Existing law requires the State Energy Resources Conservation and Development Commission (Energy Commission), at least every 2 years, to conduct assessments and forecasts of all aspects of energy industry supply, production, transportation, delivery and distribution, demand, and prices. Existing law authorizes the Energy Commission to require the submission of demand forecasts from electrical utilities, among other entities, to perform its assessments and forecasts.

This bill would require the Energy Commission, on or before July December 1, 2026, and in consultation with the Public Utilities Commission, Independent System Operator, load-serving entities, and resource aggregators, to adopt a set of upfront technical requirements and load automation standards modification protocols, as defined, to provide the option for a load-serving entity to reduce or modify its electrical demand forecast upon aggregated system operation, as specified.

Existing law requires the State Energy Resources Conservation and Development Commission (Energy Commission), at least every 2 years, to conduct assessments and forecasts of all aspects of energy industry supply, production, transportation, delivery and distribution, demand, and prices. Existing law authorizes the Energy Commission to require the submission of demand forecasts from electrical utilities, among other entities, to perform its assessments and forecasts.

This bill would require the Energy Commission, on or before July 1, 2026, and in consultation with the Public Utilities Commission, Independent System Operator, load-serving entities, and resource aggregators, to adopt a set of upfront technical requirements and load automation standards to provide the option for a load-serving entity to reduce or modify its electrical demand forecast upon aggregated system operation, as specified.

Date of Hearing: May 8, 2024

ASSEMBLY COMMITTEE ON APPROPRIATIONS

Buffy Wicks, Chair

ABPCA Bill Id:AB 2891

Author:(Friedman) – As Amended Ver:March 21, 2024

Urgency: No State Mandated Local Program: No Reimbursable: No

SUMMARY:

This bill requires the Energy Commission to adopt technical requirements and load modification protocol—meaning a combination of capabilities and operational parameters to confidently reduce a load-serving entity’s (LSE’s) electrical demand forecast for any specified hour or hours—to provide the option for an LSE to reduce or modify the LSE’s electrical demand forecast.

Specifically, this bill requires the Energy Commission, on or before December 1, 2026, and in consultation with the California Public Utilities Commission (CPUC), Independent System Operator (CAISO), electric utilities and other entities that provide electricity a to customer (also known, generally, as LSEs) and resource aggregators, adopt a set of upfront technical requirements and load modification protocols to provide the option for an LSE to reduce or modify its electrical demand forecast, submitted to the Energy Commission per current law, upon aggregated system operation. The bill asserts these requirements and protocols are to be met by the resource aggregator through the deployment of load modifying technologies and programmatic measures deemed by the Energy Commission, the CPUC and CAISO to reliably reduce or modify the LSE’s electrical demand.

The bill provides that the Energy Commission, in developing the technical requirements and load modification protocols, may use available funding to test a variety of technological and programmatic approaches in partnership with interested LSEs and distributed energy resource aggregators to facilitate a high degree of confidence for flexible demand performance under the adopted requirements and protocols.

FISCAL EFFECT:

To develop the technical protocol, as required by this bill, the Energy Commission estimates it will need four permanent energy specialist positions at a combined annual cost of $923,000 (Energy Resources Programs Account (ERPA)). It is not clear why the commission will have need for these positions, or all four positions, at least, after it has developed the protocol.

According to the Legislative Analyst’s Office, ERPA is in a structural deficit, with its ongoing revenues failing to keep pace with its increasing expenditures, and the Governor’s administration estimates these ERPA balances will be exhausted by fiscal year 2027‑28.

COMMENTS:

1. Purpose. The author intends the protocols to be developed pursuant to this bill to provide greater certainty about the standards load-modifying technologies must meet in order for LSEs and regulators to rely on them, thereby increasing the use of such technologies to manage electric load. According to the author:

By establishing a set of upfront technical requirements and load modification protocols, the bill would result in a set of quality assurance standards for any load-modifying technologies to shift or reduce the state’s resource adequacy needs during the most expensive hours. Distributed energy providers would have more clarity on what functionalities they must offer retail providers to produce cost-saving value; retail providers would have assurances that would reduce the cost of serving customers; and energy planning agencies would have greater confidence in the reliability performance of aggregated distributed energy resources.

1. Background. In the context of electric service, “load,” in a very general sense, is anything that uses electricity. LSEs, therefore, are the organizations that provide the electricity to meet the electrical demand created by load. These organizations include publicly owned utilities (POUs) and investor-owned utilities (IOUs), as well as other utility-like entities that supply electricity to customers.

The state energy regulators work together in an iterative process to ensure there is enough electricity supplied to the electrical “grid” to satisfy the demand for electricity, otherwise known as load. The process is complex, but generally can be summarized as follows:

• The Air Resources Board’s Scoping Plan establishes a target range for the electricity sector’s greenhouse gas (GHG) emission reductions.
• The Energy Commission’s Integrated Energy Policy Report (IEPR) provides a demand forecast to anticipate statewide load in the next decade or longer.
• The CPUC’s integrated resource plan (IRP) forecasts system generation resource needs to meet the customer demand forecast by the IEPR 10 years in the future.
• The CPUC’s resources adequacy (RA) process identifies resources needed to meet customer demand and ensure reliability today.
• CAISO’s transmission planning process (TPP) identifies the transmission needs to interconnect and balance the system supply described by the IRP with the customer demand projected by the IEPR.
• The TPP relies on the CPUC’s IRP planning targets. CAISO receives the IRP results as inputs into its TPP. The CAISO also considers recommendations from the Energy Commission’s IEPR. The plan is updated annually, and culminates in a CAISO Board of Governors-approved transmission plan that identifies the needed transmission solutions and authorizes cost recovery through CAISO transmission rates, subject to federal regulatory approval.

This bill seeks to effect, primarily, the Energy Commissions demand forecast of statewide load and the CPUC’s RA process. The Energy Commission forecasts demand for electricity, both for California as a whole and by regions and subregions. The Energy Commission’s demand forecast is the foundation for the CPUC’s RA process, in which the CPUC requires LSEs to procure certain amounts of electricity to meet forecast demand.

The Energy Commission provides LSEs an opportunity to modify their forecast electricity demand by demonstrating deployment of a variety of technologies that reduce customer demand for electricity. These technologies are oftentimes summed up as “distributed energy resources,” a blanket term that usually describes technologies—such as solar panels or batteries, to name just two well-known examples—located on the customer-side of the electrical meter that, when deployed en masse can substantially reduce an LSE’s overall load.

Despite the potential for such load-modifying technologies to reduce LSE demand and, consequentially, an LSE’s RA procurement obligations, the deployment of such technologies to reduce load, especially at times of peak electricity demand, has been underwhelming. The author and bill proponents—generally, entities that sell load-modifying technologies and services to LSEs—think know why. As a coalition letter puts it:

The CEC currently has a process to allow each retail electricity provider the option to deploy behind-the-meter distributed energy technologies to reduce or shift its forecasted peak demand. When a retail provider’s forecast is reduced under this load modification process, its wholesale procurement (i.e. resource adequacy) need is also reduced, yielding ratepayer cost savings from avoided wholesale power purchases. This existing CEC process is sound policy, but can be beneficially expanded in two ways as proposed under AB 2891:

(1) Increase transparency on the criteria by which demand forecast can be modified with a high degree of confidence, thereby setting commercial expectations on service quality between potential buyers and sellers of load reduction or demand management services.

(2) Eliminate the current lag between when aggregated system deployment costs are incurred and when the cost savings materializes by relying on upfront load modification protocols instead of after-the-fact load impact protocols.

When such upfront technical requirements and load modification protocols are developed, distributed energy providers and demand response aggregators will have greater assurances on what functionalities they should offer retail electricity providers to have cost-saving and reliability value. Retail providers, in turn, will have assurances that such products or services will reduce the cost of serving their customers.

Analysis Prepared by: Jay Dickenson / APPR. / (916) 319-2081

Date of Hearing: April 17, 2024

ASSEMBLY COMMITTEE ON UTILITIES AND ENERGY

Cottie Petrie-Norris, Chair

ABPCA Bill Id:AB 2891 (

Author:Friedman) – As Amended Ver:March 21, 2024

SUBJECT: Energy: electrical demand forecasts

SUMMARY: Requires by December 1, 2026, the California Energy Commission (CEC), in consultation with specified entities, to adopt technical requirements and load modification protocols to provide the option for load-serving entities (LSEs) to reduce or modify their electrical demand forecast submitted to the CEC as part of the integrated energy policy report (IEPR).

EXISTING LAW:

1. Requires the CEC to adopt the IEPR every two years, which must contain an overview of major energy trends and issues facing the state, including, but not limited to, supply, demand, pricing, reliability, efficiency, and impacts on public health and safety, the economy, resources, and the environment. (Public Resources Code §§ 25300-25327)
2. Defines “load-serving entities” as investor-owned utilities (IOUs), electric service providers (ESPs), and community choice aggregators (CCAs). (Public Utilities Code § 380 (k))
3. Requires the California Public Utilities Commission (CPUC) to work with the California Independent System Operator (CAISO) to establish RA requirements for LSEs. Existing law specifies the criteria the CPUC must consider when establishing RA requirements and specifies that an electrical corporation’s reasonable costs for meeting RA are recoverable from customers through non-bypassable charges. (Public Utilities Code § 380)
4. Requires the CEC to adopt standards for appliances to facilitate the deployment of flexible demand technologies. These regulations may include labeling provisions to promote the use of appliances with flexible demand capabilities. The flexible demand appliance standards must be based on the ability of the appliance’s functions to be scheduled, shifted, or curtailed to reduce greenhouse gas (GHG) emissions associated with electricity generation. The standards shall become effective no sooner than one year after the date of their adoption or updating. (Public Resources Code § 25402(f))

FISCAL EFFECT: Unknown. This bill is keyed fiscal and will be referred to the Committee on Appropriations for its review.

BACKGROUND:

Load Modifiers, Demand Response, and Distributed Energy Resources (DER) – DER is a catch-all term used for a variety of generation, storage, or load modifying resources that, at their most basic level, are connected to, or most closely interacting with, the utility distribution system. DERs include both generation technologies that reduce customer load when consumed on-site (e.g., customer-sited rooftop solar) and load modifying technologies that reduce customer load by actively shifting or reducing customer energy usage (e.g., demand response programs). In other words, DERs can affect either the supply or demand of energy, but are usually located behind the customer meter; and thus to the larger grid may be viewed solely as modifying customer load.

DERs have traditionally been “visible” to CAISO as load reduction resources, where their deployment reduces the overall system demand from an LSE’s territory. For example, behind-the-meter (BTM) rooftop solar reducing the need for alternative resources during the sunniest parts of the day and year. As growth in DERs continues, these resources seek greater participation in the CAISO market by not only modifying load but also seeking to export their power—often in aggregate—to be compensated for that export. The CAISO tariff does allow aggregations of DERs to participate in its markets.^[1] However, CAISO’s most recent deliverability assessment for distributed generation showed scant amounts of DER selected in LSE resource portfolios, and thus hardly any was studied.^[2] The recently established Emergency Load Reduction Program at the CPUC creates a test case for some of these DER challenges, by compensating BTM generation for exported energy under emergency conditions.^[3]

Resource Adequacy (RA) – The RA process, overseen by the CPUC and CAISO, is designed to identify resources needed to ensure reliability. Following the California energy crisis of 2000-01, the California Legislature enacted AB 380 (Nunez, Chapter 367, Statutes of 2005) to prevent future incidents of widespread blackouts and rolling brownouts due to lack of electricity. This statute established the RA program at the CPUC, which must work in consultation with the CAISO to establish RA requirements for all LSEs. The current RA program consists of system, local, and flexible requirements for each month of a compliance year. System requirements are determined for each LSE based on the CEC’s integrated energy policy report (IEPR) electricity forecast plus a 15% planning reserve margin.^[4] Local requirements are determined based on an annual CAISO study using a 1-10 (once in ten years) weather year and an N-1-1 contingency.^[5] Flexible requirements are based on an annual CAISO study that currently looks at the largest three-hour ramp for each month needed to run the system reliably. In October, LSEs must demonstrate that they have procured 90% of their system RA obligations for the five summer months (May-September) of the following year, as well as 100% of their local requirements, and 90% of their flexible requirements for each month of the coming compliance year. There is an additional monthly reporting requirement for RA, where LSEs must demonstrate they have procured 100% of their monthly system and flexible RA obligation.

The RA market has experienced significant constraint recently, largely driven by resource retirements across the western U.S. as well as extreme weather events causing California energy agencies to increase RA obligations for LSEs, such as the PRM adjusting from 15% to an “effective” 20-22.5% for the three large IOUs for summers 2022 and 2023.^[6] These changes have led to a market rush, practically at any cost, to buy resources needed to meet RA obligations for the next few summers. Energy sellers have seemingly taken note. As shown in Figures 1 and 2 below, both system and local RA prices have been increasing significantly over the last few years, and are projected to be even higher for the coming summers.

Figure 1: Weighted Average Price of Figure 2: Weighted Average Prices for

System RA ($/kW-month)^[7] Local RA ($/kW-month)^[8]

These RA requirements, matched with utilities’ desire to meet them and the resultant highly lucrative prices for RA, are critical factors in determining the market values of individual resources, to the point that the expectation that a resource would not be counted toward RA may severely disincentivize its development.

The IEPR (demand forecast) – Alongside other planning guidance focusing on energy generation needs in both the mid- and long-term, the CEC conducts an IEPR to forecast all aspects of energy industry supply, production, transportation, delivery, distribution, demand, and pricing. The demand forecast the CEC adopts in its IEPR informs the generation planning processes at the CPUC, as the supply provided by the CPUC analysis (IRP and RA) must match the customer demand (IEPR) provided by the CEC.

The CEC is responsible for producing both statewide and LSE-specific demand forecasts to inform both policy and grid operations. LSEs annually submit their own year ahead peak demand forecast to the CEC, including any relevant DER load modifiers that lower their peak demand. The CEC team reviews LSE forecasts, compares them to their own forecasts, and makes adjustments to resolve discrepancies between the two. The load reductions from a LSE program are then incorporated into the CEC's final adjusted forecast. The CPUC uses the CEC’s forecasts to determine individual LSE RA obligations. 

As a consequence, LSEs have – in effect – two venues to meet or adjust their RA requirements, utilizing either supply- or demand-side resources. The supply-side involves generation resources that are shown to the CPUC during the LSE’s annual and monthly RA reports. The demand-side involves load modifying resources that are annually shown to the CEC as a reduction in the LSE’s peak demand forecast, which the CEC then uses to adjust its final demand forecast of that LSE – and thus reducing that LSE’s RA obligation.

COMMENTS:

1. Author’s Statement. According to the author, “AB 2891 would give retail providers more options to contribute toward grid reliability and to better manage energy procurement costs for customers. This would help create a downward pressure on rates for all customers. By establishing a set of upfront technical requirements and load modification protocols, the bill would result in a set of quality assurance standards for any load-modifying technologies to shift or reduce the state’s resource adequacy needs during the most expensive hours. Distributed energy providers would have more clarity on what functionalities they must offer retail providers to produce cost-saving value; retail providers would have assurances that would reduce the cost of serving customers; and energy planning agencies would have greater confidence in the reliability performance of aggregated distributed energy resources.”
2. Chicken or the Egg? As noted above, the state’s RA program exists to ensure enough resources are available each month to serve customer demand. Changing either the volume of resources supplying the market or the volume of customer demand will impact the needed RA. The RA market has experienced significant constraint recently, largely driven by resource retirements across the western U.S. as well as extreme weather events and ever-increasing RA obligations for the state’s LSEs.^[9] These actions have affected the supply-side of the RA market.

For the past decade, demand has been relatively flat in California. However, the demand-side is expected to change over the coming decades due to increased electrification of transportation and housing, as well as climate events such as heatwaves. In fact, one of the contributing factors of recent summer shortfalls was a mismatch between the forecasted IEPR demand and the actual demand.^[10]

As a result, the State has established a number load reduction programs over the past few years to help reduce customer demand during emergencies.^[11] However, this bill’s author suggests these demand response programs have done little to reduce the pressures on the supply-side, and thus alleviate energy affordability. The author offers the CPUC’s Emergency Load Reduction Program (ELRP) as an example, which compensates participants at the premium rate of $1 per kilowatt-hour (kWh).^[12] This compensation is double that of PG&E’s default residential rate, at $0.51 per kWh for baseline customers;^[13] in other words, it is quite an expensive program. In establishing the program, the CPUC explicitly excluded the ELRP resources from being counted toward system RA. ^[14] Instead, LSEs must procure the same amount of RA as would be needed as if the ELRP didn’t exist, essentially erasing any savings to the supply-side procurement obligations of the LSEs. The CPUC notes its view of the ELRP as “an insurance policy made available during emergency conditions to supplement the reliability already provided by the RA program,”^[15] rather than a demand-side resource meant to contribute fully to the RA program. In this way, ELRP treats aggregated load modification resources in the traditional way: as emergency resources. This bill seeks to instead make clear the obligations of an aggregator if an LSE is to proactively use these resources as a demand modifier.

1. Need for bill. As noted above, there exists a process at the CEC to reduce RA procurement obligations by utilizing demand-side resources. However, the author notes this process has seen limited participation by LSEs due to a lag between deploying technologies and when the LSE’s demand forecast is reduced. Supporters for this bill notes this creates a financial risk for LSEs, where they have to purchase supply-side RA resources to cover a demand that is actually being reduced by demand-side resources; the reporting between the IEPR and RA programs is just delayed.

This bill requires the CEC to adopt a set of requirements to enable LSEs to use these demand-side resources to reduce their IEPR demand forecast, and subsequently their RA obligations. However, caution may be in order, as these demand-side resources can vary greatly in their design – from virtual power plants to aggregated residential thermostats – and vary in their visibility to the state agencies and CAISO market. It is essential for resources counted as RA to show up when expected. This bill seems to recognize this caution by not mandating adoption of these technologies, but rather enabling state agencies and the CAISO to set all the requirements and protocols and requiring any deployed technology to be deemed effective and reliable by the state agencies and CAISO.

1. Prior Legislation.

AB 1623 (Muratsuchi, 2023) required the CPUC, on or before June 30, 2024, and as part of a new or existing proceeding, to revise the net qualifying capacity and effective flexible capacity methodologies for energy storage resources. Status: Died – Assembly Committee on Appropriations.

SB 1432 (Hueso, 2022) made changes to the RA program and required the CPUC to develop a pilot program for aggregated customer-sited DER to assess the value of energy exports from those resources for purposes of fulfilling the requirements of the RA program. Status: Vetoed by the Governor, who cited “threshold issues” needing to be addressed before DER could contribute reliably to RA.

SB 49 (Skinner) expanded the CEC’s appliance energy efficiency authority by requiring the CEC develop standards for appliances to facilitate the deployment of flexible demand technologies. The standards must be based on the ability of an appliance’s operations to be scheduled, shifted, or curtailed to reduce GHG emissions associated with electricity generation. Status: Chapter 697, Statutes of 2019.

REGISTERED SUPPORT / OPPOSITION:

Support

Advanced Energy United
California Efficiency + Demand Management Council
California Solar & Storage Association
Enphase Energy
NRG Energy
Recurve Energy
San Diego Community Power
Vivint Home Smart

Opposition

None on file.

Analysis Prepared by: Laura Shybut / U. & E. / (916) 319-2083

1. ISO Tariff updated for Distributed energy resource provider, http://www.caiso.com/participate/Pages/DistributedEnergyResourceProvider/Default.aspx ↑

2. CAISO, “2022-2023 DG Deliverability Assessment Results” Resource Adequacy Deliverability for Distributed Generation, February 17, 2023. http://www.caiso.com/Documents/2022-2023-Deliverability-Distributed-Generation-Study-Results-Report.pdf ↑

3. Customers with DERs that can generate energy (BTM solar+storage, EVs, cogeneration, etc) that have permission to export are eligible to participate. https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/demand-response-dr/emergency-load-reduction-program#:~:text=What%20is%20the%20Emergency%20Load,periods%20of%20electrical%20grid%20emergencies ↑

4. The CPUC has recently adopted changes to RA, including increasing the planning reserve margin from 15% to 17.5% and in some cases to 20-22%. ↑

5. N-1-1 Contingency: A sequence of events consisting of the initial loss of a single generator or transmission component (Primary Contingency), followed by system adjustments, followed by another loss of a single generator, or transmission component (Secondary Contingency). ↑

6. D. 21-12-015, CPUC, Phase 2 Decision Directing PG&E, SCE, and SDG&E to Take Actions to Prepare for Potential Extreme Weather in the Summers of 2022 and 2023, R. 20-11-003, December 2, 2021. ↑

7. Figure 4, pg. 29, CPUC, 2021 Resource Adequacy Report, April 2023; https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/resource-adequacy-homepage/2021_ra_report_040523.pdf ↑

8. Figure 5, pg. 31, 2021 Resource Adequacy Report, Ibid. ↑

9. D. 21-12-015, CPUC, Phase 2 Decision Directing PG&E, SCE, and SDG&E to Take Actions to Prepare for Potential Extreme Weather in the Summers of 2022 and 2023, R. 20-11-003, December 2, 2021. ↑

10. Pg. 39-40, CAISO, FINAL Root Cause Analysis: Mid-August 2020 Extreme Heat Wave; January 13, 2021. ↑

11. CPUC Decision D.21-03-056 Attachment Page 22 at https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M428/K821/428821668.PDF ↑

12. Ibid. committed $201.7 million in ratepayer funds. https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M373/K973/373973362.PDF ↑

13. See PG&E residential TOU rate schedule comparison at https://www.pge.com/content/dam/pge/docs/account/rate-plans/residential-electric-rate-plan-pricing.pdf ↑

14. See page 2 of Attachment to D.21-12-015 at https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M428/K821/428821668.PDF ↑

15. Pg. 20, D. 21-03-056 ↑