By: Juliana Brint |
As the Electric Reliability Council of Texas faces rising price caps, market participants are considering broad changes to the grid operator’s credit rules to better account for potential price volatility.
At the instruction of the Public Utility Commission of Texas, ERCOT’s system wide offer cap on August 1 rose to $4,500/MWh from the previous cap of $3,000/MWh. The PUC recently postponed action on a proposal to further increase the system wide offer cap — possibly setting it as high as $9,000/MWh by June 1, 2015 — as the commission continues to discuss the state’s resource adequacy issues.
ERCOT has already implemented some changes to its credit rules for the real-time market in response to the higher offer cap. When the higher offer cap came into effect, ERCOT added a seasonal adjustment factor to the determination of collateral requirements, reduced to 40 from 60 the number of days of market participant history it reviews when determining credit requirements and gave itself more discretion in determining credit requirements. The changes aim to fix under-collateralization during shortage pricing events as well as over-collateralization following such events.
But some market participants are beginning to consider whether more far-reaching changes to the credit rules will be necessary to handle the potential increase in price volatility. Eric Goff, director at Citigroup Energy, is leading a subgroup of the Market Credit Working Group to discuss ERCOT’s future credit design.
At a Tuesday afternoon session, the group debated a number of possibilities for how ERCOT could improve its credit system, including moving to a probabilistic model, using an exchange for some ERCOT products and purchasing forced outage insurance.
Goff discussed a number of issues around the possibility of shifting to a probabilistic credit model. While ERCOT currently calculates credit requirements on a transaction-by-transaction basis, a probabilistic model would look at market participants’ entire trading portfolios and take into account the probability of different outcomes.
“The current credit system was kind of designed prior to the significant occurrences of scarcity pricing in the summer,” Goff said. “There’s potential room for improvement to more adequately capture the risk of scarcity pricing. … “At the same time, there may be some inefficiencies that may be structural to our credit system. So taking a portfolio approach might possibly provide an opportunity to reduce some structural inefficiencies.”
Much of the discussion centered on whether moving to a probabilistic model would be worthwhile given its increased complexity.
A representative from DC Energy suggested that requiring ERCOT to look at market participants’ entire portfolios might be “onerous” and suggested credit risks might be mitigated by clearing some ERCOT products on an exchange, like Nodal Exchange.
Another market participant suggested that ERCOT might want to explore forced outage insurance, which could be paid for and used as coverage by all generators in case they suffer a costly outage during a shortage pricing event. The market participant said that while prepaid insurance would require more capitalization up front from generators, it might be a simple way to reduce ERCOT’s exposure to potential bankruptcies.
“[I want] just to think a little bit out of the box on how we can simplify what we’re doing and provide better assurance to the market that we’ll have fewer entities going under,” the market participant said.
