Industry experts on Oct. 26 offered a range of recommendations for how wholesale power capacity markets can be revamped in response to the changing US energy mix and extreme weather.
"These markets have to be continually tweaked, and we understand that puts a strain on investments," Emma Nicholson, a senior economist at the Federal Energy Regulatory Commission, said during a panel discussion at the Nodal Trader Conference by S&P Global Commodity Insights in Washington, DC. "It's certainly a constant struggle."
Texas, which previously relied on scarcity pricing to ensure grid reliability, has been wrestling with its wholesale market design in the wake of a deadly February 2021 winter storm that resulted in widespread generation outages, said Mike Pickens, a principal research analyst with Commodity Insights.
Since the storm, peak electricity demand in Texas has grown by 11 GW, and renewable and short-duration energy storage has increased by 23 GW, while long-duration dispatchable resources have only grown by 3 GW in nameplate capacity, Pickens noted.
At the same time, the cost of reliability is getting more expensive. Pickens noted that rule changes implemented by the Electric Reliability Council of Texas Inc. increased the cost of ancillary services such as spinning reserves by more than $1 billion over the summer. More rule changes are on deck.
In November, ERCOT will implement a minimum price adder of $10/MWh when operating reserves fall between 6.5 GW and 7 GW, increasing to $20/MWh when reserves fall below 6.5 GW.
The Public Utility Commission of Texas also approved what is effectively a capacity market construct, called a performance credit mechanism, although that plan is still under review. Capacity markets essentially pay power generators for the promise to perform when they are called upon.
"At some point, we need to get together with policymakers, regulators and consumers and figure out the right balance between reliability and affordability," Pickens said. "I think that's still an open question."
Residual sources of revenue
Nicholson said ERCOT's experience has "made it very difficult for state policymakers to go the energy-only route."
"I think they understand, especially with the changing resource mix and extreme weather risk that we're facing, that an energy-only construct is getting riskier and politically untenable," Nicholson said.
On the other hand, Joseph Bowring, president of Monitoring Analytics LLC, said forward capacity markets such as those operated by the PJM Interconnection LLC should continue to serve as a source of residual revenue outside traditional energy and ancillary services markets. Monitoring Analytics is PJM's independent market monitor.
"The capacity market is not an energy market, and the goal is not to be providing price signals in the same sense as the energy market," Bowring said. "The energy market provides the most important, granular price signals there are, and a capacity market is never going to compete with that."
Wholesale power market experts generally agree that compensating generators for flexibility, or the ability to quickly ramp up or down, should be done in energy markets, Nicholson added.
Accreditation, prompt auctions
However, experts predict that capacity accreditation — or the measure of an individual resource type's actual contribution to system reliability — will become increasingly important as the grid becomes dominated by weather-dependent sources of renewable generation.
One potential hurdle is a lack of consensus within the industry on best practices for capacity accreditation, said Devin Hartman, director of energy and environmental policy at the R Street Institute. "Some degree of regional experimentation might just be a necessary component of the evolution of capacity market design for five to 10 years," Hartman said.
PJM, for example, is seeking FERC's approval to accredit all resource types using a methodology known as effective load-carrying capability, which accounts for correlated generator outages like those that occurred during a severe winter storm in December 2022.
Moving to a more timely version of what are currently three-year forward capacity markets may also be necessary in some regions, Nicholson suggested. Those markets were originally based on the assumption that the interconnection process for a typical new power generator — at the time a natural gas combined-cycle turbine — would take about three years.
"Anyone who's looked at the interconnection queues realizes that's not going to happen," Nicholson said. "Three years seems fast."
Electric transmission expansion can complement efforts to redesign capacity markets, Pickens said. Over the summer, ERCOT declared a state of emergency despite having "plenty" of wind generation capacity along the Gulf Coast, Pickens noted.
ERCOT ultimately managed a related transmission constraint without resorting to blackouts, "but it does illustrate the point that deliverability is certainly an important issue in these high-renewable-penetration markets," Pickens said.
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