By Robert Mullin
CAISO stakeholders last week expressed misgivings and confusion about a new issue paper exploring how the ISO can resolve certain generator and transmission contingencies currently handled by out-of-market operations.
Questions about the generator contingency and remedial action scheme modeling enhancements paper largely stemmed from uncertainty about the potential scope of the effort. Market participants also sought to understand how such an effort would differ from CAISO’s Contingency Modeling Enhancements (CME) initiative, which is nearing completion.
“I’m curious as to why this stakeholder process is arising at this point in time,” Ellen Wolfe, a consultant representing the Western Power Trading Forum, said during an April 25 stakeholder conference call. “Especially in relation to CME and where that is.”
“This just seemed like a good time to get a jump-start on this,” responded Perry Servedio, CAISO senior market design and policy developer. “It was always the thought that these two [initiatives] would overlap.”
CAISO kicked off the CME initiative three years ago to address a Western Electricity Coordinating Council reliability provision requiring grid operators to return a critical transmission path — such as Path 15 linking Northern and Southern California — to its system operating limit within 30 minutes of a destabilizing event, such as the loss of a generator or transmission line.
The ISO’s present approach to managing those contingencies relies on out-of-market interventions coupled with day-ahead market measures that procure a “bucket” of responsive capacity resources based on a flat megawatt rating of the line in question, an approach that ISO staff considers to be inefficient.
The CME initiative would update CAISO market rules to instead procure those resources based on expected flows, with the process first run in the day-ahead market and then rerun in real-time. In addition, that process would be more closely integrated with the general procurement for locational ancillary services. That is expected to reduce the overall pool of reserves receiving compensation, reducing costs.
Last week’s issue paper looks to zero in on a different, if related, aspect to an emergency response: the system’s ability to gain access to contingency reserves while at the same time keeping all affected transmission paths below their emergency ratings. The ISO calls it the “transmission feasibility” of those reserves.
“We’d want to ensure that, given a generator loss, we don’t overload any lines and we can rely on the reserves,” Servedio said.
The newer initiative would also formulate a market-based response to transmission losses stemming from the triggering of remedial action schemes (RAS) — emergency plans designed to prevent one transmission outage from setting off a series of cascading outages.
Servedio noted that CAISO currently has more than 20 RAS modeled within its own system, a figure that does not include schemes elsewhere in the Western Interconnection. While the ISO currently factors RAS into its market operations through adjustments to its market software — including the use of nomograms to avoid exceeding transmission line limits — it thinks that approach comes up short.
“Even with all that modeling, you can end up with real-time exceptional dispatch [out-of-market intervention] because we don’t have a way to model the RAS in the day-ahead market,” he said.
That statement prompted one stakeholder to seek clarification about exactly what the current process entails.
“So you’re saying there is some sort of ad hoc change in modeling that takes place in both day-ahead and real-time?” asked Bonnie Blair, speaking for the “Six Cities” — municipal utilities serving Anaheim, Azusa, Banning, Colton, Pasadena and Riverside. “I’m not sure I follow, but I’ll think about it.”
Another stakeholder questioned whether the changes being contemplated by the ISO would be worth the investment.
“When you look at this [initiative] from an economic perspective, would you say this is more economic than what you do today?” asked Wei Zhou, senior project manager with Southern California Edison.
“We expect it to be the more economic solution — clearly,” said George Angelidis, principal with CAISO’s Power Systems Technology Development group.
“We currently don’t have in the market the ability to model generator contingencies,” Angelidis later added. “Without the capability to model the RAS, your market solution is a more conservative and costly solution.”
However, CAISO staff could provide no figures for how often contingency reserves have been inaccessible in past, in part because the current manual intervention process requires system operators to rely on only those resources that are accessible in real time.
“I can’t give you data on what megawatts weren’t deliverable, because our operators are working to ensure that the megawatts are deliverable [through exceptional dispatch],” Servedio said.
Other stakeholder concerns focused on the proposal’s technical details. Call participants asked questions about how many RAS would be incorporated into a possible proposal, the duration of emergency ratings and the workings of the complex flow models CAISO staff used to determine the transmission feasibility of contingency reserves.
“I’m just trying to figure out the scope of this effort,” said Seth Cochran, manager of market affairs and origination at DC Energy.
CAISO staff took pains to assure stakeholders that the issue paper did not represent an actual proposal — despite an outlined schedule proposing a Fall 2017 implementation date for any measures resulting from the process.
“We’re not really proposing anything yet, we’re just trying to flesh out the issue,” Servedio said.
