Monday Study – California’s Plan For Distributed Resources In Power Markets
Advanced Strategies For Demand Flexibility Management And Customer DER Compensation
Energy Division Staff, June 22, 2022 (California Public Utilities Commission)
Need for a Fresh Approach to Demand Flexibility
California’s electricity system is undergoing rapid transformation on the pathway to 100% renewable power, with the expected high penetration of renewables, electrification of buildings and transportation, and deployment of behind-the-meter (BTM) distributed energy resources (DERs). Many stakeholders are concerned about potential adverse impacts of these trends on the State’s power grid (see section 3.1) and agree that going forward it is essential for California to leverage demand response (also referred to as load or demand flexibility management) as a critical resource in integrated resource planning (IRP) to meet the State’s aggressive GHG emissions reduction targets.
Demand Response (DR) continues to play an important role in achieving California’s clean energy goals. The California Public Utilities Commission (CPUC) has a long track record in developing policies to promote DR. These policies can be broadly grouped into two main strategies: 1) CAISO market-integrated DR programs(also referred to as supply-side DR (SSDR), and 2) load-modifying DR (LMDR) based on a range of time-differentiated rates or utility managed load reduction programs.
Fortunately, some of the trends noted earlier, specifically the electrification of transportation and buildings and growth in customer deployment of BTM DERs, present significant demand-side potential (see section 3.2) to address the challenges associated with the State’s energy transformation, help integrate renewables, reduce GHG emissions, improve system reliability, and reduce or minimize cost of service. These trends are driving a substantial and rapid increase in electric end uses that are capable of being flexible in terms of when energy could be consumed or generated. Some stakeholders suggest that the flexible demand/generation nature of the electrified end uses and BTM DERs, if aggregated, coordinated, and shaped properly at scale (that is, largescale demand flexibility management), could play a major role in solving the anticipated challenges to the State’s electricity system.
However, the CPUC’s current approach to demand response (SSDR and LMDR) is complex and may not be well positioned to address emerging grid needs. Additionally, current policies may have become a barrier to scaling demand management solutions to the levels necessary to support California’s clean energy goals.
With the experience gained through the CPUC’s efforts to integrate SSDR programs with CAISO markets, stakeholders have noted concerns (see section 3.3.1) about the high degree of complexity in SSDR program implementation, high level of confusion, high transaction costs, and limited flexibility. With respect to LMDR programs, other stakeholders have suggested that a comprehensive review of the underlying electricity rates policies is needed to address a range of serious issues (see section 3.3.2), including the proliferation of “boutique” technology-specific rates (e.g., for solar, electric vehicles, and storage), incentives for uneconomical load management, nonequitable fixed cost recovery and related cost shifts, and inability to monetize DER capabilities. In several proceedings, parties have provided testimony to encourage the adoption of rates based on real-time grid conditions to provide both customer bill benefits and system cost benefits.
If the State is to fully capture the significant demand-side potential enabled by electrification and customer DERs, a key “chicken-and-egg” problem related to demand response and retail rates must be resolved. For large numbers of customers (both residential and commercial) to adopt flexible demand management solutions at the scale necessary to support the future electricity grid, automation technologies for controlling various end-uses and DERs must be inexpensive and ubiquitous. For this to be true, there must exist a robust and stable policy pathway that is standardized, easy to implement, and allows the industry to develop low-cost, flexible demand management capabilities and integrate them into smart end-use devices and DERs by default for use by all customer classes.
This Energy Division (ED) white paper proposes that the CPUC seek to significantly improve demand-side resource management through a more synergistic, scalable, and integrated demand response and retail rate strategy that can effectively address the emerging grid issues and opportunities associated with the growth of renewables, building and transportation electrification, and behind-the-meter DER deployment by electricity customers. The paper proposes a comprehensive vision, guiding principles, and a policy roadmap to drive the development of a universal approach to flexible demand and DER management and compensation solutions available to all customers, initially on an opt-in basis, 1 throughout the state. Accordingly, ED Staff recommends that the CPUC initiate a Rulemaking, as referenced in the DER Action Plan 2.0 as Track 1, 2 to take up this paper’s proposal.
This paper recommends that the CPUC establish an ambitious policy vision: To achieve widespread customer adoption of low-cost, advanced flexible demand and DER management and compensation solutions across the state (and beyond) via a unified, universally accessible, dynamic economic signal. Policies in pursuit of this vision should help in addressing the following issues associated with the ongoing transformation of the electricity grid:
1. Mitigate reliability and grid integration challenges associated with high growth in renewables, end-use electrification, and behind-the-meter DER deployment by customers,
2. Minimize short- and long-term cost of service associated with the rapidly evolving electricity infrastructure, and
3. Fully leverage capabilities of customer DERs to address grid needs while providing fair compensation for grid services provided by the DERs.
In support of this policy vision, this paper proposes that the CPUC pursue the development of a policy roadmap or framework that should achieve the following objectives:
1. Enhances scalability via standardized, universal mechanisms to enable demand flexibility management.
2. Makes the value of energy and capacity services provided by the grid or DERs more transparent and based on real-time grid conditions.
3. Seamlessly accommodates different and evolving pricing policies of utility distribution companies (UDCs) and load serving entities (LSEs), both inside and outside the CPUC jurisdiction.
4. Ensures full recovery of costs associated with the infrastructure for electricity generation and delivery, consistent with cost-causation principles and avoidance of cost-shifts.
5. Offers options to all customers for bill and demand management choices, protection against bill volatility, and forward planning of energy usage or generation.
6. Encourages investment in BTM DERs, including vehicle-to-grid integration and microgrids, without cost-shifts to non-participating customers.
In support of and consistent with the above vision statement and guiding objectives, this paper describes a comprehensive policy roadmap, the centerpiece of which is a unified, universallyaccessible, dynamic, economic retail electricity price signal. The roadmap consists of a three-pillar structure addressing 1) the presentation of electricity prices to customers and smart devices, 2) electricity rate reform, and 3) customer options to optimize energy consumption and generation. For convenience, this whitepaper refers to the roadmap is as “CalFUSE” (California Flexible Unified Signal for Energy). 3 The proposed roadmap consists of six key policy elements, all intended to be available on an opt-in basis as follows:
ELEMENT 1: DEVELOP STANDARDIZED, UNIVERSAL ACCESS TO THE CURRENT ELECTRICITY PRICE
• Statewide, web-based portal to provide current electricity price specific to each customer.
• Accommodate different pricing inputs from UDCs and LSEs
• Engage tech / industry ecosystem in educating customers and developing energy management solutions.
ELEMENT 2: INTRODUCE DYNAMIC ELECTRICITY PRICES BASED ON REAL-TIME WHOLESALE ENERGY COST
• Real-time pricing tied to CAISO locational marginal price, reflecting the marginal cost of energy.
ELEMENT 3: MODIFY ELECTRICITY PRICES TO INCORPORATE DYNAMIC CAPACITY CHARGES BASED ON REAL-TIME GRID UTILIZATION
• Capacity fixed cost recovery linked to the degree of congestion relative to the available infrastructure capacity for electricity generation and delivery.
• Implements the design principle that fixed cost recovery should be higher when the system utilization is higher.
• Shift fixed cost recovery onto load driving capacity upgrades based on marginal cost of adding incremental capacity, while ensuring collection of approved revenue requirements and minimizing unintentional cost-shifts.
ELEMENT 4: TRANSITION TO BI-DIRECTIONAL ELECTRICITY PRICES
• Customers import or export energy at the same dynamic composite price.
• Fair, transparent, and rational compensation for grid services provided by customer owned DERs linked to avoided marginal costs.
ELEMENT 5: OFFER A SUBSCRIPTION OPTION BASED ON CUSTOMERSPECIFIC LOAD SHAPES
• Customers subscribe to a monthly load shape based on historic usage (and the associated hourly energy quantities) at a pre-determined monthly price.
• Protect against bill and revenue collection volatility, while still encouraging opportunistic, beneficial load shift.
• Ease customer transition from current rates to dynamic rate.
ELEMENT 6: ENABLE TRANSACTIVE FEATURES ALLOWING LOCK IN OF FUTURE ELECTRICITY PRICES
• Customer option to commit to future import or export of energy at pre-determined prices (based on forecasts) to control and optimize energy use or generation.
• Improved visibility for planning and operations (for CAISO, UDCs/LSEs, and customers & their service providers).
Structure of This Paper
The remainder of this paper is organized as follows: Chapter 2 summarizes the procedural background of policies in support of providing access to dynamic retail rates to customers and achieving greater demand/load flexibility.
Chapter 3 presents the problem statement in detail and outlines the need for a more effective, synergistic, and scalable demand response and retail rate strategy to better address the emerging issues associated with the transformation of California’s electricity system.
Chapter 4 presents the staff proposal describing the vision, guiding objectives, and the policy roadmap focused on implementing a flexible, unified signal for energy in California (CalFUSE).
Chapter 5 discusses the potential impacts of implementing the CalFUSE framework.
Chapter 6 examines the learnings from various pilots and programs around the country that have implemented dynamic retail rates. Chapter 7 concludes the white paper and offers Staff’s recommendations for next steps in the implementation of a Statewide demand flexibility roadmap. Chapter 8 (Appendix) summarizes the DER Action Plan 2.0 and stakeholder feedback in response to ED Staff’s proposal previewed at the May 25, 2021, demand flexibility management workshop…