Yet policymakers and stakeholders largely focus almost solely on increasing reserve margins to improve reliability. If we instead looked the most comprehensive means of improving reliability in the manner that matters to customers, we’d probably find that distributed energy resources are a much better fit. To the extent that DERs can relieve distribution level loads, we gain at both levels and not just at the system level with added bulk generation.
This approaches first requires a change in how resource adequacy is defined and modeled to look from the perspective of the customer meter. It will require a more extensive analysis of distribution circuits and the ability of individual circuits to island and self supply during stressful conditions. It also requires a better assessment of the conditions that lead to local outages. Increased resource diversity should lead to improved probability of availability as well. Current modeling of the benefits of regions leaning on each other depend on largely deterministic assumptions about resource availability. Instead we should be using probability distributions about resources and loads to assess overlapping conditions. An important aspect about reliability is that 100 10 MW generators with a 10% probability of outage provides much more reliability than a single 1,000 MW generator also with a 10% outage rate due to diversity. This fact is generally ignored in setting the reserve margins for resource adequacy.
We also should consider shifting resource investment from bulk generation (and storage) where it has a much smaller impact on individual customer reliability to lower voltage distribution. Microgrids are an example of an alternative that better focuses on solving the real problem. Let’s start a fundamental reconsideration of our electric grid investment plan.
The California ISO Department of Market Monitoring notes in its comments to the CPUC on proposals to address resource adequacy shortages during last August’s rolling blackouts that the number of fixed price contracts are decreasing. In DMM’s opinion, this leaves California’s market exposed to the potential for greater market manipulation. The diminishing tolling agreements and longer term contracts DMM observes is the result of the structure of the power cost indifference adjustment (PCIA) or “exit fee” for departed community choice aggregation (CCA) and direct access (DA) customers. The IOUs are left shedding contracts as their loads fall.
The PCIA is pegged to short run market prices (even more so with the true up feature added in 2019.) The PCIA mechanism works as a price hedge against the short term market values for assets for CCAs and suppresses the incentives for long-term contracts. This discourages CCAs from signing long-term agreements with renewables.
The PCIA acts as an almost perfect hedge on the retail price for departed load customers because an increase in the CAISO and capacity market prices lead to a commensurate decrease in the PCIA, so the overall retail rate remains the same regardless of where the market moves. The IOUs are all so long on their resources, that market price variation has a relatively small impact on their overall rates.
This situation is almost identical to the relationship of the competition transition charge (CTC) implemented during restructuring starting in 1998. Again, energy service providers (ESPs) have little incentive to hedge their portfolios because the CTC was tied directly to the CAISO/PX prices, so the CTC moved inversely with market prices. Only when the CAISO prices exceeded the average cost of the IOUs’ portfolios did the high prices become a problem for ESPs and their customers.
As in 1998, the solution is to have a fixed, upfront exit fee paid by departing customers that is not tied to variations in future market prices. (Commissioner Jesse Knight’s proposal along this line was rejected by the other commissioners.) By doing so, load serving entities (LSEs) will be left to hedging their own portfolios on their own basis. That will lead to LSEs signing more long term agreements of various kinds.
The alternative of forcing CCAs and ESP to sign fixed price contracts under the current PCIA structure forces them to bear the risk burden of both departed and bundled customers, and the IOUs are able to pass through the risks of their long term agreements through the PCIA.
California would be well service by the DMM to point out this inherent structural problem. We should learn from our previous errors.
Steve Berberich, CEO of the California Independent System Operator, assessed for GTM his views on the reasons for the rolling blackouts in the face of a record setting heat wave. He overlooked a key reason for the delay on capacity procurement (called “resource adequacy” or RA) and he demonstrated a lack of understanding of how renewables and batteries will integrate to provide peak capacity.
Berberich is unwilling to acknowledge that at least part of the RA procurement problem was created by CAISO’s unwillingness to step in as a residual buyer in the RA market, which then created resistance by the CCAs to putting the IOUs in that role. RA procurement was delayed at least a year due to CAISO’s reluctance. CAISO appears to be politically tone-deaf to the issues being raised by CCAs on system procurement.
He says that solar will have to be overbuilt to supply energy to batteries for peak load. But that is already the case with the NQCELCC just a fraction of the installed solar and wind capacity. Renewable capacity above the ELCC is available to charge the batteries for later use. The only question then is how much energy is required from the batteries to support the peak load and is that coming from existing renewables fleet. The resource adequacy paradigm has changed (more akin to the old PNW hydro system) in which energy, not built capacity is becoming the constraint.
In its annual report on resource adequacy (RA) transactions, the CPUC reports the wrong result for the market price to be used for valuing capacity from the RA market data. The Commission’s decision issued in the PCIA rulemaking on establishing the CCA’s “exit fee” uses this value in error. In the CAISO energy and ancillary services markets, the market clearing price used to set the value of the energy portfolio is determined by the highest accepted bid in a single hour, and then averaged across all hours. In contrast, the average reported RA price in The 2017 Resource Adequacy Report incorrectly reports the average of all transactions. This would be equivalent to the CAISO reporting the average of all accepted bids, including those at zero or even negative, as the market clearing price.
The appropriate RA price metric is the highest RA transaction price for each month. This price represents the market equilibrium point at which a consumer is willing to pay the highest price given how low a price a supplier is willing to provide that quantity of the resource. (The other transactions are called “inframarginal” and such transactions are common in many markets.) In a full auction market, all transactions would clear at this single price, which is why the CAISO reports a single market clearing price for all transactions in a single hour. That should also be the case for the RA market price, except the time unit is a month.
Due to a lack of an auction for the moment, it is possible to manipulate the highest apparent price through a bilateral transaction. Instead, the Commission could choose a price near the highest point, but with sufficient market depth to mitigate potential manipulation. Using the 90th percentile transaction is one metric commonly used based on a quick survey of market price reports.