal to overhaul ERCOT's power market through the procurement of energy and ancillary services simultaneously in its real-time market in a process called real-time co-optimization. Energy and ancillary services are considered necessary to support reliable operation of the transmission system.
Real-time co-optimization would find the most efficient way to procure energy and ancillary services every five minutes. In the existing real-time market, ERCOT cannot deploy ancillary service capacity to provide energy during real-time operations except in emergency conditions, even though sometimes it would be more economical to do so.
ERCOT estimates implementation of real-time co-optimization of energy and ancillary services in its real-time market would take four to five years and cost a minimum of $40 million.
Potomac Economics president David Patton, a power market expert, called real-time co-optimization "foundational" and testified that the benefits exceed the project cost to the extent that the commission should not order a cost-benefit study.
He said real-time co-optimization would reduce production costs, lower congestion management costs, improve competition in the ancillary services market and allow for the definition of additional ancillary services products, including locational products.
Despite Patton's remarks, both commissioners seemed to balk at the potential scale and cost of the real-time co-optimization project.
Commissioner Brandy Marquez questioned whether the market required further intervention, speculating that the low prices endured for the last six years were due to oversupply. She said investors seemed drawn to the market in spite of low power prices, and that perhaps high prices would return when some generators exited the market.
Patton speculated the investors may be drawn to the market by the "optionality" of the potential for high prices. That is, investors are willing to endure short-term losses for a large payoff down the road.
Commissioner Kenneth Anderson, Jr. raised concern that the cost and scope of the project could spiral out of control, citing ERCOT's shift from a zonal market to a nodal market, a seven-year undertaking completed at the end of 2010. "We had difficulties getting nodal implemented in Texas. It was delayed and a lot more expensive than originally planned. One has a sense that ERCOT and some of the stakeholders are unenthusiastic about tackling a big IT project again."
But he added later, "I'm inclined to believe there are [proposed changes] that make a lot of sense. The question is what foundation do we need to build in order to support a decision like that."
A brief history of ERCOT's market evolution and the potential path forward
In 2011, reliability concerns came to the forefront when the grid operator was forced to take emergency action to stabilize the grid during extreme weather that had taken place during both the winter and summer of that year.
In the wake of those events, the commission, working through ERCOT, made changes to the energy-only market, including incremental increases in price caps from $3,000/MWh to $9,000/MWh and the implementation of an operating reserve demand curve to more efficiently price reserve capacity as it diminishes. Some stakeholders pushed to alter ERCOT's energy-only market design to include a capacity market, but ultimately, the PUCT decided against radically altering ERCOT's market design.
Despite the reforms, the market has experienced persistently low power prices, and experts testifying before the commission at the Aug. 10 workshop blamed market fundamentals, market design inefficiencies and factors external to the market, including federal policy.
In summarizing their May paper, Hogan and Pope cited low natural gas prices, renewable subsidies, ERCOT market rules and state policies governing transmission planning and cost allocation for suppressing power prices.
In addition to real-time co-optimization, Hogan and Pope recommended adjustments to the operating reserve demand curve, including the marginal cost of transmission losses in energy dispatch and pricing, the addition of local scarcity pricing and changes to transmission planning and cost-recovery allocation.
Hogan and Pope also noted that ERCOT's current six-year transmission planning process has too long of a timeline. "By identifying and implementing transmission solutions over a six-year period, ERCOT's planning process suppresses locational price signals before they occur, preventing more efficient non-transmission solutions to system congestion or reliability issues," they wrote.
Hogan and Pope also argue that ERCOT's transmission cost recovery mechanism has a demand, and therefore price-suppressing, effect.
Under the transmission cost allocation methodology, known as 4CP, a distribution service provider's share of load during the interval during which the system-wide peak occurs each month from June to September defines its annual allocation of ERCOT's transmission service cost.
"With the 4CP transmission cost allocation, 44% of ERCOT load has an enormous out-of-market incentive to reduce demand during exactly the peak intervals when prices would otherwise be high or rising in an energy-only market. In effect, there is a payment, in terms of avoided transmission and distribution charge allocations in the following year, leading to a reduction in peak demand and in energy prices. Importantly, there is no real reduction in transmission or distribution costs," the authors wrote.
For now, the commissioners have decided to focus on rules governing price formation in the market, rather than external factors that might influence market behavior and pricing.
Regarding real-time co-optimization, ERCOT told the commission that it would likely have to revisit prior decisions, including those it had made about the operating reserve demand curve and price caps.
The commissioners will continue the discussion at its next open meeting on Aug. 17.