A former regulator says a study that concludes an increasing amount of wind generation will put downward pressure on electricity prices may not be giving adequate weight to certain critical factors.
The study, “The Potential Rate Effects of Wind Energy and Transmission in the Midwest ISO Region,” released May 22, concludes that increasing the amount of wind generation in the Midwest ISO (MISO) region will result in significant reductions in energy costs with only a comparatively modest investment in additional transmission.
“Wind may have the effects of bringing average wholesale prices down but you have to remember how wind delivers. It generally delivers off-peak, so it may lower prices off-peak,” Sherman Elliott, former Illinois Commerce Commissioner and principal of the regulatory, policy, and energy consultancy SJE Consulting, told TransmissionHub on May 22.
While lower off-peak prices may contribute to a reduction in the annual average price of power, other costs may go up. For example, if the wind generation is a ‘must-take’ for the grid operator, then the operator is forced to redispatch other types of generation out of economic merit order to compensate for the additional wind on their systems, Elliott said.
While redispatch may lower the cost of energy, it may also increase costs in at least three areas: increased operation and maintenance (O&M) costs due to cycling baseload coal plants, increased revenue uplift if generators are taken out of merit order, and increased costs for ancillary services to manage wind’s generation characteristics.
For example, if a baseload coal plant is backed down to accommodate wind, “You’re increasing O&M costs, you’re shortening the life of the equipment by cycling it – turbines are designed to run 24/7/365 at a high load factor – plus you’re probably increasing carbon output per kilowatt-hour,” Elliott said.
When redispatch to accommodate wind results in taking generation out of merit order, it can create additional challenges – and costs – through revenue “uplift.”
“Merit order” means committing the lowest-cost generation first, followed by the next lowest, and so on. When wind displaces generation that was previously committed, the economic merit order is disrupted, and those generators that were previously committed have to be compensated for that displacement.
That compensation takes place through a mechanism called a “revenue sufficiency guarantee,” a provision that ensures generators that are committed for reliability reasons by the grid operator will receive sufficient funds to cover their costs, even if they are not ultimately called upon to generate at the level to which they were committed.
“If a unit is committed in the day-ahead market because it was an economic unit, then [the generator] is counting on being compensated,” Elliott said. “If you have to redispatch because of wind, then you have to compensate [the generator], and that cost is uplifted” to other generators on the system through the revenue sufficiency guarantee, Elliott said.
Other costs result from the balancing services needed to manage wind’s variability.
“You may see wind have the effect of bringing energy prices down off-peak, but you end up funding all of this through ancillary services – regulation up and down to deal with the intermittency, the ramp [rate] problems that you have,” Elliott said. “At the same time, other costs – uplift, ancillary services, the cost for operating and maintenance – may go up.”
Elliott also takes issue with the study’s assertion that lower wholesale prices will result in cost savings for end-use customers.
“If a utility customer was on a real-time rate and paid hourly prices, the customer might be able to take advantage of that by shifting … a flexible manufacturing process [to the off-peak] third shift,” he said. “But for the most part, what’s happening is that [wind generators] are increasing energy production during a period of time where there’s insufficient demand to absorb it.”
In addition, Elliott said, a reduction in average wholesale prices would not necessarily be passed on to retail customers unless or until the utility brings a rate case before its state commission.
“In individual states, there can be some regulatory lag in terms of how long it takes for those utilities to come in and have their rates adjusted,” Ezra Hausman, vice president and COO of Synapse Energy Economics, which performed the study, told TransmissionHub on May 22. “In general, the [utilities] like going in for rate adjustments when prices are going up and they’re not quite as happy to do it when rates are going down.”
“So we did not account for the extent to which regulators are on the ball bringing in the utilities and making sure that those savings pass through to consumers but, by regulatory tradition and by the Federal Power Act, purchased power costs – if they go down – those savings should be passed through to consumers in due time,” Hausman said.
“We used the MISO wholesale market as a proxy for power costs that flow through to consumers,” Bob Fagan, senior associate at Synapse Energy Economics, told TransmissionHub. “At the low end of our range, [we] discounted the effect of that pass-through by 50%.”
Just as the map is not the territory, the bottom line for Elliott is that forecasts and predictions are not the final outcome.
“All in all, it’s hard to say whether the effect will, in essence, bring prices down or whether the increasing off-peak energy is basically just being dumped,” Elliott said.