Executive Summary

• Battery energy storage systems in CAISO earned over $12 million in Bid Cost Recovery (BCR) payments between January and August 2024, providing a 4% boost to wholesale market revenues.
• 98% of BCR payments to batteries came from the Real-Time Market, as deviations from Day-Ahead schedules led to compensation for lost revenue opportunities.
• CAISO is tightening BCR rules to prevent strategic bidding, introducing a proxy price mechanism to limit payments while ensuring batteries recover legitimate opportunity costs.

Subscribers to Modo Energy’s Research will also find out:

• How batteries leveraged BCR payments for strategic advantage and why some earned more than others.
• What CAISO’s new BCR rules mean for battery operators, and how they will change revenue potential in 2025.
• Why BCR has been more significant for batteries than for traditional generators, and what this says about CAISO’s evolving market design.

To get full access to Modo Energy’s Research, book a call with a member of the team today.

Bid Cost Recovery payments provide battery energy storage with a 4% top-up on wholesale revenues

Between January and August 2024, battery energy storage systems in CAISO earned over $12 million in Bid Cost Recovery (BCR) payments.

These payments provided a 4% top-up on wholesale market revenues - on average - through the first eight months of 2024.

Moving forward, this contribution will likely shrink to some degree due to recent policy changes made by CAISO.

However, BCR will still be a relevant piece of the revenue stack for batteries in CAISO.

So, what is Bid Cost Recovery, and how exactly are utility-scale batteries uniquely impacted by it?

What is Bid Cost Recovery?

Bid Cost Recovery was originally designed to ensure that thermal generators earn enough wholesale market revenues to cover their costs.

This is particularly relevant when a resource is dispatched for reliability and market prices fail to cover its operational costs.

Bid Cost Recovery ensures generation resources earn revenues that exceed their costs that are incurred when they are dispatched by the system operator for reliability. This encourages participants to offer to provide energy at a value in line with their operating costs.

In the absence of BCR payments, resources would likely incorporate a risk premium to their offers, raising overall system costs.

Conversely, inflated BCR payments may signal inefficiencies in unit commitment or dispatch.

Generators qualify for BCR payments when wholesale market revenues do not cover their costs on an operating day. These costs include commitment, start-up, minimum load, transition, and energy bid costs.

BCR then provides 'make-whole payments' to units when its revenues fall short of covering costs.

CAISO ensures that resources offering flexibility for dispatch can recover their bid-in costs within a 24-hour period. This guarantee helps these resources earn at least as much revenue as their offer costs, or more, if dispatched.

The system nets each resource’s costs and revenues across all hours of the day. It then calculates Bid Cost Recovery separately for the Day-Ahead and Real-Time Markets to encourage participation in both. However, self-scheduled resources typically do not qualify for this make-whole assurance.

In 2024, Bid Cost Recovery payouts to all generating units in CAISO averaged close to $12 million a month. Natural gas-fired resources received 74% of the total.

Batteries earned the most in Bid Cost Recovery payments of any non-Natural Gas technology type

In fact, monthly BCR payments to BESS in CAISO averaged $1.5 million, or $190 per megawatt of installed capacity.

BESS resources received a much larger share of the Bid Cost Recovery payments than the share of energy they contributed to the grid in 2024.

But, batteries can ramp up and down nearly instantaneously. Additionally, they’re able to ramp from no output to non-zero output, instead of maintaining a minimum sustained output to be considered ‘online’.

Batteries also don’t require fuel. Their primary cost is based on the price for energy used to charge the battery.

So, how do batteries earn significant BCR payments despite not having startup, shutdown, minimum load, or transition costs?

Bid Cost Recovery payments to batteries are based on opportunity costs

BCR for battery energy storage systems differs from thermal generators, primarily due to the unique duration-limited nature of batteries.

A battery has no costs associated with fuel or limitations like ramp rates or minimum on/off times. However, it can only discharge Energy for a limited amount of time.

As a result, a battery’s 'operating costs' are based on its opportunity cost whenever it is dispatched to discharge in any given operating interval.

This means that a battery’s offer to provide Energy doesn’t only account for the cost of charging and discharging. It also accounts for its perceived opportunity cost to offer - or in some cases be unable to offer - in future intervals.

Dispatches to discharge a battery earlier in an operating day sometimes prevent them from capturing higher-value revenue opportunities later on the same day. This is often when batteries are compensated by Bid Cost Recovery.

Typically, this occurs when a battery’s dispatch in Real-Time differs substantially from its Day-Ahead obligations. This can result in a battery being unable to fulfill its Day-Ahead obligations and losing out on high-value revenue opportunities.

Let’s take a look at an example, using a 100 MW / 400 MWh battery that begins its operating day with 350 MWh and a series of Day-Ahead obligations.

A battery receives Day-Ahead awards and is dispatched according to that schedule in the Real-Time Market to start the day

Prior to the operating day, the battery receives awards to buy and sell energy in the Day-Ahead Market during various hours in the morning and early afternoon.

During the initial hours of the day from 12am to 4pm, the battery operates based on this Day-Ahead schedule. Real-Time Dispatch mirrors its Day-Ahead obligations.

As a result, there is no deviation from the Day-Ahead schedule in the Real-Time Market. This means the battery's dispatch during this period of operations has no associated bid cost.

In the early evening, the battery is dispatched to discharge in Real-Time, despite no Day-Ahead obligation

From 5pm to 7pm, prices in Real-Time rise above the Day-Ahead prices. In this scenario, the battery’s offer to provide Energy is low enough for it to be dispatched in Real-Time. This means that the battery is deviating from its Day-Ahead schedule.

In this case, the battery incurs a positive bid cost, as it earns excess revenues in the Real-Time Market.

Additionally, this dispatch reduces the battery’s state-of-charge to nearly 0 MWh.

The positive bid cost here equates to the size in dispatch deviation from the Day-Ahead Market, multiplied by the battery’s offer to provide Energy in the Real-Time Market. In this case, the deviation is 100 MW. This is because the battery is dispatched to discharge 100 MW, despite having a Day-Ahead obligation of 0 MW.

Over the same period of time, the battery consistently offers to provide Energy at the value of the Day-Ahead Market price, or $75/MWh between 5 and 6 PM and $90/MWh between 6 and 7 PM.

Similarly, Real-Time revenues are calculated by multiplying the size of the Real-Time deviation from the Day-Ahead Market by the Real-Time locational marginal price.

In this example, from 5 to 7 PM, the battery incurs positive bid costs of $10,208 while earning Real-Time Market revenues of $15,505.

The battery runs out of Energy and is unable to fulfill its evening Day-Ahead obligation, accumulating a negative bid cost

Between 7 and 8 PM, the battery runs out of state-of-charge. As a result, it fails to fulfill its entire Day-Ahead obligation of discharging 100 MW over the course of that hour.

This results in a ‘buy-back’, and the battery's Real-Time revenues equal its Real-Time LMP times its Real-Time deviation - in MWs - from its Day-Ahead obligation. In this case, with Real-Time prices rising, this equates to Real-Time revenues of -$15,327 over the course of the hour.

Additionally, using the same calculation for the bid cost earlier in the evening, the battery accumulates a negative bid cost of -$1,766.

Over the course of the operating day, Real-Time revenues and bid costs accumulate.

In this example, cumulative Real-Time revenues and bid costs result in a perceived loss, as bid costs exceed revenues. In other words, the difference in cumulative bid costs ($8,442) and cumulative Real-Time revenues ($178) is positive, resulting in a Bid Cost Recovery payment of $8,263.

Hence, the battery receives compensation for its premature dispatch and the spike in Real-Time prices later in the day. It receives BCR payments as an additional top-up to its Day-Ahead and Real-Time revenues.

This is because it would have fulfilled its Day-Ahead obligation if it had not been dispatched earlier in the day.

Deviations from Day-Ahead obligations are handled differently for thermal generation vs. batteries

If a thermal generator fails to meet its Day-Ahead commitment due to a fuel shortage, CAISO de-rates the unit for the outage. This renders the generator ineligible for Bid Cost Recovery.

However, as seen in the example, if a battery cannot fulfill its Day-Ahead schedule due to insufficient state-of-charge, the operator can adjust its dispatch to match the binding state-of-charge. This adjusted dispatch may involve buy-back or sell-back of energy. In spite of the battery’s physical limitation, it’s eligible for Bid Cost Recovery.

Say a battery operator anticipates that its net revenue will be equal to or exceed the earnings from delivering its Day-Ahead schedule. They may offer at a lower cost during hours prior to its Day-Ahead schedule to receive early dispatch.

This can lead to market inefficiencies and result in resources being unavailable during some of the most critical operating hours when net load - and prices - peak.

From January to August 2024, BESS in CAISO earned an average of 4% of their revenues from BCR payments

98% of the $12 million paid to BESS as part of BCR came from the Real-Time Market, which includes both the Fifteen Minute Market and the Real-Time Dispatch Market.

In contrast, Bid Cost Recovery payments associated with the Day-Ahead Market were near zero.

In the Day-Ahead Market, batteries face fewer operational constraints that result in out-of-merit order scheduling. This is due to the 24-hour optimization horizon in the Day-Ahead Market.

The Real-Time Market is only able to optimize over a limited interval of five or fifteen minutes.

As seen in the example, this can result in dispatch decisions that impact a battery’s state-of-charge in intervals beyond the Real-Time Market’s optimization horizon. This then results in the battery’s inability to follow through its Day-Ahead schedule. That triggers a buy-back - and subsequent Bid Cost Recovery payment - to adjust for any revenue shortfalls.

How is CAISO changing the BCR mechanism?

This initial Bid Cost Recovery design has raised concerns that batteries may bid strategically to inflate payments. This also means that they would often be forgoing committed Day-Ahead schedules.

As a result, CAISO is implementing protocol changes to mitigate these unintended consequences. In essence, they would revise the Bid Cost Recovery rules that are applicable to storage resources in all Real-Time intervals.

Upon its recent acceptance by FERC, CAISO’s tariff will now use a proxy value to determine the Real-Time bid cost, instead of using the battery’s actual offer price. The proxy value will be the minimum of:

1. The resource’s actual energy offer in the Real-Time market interval, or
2. The greater of three values
1. The resource’s Day-Ahead Locational Marginal Price (LMP)
2. The default energy bid in the Real-Time Market
3. The Real-Time LMP for that interval

By implementing these changes, CAISO aims to limit opportunities for market manipulation, while still allowing storage resources to recover legitimate opportunity costs.