On March 1, 2016, Southern California Gas Company (SCG) and San Diego Gas & Electric Company (SDG&E) submitted a Joint Motion to the CPUC proposing daily balancing requirements in response to the abrupt reduction in its gas storage capacity at its Aliso Canyon facility. As a result of this Joint Motion, the CAISO initiated an expedited stakeholder initiative to evaluate market mechanisms or other tools the CAISO could provide to its resource mix to support reliability and ensure markets are not adversely impacted.

This is important to the CAISO and to gas-fired generators that seek reasonable representations of gas costs in their start-up and commitment costs. CESA is in 'monitor only' mode because energy storage is unaffected on the most part by this set of rules.

Phase 1

On May 4, 2016, the CAISO Board approved the Revised Draft Final Proposal that better aligns CAISO markets with current gas system conditions and reserves transmission capacity as necessary to take into consideration gas or electric system conditions. These temporary provisions include:

Publishing 2 day-ahead TD-2) RUC schedules to Scheduling Coordinators
Improving DAM gas-price index using an approximation of next day gas index
Adjusting the RTM gas-price index to include a scalar on the next day gas index
Including after-the-fact cost recovery filing right opportunity to seek energy costs incurred above mitigated price
Ability to enforce gas constraints for either capacity or imbalance limitations

On May 24, 2016, the CAISO activated Phase 1 of market mechanism changes, including timing of re-bidding commitment costs.

On June 1, 2016, FERC conditionally accepted the CAISO’s gas-electric coordination Tariff Revisions.

According to the Q3 Market Issues & Performance Report, the Aliso Canyon gas-electric coordination measures did not have a significant impact on market performance.

Phase 2

On July 6, 2016, the CAISO activated Phase 2 but filed a Petition with FERC to delay the use of Intercontinental Exchange (ICE) gas prices to calculate commitment and default energy bids for affected resources in the SCG and SDG&E systems, pending confirmation that the gas prices conform to the FERC's policy statements on gas prices.

On August 4, 2016, the FERC granted the CAISO's request. All other Phase 2 changes were implemented as scheduled.

On September 22, 2016, a Draft Final Proposal was published that proposed to extend all temporary provisions without refinement because the 2016 Winter Assessment by the Joint Agencies revealed that there are still risks of capacity shortage with the limited operability of Aliso Canyon. The current Phase 1 measures are set to expire on November 30, but the CAISO intends to extend these provisions through the end of November 2017.

Phase 3

On June 2, 2017, the CAISO issued a Straw Proposal that launched Phase 3 of the initiative. The Straw Proposal proposes to extend the temporary market and operational tools currently in place so that they remain in effect beyond November 30, 2017. Because the market constraint limiting the maximum gas burn of a group of generators has proven to be effective, the CAISO proposes to make it a permanent operational tool that can be used throughout the CAISO andthe Energy Imbalance Market areas. The CAISO also proposes to make permanent the mitigation measures that accompany the natural gas constraint authority. These accompanying measures include the ability to deem transmission constraints uncompetitive when natural gas constraint is enforced and the ability to suspend convergence bidding when it determines constraint is adversely affecting market efficiency.

On August 4, 2017, the CAISO will adjusted the scalars to 175% and 125% for commitment and default energy calculation because of gas curtailments in the Southern California area due to an unplanned pipeline outage. As a part of this initiative, the CAISO applied a scalar to the gas price index used to calculate both proxy commitment costs and cost-based default energy bids in the real-time market. The gas price index used in the commitment cost proxy cost calculation was set to scale the gas commodity price to 175% of the gas commodity price. The gas price index used in the default energy bid calculation was set to scale the gas commodity price to 125% of the gas commodity price. The CAISO has since re-evaluated the need for the gas price scalars. Effective as of trade date August 1, 2017, the scalars applied on the gas commodity price to calculate both commitment costs and default energy bids were lowered to zero until the CAISO determines they are needed based on system conditions.

On October 26, 2017, the CAISO re-adjusted the commitment and default energy scalars back to 100% with conditions in Southern California returning to normal, after several days of high temperatures and gas curtailments. The CAISO will continue to re-evaluate on an event-by-event basis the need for gas price scalars adjustments.

Summer Loads & Resource Assessments

On May 11, 2017, the CAISO issued its 2017 Summer Loads & Resources Assessment that found that it has adequate resources available to handle summer 2017 power use but limitations on gas supply from the Aliso Canyon Gas Storage Facility may present risks in local areas in Southern California in the event of extreme weather. In an assessment of 2,000 different weather and load conditions, the CAISO has an operating reserve margin of 19.5% under a “normal” year (greater than the 15% required by the CPUC).

The analysis also showed the following:

The summer peak, which accounts for expected rooftop PV growth, is projected to be about 46,877 MW, which reflects a modest 0.6% demand growth from 2016
About 52,785 MW of net qualifying capacity will be available this summer
About 3,090 MW of new resources have been added since last summer (June 2016 to June 2017), including about 2,302 MW of solar, 699 MW of natural gas and 80 MW of battery energy storage
Above-average hydroelectricity will be available for use after a heavy 2016-2017 snow and rainy season, translating to statewide average water content measuring, as of April 28, at 158% of the April 1 average

However, since this is a system assessment, not one on potential local capacity issues, this report may not reflect all of the potential risks associated with the Aliso Canyon facility’s restrictions.

• Review of Reliability Must-Run (RMR) and Capacity Procurement Mechanism (CPM) Initiative (Stakeholder Process)

Background

This initiative will review the RMR tariff, agreement and process, and will seek to clarify and align the use of RMR procurement versus backstop procurement under the CPM tariff. The initiative is planned to proceed in two phases. The first phase will have a limited scope and focus on developing a must-offer obligation for RMR units. The second phase will have a broader scope and address potential additional refinements to the RMR tariff, agreement and process, and strive to unify RMR and CPM procurement under a single procurement framework.

CESA is focused on this initiative to the degree that any reforms to backstop procurement processes may create undue reliance on them instead of more forward-looking planning frameworks, like the CPUC’s RA program. As more gas plants become uneconomic, CESA will need to monitor this initiative to ensure ratepayer benefits and savings from considering energy storage resources are taken into account instead of executing potentially costly RMR agreements to keep gas plants online.

Issue Paper & Straw Proposal

On January 30, 2018, a stakeholder meeting was held to discuss the Issue Paper and Straw Proposal for this new initiative. The scope of the initiative is proposed as focusing Phase 1 on making RMR Condition 1 and 2 units subject to a must offer obligation (MOO) for energy and ancillary services, since RMR resources currently do not include a MOO similar to RA resources and thus lead to RMR resources being barred from participating in the CAISO markets during many hours. The Department of Market Monitoring (DMM) requested this issue be in scope due to the market price distortions and economic inefficiency of not having an MOO for RMR resources. The CAISO plans to seek Board approval of its Phase 1 proposal at the May 16-17 Board of Governors meeting. Meanwhile, Phase 2 will run in parallel and will focus on the following key clarifications and/or reforms to the CAISO’s backstop procurement mechanisms:

Clarify when RMR is used versus CPM procurement.
Explore whether RMR and CPM can be merged.
Review allowed rate of return on capital (currently set at 12.5%) for RMR and CPM.
Explore expanding RMR and CPM tariff authority.
Consider whether both RMR Condition 1 and 2 units are needed.
Review cost allocation of RMR and CPM.
Expand RMR designation authority to include flexibility needs.

Stakeholders were split on whether RMR units should have a must-offer obligation, with those opposed (IEP, NRG, PG&E, and WPTF) to this Phase 1 proposal arguing for the need for further study, more detailed plans, and/or a focus on RA improvements and broader RA reforms.

On March 13, 2018, a Draft Final Proposal was released that finalized the scope of this initiative to take place across two phases (see also stakeholder meeting). Phase 1 recommendations are included in the draft final proposal, which, among many things, proposes that a must-offer obligation for energy and ancillary services will be added for RMR units. Condition 1 RMR units will be required to submit energy and ancillary service market-based bids up to the full RMR capacity during all hours that the unit is physically available, while Condition 2 RMR units will be required to submit energy and ancillary service cost-based bids during all hours that the unit is physically available. Otherwise, the CAISO will submit cost-based bids up to RMR capacity, similar to how it approaches RA units that fail to submit bids. The CAISO-generated energy bids will include startup costs, minimum load costs, and energy costs, while CAISO-generated ancillary service bids will be priced at $0/MW per hour. The current penalties in the RMR agreement (Section 8.5) will be used to incent performance and the CAISO may impose a 25% reduction of daily Annual Fixed Revenue Requirement if bidding requirements are not fulfilled. The CAISO aims to ensure that RMR units function equivalently to RA units. Key changes from the straw proposal include the following:

Revised Condition 2 RMR must-offer obligation to state the Scheduling Coordinator (SC) has primary responsibility for submitted bids and not the CAISO
Provided detail on components of bids submitted by SC and CAISO if the SC does not submit bids (for both Condition 1 and 2 units)
Added information on implementation plan
Clarified pricing of AS bids by SC and CAISO
If the CAISO submits bids to meet must-offer obligation, residual unit commitment (RUC) availability bids for full RMR capacity will be submitted at $0

The Phase 1 proposal also includes recommendations (as requested by stakeholders) to provide notifications to stakeholders when a resource informs the CAISO that it may retire. If a resource owner sends such a notice to the CAISO, this information (including affected unit and requested retirement date) will no longer be considered confidential and will be sent to other market participants.

On April 12, 2018, FERC issued an Order that rejected the CAISO’s proposed tariff revisions to its CPM to eliminate the current market-based compensation methodology in favor of a cost-based methodology. FERC determined that the resource-specific cost-based compensation offered by CAISO under the risk-of-retirement program is likely to exceed what a resource could earn under a bilateral RA contract. Stakeholders commented that adding a spring request window could distort prices and interfere with the bilateral RA process. FERC concluded that, without more comprehensive reform, any incremental improvement that may result from CAISO’s proposed revisions are outweighed by the potential for deleterious effects on the competitiveness of capacity procurement under CPUC’s RA program. As a result, the CAISO determined that it will not take any Phase 1 items to the CAISO Board in May 2018 as previously planned. Phase 1 items were included in Phase 2 of this initiative instead.

On May 30, 2018, a working group meeting was held to discuss the scope and approach for Phase 2 of the initiative, which as noted, will include Phase 1 items as well. During the meeting, the CAISO provided more overview of the current backstop processes, where the CAISO generally tries to procure through the CPM before resorting to the RMR agreement but resources going offline or intending to retire may front-run both the CPM and RA processes. The CAISO also said that it will now notify stakeholders when it receives a notice that resource plans to retire – a new policy that will be implemented by July 1, 2018. The meeting also featured presentations by SCE, PG&E, and Calpine. SCE recommended that the CAISO institute must-offer obligations for RMR resources consistent with RA resources and accordingly make available the RA attributes of RMR resources. PG&E, meanwhile, called for general updates to the RMR agreements to reflect the must-offer obligations and RA attributes of RMR resources as well as the consideration of transmission solutions to address any local capacity deficiencies. Finally, Calpine proposed a suite of incremental changes that would require annual RA showings and deficiency auctions in the summer before backstop procurement would be initiated in the fall. The CAISO proposed March 2019 as the target date to take its RMR and CPM proposal to the CAISO Board. Given contentiousness and potentially litigious nature of making any changes to the RMR and CPM tariffs, the CAISO also asked stakeholders if a settlement approach should be used to reach agreement and institute changes.

On June 27, 2018, a Straw Proposal was issued (see also stakeholder meeting) that clarified how the CPM will be used to backstop the RA program with voluntary, shorter-term procurement based on bids submitted into the CPM auction (or going-forward fixed costs [GFFCs] if a bid is not submitted), while the RMR will be used to address resource retirements and special reliability needs (e.g., voltage support, flexible needs) with mandatory, longer-term procurement based on cost-of-service. Specifically, related to these two procurement mechanisms, the Straw Proposal proposes the following:

Change CPM compensation where resource can file for compensation based on GFFCs of its unit using same cost categories and 20% cost adder used for CPM reference unit and keep market revenues
Delete references in CPM tariff on existing authority to designate a resource needed for "Year 2" with a bridge in Year 1 and add that same authority to the CAISO's RMR tariff to allow consideration of need for Years 2 and 3
Clarify authority to designate RMR for System or Flexible RA needs
Update allowed rate of return in RMR tariff by pursuing one of six potential options (currently at 12.25%)
Set default cost-of-service RMR agreement with a MOO where resource will have all of its cost of service paid and must credit back market revenues earned above its cost of service (same as Phase 1 Draft Final Proposal)
Require submission of a retirement letter to be considered for an RMR designation
Remove Ancillary Service bid insufficiency test and revise dispatch provisions for RMR units

There are a few areas that still need to be worked out. First, the CAISO proposed to update the allowed rate of return in RMR tariff by pursuing one of six potential options. The current rate of return is set at 12.25% and has not changed in many years, though the effective rate of return has decreased in "post-tax" terms. Several options include benchmarking the rate of return, having an independent expert develop a formula for this rate, requiring market participants to propose and justify a rate of return, or using a blended rate from recent transmission projects. Second, the details of how all RMR resources being subject to the RAAIM need to be worked out. The CAISO could establish that RMR resources have a greater performance obligation than RA or CPM capacity, and they were considering having RMR resources only subject to the RAAIM. Third, in light of load migration, the CAISO was asked by stakeholders to review the annual CPM cost allocation mechanism. The current policy is to use year-ahead load forecasts for local collective deficiency CPM costs and credits allocation, but alternative proposals include doing this allocation prior to each RA month or after each month in a "true up" based on true load.

On July 5, 2018, at the request of stakeholders, the CAISO established a new policy to provide an early heads up of potential CAISO backstop procurement designations to increase transparency. The changes were reflected in the Generator Management BPM. Thus, if a resource owner sends a notice of intent to retire or "mothball" (i.e., make unavailable on a permanent or long-term basis) to the CAISO that qualifies under this policy, the information will not be considered confidential.

On July 10, 2018, the CAISO held a stakeholder call to discuss the proposed amendment to the pro forma RMR agreement reflecting the changes above. The new interim pro forma RMR agreement provides the CAISO with additional (interim) authority to terminate the RMR contract and immediately redesignate resources for RMR service. Under the existing RMR contract, the CAISO may not decline to extend the term of the contract and immediately redesignate unless special circumstances apply. The CAISO clarified that these changes will not affect existing RMR agreements.

On July 26, 2018, the CAISO Board approved two new RMR designations for the Ellwood and Ormond Beach generating stations and limited, interim modifications to RMR agreements to enable the CAISO to terminate current agreements and re-designate the units based on a comprehensive agreement.

On August 14, 2018, a stakeholder call was held to discuss the revised draft tariff language of the pro forma RMR agreement. In doing so, the CAISO has attained some additional flexibility to maintain grid reliability through its expanded backstop procurement authority.

On August 2, 2018, the CAISO held a public stakeholder call to discuss its intention to procure capacity using its CPM authority, which can be exercised under the “significant event” provisions of the tariff. The CAISO viewed the release of an alternate forecast from the CEC for the RA program, which was revised upward to 1,247 MW for September 2018, to be a “significant event” (pursuant to CAISO Tariff Section 43.2.4). The intent was to procure CPM capacity starting to cover the 1,247-MW forecast amount plus the associated planning reserve margin through the CPM intra-monthly competitive solicitation process. The Significant Event CPM designations would have an initial term of 30 days, commencing September 1, 2018.

On August 27, 2018, a working group meeting was held to discuss some updates to the RMR settlement and invoicing process, bidding rules for RMR and CPM units, and certain changes under consideration to the pro forma agreements. The CAISO also responded to stakeholder’s comments and agreed to support the allocation of System and Flexible RA credits from RMR resources, so long as the resources have an approved EFC value, fulfill Flexible RA MOO requirements, and are subject to RAAIM during Flexible category hours. However, several stakeholders including the CPUC, ORA, and IOUs did not support the CAISO extending its authority to designate resources as RMR to Years 2 and 3, which was viewed as bypassing or undermining the bilateral RA market. The CAISO staff also discussed their narrowing down of various options considered for changing the compensation for CPM and RMR resources. First, the CAISO proposes that CPM resources should only be able to file for going-forward fixed cost (GFFC) compensation using cost categories and a 20% adder used for the soft-offer cap reference unit – thus allowing CPM resources to keep all market revenues earned and no longer mixing GFFC and cost-of-service methodologies. Second, the CAISO proposes for RMR resources to either retain the current 12.25% rate of return, update the 12.25% rate of return to a new 10.5% fixed rate based on changes to the tax code and PTOs rate of return, or have resources propose a rate of return in FERC filings for each RMR unit. Finally, feedback from stakeholders on the proposal to make RMR resources subject to a MOO and RAAIM were discussed. In general, the IPP parties expressed that forcing Condition 2 units to bid cost-based offers at all hours and be subject to a MOO may impact energy and ancillary service market prices and. They also generally did not support an RAAIM for RMR units because they must self-schedule, have no ability to substitute, and should not be subject to making offers in all hours, which is contrary to Condition 2 expectations.

On September 19, 2018, the Revised Straw Proposal was posted, and a stakeholder meeting followed on September 27. Since the Straw Proposal, the CAISO clarified its processes for CPM and RMR designations. If a resource declines a CPM designation, the CAISO will offer the next most effective resource a CPM designation. In the event no other resources are available, the CAISO will not go directly to offering the resource an RMR designation but instead will inform the resource that the resource must submit a formal retirement notice if the resource wants to be considered for an RMR designation. In addition, to address concerns of excessive compensation, the CAISO clarified that the CPM pricing formula for resources that file at FERC for CPM price above the soft-offer cap price ($75.68 kW-year) will be such that all market revenues earned above the approved cost-of-service price will be clawed back. As a result, some of the key features of how the CAISO will conduct backstop procurement is summarized below:

The CAISO will notify stakeholders when a resource that is 100 MW or greater informs the CAISO that it is planning to retire, mothball or otherwise make the entire resource unavailable, which then makes the resource eligible for RMR designation.
The CAISO has the authority to procure resources under both the RMR and CPM mechanisms, where RMR procurement will be used to address resource retirements and CPM procurement will be used to backstop the RA program.
To align RMR performance incentives and penalties with those that apply to RA and CPM resources, all CPM and RMR resources will have a similar MOO and be subject to the RAAIM mechanism, while RMR resources will be allocated Flexible RA credits.
The CAISO will move the existing ROR CPM procurement authority from the CPM tariff into the RMR tariff so that there is one procurement mechanism for ROR situations.
To address the concern that CPM compensation may be excessive for CPM prices above the soft-offer cap, the CAISO proposes to claw back all market revenues earned above the cost of service paid to such a resource.
The CAISO proposes to update the RMR pro forma agreement so that the default would be a full cost-of-service agreement where the resource would have all of its full cost-of-service paid and must credit back all market revenues earned above that amount, but at the CAISO’s discretion, and in limited circumstances, a resource may be able to negotiate an agreement where the resource is not paid all of its full cost-of-service and may keep market revenues earned above its cost-of-service.
The CAISO proposes to update the pre-tax rate of return for RMR resources so that it is based on a simple average of a blend of the rates that are being received by the three large IOUs in California.

One area that the CAISO is seeking further feedback is on whether the RMR Condition 1 should be eliminated and only offer RMR Condition 2 for eligible resources. Specifically, Condition 1 provides the possibility for a resource to recover more than full cost-of-service and may provide incentives to select cost recovery method that provides greatest revenue. Condition 1 may also be useful to help parties reach consensus when negotiating an agreement and avoid lengthy and costly rate case and there may be circumstances where this option aligns better with grid needs.

On November 1, 2018, the CAISO held a working group meeting that, among other things, summarized the comments it received in response to the Revised Straw Proposal. Many parties supported the delay of this initiative for up to six months to allow CPUC RA proceeding to play out, but the CAISO responded that the scope of the CPUC RA proceeding is sufficiently different from this initiative to allow this initiative to proceed independently and argued that these important CPM and RMR enhancements need to be put in place as soon as possible. Concerned with the insufficient notification period of resources that require backstop procurement, some parties advocated for a change of the notification period from the current 90 days to as much as 365 days, but the CAISO disagreed and said that changing the period would not resolve all the concerns around ‘front-running’ the RA program.

Specifically, around the Revised Straw Proposal, some parties proposed that the CAISO establish an economic test to prevent economic resources from receiving RMR designations and employ a mitigation test to guard against market power. However, the CAISO found that such an economic test to be inappropriate, especially as no other ISO or RTO has such a test in place, and that a FERC-approved market power mitigation test is already in place for both CPM and RMR. The CAISO also responded to stakeholders that the CPM or RMR compensation does not need to be fundamentally changed since FERC has already recently found them to be just and reasonable.

On December 12, 2018, the CAISO posted the Second Revised Straw Proposal and held a stakeholder meeting. The CAISO made some major changes to the previous Revised Straw Proposal, including some of the following:

Changes the size threshold from 100 MW to 45 MW for informing stakeholders through a market notice of an update to the announced retirement and mothball spreadsheet.
Provides a new process to mitigate the potential for front-running the RA program and provide for a longer runway for resources to make business decisions where a resource can submit its retirement notice by February 1 each year.
Eliminated the Condition 1 RMR option.
Removes the fixed rate of return that is currently in the RMR pro forma agreement and requires that resource owners specify and support a rate of return for their resource in their FERC filing.
Clarifies that the RMR pro forma agreement will specify that a resource must agree to fulfill the RA flexible capacity requirements to qualify for flexible RA credits.
Changes the pricing formula for a resource that files for a CPM price above the soft-offer cap price whereby the resource can file at FERC based on its GFFC plus a 20% adder.

On January 23, 2019, a Draft Final Proposal was published and held a stakeholder meeting.

On March 27, 2019, the CAISO Board of Governors approved the Draft Final Proposal.

On July 26, 2019, the CAISO submitted a supplemental filing to FERC to provide additional information on how the CAISO is seeking authority to use RMR agreements for System and Flexible RA capacity needs, beyond the traditional use of this backstop mechanism for Local RA needs. This filing was a follow-up to its original filing to FERC on April 22, 2019 seeking to broaden its RMR authority. The CAISO requested that FERC issue an Order by September 23 to be able to make the appropriate RMR designations for the upcoming RA year.

CPM Soft-Offer Cap Initiative (Stakeholder Process)

Background

On July 24, 2019, a Straw Proposal was published that proposed the following:

Leave the CPM soft-offer cap at the current level
Consider other options to determine a soft-offer cap in the future
Apply a 3-pivotal supplier test for 12-month designations
Allow the CAISO to file changes to CPM bids above the soft-offer cap

The CAISO staff is aiming to have a final proposal for CAISO Board vote in Spring 2020.

Reliability Services Initiative (Stakeholder Process)

Background

On May 30, 2019, an Issue Paper was published to consider updates to the CPM soft-offer cap value (see also stakeholder call on June 17, 2019), which must be done every four years in accordance with the CAISO’s tariff obligation. The current soft offer cap is $6.31/kW-month; resource owners can offer available capacity into the CAISO’s competitive solicitation process (CSP) to supply CPM capacity, if and when needed, up to this cap without further CAISO or regulatory review. The CAISO uses Going Forward Fixed Costs (GFFC) for a combined cycle resource plus 20% to calculate the soft offer cap, which was designed to be high enough to cover costs for marginal resources on the system. The representative resource initially used in the 2014 CEC report for the soft offer cap was a 550 MW resource, but the current CEC report includes analysis for a similar 700 MW combined cycle plant. The system has changed considerably since 2014 and perhaps a new resource or a blend of resource types is appropriate to set the soft offer cap going forward. The CAISO will examine 12-month CPM compensation as well to address stakeholder concerns about exercising market power.

Policy Development

On July 24, 2019, a Straw Proposal was published.

CAISO CPM & RMR Designations

Recent Activities

On September 1, 2018, the CAISO issued a Significant Event CPM designation in light of an alternate load forecast presented by CEC staff. The initial load forecast was the basis of establishing RA requirements throughout the year. This alternate forecast is not officially adopted by the CEC. Under its CPM authority, the CAISO can designate resources under CPM pursuant to the “significant event” provisions of the tariff. The CAISO viewed the release of an alternate forecast from the CEC for the RA program, which was revised upward to 1,247 MW for September 2018, to be a “significant event” (pursuant to CAISO Tariff Section 43.2.4). The CPM term is for the month of September under the tariff, subject to adjustment and the payment provisions set forth in the CPM tariff provisions. Per section 43A.3.5 of the CAISO tariff, the 30-day term may be extended for an additional 60 days if the CAISO determines that the significant event will extend beyond 30 days. The CAISO has not yet made that determination. Considering the differential in forecasts, along with the September RA showings, the CAISO concluded that it would designate 2,946 MW of additional capacity. Based on the intra-monthly Competitive Solicitation Process, the CAISO has provided CPM designations to 45 resources for that total amount of capacity.

On September 21, 2018, the CAISO notified participants that the September significant event designations were extended by 60 days and expects the significant event will last through the end of the 2018 year.

On November 12, 2018, the CAISO issued an Exceptional Dispatch CPM designation to address a non-system reliability need for 60 days. The Exceptional Dispatch for 12.46 MW was issued to address a potential thermal overload on a 60-kV line in the PG&E service territory for the next contingency event.

On July 6, 2018, the CAISO posted a list of announced retirement and mothball generating resources as part of a new process to provide stakeholders information regarding notification requests to change a resource status from active to retired, mothballed, or otherwise unavailable to the grid. “Mothballed” refers to the unit not being available for dispatch, though the unit could return to operation. By contrast, “retired” refers to the unit that will not be able to return to operation. The document contains the status of the CAISO grid reliability review, deliverability retention status, and major milestones for maintaining deliverability for these resources. Notably, the CPUC instructed SCE to negotiate bilaterally with NRG to keep the two Ormond Beach Generating Station units (1,516 MW in combined capacity) and the Ellwood Generating Station (54 MW) online to maintain short-term reliability in the Big Creek-Ventura local areas, as the CPUC and stakeholders work through RA reforms. These units provided notification on February 28, 2018 of their intention to retire with a proposed offline date of October 1, 2018 for Ormond Beach and January 1, 2019 for Ellwood. Additionally, Calpine also notified the CAISO on June 28, 2018 of its intention to retire two other plants in PG&E service territory by January 1, 2019 and May 1, 2019.

• Commitment Cost Enhancements (Stakeholder Process)

Background

A commitment cost is a concept used by the CAISO to ensure all the costs of a resource are known. The CAISO's optimization considers the costs (known as ‘commitment costs’) of turning a market resource ‘on’ and readying or ‘committing’ it to participate in its market when deciding whether to schedule a unit for energy or ancillary services.

The CAISO started this initiative because it believes that the current bidding rules do not always provide suppliers with flexibility to reflect costs and business needs, especially in light of the Energy Imbalance Market (EIM) expansion, increasing instances of constrained conditions, and growth of its fleet to include increasingly diverse supply resource. If the market overly limits supply offers, the CAISO is concerned this could undermine market efficiency and discourage participation by non-resource adequacy resources and Energy Imbalance Market resources. Efficient resource commitment by the CAISO market relies on the ability of suppliers to submit supply offers that reflect suppliers’ willingness to sell based on expectations of costs. This in turn also ensures that market participants recover these costs.

Under current rules, CAISO’s supply offers include up to four components that represent the total production cost of the unit their willingness to provide energy at a given price. In the below, the first three costs are considered "commitment cost offers" while the last one is considered an "energy offer":

Startup costs associated with bringing a unit online from being shut down into a mode it can produce energy
Transition costs associated with moving from one configuration to another for multi-stage suppliers (MSG)
Minimum load costs for operating the unit at the minimum operating level (Pmin) where a unit cannot drop below without compromising the unit’s operation including run hour costs and costs of producing energy up to Pmin
Incremental energy costs associated with producing energy above Pmin

The CAISO allows market-based energy offers limited by an offer cap and subject to a local market power mitigation test that identifies potential for uncompetitive conditions. If uncompetitive conditions are identified, the CAISO will replace market-based energy offers with the administratively calculated default energy bid (reference level for energy). For its commitment cost offers regardless of whether there is a potential for uncompetitive conditions, the CAISO applies a cost cap effectively only supporting suppliers submitting cost-based commitment cost offers subject to a validation. The validation determines if the cost offers are within a reasonable range of CAISO’s expectations of unit's costs - i.e., 125% of proxy costs. If suppliers submit cost-based commitment cost offers in excess of this range set by the cost cap, the commitment cost offers are adjusted down to the maximum allowable level.

This initiative is a continuation of the Commitment Cost Enhancements Phase 2 initiative, which focused on understanding the opportunity costs associated with committing a conventional (gas) generation unit that has a limited number of starts per year. The CAISO sought to represent these start-limitations as an opportunity cost that could be included in its commitment costs.

Phase 3 (Stakeholder Process)

In Phase 3, the CAISO will develop a methodology for calculating use-limited resource opportunity costs and creating opportunity cost adders for bidding into the CAISO market using the proxy cost option. Upon implementing these changes, the registered cost option will be eliminated and all use-limited resources will be required to use the new methodology.

CESA has worked with the CAISO to emphasize that many energy storage resources may have commitment costs. CESA is clarifying some of these costs (e.g., station power) and has been pressing the CAISO to allow for energy storage resources to represent commitment costs. Currently, PDR resources can do this, but NGR resources cannot. The CAISO delayed the implementation of only allowing resources categorized as ‘use-limited’ to represent opportunity costs in their commitment costs to allow Demand Response Auction Mechanism (DRAM) I winners to complete their pilots before rules were changed and to comply with the Resource Adequacy Availability Incentive Mechanism (RAAIM), which requires the current ‘use-limited’ category.

On February 17, 2016, the CAISO published a Draft Final Proposal on Phase 3 changes.

On June 15, 2016, the CAISO held a workshop on commitment costs related to energy storage and other resources. CESA presented at this workshop on where and how risk exposures to PDR and/or NGR resources may shift under the CAISO’s proposed rules that limit the ability for resources to exit the market by taking outages. CESA discussed the risks of these new exposures, which warrant further consideration and safeguards, although the risks are not immediately extreme. As such, CESA supported the CAISO's efforts to keep some versions of the old rules for managing these exposures until the full suite of new solutions is developed.

On July 27, 2016, the CAISO held another workshop to work through further details on opportunity costs, outage cards, and use-limit data. The workshop detailed the types of documentation that could be provided to validate limitations on the four types of supply-side DR – i.e., DRAM, third-party direct participation, utility DR programs, and utility aggregator-managed DR programs. Critically, the CAISO wants resources to express use-limitations through their bids and commitment costs and the new functionality seems to allow this sufficiently.

While CCE3 is ready to proceed and be finalized, CESA recommended that there be clear and workable paths to represent commitment costs in PDR and NGR models, and that use-limited status should be reasonably easy to achieve for energy storage resources.

See CESA's comments on August 10, 2016 on the July 27, 2016 workshop.

On November 17, 2016, the CAISO released a CCE3 Revised Action Plan. The CAISO has now detailed the types of documentation that could be provided to validate limitations on the four types of supply-side demand response – i.e., DRAM, third-party direct participation, IOU DR programs, and IOU aggregator-managed DR programs. Critically, the CAISO wants resources to express use-limitations through their bids and commitment costs and the new functionality seems to allow this sufficiently.

On June 30, 2017, the CAISO issued a Straw Proposal that addresses the bidding flexibility framework described in the Issue Paper and evaluated with stakeholders in March and April working calls. This proposal was discussed at the July 6, 2017 stakeholder meeting and proposes to do the following:

Support hourly minimum load offers
Apply settlement rules when no minimum load offer present
Add negotiated option for commitment cost reference levels
Apply supplier provided ex ante reference levels adjustments subject to verification requirements
Re-calibrate penalty price parameters to support possibility of energy offers at $2,000/MWh
Support market-based commitment cost offers subject to market caps
Apply dynamic market power mitigation
Apply results of market power mitigation on commitment costs to default assessment for exceptional dispatches

• Day-Ahead Market Enhancements (Stakeholder Process)

Background

The CAISO has observed that the current Day-Ahead Market (DAM) is limited due to subsequent runs of the Integrated Forward Market, which clears the market on the next trade day based on bid-in demand, and of the Residual Unit Commitment (RUC), which procures incremental capacity to address shortfalls between the IFM and the CAISO net load forecast and to ensure additional resources (through a must-offer obligation of economic bids) will be available in real-time. However, the CAISO found that the RUC does not address upward uncertainty by de-committing resources – i.e., if IFM clears above the net-load forecast.

This initiative has thus been established to make DAM enhancements to reduce the burden on the real-time market to resolve imbalance and net load forecast uncertainty.

DAME is focused on co-optimizing supply based on both cleared demand and demand forecast and on developing a day-ahead imbalance reserve product. The CAISO is targeting Q2 2021 for EIM Governing Body briefing and ISO Board decision. A separate Extended Day-Ahead Market (EDAM) Initiative is focused on extending day-ahead market to EIM entities decision:

Bundle 1: Transmission provision, resource sufficiency evaluation, and distribution of congestion rents
Bundle 2: Accounting for GHG costs, ancillary services, full network model enhancements, and administrative fee
Bundle 3: Price formation, convergence bidding, external resource participation, and other items

Straw Proposal will be posted in July 2020 and scheduled for Q2 2021 EIM Governing Body and ISO Board decisions.

Issue Paper

On February 28, 2018, the CAISO issued its issue paper and straw proposal on proposed DAM enhancements (see also March 7, 2018 stakeholder meeting). To reduce the burden on volatility in the real-time market, the CAISO proposed 15-minute scheduling granularity in the IFM (as opposed to the current one-hour blocks) to address granularity issues between the DAM and 15-minute market (FMM). While bid submissions and scheduling may remain hourly, resources now have the option to be committed intra-hour at the beginning of any 15-minute interval. In addition, the CAISO proposed the development of a day-ahead imbalance reserve product to ensure sufficient real-time bids to meet imbalances in the real-time market and add ramping headroom in the day-ahead solution. Similar to the Flexible Ramping Product (FRP), the CAISO will then be able to commit some fast-ramping resources to be ready to meet any uncertainty needs. The CAISO will seek to procure 100% of the imbalance reserve requirement, which is based on potential imbalance between IFM and real-time. Penalty prices based on the real-time flexible reserve product penalty price will be used to seek market solutions when there are inadequate imbalance reserve bids. Bids for up and down imbalance reserves will replace the current RUC availability bids. Finally, by integrating IFM and RUC, the CAISO believed that the day-ahead imbalance reserve product will be procured relative to the CAISO’s net load forecast, not based on bid-in demand.

Straw Proposal

On April 11, 2018, a revised straw proposal was issued reflecting revisions based on stakeholder comments received on the issue paper and straw proposal. This is a follow-up to the straw proposal where the CAISO proposed 15-minute scheduling granularity in the IFM (as opposed to the current one-hour blocks), the development of a day-ahead imbalance reserve product, and the integration of the IFM and RUC. As compared to the initial straw proposal, the CAISO proposed a revision to have a single product for both the upward and downward directions for the 15-minute and 5-minute imbalance reserve products in response to stakeholder comments. The 5-minute need can be addressed by distributing portions of the imbalance reserve requirement to sub-regions while the regional requirement will be set at the total need to address FMM imbalance and the FMM flexible ramping product uncertainty requirement. The FMM flexible ramping uncertainty requirement will then be distributed to the various sub-regions where only 5-minute dispatchable resources will be eligible to meet the sub-regional requirement. Additionally, the CAISO provided additional information in a draft technical paper explaining the formulations for the new day-ahead market, provided data analysis of historical imbalance, proposed methodologies to determine the imbalance reserve requirement, and provided a settlement and cost allocation worksheet

Overall, the CAISO provided some revisions and provided additional data analysis for justification for the proposed changes in this initiative. With these changes, the CAISO aimed to ensure sufficient real-time bids to meet imbalances in the real-time market, add ramping headroom in the day-ahead solution, and address granularity issues between the DAM and FMM.

On June 19, 2018, a workshop was held on June 19 to discuss updates to the Revised Straw Proposal.

On July 2, 2018, a stakeholder call was held on July 2 to discuss the new Day-Ahead Flexible Ramping Product (DA-FRP) requirement, which will replace the imbalance reserves, as detailed in the design elements matrix. Currently, the Real-Time Flexible Ramping Product (RT-FRP) settles forecasted movement and uncertainty awards, but the CAISO now proposes that the DA-FRP align resources to be settled for scheduled energy as well as up and down uncertainty awards. The DA-FRP will be procured using a demand curve consistent with the current RT-FRP procurement. RA resources will still need to submit bids into the real-time market even if it does not receive a DA-FRP award, while non-RA resources that have a DA-FRP award have a real-time must-offer obligation.

On August 27, 2018, the CAISO posted a Second Revised Straw Proposal and held a stakeholder meeting on September 4, 2018 that proposed to allow 15-minute scheduling granularity for all market participants, eliminate the use of forecasts to shape hourly bids, and move the DAM submission deadline to 9 am (from 10 am) to allow for additional processing times. Imports and exports along the interties can be schedule with 15-minute granularity or in hourly blocks, and similar 15-minute granularity applies to load submissions, though there is no requirement for 15-minute meters. For ancillary services, the CAISO clarified that ancillary services will be awarded using a single dynamic ramp rate, limited by certified ancillary service capacity. Currently, Appendix K requires spin and non-spin to sustain output for 30 minutes, and NGR awards must be supported by 30-minute state of charge. The regulation ramp rate used in the automatic generation control (AGC) can be lower than the dynamic ramp rate, which will also be used to dispatch spin, non-spin, and regulation services during a contingency event. Finally, the CAISO is planning an update to the technical appendix describing the integrated IFM and RUC, the day-ahead flexible ramping product, and improved reserve deliverability.

The CAISO notified stakeholders that it is delaying posting of the Draft Final Proposal until it completes further internal assessments on the technical feasibility of changing DAM scheduling from hourly to 15-minute granularity. Concurrent with the stakeholder initiative, the CAISO has been conducting performance testing on the DAM solve time under 15-minute scheduling granularity. The results to date have raised concerns on whether the system performance levels can meet the required market timelines. In Q4 2018, the CAISO will continue to attempt to resolve the system performance issues and will also evaluate additional implementation approaches that require less computer processing resources. The time to perform additional technical studies does not change the planned implementation date of fall 2020.

On November 30, 2018, CAISO held a stakeholder working group meeting as part of Phase 2 of this initiative. This meeting discussed alternatives to combining the IFM and RUC process (i.e., keeping IFM and RUC markets separate) and to discuss incorporating the FRP into the day-ahead market. The two proposed alternatives include:

Alternative 1 (conservative): Keep the current DAM application sequence and add the FRU and FRD procurement in the IFM and provide additional unit commitment and fixed AS, FRU, and FRD in RUC
Alternative 2 (aggressive): Change current DAM application sequence, co-optimize Energy, AS, FRU, and FRD in RUC and have fixed unit commitment and AS, FRU, and FRD in IFM

The CAISO explained that Alternative 1 would require minimal change to the RUC and to the deviation settlement, which is lower regulatory risks and is easier to implement since it is closer to the status quo and provides a hedge for forecast error by liquidating virtual schedules in the FMM, but may lead to less efficient unit commitment and RUC capacity. By contrast, Alternative 2 has the advantages of more efficient unit commitment and RUC schedules to meet real-time conditions, but the downside is that it would introduce a cost for variable energy resource forecast error.

On May 2, 2019, the CAISO held a stakeholder call to discuss next steps for the initiative. As a result of both implementation complexity and stakeholder comments, the CAISO proposed to revise the scope of this initiative to defer consideration of day-ahead market 15-minute scheduling and to instead focus on the development of a flexible ramping product to address uncertainty that can materialize between the day-ahead and the real-time markets.

On June 20, 2019, a technical workshop was held to review the proposed options for developing a new day-ahead product that will address ramping needs between intervals and uncertainty that can occur between the day-ahead and real-time markets.

On August 13, 2019, the CAISO held a stakeholder working group meeting on to review comments received from the June workshop and continue discussions on the proposed design options.

On February 10, 2020, a stakeholder meeting was held to discuss the proposed day-ahead market design and solicit stakeholder feedback on design elements, which are intended to co-optimize and value energy and capacity in an efficient market solution.

On February 11-12, 2020, a two-day workshop was held for the Extended Day-Ahead Market (EDAM) Initiative to focus on topics related to transmission provision, resource sufficiency evaluation, distribution of congestion rents, accounting for GHG costs, ancillary services, Phase 2 of the full network model, administrative fee for EDAM, price formation, convergence bidding, and external resource participation.

On March 5, 2020, a web conference was held to discuss the remainder of the straw proposal for the DAME Initiative, including a discussion on the proposals for the congestion revenue rights and local market power mitigation topics

• 2018 Interconnection Enhancements (Stakeholder Process)

Background

Periodically, the CAISO holds stakeholder processes to adjust the resource interconnection study process. This year, the CAISO identified a robust set of issues that include the following:

Affected systems
Time in queue limitations
Negotiation of generator interconnection agreements
Study deposits
Self-build option for standalone network upgrades
Allowable modifications between Phase 1 and 2 studies
Conditions for issuance of study reports
Interconnection agreement insurance
Interconnection financial securities
Funds forfeiture for withdrawal
Full Capacity Deliverability "Option B" clarification

Issue Paper

On August 10, 2017, the CAISO requested stakeholders to submit potential topics to be included the next iteration of this wholesale interconnection process enhancement initiative. CESA requested that the CAISO consider creating an expedited process for the utilization of full interconnection service at existing generating facilities by co-located energy storage systems and re-evaluate methods for modeling energy storage resources in worst-case scenarios.

See CESA's comments on August 30, 2017 for consideration by the CAISO in its 2018 initiative

On January 24, 2018, the CAISO held a stakeholder meeting to discuss an issue paper for the new 2018 Interconnection Process Enhancements Initiative. This initiative will evaluate potential changes needed to enhance the CAISO generator interconnection procedures and agreements. The CAISO requested topic suggestions from stakeholders in August 2017, which were considered for inclusion in the scope of this initiative. In its issue paper, the CAISO expressed its intent to include many topics in the scope, including the few key ones highlighted below:

Enhancements to the transmission plan deliverability (TPD) allocation process around rules for parking and cost allocation for upgrades.
Review of the effectiveness and potential changes to the balance sheet financing option to demonstrate commercial viability.
Clarification to the annual full capacity deliverability option as well as options to transfer deliverability.
Consideration of solutions to prevent gaming of cost responsibility through processes to convert projects to energy only deliverability status or to re-enter the queue for full capacity.
Address tripping rules, ride-through requirements, and other inverter settings for inverter-based generation.
Consider a cut-off for project technology and fuel type changes.
Consider increasing the repowering study deposit from $10,000 to $50,000.
Reevaluate short circuit duty contribution criteria for repower projects.

CESA focused on two topics that we proposed as topics to consider in the 2018 IPE Initiative. The CAISO staff noted that it did not plan to consider those topics in its scope, but we reinforced the inclusion of these topics in our comments (as summarized below):

CESA recommended that the CAISO provide further clarity and transparency on the repowering process around “repower-and-retire” scenarios, as the current rules and processes may unreasonably cause the repowered energy storage resource to retire along with its paired existing generating facility.
CESA proposed that the CAISO provide clarifications on how deliverability is allocated between system and flexible capacity deliverability.

See CESA's comments on February 7, 2018 on the Issue Paper

Straw Proposal

On May 9, 2018, the CAISO issued its straw proposal and held a stakeholder meeting that narrowed down the list of 42 potential topics in the issue paper to 24 topics to be addressed in this initiative. On the issue of replacing entire existing generator facilities with energy storage, the CAISO responded to CESA’s comments that charging was never studied for the traditional generator and thus the CAISO cannot permit a 100% replacement through the modification process due to material changes to the electrical characteristics that were studied. Instead, the CAISO held firm that whole-change energy storage replacement requests must go through the cluster study process as a new project. Despite contesting CESA’s view on 100% replacement through the modification process, the CAISO agreed to further explore and provide clarity around the rules for the addition of energy storage and define better guidelines or “rules of thumb”, including in “repower-and-retire” scenarios where energy storage is added to an existing generating facility, which then retires. The CAISO noted that it would assess the reliability impact of the system without the original generating facility and just the energy storage remaining. If there is no reliability issue, the CAISO explained that it may allow the energy storage system to remain interconnected and operational, with available full capacity deliverability status (FCDS) or partial capacity deliverability status (PCDS) that could be transferred from the retiring unit to the energy storage resource; otherwise, the energy storage resource may also need to disconnect.

Additionally, the CAISO reviewed its interconnection data and found that it has thus far approved up to 10% conversion to battery storage from an existing project via the modification process. The CAISO affirmed that a bright line should not be established, and approval of partial replacement requests should be determined on a case-by-case basis due to the impact to the short circuit duty and assurance that energy storage is dispatched at the CAISO’s direction. The CAISO provided examples of how the modification process does not restudy on-peak deliverability and how energy storage additions could only be added as energy-only resources.

CESA successfully advocated to persuade the CAISO to consider these various modifications and “repower-and-replace” scenarios, which has significant impacts for many members developing hybrid energy storage projects. Even though 100% replacement through the modification process is not considered tenable, the CAISO may consider in this initiative how partial repowering could be allowed in the modification process to facilitate the retirement of existing generating facilities while keeping the added energy storage online. While adding energy storage to the rest of the interconnection capacity available to the original generating facility would require a full cluster study process, greater clarity on partial repowering may still deliver significant development cost savings by leveraging the modification process.

CESA expressed great appreciation for the CAISO in reassessing its initial position by including our repower-and-replace scenario issue in the scope of the initiative, but we offered comments on few areas of clarity needed:

CESA seeks to work with the CAISO to understand whether there are pathways for the reliability assessment for repowered energy storage facilities to remain online after the original generation facility retires.
CESA notes that non-battery storage technologies when used for repowering are capable of providing the critical inertial response, short circuit duty, and voltage support that the retiring synchronous generator provided.
CESA seeks clarity on the implications of FERC Order No. 845, specifically around the one-year grace period for these scenarios, in this initiative.

See CESA's comments submitted on June 8, 2018 on the Straw Proposal

On July 10, 2018, a Revised Straw Proposal was issued that responded to stakeholder comments on a number of topics within its scope. For CESA’s “repower and retire” scenario, the CAISO generally indicated that the current Generator Management Business Practice Manual (BPM) already addresses many of the issues raised by CESA, including the case-by-case determination through the material modification assessment (MMA) process of whether by what percentage of generation resource capacity a repowering with energy storage could be allowed. The CAISO recommended that CESA work through the BPM change management process for any requested changes and added that it will implement the proposed retirement clarifications through the Generator Management BPM. Finally, the CAISO explained that it is working on a compliance plan for Order No. 845 concurrently with the IPE Initiative.

On July 26, 2018, the CAISO Board approved seven changes to the generator interconnection process, including the requirement for resources to provide a copy of their PPA to demonstrate commercial viability and an increase to interconnection study deposits to $50,000 from $10,000.

CESA supported the CAISO and noted that CESA will work through potential changes to the reliability assessment through the BPM change management process and echoed our views on developing an Order 845 compliance plan for the repower-and-retire scenario.

See CESA's comments on July 31, 2018 on the Revised Straw Proposal

On August 28, 2018, the CAISO published an Addendum to the Revised Straw Proposal that addressed stakeholder comments with slight modifications to the proposal on a couple of items. Specifically, the CAISO proposed to not establish cost responsibility for any assigned DNUs for projects that obtained a transmission plan deliverability (TPD) allocation but had their PPA terminated at no fault of the interconnection customer or did not receive a PPA after being shortlisted. Previously, the CAISO proposed to require the interconnection customer to retain cost responsibility in these cases. Additionally, the CAISO clarified that projects will be eligible for reimbursement of funding provided for the construction of DNUs if a project that is required to retain the cost responsibility for assigned DNUs after conversion to energy only, and does fully fund its allocated portion of the DNU assigned to it and achieves commercial operation.

Final Proposal

On September 17, 2018, the CAISO held a public stakeholder meeting on to discuss the Draft Final Proposal for this initiative. In response to stakeholder requests to combine the generator interconnection agreement with the affected PTO upgrade facilities agreement, the CAISO said it will defer the issue of combining the generator interconnection agreement with the affected PTO upgrade facilities agreement to the next IPE process and proposed changes to the maximum cost responsibility for network upgrades. Next, the CAISO discussed the technical aspects of the proposal on ride-through requirements for inverter-based generation. The Generator Interconnection Agreement (GIA) is proposed to be revised to:

Eliminate momentary cessation for transient low voltages, and transient high voltages where V < 1.20 pu
Allow momentary cessation for V ≥ 1.20 pu
Eliminate inverter trip for momentary loss of the phase lock loop
Establish inverter TRIP return time range
Coordinate inverter controls with plant level controller
Identify minimum level of diagnostic equipment

The requirements for diagnostic equipment for plants with net export greater than 20 MW include the following:

Plant level data: monitor plant voltage, current and power factor, and any plant protective relay trips
Inverter level data: record ride through events and phase lock loop status
Time synchronization of data (1 mSec)
Data retention: retain data for 30 calendar days
Data reporting: provide data within 10 calendar days
Install a PMU or equivalent (minimum 30 samples per sec), but no real time telemetry is required

On November 13, 2018, the CAISO published an addendum to the Draft Final Proposal to reconsider its proposal for maximum cost responsibility of network upgrades and to explore new issues around interconnection request acceptance and validation criteria. Specifically, the CAISO proposes to specify minimum requirements for an IR application to be deemed complete:

If an IR application is not deemed complete by the close of the cluster application window, it will not move on to the validation process.
The CAISO will respond to IR submissions within five business days with a determination of IR deemed complete, or IR deemed incomplete and identify deficiencies in IR application.
Final submissions and attempts to cure must be submitted by April 15, and if the CAISO exceeds the 5 business day response timeline, the interconnection customer will be provided a day-for-day extension to the April 15 deadline.

On November 27, 2018, the CAISO held a stakeholder meeting discuss an addendum to the Draft Final Proposal.

On January 3, 2019, a second addendum to the Draft Final Proposal was discussed on a stakeholder call. The CAISO proposed the following modifications on maximum cost responsibility for network upgrades:

Proposes to adjust the maximum cost exposure (MCE) downward with the maximum cost responsibility (MCR), pursuant to Appendix DD, Section 7.4, with the understanding that it could increase with the MCR if the situation were to occur
Identifies each Interconnection Service Reliability Network Upgrade (ISRNU) as ‘allocated ISRNU’ and ‘non-allocated ISRNU’ for the purposes of defining cost responsibility within the current cost responsibility (CCR) and MCR
Retain the GIA as the point at which a PTO becomes responsible for network upgrade costs and appropriately align the execution of GIAs in the projects development process by removing the execution of a GIA from the TPD retention requirements
Provide clarification as to the impacts of a project that needs to fund a precursor network upgrade (PNU) or conditionally assigned network upgrade (CANU) early in order to achieve COD or deliverability.
Clarify that the RNU reimbursement cap can be impacted from a CANU-to-ANU [assigned network upgrade] conversion

The second addendum did not make any modifications to the proposals for interconnection request acceptance criteria and interconnection request validation criteria that were included in the first addendum. The CAISO believed the proposal will more efficiently and effectively assist interconnection customers during the interconnection request validation process and scoping meetings. The proposal also provided greater flexibility to the CAISO when large volumes of complex interconnection requests are received by enabling the CAISO to give interconnection customers more time if the CAISO misses any of its validation timeline requirements.

On April 1, 2019, FERC issued an Order that approved the CAISO’s Feb. 7, 2019 filing of tariff revisions to the Generator Interconnection and Deliverability Allocation Procedures in Appendix DD of the CAISO Tariff on April 1. The revisions enhance the generator interconnection process by: (i) clarifying what constitutes a “complete” interconnection request and what constitutes a “valid” interconnection request; (ii) extending the validation period, for curing deficiencies in submitted data, from May 31 to June 30; (iii) removing the requirement that interconnection requests must be valid before the ISO can schedule scoping meetings; and (iv) providing interconnection customers with day-for-day extensions to deadlines when the CAISO cannot meet its response deadlines for documentation submitted before May 31.

On April 25, 2019, the CAISO held a stakeholder call to discuss the proposed tariff revisions in compliance with FERC Order No. 845.

Energy Storage Interconnection (Stakeholder Process)

Background

The scope of this proceeding is to address energy storage interconnection issues to the CAISO-controlled grid, with a short-term focus on existing rules and opportunities to streamline them and a long-term focus on policy issues that may require more comprehensive examination. Not in scope of this initiative is interconnection below the CAISO-controlled grid and market/rate issues. Distribution-connected and customer-sited projects are not the focus of this initiative. The CAISO also modified the interconnection request reform to include technical data relevant to energy storage projects.

Issue Paper & Straw Proposal

On April 7, 2014, a stakeholder call was held to discuss the existing processes for interconnecting generators to the CAISO-controlled grid. This meeting also provided an introduction to the preliminary scope of the initiative, which is to ensure a one-stop, streamlined process for energy storage interconnection and identify improvements to the GIDAP that could be implemented prior to the Cluster 8 window. The CAISO will examine alignment between study methodologies with energy storage configurations and use cases, while assessing impacts of both discharging and charging given system, local, and flex RA rules. Most stakeholders supported consolidating the interconnection process for grid-connected storage under the GIDAP in order to avoid the inefficiencies of a bifurcated process that separates a storage facility into generation and load. As part of the GIDAP, the CAISO clarified that the facility would then have its charging and discharging cycles subject to CAISO dispatch instructions, including curtailment instructions to manage congestion or other operational issues on the system. The CAISO in particular opposed including unrestricted charging load in its retail load forecast, as it would, among other things, incent the approval of TAC-funded upgrades to support unrestricted charging, contradicting the potential for energy storage to increase T&D utilization and reduce the need for upgrades.

On June 24, 2017, an Issue Paper & Straw Proposal was issued that discussed how the existing GIDAP rules can accommodate energy storage projects in the Cluster 7 queue that want to be treated as generators for both aspects of their operation - i.e., produces positive output during discharge mode and negative output during charging mode. The CAISO observed that there is insufficient time to identify, seek approval, and implement changes to the GIDAP tariff for Cluster 7, and that this initiative would be used to inform the design of changes for future clusters. The CAISO identified the following topics as being within the scope: GIDAP interconnection study process, modification request process, ISP-BTM expansion process, deliverability study methodology, and new/streamlined agreements. Issues not in scope of this initiative were determined to be rate treatment for energy storage charging, energy storage as a non-transmission alternative, metering/telemetry rules, and market design. The CAISO also determined that it would examine three categories (CAISO grid-connected, distribution-connected, and customer-sited) and three configurations (standalone, paired with generation, and paired with onsite load) for consideration in this initiative.

On August 4, 2014, the CAISO made its FERC Order 792 compliance filing to revise its tariff to specifically define electric storage devices as "generating facilities" that can take advantage of generator interconnection procedures (see definition of the term "Generating Facility" in CAISO Tariff Appendices A, EE, and FF).

On August 13, 2014, a stakeholder meeting was held to provide an update that no changes to the GIDAP have been identified as necessary to accommodate standalone storage and storage combined with onsite generation interconnection to the CAISO grid. Changes to pro forma interconnection agreements to address charging functions are still under consideration. In addition, the CAISO indicated that this approach is not intended to determine what payments or charges beyond the interconnection process should be applicable to the charging mode. Considering energy storage resources must qualify for System or Local RA to provide Flex RA, the CAISO will study the resource for System and/or Local RA deliverability (as already done) and perform whatever additional study regarding its flexibility. The CAISO may need to modify a resource's Pmin due to transmission constraints. A future "unbundling" of flexible capacity (i.e., not delivering during peak system conditions) from system/local capacity may offer alternative interconnection options for flexible-only status. The CAISO also noted the need for additional study methodologies for storage facilities wishing to only provide Regulation Energy Management (REM).

Final Proposal

On November 18, 2014, a Draft Final Proposal was issued that confirmed that only few changes to the GIDAP have been identified as necessary, as discussed above. One notable change is that the Draft Final Proposal discussed how Non-Generator Resource (NGR) model resources are settled at the locational marginal price (LMP) for both discharging and charging, are not allocated a Transmission Access Charge (TAC), and treated similar to other generators for the settlement of station power. The CAISO also discussed how it will not adopt a charging deliverability study given that there is no specific system condition when energy storage must be able to charge, and it is difficult to demonstrate that what is not possible under one set of conditions proves that it is not possible under any conditions. The CAISO held the position that there is some reasonable window for charging available.

• Energy Storage and Distributed Energy Resources (ESDER) (Stakeholder Process)

Background

Following a road-mapping exercise, the CAISO combined many potential identified barriers to market participation by energy storage and aggregated distributed energy resources (DERs) into a catch-all initiative. Many critical items are lined up for consideration and resolution in this multi-phase initiative.

The Energy Storage and Distributed Energy Resources (ESDER) Stakeholder Initiative is the primary policy development mechanism to advance the opportunities for DER (including EV) for participating in the ISO Markets. Stakeholder initiatives typically take 1-2 years of policy development followed by system implementation. Initiatives are open to all stakeholders and the CAISO encourages participation and comments as the policy is developed.

The ESDER initiatives focus largely on modifications to the Demand Resource (DR) and Non-Generator Resource (NGR) participation. ESDER Phase 3 (Fall 2020 implementation) will have an enhancement to measure EV performance separately from traditional facility loads, such as HVAC and lighting, which should better capture the response of EV’s to their traditional baseline energy consumption.

DERs can participate in the Proxy Demand Resource (PDR) and Reliability Demand Response Resource (RDRR) load curtailment products for energy, spin and non-spin products at a facility/utility line of service aggregation level on a non 24x7 basis. More information is located here.

The CAISO Distributed Energy Resource Provider (DERP) framework allows for the aggregation of BTM devices meeting CAISO participation requirements (size, communication, visibility, performance, and measurement). The DERP framework allows for the provision of all CAISO wholesale market products, including regulation under the NGR model. However, given the complexities of transmission and distribution dispatch coordination, costs, and interconnection of resource aggregations that export beyond the meter, these types of resources are not participating in the CAISO markets today. More information is located here.

Phase 4

On February 6, 2019, the CAISO published its Issue Paper for Phase 4 of this initiative and held a stakeholder call on February 13, 2019 that proposed to address the following topics:

Reviewing the CAISO’s market optimization of NGRs (i.e., real-time state of charge [SOC] management, effects of multi-interval optimization) and NGR participation agreements
Considering bidding requirements to optimally use energy storage resources, including local market power mitigation measures
Reflecting the operational characteristics of PDRs, including weather-sensitive DR resources
Consideration of MUA rules and application to CAISO market participation – e.g., 24x7 settlement rules for NGRs

In response, CESA recommended that the Phase 4 scope be expanded to better focus not only on key NGR model changes for IFOM resources, but also to better accommodate solar-plus-storage resources as well as key capabilities for BTM and MUA participation structures. CESA specifically recommended the following scope:

Establish RA counting for DERP model
Develop ‘less-than-24-hour’ participation requirement for DERP (e.g., by creating a baseline)
Incorporate weather adjustments to MGO baseline
Incorporate ‘spread bids’ for energy storage in the Day-Ahead Market
Review outage rules for NGRs and DERPs
Review RAAIM formulas for NGR and DERPs
Improve the management of customers in PDR groupings
Address various scheduling and dispatch limitations for NGRs
Value solar exports in the NGR and/or PDR models

See CESA’s comments on March 4, 2019 on the Issue Paper

On May 20, 2020, the Draft Final Proposal was published to discuss the following key changes:

Applying market power mitigation to storage resources
State-of-charge (SOC) biddable parameter for storage resources, including end-of-hour (EOH) and end-of-day (EOD)
Vetting qualification and operational processes for variable-output demand response resources

Two items were not covered because they remained unchanged, including the maximum daily run time parameter for DR and the streamlining of market participation agreements for NGR participants.

On August 21, 2020, a Final Proposal was published that only included changes to the EOH SOC biddable parameter proposal and the removal of an end-of-day (EOD) SOC until the short-term unit commitment (STUC) process can recognize the latter. Another simplified example of the BCR proposed settlement is provided.

• ESDER Phase 1 (Stakeholder Process)

Background

In Phase 1, the CAISO carved out critical wholesale market rules for Proxy Demand Response (PDR) metering, which allows for more optimal participation of behind-the-meter resources.

Phase 1 also established key CAISO approaches for multiple-use applications and for enhancements to the Non-Generator Resource (NGR) participation model. NGR will likely be used by larger energy storage systems coming online and participating in CAISO markets in coming years.

Draft Final Proposal

On December 23, 2015, the CAISO published its Revised Draft Final Proposal that:

Established a metering generator output (MGO) performance evaluation methodology: The MGO performance methodology baselines the energy storage device's "normal dispatch operations" and only provides credit for discharge above the baseline for the hours in which it was dispatched as a PDR resource. See Demand Response User Guide on page 164.
Established the use of statistical sampling to derive settlement quality meter data (SQMD) for: (1) day-ahead participation when hourly interval metering is not installed at all underlying resource locations; and (2) day-ahead market participation when hourly interval-capable meters are installed but RQMD is not derived from the hourly interval meter data

CESA overall sees challenges with a baseline approach for measuring DR resource deliveries of energy storage systems, which can prohibit behind-the-meter storage resources from offering other services.

On February 3-4, 2016, the CAISO Board approved the final ESDER design, which approved the MGO for BTM energy storage. Under Meter Configuration A, the performance cannot be separated into the two response methods for the load and generation device - i.e., actual load reduction versus load consumption offset by output from a BTM generator or device.

However, under Meter Configuration B Option B1 (Load Reduction Only), this option would allow facility loads that are registered in the PDR/RDRR to have DR performance evaluated using a baseline (B) determined from Net Meter (N) and Generator Meter (G) values for comparable non-dispatch hours - i.e., N minus G. The actual demand reduction of the load in response to a CAISO dispatch interval (t) would be calculated as: DRLOAD(t) = BN-G(t) - [N(t) - G(t)].

Under Meter Configuration B Option B2 (Generation Offset Only), the BTM device is registered in the PDR/RDRR (not the facility load as in B1). The DR performance, referred to as DRSUPPLY(t) for purposes of this proposal, is the demand reduction resulting from the output of the BTM generation device for dispatch interval, t. The DR performance, DRSUPPLY(t), would be evaluated based on the physical meter generator output, G, for dispatch interval t or G(t), adjusted by a quantity GLM which represents an estimate of the typical energy output used for retail load modifying purposes and benefits. The calculated value, GLM10, would appropriately remove an estimated quantity of energy delivered by the device to the facility for its retail load modifying purposes – i.e., energy not produced in response to an ISO PDR/RDRR dispatch. The performance evaluation introduces an adjusted MGO value calculated by taking the difference between G(t) and GLM, where the demand response performance attributed to a PDR/RDRR supply dispatch would be calculated as: DRSUPPLY(t) = – [G(t) – GLM]

Under Meter Configuration B Option B3 (Load and Generation), the load and the BTM device together are registered as the PDR/RDRR resource. Under this option, the DR performance would be the combined DR performance attributed to DRLOAD(t) and DRSUPPLY(t), as previously detailed under options B1 and B2 respectively, resulting in a total demand response reduction calculated as: DRTOTAL(t) = DRLOAD(t) + DRSUPPLY(t).

On May 18, 2016, the CAISO submitted Tariff Revisions for FERC approval on NGR enhancements and the development of an MGO-adjusted baseline for PDR resources.

See CESA's comments on June 8, 2016 supporting the tariff changes.

CESA has worked closely with the CAISO to ensure a timely implementation of this critical capability.

• ESDER Phase 2 (Stakeholder Process)

Background

In Phase 2, the CAISO seeks to address further NGR enhancements, rules for station power for transmission-interconnected resources, more multiple-use application concepts, further PDR enhancements, and consideration of a Clean Coalition proposal relating to the allocation of transmission system costs to DERs.

Scoping Memo

On March 22, 2016, the CAISO published its Scoping Memo detailing these outstanding issues. CESA supported the proposed scope but requested that the CAISO add NGR metering to the scope to enable greater multiple-use applications.

See CESA's comments on April 18, 2016 on the Scoping Memo.

Straw Proposal

On May 24, 2016, the CAISO released its Straw Proposal. CESA commented largely in support but recommended that the Proposal also focus on how NGRs can represent and recover commitment costs, as well as how they can adjust their bids in CAISO markets based on NGR's state of charge. Significantly, the CAISO pushed the Station Power reforms issue to the CPUC.

See CESA's comments on June 9, 2016 on the Straw Proposal.

Revised Straw Proposal

On July 21, 2016, the CAISO published its Revised Straw Proposal that explores how to best reflect resource use limitations and characteristics, supports a bi-directional PDR concept, considers energy settlement for PDR frequency regulation, and explores the use of alternative baselines such as controls groups. Furthermore, the CAISO has stated that there are ‘no issues’ with multiple-use applications and has set the stage to accept CPUC/LRA rules for Station Power.

CESA supported many of the proposed enhancements and offered several brief comments on how NGR refinements should focus on detailing commitment costs, how the CAISO should affirm that multiple-use applications are authorized, and how the CAISO should affirm that charging energy for in-front-of-the-meter (IFOM) market participants is a wholesale transaction. CESA also requested that the CAISO approve the PDR regulation approaches and load-increasing baseline methodologies developed by the Load Consumption Working Group (LCWG).

See CESA's comments on August 11, 2016 on the Revised Straw Proposal.

Second Revised Straw Proposal

On September 19, 2016, the CAISO published its Second Revised Straw Proposal, which provided the following updates:

NGR use limitations: The CAISO has discussed use-limited status of energy storage resources, but CAISO staff said that it is not yet ready to put these ideas into a proposal.
Multiple-use applications: The CAISO will collaborate with and wait on the CPUC in the Storage OIR Track 2 proceeding. The CAISO generally supports MUAs so long as inappropriate redundant payments are prevented.
Station power: The CAISO proposed a couple of narrow options to mitigate some concerns of energy storage companies but reiterated its position that the CPUC must act first. The CAISO also noted that the CPUC station power rules can inform CAISO market views and treatment of commitment costs, such as station power.

CESA supported the CAISO on these matters, but requested that the CAISO confirm the eligibility of NGRs to have use-limited status, how such status is acquired, and how outages and a lack of bid mitigation rules accommodate use-limitations and related opportunity costs.

See CESA's comments on October 12, 2016 on the Second Revised Straw Proposal.

Third Revised Straw Proposal

On April 17, 2017, the CAISO published its Third Revised Straw Proposal, which discussed how the CAISO is preparing to submit three topics for approval by the CAISO Board on July 26-27, 2017:

DR enhancements in the form of alternative baselines
Rules for distinguishing between charging energy and station power
A net benefits test (NBT) for DR resources that participate in the Energy Imbalance Market (EIM)

The CAISO proposed the following topics as part of ESDER Phase 3, which will start with the posting of an Issue Paper on September 29, 2017:

Defined rules for energy storage modeled as NGRs to qualify as a use-limited resource
Modeling daily cumulative MWh charge and discharge limits based on bid parameters for NGRs
Any issues identified in Track 2 of the CPUC's Energy Storage proceeding on multiple-use applications

The CAISO does not currently propose to include development of bi-directional PDR products in ESDER Phase 3 until retail rate interactions are resolved. The CAISO discussed parties’ comments and the initial results of PG&E’s Excess Supply DR pilot, which is looking at how customers can shift load to take advantage of excess renewable energy. PG&E found “challenges” related to interaction with retail rates and potential operational issues on the distribution system. For example, the CAISO said that the CPUC must take action first because any CAISO dispatch affects customers through their retail rate structure (e.g., demand charges). Some of the "fundamental" issues to be addressed, according to the CAISO, are:

Could a load serving entity (LSE) turn its retail demand charge settlement on/off in sync with when a customer receives a CAISO dispatch instruction to consume more energy, and if so, what IT and billing system changes would this functionality require?
What is the impact of load consumption on rates, rate designs, and revenue requirements?
Is a retail load consumption “program incentive” appropriate, and if so, how is it set and valued since the underlying retail customers are not paid the negative wholesale energy price, but are charged a retail rate?
How is the value of load consumption determined since load consumption is not a “capacity” or resource adequacy (RA) resource and not valued on a traditional avoided cost basis?

CESA expressed its disappointment with the perceived slow pace and limited progress on key ESDER issues and urged strong focus on fixes to the NGR and PDR models:

CESA understands the desire to discuss NBT and default load adjustment concepts but strongly disagrees that the CAISO should wait for utility retail rate changes to make progress on bi-directional PDRs capable of providing load consumption and regulation.
CESA supports the scope of NGR enhancements for ESDER Phase 3 scope but adds that the tools to manage excessive cycling and state of charge and the ability of Distributed Energy Resource Providers (DERPs) to exit the market should be included.
CESA generally supports the details and approaches for implementing new station power definitions and rules but recommends that the CAISO leave it to the state-jurisdictional utilities to establish workable configurations for measuring station power.

Parties offered mixed views on the need for speed versus slower approaches to allow load consumption, while parties generally agreed that tuning the NGR model is appropriate.

See CESA's comments on May 18, 2017 on the Third Revised Straw Proposal.

Draft Final Proposal

On June 8, 2017, the CAISO issued its Draft Final Proposal, which had no changes - i.e., the CAISO still plans to submit three topics for approval by the CAISO Board on July 26-27, 2017.

Regarding the station power issue, the CAISO opted to not mirror retail rules in its tariff and instead plans to reference retail tariffs given the extraordinary number of use cases that could exist as systems and technologies evolve and the variety of local regulatory authorities that may define station power differently from the CPUC. Instead, the CAISO proposes to work with stakeholders to implement CAISO Business Practice Manual revisions that provide useful examples of wholesale and retail uses. The CAISO also agreed with CESA that deference to local regulatory authorities on metering station power is both prudent and required, especially considering it is in their interest to make sure that customers are not avoiding retail charges. Instead of any prescriptive metering configurations, the CAISO proposes simply to state in its metering tariff provisions that generating units interconnecting to the CAISO will work with their local energy provider to ensure that their metering configurations accurately account for station power.

The proposal also provides an updated discussion on the ongoing topics of MUAs, increased load consumption as a DR enhancement, and NGR enhancements. The CAISO reiterated its view that retail-rate interaction barriers are not just jurisdictional in nature, but are real impediments to customer interest and robust customer participation in a bi-directional PDR product. The CAISO also clarified that using the Outage Management System (OMS), or utilizing MWh limitations to facilitate contractual or economic based limitations is not a physical limitation, adding that energy storage systems should not be maximizing capacity sold if it plans to limit its availability. On the 24-hours per day requirement of NGRs, the CAISO re-routed consideration of this issue to the MUA work being done in collaboration with the CPUC.

The CAISO added one topic (italicized below) as part of Phase 3 of the ESDER Initiative:

Development, if feasible, of a load consumption product for DR resources and participation in the regulation market
Defined rules for energy storage modeled as NGRs to qualify as a use-limited resource
Modeling daily cumulative MWh charge and discharge limits based on bid parameters for NGRs
Any issues on MUAs identified in Track 2 of the CPUC’s Energy Storage proceeding

CESA signaled support for the CAISO's approach to station power rules (which fits with the CPUC’s rules developed in R.15-03-011) and emphasized urgency and need for progress on important issues teed up for the next phase of ESDER. Phase 3 will be important to members, and CESA urged the CAISO to approach it in a manner to allow broad and non-discriminatory participation from an array of energy storage resources:

See CESA's comments on June 23, 2017 on the Draft Final Proposal.

On July 26, 2017, the CAISO Board approved the Draft Final Proposal that included three topics:

DR enhancements in the form of alternative baselines
Rules for distinguishing between charging energy and station power
A net benefits test (NBT) for DR resources that participate in the energy imbalance market (EIM)

On October 24, 2018, FERC approved the CAISO's submission of amendment to its tariff accordingly. No protests or adverse comments were filed. CAISO tariff section 4.13.4 now offers the option for non-residential end users to use either the 10-in-10 methodology, the MGO methodology, the control group methodology, or weather-matching methodology.

State of Charge

Previously, the CAISO investigated a dynamic rate model on an energy storage resource's state of charge (SOC), but it was later determined that a battery resource's ramping rate is not dependent on SOC. Rather, the challenge for energy storage resources is in sustaining a MW output at a given SOC due to operating restrictions.

On September 27, 2016, the CAISO said that it is not pursuing multiple bid stack submissions for different SOC levels at this time, but will re-evaluate this option when more energy storage resources participate in its NGR market.

Use Limitations

The CAISO generally defines use-limitations, for purpose of Resource Adequacy Availability Incentive Mechanism (RAAIM) exemptions, as exogenous factors that limit a resource’s capabilities to participate in the CAISO market. This concept can apply to power plants with air quality emissions limitations, hydro resources facing limited ‘fuel’ availability in a given time-period, warranty limitations, or other factors. Use-limitations create opportunity costs, and such costs are both biddable and recoverable. Tracking of use limitations then inform the eligibility for use-limit reached outages and related RAAIM exemptions. A resource can be flagged as use-limited in the CAISO market if it meets the current definition, completes the application/registration process, and provides an annual use plan.

The CCE3 Initiative modified the definition of a use-limited resource to include energy storage modeled as a PDR, but it did not consider it for energy storage modeled as an NGR. This topic was thus deferred to the ESDER Phase 2 Initiative.

On September 13, 2016, the CAISO held a NGR Working Group meeting to develop a common understanding of use-limited status for resources such as energy storage. This Working Group focused on whether and how NGRs may have use-limitations, opportunity costs, commitment costs, or other restrictions on their operations that may warrant special rules and exemptions of certain performance criteria, such as those in the RAAIM. Previously, this issue was covered in the Commitment Cost Enhancement Phase 3 Initiative, but energy storage modeled under NGR is not within the scope of that initiative.

NGRs are generally expected to be in-front-of-the-meter (and larger) energy storage resources participating full-time in the CAISO's market. Use limitation issues for energy storage include:

Applying a daily MWh limit for energy storage similar to use-limited peaker and hydro plants
Applying the Major Maintenance Adder (MMA) to energy storage
Applying the outage card functionality to no longer assess RAAIM
Clarifying the Must-Offer Obligation (MOO) hours and RAAIM assessment hours

CESA requested that the CAISO confirm the eligibility of NGRs to have use-limited status, how such status is acquired, and how outages and (a lack of) bid mitigation rules accommodate use-limitations and related opportunity costs. Specifically, CESA advocated that limits on cycles, starts, and MWh per year, month, and/or day be reflected in energy storage resource's use-limited status. These limits already exist in warranties and other contracts.

See CESA's comments on September 20, 2016 on the NGR Working Group Call.

On May 11, 2017, the CAISO sent out a note to all SCs in connection with scheduling energy storage resources in the CAISO’s markets. The CAISO said that it understands that in some cases these use limitations are the result of maintenance contracts and/or negotiated warranty arrangements in which the resource operator faces additional costs for maintenance and/or augmentation of battery cells, if the resource is operated in a manner that is inconsistent with agreed-upon terms. However, there are currently no rules that allow energy storage resources to manage these types of limitations through the use of the outage management system (OMS), which is being explored in ESDER Phase 2. Until any such market enhancements (and their associated tariff amendments) are put into effect, the CAISO reminded market participants that they should only use outage cards to report de-rates of resources due to physical reasons, even though SCs may reflect the cost of operating their resource or managing their resource’s state of charge through the submission of economic bids.

Load Consumption Working Group

The CAISO established the Load Consumption Working Group (LCWG) to explore the ability for PDR to consume load based on ISO dispatch, including the ability for PDR to provide regulation service. LCWG re-stated the objective to create market rules to "allow for bi-directional modeling and bidding" for non-exporting energy storage resources.

On September 19, 2016, the CAISO published its Second Revised Straw Proposal that included LCWG's recommendation to create an 'inverse' baseline to measure additional consumption and to allow bi-directional frequency regulation without energy settlement. The LCWG also determined that this issue of load consumption settlement is within CAISO/FERC jurisdiction due to direct impacts on wholesale rates. According to the LCWG, there are still open issues that require continued vetting of assumptions.

On December 21, 2017, the LCWG held a call to to discuss the scope of issues to be addressed in the working group and determine the priority of these issues based on likelihood of success in terms of ease of implementation, complexity of regulatory adoption, meeting of broader policy objectives, and costs/benefits. From the CAISO’s view, the biggest issue is to resolve settlement issues for both load curtailment and consumption within a single day using the existing 10-in-10 baseline methodology, as well as discussing the feasibility of bidirectional frequency regulation participation for PDRs without energy settlement.

During the call, other issues raised by stakeholders were discussed as well, including revenue insufficiency, non-negative consumption bids, retail rate structures reflecting wholesale price fluctuations, and negative bid floor. The lowering of the negative bid floor is of particular interest to CESA, but the CAISO indicated that it does not want a subset of bid parameters for one specific product and therefore said that this issue should be addressed in a broader market initiative.

On April 17, 2017, the CAISO published its Third Revised Straw Proposal without any proposal from the LCWG. Issues discussed in the LCWG are potentially deferred to ESDER Phase 3.

Baseline Analysis Working Group

The CAISO organized the Baseline Analysis Working Group (BAWG) to explore and create additional baselines and settlement methodologies to assess the performance of PDRs when the application of the currently approved 10-in-10 baseline methodology is sufficiently inaccurate. Research has shown that the 10-in-10 baseline methodology has been relatively accurate for many large and medium C&I customers, but not for all customer types.

The BAWG conducted performance analysis on three types of baseline and control group settlement methodologies, and tested four customer groups:

Control group performance evaluation methodologies establish a baseline of load patterns during a curtailment event using non-dispatched (non-participating) customers with similar profiles (load and weather patterns).
Day-matching baselines estimate what electricity use would have been in the absence of DR dispatch, using electricity use data on non-event but similar days.
Weather-matching baselines estimate what electricity use would have been in the absence of dispatch during non-event days with the most similar weather conditions.

On September 19, 2016, the CAISO published its Second Revised Straw Proposal that included BAWG's recommendations for alternative baselines and settlement methodologies. The proposal provides a set of options for residential versus commercial customer classes.

For residential customers, there are two options. The '4-day weather match by maximum temperature' option looks at a customer's non-event days with similar temperature conditions to establish the baseline. Alternatively, the 'randomized control group' option looks at control (not curtailed) and treatment (curtailed) groups to establish the baseline, and requires a good match between the two.
For commercial customers, there are three options. The '5-in-5' option and '10-in-10 with adjustment 20% cap' options are variations of the current baseline. Alternatively, these customers are also offered a 'randomized control group' option.

On April 7, 2017, the BAWG (led by Nexant) submitted its Draft Final Proposal that identifies alternative baselines (day-matched, or weather-matched) for PDR resources and supports the option to use control groups (randomized, propensity score matching) rather than traditional baselines. The basis of this proposal is that the 10-in-10 baseline may be underestimating the load impact from residential customers. The analysis showed that randomized control groups with sample sizes between 200-400 participants were more than twice as precise as day- or weather-matching baselines. For DR Providers (DRPs) that do not have the proposed minimum size of 150 participants, day- or weather-matching baselines can be used as alternatives. All of the recommended baselines have an adjustment period that includes two pre-event and two post-event hours (4 hours total), each with a two-hour buffer from the event.

In implementing the recommended baselines, the CAISO proposes to have the baseline calculations performed by the DRP or its Scheduling Coordinator (SC), with the SC submitting it as Settlement Quality Meter Data (SQMD). The DRP must get its performance methodology approved by the CAISO in advance. A limitation of the proposal is that it does not recommend how to achieve a five-minute derived baseline for PDR participating in the real-time market. In the interim, the CAISO recommends pro-rating the hourly baseline from day-ahead market participation and the 15-minute intervals when participating in the real-time or ancillary services market to create a five-minute baseline.

The proposal does not discuss ways to measure load impacts of behind-the-meter storage resources that are frequently dispatched, therefore, making this proposal less of a concern for CESA members.

Multiple-Use Applications

Multiple-use applications (MUA) involve energy resources or facilities that provide services to and receive compensation from more than one entity.

On July 21, 2016, the CAISO published its Revised Straw Proposal that stated that there are ‘no issues’ with multiple-use applications.

On September 27, 2016, the CAISO held a stakeholder call that reiterated that the CAISO will continue collaborating with the CPUC and track this issue in the Energy Storage Rulemaking Track 2. If and when issues arise, the CPUC indicated that the CAISO will consider it then.

Station Power

Energy for resale is considered 'wholesale' under the Federal Power Act, which means that charging an energy storage device is a wholesale, FERC-jurisdictional activity. Meanwhile, station power is energy consumed to operate a generator and is therefore a retail, CPUC-jurisdictional activity. For station power purposes, the CAISO said it will treat energy storage similar to generators.

The CAISO believes that energy used to charge a battery for later resale, including efficiency losses, should be subject to a wholesale rate. Regarding 'netting,' the CAISO clarified that it does not 'net' retail consumption and wholesale generation as part of its settlement process, which generators do by self-supplying the energy needed for their station power load.

On September 27, 2016, the CAISO held a stakeholder call that provided several options for station power treatment, but will defer to the CPUC to act first on settling this matter. The CAISO suggested that it could revise the CAISO tariff definition to explicitly exclude charging energy as station power, revise its tariff later to be consistent with IOU tariffs, or treat negative generation as positive such that energy storage resources can net charging energy.

ESDER Phase 3 (Stakeholder Process)

Background

In Phase 3, the CAISO proposes the following topics as part of Phase 3 of the ESDER Initiative, which started in September 2017:

Development, if feasible, of a load consumption product for DR resources and participation in the regulation market
Defined rules for energy storage modeled as NGRs to qualify as a use-limited resource
Modeling daily cumulative MWh charge and discharge limits based on bid parameters for NGRs
Any issues on MUAs identified in Track 2 of the CPUC’s Energy Storage rulemaking proceeding

Issue Paper

On September 29, 2017, an Issue Paper was issued to kick off ESDER Phase 3. Phase 3 will continue to identify and evaluate opportunities for increased participation of transmission grid-connected energy storage in the CAISO market. For PDR and Reliability DR Resource (RDRR) models, the Issue Paper highlighted the following issues to be considered in this new phase:

When and how to set start-up and minimum load costs, and the impacts of a 0 MW Pmin on its real-time dispatch
Application and use of minimum and maximum run-time constraints
Recognition of a notification time, if applicable
Inability for some DR resources to respond to a marginal dispatch
How to set and update the qualifying capacity value of weather-sensitive DR resources (e.g., A/C cycling programs)
Difficulty in meeting minimum participation size thresholds due to aggregation rules requiring a DR resource to confine locations to within a sub-LAP served by the same LSE
Inability to recognize contribution of load curtailment from EV station equipment (EVSE) separately from the facility load

The CAISO has indicated that the load shifting product will be one of the top priorities for ESDER Phase 3. CESA has been working with the CAISO staff to develop a load shifting NGR product and has begun by considering product features and any potential barriers to these features. CESA has been collaborating with the CAISO staff on whether the PDR or NGR model is the better vehicle and whether traditional market and product features of load curtailment (e.g., Net Benefits Test) are applicable to load consumption. Some of these barriers include:

The inability of DERPs to be eligible RA resources due to specific policy provisions in the DRAM
The requirement for NGRs to be in-market and settle 24x7 rather than to opt out of CAISO metering during some intervals
The inability for LSEs to forecast and schedule load separate from NGR market participation

In addition, the CAISO staff indicated that it would evaluate the parallel between the NGR and PDR participation models with respect to minimum participation size requirements, performance measurements with directly-metered load and generation, seamless movement between load consumption and load curtailment, and capabilities to bid negative prices and quantities. For the NGR model, the CAISO highlighted the following issues:

New bid parameters or outage procedures to reflect non-physical limitations of energy storage resources (e.g., based on warranties and performance guarantees)
Market mechanisms, such as multiple bid stacks, for managing state of charge (SOC) and throughput limitations
Establishment of use-limited status for NGR resources

CESA sought to ensure that our top priority items are addressed in ESDER Phase 3:

Enhancements to NGR for managing SOC and throughput limitations and authorizing use-limited status
Enhancements to NGR and PDR representing commitment costs
Development of a load shift product
Enhancements to PDR to allow fleets of ‘storage on wheels’ to compete as V1G
Consideration of NGRs in multiple-use applications (e.g., less than 24-hour participation)
Consideration of PDR and DERP aggregation rules (if not too resource intensive or complicated)

CESA also recommended that some non-priority issues (e.g., wholesale market participation model for microgrids) be excluded from the scope to ensure our issues are addressed. CESA has fostered strong relationships with the CAISO staff, has pre-shopped our key issues with them, and is one of the main stakeholders they want to hear form on this matter. There is a good chance that most of our top issues will be in scope in this initiative.

See CESA's comments on October 18, 2017 on the Issue Paper.

On November 6, 2017, a stakeholder meeting discussed the potential scope for DR, MUA, and NGR issues. Below are the potential scope items that were proposed in the Issue Paper (with CESA’s priority items highlighted):

Two CESA members, eMotorWerks and Stem, presented on PDR load curtailment by electric vehicle supply equipment (EVSE) and the load-shift product development, respectively. CESA and Stem advocated for a ‘minimum viable product’ for a load shift product but raised issues related to whether NGR or PDR is the right model for this product, and how different factors would apply depending on the model (e.g., minimum size, baselines, bid curves versus baselines, metering, and qualification for capacity contracts). During the meeting, eMotorWerks also presented on the adaptation of the Metered Generator Output (MGO) approach approved in ESDER Phase 1 to the Metered Device Input (MDI) for EVSEs.

On December 8, 2017, the Market Surveillance Committee (MSC) held a meeting to discuss the Commitment Cost and Default Energy Bid Enhancements Initiative, Transmission Access Charge Initiative, and the load shift and load consumption product development work. CESA attended the call to voice support of the load shift product that could help to address overgeneration with in-market solutions, increase market access to different resources, and increase liquidity of resources to address market needs. The MSC is an independent body of industry and academic experts that provides comments, critiques, and recommendations about the CAISO market monitoring process as well as other various market issues. This body is important to the degree that support from MSC is needed for any new market designs.

On January 18, 2018, a Phase 3 working group meeting was held to further vet policy issues and items to be considered for the initiative scope. Some key energy storage issues will be included in the scope, including the “load shift product”, which will likely be (for now) an energy-storage-only product to allow access by BTM resources to help address grid “overgeneration” conditions. However, the CAISO remains on the fence about how to prioritize among myriad DR or other NGR model enhancements. For some NGR matters, the CAISO is seeing that new resource schedulers have a steep learning curve, but that the underlying model may be mostly workable. CESA supported the inclusion of load shift product development but also continued to advocate for pathways whereby energy storage resources can represent and honor usage restrictions (i.e., throughput limitations) on the cycling of energy storage systems, which may be helpful in managing warranty terms and conditions. Ideally, there will be paths to represent any limitations via economic signals that can be expressed to and in the CAISO’s market. In some cases, however, it may be important for energy storage resources to “exit the market” due to excessive usage. One way to achieve this latter outcome is through the authorization of “use-limited status”, which allows energy storage resources to exit the market using a “use-limited outage” and avoids exposure to capacity availability penalties in that month (i.e., RA Availability Incentive Mechanism). If still unavailable in the subsequent month, any resource may need to line up replacement capacity to fulfill an RA obligation. Additionally, CESA’s comments advocated for participation pathways for EV fleets.

See CESA's comments on January 24, 2018 on the Phase 3 Working Group meeting.

Straw Proposal

On February 15, 2018, a straw proposal was issued and a stakeholder meeting was held thereafter to discuss it. The CAISO proposed the following scope for Phase 3:

New bidding and real-time dispatch options for DR
Removal of the single load serving entity (LSE) aggregation requirement and the need for application of a default load adjustment (DLA)
Load shift product for BTM energy storage
Measurement of BTM electric vehicle supply equipment (EVSE) load curtailment
Assessment of multiple-use application (MUA) tariff and market design changes
Develop a process to qualify NGRs for use-limited status
Identify policy developed for commitment costs that apply to NGRs

There are four key issues that will be the focus of CESA. First, the CAISO proposed to remove the requirement of a PDR or RDRR resource aggregation to be limited to one LSE, which is a growing issue due to the rise of Community Choice Aggregators (CCAs), and to develop a “SIBR rule” to only accept bids above the NBT threshold price for these resources, which eliminates the need for the DLA settlement mechanism tied to the resource’s LSE. With the removal of this barrier, multi-LSE aggregations are better enabled to participate as PDR resources. Second, the CAISO included development of the load shift product for BTM energy storage participation as PDR resources in the scope of the initiative. This is particularly important to CESA and represents a means by which BTM energy storage can provide grid services during oversupply conditions. The CAISO did note that this new product does not represent resource adequacy (RA) capacity, would be for directly-metered, non-exporting resources, would allow negative cost energy bids, and would pay full retail rate for all charging energy. In a way, this new product would provide critical grid services during oversupply conditions while allowing BTM energy storage providers to utilize “cheap” charging – i.e., negative wholesale prices would offset some of the retail prices for charging energy. Third, the CAISO responded to support from CESA and EV stakeholders to extend the MGO concept to sub-metered EVSEs. The CAISO thus proposed to develop an option for direct measurement of EVSE load curtailment, independent of its host customer, in response to a market dispatch. Finally, the CAISO proposed to develop a process to define use-limited status for NGRs, including considering potential use-limited qualifying factors and commitments to reflect contract provisions as cycling limitations in the market. While this issue is in scope, the CAISO seeks to first get industry response on where the CAISO market is encountering problems.

CESA generally supported the scope as proposed in the straw proposal and echoed many of the same points made in previous comments. In particular, CESA noted that enhancements for the participation of aggregations of BTM resources are needed, including a Distributed Energy Resource Provider (DERP) model that does not expose retail resources to 24x7 wholesale market settlement. CESA also recommended that the CAISO inform and augment the scope with compliance items resulting from FERC Order 841.

See CESA's comments on March 7, 2018 on the Straw Proposal.

On March 29, 2018, a technical working group meeting was held to discuss the load shift product and measurement of load curtailment for BTM EVSE. The CAISO is proposing to directly measure EVSE load curtailment because a DR resource with EVSE is currently measured without differentiating the performance of the EVSE from the normal load (as shown below). To separate out the EVSE load, the CAISO discussed how it needs to identify the meter that will provide the revenue quality meter data in compliance with its Metering BPM Appendix G requirements. The CAISO also proposed to evaluate EVSE performance using the 10-in-10 customer load baseline methodology, which looks back across a 45-day period to use 10 of the most recent non-event hours to set the baseline. A 20% load point adjustment for the baseline will be applied using the morning hours prior to the DR event to account for temperature differences between the event and historical data.

CESA was supportive of the approach on the 'EVSE baseline' but reminded the CAISO to not require unduly expensive metering or performance measurement solutions. This way, resources with sufficiently accurate meters can compete and be 'measured' via the Scheduling Coordinator Metered Entity (SCME) approach, which exists today at the CAISO for other resources.

The CAISO also discussed how it will create a new load shift product as an option under the Demand Response Provider (DRP) Agreement where a resource can participate as a traditional PDR or RDRR resource or participate as a load shift resource that can economically demand both load curtailment (positive generation) and consumption (negative generation). The key features of the load shift product are:

Load consumption is attributed to non-export, charging BTM storage.
Load consumption does not qualify as RA; only load curtailment qualifies as RA.
Load consumption is an economic product that must submit 5-minute bids in either day-ahead and real-time.
BTM storage participation must be directly metered.
Qualifying resource must register with two separate resource IDs for both consumption and curtailment but can register under same service account.
The Metered Energy Consumption (MEC) methodology will be used to measure and net out "typical consumption" to define incremental value of load shift provided.

CESA was supportive but recommended that the CAISO use a more accurate baseline (i.e., the ‘true average’ baseline) based on the average energy use during an applicable period. Separately, CESA is setting up longer-term conversations on how baselines work for storage-enabled DR, where the baseline approach appears conservative enough that it may cause resources to charge more than the dispatch need. The true average baseline approach also works better when considering the potential lack of timeliness and accuracy of load schedules in many intervals. Additionally, CESA recommended that the CAISO explore and authorize load shift to count for Flex RA, similar to how energy storage charging for IFOM resources work. CESA also advocated for the CAISO to also explore and, if reasonable, authorize participation for load shift from storage resources coupled with NEM systems, since we do not see any double-payment risk as energy is being removed from NEM calculations. Specifically, CESA discussed how the NEM resource will then be encouraged to reduce export and actively reduce oversupply in accordance with a grid signal.

See CESA's comments on April 9, 2018 on the technical working group discussion

On April 30, 2018, a revised straw proposal was issued that proposed several changes to an earlier straw proposal in response to stakeholder feedback. Building on the March 29, 2018 technical working group meeting and in response to CESA’s comments on the PDR load shift resource (PDR-LSR), the CAISO will have the MEC and metered generator output (MGO) account for both the consumption (charge) and curtailment (discharge) of non-event hours to determine a typical use measurement. The CAISO rejected SDG&E’s concerns about bid cost recovery (BCR) of both resource IDs resulting in over-payment, responding that it will calculate BCR separate for each resource ID. The CAISO also rejected SDG&E’s proposal to expand load consumption under PDR-LSR beyond just negative bids, responding that PDR-LSR will incur higher costs by bidding load consumption in the positive range and that PDR-LSR is intended for energy storage to take advantage of negative prices.

No changes were proposed for measurement of EVSE performance, finding that a majority of stakeholders supported their proposal. The CAISO noted that EVSEs are similar to an energy storage device in that they are physically separated from the host facility and performs differently from the host facility’s load curtailment resources (e.g., EVSEs are not temperature sensitive).

There were a number of other issues scoped in Phase 3 that were changed from the straw proposal to the revised straw proposal. Of note, the CAISO updated the proposal to offer an hourly and 15-minute bid option for PDRs and removed the proposal to offer an hourly bid option with the ability to change the bid once within the hour. A scheduling coordinator (SC) will thus be able to submit an economic bid in the real-time market rather than having to self-schedule.

CESA supported the CAISO’s proposed ‘middle-ground’ baseline for determining typical use for PDR resources, which is superior to the more conservative baseline methodology. CESA also supported the combined PDR-LSR approach (e.g., bidding, product specifications, baseline calculation methodology) but advocated for how the LSR range should be eligible to be counted as Effective Flexible Capacity and for how bid cost recovery may be needed if the LSR side (consumption) of a resource has a different ramp rate than the PDR side (discharge) of a resource. Finally, CESA supported the flexible and user-friendly approaches to implement the EVSE baseline but sought clarification on whether the accuracy standards of on-board EV telematics are sufficient to act as the EVSE meter.

See CESA's comments on May 21, 2018 on the revised straw proposal

While most of Phase 3 has focused on BTM energy storage issues, CESA is also working to get use-limited status for IFOM energy storage resources to allow it to leave the market at times without RA availability penalties, similar to the treatment that hydro resources receive. CESA is working with the CAISO to convey how this is an important development, especially for high-cycling energy storage resources to maintain battery lifespan, and potentially propose whether the average state of charge parameter can be used to establish use-limited status. However, in our comments, CESA supported tabling the resolution of this issue to some later stakeholder process because of the limited deployments of NGRs, leading to limited data or concrete ideas to propose solutions on use-limited eligibility criteria.

On June 5, 2018, a meeting was held on the revised straw proposal to discuss a couple key changes to the PDR-LSR product. First, the CAISO indicated that it will move away from two resource IDs to one where a single bid will be submitted under one resource ID for the CAISO to optimize the resource. The Net Benefits Test (NBT) is not expected to change on the load curtailment side even though the PDR-LSR will be providing both load consumption and curtailment under one resource ID. The CAISO explained that a single resource ID was preferred based on views expressed by the Department of Market Monitoring (DMM). For example, with two resource IDs that are not connected, DMM discussed how there could be a conflicting dispatch issue where the curtailment resource ID has a minimum run time (e.g., 1 hour), a consumption bid has been awarded, and the CAISO does not have visibility of the minimum run time requirement on the curtailment side. Second, the CAISO also introduced potential resource parameters for the new PDR-LSR product, including maximum charge/discharge and minimum charge/discharge. Despite having a single resource ID, the CAISO explained that bid parameters may be different for the load curtailment versus the load consumption side, though stakeholders reiterated the need to not overly complicate this product and instead move toward a minimum viable product.

There were no changes related to the energy services that the PDR-LSR product can provide, the requirement to directly meter the energy storage resource, paying full retail rate for all charging energy, resource adequacy (RA) qualification only for the load curtailment portion, and applying non-export rules. No modifications were made to the PDR-LSR performance evaluation methodology either, as the CAISO proposes to continue measuring and netting out “typical use” to define incremental value of load shift provided. In addition, the CAISO noted that the PDR-LSR product will still be eligible for bid cost recovery and for dispatchability in the 5-minute and 15-minute markets.

Finally, the CAISO presented examples of performance evaluation calculations for the PDR-LSR product using the “net export rule” that derives the generation value of the energy storage device. Load served by the storage device (charging) is expressed as a positive quantity and its output in discharging mode to serve onsite load is a negative quantity. A typical use calculation for either curtailment or consumption will sum the typical curtailment value (simple average of 10 non-event hours) and typical consumption value (simple average of 10 non-event hours) and subtract this total from the generation value of the energy storage device using the net export rule. The difference is whether the PDR-LSR event was load curtailment or consumption, which determines whether the typical use value is above or equal to zero or below or equal to zero, respectively. Meanwhile, the CAISO proposed how the performance evaluation methodology for the load curtailment of facility and EVSE can be calculated separately using the 5-in-10 baseline methodology for similar days and non-event hours.

On June 25, 2018, a technical working group call was held to review the final design proposal and discuss performance evaluation methodology. The CAISO presented the near-final proposed design for the PDR-LSRproduct, which will allow for the provision of grid services for both the decrease or increase of load. Key features of the PDR-LSR include:

Direct metering of BTM energy storage is required
Resource must pay full retail rate for all charging energy
The same service account must be utilized
Load curtailment is eligible for RA capacity eligibility (status quo) and non-exporting rules and net export rules for performance evaluation are applied
Load consumption is ineligible for RA capacity and ancillary services, but PDR-LSR resources are able to bid a negative price for energy
Use of 15-minute interval data is required and bidding options must be uniform (15-minute or 5-minute dispatchable)
Pre-market registration of PDR-LSRs for both curtailment and consumption is required, but both resources may utilize the same service accounts
Load curtailment can bid at or above $0 while load consumption can bid from -$150 (bid floor) to $0
Load curtailment and consumption is eligible for bid cost recovery and will be calculated separately

A key change was that the CAISO proposed to return to the two resource ID model after having proposed a potential path of a single resource ID model for the PDR-LSR at the June 5, 2018 technical working group meeting. The CAISO indicated that bidding requirements can be implemented to avoid the conflicting dispatch issue. On performance evaluation methodologies, the CAISO clarified that the 10-in-10 typical use calculation will be separately calculated for load curtailment and consumption, with 10 non-event “like” days specific to the 15-minute interval of the “event” is selected. In other words, “event days” are considered as either a dispatch (on the curtailment or consumption side) or outage in the CAISO market and both curtailment and consumption events will be taken out in choosing non-event 15-minute intervals. Additionally, the CAISO clarified that there will be separate baselines and performance evaluation for sub-metered PDR-LSRs and premises, but noted that this construct is not intended to allow for two separate registrations for the premise and BTM energy storage resource where there could be two dispatch signals.

Draft Final Proposal

On July 11, 2018, a Draft Final Proposal was issued that made a number of small changes. First, the CAISO corrected a description of the hourly bid option where a DR resource will indeed be a "price taker" for the full hour it is scheduled at the 15-minute market price but determined that it is not feasible for DR resources to receive a guaranteed price in the first 15-minute interval under the hourly bid option because the Hour-Ahead Scheduling Process (HASP) runs approximately 45 minutes before the hour and the dispatch is based on advisory prices. Specifically, the CAISO explained that the resource's hourly block is scheduled before the first 15-minute interval price is set and 22.5 minutes before the first binding interval, making all four pricing intervals of the advisory as advisory.

Second, the CAISO provided further details on the new PDR-LSR product. The resource will need to register two separate resource IDs (curtailment, consumption) containing the same service accounts and 15-minute granularity is needed in determining event and non-event intervals for performance evaluation purposes. The move to 15-minute granularity is favorable and more accurate for measuring the "typical use" of a sub-metered energy storage device using the MGO methodology. The CAISO also explained that an event that occurred at an earlier interval does not justify the removal of an entire day. In response to DMM's scenarios, the CAISO explained that it will enforce ramp rates to ensure PDR-LSRs are able to meet its dispatch in a given interval, utilize existing market functionalities (e.g., not include startup times), and rely on the market optimization engine to manage when consumption and curtailment resource IDs are both expected to respond to a dispatch.

Lastly, no major changes were proposed on the removal of the single LSE requirement and the default load adjustment and the measurement of EVSE performance. Despite SCE's concerns about EVSEs lacking a dedicated meter for the resource, the CAISO said that it will just monitor the potential use cases but still move forward with the proposal.

CESA was supportive of the Draft Final Proposal but expressed our ongoing desire to further evolve the typical-use baseline to the “true-average approach” because the 15-minute interval baseline calculation can be more accurate than the hourly averaging approach. The hourly averaging approach may cause market participants to have to “over-deliver” due to how the baseline affects their settlements. CESA also voiced support for the EVSE load-reduction participation model and rebutted concerns expressed by the IOUs about hypothetical performance outcomes that can be managed through existing rules.

See CESA's comments on July 27, 2018 on the Draft Final Proposal

On July 26, 2018, a redlined Revised Draft Final Proposal was posted that provided minor clarifications and modifications that that RDRRs are not eligible for the hourly and 15-minute real-time bidding options due to their real-time emergency response nature.

Tariff Implementation

On April 22, 2019, despite initial indications that ESDER Phase 3 implementation would be completed in 2019, the CAISO announced that it is delaying implementation of the PDR-LSR product, EVSE sub-metering, and removal of the single LSE requirement for PDRs until Fall 2020. However, by Fall 2019, the CAISO indicated that it will still be implementing hourly and 15-minute DR bidding options.

On September 3, 2019, the CAISO submitted a tariff filing to FERC on several enhancements from Phase 3:

Providing hourly and fifteen-minute scheduling options for DR resources in the real-time market
Removing the requirement that DR resources aggregate within a single LSE
Converting the net benefits test from a settlement adjustment to a bid floor

On July 16, 2020, the CAISO filed the Phase 3B tariff amendments in Docket ER20-2443 that would:

Allow EV charging stations to have a separate load curtailment measure when providing demand response with onsite load
Creating a DR participation model that facilitates “load shifting” capabilities and accounts for when behind-the-meter energy storage charges and discharges at optimal times

First, the proposed tariff included the addition of a PDR Load Shift Resource (PDR-LSR) wherein DR resources with BTM storage devices can participate in both load consumption and load curtailment. Two Resource IDs will be assigned to the same Resource to allow Consumption versus Curtailment participation (PDR-LSR). This option will likely be unavailable for DRAM resources and other retail programs where sub-metering is not allowed or used. Second, the proposed tariff revisions will enable sub-metered EVSE to participate in load curtailment.

CESA support of the tariff filing. The comments by PG&E and SCE add caveats to CAISO’s tariff filing to preempt any concerns that the CAISO tariff changes do not immediately unlock the ability of EVSEs to participate in PDR using submetering methods and for BTM storage to participate in the PDR-LSR model, given the number of changes needed at the CPUC level. To a degree, the IOUs are correct in the need for CPUC to approve the EVSE submetering protocols and the MGO baseline for PDR-LSR for use in resource contracts and programs, but CESA does not see these concerns as being an insurmountable barrier that requires significant IT system upgrades or standards beyond industry-accepted ones, as the IOUs have argued in the Transportation Electrification proceeding (R.18-12-006) and Demand Response proceeding (A.17-01-012). Some of these issues may need to be addressed in the new Multiple-Use Application proceeding, which CESA is considering efforts to petition to launch a rulemaking, if not initiated by the CPUC.

See CESA’s comments on August 5, 2020 on the FERC Tariff Filing

A number of other parties were in support of the CAISO tariff filing, including Enel X, Olivine, and CEDMC, an association representing energy efficiency and demand response companies. PG&E and SCE were supportive but caveated their support with certain key changes needed and/or areas to monitor. PG&E, for example, highlighted the need to have corresponding retail IOU systems (e.g., baselines, Rule 24 reforms, and IT systems) need to be in place and adopted by the CPUC for PDR-LSR to be fully realized. PG&E also recommended that the tariff filing be modified to institute a two-hour buffer period before and after the PDR-LSR event window when selecting non-event days to avoid biases in baseline calculations and better capture typical use.

Meanwhile, on the EVSE submetering modifications, PG&E noted its efforts to adopt submetering protocols to be revenue grade and meet CAISO and utility specifications (i.e., ANSI 0.5% accuracy class) and highlighted how Rule 24 prohibitions against split loads, where a single service account cannot be served by more than one registered DRP at one time, thus prohibiting the EVSE provider as the DRP if another DRP is operating for the facility master meter. SCE recommended that EVSE submetered participation be monitored for gaming purposes, highlighting concerns that the EV could switch from EVSE submeter to the master meter to show load curtailment.

The CAISO requested that FERC issue and order approving the proposed revisions by September 15, 2020, with an effective date of October 1, 2020. Activation of Phase 3B proposals is planned for Fall 2020.

• Default Energy Bids (DEBs)

Background

Default energy bids (DEBs) are used to prevent resources from exercising market power by replicating resource marginal costs, thus ensuring that wholesale prices are just and reasonable and avoid non-competitive outcomes. Local market power mitigation (LMPM) is utilized to replace market bids with marginal cost when the CAISO detects potential market power; however, DEBs are not constructed for storage. In effect, depending on the unmitigated bids, DEBs could change dispatch instructions or reduce the entire bid curve. The CAISO expressed some concern that energy storage sells very little energy into the system.

Phase 4

On February 6, 2019, the CAISO published its Issue Paper for Phase 4 of this initiative and held a stakeholder call on February 13, 2019 that proposed to address several topics, including bidding requirements to optimally use energy storage resources. Since the CAISO must ensure wholesale prices are just and reasonable under the Federal Power Act, which involves mitigation measures to minimize the exercise of market power and non-competitive outcomes, the CAISO wanted to consider the potential market impacts and mitigation tools applicable to storage resources. NGRs are not mitigated for local market power at the moment.

Storage market participants expressed concern about the CAISO's focus on market power mitigation measures without further CAISO analysis on the problem but generally agreed with the need to bid in variable operating and maintenance (VOM) costs in bids in multi-interval optimization and bid cost recovery (BCR) to reflect wear and tear costs of cycling. Current VOM costs are zero. Providers also commented on the fact that NGRs today cannot have the same maximum charge rate (Pmin) or maximum discharge rate (Pmax) at all times, which is the function of the resource's state of charge (SOC) - i.e., a battery cannot physically charge at its usual maximum rate when it is getting close to 'full' and cannot discharge at its usual maximum rate when it is getting close to 'empty'. Meanwhile, BTM storage providers recommended that the scope of the initiative be expanded to include NGR barriers for BTM storage resources.

See CESA’s comments on March 4, 2019 on the Issue Paper

ESDER 4 Issue Paper DEB Mitigation 1.png

The CAISO is considering three options: (1) set DEB equal to expected energy prices for the next hour; (2) use expected profit-maximizing approach that includes charge-discharge time as a variable input, which accommodates different peaks and troughs, and potentially models costs to switch between charging and discharging ; and (3) estimate actual charging costs plus roundtrip efficiency loss factors. The IOUs and storage providers expressed confusion on how the spread bidding concept would work when there are no discernable peaks and troughs and concern about how different storage technologies may need to be treated for bid mitigation. Questions were raised on whether it is reasonable to allow bids to rise, potentially far above the normal “expected value”, on extreme weather days. While acknowledging that bid mitigation has not been needed for storage thus far, DMM recommended that these issues be addressed now to avoid a hastily developed solution later on.

Though the CAISO observes market power mitigation issues for energy storage that is increasingly being found to be on the margin, CESA recommended that Phase 4 focus on educating stakeholders on market power mitigation while considering designs and implementation structures in Phase 5. CESA indicated that further analysis is needed to understand if the market power risks are realistic before considering any measures.

See CESA’s comments on April 1, 2019 on the Issue Paper Stakeholder Workshop

Stakeholders mentioned that storage resources may have daily cycle limitations and total lifetime cycle limitations -different from the CAISO’s proposal to use expected energy price and associated dispatch behavior - regarding multi-level optimization, which may cause earlier end of life of batteries. As follow-up, the CAISO staff reached out to CESA to connect with members to better understand VOM costs, where CESA discussed how it will be challenging to determine the appropriate spread to cover the wear and tear costs.

On April 29, 2019, the CAISO published its Straw Proposal and held a stakeholder call that discussed updates on each of the scoped items. The CAISO identified three primary cost categories: charging energy, roundtrip efficiency losses, and cycling costs. The CAISO was unclear on whether to include cycling or replacement costs in DEBs (since this is a complex function around depth of discharge) but was considering the use of VOM adders covering raw materials consumed from generating energy and the use of major maintenance adders covering costs incurred from starting or running a resource, based on past and expected maintenance that are applied to start and minimum load costs. The CAISO proposed three potential solutions: (1) a semi-customizable DEB that includes expected energy prices and discharge duration (using 50% of maximum discharge); (2) create a storage-specific variable cost adder based on industry-wide averages; or (3) calculate all specific costs for individual storage facilities. The proposed DEB would be calculated as a single value for the entire range of output from PMin to PMax but could still bid above the DEB, with mitigation only triggered when market power is detected. The CAISO favored Option 1, with an additional 10% adder similar to other DEBs since Option 2 may inappropriately apply the same costs for all storage facilities and Option 3 would be overly complex. CESA recommended that the CAISO ‘slow down’ and create customizable pathways for market power mitigation and DEB calculations of storage resources.

See CESA’s comments on May 17, 2019 on the Straw Proposal

Many other stakeholders challenged the CAISO's proposal in that it does not sufficiently account for mitigation on the charging side and/or relies on an assumption that a storage resource cycles less than once per day. Overall, this issue seems to require much more additional work.

On August 21, 2019, a stakeholder call was held to follow-up on DEB discussions. The CAISO shared a paper that identified cycling costs as the primary cost driver and included a "rainflow" model to account for cycling costs (i.e., in multiple small segments). It quantified the idea that deeper discharges are more expensive in a quadratic relationship between total cost and cycle depth, though the speed of discharge was not found to impact costs. As a result, the CAISO proposed two options. First, the CAISO proposed a model that includes a multiplier applied to the 'distance' dispatch SOC when below the maximum SOC. The benefit of modeling resources based on maximum cycle depth is that it aligns with increasing marginal costs and the price for any discharge increases as SOC decreases; on the other hand, it may grossly overestimate the cost to produce since it assumes costs at maximum cycle depth. Second, the CAISO proposed an alternative model that includes a multiplier applied to the difference in SOC from one interval to the next. The benefits of modeling resources based on total costs for cycle depth is that it more efficiently dispatch resources for energy and more consistently produce the correct price on average, but it may overestimate costs for large dispatches when cycle depth is thin and underestimate costs for small dispatches when cycle depth is deep. Both proposed models thus have cost adders that will be included in the market optimization for bids and DEBs.

CESA continued to support a customizable pathway for DEBs for energy storage resources but also expressed our preference for the CAISO’s proposed Option 2 to reflect how storage marginal costs are dynamic and depend on the project specifics as well as degradation factors due to state of charge, depth of discharge, and cycling. For example, the storage operator has the ability to adjust the state of charge of the storage unit so that any award amount aligns with an increasing marginal cost.

See CESA’s comments on September 4, 2019 on the Revised Straw Proposal

On October 21, 2019, the CAISO published its Revised Straw Proposal and held a stakeholder meeting to discuss key changes. The CAISO proposed a dynamic DEB calculation that can change on an interval-by-interval basis with depth of discharge or specific dispatch instructions sent to the resource. Under the “rainflow” methodology, the DEB would apply to the entire output of the storage resource, including both the charge and discharge portion of the resource bid. The cost to discharge in the equation below will be zero for the entire charging portion of the bid.

ESDER 4 RSP Storage DEB Equation 1 - 2.png

The CAISO proposes a methodology to estimate costs that a storage resource may pay to charge since this will impact the price at which it will economically discharge (i.e., higher fuel costs mean higher energy prices needed to economically sell power). Specifically, the methodology will use current day-ahead prices to estimate the marginal cost a storage resource may pay to procure energy in the day-ahead up to its full capacity, using the fourth expected lowest hour of prices in the upcoming day for four-hour storage resources. Expected prices will be calculated based on past prices at this resource location.

ESDER 4 RSP Storage DEB Equation 2 Energy Costs 3.png

Currently, the CAISO is not proposing a methodology to account for parasitic losses. These costs may be accounted for by the storage resource’s average SOC and a variable describing how much that state of charge degrades over time. However, the CAISO is proposing to account for round-trip efficiency losses.

Meanwhile, for cycling costs, the CAISO leveraged the findings from the Xu, et al. study to provide additional detail to two potential models previously shared in a stakeholder call based on its understanding that the dispatch costs for batteries have two main drivers: (1) depth of discharge (DOD); and (2) average SOC. A perfect “rainflow” methodology would account for both, but the CAISO indicated that it cannot do that now due to computational constraints. Thus, the CAISO came up with two formulas, each prioritizing different factors.

Option 1 is the total depth of discharge model that makes SOC the primary factor that drives the cost of dispatch. Cycling costs are calculated dynamically and are directly related to the SOC for the resource, and the costs to discharge will increase as the SOC value decreases. In this case, a 1% discharge when a resource is almost fully charged (e.g., 90% SOC) is much more economical (i.e., cheaper) than a 1% dispatch when that same resource is almost fully discharged (e.g., 10% SOC). The value of represents the cost of discharge that the resource would incur if the resource were to be dispatched down to 0% SOC. This formula is favorable in that it makes sure that the DEB will always be equal or greater than the cost of the battery, but it may grossly overestimate the cost of dispatching the battery, thus making it less likely to be used.

ESDER 4 RSP Storage DEB Equation 3 Total Depth of Discharge 5.png

Option 2 is the individual depth of discharge model that makes the DOD the primary factor that drives the cost of dispatch. This formula assumes the maximum costs of cycle depth per dispatch during every interval, regardless of prior dispatches and current SOC. In this case, a 1% dispatch is valued the same way regardless of SOC. Instead, dispatch cost increases as DOD increases. The value represents a multiple of the same cost, so that the values were related to the specific MW dispatch received by the resource. These values do differ between the day-ahead and real-time markets. This formula is good at efficiently dispatching resources and producing more accurate prices on average. Nevertheless, it is limited in the sense that it overstated costs at high SOC and understates them at low SOC.

ESDER 4 RSP Storage DEB Equation 4 Individual Depth of Discharge 6.png

Finally, the CAISO proposed to include an opportunity cost adder to the DEB for storage resources based on the highest price(s) corresponding to the storage duration of the resource. For example, a four-hour storage resource would have an opportunity cost adder that includes the estimated prices in the fourth-highest priced hours of the day.

ESDER 4 RSP Storage DEB Equation 5 Opportunity Costs 7.png

For each of the variables in the equation above, the CAISO plans to collect this data from storage resources to put into the master file. To align DEBs with market bids, the CAISO proposes to allow storage resources to vary its market bids based on SOC or dispatch instructions. The CAISO is also exploring the possibility of negotiated DEBs as well.

CESA appreciated the thoughtfulness of the CAISO's DEB proposal. However, CESA recommended that the CAISO eventually develop a methodology that does not require the CAISO and storage resources to choose calculation methodologies that prioritize one cycling cost driving factor over the other, though we express a slight preference toward the methodology that would encourage greater utilization of storage resources (Option 2). CESA also recommended a broadening of the opportunity cost adder categories and refinement of roundtrip efficiency data inputs.

See CESA’s comments on November 12, 2019 on the Revised Straw Proposal

On May 20, 2020, the Draft Final Proposal was published that, in contrast to the Revised Straw Proposal where DEBs were dynamically calculated on an interval-by-interval basis, the CAISO will use a significantly simpler approach to cycle depth costs based on daily resource production values and will solicit documentation from storage resources on both energy and opportunity costs, and apply the higher value to the (cycle cost) component of the DEB. Non-linear marginal costs are difficult to model and the CAISO would be departing from its paradigm by updating DEBs throughout the day. The CAISO will need to collect information in the Master File (i.e., roundtrip efficiency, storage duration, cell degradation costs) and storage bids to construct DEBs. The DEB framework includes three components:

Energy costs: The CAISO assumes storage will charge in the periods with the lowest costs. Rather than using historical prices, this proposal focuses on using market power mitigation data from unmitigated bids in the day-ahead market, which will be incorporated in the successive IFM run. Resources will be assumed to cycle once a day, but a subset of resources may be considered for DEB adjustments that can cycle more than once per day, via consultation with the CAISO.
Opportunity costs: The CAISO seeks to estimate the expected price a resource could discharge if fully charged, corresponding to the storage duration (e.g., fourth highest hours of the day if capable of four-hour storage duration). Each resource will be mapped to a representative bilateral hub to scale the prior day’s prices.
Cycling costs: The simplified approach to utilize a value submitted by market participants and vetted by the CAISO will be used. The CAISO justified this based on RFO responses and conversations with manufacturers who noted the minimum specifications of one cycle per day to lead to generally consistent cycling costs. The CAISO has not included a means to represent or capture cycling incremental to one cycle a day.

The DEB formula would be as follows, where: En is the estimated cost for resource to buy energy, is the energy duration; η is the round-trip efficiency; is the variable cost; and OC is the opportunity cost.

The DEB will be applied to the entire positive and negative output of a storage resource, not to only the discharging portion of the resource bid. The opportunity cost component of the DEB will be calculated as follows, where: OC is the opportunity cost, DAB is the day-ahead bilateral hub; t is the interval (day); and is the storage duration for the resource. The OC calculation will be computed differently in the real-time market and the day-ahead market.

ESDER Storage DEB OC Final Proposal 9.png

The CAISO performed analysis on this DEB calculation based on this proposal and modeled how a resource would run when bidding to discharge at the DEB. The analysis assessed actual pricing data for all days in 2019 and for two different nodes priced at NP-15 and SP-15. A four-hour lithium-ion battery with 80% roundtrip efficiency and a $20/MWh assumed degradation operating cost was assumed. This analysis showed that the opportunity cost outweighed the variable costs when price spreads are highest (e.g., winter), whereas the opposite was true when prices are generally higher (e.g., summer).

ESDER Storage DEB Example Analysis 10.png

The option to utilize customized DEBs is an important part of this aspect of the proposal, which offers optionality and flexibility if the DEBs and data sources identified by the CAISO are not applicable, especially for different use cases and technology types. CESA was partially supportive of the effort made across various proposals in this initiative but expressed how they still require significant revisions to ensure that they support different energy storage use cases and/or do not hinder or discriminate storage participation. Specifically, the default energy bid proposal needs to account for different services being provided in the CAISO market as well as the incrementally higher costs for storage systems that are able or seek to cycle more than once per day.

See CESA’s comments on June 10, 2020 on the Draft Final Proposal

• Demand Response (DR) Operational Characteristics

Background

DR resources receive dispatches to move between Pmin and Pmax. Market respects the minimum run time parameter because it will commit a DR resource to its Pmin. Certain DR resources can only provide a single sustained response from its Pmin of 0 MW. A DR resource can use existing parameters, such as registering a Pmin just below its Pmax, identifying a minimum load cost (MLC), defining a maximum daily energy limit, or choosing an hourly bid option in the Master File. For DR resources with a non-zero Pmin and identified MLC, DR resources will be optimized in the residual unit commitment (RUC) process. If committed in RUC, the DR resource will be instructed to its Pmin (just below Pmax) and the market will honor the minimum run time and maximum daily energy limit.

The maximum output of certain DR resources can vary due to their weather-sensitive nature. When a weather-sensitive DR resource bids its RA-qualifying capacity into the day-ahead market, depending on the weather, it may be unable to deliver its full RA amount in real-time. If the resource cannot legitimately bid its full capacity and deliver it under its must offer obligation, the resource will be assessed penalties through the Resource Adequacy Availability Incentive Mechanism (RAAIM).

The CPUC adopted load impact protocols (LIPs) as a defined set of guidelines to estimate the load impacts of IOU DR programs. LIPs are a combination of ex post and ex ante assessments of load impacts used to determine the load reduction capability of each demand response program. Ex post impacts consider historical demand reductions during actual demand response events. Ex ante load impacts estimate load reduction capability for each month using 1-in-2 and 1-in-10 peak conditions. Ex ante impacts are forward looking and based on historical load impact performance. LIPs generally rely on regression analysis to predict average customer load and estimate DR program load impacts using independent variables including weather conditions, month, time of day, and day of the week.

Phase 3

The CAISO designed the hourly and 15-minute bidding options for PDRs to extend notification times and longer duration interval dispatches.

Phase 4

On February 6, 2019, the CAISO published its Issue Paper for Phase 4 of this initiative and held a stakeholder call on February 13, 2019 that proposed to address, among other things, the operational characteristics of Proxy Demand Resources (PDRs), including weather-sensitive DR resources.

In response, CESA recommended that the Phase 4 scope be expanded to better focus not only on key NGR model changes for IFOM resources, but also to better accommodate key capabilities for BTM and MUA participation structures. CESA specifically recommended that the CAISO incorporate weather adjustments to the MGO baseline.

See CESA’s comments on March 4, 2019 on the Issue Paper

On March 18, 2019, a follow-up stakeholder workshop was held on the Issue Paper to finalize the Phase 4 scope and to start a deeper discussion on in-scope items after considering stakeholder comments. No solutions were identified on the Pmin and run time issue but the CAISO discussed the issue in detail. Stakeholders recommended a maximum run time parameter as well.

For weather-sensitive DR, the CAISO discussed how to apply approaches used for variable energy resources (VERs) that are also weather-sensitive in nature – e.g., how to perform a LOLE study and establish an ELCC value for weather-sensitive DR to inform CPUC consideration for an appropriate qualifying capacity (QC) methodology to count as RA, which is typically done with load impact protocols (LIPs) for utility. The CAISO sought feedback from stakeholders on potential forecasting methodologies for SC-submitted weather sensitive DR forecasts and how the CAISO could validate and approve these forecasts. Some stakeholders questioned the use of the ELCC of weather-sensitive DR for operational purposes when it has traditionally been used for planning purposes.

On April 29, 2019, the CAISO published its Straw Proposal and held a stakeholder call that discussed updates on each of the scoped items. The CAISO explained that hourly bid options and non-zero commitment costs at zero Pmin are adopted proposals that will be implemented in Fall 2019, which could address this issue. However, the CAISO also proposed other solution options DR resources could use existing bid parameters (e.g., minimum load cost, daily energy limit) or develop a new maximum run time parameter. The CAISO expressed concern with a maximum run time parameter for PDRs with zero Pmin since a PDR may be dispatched to its Pmin and reach its maximum run time parameter without providing any curtailment. It would also be the most effort to implement since it would be introducing an additional parameter, though it gives the PDR an ability to signal its program hour limitations.

For weather-sensitive DR, the CAISO proposed to use bids as the dataset for ELCC calculation to calculate the QC value of variable-output DR resources. In addition, the CAISO is considering how to adapt VER bidding rules to weather-sensitive DR, where SCs would submit forecasts, which would set their must-offer obligations. As a result, the variable-output DR resource would not be required to bid up to the RA quantity but rather to the forecasted quantity, exempting it from RAAIM similar to solar and wind resources. However, the CAISO needs to consider ways to eliminate any incentives for submitting inaccurate forecasts. The CAISO favored ELCC calculations because LIPs rely on historical data from past DR events, including test events, but do not consider a resource's contribution in all hours, including loss-of-load-expectation (LOLE) hours.

Many DR parties as well as SCE strongly opposed the ELCC calculation since DR resources represent a broad class of resource types, DR is not passive like solar/wind and can be actively dispatched, and RA Program examines historical data performance during the availability assessment hours (AAHs) for all resources other than dispatchable generation. They added that LIPs are forward-looking assessments that look at the hours of future availability needs.

On August 21, 2019, a stakeholder call was held to follow-up on DR operational characteristics discussions. Specifically, the CAISO informed stakeholders that it will provide informational ELCC values for DR resources with data inputs on DR resource availability (e.g., number of calls, maximum call duration, hourly load profile). The CAISO also sought feedback on the feasibility of DR providers to submit resource capability in real tim, similar to how VERs provide production and meteorological data every four seconds.

• Multiple-Use Applications

Background

Non-Generator Resources (NGRs) are 24x7 wholesale market resources comparable to all other supply resources. NGRs are thus financially settled for charge or discharge in a given interval, regardless of whether the resource received a CAISO dispatch instruction.

Phase 4

On February 6, 2019, the CAISO published its Issue Paper for Phase 4 of this initiative and held a stakeholder call on February 13, 2019 that consider MUA rules and application to CAISO market participation – e.g., 24x7 settlement rules for NGRs.

Establish RA counting for DERP model
Develop ‘less-than-24-hour’ participation requirement for DERP (e.g., by creating a baseline)
Incorporate ‘spread bids’ for energy storage in the Day-Ahead Market
Review outage rules for NGRs and DERPs
Review RAAIM formulas for NGR and DERPs
Improve the management of customers in PDR groupings
Address various scheduling and dispatch limitations for NGRs
Value solar exports in the NGR and/or PDR models

See CESA’s comments on March 4, 2019 on the Issue Paper

On March 18, 2019, a follow-up stakeholder workshop was held on the Issue Paper to finalize the Phase 4 scope and to start a deeper discussion on in-scope items after considering stakeholder comments. The CAISO responded to stakeholder comments on a range of BTM issues, which they view as not desirable to use a centralized, top-down structure for an increasingly decentralized system. Specifically, the CAISO said that further discussion is needed outside of this initiative (e.g., with utilities and CPUC) on assigning multiple resource IDs under a single service account and the removal of the 24x7 participation requirement and RA qualification for DERAs before taking these on in the ESDER Initiative. Due to implementation delays, the CAISO said it cannot take on making PDR-LSR technology agnostic, which was suggested by several parties. Furthermore, the CAISO said it will respond to and implement the FERC orders and directives, so it does not need to be specifically addressed here. Finally, the CAISO explained that physical net export onto the grid is not prevented for PDRs, but they are not compensated due to legal- and policy-related double payment issues (e.g., already paid via the NEM tariff).

CESA supported removing the 24x7 settlement requirement for non-RA resources utilizing the DERP model. In addition, CESA supported the CAISO providing a forum to discuss potential QC methodologies for multi-technology DERs. In addition, CESA offered comments on how Phase 4 should be scoped, especially for an increased focus on DER-related market participation pathways (e.g., opportunities to provide Regulation, Order No. 841 updates to avoid double payment of transmission fees, customer ID limitations for capacity-differentiated dual DR participation).

See CESA’s comments on April 1, 2019 on the Issue Paper Stakeholder Workshop

On April 29, 2019, the CAISO published its Straw Proposal and held a stakeholder call that discussed updates on each of the scoped items. The CAISO did not have an MUA-related proposal but instead requested stakeholder comment on load forecasting, settlement, and accounting issues. CESA offered comments on how a less-than-24x7 hour settlement of the NGR model is appropriate for multiple reasons, including for creating a non-discriminatory path to the market for DERs.

See CESA’s comments on May 17, 2019 on the Straw Proposal

On August 21, 2019, the CAISO held a stakeholder meeting to clarify that the non-24x7 nature of BTM resources is under the assumption that the resource is participating as a DER aggregation under the NGR model, not the PDR model. DR resources under a PDR model are not allowed to net export onto the transmission system, per CPUC jurisdictional rules. PG&E highlighted that there is currently no way for an LSE to account for changes in services between retail, distribution, and wholesale, thus requiring communication standards between the DER and LSE for correct load forecasts. CESA recommended three options: (1) ex post settlement; (2) reporting to UDCs throughout the billing cycle; or (3) estimation methodologies or tools to remove retail settlements. Meanwhile, others such as IEP and SCE were concerned about double counting and double compensation issues for non-24x7 participation for BTM resources via the NGR model.

CESA expressed that settlement approaches have already been developed in the CPUC’s MUA Working Group but also agreed with the CAISO that load scheduling effects should be considered if market entry and exit is allowed for BTM resources. At the same time, CESA noted that load scheduling of BTM resources may represent ‘noise’ compared to broader system-wide loads and recommended a conferral process to be used to account for BTM resource impact on distribution systems.

See CESA’s comments on September 4, 2019 on the Revised Straw Proposal

On October 21, 2019, the CAISO published its Revised Straw Proposal and held a stakeholder meeting to discuss key changes. Based on stakeholder comment, the CAISO observed that there is no definitive solution with how LSEs will forecast and bid load with BTM DER participation and that several stakeholder-proposed solutions would require clarification from the CPUC. The CAISO reiterated its views that a simple extension of the DR model to net-exporting of BTM resources is not feasible for technical, operational, and jurisdictional reasons. The CAISO argued that it does not have jurisdictional authority or the visibility to establish methods to account for wholesale versus retail activity and transactions.

• Real-Time State of Charge (SOC) Management

Background

The CAISO introduced the Non-Generator Resource (NGR) model in 2012 to allow for wholesale market participation of energy storage resources. Over the years, a number of enhancements have been made to the NGR model to better operationalize energy storage resources in the real-time market (RTM) where storage is subject to shorter optimization horizons, resulting in potential deviations from their day-ahead schedules. Self-schedules can be utilized but the lag between market execution and bid submission deadlines makes this challenging.

Phase 4

On February 6, 2019, the CAISO published its Issue Paper and held a stakeholder call on February 13, 2019 that proposed to address a number of topics, including the CAISO’s market optimization of NGRs (i.e., real-time state of charge [SOC] management, effects of multi-interval optimization) and NGR participation agreements. The real-time market optimization horizon may impede scheduling coordinators (SCs) from optimally managing their NGR over the day. The real-time market optimizes schedules over a 1 hour and 45 minute time horizon that does not consider conditions later in the day. Additionally, the market does not ensure that the resource state of charge (SOC) at the end of the time horizon is sufficient to meet future dispatches beyond the real-time market horizon. With tools to manage the SOC, an SC could better ensure that its energy storage resource can meet its day-ahead schedules later in the day.

An NGR may receive an uneconomic outcome if the price in a future interval does not materialize as anticipated. Due to the CAISO’s multi-interval optimization, a resource is economic over the market horizon considering its single binding interval dispatch and each of its advisory interval dispatches. There are instances when a resource receives an award to charge, which may be higher than its bid for the financially binding interval, but the optimization identifies a future interval with greater economic incentive for the resource to discharge. However, if future prices do not materialize, this may result in a revenue shortfall for the binding interval, which is addressed through real-time bid cost recovery (BCR).

Furthermore, the CAISO currently utilizes both the Participating Generator Agreement (PGA) and Participating Load Agreement (PLA) to facilitate the implementation of NGRs in the CAISO markets. In order to reduce administrative burden and improve efficiency, the CAISO proposed to consider allowing NGRs to participate in the CAISO market solely under the PGA.

Establish RA counting for DERP model
Develop ‘less-than-24-hour’ participation requirement for DERP (e.g., by creating a baseline)
Incorporate weather adjustments to MGO baseline
Incorporate ‘spread bids’ for energy storage in the Day-Ahead Market
Review outage rules for NGRs and DERPs
Review RAAIM formulas for NGR and DERPs
Improve the management of customers in PDR groupings
Address various scheduling and dispatch limitations for NGRs
Value solar exports in the NGR and/or PDR models

See CESA’s comments on March 4, 2019 on the Issue Paper

On March 18, 2019, a follow-up stakeholder workshop was held on the Issue Paper to finalize the Phase 4 scope and to start a deeper discussion on in-scope items after considering stakeholder comments. In order to meet future-interval desired discharge, the CAISO proposed that the NGR could provide a desired SOC of 100% in interval prior to discharge. Stakeholders generally supported the concept, but some parties recommended an optional SOC parameter, greater use of outage cards, or implementation of end-of-day (as opposed to hourly) SOC. Several stakeholders raised concerns about the economic inefficiency of having storage resources reach a certain SOC at any cost.

Meanwhile, regarding multi-level optimization, even though stakeholders requested that BCR rules be applied to all resources or to allow for opt-out of multi-interval optimization, the CAISO found these suggestions unnecessary.

CESA supported the discussion of SOC management and multi-interval optimization for NGRs as well as potentially removing the 24x7 settlement requirement for non-RA resources utilizing the DERP model. In addition, CESA commented on the need to use the Participating Generator Agreement for NGRs, rather than having two agreements, to support IFOM storage as transmission resources.

See CESA’s comments on April 1, 2019 on the Issue Paper Stakeholder Workshop

On April 29, 2019, the CAISO published its Straw Proposal and held a stakeholder call that discussed updates on each of the scoped items. The CAISO proposed that the SC submit an end-of-hour (optional) SOC parameter as well as other resource constraints (e.g., maximum or minimum SOC) that will take precedence over economic outcomes in the market optimization. The end-of-hour SOC parameter will be ignored if it falls outside of the resource's minimum and maximum SOC values. SCs are able to update their real-time bids at any point after the day-ahead market and up until the respective real-time market closes. In essence, this SOC parameter would function as another resource constraint to the market optimization. CESA supported the steps to authorize SOC management at the end of an interval but proposed additional considerations.

However, if the resource is dispatched uneconomically due to the SOC parameter, the CAISO proposed that the NGR would be ineligible for bid cost recovery, similar to the rules in place for self-scheduled resources. Similarly, the NGR will be ineligible for BCR in an interval where the submitted end-of-hour SOC is greater than the current SOC while the awarded value is at physical minimum, or is less than the current SOC while the awarded value is at the physical maximum.

Additionally, the CAISO will not allow resources to opt-out of the multi-interval economic optimization, where SCs can bid costs and use the new SOC constraint to manage a resource to meet needs outside of the wholesale market. Contrary to some stakeholder comments, the CAISO argued that an NGR's energy revenues plus BCR payments should cover an NGR's bid-in costs - i.e., whole to their marginal cost - since SCs should be able to bid in variable O&M costs represented as a $/MWh bid.

Overall, CESA supported the Phase 4 efforts but also recommended an additional issue be considered in this initiative or its own standalone initiative. Specifically, considering the discussions around NGR optimization and enhancements, CESA recommended that scheduling pathways for solar-plus-storage should be available at the CAISO and should recognize a resource’s operational plans to maximize solar-based charging. Meanwhile, other stakeholders raised concerns with the SOC parameter as restricting the economic bidding of resources, not sufficiently accounting for multiple-use applications, among other things. Instead, one party recommended an SOC range to provide additional flexibility while others supported the optionality of this parameter.

See CESA’s comments on May 17, 2019 on the Straw Proposal

On October 21, 2019, the CAISO published its Revised Straw Proposal and held a stakeholder meeting to discuss key changes. First, the CAISO shared that it will view ancillary service awards as the more "binding" parameter as compared to the end-of-hour SOC parameter, ensuring that the ancillary service awards are met. Second, the end-of-hour SOC parameter will be represented as a minimum and maximum range, which gives the option for flexibility for some or the option to meet a targeted value for others by setting the minimum and maximum equal to each other. However, the CAISO rejected proposals to have "true spread bids" for end-of-day SOC and remain energy neutral by the end of the day since this preference can already be reflected in bids and could lead to inefficient outcomes. No changes were made to the BCR proposals, where a storage resource is ineligible for BCR when bids are uneconomic to meet the SOC parameter. CESA supported the revisions in the end-of-hour SOC proposal.

See CESA’s comments on November 12, 2019 on the Revised Straw Proposal

On May 20, 2020, the Draft Final Proposal was published that affirmed that SCs can opt to submit an EOH SOC MWh value with their bids in the real-time market and make updates up until the relevant real-time market closes. The SC can represent the EOH SOC parameter as a minimum (i.e., charge up to this MWh level regardless of market prices) and maximum (i.e., charge up to this MWh level if economic) MWh range, constrained by upper and lower charge limits. The market will respect ancillary services awards when an SC submits an infeasible EOH SOC value but cannot guarantee meeting a targeted EOH SOC range when storage is providing energy and ancillary services simultaneously.

Notably, the CAISO removed its proposal for an end-of-day (EOD) SOC parameter proposed with a 0% to 10% minimum range. More alarmingly, CAISO cited the Business Practice Manual (BPM) for Reliability Requirements Section 7.1.1 that in arguing that an SC should not submit an EOH SOC parameters that is below the resource’s must-offer obligation for storage resources claiming RA. According to potential proposals from the RA Enhancements Initiative, self-schedules and EOH SOC parameters that fall below the resource’s contracted value may be treated as a reduction in the availability of the RA resource and thus lead to a capacity derate under the unforced capacity (UCAP) methodology. CESA expressed concerned with CAISO explaining that RA resources cannot use the EOH SOC parameter because it would violate MOOs, thus limiting the usefulness of this tool.

Furthermore, this proposal modified a storage resource’s BCR settlement in hours when EOH SOC bid parameter or self-schedule has the potential to create an uneconomic dispatch. NGRs will be ineligible to receive BCR for an hour with an EOH SOC bid and the hour preceding this bid, and self-scheduling NGRs will also be ineligible for BCR in the hour before the self-schedule. This was justified since the resource should bear the associated costs of this uneconomic movement, rather than having the CAISO uplift the costs to aggregate demand. Revenue shortfalls will not be counted towards the daily BCR settlement during ineligible hours, but revenue surpluses in these hour(s) will offset shortfalls accrued during other intervals during the day. Finally, the CAISO proposed to align visibility of the EOH SOC bid constraint to the same binding intervals for both the 15-minute market (FMM) and the 5-minute real-time market (RTED) markets.

CESA was partially supportive of the effort made across various proposals in this initiative but expressed how they still require significant revisions to ensure that they support different energy storage use cases and/or do not hinder or discriminate storage participation. Specifically, the EOH SOC proposal could prevent or penalize storage resources providing RA under the UCAP proposals in the RA Enhancements Initiative, and could lead to bid cost (under) recovery by not taking into account the SOC in the two hours prior to the EOH SOC application.

See CESA’s comments on June 10, 2020 on the Draft Final Proposal

Expanding Metering and Telemetry Options (Stakeholder Process)

Background

The CAISO currently has two metered entity options:

ISO Metered Entity (ISOME): The CAISO reads all dispatches under this option, and the ISOME participates in the market at all times. Everything that crosses the meter is settled (i.e., 24x7 settlement). ISOMEs have the option of managing the resource by submitting outages.
Scheduling Coordinator Metered Entity (SCME): The CAISO is told what the SCME does under this option. The CAISO developed the SCME option to permit resources to come in and out of the market and be utilized for multiple-use applications.

The CAISO is evaluating additional configuration options for metering and telemetry to reduce barriers for aggregated resource models. The CAISO plans to conduct pilot programs as needed to demonstrate that the alternatives meet CAISO and participant needs, and review and modify CAISO requirements, if necessary.

Phase 2

On June 10, 2015, the Draft Final Proposal was published that explicitly authorized the aggregation of distributed energy resources (DERs), especially energy storage, to provide aggregated products to the market and receive compensation. Specifically, it allows aggregations of at least 0.5 MW that can span one or multiple pricing nodes (although those spanning nodes are limited to 20 MW in size). The CAISO also required each DER aggregation to be located in a single sub-load aggregation point (sub-LAP) to ensure that it does not create additional congestion. At the same time, FERC rejected PG&E’s proposal to impose penalties on those that fail to respond to dispatch instructions in a manner consistent with its generation distribution factors

On June 7, 2016, FERC approved the CAISO Tariff language.

On January 1, 2017, the tariff provisions went into effect that DER aggregations are allowed to meet the minimum 500 kW size requirement to participate in the NGR model.

Flexible Ramping Product (Stakeholder Process) & FRP Refinements (Stakeholder Process)

Background

This initiative aims to enhance the real-time market design by constructing a Flexible Ramping Product (FRP) that compensates resources for providing ramping capability, as well as incentivizes loads, resources, and interties to reduce the significant ramps illustrated by the well-known 'duck curve' diagram. Instead of a Flexible Ramping Constraint (as the market was previously designed), the CAISO aims to procure sufficient ramping capability via economic bids.

The FRP differs from the Flexible Ramping Constraint in several important ways. First, the constraint procured flexibility in only the upward direction in the 15-minute market, whereas the new mechanism procures flexibility up and down in both the 5-minute and 15-minute markets. Second, the amount of flexibility procured and the willingness to pay for the flexibility procured by the new product is determined by a sloped demand curve, rather than a set price-quantity pair at $60/MWh. Third, the new mechanism compensates units providing flexibility, and charges resources that are creating more need for flexibility.

It is important to recognize that the FRP will be linked to the CAISO’s energy market rules. The new product will allow the CAISO to use energy resources for ramping and load following. The market rules will favor fast-responding resources with greater ability to meet projected ramps. The FRP will also attempt to make resources indifferent to whether or not they ramp or deliver energy by allowing awarded resources to be paid at the full energy market price regardless of whether or not they actually have delivered energy.

Specifically, if load or supply resources increase the forecast ramp, the market charges the load or supply resource for the FRP, and may impose charges on these resources that increase the need for flexibility. If load or supply resources decrease the forecasted ramp, the market compensates the load or supply resource. In addition, the FRP procures additional ramping capacity to meet uncertainty in the net load forecast when it is economic to do so. The market allocates the cost for the FRP to cover uncertainty based on a load or supply resources forecast error.

The methodology for determining the amount of FRP procured is as follows: A demand curve is generated for the CAISO area, each balancing area in the energy imbalance market, and the aggregate of all areas. Each specific curve is calculated as the expected cost of a power balance relaxation for each amount of flexible capacity procured for that region. The probability of a power balance constraint relaxation is calculated using historical net load forecast error, and not historical ramping needs.

In September 2019, CAISO published a report that analyzed the price performance within CAISO markets. The analysis showed inefficiencies in the FRP, including the eligibility of FRP for non-5-minute dispatchable PDRs and ramping management issues between the 15-minute market (FMM) and 5-minute real-time dispatch (RTD). This initiative will explore several refinements to the FRP design to improve the effectiveness of the FRP awards in the real-time market

Policy Development

On February 3, 2016, the Revised Draft Final Proposal was approved by the Board of Governors. The rules will likely favor energy storage resources, either standalone or in combination with thermal generators. The actual expected benefit is unclear at this time.

On June 24, 2016, the CAISO submitted its Tariff Amendment filing. CESA submitted brief comments on the benefits of the FRP correcting a known market deficiency for faster-ramping resources, but also suggesting that the FERC should direct further lowering of the bid floor to ensure efficient pricing for downward flexibility

See CESA's comments on July 15, 2016 on the FERC tariff amendment filing.

On August 1, 2016, the CAISO filed an Answer to comments and protests. In this Answer, the CAISO noted that it does not disagree with CESA that a lower negative bid floor may be needed. The Self-Schedule Bid Cost Recovery Allocation and Bid Floor Initiative is slated to consider lowering of the negative bid floor.

On September 26, 2016, the CAISO received authorization from the FERC to implement the new FRP on October 1, as originally requested by the CAISO. FERC rejected calls from some distributed energy providers to make the FRP biddable because the CAISO's frequency regulation service addresses some of these grid issues. FERC agreed with the assessment of the CAISO, which opted for a new product to preserve capacity for regulation and avoid distorting regulation pricing.

To ensure participants and the CAISO are fully prepared for the transition to a new market feature, the CAISO decided to reschedule the deployment of the FRP to November 1, 2016, pending FERC approval of the new deployment date. The approval of the FRP is good news for CESA members. These enhancements will better value flexibility and improve upon the previous Flexible Ramping Constraint structure, which at times inadequately compensates and 'holds' flexibility in order to meet ramping needs for intra-hour dispatch.

On November 14, 2019, an Issue Paper was published that highlighted issues related to eligibility, ramping management between the 15-minute market (FMM) and real-time dispatch (RTD), and lack of deliverability due to the EIM transfer and internal constraints. Given that PDRs often bid at or close to the bid cap, the market optimization engine often considers PDRs as having a zero opportunity cost since they are uneconomic to be dispatched for energy. This is an issue if certain PDRs cannot respond to a 5-minute dispatch.

Additionally, the CAISO procures FRP in both the FMM and RTD, with a “buffer interval” in place as the first interval in a real-time unit commitment (RTUC) run horizon, or the interval preceding the FMM, pursuant to FERC Order No. 764 in order to provide sufficient time for tagging purposes for fast and short-start units. Since the FRP requirement is not enforced in the buffer interval, the ramping capability may be lost if conditions change between FMM runs and FRP resources are re-optimized in subsequent intervals.

Finally, the CAISO discussed how transfer capabilities lead to the CAISO FRP requirement from internal capabilities to become zero due to the larger net import and export capability, leading to concerns that the FRP needs not being met if so heavily reliant on external resources, even as the CAISO is the largest driver of the system-wide FRP requirement. Furthermore, the CAISO raised concern with the market not considering locational constraints when procuring FRP, which can result in under-utilization and under-deployment.

As a simultaneous Issue Paper and Straw Proposal, the CAISO proposed several quick fixes as follows:

Eligibility: PDRs that elect the 60-minute and 15-minute dispatchable options in the Master File (i.e., additional scheduling options implemented as part of ESDER Phase 3A proposals) are ineligible to receive FRP awards. This would be a Business Practice Manual (BPM) update.
Ramping management issue: FRP awards should be maintained in the buffer interval up to 100% of the award, which would add enforcement to ensure unit commitment alignment for ramp capability in the FMM and RTD.
EIM transfer and internal constraints: To address this, the CAISO proposed to enforce a minimum CAISO requirement via BPM modification that results in more local awards than system-wide constraint provides. The CAISO also sought to improve deliverability by not awarding FRP to resources that have a zero opportunity cost because of congestion. Instead, the CAISO proposed more granular approaches (i.e., either zonal or nodal), which come with implementation effort and congestion consideration tradeoffs. These solutions would likely require both BPM and tariff changes.

CESA was supportive of these changes as they enhance the FRP – a market product that will likely be a revenue and value driver for energy storage – and ensure some minimum reliance on internal resources. In addition, changes are being considered around ramp management to ensure FRP capacity is reserved and delivered. Since the proposals are largely beneficial for internal storage resources, CESA supported each of the proposals, with a recommendation around ramp management to better ensure that FRP is delivered.

See CESA’s comments on December 6, 2019 on the Issue Paper and Straw Proposal

On March 16, 2020, a Revised Straw Proposal was published. PDR eligibility will be based on being 60-minute dispatchable as the default, while the deliverability enhancement will be based on nodal procurement. The CAISO also described the methodology to incorporate load, wind and solar forecasts into the scaling FRP requirement.

On May 18, 2020, a web conference on the Draft Final Proposal was held, where the CAISO included three major changes since the Revised Straw Proposal:

The date of implementation for the PDR eligibility issue has been pushed to Fall 2021.
The CAISO has proposed a simplified approach to establish a minimum FRP requirement only when a BAA represents 60% of the system requirement.
Deliverability enhancement will be done in a nodal fashion to account for congestion and transmission constraints.

On this last point, the CAISO explained that the FRP uncertainty is distributed to load and VERs (75%) in the deployment scenarios. The demand curve surplus variable is considered as a decision variable at load aggregation points.

CESA expressed how the CAISO’s are in line with the improvement of the FRP framework and beneficial for internal storage resources. CESA offered brief comments in support of each of the proposals, with a recommendation around the establishment of partial minimum FRP requirements for non-pivotal BAAs in order to better signal the need to procure fast-response resources.

See CESA’s comments on June 2, 2020 on the Draft Final Proposal

Date of implementation for PDR eligibility issue has been pushed to Fall 2021. Tariff, business requirements, and BPM changes will be completed between July and September 2020.

Market Reports on FRP Performance

On December 7, 2016, the Market Performance & Planning Forum (MPPF) reported that FRP prices are driven by hourly needs.

On March 6, 2017, the CAISO published its Q4 2016 Report on Market Issues and Performance that revealed that payments for flexible capacity remain low (as a portion of overall energy costs) at less than $0.10/MWh of load. Total payments for flexibility were $1.7 million in November and $2.3 million in December, up from payments of less than $1 million prior to FRP implementation. About 59% of payments during these two months were to CAISO generators, which reflect the majority of flexible ramping capacity awards.

FRP procured extended up to about 1,500 MW in hours ending 8, 9 and 23. Similarly, the downward demand curve extends to over 1,000 MW in early evening hours (15 through 19) and is very small in the late evening and early morning hours.

On May 5, 2017, FTI Consulting presented on the Flexible Ramping Product and reported DMM data showing that the target procurement for upward ramping in the 15-minute market was relatively low in hours 16-21 during November and December 2016, perhaps indicating that the CAISO should review how the target is being set and implemented in dispatch as these hours have shown relatively high levels of power balance violations during the evening ramp.

On July 10, 2017, the CAISO issued the Q1 2017 Market Issues & Performance Report that found that payments for flexible capacity have increased since implementation of the Flexible Ramping Product (FRP), but still remain low overall at less than $0.14/MWh of load. Total payments for flexible ramping capacity in Q1 2017 were about $9.2 million, almost twice the amount of payments in Q4 2016, which totaled about $5 million.

On December 8, 2017, the CAISO Department of Market Monitoring (DMM) also published its Q3 2017 Report on Market Issues & Performance on December 8. There were two notable highlights from the latest quarterly report:

The late August and early September heat waves led to system load peak almost reaching all-time highs (50,116 MW on September 1 vs. 50,270 MW on July 24, 2006), which also lead to near-historic highs in day-ahead prices (greater than $200/MWh during a four-hour period and over $770/MWh in one hour on September 1).
Flexible Ramping Product (FRP) prices continue to be low due to the inclusion of individual FRP demand curves for each Balancing Area, rather than using only the system-level demand curve. Low prices continue to make the FRP a lean revenue stream for energy storage providers.

On February 28, 2020, the Q4 2019 Market Issues and Performance Report was published that found, among other things, the flexible ramping product system-level prices were zero for more than 95% of intervals in the 15-minute market and more than 99% of intervals in the 5-minute market in the upward direction. Prices were zero in all intervals in the downward direction in both markets at the system level. Some resources supplying flexible ramping product capacity are not able to resolve system level uncertainty because of resource characteristics or congestion, reducing the efficacy with which the product can manage net load volatility or prevent power balance violations.

Frequency Regulation

Background

The CAISO procures ancillary services, including regulation up/down and spinning/non-spinning reserves, to meet NERC and WECC reliability standards and to support reliable electric system operations. In addition to the system-wide procurement requirements, the CAISO establishes minimum ancillary service procurement requirements in some of its sub-regions.

On December 1, 2010, the CAISO implemented an ancillary service scarcity pricing mechanism, which is triggered when there is insufficient ancillary service supply with the price automatically rising to a pre-determined scarcity price. The mechanism is reviewed every three years in a report on the details and financial impacts.

On October 10, 2016, the CAISO instituted a new method for determining day-ahead regulation procurement requirements in response to growing needs for regulation to balance variable renewable generation. With the new method, requirements were calculated for each hour, and that calculation was based on observed regulation needs in the same month during the prior year. These requirements are updated approximately monthly. Furthermore, the CAISO adjusts requirements when large weather systems moved across California.

For most of Spring 2016, regulation requirements were roughly double from 2015 levels and set at 600 MW for both regulation up and regulation down during all hours of the day. This has resulted in a significant increase in regulation procurement costs.

Intra-Hour Variability Reports

On July 24, 2017, the CAISO held an onsite workshop to discuss the operational challenges associated with high levels of inverter-based generation, as well as an overview of NERC’s recommendations on essential reliability services to integrate higher levels of renewable resources. The CAISO held this workshop to start a conversation on how renewable resources can support control performance through active power controls and provide frequency response, regulation, flexible ramping, and voltage support. The CAISO highlighted the following trends as pointing to the need for faster units:

Solar/wind production and net load production varies from one day to the next
Actual monthly 1-hour upward ramp could be about 50% of the 3-hour upward ramps for 2016, especially in fall/spring months
Actual monthly 1-hour and 3-hour downward ramps for 2016 were greater than during the summer months, with 1-hour downward ramps being about 65% of the 3-hour downward ramps during the winter months

Operating statistics indicate that the CAISO is moving toward too high frequency and high ACE. Balancing Authority Ace Limit (BAAL) is a real-time measure of area control error (ACE) and system frequency which cannot exceed predefined limits for more than 30 minutes. Frequency Response standards require all BAs to support the interconnection frequency within 52 seconds following a disturbance greater than 500 MW anywhere within the interconnection. The Western Interconnection implemented 23 ‘fast manual’ time error corrections from January through March 2017 and no manual ‘slow time’ error correction.

ACE and System Frequency Distribution Jan-March 2017.png

Increasing levels of intra-hour variability and uncertainty could result in inability to control the interconnection frequency in real-time. The inability to meet its Control Performance Standard (CPS) was due to solar/wind production during certain hours and days, even though the CAISO has met its 12-month CPS1 rolling average. While there is headroom from dispatchable resources to address intra-hour variability in the morning ramp, there are difficulties in addressing intra-hour variability for the evening ramp due to the lack of headroom from dispatchable resources.

The workshop also covered NERC’s recent advisory regarding inverter-based resources that reduce power output during fault conditions on the transmission system. The CAISO has observed large blocks of solar PV generation disconnect from the system - sometimes for extended periods of time - during the normal clearing of high voltage transmission system faults. Between the months of August 2016 and February 2017, there have been eight transmission system faults that occurred in the southern California area that resulted in the unanticipated loss of up to 1,200 MW of inverter based generation. All transmission line faults cleared in four cycles or less, which indicates the transmission problem was resolved very quickly but the solar still tripped off due to the settings and safeguards on the solar farms.

As a result, in its 1,200 MW Fault Induced Solar Photovoltaic Resource Interruption Disturbance Report, NERC recommended a review of inverter control settings for solar PV resources – e.g., add time delay to avoid erroneous tripping and configure to restore output with a delay no greater than five seconds for inverters that momentarily cease current injection. NERC has established an Inverter-Based Resource Performance Task Force, which includes the CAISO and SCE, to address the broader issue of utility-scale inverter-based resources.

Ancillary Service Scarcity Event Reports

In the event that there are insufficient ancillary service offers to meet the minimum reserves requirement, the CAISO triggers an ancillary services scarcity event and reserves will be settled based on a scarcity reserve demand curve instead.

The 2014-2016 Ancillary Service Scarcity Event Report has shown ancillary services event occurrences have increased from 13 of market intervals in 2014, and to 24 and 25 of market intervals in 2015 and 2016. Generally, real-time scarcity events occurred due to load forecast error or transmission congestion, and day-ahead scarcity events occurred mostly due to forced outages or derates of generating resources. There was only one incident on April 12, 2014 whee the cause of the scarcity event was overgeneration conditions, which prevented resources from moving up to provide regulation down. Overall, the frequency of scarcity events were low and the duration of these events were generally short, lasting only one or two intervals. The CAISO believes that the Ancillary Services market is robust enough to recover in a short amount of time and does not see a need to change the Scarcity Reserve Demand Curves.

Frequency Response (Stakeholder Process)

Background

An interconnection needs to have a system frequency that is on average near the scheduled frequency value at 60 Hz to support a reliable and well-functioning grid. Primary frequency response is a service that provides an actual response to a frequency change where additional power is provided to the grid to arrest and stabilize frequency within 52 seconds by automatic, autonomous response either through control devices or ISO-signals based on an algorithm that matches product specifications. Primary frequency response is also typically maintained through 10 minutes after the event or when the frequency has been fully restored.

Conventionally, primary frequency response is provided by large motorized loads and conventional resources with rotating mass, which combined with governor controls provide synchronous inertial response. The more inertia on the system, the quicker the arrest will occur, thereby requiring less primary response to restore frequency. However, with greater shares of renewables coming online, there are concerns about the decreasing level of inertial response and the need for greater primary frequency response resources that can provide a response in a matter of seconds (i.e., fast frequency response). Often the stabilized frequency in the post-event period will be less than the scheduled value but is at a stable and recovering level, after which secondary and tertiary response (provided by regulation and operating reserves) will fully restore the frequency value.

Starting on December 1, 2016, the CAISO will need to comply with NERC BAL-003-1, which requires each Balancing Authority (BA) to achieve an annual Frequency Response Measure (FRM) that is equal to or more negative than its Frequency Response Obligation (FRO). This new standard was approved by FERC on March 29, 2013 to protect against a loss of generation event. The CAISO expects a 2017 FRO of 258 MW/0.1Hz of frequency response, some or all of which can come from resources already on the system. Importantly, compliance with this obligation will be measured on actual performance in providing sufficient frequency response (i.e., primary frequency control) rather than by procurement of frequency response capability, which the CAISO currently does not do explicitly. The CAISO will submit its 2017 FRM by March 7, 2018 and will be assessed for compliance based on the percentage difference between the FRM and FRO among a sample of qualifying events.

In the CAISO's assessment, frequency response performance has not been sufficient to meet NERC’s reliability standards due to the increased portion of renewable generation on the grid and the current market design. The challenge is that there is very little headroom in the resources that have historically provided frequency response (i.e., it cannot move any more above its maximum operating limit), and resources have multiple configurations, performance requirements, signal times, and dispatch operating targets that make it difficult to provide frequency response. In the regulation or spinning reserves markets, only a limited number of resources is awarded and the relationship between unloaded capacity and frequency response capacity is not one-to-one.

The CAISO has divided its compliance process with BAL-003-1 into two stages where Phase 1 addresses near-term compliance and Phase 2 addresses long-term compliance through market mechanisms.

Phase 1

On March 25, 2016, the CAISO Board of Governors approved its Phase 1 design, which proposes to:

Modify requirements (e.g., minimum values for droop, deadband settings) for all participating generators with governor controls (not just those providing spinning reserves)
Establish the authority to procure transferred frequency response from other balancing authorities
Allocate the cost of transferred frequency response to CAISO demand
Clarify CAISO's practice of designating operating reserves procured day-ahead as contingency only reserves in real-time
Clarify that participating transmission owners and CAISO may issue voltage schedules

On April 21, 2016, the CAISO submitted a Tariff Amendment filing to the FERC.

On May 19, 2016, the CAISO filed an Answer to a protest that the proposed rules are discriminatory. In this Answer, the CAISO offers to pursue Phase 2 of its Frequency Response plans later this year. This work will contemplate compensation mechanisms for resources providing Frequency Response inside the CAISO’s footprint. CESA will participate in this docket and has supported procurement of Frequency Response through the CAISO’s centralized market so that Frequency Response providers are adequately compensated both for the services they provide and for any opportunity costs they suffer.

On June 17, 2016, the FERC issued a deficiency letter focused on details of CAISO’s approaches to ensure frequency response capability from synchronous generators and to procure transferred frequency response from other balancing authorities.

On July 18, 2016, the CAISO filed its Response to the deficiency letter.

On September 16, 2016, FERC approved the CAISO’s Tariff Amendment filing, which will clarify and enhance market rules regarding the primary frequency response capabilities of generators with governor controls, and authorize the CAISO to procure transferred frequency response from other BAs in the Western Interconnection (with these procurement costs allocated to load on the CAISO system). As part of the FERC approval, CAISO agreed to compare costs of a FRO ‘transfer’ to another BA Area against the costs of additional Regulation Up. This action provides some opportunity for procurement of incremental Frequency Response capability to result in increased payments to CAISO system resources. The CAISO also committed to evaluate whether a market mechanism should be designed that encourages frequency response capabilities of all participating resources.

The CAISO basically ended up with a forward contract approach to 'buy' PFR from other BAs like BPA and Powerex, both of which have significant large hydro.

Phase 2

On December 15, 2016, Phase 2 kicked off with the issuance of an Issue Paper, which seeks to examine a market structure for primary frequency response procurement and compensation. Specifically, the CAISO will examine:

Whether the current ancillary services paradigm positions the system to be able to sufficiently respond to meet reliability requirements
Whether the current market design produces price signals that incent capital investments on resources to be capable of primary frequency response
Whether capital expenses, opportunity costs, and/or operating expenses should be compensated for primary frequency response resources

CESA recommended that the CAISO focus on market mechanisms for procuring primary frequency response in Phase 2. CESA aimed to foreclose any consideration of interconnection or operational requirements to provide primary frequency response, as contemplated in FERC's Notice of Proposed Rulemaking (RM16-6). CESA also wishes to avoid relying on PFR from other BAs, which can only participate in CAISO through a pseudo-tie, and recommends that the CAISO phase out the Phase 1 solution.

See CESA's comments on January 11, 2017 on the Issue Paper.

On January 17, 2017, the CAISO held a stakeholder call to discuss its request for frequency response data on participating generating units' plant-level and governor-level control systems. This data request likely does not affect CESA members and is related to verifying that generating resources are not overriding their governor responses to provide frequency response except in certain situations.

On February 9, 2017, the CAISO held a working group meeting to discuss long-term options for PFR competitive procurement mechanism. The challenge in creating a market design is that not all resources provide PFR equally, and because the Resource Adequacy (RA) program does not currently consider PFR needs, the CAISO may need to contract with non-RA resources only.

CESA therefore presented on the need for an in-market constraint or product to incent capability and performance while compensating for opportunity costs. This solution would reserve PFR capabilities in the day-ahead and real-time markets, and include mechanisms for calculating how much PFR resources can provide since not all resources provide PFR equally or linearly. When dispatched, PFR resources would settle for energy similar to the Regulation market. CESA also highlighted how energy storage is an efficient PFR provider that is autonomous and instantaneous.

See CESA's presentation on February 9, 2017 at a CAISO working group meeting.

There are still open issues regarding the counting metric for PFR capability and the definition of PFR 'burst' duration (i.e., energy backing a MW of PFR).

CESA subsequently submitted comments on how the changing fleet necessitates new rules to position units to provide PFR and compete to be compensated for this service. CESA reiterated how the CAISO should develop an in-market product, but noted how electrical engineering details on the 'deliverability' of PFR may require further documentation. CESA recommended that the next Straw Proposal should include a PFR 'efficiency ratio' structure as part of an in-market solution to apply to bidders of PFR in the market. But in the near term, CESA suggested that a hybrid approach could be used between an in-market solution and outsourcing or forward-planning approaches because the current fleet lacks to capability to provide PFR capacity in addition to energy and ancillary services. Forward planning approaches may need CPUC consideration. At the same time, CESA recommended a sunset of the outsourcing of PFR needs. Finally, CESA commented on the economic benefits of a Fast Frequency Response (FFR) product that could arrest frequency excursions with a smaller amount of FFR.

See CESA's comments on March 17, 2017 on the CAISO working group meeting.

On August 18, 2017, FERC issued a supplemental request for comments in its NOPR on requiring PFR capability for new interconnections (RM16-6). The NOPR also proposed to establish certain operating requirements, including maximum droop and deadband parameters in the pro forma Large Generator Interconnection Agreement (LGIA) and pro forma Small Generator Interconnection Agreement (SGIA). The NOPR did not propose provisions specific to energy storage resources, and thus requests supplemental comments on whether and when electric storage resources should be required to provide PFR and on the ability and costs associated with PFR capabilities for small generating facilities. The questions, which are a direct response to requests by ESA and AES to partially or completely exempt energy storage resources, ask about methods to accommodate the specific operational constraints of energy storage while still requiring PFR technical capability for interconnection of energy storage.

CESA conducted outreach to FERC staff to convey our views and understand FERC’s intentions. CESA advocated for market-based solutions to ensure that sufficient PFR capabilities are online and thus recommended that FERC take no position on whether energy storage systems should have this PFR capability or authorize regional solutions instead of determining that energy storage systems should be subject to exemptions from this requirement. CESA also answered select questions posed in the request, in case FERC does pursue an interconnections-based approach. Some of our recommendations include ensuring that FERC allows for recovery of the opportunity costs and variable O&M costs for electric storage resources, and that any adopted rules should accommodate ‘gating’ at the right times to enable multiple-use applications.

See CESA's comments on October 10, 2017 on FERC's supplement request.

On August 24, 2018, an Order was issued that responded to three Motions for Rehearing by PJM, Arizona Public Service (APS), and AES that clarified provisions from Order No. 842. First, FERC agreed with PJM that Order No. 842 was not intended to establish a “blanket prohibition” against ISOs and RTOs imposing PFR service obligations on existing facilities, citing how BAs have the right to take the appropriate actions to meet BAL-003-1 requirements. However, FERC denied AES’s Motion to reassess whether compensation for PFR service is prudent due to the greater efficiency in delivering PFR, such as from energy storage solutions because no new information was provided to reassess its previous determination. In Order No. 842, FERC found that the cost of installing, maintaining, and operating a governor or equivalent controls is minimal and thus are considered the “general cost of doing business” and do not need to be specifically compensated.

Flexible Resource Adequacy Capacity Must-Offer Obligations (FRACMOO) Phase 2 (Stakeholder Process)

Background

FRACMOO is an initiative focused on developing rules to enable Flexible Resource Adequacy (RA) capacity to participate in markets. FRACMOO Phase 1 developed rules for how capacity designated as 'flexible' (flexible RA capacity) was to participate in markets, along with other details. FRACMOO Phase 2 is focused on whether further Flexible RA reforms are needed to ensure the monthly RA generator fleet can adequately mitigate overgeneration and related Pmin burden operating challenges, in addition to the already employed upward ramping, system, and local capacity needs. Specifically, the CAISO identified issues related to imports/exports providing Flex RA, pumped hydro resources, and allocation of negative flexible capacity.

CESA's positions will continue to build on the view that energy storage solutions provide important value as ramping and cycling resources, and that the CAISO's rules should fairly value energy storage solutions.

Phase 1

In 2014, FERC approved the CAISO's tariff revisions to implement the FRACMOO Phase 1 proposal. Specifically, the tariff provisions established:

A study methodology for determining flexible capacity needs and allocation of those needs to local regulatory authorities (LRAs)
Rules for assessing the system-wide adequacy of flexible capacity showings
Backstop procurement authority to address system-wide deficiencies of flexible capacity
Must-offer obligations to ensure the CAISO has the authority to commit and dispatch flexible resources through its markets

These changes represented the first ever flexible capacity obligation in any ISO market, recognizing that a RA program should include both the size (MW) of resource needs and the attributes of the resources providing them (e.g., dispatchability, ramp rate). These tariff provisions, however, did not impose requirements on the dispatch frequency of resources or their operational attributes (e.g., start-up time, minimum run-time).

Straw Proposal

On December 11, 2015, the CAISO published a Straw Proposal. The CAISO proposes to allow 15-minute intertie resources to provide Flex RA, capped at 50% of the total Flex RA showing if: (1) the capacity is resource-specific; (2) the LSE has sufficient MIC at the intertie point to cover the resource; and (3) the energy schedule is firm. The CAISO is seeking stakeholder input on whether exports should be allowed to provide Flex RA. For pumped hydro resources, the CAISO proposes to allow such resources with transition times to be eligible to receive Effective Flexible Capacity (EFC) values for their pumping loads as well as their generation output. Finally, on allocation of negative flexible capacity, the CAISO proposes to allow each LRA to allocate negative values to its LSEs, which are then allowed to sell those negative contributions as a credit toward another LSE's Flex RA showing.

On July 7, 2016, the CAISO notified parties of a modified scope for FRACMOO Phase 2 to include a ‘holistic assessment’ of the existing flexible capacity product in meeting current and future needs. The assessment will continue through late Q3. CESA believes the CAISO will defer any major reforms to the CPUC, which has its RA proceeding underway. CESA expects FRACMOO Phase 2 to extend the original FRACMOO rules.

Supplemental Issue Paper

On November 9, 2016, the CAISO released a Supplemental Issue Paper that provides an assessment of the flexible capacity showings to date, a review of the forecasted flexible capacity needs, and efforts to enhance the current flexible capacity product so it can meet the CAISO’s needs into the future. The CAISO has identified six potential issue areas where the flexible RA product can be enhanced:

Ramping speed for the largest single hour and for transitions from low net load to steep ramps
Cycle time for determining daily start requirements
High minimum operating levels (p-min) from both RA and flexible RA resources
Most significant net load ramps occurring on weekends or holiday weekdays
Significant quantities of long-start resources
No means to assess the likelihood of flexible RA showings meeting operational ramping needs

The CAISO may choose to focus its solution on ramping needs for a two-hour time frame, rather than the current three-hour time frame. This change stems from CAISO staff views that the current three-hour approach is being addressed by ‘slow’ longer-start resources that aren’t always fast enough to be committed in time to meet the CAISO’s ‘real-time’ ramp needs. Other ideas for change from the CAISO include:

Changing eligibility requirements based on full cycle-time rather than just minimum down-time (i.e., limiting long-start units)
De-rating the Flex RA count from resources with high P-min values (e.g., by using a ratio of P-min to P-max)
Requiring Category 3 Flex RA resources to be available more of the time and on weekends
Developing assessment tools to validate sufficiency of portfolio

The CAISO has thus re-scoped Phase 2 to include:

Enhancements to the existing flexible capacity product
Imports and exports providing flexible capacity, including any modifications to the Effective Flexible Capacity (EFC) calculation to incorporate flexible capacity
Flexible capacity from storage resources not using the Non Generator Resource (NGR) model
Allocating the negative contributions of flexible capacity requirements

Overall, the goal of Phase 2 is to consider enhancements to the flexible capacity product that increase the overall availability and ramp rate of the flexible capacity fleet, while reducing the minimum operating level of flexible capacity resources. As a starting point, the CAISO aims to review flexible RA capacity showings and forecasted needs, but an initial finding appears to be that the correct market signal is not being sent to ensure flexible capacity is maintained in the long term.

In CESA’s view, these charges are good for energy storage. Generally, the CAISO is moving in a positive direction. CESA will be more focused on the CAISO’s changes to the NGR and PDR models (and less so on the PHS model used by older PHS units). CESA’s goals in this initiative will be to ensure an appropriate and high valuation for energy storage in providing flexibility to address overgeneration challenges and in providing fast ramping and fast cycling (e.g., twice per day) when needed.

CESA continues to urge the CAISO to provide leadership in a downward Flex RA capacity product to ensure reliable grid operations, even though the CAISO may not pursue such reforms in this initiative. Without one, the CAISO appears to rely on exceptional dispatches rather than on a feasibly planned fleet with efficient dispatches. CESA therefore proposes a ‘beta’ version of a downward Flex RA capacity product with a small enough requirement that it would not be economically material but would pave the way for the CAISO to gain experience, develop must-offer obligations, and test concerns of ‘complexity’.

CESA also added comments that the refinements to upward ramp counting and eligibility rules are appropriate for the FRACMOO Phase 2 scope, and the EFC study reforms should be added to the scope as well.

See CESA's comments on January 6, 2017 on the Supplemental Issue Paper.

Revised Straw Proposal

On May 1, 2017, a Revised Straw Proposal was issued (followed by a stakeholder meeting on May 8, 2017). The focus of the Revised Straw Proposal is on supporting fast-ramping and fast-starting resources to help minimize RPS curtailment and mitigate the risk of uneconomic retirements. As it currently stands, the CAISO views the current Flex RA product being overly inclusive, such that long-start, slow-ramping once-through-cooling (OTC) resources make up 25-33% of total Flex RA showings, while not ensuring long-term financial viability for faster ramping resources. In addition, many fast ramping resources are not shown as either System or Flex RA resources in non-summer months, when flexible capacity needs are highest. With continued reliance on long-start and OTC resources, the CAISO fears that the greater Pmin burden will result in steeper ramps and frequent curtailment of renewable resources.

Short-term modifications for 2019 and 2020 are therefore proposed until long-term market mechanisms valuing resources with fast start, fast ramp, and low minimum operating levels (i.e., low Pmin burden) are comprehensively developed. Specifically, the CAISO proposes to change eligibility rules to only allow resources with startup and minimum run times of less than 4.5 hours and with the capability to fully decommit within a single Short-Term Unit Commitment (STUC) interval to qualify as Flex RA; conversely, resources unable to meet this eligibility requirement would be considered “long-start resources” or “long-run resources” and would not qualify as Flex RA. The CAISO believes that these changes will reduce the fleet’s minimum operating levels while increasing its ramping speed. This rule change would leave between 17,000-18,000 MW of the total 35,234 MW of EFC-eligible resources to qualify as Flex RA and would allow fast-ramping resources to also be made available in the real-time market. For 2018, the CAISO predicts the largest monthly flexible capacity requirement to be 15,743 MW, thereby meeting short-term needs despite tighter eligibility requirements. Due to many of the largest three-hour net-load ramps occurring on the weekend, the CAISO also proposes to extend the must-offer obligations for Super-Peak Flex RA resources to all seven days a week (not just non-holiday weekdays, as it is currently). These are all short-term measures while the CAISO works toward developing long-term enhancements over the coming years. A number of portfolio management, resource attribute valuation, and process coordination topics are teed up for long-term discussion.

CESA responded in favor of fast action on the near-term eligibility changes to get more of the capacity needed starting in 2019, considering the high use of the load bias limiter and the recent Stage 1 emergency signals the need for faster flexibility units. CESA conveyed its view on the eligibility changes being somewhat modest but directionally helpful, while the disagreement on specific problems that this initiative aims to address may stem from the expectation of a single durable Flex RA product being developed here. CESA also advocated for immediate development of an Effective Flexible Capacity (EFC) calculation based on a resource’s ramping across two hours, rather than three hours, to meet more complicated real-time ramping needs - not just the study-based needs.

See CESA's comments on May 22, 2017 on the Revised Straw Proposal.

On June 16, 2017, CESA held meetings with CAISO leadership and technical staff to discuss various market issues. The CAISO acknowledged its unclear path to ensure adequate flexibility in its fleet, as the CAISO has made little to no progress in FRACMOO or Regionalization. As a result, the CAISO indicated that it has had to rely on existing reliability tools and authorities, such as the Capacity Procurement Mechanism (CPM). The CAISO appears to be favorably disposed to energy storage in general.

On August 2, 2017, the CAISO held a Working Group call was held on August 2 that previewed the integrated operational and procurement framework for the study to be conducted by the Brattle Group. The CAISO is proposing to ‘reset’ its FRACMOO initiative to reflect a need for independent study of the flexible capacity need. The study framework will analyze operational needs, system capabilities, and operational barriers, which together will be used to define flexibility attribute information that inform flexible capacity needs by type and time horizon and guide improvements to operations and market design. The CAISO plans to develop a Draft Final Proposal, which will be informed by an independent analysis by the Brattle Group before the end of this year, with FRACMOO changes implemented for the 2020 RA year. This plan ultimately should provide a path forward for FRACMOO, which has been stalled by challenges with ‘defining and measuring the flexibility problem’ as well as concerns and preferences for more analysis or no changes by key stakeholders.

CESA supported the plan but recommend several key enhancements. First, CESA recommended that the Brattle Group detail a ‘point and counterpoint’ table of all criticisms on its analysis and/or proposal to identify valid criticisms and prevent them from derailing progress. Second, an aggressive schedule of in-person meetings should be set up for this fall to allow stakeholders to learn and process the information. Finally, CESA noted that reliance on out-of-market action should be affirmed by the CAISO as unacceptable, given their market inefficiencies.

See CESA's comments on August 18, 2017 on the Working Group Call.

On September 26, 2017, a Working Group meeting was held to discuss the CAISO’s operational needs and how the Flex RA product can be reformed to maintain real-time system reliability. The CAISO presented on the increasing need for sustained ramping and ramping speed (up and down), as well as tradeoffs between ramping and curtailment as forecasted net load continues to drop. Some key observations from the CAISO’s report on operational needs include the following:

The three-hour Flex RA capacity is relevant and is showing increases with renewables and BTM PV build-out, but is insufficient to meet all flexible ramping needs going forward as one-hour and intra-hour ramping needs increase.
Ramping needs are not just spring-time issues as actual monthly one-hour and three-hour downward ramps were greater during summer months for 2016.
Downward ramps are comparable to upward ramps in terms of speed and magnitude.
Net load varies from one day to the next due to day-ahead and real-time forecast error of the load and variable generation, creating difficulties for the fleet to meet ramps in real time.

Given these operational issues, the CAISO recommended the following:

The Flex RA fleet needs to cover the entire ramping range over any given month, to have faster ramp rates with potentially shorter notice in real-time, and to ensure an increased regulation quantity and frequency of use.
Net load should be redefined as load minus inflexible capacity since the ‘duck curve’ was based on self-scheduled wind and solar.
Flex RA capacity should provide sufficient economic bid range for the CAISO to dispatch around inflexible capacity.

The CAISO proposes four Flex RA products as a result: (1) day-ahead ramping range capacity; (2) 15-minute dispatchable flexible capacity; (3) 5-minute dispatchable flexible capacity; and (4) regulation certified capacity. With this new framework, the CAISO recommends resource counting rules, startup time and notification requirements, duration requirements, and must-offer obligations to fit these operational needs and product definitions.

Overall, CESA finds the conclusions from the CAISO to be positive for energy storage as it finds that Flex RA products need to address one-hour and intra-hour ramps. While the Flex RA product is currently a three-hour product, the CAISO presented data showing that a three-hour product is insufficient to meet real-time operations. The IOUs do not support the CAISO’s findings and dispute some of the data. CESA supported the CAISO's findings on flexibility needs, the goals of RA, and the use of principles, and advocated for quick next steps to develop these products. CESA also included the following comments:

CESA provides additional analysis showing that three-hour and hourly ramping needs are forecasted to grow under IRP assumptions and scenarios, creating urgency to address this issue as soon as possible since the operational challenges will only grow with time.
CESA supports the proposal for new Flex RA products, including the redefinition of net load.
The new products should align must-offer obligations with grid needs and tighten eligibility requirements accordingly to properly value and compensate resources that meet actual flexibility needs.
Energy storage counting for Flex RA should be for the full range of its charge and discharge.
The CAISO should ensure that resources in all market participation models can qualify for Flex RA under the new proposed framework.
CESA expresses caution about how much interties should 'count' as Flex RA.
CESA also expresses caution against any analysis showing that the current Flex RA fleet is sufficient based on ‘showings’, given that the CAISO data seems to indicate otherwise.
Point-counterpoint responses by the CAISO are needed to move the discussion forward in some instances.

See CESA's comments on October 10, 2017 on the Working Group Meeting.

On November 20, 2017, the CAISO released its Draft Flexible Capacity Framework Proposal and held a stakeholder meeting on November 29 to discuss the proposal, which seeks to meet both anticipated ramping needs and uncertainty within the time scales of the real-time market, including for load forecast, variable energy resource (VER) forecast error, and outages. The CAISO laid out its basis for a new Flex RA framework. First, the CAISO identified the ramping and uncertainty needs that Flex RA should be procured to address. As the CAISO has shown before, the three-hour net load ramps, which can be addressed in the day-ahead market, are projected to continue to increase, while uncertainty between market runs indicates a need to establish new requirements to procure flexible resources in real-time, especially during steep net-load ramp hours where forecast error is greatest. Unlike in the first iteration of its proposal, the CAISO is no longer proposing “regulation certified capacity” as a new Flex RA product, as regulation is already procured in the day-ahead market and there is sufficient regulation capacity available in the system.

CAISO Draft Flexible Capacity Framework Proposal - Nov 2017 -2.png

Second, the CAISO quantified the capacity needed to address all identified needs. Currently, overall Flex RA need is determined by the calculation of the maximum forecasted three-hour net load ramp plus contingency reserves, but due to the increasing levels of uncertainty across different time scales, the CAISO proposes to add uncertainty to the three-hour net load ramps to determine overall flexible capacity need.

CAISO Draft Flexible Capacity Framework Proposal - Nov 2017 -3.png

Finally, the CAISO proposed criteria regarding how resources qualify for meeting those needs. Given these flexible capacity needs, the CAISO proposes a day-ahead shaping product that does not account for uncertainty and two new market products that manage uncertainty at different time scales: 15-minute and 5-minute Flex RA products. Details still need to be worked out. For example, resource counting for the 5-minute Flex RA product would be based on the number of MWs the resource can ramp in five minutes, but since uncertainty is relevant across all hours, it may subject a resource to must-offer obligations across all hours. For the 15-minute Flex RA product, similar counting rules would apply but intertie resources would be eligible to provide this product. Other issues related to startup time, cycle time, capacity factor, and Pmin for all products must be considered and resolved as well.

CESA expressed support for the CAISO’s framework for valuing fast-ramping resources such as energy storage to meet both predictable ramping needs and uncertainty-driven ramping needs. In general, CESA was supportive of the principles and goals of the framework. However, CESA noted that need assessments should be based on forward-looking conditions, not just historical conditions. Regarding the proposal, CESA recommended that the eligibility criteria value fast-ramping resources and that the framework should link to ‘steel in the ground’ or resources physically guaranteed to be available. CESA added that energy storage resources are use-limited and should count as high-grade flexibility. In addition, considerations of deliverability and of “decoupling” a resource’s Flex RA capacity from its System RA and Local RA capacity should be explored.

See CESA's comments on December 13, 2017 on the Draft Flexible Capacity Framework Proposal.

On January 31, 2018, the CAISO published its Revised Flexible Capacity Framework Proposal and held a stakeholder meeting to discuss it. In line with the original proposal, the CAISO recommends maintaining the three Flex RA product framework to address predictable and unpredictable flexible capacity needs, despite some stakeholders preferring different approaches (i.e., market design fixes instead of new capacity products). The CAISO already conducted an assessment of flexible capacity needs and identified how uncertainty can amount to more than 6,000 MW in any single day, even during the largest net-load ramps.

With this framework in place in defining the different needs, the CAISO recommended a few key changes in the way that it determines the overall flexible capacity need. The current flexible capacity needs determination is based on the largest forecasted three-hour net load plus 3.5% of expected peak load. In its original proposal, the CAISO proposed changes to adhere to the new NERC BAL-002 Standard for determining the contingency reserve requirement. But in response to stakeholder suggestions, the revised proposal will remove the upward uncertainty measure from the flexible capacity needs calculation since it is accounted for in the maximum three-hour net-load ramp. The CAISO also adopted CESA’s recommendation to base this needs determination on using historical data to determine the amount of forecast error for gross load and each type of VER to then project future VER and forecasted load.

The CAISO proposes to meet the flexible capacity requirements with three products: (1) day-ahead load shaping product; (2) 15-minute Flexible RA product; and (3) 5-minute Flexible RA product. To simplify matters, the CAISO is proposing consistent must-offer obligations and requirements for resources to have their shown Effective Flexible Capacity (EFC) to be available 24 hours a day for all three products. Overall, the CAISO proposes to determine monthly flexible capacity needs based on the largest three-hour net load ramp for the day-ahead load shaping product and the widest range of uncertainty for all real-time flexible capacity products, with 75% of this day-time uncertainty being used to determine how much capacity must be available 24 hours a day.

The 5-minute and 15-minute Flexible RA products are designed to address real-time uncertainty and thus must have a startup time of less than 60 minutes to allow the CAISO to commit resources in the shortest interval of the real-time unit commitment process. This new eligibility criteria addresses the CAISO’s concern with overly inclusive criteria, leading to a relatively more inflexible fleet. The CAISO also modified its proposal to consider adding Regulation to the 5-minute uncertainty need since it agreed with stakeholders that there may be some overlap between resources addressing 5-minute uncertainty and providing Regulation, which is explicitly procured in the day-ahead market. Meanwhile, the day-ahead load shaping product is intended to meet anticipated ramping needs. This proposal will maintain the 90-minute startup time requirement and will require economic bids to be submitted in the day-ahead market, as well as making all capacity committed in the Integrated Forward Market (IFM) available in the real-time market through economic bids or self-scheduling.

To better ensure resource deliverability of flexibility, the CAISO proposes to modify its existing EFC eligibility to include a new flexible capacity deliverability study that confirms how a resource could be ramped from Pmin to Pmin+EFC during the most stressed flexibility conditions. The new deliverability study will apply to all three products and will better ensure that flexible resources are demonstrated to be delivered for a subset of hours when flexibility need is greatest, which has been shown to be when load and solar output is the highest, rather than having this capability during all hours of the day.

For the first time, VERs will be eligible to provide Flexible RA capacity under this proposal. For VERs, the EFC could be larger than its Net Qualifying Capacity (NQC) during certain months and hours if they are willing to economically bid at less than full output. The VER must-offer obligation will be to the lower of the shown EFC value or the resource’s forecasted output, allowing it to economically bid its EFC during daylight hours and allowing it to bid 0 MW during nighttime hours when there is no generation. By making VERs eligible to provide Flexible RA capacity, the CAISO will thus reconstitute the curtailed wind and solar resources into the three-hour net load ramp value. However, VERs with EFC will now be subject to new replacement and availability rules. While wind resources and Proxy Demand Response (PDR) resources are not capped, solar resources are capped to 25% of the Flexible RA capacity that it could provide for any single product, which the CAISO attributes to uncertainty related to their deliverability to EFC due to weather variability.

Additionally, for all three products, the Energy Imbalance Market (EIM) and purely external resources will be eligible to provide flexibility so long as a Load Serving Entity (LSE) demonstrates that it has sufficient Maximum Import Capability (MIC) capacity. The CAISO adds that imports are already providing Flexible RA capacity today, so it will simply establish new technical requirements for imports comparable to internal resources.

Finally, the CAISO does not propose any major changes to how it will allocate flexible capacity requirements, except that it will look at contributing factors for each product. Each LSE will be required to procure 100% of their monthly needs in year-ahead showings, and the CAISO establishes a process to identify and allocate actions related to any deficiencies. In a limited assessment, the CAISO determines that its current fleet of resources would meet the day-ahead and real-time flexibility needs under this three-product approach.

CESA supported the revised proposal, including the CAISO’s proposal to develop products with ramping capabilities based on short-duration ramp periods and to fully unbundle a resource’s EFC from its NQC, but recommended that additional vetting of the methodology and uncertainty and variability metrics are warranted to ensure the metrics yield logical outcomes that also address the CAISO’s downward ramping needs and self-scheduling effects. CESA added that: (1) details on the proposed flexible deliverability study or authorization process are needed; counting rules, portfolio limits, and approaches for hybrid resources should appropriately value the fast-ramping capabilities of energy storage; the CAISO should explore whether the 24x7 must-offer obligations for real-time flexible capacity providers is appropriate given the potential of demand response and multiple-use energy storage resources; and energy storage resources that have modest transition times to go from charging to discharging should be authorized for Flex RA value that ranges from the appropriately determined Pmax to the appropriately determined P-min.

See CESA's comments on February 21, 2018 on the Revised Draft Flexible Capacity Framework Proposal.

On February 16, 2018, the CAISO submitted its proposal into the record of the CPUC’s RA proceeding.

On April 27, 2018, the Second Revised Flexible Capacity Framework Proposal was issued with most of the foundational framework still in place where three new Flexible RA products (5-minute, 15-minute, and day-ahead shaping Flexible RA). See also the stakeholder meeting was May 3, 2018. The CAISO proposed several material changes from their previous proposal:

The basis for real-time flexible capacity needs will align with the need for imbalance reserves identified in the Day-Ahead Market (DAM) Enhancements, including the data used for the analysis.
The CAISO has removed start-up times as an eligibility criterion for providing Flexible RA capacity.
Must-offer obligations will be limited to day-ahead while all real-time must offer obligations will be determined through day-ahead market awards.
VER EFC values will be determined based on PG&E’s “simple” option, which scales VER EFC relative to the resource type’s contribution to the three-hour net load ramp.
For purposes of real-time flexible capacity counting, energy storage resources will be limited to the resource’s instantaneous maximum output but would be allowed a 15-minute transition time for an energy storage resource to count the full charge and discharge range for the day-ahead load shaping product.
RAAIM for Flexible RA capacity will be assessed only on day-ahead bidding and will be assessed over all 24 hours.

Overall, the CAISO is making progress in evolving capacity rules to meet the growing flexibility needs, even though the CPUC remains in the driver’s seat on rules for RA capacity. In comments filed on May 17, CESA expressed appreciation for the CAISO’s efforts, including the changes made to better reflect energy storage “counting” for EFC, the proposed category of products, and the proposed separate EFC-only deliverability study. CESA commented on the following:

The full flexible range of energy storage should be valued, meaning the full charge to full discharge range of energy storage should ‘count’ towards its flexible capacity, if deliverable.
Minimum start-up time should not be removed as eligibility criteria for the real-time Flex RA Capacity product to more efficiently address flexibility issues.
Hybrid energy storage resources must be counted and fully valued.
The CAISO should continue to explore the right approach to real-time flexibility must-offer obligations for demand response (DR) and multiple-use energy storage systems.

On June 18, 2018, the CAISO held a working group meeting that focused on aligning the efforts in this FRACMOO Phase 2 initiative with the Day-Ahead Market Enhancements initiative, which is developing a Day-Ahead Flexible Ramping Product (DA-FRP). In defining the quantity of real-time flexible capacity needed for each new Flexible RA product, the CAISO will need to align the methodology used for the DA-FRP, potentially by determining real-time Flexible RA needs as a function of load, wind, and solar.

The meeting also discussed proposed changes to must-offer obligations of the new Flexible RA products. The key change is that all Flexible RA resources must submit economic bids for the shown EFC value for all 24 hours in the day-ahead market and make all capacity committed and awarded in the day-ahead market available in the real-time market as well. To incentivize resources to bid consistent with their must-offer obligations, the CAISO is exploring alternative availability incentive mechanisms, such as including “tiered pricing” with the RAAIM, or not using the RAAIM and instead having EFC derates of resources in the following year. Flexible RA resources that reach use limitations will be required to provide replacement capacity for real-time Flexible RA capacity products.

Finally, the CAISO staff introduced their new proposed Flexible Capacity Deliverability Study, which will assess the transmission capability of a flexible resource to be ramped to its EFC simultaneously with other flexible resources in the same generator pocket. There are still open questions on how to conduct the deliverability test in different seasons since it may not be appropriate to look only at summer peak load conditions (as done in full capacity deliverability studies), and along the ramping curve because resources may have different ramping rates (e.g., constant, variable).

Several stakeholders were also given an opportunity at this meeting to discuss their views of the FRACMOO proposal. LS Power focused on the details of the FRACMOO proposal, seeking to make distinctions between planning flexible capacity and operational flexible capacity. To unlock real-time flexible capacity, LS Power advocated for addressing the start-up time criteria (i.e., 60 minutes) to ensure optimal resources are procured and counting the full charge to discharge range of the energy storage resource to count toward real-time flexible capacity (not just limited to the resource’s instantaneous output). Powerex expressed its support for the CAISO’s proposal as a significant improvement over the current Flex RA framework but explained that the ultimate success of this new framework will depend on accurate determination of Flex RA requirements (e.g., accurately model ramping and uncertainty forecasts in each month) and accurate assessment of Flex RA supply (e.g., adjust for resource outages).

In addition to the presentations by the CAISO staff and various stakeholders on how to enhance or improve the FRACMOO proposal, the CPUC presented on the separate but related issue of allocating flexible capacity needs across LSEs, where current processes leave most of the flexible capacity procurement burden on bundled customers, in part due to the long-term solar contracts that were procured by the IOUs on behalf of all load. SCE proposed several options to better allocate these flexible capacity requirements, including based on LSE’s portfolio of wind and solar resources, which are sources of real-time uncertainty. Potentially, with SCE’s proposed changes, it would create an incentive for LSEs to procure more “predictable” resources (e.g., solar-plus-storage) to reduce these requirements.

On July 30, 2018, the CAISO notified stakeholders that the FRACMOO Initiative is suspended until the Day-Ahead Market Enhancement (DAME) Initiative is aligned with some of the ideas developed in this initiative. In RA Track 2 testimony, CAISO explained that it will delay implementation of its FRACMOO efforts until the 2021 RA year or later because the CAISO cannot pursue proposed reforms without California Public utilities Commission (CPUC) buy-in. Meanwhile, the DAME proposals are complicated and require more work before implementation, making it unlikely that new market designs will be implemented by Spring 2019.

Hybrid Resource Contracting

Issue Paper

On July 18, 2019, an Issue Paper was published and a working group meeting was subsequently held. Any hybrid resource project’s Generator Interconnection Agreement (GIA) must include provisions to address both components of the resource, regardless of the number of Resource IDs, and can capture schedules for the PGA that limit the generating capability of the on-site generating unit if charging of the energy storage unit only comes from on-site generation. Hybrid resources will also need to execute (or amend) a Meter Service Agreement (MSA). The issue of RPS reporting also came up, where the CAISO affirmed the CEC’s RPS Guidebook guidance that reportable RPS energy from this hybrid resource configuration would be equal to the renewable energy produced net of any losses from storage. However, the CAISO may need to develop new metering requirements and/or new requirements for additional data or inputs from hybrid resource owners to accomplish the necessary RPS reporting.

See CESA’s comments on August 13, 2019 on the Issue Paper

Hybrid Resource Interconnection

Issue Paper

On July 18, 2019, an Issue Paper was published and a working group meeting was subsequently held. If the generating unit will be charged from the CAISO controlled grid at CAISO’s direction, the CAISO explained that the CAISO and the participating transmission owner must study the “negative generation” for reliability impacts or proceed through the load interconnection process for firm load service if a project desires charging at any time. Project sizing is limited by the approved capacity in the GIA, though interconnection customers could propose to install a generation limiting mechanism (e.g., controls, relays) .

See CESA’s comments on August 13, 2019 on the Issue Paper

Straw Proposal

On April 29, 2020, a Second Revised Straw Proposal was published where the CAISO made no major changes on the interconnection pathways for hybrid and co-located resources, affirming that the components behind the POI will be studied independently, including for whether they are synchronous or asynchronous.

Hybrid Resource Market Modeling & Forecasting

Issue Paper

On July 18, 2019, an Issue Paper was published and a working group meeting was subsequently held. For hybrid generation and storage projects, the selection of certain resource ID configurations has numerous market modeling consequences related to the status of the resource components for Eligible Intermittent Resource (EIR), Variable Energy Resource (VER), and Participating Intermitted Resource (PIR) status.

According to CAISO Tariff Appendix A, an Eligible Intermittent Resource (EIR) is defined as a Variable Energy Resource (VER) that is a Generating Unit or Dynamic System Resource subject to a Participating Generator Agreement, Net Scheduled PGA, Dynamic Scheduling Agreement for Scheduling Coordinators, or Pseudo-Tie Participating Generator Agreement.
According to FERC Order No. 764, a Variable Energy Resource (VER) is defined as a device for the production of electricity that is characterized by an energy source that: (1) is renewable; (2) cannot be stored by the facility owner or operator; and (3) has variability that is beyond the control of the facility owner or operator.

VER-Storage Hybrid Configuration Types.png

For example, the CAISO discussed how a solar-plus-storage resource that only charges from on-site generation would retain its status as a VER as defined in FERC Order 764 but could not be certified with PIR status since the CAISO cannot produce an accurate forecast due to the impact of charging or discharging of the paired storage resource. As a result, these resources may need to economically bid or self-schedule in the day-ahead market and adjust schedules in the real-time market, which could lead to Uninstructed Imbalance Energy (UIE) settlements in the real-time market for any uninstructed deviation. By contrast, PIRs have updated forecasts at five-minute intervals that reduce the risk of incurring UIE charges (i.e., flexible ramping allocation charges in the case of PIRs).

When storage is added to an existing EIR resource, the CAISO explained that the current rules will cause the EIR resource to lose EIR and PIR status. In general, the CAISO explained that the charging behavior can cause potential CAISO forecast error to increase, though an alternative option may be to have these single Resource ID configurations to provide their own forecast for VER components, including the installation of project-specific meteorological stations to provide the necessary forecasting information. Given the lack of visibility into the solar forecast and state of charge of the paired storage device, the CAISO is concerned about whether the resources participating in CAISO markets could actually provide the energy or ancillary services awarded through the market, such as when hybrid resources are self-scheduled or bid and can only be updated once an hour at 75 minutes prior to the operating hour.

Hybrid Facility Treatment by Charging Option.png

The marketing modeling implications are simplified if both EIR generating unit and energy storage device are under their own individual resource IDs, with the EIR generating unit being able to retain its PIR eligibility status and the energy storage unit being treated as an NGR. However, even in these cases, forecasting issues could be present, such as if the solar meter is ahead of the storage meter on the gen-tie.

See CESA’s comments on August 13, 2019 on the Issue Paper

Straw Proposal

On September 30, 2019, a Straw Proposal was published and a stakeholder meeting was subsequently held on October 3, 2019 that differentiated between hybrid and co-located resource projects. A key change in the Straw Proposal was around allowing hybrid resources, defined as projects configured under single resource IDs that participates and is optimized as a single resource for bidding and dispatch/settlements, to be able to use a self-provided forecast under the single resource ID model, which the CAISO recognized as being a valid use case for many developers and operators (e.g., for ITC qualification). Previously, CAISO had pushed for a one-size-fits-all model in the Issue Paper that would force hybrid resources on a two resource ID path. Although hybrid resources under a single resource ID would lose EIR) eligibility, the ability to self-provide forecasts better addresses use cases where hybrid resources seek to be treated in the market as an EIR in effect. Furthermore, a number of other positive changes included refinement of the "hybrid resource" definition and more details on how hybrid resources should be metered, scheduled in the market, and provide ancillary services. However, there were still several key areas that likely require clarification and modification, which we detail in our comments.

CESA supported many of the positive changes in the Straw Proposal, particularly around allowing self-provided forecasts. However, CESA commented on additional refinement needed around further differentiating hybrid resources around how they should be treated as generators versus NGRs, which have implications to how these resources should be treated in forecasting, bidding/scheduling, and RA capacity valuation. CESA also commented on the CAISO's interim solution to limit the Pmax of co-located resources to their interconnection rights, resulting in stranded capacity; in response, CESA proposed using limiting schemes and controls used elsewhere for storage interconnections.

See CESA's comments on October 21, 2019 on the Straw Proposal

On December 10, 2019, a Revised Straw Proposal was published that established a new hybrid resource “net-to-grid operational forecast” term that would define the overall capability of the hybrid resource to the grid by incorporating the VER component forecasted output, storage component state of charge, and anticipated charging or discharging operation of any storage component. The resource scheduling coordinator must provide this forecast since the CAISO cannot provide forecasting due to the onsite optimization decisions for charging or discharging of underlying components, though the CAISO provided the option for the CAISO to perform the forecasting for the VER component of the hybrid resource for a fee. All hybrid resources with VER components are required to provide the following data and information to CAISO:

Topographic map
Site information sheet designating CAISO or SC provided VER forecast
Meteorological stations per Appendix Q
VER component real-time forecast (if self-providing VER component forecast)
Meteorological data streaming in real time
Telemetry actuals on VER components
High Sustainable Limit forecast of the VER component

These operational forecasts must be updated with 5-minute granularity for a minimum of a rolling three-hour forward basis and will be used to ensure the hybrid resource market awards and dispatches do not exceed real-time production capabilities of the resource (i.e., upper economic limit). The CAISO said it will be monitoring for “strategic forecasting” that inappropriately seeks to take advantage of price differences between the 15-minute market (FMM) and real-time market (RTD). Finally, for co-located resources, the CAISO will incorporate the interconnection rights constraint in the VER forecasting process (e.g., reductions in VER market awards or output as an input to CAISO forecasting).

See CESA’s comments on January 14, 2020 on the Revised Straw Proposal

On April 29, 2020, a Second Revised Straw Proposal was published where, similar to previous proposals, the CAISO continues to propose that hybrid resources are not classified as VERs, but as NGRs, except for some gas-based hybrids. The CAISO also continues the requirement that a forecast for all variable energy components of hybrid resources be generated, either by the CAISO (pay for this optional service) or submitted by market participants, which should include the submission of:

Topographical map
Site information sheet (designating either CAISO or SC forecasts)
Real-time metrological station data (with meteorological stations in accordance with Appendix Q, Section 3.1)
Real-time forecast data (if SC provided)
Real-time telemetry data
High sustainable limit (HSL)

Outlined previously in the Revised Straw Proposal, the HSL is a real-time telemetered measurement of what the variable component is capable of producing. Relative to the Revised Straw Proposal, however, the CAISO proposed a new “dynamic limit” tool, which will be used to limit the economic dispatch of a hybrid resource. Unlike the upper economic dispatch parameter for VERs today that are based on forecasted generation, this new real-time (not yet day-ahead) tool will only be determined based on values submitted to the CAISO from the hybrid resource SC and will limit the dispatch instruction for the hybrid resource in the positive or negative direction, thereby avoiding infeasible dispatch based on state of charge, renewable available, and charging schedules. The tool will be optional to allow SCs to freely submit bids for all real-time intervals. but will not be available in the day-ahead market at this time.

CESA commented on the need to evaluate different modeling approaches for hybrid resources compromised by VERs and a small addition of energy storage.

See CESA’s comments on May 28, 2020 on the Second Revised Straw Proposal

Hybrid Resource Market Participation

Issue Paper

On July 18, 2019, an Issue Paper was published and a working group meeting was subsequently held. The CAISO discussed how the current Master File limits Resource IDs to their Pmax, which may artificially limit hybrid resources with multiple Resource IDs and lead to stranding hybrid resource capacity. For example, a solar-plus-storage resource with maximum POI injection rights of 100 MW could be modeled in the Master File as having a 100-MW solar resource with a Pmax of 50 MW and a 100-MW storage resource with a Pmax of 50 MW, which ensures the project’s Master File Pmax remains below the 100-MW total POI rights but potentially strands 100 MW of capacity. The CAISO wishes to explore whether it is appropriate to develop a new hybrid resource constraint that ensures that the project remains below the project’s maximum POI rights without stranding capacity.

Like other NGRs, hybrid resources are also eligible to provide ancillary services (see Appendix K for required operating characteristics), so the CAISO is exploring what real-time data is needed (e.g., plant potential, state of charge) for regulation or reserves and whether mixed fuel resources can meet the timing requirements for change in power output to provide spinning and non-spinning reserves. For regulation provided by hybrid resources under a single Resource ID, the CAISO is considering a minimum requirement for the storage generating unit to comprise greater than or equal to 10% of the overall hybrid resource interconnection rights, with a capability to provide the minimum required capacity output for at least 30 minutes, considering the current minimum sizing requirements for ancillary service provision is 0.5 MW.

See CESA’s comments on August 13, 2019 on the Issue Paper

Straw Proposal

On December 10, 2019, a Revised Straw Proposal was published. While the self-provided operational forecast sets the upper economic limit for market participation, the CAISO affirmed that hybrid resources will still need to provide economic bids (either with or without a self-schedule) in the real-time market. Similar to other resources, generator bids and self-schedules can be updated once an hour at 75 minutes prior to the operating hour. Furthermore, the Revised Straw Proposal clarified that hybrid resources must meet the minimum sizing requirements for both of the underlying generation components: 500 kW for any participating generator hybrid resource component; and 100 kW for any storage hybrid resource components.

Additionally, for co-located projects, the CAISO will reflect the total interconnection rights of the co-located project at a single point of interconnection, which will adjust market awards, schedules, and dispatches to the injection limits. Although stakeholders strongly opposed limiting the combined Pmax of co-located resources to the project’s established interconnection rights, CAISO indicated that they cannot implement a more controls and reporting framework to limit components to their true Pmax. Instead, a scaled-down energy-only interconnection constraint option is proposed for implementation in Fall 2020 to allow co-located projects to maximize their interconnection rights, though they would not be eligible to provide Ancillary Services.

Finally, the CAISO proposed that hybrid resources must provide a new data point for the “High Sustainable Limit” (HSL) of the VER component to describe the maximum output capability in addition to the state-of-charge and telemetry data of the storage component to gauge actual capabilities to provide any services it has been awarded. Co-located resources, by contrast, will be treated as separate resources for the provision of Ancillary Services. When providing frequency response, the energy storage component of the hybrid resource must be of sufficient size (i.e., based on governor configuration requirements or 10% of certified capacity for inverter-based responses) to address situations where the other fuel components of the resource is offline or has insufficient fuel or headroom to respond autonomously to a frequency disturbance event.

CESA offered general support for many aspects of the Revised Straw Proposal but we sought clarification on the CAISO’s proposed interim solution to mitigated “stranded capacity” concerns for co-located storage resources that would be otherwise limited to their point of interconnection limits.

See CESA’s comments on January 14, 2020 on the Revised Straw Proposal

On April 29, 2020, a Second Revised Straw Proposal was published where, for hybrid resources, the CAISO proposes to extend market functionality similar to tools for standalone VERs to hybrid resources – i.e., utilize forecast data, charging models, and market insight to ensure that they are bidding in such a way so that they will receive feasible market awards and dispatch instructions. Hybrid resources may conduct their own onsite optimization of underlying resource components, with the CAISO expressing that it will not track storage state of charge.

For co-located resources, the CAISO proposes to lift the requirement that the combined Pmax must sum to the interconnection rights of a co-located resource, thereby addressing the potential “stranded capacity” issue and utilizing the full POI capacity. Instead, the CAISO seeks to impose a market constraint on the two resources to ensure that joint dispatch does not exceed interconnection rights at the POI to the CAISO-controlled grid. The CAISO will enforce an “aggregate capability constraint” where net output at the POI will be limited to the maximum and minimum capacity studied in the generator interconnection process. Market awards, not bids, will be constrained. If violations of the POI are still seen, then the CAISO will revert to constraints using the additive Pmax values behind the POI. In the future, the CAISO discussed how both hybrid and co-located resources will be able to provide ancillary services. The CAISO optimization engine will continue to optimize energy and ancillary service awards, with hybrid resources being required to submit information to ensure capability to deliver on bids. No changes to settlement processes are proposed, and the CAISO said it will tee up market power mitigation in the future for hybrid resources.

On May 13, 2020, due to stakeholder pushback, an addendum was subsequently published to remove the “one SC requirement” since it would preclude current and future procurement. Originally, CAISO proposed to limit co-located resources to one SC to submit bids since the CAISO saw challenges to manually managing independent resources behind constraints. Instead, the CAISO determined that it can manage reliability by limiting flows at the POI, leveraging the control technologies required for generation facilities (Tariff Appendix DD Section 3.1).

Hybrid Resource Metering & Telemetry

Issue Paper

A CAISO Metered Entity (CAISO-ME) is an eligible entity that has elected that the CAISO will collect and process its Revenue Quality Meter Data (RQMD) directly from CAISO-certified revenue quality meters, while Scheduling Coordinator Metered Entity (SCME) is an eligible entity that has elected that its Scheduling Coordinator (SC) will process and submit its Settlement Quality Meter Data (SCME) to the CAISO (see CAISO Tariff Section 10.1).

Issue Paper

On July 18, 2019, an Issue Paper was published and a working group meeting was subsequently held. Metering and telemetry requirements for hybrid resources are slightly different depending upon the point of interconnection, where a meter is needed for each Resource ID, and potentially for each sub-resource depending on how it is operated. For a single Resource ID hybrid resource that only charges from its own on-site generating unit, the CAISO would only see the output of the combined generating facility and the individual sub-resources would not be subject to CAISO dispatch instructions for generation, charging, or discharging purposes. All settlements for the project will be at point of delivery, based on metered output to CAISO controlled grid as adjusted for losses, at five-minute intervals. For a single Resource ID hybrid resource that charges from the CAISO grid, each resource component will be required to be separately metered and telemetered for grid reliability purposes, even if dispatch instructions and settlement are tied to a single Resource ID.

See CESA’s comments on August 13, 2019 on the Issue Paper

Many stakeholders expressed that metering and telemetry solutions may eliminate forecasting risk and can solve operational issues. As a result, they requested clarity and clarification of existing metering and telemetry requirements and expressed the need for certification of DC meters.

On August 27, 2019, a technical working group meeting was held to discuss metering and telemetry issues. The CAISO explained that a meter is needed for each Resource ID, and, depending upon where the meter is connected, the meter will need to be compensated for losses to the point of interconnection with the CAISO-controlled grid. Unit output telemetry for the single Resource ID charging from the on-site generating unit can be the net output of the generating units; however, separate telemetry will be needed for a single Resource ID projects selecting option for charging from the CAISO grid. Meanwhile, if the sum of the resource component’s ability to generate is greater than the approved interconnection capacity amount, a generation output limiting scheme is required to limit the energy output from the generating facility to the grid. Alternatively, if a hybrid resource has a single Resource ID configuration and elects to charge an energy storage unit from the on-site generating unit, a limiting scheme is also required to prevent generating facility from charging from the grid.

For hybrid resources connecting to either the CAISO-controlled grid or to the distribution grid, the CAISO proposed that the high-side meter would measure the total resource output while an additional meter may be required on the battery to measure charging and discharging. For a low-side metering layout, the CAISO explained that compensation is needed for transformer losses and/or transmission line losses depending on the location of the interconnection. For single Resource ID configurations, CAISO dispatch instructions would be for the combined resource, not for the individual components, making settlements done at the point of delivery, but each component would be required to be separately metered and telemetered.

Hybrid Resources Metering-Telemetry Proposal.png

Distinctions were also made for AC- and DC-coupled hybrid resources, where the SCME option was only available for single Resource ID configurations but both the CAISO-ME and SCME options available when separate Resource IDs are pursued for each component.

On December 10, 2019, a Revised Straw Proposal was published and a stakeholder meeting was subsequently held. For co-located resources, the Revised Straw Proposal proposed to accommodate charging from onsite generation by requiring a third meter to be installed that select the option to charge from the onsite generation, which will be used to perform logical metering calculations that allows for charging from onsite generation without the settlement and financial implications. With the three meters, the CAISO will be able to differentiate actual net charge to or discharge from the grid that should be settled versus the amount that is used to charge onsite generation.

Hybrid Resources RSP Co-Located Metering Example.PNG

Furthermore, separate telemetry and metering requirements is needed for all hybrids resources to ensure CAISO can be aware of the operational capabilities of hybrid resources and their underlying components. Finally, the CAISO noted that RPS treatment of storage conversion losses is outside of their purview.

See CESA’s comments on January 14, 2020 on the Revised Straw Proposal

Straw Proposal

On April 29, 2020, a Second Revised Straw Proposal was published where the CAISO made no major changes on the metering and telemetry requirements for hybrid and co-located resources. The CAISO will not require separate metering and telemetry requirements for each underlying component of a hybrid resource, only the renewable resource components at the high-side of the POI and the renewable resource for RPS reporting purposes – i.e., RECs will be generated net of storage losses in line with current RPS eligibility rules set by the CEC. Each co-located resource will have a separate resource ID and will be metered and telemetered separately.

Hybrid Resource RA & Deliverability

Issue Paper

On July 18, 2019, an Issue Paper was published and a working group meeting was subsequently held. RA deliverability, counting rules, and must-offer obligations (MOO) are the CAISO’s primary RA concerns for hybrid resources. The CAISO favored the more straightforward multiple Resource ID approach for hybrid projects since single Resource ID configurations present some challenges related to RA counting rules and must-offer obligations, as there is not an established QC counting rule for such configurations. The CAISO suggested that a potential QC counting methodology for hybrid resources under a single resources ID configuration is to utilize an exceedance methodology. The exceedance approach measures the minimum amount of generation produced by the resource in a certain percentage of hours. The CAISO said that they will need to establish MOO provisions for these hybrid resource configurations and believes the resulting MOO for single Resource ID hybrids would need to reflect QC value provided by any new applicable QC methodology and NQC value for which the resource has been shown for RA.

For deliverability, the CAISO explained that there are three configurations for deliverability assessment of hybrid resources: additive (sum of the outputs from each underlying resource), supplemental (less than the sum of the outputs from each underlying resource), and BTM expansion (one or more resources are added to an existing facility with expansion treated as energy only unless deliverability transfer request is made or if separate Resource IDs are pursued). In each case, the resource is modeled as one generator. No proposals were made, and no issues were identified .

See CESA’s comments on August 13, 2019 on the Issue Paper

Straw Proposal

On December 10, 2019, a Revised Straw Proposal was published that reiterated how the CAISO will defer to the local regulatory authority on RA counting rules and would refine its proposal as the CPUC finalizes its counting rules. Depending on the component that drives the capacity value of the hybrid resource, the must-offer obligation rules will follow accordingly. If the storage component is assigned as the “greater-of” capacity value for the hybrid resource (“storage-driven hybrids”), then the MOO rules for storage would apply to the hybrid resource, which includes day-ahead MOOs; however, for “VER-driven hybrids,” then the MOO rules for VER resources would apply to the hybrid resource, which does not include a day-ahead MOO but does include a real-time MOO equal to their self-provided operational forecasts.

CESA offered general support for many aspects of the Revised Straw Proposal but commented on the need to set RA and must-offer obligation rules based on market participation model chosen by the resource operator as opposed to the interim greater-of QC methodology, as proposed for adoption by the CPUC, which CESA has strong reservations against.

See CESA’s comments on January 14, 2020 on the Revised Straw Proposal

On April 29, 2020, a Second Revised Straw Proposal was published where the RA must offer obligations will persist for all co-located projects, and the CAISO proposed to extend the 24x7 must-offer obligations for hybrid resources as well. In periods when the hybrid resource is incapable of bidding all capacity into the market, the hybrid resources will have access to outage cards that may be used during non-availability assessment hours (AAHs); the resource will be required to provide full RA capacity during the AAHs. Variability need not be reported to the CAISO with an outage card but may be captured in the dynamic limits of a hybrid resource so that the resource is always capable of delivering what is bid into the market, during all intervals. If the forecast solar availability changes during the charging periods, the resource would continue to update the CAISO to new availability via the dynamic limit. All updates submitted through the dynamic limit tool would not be subject to resource adequacy availability assessment mechanism (RAAIM).

CESA offered general support for many aspects of the Second Revised Straw Proposal but sought clarification on the CAISO’s proposed MOO rules for hybrid resources and their relationship to the application of the unforced capacity (UCAP) framework and the RAAIM.

See CESA’s comments on May 28, 2020 on the Second Revised Straw Proposal

Self-Schedule Bid Cost Recovery & Negative Bid Floor (Stakeholder Process)

Background

To ensure that the CAISO is able to provide accurate price signals to incent a more flexible fleet of resources during this evolution toward a 50% RPS, market changes may need to be implemented to encourage generators to economically participate in markets rather than self-schedule. Increased economic bidding of flexible resources and decreased self-schedules will provide the market optimization with more flexibility to economically mitigate instances of over-supply, as opposed to uneconomically cutting self-schedules.

This initiative explores two modifications to existing market design policies to incent more economic bidding by:

Lowering the bid floor from -$150/MWh to -$300/MWh
Modifying the IFM tier 1 uplift cost allocation by no longer exempting load corresponding to self-scheduled supply from being allocated integrated forward market bid cost recovery costs

These modifications were previously discussed in the Stepped Constraints Parameter Initiative, but were combined into this new initiative to facilitate an earlier implementation.

On December 19, 2013, FERC accepted the CAISO's proposal to lower the bid floor from -$30/MWh to -$150/MWh under the notion of facilitating increased real-time economic bidding by variable energy resources. By lowering the bid floor, the opportunity costs of not producing for many variable energy resources could be reflected in the resource's economic bid. It also provides an incentive for resources with positive marginal costs to economically bid instead of self-schedule. Those resources can avoid negative prices in both DA and RT, for schedules above DA, and generate more revenues in RT for decremental dispatches below DA.

Currently, the bid floor (-$150/MWh and bid cap (+$1,000/MWh are not symmetrical. This reslts in under-scheduled load in the DA market being potentially subject to RT prices at the bid cap and for overscheduled load in the DA market potentially incurring a cost at the bid floor. Thus the incentive for not under-scheduling load in the DA market is not equivalent to the incentive for not over-scheduling load in the DA market. Furthermore, as the supply fleet evolves toward a 50% RPS, there may be increased instances of oversupply conditions. A deeper pool of economic bids could enable the market to more efficiently manage oversupply conditions, but may require a bid floor such that resources are able to fully reflect the cost of not producing. The current bid floor may not be sufficiently low enough to incent the procurement of downward flexible resources that will be needed.

Policy Development

On August 11, 2016, the CAISO issued a Draft Final Proposal on rules related to bid cost recovery and a negative bid floor adjustment.

On September 16, 2016, the CAISO announced that it has backtracked on its plan to lower the negative bid floor in its markets from -$150 to -$300, opting to instead keep it at -$150 (as evidenced in the CAISO’s Addendum to the Draft Final Proposal). This matter may reduce the potential profitability of energy storage resources in the CAISO's markets, including those for NGRs and PDRs, which is why CESA has concerns over these recent developments. In addition, CESA is disappointed with the lack of a clear and robust process for making this change, which occurred without much public input. The Draft Final Proposal will go before the CAISO Board of Governors for approval at their October 26-27 meeting.

On September 27, 2016, the CAISO held a stakeholder call to discuss this and said it will continue to monitor levels of self-schedule curtailments. The CAISO's reason for deferring the lowering of the bid floor is that “benefits of lowering the bid floor do not outweigh the potential risks at this time.” The Department of Market Monitoring (DMM) expressed its concerns that in some (very rare) instances, bad actors could game and exploit a lower negative bid floor. PG&E and SCE also supported keeping the bid floor given the “lack of data.” On the call, the CAISO also said that the bid floor is not hit very often. CESA does not see it the same way given that the bid floor was hit in 15% of 5-minute intervals in April, when over-supply conditions are more frequent. Furthermore, in CESA’s view, the DMM did not have an adequate response to how negative price market power mitigation still exists at the current bid floor.

The CAISO also announced that it has modified its integrated forward market (IFM) bid cost recovery (BCR) allocation approach such that the existing transmission contract or transmission ownership rights self-schedules will continue to be exempt from the IFM BCR allocation. The CAISO is proposing to only exempt the balanced portion of an EETC/TOR self-schedule from IFM BCR uplift cost allocation.

On October 18, 2016, the CAISO announced that it will not lower the negative bid floor because of a desire to monitor the markets following implementation of the Flexible Ramping Product (FRP). Some groups opposed a near-term lowering of the negative bid floor, which may have influenced the CAISO Board's decision. CESA aims to get the lowering of the negative bid floor to be a highly ranked 2017 initiative.

See CESA's comments on November 17, 2016 on the 2017 Stakeholder Initiatives Catalog.

Hello, World!

Resource Adequacy (RA) Enhancements (Stakeholder Process)

Background

The CAISO launched this new initiative to consider “holistic” changes to the CAISO’s RA Program that are necessary to support a multi-year RA proposal adopted by the CPUC in Phase 1 and to explore other RA enhancements necessary to further align CAISO planning and procurement process with operational needs to maintain system reliability in Phase 2. In particular, given the objectives of SB 100, the CAISO is looking to reforms that ensure the future reliability and operability of the grid. Phase 1 implementation is planned for Fall 2019 while Phase 2 implementation is planned for Fall 2020.

This initiative laid out a key set of principles in enhancing the RA fleet to meet the CAISO’s operational and reliability needs:

The RA framework must reflect the evolving needs of the grid.
RA counting rules should promote procurement of most dependable, reliable, and effective resources.
RA Program should incentivize showing all RA resources.
LSE’s RA resources must be capable of meeting load requirements all hours (e.g., not just in meeting peak demand).

The objectives of this initiative are to:

Update the RA framework to assess forced outage rate
Conduct RA adequacy assessments based on unforced capacity of resources and RA portfolio’s ability to ensure CAISO can serve load and meet reliability standards
Simplify existing complex and interrelated RA provisions to the extent possible while considering impacts to resulting incentives
Coordinate and align RA modifications with CPUC processes and decisions
Consider RA modifications beyond just relying on installed capacity-based PRM
Utilize both installed capacity (NQC) and unforced capacity (UCAP) values in CAISO’s RA processes

Phase 1 implementation is planned for Fall 2019 while Phase 2 implementation is planned for Fall 2020. The CAISO is moving toward a Phase 1 Draft Final Proposal in September 2019 so that it can be presented to the CAISO Board in November 2019.

Issue Paper

On October 22, 2018, the CAISO published an Issue Paper and hosted a stakeholder meeting on October 29, 2018. First, the CAISO explained that it is an active participant in the CPUC’s RA proceeding to develop a multi-year Local RA framework, which will likely maintain the CAISO’s existing backstop authority and will thus require minimal or no tariff modifications. Notwithstanding the multi-year RA issues, the CAISO also identified numerous aspects of its RA tariff authority that must be updated:

The current RA counting rules do not adequately reflect resource availability and the CAISO proposes that the application of Effective Forced Outage Rate (EFOR) performance adjustments be considered.
Flexible RA capacity counting rules may not sufficiently align with system and locational operational needs and must align with adopted DAME changes.
Available import capability and allocation may result in inefficient outcomes and withholding of import capabilities and the CAISO plans to consider multi-year Import Capability assessments and allocations. Each year, the CAISO establishes maximum import capability (MIC) values for import paths, and allocates MIC to scheduling coordinators for LSEs in the ISO BAA for RA purposes. The CAISO calculates available import capability for each intertie by using historical import schedule data during peak load periods for the prior two years along with power flow studies. The total Available Import Capability is assigned on an annual basis through the Available Import Capability Assignment Process (Tariff Section 40.4.6.2.1).
RA eligibility rules and must-offer obligations (MOOs) for import resources may provide opportunities for economic withholding and/or non-delivery of energy and thus the CAISO proposes that must-offer obligations be developed for RA imports. RA imports are not required to be resource specific or to represent supply from a specific balancing area, but only that they be on a specific intertie into the CAISO system. Scheduling coordinators are only required to submit energy bids for RA imports in the day-ahead market. Imports can be bid at any price and do not have any further obligation to bid into the real-time market if not scheduled or cleared in the day-ahead energy or residual unit commitment process.
A holistic review of MOOs and RA substitution rules that better ensures that substitution capacity is provided in forced and planned outages, and of the RA Availability Incentive Mechanism (RAAIM) that limits having bare minimum RA capacity types and amounts to be “shown”.
System and Flexible RA assessments do not consider the overall ability of the RA fleet to meet the CAISO’s operational needs and thus the CAISO proposes to develop a tool to assess all RA showings.
Growing reliance on availability-limited resources may not have sufficient hours or dispatches to serve local capacity areas, based on the CAISO’s hourly load and resource analysis from the Moorpark and Santa Clara studies. The current transmission planning studies do not consider hourly load and resource analysis in determining Local RA procurement needs. The Moorpark and Santa Clara studies were an exceptional case.
Exploration of how to best operationalize slow-response DR resources, such as through pre-contingency dispatch, in a contingency event that requires 20-minute response time. Slow DR resources are defined as DR resources that typically are unable to meet the 20-minute resource dispatch and response time required for the CAISO to secure the system within 30 minutes of a contingency, per NERC standards and Tariff Section 40.3.1.1(1).
Local RA capacity backstop procurement cost allocation does not contemplate the effectiveness of the Local RA resources and thus the CAISO will examine whether and how to allocate costs of procured resources that are not effective at meeting Local RA requirements.

CESA supported exploring some RA adjustments, including around simplifying substitution and replacements rules, and will be particularly focused on the issues around Maximum Cumulative Capacity (MCC) buckets as they relate to RA showings and the impacts of reliance on availability-limited resources in local capacity areas. CESA will advocate for the CAISO to not impose limits on energy storage solutions providing RA in local areas and instead support the CAISO identifying needs and devising procurement structures to ensure that the needs are met. In addition, CESA will continue to advocate for other RA issues, including the unbundling of System, Local, and Flex RA, the development of a Flexible Deliverability Study, and RA and interconnection study clarifications for hybrid resources. In comments, CESA focused on what could be in scope and what should be out of scope of this initiative:

Expand scope to include RA counts and RA offer or other rules for hybrid resources
Expand scope to include components of FRACMOO, including the unbundling of Local and Flex RA along with the standalone Flexible Deliverability Study
Expand scope to explore how the CAISO will address contingency condition based local RA needs and if RA is the proper tool for meeting these needs
Expand scope to include development and authorization of RA counts and eligibility for exports from BTM DERs
Remove from scope any use of “buckets” from the scope and instead establish rules for non-conventional RA needs for cases where the RA tool may be leveraged but would be defined differently
Remove or defer from scope any expansion of CPMs or RMRs to be “multi-year” backstops

See CESA’s comments on November 12, 2018 on the Issue Paper

Whereas the CAISO uses a combination of MOOs, substitution rules, and RAAIM to incentivize resource availability, most other ISOs and RTOs use the effective forced outage rate of demand (EFORd) to assess upfront resource availability and some ISOs and RTOs use a performance assessment to assess how a resource performs under stressed grid conditions. EFORd is the probability that a resource will be unavailable due to forced outages or forced deratings when there is demand on the unit to operate and generally accounts for hours and months of greatest demand and excludes planned or maintenance outages. MISO, NYISO, and PJM have roughly similar calculations for unforced capacity (UCAP) based on EFORd and the installed capacity (ICAP) value that is equivalent to the CAISO’s NQC methodology: UCAP = ICAP * (1-EFORd). Only ISO-NE is the only RTO that measures performance, not just availability.

Straw Proposal

On January 23, 2019, a stakeholder call was held on Straw Proposal Part 1. Each aspect of the Straw Proposal is elaborated below, followed by CESA’s response and comments.

See CESA’s comments on February 6, 2019 on Straw Proposal Part 1

First, the CAISO is proposing a definition for availability-limited resources, which are energy-limited resources and are not fully considered in the current RA program. Under contingency events in certain local areas, availability-limited resources may have dispatch limitations such as duration hours or event calls that would limit their ability to respond to a contingency event within a local capacity area. The current Local Capacity Technical (LCT) study will be used to inform the availability needs. CESA supported studies to explore energy duration needs in local sub-areas through expanded LCT Studies. The CAISO currently studies only peak needs in local sub-areas but wants to expand its studies to inform RA procurement with an eye towards energy duration needs. The CAISO has committed to not use its studies in binding ways for now, but the information may be helpful to energy storage insofar as it helps developers provide solutions that fit needs. In some areas, the CAISO has identified energy duration needs as high as 9 hours. A risk with the CAISO’s actions is that it could instead support more targeted procurement of existing gas resources as opposed to new energy storage procurement. CESA will thus need to cultivate opportunities to work with the IOUs and CCAs to provide solutions so they have paths to get the storage capacity they both need and want. CESA also suggests that existing energy storage should be fully valued and that studies need to be vetted carefully to inform the energy storage industry and LSEs early on.

Second, the CAISO is looking at RAAIM modifications to resolve gaps in the current planned outage approval process and to ensure sufficient System, Local, and Flexible capacity. The CAISO utilizes two types of outages. Planned outages involve working with the CAISO to schedule the outage and ensure that sufficient replacement capacity remains available. The CAISO has the authority to deny the outage if a planned outage results in a RA shortage. If the Scheduling Coordinator decides to take a planned outage that was denied, the CAISO will treat that resource as a forced outage. Forced outages may be subject to the RAAIM if the resource does not provide substitute capacity, depending on the cause of the outage. Specifically, the CAISO was looking to reform rules to incentivize submission of planned outages to allow for more effective management of outages and finding of alternative resources with longer lead times. The CAISO is considering two ‘bookend’ options that represent the extremes of flexibility and strict requirements:

Option 1 (Flexible): Scheduling Coordinators (SCs) would be allowed to determine whether the outage is cost-effective and make an election 8 days prior to the planned outage, which would not impact the resource’s NQC or face availability charges. If the election is not made 8 days prior to the planned outage, then the resource would be treated as a forced outage and face RAAIM penalties.
Option 2 (Strict): SCs would be prevented from taking planned outages during the month in which the resource is providing RA capacity. This may create incentives to not provide planned outages.

The CAISO also proposed to establish NQC adjustments for resources taking forced outages that would be applied to future periods, not capacity that has already been sold as RA, and to consider both availability and performance assessments using event-based triggers, similar to what is done by ISO New England’s Forward Capacity Market Pay-for-Performance (PFP) tool, instead of only assessing availability. Note that the RAAIM only assesses whether an RA resource submits economic bids or self-schedules in the day-ahead and real-time markets during Availability Assessment Hours (AAHs), regardless of system conditions and consistent with the must-offer obligations (MOO) for the given resource and RA capacity type.

RA -1 RA Straw Proposal Part 1 Outage Trigger Options.png

Thus, the new performance aspect would be a comparison between dispatch instruction and metered output, with a preliminary focus on real-time market performance. Notably, considering the current RAAIM was developed as a self-funding mechanism where charges for under-performance are used to fund over-performance, the CAISO plans to consider creating an additional incentive for resources to make capacity above its RA value available to the CAISO. To reduce the complexity of developing event-based triggers tied to operational needs, the CAISO will review all existing RAAIM exemptions.

CESA expressed caution about reforms to the CAISO’s outage and substitution rules. The CAISO is exploring whether and how to move towards a forced outage rate type of ‘count’ for resources (i.e., NQC). The CAISO’s thinking may be that, if they count resources at less than their full value, LSEs will be obliged to bring more capacity in their monthly showings, thereby providing the CAISO with ‘enough’ resources even if resources go on outage. The CAISO thinks this approach could simplify RA tracking and outage evaluation. Alternatively, this approach could give expensive capacity ‘haircuts’ to resources’ NQC values, which may be particularly harmful to more newly contracted resources. One possible upside of the CAISO proposal, however, is that older resources with frequent outages would receive bigger haircuts, in theory creating opportunity for new procurement needs. In comments, CESA thus emphasized that any change in its RA outage and replacement rules should involve transition approaches so existing energy storage contracts are not inadvertently harmed.

Third, the CAISO is following up on its planning studies on slow DR resources from previous initiatives in this initiative. As a preventative measure, the CAISO explained how slow DR resources are valuable when being used for pre-contingency dispatch, which would allow them to qualify for Local RA, so long as resources are able to respond to dispatches within real-time market time horizons. In Phase 3 of the ESDER Initiative, the CAISO adopted such bidding options for slow DR resources in hourly blocks (52.5 minute notification time) and 15-minute blocks (22.5 minute notification time).

RA -2 RA Straw Proposal Part 1 Slow DR Pre-Contingency Dispatch.png

Under the CAISO’s proposal, slow DR resources would be dispatched for pre-contingency when the “slow DR MW requirement” as defined by day-ahead local load forecast minus import capability and generation capacity bid into the day-ahead market is greater than zero. One effect of this proposal may be that slow DR resources would be subject to more frequent dispatch.

Fourth, the CAISO discussed how it is exploring options to ensure more comparable treatment between import RA and internal resources, given that the current RA rules allow for speculative supply to qualify as RA. Import RA resources are currently only required to be shown and make offers at a specific intertie and to submit energy bids in the day-ahead market (i.e., no further obligation to bid in the real-time market if not scheduled in the day-ahead market). Import RA is also not resource-specific, which raises concerns about double counting resources for reliability. Thus, the CAISO is exploring proposals to set 15-minute bidding and scheduling requirements for all MWs, to set real-time market participation requirements, and to expand to 24x7 must-offer obligations. The CAISO also proposed to establish “resource-specific” designations for RA, in light of the extension of the day-ahead market to EIM resources. Some stakeholders indicated that the CAISO should consider how to modify processes to more efficiently utilize allocated MIC on each intertie, as some LSEs may not make their allocated MIC available for others to buy or trade. The CAISO responded that it is considering including options and potential enhancements to the Available Import Capability Assignment process, such as reassignment, trading, transfers, or auctions.

Finally, CESA supported addressing many other RA enhancements, which were not included in the final scope. These enhancements include unbundling System from Flexible RA, having a standalone flexible deliverability study, supporting the development of RA values for DER aggregations, and determining RA value for solar-plus-storage and other hybrids with energy storage.

On March 5, 2019, the CAISO issued a Revised White Paper where the CAISO indicated its plans to file a tariff amendment to clarify that the RAAIM exemption for outages that relate to resource owner's administrative actions, causes outside the resource's control, or management of short-term use limitations applies whether the outage is planned or forced. Previously, pursuant to Section 40.9.3.4(d) of the CAISO Tariff, generator outages caused by forced transmission outages are exempt from the RAAIM, but the CAISO does not apply the same exemption for transmission-induced generation outages caused by planned transmission outages.

On February 27, 2019, the CAISO published Straw Proposal Part 2 and held a stakeholder meeting where a range of RA-related changes were discussed and proposed that could provide modest benefits for energy storage. The CAISO began the meeting with an overview of its review of RA counting rules in other ISO/RTOs to determine if the CAISO’s current RA rules are beneficial and necessary and whether there are alternatives to RAAIM. The CAISO concluded that other ISO/RTOs assess availability of RA resources by considering historical (3-5 year) forced outage rates and class average data for new resources without sufficient historical data. Based on this review, the CAISO indicated that it believes that a review of resources’ forced outage rates and inclusion in RA valuation is warranted.

The CAISO thus proposed a new framework to assess the forced outage rates for resources and to conduct RA adequacy assessment based on the resources’ unforced capacity and the RA portfolio’s ability to ensure CAISO is able to serve load and meet reliability standards. As a result, the CAISO proposed to calculate and publish NQC and EFC values for all resources, the UCAP value for all resources types except those that rely on the ELCC methodology (which already accounts for the probability of ‘forced’ outages to an extent), and the EFORd for each season in the upcoming RA year.

The CAISO also proposed to use a variant of a UCAP methodology for flexible counting purposes with the following general formula: EFC = UCAP * (% of available capacity bid into CAISO market). However, the CAISO indicated that it is still unclear and in the process of reviewing UCAP values for DR, imports, hydro, qualifying facilities (QFs), and new resources.

Finally, the CAISO proposed a 16-hour window (from 5am to 9pm) for calculating forced outage rates to simplify existing AAHs, reduce the impact of forced outages during peak, and calculate the same forced outage rate for both generic and flexible capacity. For example, assuming a one-month forced outage rate calculation period with a resource that is on forced outage for 15 days during a month from 4pm to 9pm, the forced outage rate is calculated as follows:

RA -4 Forced Outage Rate Calculation Periods.png

With these UCAP values in place, the CAISO proposed to develop a minimum UCAP requirement that all LSEs must meet and show as RA, though RA showing timelines and assessments is not proposed to be changed. By anticipating outages ahead of time, the CAISO aims to line up more capacity for the showings so that the replacement capacity is already included in the portfolio – i.e., the CAISO will want slightly more RA capacity procured each month and resources will receive a proportional UCAP value. If the portfolio is inadequate, then LSEs will have an opportunity to cure it and/or have the CAISO conduct backstop procurement as a last resort.

These potential changes involve how the CAISO plans for getting additional capacity if some of the expected capacity goes on an outage. These replacement and substitution processes are complex and may be difficult for smaller LSEs and/or resource schedulers. For planned outages, the CAISO continues to explore a new substitution concept and will not require LSEs to provide substitute capacity if their unforced capacity exceeds the minimum UCAP threshold. For forced outages, the CAISO will not allow for substitution of capacity to more accurately reflect the true availability of resources. In local capacity areas there may not be substitute capacity available, the CAISO will rely on CPM designations, with some modifications, to meet UCAP-related capacity deficiencies if additional capacity is available. The CAISO is also assessing the need for both the RAAIM and a UCAP assessment tool to prevent gaming using resource IDs to avoid a UCAP reduction.

CESA recommended that the UCAP proposals do no harm and do not change the NQC or EFC terms, which are already embedded in many contracts. In addition, the proposal should be modified to fully value the EFC from energy storage and should use a new Effective Flexible Adjusted UCAP metric (EF-CAP) that properly values energy storage while adopting the CAISO’s new outage-focused methodology (EFORd). That is, energy storage resources should have the ability to take corrective actions to improve their outage assumptions – i.e., methodologies other than averaging are needed, which, for example, may disproportionately penalize an entire class of new resources based on a single poor performer.

See CESA’s comments on March 20, 2019 on Straw Proposal Part 2

On October 3, 2019, the CAISO published its Second Revised Straw Proposal. The CAISO continued its efforts to address operationalization concerns of the RA fleet to provide capacity in all hours of need and to provide effective flexibility. As such, in its latest proposals, the CAISO has made refinements to its proposal to calculate the UCAP requirement for resources, where the CAISO has observed a portion of capacity resources taking an "outage" for various reasons (beyond planned maintenance) without sufficiently substituting capacity. The UCAP rates are determined by determining the EFOR of resources, which will drive System/Local RA requirements. In addition, the CAISO is also considering a simplification of its Flexible RA product to focus on 15-minute ramp-capable capacity through the Imbalance Reserve Product, which is being developed in a separate Day-Ahead Market Enhancements (DAME) Initiative. This is a welcome development in the sense that it refines flexible capacity eligibility to fast-start resources like storage but it is unclear if the three-hour ramping product should be eliminated as well since there could be value in long-ramping resources.

CESA supported the UCAP proposals but recommended that the CAISO take a slightly different approach for energy storage resources in assessing their forced outage rates, while also stressing the need to ensure local capacity needs do not unduly limit energy-limited resources. Furthermore, while supportive of the Imbalance Reserve Product, we expressed caution with eliminating the three-hour ramping product altogether.

See CESA’s comments on October 24, 2019 on the Second Revised Straw Proposal

On October 3, 2019, a separate Draft Final Proposal was published on local RA issues for availability-limited resources and slow demand response. CESA supported the CAISO’s Draft Final Proposal to provide duration information on local capacity needs but opposed placing any caps on availability-limited or energy-limited resources.

See CESA’s comments on October 24, 2019 on the Draft Final Proposal

On March 17, 2020, a Fourth Revised Straw Proposal was published and discussed at a stakeholder meeting that continued refinements to the CAISO’s proposal to move from a net qualifying capacity (NQC) accounting for System, Local, and Flexible RA to one based on unforced capacity (UCAP) that eliminates substitution requirements.

The CAISO shared how the CAISO tariff and CPUC RA program requirements should align and require forward commitment of real, physical resources to meet capacity requirements. These RA changes are the subject of Track 1 discussions in the RA proceeding (R.19-11-009), so the CAISO spent time advocating for its view that all RA imports should be resource specific, be separately committed to the LSE, and have firm transmission delivery. The CAISO added that it will extend must-offer obligations to the real-time market for all MWs of RA imports included on RA showings consistent with existing rules for internal resources and pseudo ties. Although some stakeholders argued that there currently may be a limited number of long-term firm transmission rights holders on certain paths or areas, CAISO responded that these rights may be traded or developed.

CESA was largely supportive of the refinements included in the Fourth Straw Proposal but challenged the CAISO’s intention to establish upfront procurement requirements with a structure similar to the CPUC’s maximum cumulative capacity (MCC) buckets, which would be constraining to the use of energy-limited resources such as storage. Instead, CESA advocated for the use of broader performance attributes in setting MCC-like upfront procurement requirements.

See CESA’s comments on April 14, 2020 on the Fourth Revised Straw Proposal

Hello, World!

Reactive Power Requirements (Stakeholder Process)

Background

The purpose of this initiative is to identify a uniform requirement for asynchronous generators such as wind and solar to provide reactive power and voltage regulation. This issue was previously addressed by the CAISO in 2010, but its proposal was rejected by FERC. However, since then, the CAISO believes that system conditions have changed sufficiently to revisit the topic and develop a new policy due to reactive power deficiencies the CAISO has been experiencing that require curtailment of renewables and dispatch of fossil resources to provide reactive power. The CAISO also believes that this approach will replace the current case-by-case system impact studies to assess whether asynchronous resources must have the ability to provide reactive power to safely and reliably interconnect to the transmission system.

Policy Development

On November 17, 2015, the CAISO issued its Draft Final Proposal, which requires asynchronous resources like energy storage to interconnect with certain levels of reactive power capabilities. The capabilities roughly mirror those of traditional synchronous resources. These rules will apply to new generators (e.g., future energy storage installations) whose contracts in theory have yet to be inked. CESA members should thus note the potential need to include Reactive Power capabilities and provisioning in designing projects for CAISO interconnection and market participation.

On December 3, 2015, the CAISO filed Draft Tariff Language to the FERC. Early in 2016 though, the CAISO suspended this initiative pending the outcome of FERC's Notice of Proposed Rulemaking.

On June 16, 2016, FERC adopted Order No. 827, a final rule establishing reactive power requirements for non-synchronous resources. Order No. 827 requires all newly interconnecting non-synchronous generators to provide reactive power at the high-side of the generator substation as a condition of interconnection as set forth in their generator interconnection agreements. FERC, however, did not apply this requirement to existing resources making upgrades that require new interconnection requests after the effective date of the final rule. FERC determined instead that these resources would only be required to provide reactive power if the transmission provider’s system impact study shows that provision of reactive power by the resource is necessary to ensure safety or reliability.

The CAISO also requested that FERC allow transmission providers to propose additional technical requirements related to automatic voltage control for interconnecting non-synchronous generators. The CAISO believes that automatic voltage control regulator systems are necessary to maintain voltage schedules. The FERC did not rule on this requirement as a standard condition of interconnection, but opened up the opportunity for the CAISO to propose these additional requirements under a separate section 205 filing.

On July 21, 2016, the CAISO approved the final Reactive Power Design (via an Addendum to the Draft Final Proposal) to comply with FERC Order No. 827. CESA supported the Addendum but requested that the CAISO mirror its Tariff Language with those used in the IEEE 1547 process.

On August 31, 2016, the CAISO posted updated Draft Tariff Language reflecting automatic voltage regulation requirements adopted by the CAISO Board of Governors, as well as separate Draft Tariff Language to comply with FERC Order No. 827 and FERC Order No. 828, which set requirements for frequency and voltage ride-through capabilities for small generating facilities.

On November 4, 2016, the CAISO posted Revised Draft Tariff Language to implement reactive power requirements based on stakeholder feedback. The CAISO has clarified its expectation that automatic voltage regulators operate in voltage regulation mode and clarified that automatic voltage requirements for asynchronous generating facilities apply to generating units required by FERC Order No. 827 to provide reactive power capability.

On January 11, 2017, the submitted an Answer to Protests. EDF Renewable Energy challenged the filing because it asserted that the proposed tariff revisions would impose unnecessary costs to non-synchronous generators.

On March 2, 2017, FERC accepted the filing but suspended the determination on the filing, as it contemplates whether the CAISO’s proposed tariff revisions are unjust, unreasonable, or discriminatory.

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Regionalization

Background

The CAISO has been exploring greater linkages with other balancing areas in surrounding states, such as through the Energy Imbalance Market (EIM) to provide additional real-time flexibility and grid support. Since the passage of SB 350, regionalization has become an important focus for the CAISO. The CAISO is developing policy and tools to support greater regionalization through the following initiatives:

Regional Integration and EIM Greenhouse Gas Compliance Initiative (Stakeholder Process)

Background

This initiative will determine how costs for generation to comply with California’s greenhouse gas (GHG) regulations will be treated in the ISO’s integrated forward market (IFM). The energy imbalance market (EIM) currently has a methodology that enables generation resources to include GHG compliance costs in their offers to supply California load. Similar provisions must be developed for the IFM to address GHG compliance costs for new participating transmission owners outside of California. The California Air Resources Board (ARB) currently has a rulemaking process to amend its GHG regulations for emissions associated with EIM transfers considered electricity imports into California. The CAISO is working in collaboration with ARB and stakeholders to address the proposed amendments to ARB regulations.

On April 24, 2019, the Real-Time Market Neutrality Settlement Initiative was started to consider the elimination of the transfer of the real-time imbalance energy offset between balancing authority areas in the Western EIM and to remove the GHG awards from the real-time market neutrality and to create a GHG-specific neutrality allocation. Real-time market neutrality is a settlement charge currently calculated based on the sum of instructed imbalance energy, uninstructed imbalance energy, unaccounted for energy, and GHG awards. To allocate the real-time market neutrality in settlements, an offset is calculated for each of the components of the locational marginal price.

Issue Paper

On August 29, 2016, the CAISO published its Issue Paper on how the CAISO will track transfers within a multi-state balancing authority for purposes of determining a compliance obligation consistent with a state’s GHG program.

On October 13, 2016, a technical workshop was held to discuss the treatment of intertie schedule points for determining if an import or export is attributed to the state receiving energy and to serve as an educational forum where stakeholders can learn more about GHG compliance costs used to establish locational marginal prices inside and outside of the CAISO.

On November 7, 2016, the CAISO released a draft Tracking Report, along with a Methodology Paper, that that outline the calculating methods and provide data on GHG emissions from energy resources dispatched on the CAISO’s grid and imported to serve CAISO load. Going forward, the report will be updated monthly and made publicly available.

The CAISO indicated the Tracker will require further work as it may be inaccurate, based on comparisons with actual grid emissions. Moreover, the CAISO is struggling to anecdotally identify and separate the GHG emissions benefits from EIM vs from other factors – e.g., low natural gas costs. The CAISO thus postponed the release of a companion report on GHG emissions associated with serving CAISO load from the Western Energy Imbalance Market (EIM). The CAISO is proposing the following enhancements to address the Tracker issues:

Identify the least-cost dispatch of resources to serve EIM load without transfers to serve California load
Re-run the least cost model allowing the transfers to serve California load

After implementing the proposed enhancements, the CAISO believes that it can identify dispatches above the dispatch level calculated in the first run, and attribute and quantify which EIM participating resources are operating strictly to serve California load.

Straw Proposal

On November 18, 2016, the CAISO published a Straw Proposal that outlines the options to account for compliance obligations with California GHG regulations for supply resources outside of California in an expanded balancing authority area and for resource scheduling coordinators participating in the EIM.

Draft Final Proposal

On May 24, 2017, the CAISO posted its the Draft Final Proposal, which proposed to require “California supply” to be a biddable parameter. “California supply” includes generators located in California, imports, and EIM participating resources contracted to California load. A two-pass solution was proposed to maintain resource-specific cost and attribution:

Optimize schedules outside of California without transfers to California in order to determine the “GHG allocation base” and not inappropriately impact Locational Marginal Prices (LMPs) and dispatch opportunity outside of California
Optimize transfers to California and compare with the previous step to determine incremental dispatch possible.

The GHG award is only attributed if the resource is incrementally dispatched above the new “GHG allocation base” to support EIM transfer into the CAISO. The CAISO would thus need to solve the market twice to add GHG accounting functionality. The CAISO was also working in collaboration with ARB and stakeholders to enact a bridge solution until the two-pass solution can be implemented.

On June 23, 2017, the CAISO issued a Revised Draft Final Proposal that proposed to limit the GHG bid quantity to the difference between the resource’s upper economic limit and the GHG allocation base determined in the ‘first pass’ solution. This approach does not require additional constraints to be added to the market optimization. This is different from the May 24 Draft Final Proposal, which proposed to add a resource-specific constraint that GHG attribution must be above the GHG allocation base determined in the first pass. The CAISO noted that no two pass solution can eliminate all secondary dispatch; therefore, the solution must balance the objective of minimizing secondary dispatch with optimization solution performance and price/dispatch consistency. An additional benefit of the two pass solution is that the GHG allocation base allows the CAISO to provide data to ARB on the emissions of any residual secondary dispatch that remains after the GHG enhancement is implemented. The CAISO will implement the two pass solution described in parallel operations and produce a report in Q4 2017 that evaluates the effectiveness of the design in minimizing secondary dispatch. In addition, the CAISO is investigating the potential for additional enhancements in the event that the Q4 2017 demonstration identifies the need for improved attribution accuracy.

On February 16, 2018, the CAISO published the Second Revised Draft Final Proposal that recommended design changes to enhance the current EIM GHG market design to improve how it captures the atmospheric impact that occurs in connection with EIM transfers that serve California load. The previous proposal, which introduced a second pass of the real-time market, was determined to have bidding incentive and pricing issues. The new approach uses the existing market optimization but proposes GHG bidding rules to account for the secondary dispatch emissions.

On April 25, 2018, the CAISO published its Third Revised Draft Final Proposal that, as compared to the previous proposal, only proposed to modify the GHG bid quantity rules from 9 MW to the upper economic limit less the base schedule. In doing so, the CAISO argued that it provides a more accurate attribution of resources serving CAISO load by reducing the quantity that may be attributed to base schedules that serve non-CAISO load. After one more round of stakeholder comments, the CAISO will take this version of the proposal to the EIM Governing Body for a vote on July 12 and to the CAISO Board for approval on July 25-26.

On August 9, 2018, a stakeholder call was held to discuss draft tariff language to implement the Third Revised Draft Final Proposal to reflect GHG compliance costs within locational marginal prices for resources serving CAISO load.

Regional Resource Adequacy (RA) Initiative (Stakeholder Process)

Background

The Regional RA Initiative evaluates RA tariff provisions appropriate for use in a regional CAISO balancing authority area that encompasses multiple states. The primary objective of this initiative is to implement a multi-state process that ensures sufficient capacity is offered into the Regional ISO's market to serve load and operate the electric grid reliably. This initiative is one of several regional integration initiatives targeted for completion by the end of 2016 and is focused on ‘need to have’ items.

Policy Development

On April 13, 2016, the CAISO issued the Revised Straw Proposal that proposed to maintain the current capacity-procurement programs for local regulatory authorities and load-serving entities while having the CAISO communicate its forecasted reliability needs to inform capacity procurement decisions.

On May 26, 2016, a Second Revised Straw Proposal was published that adds discussion on two new items: (1) RA unit outage substitution rules for internal and external resources, and; (2) discussion of import resources that qualify for RA purposes.

CESA submitted brief comments focused on recommending that the CAISO incorporate default counting rules for energy storage systems. These rules should appropriately value Regulation Energy Management (REM) capacity that accounts for the full storage range from charging to discharging. CESA also commented on the need to limit the use of Maximum Import Capabilities (MIC).

See CESA's comments on July 29, 2016 on the Second Revised Straw Proposal

On August 10, 2016, the CAISO held a stakeholder meeting to discuss the reliability assessment topics within the Second Revised Straw Proposal. A key challenge in this matter is, jurisdictionally, who should determine ‘counting’ rules for RA capacity. To some, the CPUC is the appropriate party. Other states and Balancing Authority areas also have their own approaches. Finally, the CAISO, responsible for reliability, likely wants or needs some say in capacity accounting.

On October 6, 2016, the CAISO held a stakeholder meeting in Folsom, CA to review the Third Revised Straw Proposal. There are several issues that need to be resolved. For example, there are concerns about whether the CAISO’s Regional RA rules would supersede some or all of the CPUC’s existing RA rules, and whether Regional RA rules implementation should be delayed until regional governance rules are resolved. In addition, there are disjointed views among stakeholders regarding who jurisdictionally should determine 'counting' rules for RA capacity.

On December 1, 2016, the CAISO published a Regional RA Framework Proposal that addresses the full range of issues discussed throughout the Regional RA Initiative. The proposed framework would provide the flexibility for Local Regulatory Authorities (LRAs) and Load Serving Entities (LSEs) to maintain much of their current capacity procurement programs, while the CAISO would clearly communicate forecasted reliability needs to inform their procurement decisions. The CAISO intends to change only those tariff provisions that require modification to make RA work in the context of an expanded multi-state balancing area. The proposal also includes further details on load forecasting, reliability assessment, maximum import capability, RA import requirements, resource substitution issues, RA requirement allocations, and local RA needs and procurement monitoring.

The Regional RA proposal continues to experience disagreement among stakeholders. The main issue is how or whether PacifiCorp should be able to operate under different rules than California utilities. For instance, PacifiCorp wants rules to allow its planning to be for greater than 100% of its forecasted need, with the expectations that spot-market energy purchases can provide for some of its needs. This differs from California planning where spot purchases are deemed less reliable and so generally not allowed for RA purposes. The CAISO currently is proposing to allow PacifiCorp to rely on up to 10% of its needs from spot energy purposes. California parties have thus expressed concerns with the CAISO’s direction. See the summary of the CAISO's responses to stakeholder comments received on the Draft Regional RA Framework Proposal.

SB 350 Regional Integration Study

Background

In 2015, Senate Bill 350 (SB 350) directed that the CAISO consider the benefits of regional expansion, along with a 50% Renewables Portfolio Standard (RPS). The CAISO hired multiple consulting and modeling groups to support its study-efforts. Fundamentally, this study is a step to investigate changes to the CAISO’s governance, but the potential robustness of the study may highlight key pathways for 50% RPS portfolio and for integration solutions (e.g., energy storage, curtailment, exports).

On February 8, 2016, a stakeholder meeting was held that previewed the study assumptions and methodology. CESA focused on how the study’s assumed high costs for energy storage and California's historical preference for siting the majority of RA capacity in-state.

See CESA's comments on February 19, 2016 on the study assumptions and methodology.

On May 24, 2016, the CAISO unveiled the SB 350 Study’s preliminary results. CESA challenged some of the SB 350 Study’s assumptions, which may overstate the benefits to California ratepayers of a Regional ISO as opposed to in-state renewables and energy storage.

See CESA's comments on June 22, 2016 on the preliminary results.

On July 12, 2016, the CAISO released the final results (see executive summary and presentation) on the potential effects of creating a multi-state, regional electric market. The findings show that by expanding the energy grid, California would reach its 50% RPS goal while saving consumers up to $1.5 billion by 2030, lowering GHG emissions and adding jobs in California. Following the finalization of these study results, the CAISO will share the study with key California agencies and offices, including the Governor’s Office, CPUC, CARB, and CEC. In its comments, CESA re-emphasized the importance of in-state solutions such as energy storage that can play a role in renewables integration, GHG reductions, creating clean energy jobs, and ensuring grid resiliency. CESA also requested careful review of the regionalization implications for the TPP.

See CESA's comments on August 2, 2016 on the final results.

On July 21, 2016, the CAISO published an addendum to the SB 350 study that includes two additional sensitivities requested by stakeholders: 1) to conduct a full ratepayer analysis of high energy efficiency and 2) to provide a scenario modeling a 60% renewable portfolio standard. In the high energy efficiency (EE) case, cost savings related to regionalization decrease slightly as compared to baseline scenarios because less solar is needed and renewable integration challenges are reduced. In the 60% RPS case, cost savings related to regionalization are doubled as compared to baseline scenarios because out-of-state renewable resources reduce the need for over-procurement of curtailment solutions.

On September 16, 2016, the CAISO submitted the Final Study Results to the Governor’s Office.

Regional ISO Governance

On July 26, 2016, the CEC, CPUC, and ARB jointly hosted a public workshop (CEC Docket No. 16-RGO-01) on a new proposed governance structure of a regionalized ISO. In response to concerns about preeminence of California policy goals, the new governance document added binding provisions to protect and preserve state authority over state matters (such as procurement policy and resource planning) and removed the commitment to develop a mechanism for tracking and accounting for GHG emissions (which the CAISO believes does not involve corporate governance). If the principles are incorporated into state legislation, a transitional committee will be formed to develop a transition process, Regional ISO Board, Western States Committee (WSC), and stakeholder processes.

On August 8, 2016, Governor Brown issued a letter to the State Legislature that he intends to pursue legislation in January 2017, thereby extending the timeline to refine the Regional ISO governance proposal. The extended timeline also provides additional time for key state agencies to continue to work on key concerns/complexities with Regionalization so that the Legislature may, in 2017, direct changes to the CAISO governance so that it is more regionally governed. Presumably, this would occur in conjunction with out-of-state Balancing Authorities like PacifiCorp joining the CAISO to be full participants in the CAISO, akin to PG&E, SCE, and SDG&E..

On September 16, 2016, the CAISO posted a Second Revised Proposal for principles for governance of a regional ISO.

On October 17, 2016, the CEC and Governor's Office hosted a workshop in Sacramento, CA on the Second Revised Proposal.

The election of Donald Trump has now led to views that regionalization may be more difficult. Regionalization would likely involve some reduction in California’s control over the CAISO with increased influence in the CAISO from other Western States. Given that other states may differ from California on environmental goals and the Clean Power Plan is expected to abandoned, California’s leaders seem less inclined to cede authority.

On January 12, 2017, a meeting on regionalization was held at the Capitol in Sacramento, CA. Disagreement exists among stakeholders on:

Governance models
Control of regional RA rules and transmission cost allocation
Risks and potential effects of regionalization to RPS 'buckets'
GHG benefits, risks, and compliance

Additionally, turnover in the Governor's office has stalled the effort, and it remains unclear if and/or when draft legislation will be authored and who in the Legislature might carry it.

On September 7, 2017, the EIM Regional Issues Forum met on September 7 to discuss a number of regionalization issues, including resource sufficiency, REC and GHG treatment, resource pricing, and fuel constraint management in the EIM.

Market Reports & Informational Sessions on Regionalization & Energy Imbalance Market (EIM)

On June 7, 2017, the Assembly Utilities & Energy Committee hosted an Informational Hearing on Regionalization that provided an opportunity for Legislators to come up to speed on regionalization by hearing from speakers from the CAISO, labor groups, environmental groups, and others. CESA offered public remarks. Nine Assembly Members attended, which is significant for an Informational Hearing. While some groups (including the CAISO) favor regionalization, other groups have seen risks in it, such as how it might require changes to California's governance of the CAISO or to where renewable projects are developed.

A key concern raised by legislators raised was how regionalization may ‘increase costs’ of electricity. They pressed the CAISO to explain if regionalization would lower costs or keep costs from rising as quickly. CAISO claimed that regionalization would help with the latter. Labor representatives made a strong case that regionalization could threaten California labor if it shifted the development of renewable projects directed by California's policies into other states, yet continued to ask California ratepayers to pay for projects. The facts, needs, and benefits for regionalization remained unclear or confusing to many, although the CAISO did highlight the theoretical benefits. Many speakers cited facts and study findings to make their case, but one speaker's facts were often contradictory to another’s, muddying audience member understanding, or so it seemed.

The Legislators understood that a key barrier to regionalization is the CAISO's governance model, and that legislative action is needed to change this governance model to allow for new Board members or other forms of representation from non-California appointees. The Legislators generally did not signal whether they would do this.

CESA expressed a view that energy storage is very well-suited to provide solutions to renewables integration and to the ‘duck curve’, and noted respectfully that some aspects of the CAISO’s study should be reviewed. CESA expects that the Legislature will not direct changes to the CAISO’s governance structure this year. Some parties may continue to explore how to modify CAISO governance, with the CAISO driving some of this inquiry. The CAISO’s goals for regionalization seem to include its desire to have a larger footprint and to help with renewables integration.

On July 10, 2017, the CAISO issued the Q1 2017 Market Issues & Performance Report that found that a significant amount of transfer capacity was added with Arizona Public Service (APS) and Puget Sound Energy (PSE) joining the Energy Imbalance Market in October 2016, creating little congestion between these regions.

On October 18, 2017, the CAISO released its Q3 report that showed that the EIM produced benefits of $40 million for its five participating members. The CAISO noted that the EIM has helped to reduce the amount of energy flexibility reserves that utilities have needed due to the real-time optimization capabilities of the EIM.

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System Market Power Mitigation

Background

On September 3, 2019, the CAISO published a white paper analysis of the structural competitiveness of the CAISO market at the system level based on the CAISO’s DMM annual report in June 2018 that there may be an increase in the ability of energy suppliers to exert market power in the day-ahead market at the system level. Using the “residual supply index” (RSI) test to evaluate competiveness (i.e., whether load can be met without the three largest suppliers, the CAISO’s analysis concluded that the market was likely structurally uncompetitive in 201 hours, or 2% of all hours in 2018, less than the DMM analysis, because the CAISO evaluated the day-ahead and real-time market structures together. However, these failures generally occurred during the net load peak hours when supply was extremely tight, raising reliability concerns. Given these issues, the CAISO is considering several options:

Increased fixed-price forward energy contracting by LSEs to hedge exposure and incent aggressive supply bidding
Provide more RA resources to address tight supply conditions (e.g., IRP Reliability Procurement)
Enhanced ISO market scarcity pricing provisions to incentivize bidding at marginal costs even during tight supply conditions
System-level market power mitigation process, such as default energy bids for imports

On September 19, 2019, the CAISO shared a conceptual design proposal that laid out design principles, such as establishing effective measures on actual and potential market exercising opportunities while not discouraging robust market participation and long-term contracting, and would mitigate suppliers in constrained and potentially uncompetitive areas in the real-time market. The CAISO argued that this conceptual design proposal is practical to implement by modifying and extending existing market functionality, with the design being expanded in the future to the day-ahead market if the market does not behave as economically presumed. Specifically, the CAISO proposed the following conceptual approach to system-level market power mitigation:

Determine whether the CAISO’s balancing authority area is import-constrained.
If it is import-constrained, test to see whether the internal supply is structurally competitive, where “internal supply” would also include supply and demand within the Energy Imbalance Market (EIM) that is price converged with the CAISO balancing authority area
If the internal supply is not structurally competitive, mitigate the energy offers of internal suppliers, but the CAISO would not test the external supply for structural competitiveness or mitigate the energy offers of external suppliers

The CAISO discussed how it will deem the CAISO balancing area as import constrained when its three major interties are simultaneously constrained. Unless import constraints are actually binding, the CAISO balancing area is part of a broader constrained area within the western interconnection, such that it would be unworkable for the CAISO to test the true supply competitiveness and incomplete for the CAISO to only evaluate offers in its own area.

On October 28, 2019, the CAISO published a Scoping Document that outlined the design principles for market power mitigation process measures to address system market power and laid out the following scope for Phase 1:

Implement system market power mitigation in the real-time market only
Only mitigate for system market power if the CAISO balancing area is import constrained
Use a RSI with a three pivotal supplier test to determine if the supply mix is competitive
Mitigate internal resource offers within the CAISO

The objective of Phase 2 will be to develop a broader system market power mitigation design that can be implemented over a longer timeframe, including enhancing the EIM mitigation design and expanding the process to the day-ahead market.

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Storage As Transmission Asset (SATA) (Stakeholder Process)

Background

The CAISO continues to look at energy storage options in the TPP process. To date, the CAISO has deployed storage as a transmission-only asset only where all costs are recovered through the transmission access charge, or has ‘selected’ energy storage to be procured in a CPUC process as a local capacity asset to address transmission problems but operate as an RA asset that receives capacity payments and energy market revenues (e.g., Oakland Clean Energy Initiative). There have not been any cases where energy storage as transmission assets under cost-based payments participates in the market and earns market revenue.

This initiative will explore how transmission connected electric storage resources can provide cost and market-based services to maximize their efficiency and enhance their value to the system and ratepayers. Developments in this initiative will be important to make energy storage as transmission asset more viable in terms of cost-effectiveness versus conventional transmission investments.

Underpinning any proposal will be adhering to the following principles from the FERC Policy Statement (PL17-2):

Mitigate market distortion concerns: The potential for cost recovery through cost-based rates to inappropriately suppress competitive prices in the wholesale electricity markets to the detriment of other competitors who do not receive such cost-based recovery.
Maintain ISO independence: The level of ISO control over the operation of the electric storage resource could jeopardize its independence as the market operator (i.e., no direct ISO control).
Avoid double compensation: The potential for combined cost-based and market-based rate recovery to result in double recovery of costs by the electric storage resource owner or operator to the detriment of the ratepayer.

Issue Paper

A stakeholder call was held on April 6 to discuss the initiative’s Issue Paper. The Issue Paper proposed to focus on transmission-level energy storage systems only that are connected to the CAISO-controlled grid. Energy storage resources considered in this initiative must be needed for reliability-based transmission and thus must be selected in the TPP. In other words, energy storage resources procured or contracted for reasons beyond meeting a reliability need identified by the CAISO in the TPP are outside of the scope. Key questions were raised by stakeholders on how the CAISO will forecast energy market revenues in the TPP or how it will predict an applicant’s ability to manage or maximize market revenues, both of which the CAISO has not done historically in the TPP. However, in the Issue Paper and on the stakeholder call, the CAISO clarified that the scope does not include TPP evaluation methodologies or its competitive solicitation framework, which will be addressed later in the TPP at the conclusion of this initiative. Furthermore, the CAISO clarified that the scope will not include the cost allocation mechanism itself for cost-based revenue requirements.

The Issue Paper proposed to focus on transmission-level energy storage systems only that are connected to the CAISO-controlled grid. Energy storage resources considered in this initiative must be needed for reliability-based transmission and thus must be selected in the TPP. In other words, energy storage resources procured or contracted for reasons beyond meeting a reliability need identified by the CAISO in the TPP are outside of the scope. Key questions were raised by stakeholders on how the CAISO will forecast energy market revenues in the TPP or how it will predict an applicant’s ability to manage or maximize market revenues, both of which the CAISO has not done historically in the TPP. However, in the Issue Paper and on the stakeholder call, the CAISO clarified that the scope does not include TPP evaluation methodologies or its competitive solicitation framework, which will be addressed later in the TPP at the conclusion of this initiative. Furthermore, the CAISO clarified that the scope will not include the cost allocation mechanism itself for cost-based revenue requirements and will not consider SATA resources that count as RA resources, as these resources are already taken into account when determining local capacity area needs.

The CAISO is proposing two options for discussion for TAC recovery for energy storage as transmission assets:

Option A. Wholly in ratebase: This option ensures that the total revenue requirement (TRR) is covered through the TAC, and market revenues reduce the TAC portion of the transmission asset. There is no potential upside other than the guaranteed cost recovery. Additional consideration is needed in how and when storage as transmission can participate in other markets. If guaranteed through the TAC, it is unclear why a resource would pursue energy market revenues.

Option B. Partially in ratebase: This option only partially guarantees recovery of TRR through the TAC, but this option is structured so that a storage owner could recover more than the transmission requirement, or not quite recover it all. There is no crediting against the TAC, but there is both upside and downside risk to be recovered as a portion of its costs.

Because transmission resources operate on a ‘cost-of-service’ ratebase model, special consideration is being given to the treatment of any energy revenues or charges related to the operation of the energy storage resource as transmission, or when the resource acts as a profit-seeking ‘market’ resource at times when unneeded as a ‘transmission resource’. In this initiative, the CAISO sought to develop rules and accounting protocols for energy storage as transmission to avoid cases where: (a) transmission ratebasing cross-subsidizes a market resource; or (b) the CAISO's independence as a transmission operator is compromised by profit-seeking market actions from a transmission resource. Additionally, the CAISO will explore how energy storage resources will manage their state of charge and longevity to ensure delivery of the transmission service across time. The CAISO had FERC’s blessing to pursue this work based on FERC decisions and past approvals.

CESA thanked the CAISO and supported the scope but offered a few ways in which it can be expanded, such as considering all viable transmission opportunities – i.e., economic and policy projects, not just reliability-based projects. In addition, CESA noted that distribution-connected energy storage resources as transmission assets could be within scope so long as CAISO visibility needs are met. CESA also commented on the CAISO’s two proposed options for discussion but added that a third option should also be considered, where energy from energy storage operations are treated as ‘system losses’ and are accounted for as Unaccounted for Energy (UFE). CESA emphasized the need for discussion on energy storage operations as well as making sure that market revenue projections in this initiative are fed back into the TPP to ensure energy storage resources are not disadvantaged in the evaluation process due to underestimated market revenues credited against their costs. Finally, CESA supported the use of FERC’s principles to guide this initiative but recommended one revision to not exclude cases where energy storage can reasonably be compensated for doing multiple things at once, in line with our ongoing MUA with the CPUC and CAISO.

See CESA's comments on April 20, 2018 on the Issue Paper

There was a wide range of views from stakeholders reflected in the comments. Some parties, such as IEP and providers of other resource classes, wondered why this initiative was limited to energy storage resources when other resources, such as gas generators, can address transmission reliability needs, while others had principled concerns around CAISO independence and anti-competitiveness impacts of cost-based resources. These parties also argued to ensure that SATA resources undergo the appropriate interconnection study processes, or contended that state resource planning processes may be more appropriate for comparing transmission alternatives. Energy storage parties generally supported the initiative and offered suggestions that the scope be expanded to include SATA projects for economic and policy driven needs and to consider TPP evaluation methodologies for projecting market revenues. NextEra also proposed binding minimum market revenues similar to cost caps for transmission capital investments as a way to ensure reductions in transmission revenue requirement (TRR) costs.

In response to CESA’s comments of expanding the scope of the initiative to also include economic and policy driven needs, the CAISO stated that the Transmission Economic Analysis Methodology (TEAM) is focused on the market resource benefits and improvements to the access of cost-efficient resources rather than improvements to the transmission system capacity. The CAISO also did not want to duplicate CPUC resource planning processes where economic-driven transmission could be procured to reduce local capacity needs, in which case the storage resource should compete in the RA framework. While the CAISO will consider energy storage to meet economic-driven transmission needs when the solution reduces congestion, the CAISO noted that the majority of the economic benefits of energy storage projects appear to occur when they act as resources competing with other market resources. Regarding distribution-connected resources, the CAISO said it would consider such resources on a case-by-case basis and that these resources should be procured instead through local capacity procurement processes. Limiting the scope to resources directly connected to the CAISO-controlled grid has the advantages of direct operational line of sight and clarity on cost allocation (regional or local TAC) based on the voltage the storage is interconnected to.

In response to stakeholder comments regarding the CAISO’s independence, the CAISO explained that the hours in which the resource will be most needed for transmission will be the same hours in which the resource would most likely have the ability to significantly impact energy market prices. Additionally, to the extent that SATA resources may lower energy prices in some intervals while discharging, they would increase the price in other hours when the resource is charging.

Straw Proposal

On May 24, 2018, a stakeholder meeting was held on May 24 to discuss the Straw Proposal. The CAISO provided an overview of the TPP cycle in response to stakeholder comments on the need to refine the TPP evaluation methodology to accommodate energy storage as transmission assets. In particular, the CAISO commented that there may be opportunities to revise and refine evaluation methodologies in Phase 2 of the TPP cycle (e.g., specific times the resource is needed for transmission services) to account for market participation of transmission assets. The CAISO also clarified its position to not limit the scope of energy storage as transmission to just transmission-connected assets, as it could also include distribution-connected energy storage systems, but noted that the consideration of issues for transmission-connected storage in this initiative should not affect the consideration of other energy storage solutions, which can be addressed in the TPP. Previously, the CAISO held the position that this initiative will only focus on transmission-connected energy storage due to the CAISO’s visibility of the energy storage resource.

Importantly, a key development in the Straw Proposal is that the CAISO proposed a new contract that would include a combination of the Transmission Control Agreement (TCA) provisions (e.g., transfer of operational control, system operation/maintenance, system emergencies, critical protective systems) and participating load/generator agreement provisions regarding how energy storage resources will be compensated when it can participate in market. Recall provisions will also be included in the new contract that allows the CAISO to divert the resource from market participation to transmission service during emergency system needs, with notice provided to the resource owner regarding the nature of the need and expected duration of the need. Notably, the CAISO expressed that it aims to retain the right to make necessary modifications to market participation of the resource and to build in additional limitations if system conditions change and affect the underlying transmission need. When it comes to the terms and conditions for market participation, the CAISO proposed to use concepts similar to those in RMR agreements where resources are compensated by the CAISO for all or some portion of its fixed costs and can participate in the CAISO markets. Whether an energy storage asset can serve a transmission need will depend on the predictability (as quantified through variable probabilities) of the transmission need by month or hour(s), the CAISO explained.

The CAISO also added details on how energy storage assets selected in Phase 3 of the TPP would not be required to request interconnection through the CAISO’s generator interconnection processes, but questions were raised to stakeholders on how excess capacity interconnecting at the same point of interconnection would be addressed in the interconnection process.

No changes were proposed on the full cost-of-service (through the TAC) and partial cost-of-service cost recovery mechanisms previously proposed for discussion in the Issue Paper. However, the CAISO clarified that energy storage resources may not request increased cost-of-service cost recovery under Option B if forecasted market revenues do not reach expected levels. The CAISO also sought stakeholder comments on how to ensure resources receiving full cost-of-service based cost recovery make reasonable efforts to earn market revenues when permissible and on how to conduct competitive solicitations that may be impacted by the willingness and ability of energy storage asset operators and owners to take market risk. Additionally, there were no proposed changes on the current practice of allocating costs to high or low voltage TAC based on the point of interconnection.

CESA supported the CAISO’s efforts, including the consideration of energy storage resources for economic- and policy-driven transmission needs, but recommended the following:

The TPP should be realistic about costs of resources and reasonably estimate how market revenues of SATA resources reduce transmission cost recovery amounts.
The CAISO’s approaches should liken periods of market participation from energy storage as transmission resources to pre-approved energy storage outages.
Protocols should allow for any existing energy storage resources where appropriate to serve as transmission assets and to have some cost-of-service cost recovery, so long as that resources is not providing RA.
Oversizing of energy storage resources beyond the transmission need should be allowed with different Resource IDs for the transmission and market components, but rules should direct that the oversized capacity honor the interconnection queue line and study structure.
The CAISO should endeavor to only update or change operational periods with predetermined frequency in most cases but also factor into the TPP evaluation how energy storage resources provide optionality to meet evolving transmission needs unlike traditional transmission solutions.

See CESA's comments on June 7, 2018 on the Straw Proposal

On June 29, 2018, a working group meeting was held to discuss clarifications and examples, build off stakeholder comments, and add more detail on the pathways for the two cost recovery options. A summary of comments on the straw proposal was provided by the Center for Renewables Integration (CRI). The working group discussed four topics in more depth: TPP evaluation; policy/economic SATA projects; cost recovery options; and SATA agreement.

First, the CAISO explained that the SATA resource must meet the criteria of an “advanced transmission technology” and pass through the usual technical studies, and elaborated on the TPP process for the consideration of preferred resources. SATA resources would then be eligible for a transmission need if there is sufficient lead time for the CAISO to fall back on transmission solutions as a backstop. In conducting the TPP evaluation, the CAISO favored conducting an evaluation over a 40-year timeframe, which generally aligns with the expected lifecycle of traditional transmission solutions and provisions within RMR contracts. The CAISO indicated at the meeting that it favors an apples-to-apples comparison rather than assessing a SATA resource for 7-10 years and then having to reassess and procure for transmission needs later after the first lifecycle of the SATA resource. In assessing the predictability of the transmission need, the CAISO discussed the uncertainties of load forecasts and other policy drivers (e.g., TOU rates, transportation electrification), which likely require more granular and hourly load forecasts because energy storage solutions are likely local in nature. This is where energy storage has significant potential value since energy storage provides optionality to respond to load forecast uncertainties – i.e., to downsize or expand depending on the changing nature of the transmission need. Flexibility in the TPP process will be needed since traditional transmission solutions have been historically selected and procured to meet a precise transmission need.

While the focus of this initiative thus far has been on how SATA resources can address grid reliability needs, the CAISO changed its position and responded in favor of CESA in also considering on a case-by-case basis how SATA resources can be selected for policy and economic transmission projects. The CAISO observed that there have been no identified opportunities or procurements thus for storage for economic-driven transmission projects. Generally, the CAISO explained that the evaluation of reliability solutions is more straightforward since capital costs are the primary economic consideration and the benefits are comparable based on delivering on the specific reliability need, but the evaluation of economic solutions is more complex because the value of net benefits is based on the net present value of market participation, financial inputs (e.g., discount rates), and operational assumptions (e.g., O&M costs, lifecycle). The CAISO explained that it plays no role on determining the return on equity (ROE), which is set based on an evaluation of a “proxy group” of companies with similarities (e.g., risk profile). This points to how the CAISO will need to develop a framework to source cost data (e.g., capital costs, replacement costs) and value various benefits. However, the CAISO indicated its position that the economic-driven transmission framework should not serve as an alternative to resource planning, citing examples where energy storage that participates as a local capacity requirements in an area and indirectly increases the path flows of a transmission line would not qualify as a transmission asset, whereas energy storage that “pushes back” on a limiting flow on a transmission line and directly increase the path flows would qualify. Other criteria for eligible SATA project opportunities include the need for CAISO visibility, expected constrained operations, lack of alignment of RA obligations with transmission system needs, and overly complex interconnection of resources as a market resource.

The CAISO revised the framework in which the two cost recovery options would be made available based on where the SATA resource interconnected. SATA resources interconnected at the “local” level (less than 200 kV) would be directly assigned to the incumbent participating transmission owner (PTO) due to the lack of competition (i.e., local projects are not open to the TPP Phase 3 competitive solicitation process) and only be allowed full cost-of-service recovery. By contrast, because competition is available at the regional level (greater than 200 kV), SATA resources would be open to both PTOs and non-PTOs and would have the option to choose between full cost-of-service or partial cost-of-service with market risk. Another criterion of whether Option 1 and/or Option 2 would be made available would be based on the predictability of the transmission need. However, if partial cost-of-service is selected, the CAISO clarified that it would not allow the SATA resource to switch to full cost-of-service if actual market revenues are not reaching forecasted market revenues. For both scenarios, charging and discharging of the SATA resource would still be assessed at market rates during reliability events even though it is not directly participating in CAISO markets, since this behavior must be reflected in the market. Finally, cost recovery would apply to network upgrades (covered through the transmission revenue requirement) and only for ‘right-sized’ solutions to avoid interconnection queue jumping.

SDG&E and CRI presented their proposals to enhance the cost recovery options. SDG&E noted that it favors the full cost-of-service option because there are concerns about queue jumping of the partial cost-of-service option and inability to claim partial cost-of-service assets as tax liabilities. To address concerns of the lack of incentive to participate in the market to reduce the ratebased portion, SDG&E proposed allowing the “50-50 splitting” of market revenues between the SATA operator and the ratepayer. CRI, meanwhile, focused on addressing the financeability concerns of the partial cost-of-service option through secondary bilateral contracts between the applicable LSE and the SATA project sponsor.

Finally, the CAISO’s vision is to have one agreement that encompasses all the scenarios and cost recovery options. The SATA agreement would be separate from the Transmission Control Agreement (TCA) to facilitate easier modifications and provisions in the agreement would outline “operational control” by the CAISO of the SATA resource, such as through out-of-market state-of-charge requirements. Importantly, the CAISO has not determined whether owners of SATA resources would need to become PTOs, which the IOUs favor, but CESA agrees with the CAISO that this may be unnecessary since the majority of Transmission Control Agreement (TCA) provisions do not apply to energy storage, especially for local energy storage units that are not connected to other parts the transmission grid (e.g., transmission maintenance requirements do not seem to apply).

CESA focused on making sure that the SATA Initiative continues to progress without unnecessarily limiting how SATA resources during identification of eligible transmission grid needs, evaluation during the TPP, and determination of cost recovery options. Specifically, CESA commented on the following:

Seeking “backstop” solutions for identified transmission needs should not be a binding criterion by which SATA resources would be eligible.
The CAISO has the potential flexibility to procure SATA resources as “closer to the edge” solutions that account for changes in load forecasts.
Clarifications should be provided that allow appropriate sizing of the SATA resource to account for degradation and/or some de minimis margin of oversizing.
Net present value (NPV) evaluation of SATA resources accommodate a “like for like” comparison across a 40-year period but also recommends explorations such comparisons on a somewhat shorter timeframe as well.
CAISO should accommodate “control” preference of resources, such as state-of-charge management, must-offer obligations, etc.
Any of the three cost recovery mechanisms are viable and the CAISO should solicit proposals for SATA projects selecting any of the options in addressing transmission service needs.

See CESA's comments on July 16, 2018 on the June 29, 2018 Working Group meeting

On August 21, 2018, a meeting was held to discuss the Revised Straw Proposal, which maintained many elements of the Straw Proposal, including the proposal to develop a new and separate SATA agreement. One key change in the Revised Straw Proposal was that the CAISO proposed to add an “Option 3” for SATA resource cost recovery, in addition to the original two cost recovery options:

Full cost-of-service based cost recovery and energy market crediting
Partial cost-of-service based cost recovery and no energy market crediting where the SATA resource will bear both upside and downside risk from market services
Full cost-of-service based cost recovery with partial market revenue sharing between owner and ratepayer

The other key additions were around the proposed bidding requirements and notification options for SATA resources. First, to ensure that SATA resources providing market service do not inappropriately suppress market prices, the CAISO proposed to develop a Transmission Revenue Requirement (TRR) crediting structure based on the expected useful life of the resource to incentivize the efficient use of these resources, ensure that ratepayers receive the expected benefits, and ensure that SATA resources bid at marginal costs. Specifically, the CAISO proposed to calculate an energy storage system’s capital cost based on a “use credit” that is applied against the resource’s overall TRR for each instance of market-based dispatch and that would be fixed for all MWh of a resource’s market-based discharges. The formula are as follows:

Option 1: TRR = (Capital Costs – (Cap Cost Credit Multiplier x MWh discharge)) x ROE) + Variable O&M + A&G
Option 2: TRR = (Capital Costs – (Cap Cost Credit Multiplier x MWh discharge)) x ROE) + Variable O&M + A&G

Second, the CAISO initially indicated that it wanted to identify specific hours, months, or seasons when a SATA resource would be permitted to provide market services but found that such specific information may not be provided with certainty during Phase 2 of the TPP. Therefore, the CAISO proposed two new notification options to maintain its independence and ensure that transmission services take primacy over market participation. The first option is the day-ahead (DA) option. Under the DA option, the CAISO will evaluate the needs for SATA resources to be used as transmission asset in the Day-Ahead Market (DAM). The CAISO will generate a bid right below the transmission relaxation penalty in DAM RUC run. If DAM clears the SATA resources, then SATA resources will be deemed as “Transmission Service Asset” and will not be allowed for market based participation. If DAM does not clear the SATA resources, then SATA resources will be allowed to bid in the Real-Time Market. The second option is a two-days prior to the operating day (D+2) option. Under the D+2 option, the CAISO will evaluate the needs for SATA resources to be used as transmission asset two days prior to the operating day, at D+2. Similarly, CAISO will generate a bid right below the transmission relaxation penalty for SATA resources in D+2 RUC run. If SATA resources are cleared in this process, then SATA resources will be deemed as a “Transmission Service Asset” and will not be allowed for market based participation. If SATA resources do not clear in the D+2 process, then SATA resources will be allowed to bid in both DAM and Real-Time Market. No major details were provided on the potential SATA agreement, as the CAISO discussed how policy details must first be finalized before outlining contractual provisions.

CESA supported the CAISO's addition of an Option 3 and notification options in the Revised Straw Proposal, but recommended that the CAISO leverage the SATA agreement to ensure ratepayer protections, rather than using a more complicated TRR crediting mechanism. Overall, while CESA expressed that the CAISO is moving in a good direction related to cost recovery options and market participation pathways, there are concerns about degradation that have motivated the CAISO to propose a TRR crediting mechanism that reduces the TRR based on expected lifecycles. CESA also reminded the CAISO of different alternative energy storage technologies as well, since lithium-ion batteries seem to be the focus of the CAISO proposal.

See CESA’s comments on September 4, 2018 on the Revised Straw Proposal

Many parties echoed the concerns about using the TRR crediting mechanism and instead recommended relying on the SATA agreement to enforce lifetime of the SATA resource and to give autonomy to market participants to reflect their full operating costs in their marginal cost bids. These concerns included differences in energy storage technologies, difficulties and litigiousness of administratively estimating and setting TRR credit, complexities of calculating degradation costs (e.g., degradation is not just a function of cycles but also by application), and disagreements on whether divided fixed capital costs represent short-run variable costs. Only ORA, NRDC, and CEERT were supportive of the TRR crediting mechanism.

To address market price suppression concerns, several different ideas were proposed, including having the CAISO set a floor or reference price (Calpine, WPTF), $/MWh “wear and tear” discharge cost (SCE), or opportunity cost of market participation (Six Cities), or just relying on market monitoring processes (Northwest Hydroelectric Association). Several parties representing market-participating generators appear unconvinced by the CAISO’s arguments addressing market price suppression concerns and called for greater analysis to support this important principle. Meanwhile, all parties seemed to agree that notification to all market participants of SATA resource use for transmission services is needed to avoid gaming and ensure fair and non-discriminatory access to market information and participation, and to agree that D+2 notification options are preferable to allow for access to both the day-ahead and real-time markets. Finally, preferences for cost recovery options continued to vary among parties. The IOUs and ORA, among others, favored Option 3 due to the balance of greater incentives for market participation, easier comparability of bids, and (supposedly) more reliability of transmission service provision, but others argued for maintaining Option 2 due to the greater cost-effectiveness to ratepayers.

On October 23, 2018, the CAISO held a stakeholder meeting to discuss the Second Revised Straw Proposal issued on October 16, 2018. Some of the key updates were that the CAISO plans to:

Maintain Option 2 (i.e., partial cost-of-service) due to sufficient stakeholder support to maintain this option
Eliminate the Transmission Revenue Requirement (TRR) crediting mechanism to manage cycle life of the SATA resource and instead to rely on a contractual alternative
Develop 10-year, 20-year, and 40-year variants of the SATA agreement, with differences around escalation factors, market participation conditions, maintenance obligations, capital additions and repairs, and testing and monitoring
Eliminate the prior-to-day-ahead market notification option due to operational concerns over the available forecast, resource bid availability, and lack of detail on constraints
Develop a load-based notification test process to determine of SATA resources will be needed for the following day

Regarding the contractual alternative to the TRR credit mechanism, the SATA agreement will detail the maintenance and replacement obligations consistent with Option 1, 2, or 3 selected by the SATA owners. The SATA owner will then be responsible for maintaining the resource at a certain pre-defined performance level consistent with meeting the transmission solution requirements, as identified in the agreement, and the CAISO will test the resource periodically to ensure transmission requirements are being met, with the results dictating implementation of maintenance or replacement plans. Depending on agreement terms, cost sharing of maintenance and replacement costs will be negotiated between SATA owner and CAISO and may be calculated based on historical performance for transmission versus market dispatches. Degradation due to market-driven use of resource will likely be paid for by SATA owner without CAISO cost recovery. The CAISO seeks specific input on these contractual terms.

Other key areas where the CAISO seeks additional input are around whether a MOO must be established for direct-assigned SATA resources that sets the discharge price at the energy price cap or at the 95% level at a given location to mitigate market price suppression and to ensure CAISO independence. The CAISO also seeks stakeholder input regarding whether it should make the same provisions available to both direct-assigned projects and to projects subject to a competitive solicitation process.

CESA continued to support the direction of the SATA proposals, including the retention of the Option 2 cost recovery option and elimination of the TRR capital crediting mechanism, which CESA previously found to be unnecessarily complex. The CAISO was responsive to our concerns and made changes accordingly. However, CESA expressed some disappointment with the elimination of the D+2 notification option that determines whether a SATA resource is freed to participate in the market. In doing so, CESA expressed how value is left on the table by only allowing SATA resources to participate in the real-time market, which eliminates day-ahead market products such as frequency regulation capacity from being provided by SATA resources. Instead, CESA recommended the re-inclusion of the D+2 option with an “option” for the CAISO to place the SATA unit into transmission service after the D+2 period but before real-time – i.e., by “unwinding” the day-ahead schedule it has been awarded. CESA also recommended that historical load deviations in transmission service pockets to be evaluated, rather than conservatively settling on a 10% buffer.

See CESA’s comments on November 12, 2018 on the Second Revised Straw Proposal

On January 14, 2019, a stakeholder call was held to discuss the current status of the initiative and to highlight the lingering issue of SATA resource dispatch in the market using the NGR model, where the market optimization of the SATA resource as an NGR would lead to potential dispatch not aligned with what is needed for the transmission service (i.e., it may result in exceptional dispatch). The CAISO instead explained that the ESDER initiative would be the more appropriate venue to address technical bidding requirements, including the potential to explore minimum bid price requirements or opportunity cost bidding. For opportunity cost bidding, a new set of provisions may be needed for energy storage (e.g., “spread bidding) since the RMR and CPM provisions are not applicable to energy storage resources. The CAISO added that SATA resources would need to receive different treatment than NGR resources providing market-only services under the load-based notification test. As a result, the initiative was indefinitely suspended to deal with these lingering issues, with final approval of the SATA proposal by late 2019 as an additional issue added to the scope of the forthcoming ESDER Phase 4 Initiative. Consequently, we may not see opportunities for SATA resources until the 2020-2021 TPP cycle when the SATA policy and market development process wraps up ahead of March 2020.

CESA expressed concern about the delay, given all the work already put into developing proposals, and sought to further understand the lingering issues. At the same time, CESA observed that ESDER is a more technical working group that may be better positioned to tackle these matters. On the stakeholder call, CESA continued to indicate that the real-time optimization should model SATA resources as NGRs as a fixed, self-scheduling resource, similar to how other transmission is treated in the market algorithm.

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Transmission Cost Recovery

Background

AB 1890 directed the creation of the ISO and required the CAISO to develop within two years a transmission rate methodology based on principles including an equitable balance of costs and benefits. The CAISO also had to define those transmission facility costs, if any, to be rolled into the transmission service rate and spread equally among all ISO transmission users, and those transmission facility costs, if any, which should be specifically assigned to a specific utility’s service area. Those AB 1890 requirements form the basis of the cost recovery provisions.

The transmission system operated by the CAISO, referred to as the CAISO Controlled Grid, is comprised of transmission facilities owned, and contractual transmission entitlements held, by PTOs and for which the PTOs have turned over operational control of those facilities and entitlements to the CAISO through the Transmission Control Agreement. These PTOs recover the costs associated with owning, maintaining, and physically operating these facilities and paying for the entitlements, reduced by the transmission revenue balancing account, non-volumetric standby demand charges and revenue from existing contracts that pre-date ISO operations, from CAISO load and exports (i.e., ratepayers). The amount of costs each PTO is authorized to recover annually is referred to as its transmission revenue requirement (TRR), which must be approved by FERC.

Most of the PTOs—the investor-owned utilities (IOUs) and those municipal utilities that have turned over their transmission facilities and entitlements to CAISO operational control—have transmission and distribution service areas, which means they have end-use transmission and distribution service customers who pay their share of the costs through retail transmission charges. For such load serving PTOs, FERC also approves a Gross Load figure that is used in determining the TAC rates. PTOs that do not have a service area are typically (but not exclusively) independent or non-utility transmission developers whom the ISO selected in its competitive solicitation process to build specific transmission facilities approved in the CAISO’s transmission planning process (TPP). The TRRs of these PTOs become part of the total amount of costs that must be recovered, but these entities do not have their own retail customers who pay a share of the costs.

Each PTO’s TRR for CAISO Controlled Grid facilities and entitlements is divided into a “Regional” or high-voltage revenue requirement (R-TRR) associated with transmission facilities rated 200 kV and higher, and a “Local” or low-voltage portion (L-TRR) for transmission facilities rated below 200 kV. Currently, the CAISO combines the R-TRRs of all PTOs into a total sum and divides by the total Gross Loads of all load-serving PTOs to produce a uniform “postage stamp” regional TAC rate (R-TAC) charged to all utility distribution companies (UDCs) and metered subsystems (MSS) serving customers in the ISO area and exports from the ISO area. The regional WAC rate (R-WAC) is calculated the same way to be equal to the R-TAC rate. The ISO then remits the appropriate amount of TAC and WAS revenues to each PTO in accordance with ISO Tariff Appendix F. In contrast, each of the PTOs with Local facilities collects its own L-TRR from customers served over its Local facilities. Customers using an IOU’s Local facilities can include customers of municipal utilities that are PTOs or Non-PTOs located within the IOU’s PTO service area.

The general process for transmission cost recovery is as shown below.

Transmission Access Charge (TAC) (Stakeholder Process)

Background

In 2015, the CAISO launched its Transmission Access Charge (TAC) Options Initiative where the CAISO considered potential modifications to its TAC structure to support the possible expansion of the CAISO balancing authority area. Following that initiative, in June 2016, the CAISO opened its Review TAC Wholesale Billing Determinant Initiative to consider the Clean Coalition’s proposal to modify the point of measurement for assessing TAC charges.

The objective of this initiative is to examine potential changes to the CAISO’s current TAC structure for recovering participating transmission owners’ costs of owning, operating and maintaining high-voltage transmission facilities under CAISO operational control. In this initiative, the CAISO aims to resolve where to measure transmission usage and how to measure transmission usage. One of the key issues around the point of measurement is whether it should be moved from the end-use customer (current) and to the T&D interface.

Straw Proposal

On January 11, 2018, a straw proposal was issued. Despite stakeholder requests, the CAISO proposes to maintain its existing practice of summing hourly gross load metered at the end-use customer as the point of measurement. However, the CAISO is proposing to modify the current volumetric billing determinant to better reflect customer usage and the cost causation and benefits of the transmission system. CESA is monitoring this initiative, as it may impact whether DERs are assessed TAC charges.

On April 11, 2018, a stakeholder meeting was held to discuss the revised straw proposal that continues to examine potential changes to the CAISO’s current TAC structure for recovering participating transmission owners’ costs of owning, operating and maintaining high-voltage transmission facilities under CAISO operational control.

Final Proposal

On September 19, 2018, the CAISO held a stakeholder meeting to discuss the Draft Final Proposal to continue examining potential changes to the current TAC structure for recovering Participating Transmission Owner (PTO) costs of owning, operating and maintaining high-voltage transmission facilities under CAISO operational control.

Excess Behind-the-Meter Production (Stakeholder Process)

Background

This initiative will explore the potential market changes needed to establish a standard reporting practice for excess behind the meter (BTM) production and determine how this excess energy production (i.e., above the host customer’s load) is best represented in CAISO market processes. There are currently about 6,200 MW of non-utility BTM rooftop solar installed in the CAISO balancing area, with over 2,500 MW installed since 2016. As additional rooftop solar is installed, it is likely that the differences in current practice could become an increasingly significant issue that impacts market settlement charges, including transmission access charges. The CAISO aims to take this issue to the CAISO Board by early 2019.

Issue Paper

On June 28, 2018, the CAISO published an Issue Paper for this new initiative. During the TAC stakeholder initiative, the CAISO observed some inconsistencies in how excess BTM production was reported by the utility distribution companies (UDCs) to the CAISO in the gross load data submittals, which can impact load-based settlement charges, including allocation of transmission access charges, and lead to sub-optimal CAISO forecasts and ancillary services procurement. The different reporting practices to net excess BTM production among some UDCs and not net excess BTM production among other UDCs also have implications for unaccounted for energy (UFE) and uninstructed imbalance energy (UIE). In the example provided by the CAISO below, UDCs that net excess BTM production would incur less transmission access charges due to lower reported gross load (4 MW, as opposed to 5 MW) and incur no UFE charges (0 MW, as opposed to -1 MW) since excess BTM production exported to the grid is not captured in reported gross load.

The CAISO thus proposed to clarify that the definition of “gross load” should not net out excess BTM production because excess BTM production that is exported benefits from having access to and use of the transmission system. Furthermore, the CAISO proposed this definition to have greater visibility into the actual conditions of the grid. Finally, the CAISO proposed to treat excess BTM production as load due to the additional requirements for treating it as generation (e.g., Resource IDs, submission of hourly profiles).

Straw Proposal

On September 5, 2018, a Straw Proposal was issued and a stakeholder meeting was held that discussed how the CAISO will clarify the tariff definition for “gross load” to state that excess BTM production should not be netted from gross load to allow for the CAISO to have better insight into the quantity of excess BTM production. The new draft tariff language would include removal of an initial clause stating that gross load is used for the purposes of calculating TAC, gross load refers to a subset of demand rather than energy, and the kinds of loads (i.e., generating units and storage devices that are behind the same meter) that are excluded from gross load. The determination for UFE will also be updated to account for excess BTM production. Finally, the Straw Proposal clarified that energy generated and scheduled into the CAISO as a resource would not be subject to any change proposed in this initiative and that adjustment for distribution losses will not need to be applied for excess BTM production values submitted to the CAISO.

On November 5, 2018, a Revised Straw Proposal was issued and a stakeholder meeting was held to provide greater clarifications to the Straw Proposal. Regarding losses, the CAISO explained that excess BTM production generally travels short distances and may not reach the bulk distribution system, and therefore losses are small, leading the CAISO to conclude that it does not see it necessary at this time to apply losses to this energy when reporting to the CAISO. However, excess BTM production may reduce the overall losses from the T-D interface to retail meters, which should be captured when SCs report load to the CAISO. Finally, the CAISO discussed how it will publish an aggregation of the excess BTM production data in a monthly performance report that will be posted every other month.

Final Proposal

On December 19, 2018, a stakeholder meeting was held to discuss the Draft Final Proposal that will clarify the tariff definition of Gross Load to state that excess BTM production should not be netted from Gross Load and that will include new draft tariff language, including the following changes:

Removal of an initial clause stating that Gross Load is used for the purposes of calculating TAC
Clarification that Gross Load refers to a subset of Demand rather than Energy
Clarification of the list of kinds of load that are excluded from Gross Load

Second, the proposal will specify that excess BTM production is “energy from an end-use customer in excess of its onsite demand,” which is intended to represent the excess BTM figures that will be reported to the CAISO. This will also specify that losses will not be applied when reporting excess BTM values.

Third, excess BTM production will be reported on the same load Resource ID but distinguished by measurement type and will be subject to prices at the location where values are reported (i.e., DLAP or CLAP). The determination for UFE will be updated to account for excess BTM production. Gross Load values will be used for allocation of a number of charge codes, but allocation for these charge codes will not include excess BTM production.

Finally, excess BTM production will receive credit for offsetting losses. Excess BTM production generally travels short distances and may not reach the bulk distribution system, and therefore, losses are small. At this time, the CAISO did not find it appropriate to apply losses to this energy when reporting to the CAISO. However, excess BTM production may reduce the overall losses from the T&D interface to retail meters. This reduction in losses should be captured when SCs report load to the CAISO.

This proposal does not directly affect members. Rather, the proposal will standardize reporting for LSEs to ensure fair cost allocation of the TAC and give the CAISO greater operational visibility. The monthly reports should be very helpful going forward, as it may highlight how excess BTM production could reduce T&D losses and obviate the need for certain transmission investments.

On May 15, 2019, the CAISO Board of Governors approved the Draft Final Proposal.

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Transmission Planning Process

Background

Regulations require ISOs to consider multiple factors when evaluating need for transmission. First, ISOs consider failure scenarios and peak load conditions for reliability investments. Second, ISOs also determine if economic congestion is driving up prices in a region, and if so, identify cost-effective solutions for economic investments. Finally, ISOs determine if there are policy-driven transmission needs to address RPS or clean air requirements.

Each year, the CAISO conducts its Transmission Planning Process (TPP) to identify potential system limitations over a 10-year planning/study horizon as well as opportunities for system reinforcements that improve reliability and efficiency and maintain the long-term congestion revenue rights. The reliability analysis also satisfies NERC Reliability Standards, WECC Regional Criteria, and ISO Planning Standards. According to CAISO Tariff Section 24.4.6.6, policy-driven transmission solutions should be categorized as either Category 1 or Category 2 transmission solutions. Category 1 solutions are those that are found to be needed and are recommended for approval as part of the comprehensive Transmission Plan in the current cycle. In contrast, Category 2 transmission solutions are defined as those that could be needed to achieve policy requirements or directives but have not been found to be needed in the current planning cycle.

Finally, the CAISO also considers transmission projects for its economic benefits through production cost modeling. Generally speaking, transmission congestion increases consumer costs because it prevents lower-priced electricity from serving load, or minimizing or resolving transmission congestion can be cost-effective to the ratepayer if solutions can be implemented to generate savings that are greater than the cost of the solution. Other end-use ratepayer cost saving benefits such as reducing local capacity requirements in transmission-constrained areas can also provide material benefits. Note that other benefits and risks - which cannot always be quantified - must also be taken into account in the ultimate decision to proceed with an economic-driven project. An “economic driven” transmission project may be upsizing a previously identified reliability solution, or replacing that solution with a different project.

This annual planning process occurs in three phases:

Phase 1 - Develop detailed study plan: The CAISO outlines its planning assumptions and shares how it will conduct this study. Key assumptions are state/federal policy, demand forecasts from the CEC's Integrated Energy Policy Report (IEPR), resource forecasts from the CPUC (e.g., LTPP), and other common assumptions with procurement processes. Stakeholders may request specific economic planning studies to assess the potential economic benefits (such as congestion relief) in specific areas of the grid. This phase typically occurs between January and is finalized by March.
Phase 2 - Sequential technical studies: The CAISO conducts its reliability, policy-driven renewable, and economic analyses. These analyses include contingency analysis, technical studies (e.g., power flow, voltage), and local capacity resource studies. Preliminary results are usually shared in August, and participating transmission owners (PTOs) propose recommended mitigations (projects) in September. The Draft Transmission Plan is posted in February and the CAISO Board approves the Final Transmission Plan by March. Phase 2 also includes a Request Window to solicit and manage submissions of solution proposals for certain categories of transmission needs, project-related data, and DR/non-wires as alternatives to reliability mitigation solutions. Usually, the Request Window opens in mid-August and closes in mid-October.
Phase 3 - Procurement: Phase 3 takes place after the CAISO approves a transmission plan that includes projects eligible for competitive solicitation. Although the CAISO typically identifies a single preferred solution, the process is sufficiently flexible to identify multiple transmission alternatives that could meet the identified needs. Reliability projects less than $50 million and identified before the December ISO Board of Governors meeting are eligible for management approval and are presented at a November stakeholder session. Approving these projects allows for streamlining the review and approval process of the annual transmission plan in March of the next year. Reliability projects more than $50 million require ISO Board of Governor approval and are included in the Draft Transmission Plan. Other projects less than $50 million will be identified in January and need to be dealt with in the approval of the comprehensive plan in March. Projects eligible for competitive solicitation include regional reliability-driven, Category 1 policy-driven, or economic-driven transmission solutions, except for regional transmission solutions that are upgrades to existing facilities. Finally, projected connected at 200 kV or higher will be subject to competitive solicitation unless the project constitutes an upgrade to an existing transmission facility. Incumbent PTOs are responsible for projects connected at less than 200 kV.

The TPP is where energy storage will be considered as an option to meet transmission reliability needs as non-wires alternatives. For an asset to be approved as FERC-jurisdictional transmission, it must fulfill a transmission need identified by the ISO/RTO, meet the performance requirements established by the ISO/RTO, be selected by the ISO/RTO during their competitive process, provide a transmission service function, and comply with FERC guidelines on cost-based versus market-based revenues. A recent FERC analysis in their 2017 Transmission Metrics Staff Report showed that the CAISO awarded 9 projects in 2017, of which 4 went to local distribution companies.

Special studies are also often conducted as forward-looking studies within the TPP. For example, recent special studies include those for gas-electric coordination in the aftermath of Aliso Canyon, potential for economically-driven retirement of gas generation, and a 50% RPS scenario.

The Conceptual Statewide Plan is developed in parallel in coordination with other regional transmission planning groups to potentially identify additional transmission upgrades, additions, or elements needed to meet state and federal policy requirements. This plan is also an input into the CAISO’s Phase 2 evaluation process leading to the development of the Transmission Plan.

Starting in 2005, the Transmission Economic Assessment Methodology (TEAM) outlines a framework to assess ratepayer benefits, network representation, market prices, uncertainty, and resource alternatives. TEAM provides a standard for measuring transmission expansion benefits for consumers, producers, and transmission owners.

Legal/Regulatory Context

FERC issued Orders 888 (1996), 890 (2007), and 1000 (2011) to allow for alternative transmission solutions that would improve efficiency and competition in meeting transmission needs.

In 1996, Order 888 was issued that established a legal definition of "transmission" as infrastructure capable of providing transmission services, which are defined as transmitting electrons and/or scheduling/dispatching services, load following services, energy imbalance services, system protection services, reactive power and voltage control services, and loss compensation services. Order 888 was important because it laid the foundation for other alternative technologies such as energy storage and demand response to be eligible to provide transmission service and receive cost-based compensation.

In 2007, Order 890 was issued that required transmission planning for all transmission owners. It further defined transmission planning principles around coordination, openness, transparency, information exchange, comparability, dispute resolution, regional participation, economic planning studies, and cost allocation. The comparability principle was particularly important as it ensured that transmission owners consider proposed alternatives on a comparable basis. Citing the Energy Policy Act of 2005 (Section 1223), advanced transmission technologies are defined to include energy storage, distributed generation, demand response, and several other technologies.

In 2010, Western Grid Development built on Order 890 and requested a declaratory order from FERC that energy storage would provide transmission services as defined in Order 888 and qualify as an advanced transmission technology per Section 1223. FERC ultimately declared that energy storage could be considered transmission infrastructure and be ratebased accordingly. Ultimately, Western Grid's energy storage solution was not selected in the competitive process, but this declaration was key to opening the market for energy storage as transmission.

In 2011, Order 1000 was issued that required transmission owners to participate in regional transmission planning (no longer just requiring coordination). It reinforced "comparability", reinforced the use of alternative transmission technologies as alternative transmission solutions (citing the Western Grid order), and eliminated "right of first refusal" (ROFR) in most instances. ROFR means that, if a proposal is brought forward as a solution to a transmission solution, the "incumbent" would no longer have the right to refuse that proposal in favor of their own, and a competitive process would be needed to consider all transmission solutions.

Transmission Planning Standards

The following TPL NERC reliability standards are applicable to the CAISO as a registered NERC planning authority and are the primary drivers determining reliability upgrade needs:

TPL-001-4 Transmission System Planning Performance Requirements
NUC-001-2.1 Nuclear Plant Interface Coordination

The WECC TPL system performance criteria are applicable to the CAISO as a planning authority.

The CAISO Planning Standards address specifics not covered in the NERC reliability standards and WECC regional criteria and provide interpretations of the NERC/WECC standards. The CAISO identifies whether specific criteria should be adopted that are more stringent than the NERC/WECC standards. In addition to the system under normal conditions (P0), the following contingencies are evaluated as part of the study:

Single contingency (P1): Loss of one generator, one transmission circuit, one transformer, one shunt device, or a single pole of DC lines
Single contingency (P2): Loss of one transmission circuit without a fault, one bus section, one non-bus-tie breaker, or one bus-tie breaker
Multiple contingency (P3): Loss of one generator unit followed by the loss of one transmission circuit, one transformer, one shunt device, or a single pole of DC lines
Multiple contingency (P4): Loss of multiple elements caused by a stuck non-bus-tie breaker attempting to clear a fault on the loss of either one generator, one transmission circuit, one shunt device, one bus section, or a bus-tie breaker
Multiple contingency (P5): Delayed fault clearing due to the failure of a non-redundant relay protecting the faulted element to operate as designed for the loss of either one generator, one transmission circuit, one shunt device, or one bus section
Multiple contingency (P6): Loss of two or more non-generator unit elements with system adjustment between them, which produce the more severe system results
Multiple contingency (P7): Loss of a common structure - i.e., any two adjacent circuits on a common structure or loss of bipolar DC lines

On September 6, 2017, the CAISO published its proposed changes to its Transmission Planning Standards to address changes to WECC Regional Criteria. This planning guideline document is intended to ensure consistent reliability standards for the CAISO grid to maintain or improve transmission planning reliability and complement the NERC/WECC standards. Changes were made to the steady-state voltage standard, which now allows for a maximum voltage deviation of 8% instead of 10%, in accordance with the WR2 and WR3 requirements of WECC Regional Criteria TPL-001-WECC-CRT-3.

On January 23, 2019, FERC approved reliability standards for Transmission System Planning Performance Requirements (RM19-10-000, TPL-001-5) that requires a more comprehensive study of the potential impacts of protection system single points of failure and sets new requirements related to planned maintenance outages and stability analysis for spare equipment strategies. FERC also approved reliability standards for Cyber Security Communications between Control Centers (RM18-20-000, CIP-012-1) on mitigating risks associated with communications between bulk electric system control centers.

Transmission Deliverability

The CAISO coordinates the TPP with other CAISO processes. To achieve a specific RPS, the CAISO will be delivered an RPS portfolio from the CPUC where new renewable energy projects are assumed deliverability. The CAISO also calculates the available transmission plan deliverability (TPD) in each year's TPP in areas where the amount of generation in the interconnection queue exceeds the available deliverability, as identified in the generator interconnection cluster studies.

For distributed generation (DG) deliverability, the CAISO performs a deliverability study in the TPP to determine nodal MW quantities of deliverability status that can be assigned to DG resources, without requiring any additional delivery network upgrades and without adversely affectiving the deliverability status of existing generation resources or proposed generation in the interconnection queue. Next, the CAISO apportions these quantities to utility distribution companies, including both the IOUs and POUs within the CAISO controlled grid, who then assign deliverability status to eligible distributed generation resources.

Transmission Economic Assessment Methodology (TEAM)

TEAM is a methodology developed by the CAISO to quantify production benefits through production cost simulation that computes unit commitment, generator dispatch, locational marginal prices, and transmission line flows over 8,760 hours in a study year. With the objective to minimize production costs, the computation balances supply and demand by dispatching economic generation while accommodating transmission constraints. The study identifies transmission congestion over the entire study period. In comparison of the "pre-project" and "post-project" study results, production benefits can be calculated from savings of production costs or ratepayer payments. Production benefits include consumer energy cost decreases, increased LSE-owned generation revenues, and increased transmission congestion revenues. Other benefits include System/Local RA savings (i.e., reduction of CAISO system or local resource requirements). It does not, however, quantify social benefits into dollars.

Once the benefit is calculated, the benefit is weighed against the cost, which is the total revenue requirement of the project under study. To justify a proposed network upgrade, the CAISO ratepayer benefit needs to exceed the cost of the network upgrade. If the justification is successful, the proposed network upgrade may qualify as an economic-driven project.

On November 2, 2017, TEAM was updated. As recommended by the CPUC and CEC, the production cost modeling assumes multi-tiers of renewable curtailment cost: -$15/MWh for less than 200 GWh of curtailment, -$25/MWh for 200 to 12,400 GWh of curtailment, and -$300/MWh for greater than 12,400 GWh of curtailment.

Transmission Access Charge (TAC)

The CAISO currently applies the TAC to each MWh of metered internal end-use load and exports to recover participating transmission owners' (PTO) costs of owning, operating, and maintaining transmission facilities under CAISO operational control.

ransmission Outage Procedure

Understanding of the CAISO's transmission outage procedures are relevant to non-wires alternatives providing transmission services, especially as they provide multiple-use applications (i.e., grid and customer services other than the primary transmission service). In particular, if there are planned outages, then energy storage as transmission will be able to ensure the primary transmission service is provided with advanced notice, as will grid operators.

Planned outages:

New requests for planned transmission Maintenance Outages or requests to change Approved Maintenance Outages must be submitted to the CAISO Outage Coordination Office (OCO) at least seven (7) days in advance of the start date for the Outage, in order for the Outage to be designated as a Planned Outage. The timeline for submitting the required advanced notice is calculated excluding the day the request is submitted and the day the Outage is scheduled to commence.
New Outage requests or requests to change Approved Maintenance Outages submitted 7 days or less prior to the start of the Outage are designated as Forced Outages.
The preferred medium for submitting Outage requests is through the CAISO outage management system (OMS). Outages can be submitted to the CAISO OMS directly from a web interface or via an Application Program Interface (API). The CAISO OMS will automatically designate an Outage as either Planned or Forced based on the date of submittal.
Planned Outage Requests of Significant Facilities CAISO transmission facilities of 200 kV or greater, or which have been designated as Significant Facilities in Attachments B, C, or D, must be submitted 30 days in advance of the calendar month that the outage is to begin. If the 30th day falls on a non ISO business day then the Planned Outage Request is due on or before the last business day, 30 days prior to the month the Outage is to begin.

Relatedly, the CAISO can plan for long-range outages if such plans are submitted by October 15 of each year. PTOs shall provide the CAISO with any proposed Outages for the following year impacting its transmission system, in the CAISO OMS. These proposed Outage submittals should also include any requested additions or changes to previously approved Outages. The resulting submittal looks forward approximately 15 months, including any new or revised Outages for the period January 1 until December 31 of the following year. In addition, long-range plans from external BAs and TOPs are also accepted and are used in determining priority of all Outages affecting PTOs.

Consideration of Non-Wires Alternatives

The CAISO published a methodology in 2013 on the consideration and use of preferred resources (i.e., energy efficiency, demand response, renewables, and energy storage) as non-conventional solutions to meet local (not system) area needs that otherwise would require new transmission or conventional generation infrastructure. This would be possible in situations where the timeline for an identified need allows time for monitoring the development of non-conventional alternatives before a conventional solution would be required to be approved. Once the comprehensive transmission plan with the non-conventional solution is approved by the CAISO Governing Board, the CAISO would monitor the development of the resources that comprise the non-conventional solution to determine whether they will be in operation by the time they are needed. If the CAISO determines that the non-conventional resource mix is not developing in a timely manner, then the CAISO would consider whether to reinstate the avoided transmission solution or another appropriate alternative in a subsequent TPP cycle.

The approach employed by the CAISO in past TPP cycles to assess non-transmission alternatives was to examine the effectiveness of each alternative proposed to meet a specific area need on a case-by-case basis. The area needs were based on the local load profile characteristics, transmission configuration in the area, and the types of other resources already serving the area. This approach required that each such assessment be scoped individually to fit the specific alternative that was proposed. As such, it was very labor-intensive, was reactive to specific proposals, and did not provide any criteria for such alternatives in advance that could serve as guidance to prospective developers of such proposals. The case-by-case study of past proposals tended to be unsuccessful because the proposed alternatives did not meet one or more of the required performance characteristics.

The proposed approach will identify in advance the needed performance characteristics and load profile impacts that non-conventional solutions should be able to provide to effectively defer or eliminate the need for particular transmission additions or offset some or all of the need for particular conventional generation additions. The CAISO suggests that there are three primary characteristics to be considered in developing a catalog of supply-side resources. These characteristics necessarily imply that the resource is dispatchable by the CAISO and that the CAISO can optimize and commit the resource through the market along-side all other resources:

Response time – how quickly can the resource respond to an CAISO dispatch and achieve its full capacity?
Duration – how long can the resource sustain its response once called?
Availability – how many times can the resource be called during a time period?

Limitations in the availability of DR and multiple-use energy storage systems may be addressed by developing a combination or portfolio of individual resources to meet a specific need, and must be considered in assessing the effectiveness of a given mix of resources. Once a preliminary catalog of generic resources is developed, the second component of this methodology is to carry out a process of selecting, refining, and validating a potential mix of resources that could best provide the performance characteristics needed for a particular local area. This step would be carried out during Phase 2 of any given TPP cycle. This consists of aligning the required characteristics for each local area with the catalog of generic resource types. Once the CAISO settles on a preferred mix of resources, the CAISO would perform an analysis to test the mix of resources to validate that it will meet the identified reliability needs in that local area.

The third component of this methodology is to monitor the development of the mix of selected non-conventional resources. This monitoring would be similar to that which the CAISO conducts today on an annual basis to review the progress of transmission facilities, operating procedures, and special protection schemes and develop alternatives as needed if the initial solutions are not advancing. An additional aspect of this annual monitoring should address the cumulative effects on grid reliability and market stability of increased reliance on non-conventional alternatives over the longer term. Historically, overall system and market performance were based on transmission elements (with high availability) and dispatchable generators (with high availability). This resulted in systems that met criteria with little excess margin at peak load conditions, but with considerable margin the rest of the year. Adding to this, the operating margins in off-peak seasons were further increased by the fact that much of the load in California is summer peaking, when both thermal plants and transmission line capacities are based on seasonally de-rated numbers. In contrast, increased reliance on non-conventional alternatives may have comparatively less availability such that the implicit cushion or margin that previously existed for much of the year is no longer there. If this were in fact the outcome, the cumulative effects on grid reliability and market stability would need to be closely monitored.

Based on an examination of the load curve, the CAISO has developed a preliminary catalog of generic resources that characterizes their duration, response time, and availability. CAISO suggests that availability can be characterized in terms of a minimum number of times in a given period (e.g., week or month) that the resource can respond to an CAISO dispatch, and that it may make sense to differentiate between seasonal and annual availability. If a resource is willing to be called down more frequently, it could sell the extra blocks of curtailment availability as additional products.

An important issue is commitment to perform, and whether a non-conventional solution to a transmission need could include voluntary demand response The MW values of programs with voluntary actions (e.g., responses to price signals) may need to be discounted rather than counted at their nominal MW amounts. In contrast, if the resources are more reliable and firmly committed to perform—for example those with significant financial consequences for lack of performance or those with automation—then required response times can be lengthened and a broader range of resources may be able to participate

Due to the magnitude of projected local reliability needs in the LA Basin and San Diego areas, the CAISO pursued transmission solutions to complement non-conventional alternatives to reduce the need for conventional generation to fill the gap in the initial application of this methodology in the 2013-2014 TPP cycle.

On August 16, 2017, the CAISO further refined and advanced this methodology for assessing the necessary characteristics and effectiveness of preferred resources to meeting local needs through the development of the Moorpark Sub-Area Local Capacity Alternative Study. If a preferred resource is identified in Phase 1 as having the potential to meet a reliability need, the CAISO considers the cost effectiveness and other benefits these alternatives provide in Phase 2. Although the CAISO Board does not "approve" non-transmission solutions (e.g., preferred resource capacity), the CAISO can identify solutions as preferred solutions to transmission projects and work with the appropriate LSEs and LRAs to support their development. An example of this effort is the development of PG&E's Oakland Clean Energy Initiative. An issue of concern is the quality of cost estimates used in considering preferred resources in the economic assessment of potential transmission solutions, with the CAISO viewing these estimates as informational only and having cost commitments made in the competitive solicitation process.

Hello, World!

2017-2018 Transmission Planning Process (Stakeholder Process)

Study Plan (Phase 1)

On February 28, 2017, a stakeholder meeting was held where CAISO shared its Draft 2017-2018 Study Plan to kick-off the 2017-2018 TPP cycle, which will include the 2016 Integrated Energy Policy Report (IEPR) from the CEC and 2017 Draft Planning Assumptions and Scenarios from the CPUC. The CAISO indicated that it will model the retirement of Diablo Canyon but that it will continue to use the existing 33% RPS scenarios until direction is made available on the 50% RPS goals, which is likely to occur for the 2018-2019 TPP cycle. Until then, no new policy-driven analysis is anticipated to be required. Regarding energy storage, the CAISO will model the amounts consistent with D.13-10-040 along with the locations of energy storage resources procured to date. The CAISO also does not anticipate another round of new special studies and is instead focused on completing and updating the two special studies from the 2016-2017 TPP cycle. This updated analysis includes assessing the risks to reliability of economically-driven early retirement of natural gas-fired generation.

CESA focused its comments on the non-transmission alternative identification process. Specifically, CESA recommended the development of a benefit-cost allocation methodology and the identification of the types of information and data that are needed for third parties to develop high-quality non-transmission alternatives to address identified transmission reliability needs. Given that the 50% RPS and Bulk Storage special studies are expected to be continued in this cycle, CESA also commented on improvements to these studies. For the 50% RPS Special Study, CESA recommended that sensitivities of in-state non-transmission alternatives should be tested instead of just exploring regional solutions, as the study is currently structured. For the Bulk Storage Special Study, CESA recommended a re-run of this study with more moderate assumptions of renewable curtailment prices.

See CESA's comments on March 14, 2017 on the Draft Study Plan.

On March 31, 2017, the Final Study Plan was published. There were no significant changes in the final version of the plan from the draft version.

On June 8, 2017, the CAISO published its Interregional Transmission Project Evaluation and 50% RPS Out-of-State Portfolio Assessment Plan. This study is a continuation of the 2016-2017 planning cycle, for informational purposes only, and is based on stakeholder input received during the 2016-2017 planning cycle stakeholder meetings. The plan intends to continue its investigation of the transmission impacts of moving beyond 33% RPS in California, test and potentially update the transmission capability estimates used in RPS calculator v6.2, and begin an examination of the transmission implications of meeting part of California’s 50% RPS requirement. In particular, the study aims to assume California’s procurement of 2,000 MW of wind resources in Wyoming and 2,000 MW of wind resources in New Mexico, as well as consideration of four Interregional Transmission Projects (ITPs) that were submitted to the CAISO and two other planning regions in early 2016.

Over the next several months, the CAISO will do the following as part of this study:

Identify out-of-state resource scenarios
Identify Available Transfer Capability (ATC) between Wyoming/New Mexico and California
Identify transmission constraints outside of California
Test the effectiveness of ITPs in mitigating observed transmission issues outside of California
Perform a comparative assessment of ITPs

The CAISO will conduct this study and coordinate on assumptions and methodologies in close collaboration with other western planning regions. The study results will assess renewable curtailment, congestion caused due to transmission constraints, and the extent and number of reliability issues observed in the stressed snapshots modeled in power flow assessments.

On June 16, 2017, CESA held meetings with CAISO leadership and technical staff to discuss various market issues, including a pathway for bulk storage procurement through the CAISO – e.g., through a similar mechanism as the Transmission Access Charge (TAC).

Technical Studies (Phase 2)

On September 21-22, 2017, the CAISO presented on the preliminary reliability results that continued to use the existing 33% RPS scenarios until direction is made available from the IRP proceeding on 50% RPS goals, noting that the updated scenarios will likely be incorporated in the 2018-2019 TPP. Until then, no new policy-driven analysis is anticipated to be required. In general, not many reliability-driven projects were being proposed, as many previously approved projects were either put on hold or canceled due to no longer being needed. Importantly, the CAISO stated that it is continuing to consider stakeholder interest in the assessment and selection of preferred resources for reliability mitigations using previously established frameworks (see 2013 document). The meeting discussed thermal overloads in the Oakland area (Moraga Substation), which currently are being addressed by two Special Protection Schemes (SPS) and some load shedding. In the request window proposal presentations, after all the proposed substation upgrades ($35 million), PG&E is proposing a combination of DERs, energy storage, and operational (switching) solutions to be assembled on a least-cost, best-fit basis to meet the remaining need.

The preferred resource solution candidates relevant to CESA members are summarized below. PG&E proposes to run a market solicitation for the energy storage and DER portfolio. Notably, PG&E stated that PG&E’s preliminary analysis shows the potential for many million dollars in savings for customers versus transmission or generation alternatives.

TPP2 PGE NWA RFP Idea for 2017-2018 TPP.png

The CAISO also presented on the four special studies that were being updated from the 2016-2017 TPP cycle, including the completion of a large energy storage benefits analysis, completion of the out-of-state analysis for the 50% RPS special study, and continuation of the system risk assessment to reliability of economically-driven early retirement of gas-fired generation:

50% RPS Study: This study began in the 2016-2017 TPP cycle to investigate the transmission impacts of moving beyond 33% RPS requirements in California, investigate transmission implications on in-state facilities for meeting part of the RPS requirement with 2,000 MW of wind resources in Wyoming and New Mexico, and update the transmission capability estimates in the RPS Calculator. In 2016-2017, the key findings were: (1) the out-of-state (OOS) wind portfolio showed the lowest curtailment and least amount of intra-California congestion, but further refinement of assumption was needed due to the fact that the OOS portfolio being investigated was the “least severe one”; and (2) adequate import capability exists to deliver OOS resources in New Mexico and Wyoming from injection point into the CAISO loads. For 2017-2018, the goal of the continued study was to: (1) refine the OOS resource and topology modeling; (2) identify Available Transfer Capability (ITC) that can be used by the OOS wind resources in Wyoming and New Mexico in order to deliver to California; (3) identify transmission constraints outside of California while trying to meet part of the 50% RPS obligation by relying on OOS wind resources in Wyoming and New Mexico; and (4) test effectiveness of Interregional Transmission Projects (ITPs) in mitigating observed transmission issues outside of California and test a framework for comparing ITPs. Generally, three out of the four ITPs showed reduction in thermal overloads in the CAISO but no impact relative to baseline on CAISO renewable curtailment under either a 2,000 MW net export limit. In the no net export limit case, the CAISO saw major reductions in renewable curtailment, perhaps indicating that renewable curtailment in the 2,000 MW net export scenario is not related primarily to transmission congestion. Major OOS transmission congestion was also found related to OOS wind due to the overall generation dispatch of gas and coal generation. None of the ITPs except TransWest Express created sufficient long-term, firm ATC from the renewable resource area all the way to the CAISO without relying on other transmission not owned by the project sponsor.
Risk of Early Gas Retirements Study: This study was conducted in 2016-2017 that looked at different cases of gas-fired generation retirements. It found that capacity sufficiency issues start to emerge between 4,000 MW to 6,000 MW of retirement, especially with shortfalls in load following and reserves in the early evening after sunset.
Bulk Energy Storage Study: In the 2015-2016 TPP, initial studies were conducted on the benefits of bulk storage resources in reducing production costs, renewable curtailment, GHG emissions, and renewable overbuild under 40% RPS and later under 50% RPS scenarios. The 2016-2017 TPP continued the study with new assumptions and two sizes of bulk energy storage resources (500 MW and 1,400 MW separately). The CAISO also discussed how it updated the default scenario as follows: (1) change the import from OOS renewable resources to Category 1 and 2 RPS resources (which reduces allowed net export when there is curtailment of renewable generation in the CAISO); (2) change the CHP from 50% dispatchable to all non-dispatchable; (3) change the energy efficiency forecast assumption from 2x 2015 IEPR Mid-AAEE by 2030 to the 2015 IEPR Mid-AEE forecast for 2026; and (4) change the curtailment price scale. Across all scenarios, the change to these assumptions showed increase in renewable overbuild capacity, curtailment, and production costs.

TPP3 Bulk Storage 2017-2018 TPP Assumptions.png

TPP4 Bulk Storage 2017-2018 TPP Assumptions Curtailment Price Scalar.png

CESA supported PG&E's request window proposal for a non-wires alternative while also recommending that the bulk storage special study be re-run with IRP assumptions in the 2018-2019 TPP.

See CESA's comments on October 6, 2017 on the Preliminary Reliability Results.

On September 25, 2017, the CAISO presented at the IRP Proposed Reference System Plan Workshop on how the assumptions and scenarios in the IRP will feed into the TPP. For the 2018-2019 TPP and 2018 IEPR, the Reference System Plan assumptions and scenarios will be incorporated, with the Preferred System Plan then feeding into the 2019-2020 TPP and 2019 IEPR.

ALJ Ruling IRP Proposal TPP Alignment.png

Procurement (Phase 3)

On November 16, 2017, CAISO held a stakeholder meeting to present the preliminary economic assessment results and the recommendations for reliability projects with an estimated cost of less than $50 million. Multiple mitigation measures considered battery energy storage, but the PTOs ultimately recommended traditional “wires” solutions. No specifics were provided on how energy storage solutions fared against traditional transmission investments. During the meeting, the CAISO also introduced a new proposal to add Phasor Measurement Units (PMUs) to all CAISO interties to enhance accuracy of measurements related to the compliance with the NERC BAL-003 Reliability Standard – a standard that sets frequency response obligations for different Balancing Authorities based on net actual interchange measurements. The PMUs at all interties will provide more precision regarding the system’s net actual interchange after a frequency disturbance event.

On December 6, 2017, PG&E announced that it will be seeking to procure 20 MW to 45 MW of clean energy resources in an RFO in collaboration with East Bay Community Energy (EBCE) in lieu of a traditional wires solution (e.g., upgrade existing substation infrastructure) to ensure transmission reliability in the Oakland area.

On December 14, 2017, SCE submitted a transmission solution into the 2017-2018 TPP for approval to partially mitigate the Moorpark sub-area local capacity need due to more than 2,000 MW of generation announcing or expecting retirement and CPUC rejection of the Ellwood refurbishment contract.

On January 11, 2018, a stakeholder call was held to provide the results of the CAISO’s preliminary analysis of the proposed circuit, with an estimated cost of $45 million and CAISO approval by March 2018 to meet the in-service date by December 31, 2020.

The CAISO presented on three alternatives considered:

TPP7 Moorpark-Pardee Tx 4 Line Alternatives Analysis.png

Pardee-Moorpark project to address Moorpark LCR need coupled with 86-105 MW of local capacity located downstream of Goleta to address Santa Clara LCR and SCE’s Goleta resiliency needs
Approximately 318 MW of local capacity to address Moorpark LCR need of which 105 MW is located downstream of Goleta to address Santa Clara LCR and SCE’s Goleta resiliency needs
240 Mvar dynamic reactive power support coupled with 135 MW of local capacity to address Moorpark LCR need of which 105 MW is located downstream of Goleta to address Santa Clara LCR and SCE’s Goleta resiliency needs

As a result of the stakeholder call, it appears that the CAISO conducted the preliminary analysis using cost estimates used in the Moorpark Alternative Analysis in August 2017. CESA supported the CAISO’s efforts to study the proposed transmission solution as well as to conduct a preliminary assessment of non-wires alternatives, but commented that further consideration of whether reliability outcomes and expectations are appropriate (considering the resilience objectives of the No. 4 line), even if reliability standards are met. CESA also requested careful review and expectations of costs and project online dates of the transmission solution and potential non-wires alternatives.

See CESA's comments on January 18, 2018 on the Moorpark-Pardee 230-kV No. 4 Circuit Project.

On February 1, 2018, the Draft 2017-2018 Transmission Plan was issued and a stakeholder meeting was held to discuss the draft plan. This year will be the last year that the TPP continues to use old 33% RPS portfolio assumptions and scenarios, as the IRP proceeding will produce updated Default Scenarios and Preferred Scenarios. Given this context, the CAISO reported that its reliability issues are largely addressed, especially with load forecasts declining and BTM generation forecasts increasing as compared to previous years. These trends have led the CAISO to reassess some previously approved transmission projects – i.e., resulting in the cancellation of 19 projects and re-scoping of 21 projects in PG&E’s service territory. Importantly, the CAISO noted that preferred resources and energy storage are beginning to play a larger role in transmission planning. There were two key transmission projects that the CAISO team is proposing for approval by the CAISO Board. First, the CAISO is proposal approval of the South Bay-Moss Landing enhancements comprising of the San Jose-Trimble 115-kV series reactor and the Moss Landing-Panoche 230-kV path upgrade as reliability- and economic-driven projects. Collectively, these projects would cost $14 million and reduce the local capacity requirements for the South Bay-Moss Landing sub-area by 400-600 MW beginning in 2019. The RMR agreement for the Metcalf Energy Center would thus be needed until 2019. Second, the CAISO is recommending that the Moorpark-Pardee Line #4 230-kV transmission circuit to be approved by the CAISO Board as well. SCE proposed this $45-million to be in service by December 31, 2020 to coincide with the retirement of once-through-cooling generation in the area. The implications of these two transmission project approvals are that the local capacity needs as required by the CPUC under Resolution E-4909 to be met by energy storage and preferred resources would be largely eliminated, and that the local capacity needs in the Moorpark local area would be significantly reduced.

While not opposed to cost-effective transmission solutions, CESA raised questions on whether the Moorpark-Pardee Line #4 would reduce load-shedding risks for customers in the Moorpark sub-area, even though the project would meet relevant planning criteria, and whether local generation and energy storage resources would mitigate some of these risks not captured in present planning standards. For the South Bay-Moss Landing projects, CESA just sought clarity on what the residual LCR need would be if the projects are approved. Finally, CESA supported the CAISO’s recommendations to approve the Oakland Clean Energy Initiative, a hybrid solution of transmission and preferred resources, as well as the CAISO’s intent to address issues around energy storage as transmission and market resources in an initiative later this year.

See CESA's comments on February 22, 2018 on the 2017-2018 Draft Transmission Plan.

CESA conducted informal outreach to the CAISO staff to understand the conditions and variables around the proposed decision around the two transmission projects, which led to the following insights:

Moorpark-Pardee Line #4: The CAISO noted that it plans for n-1 and n-2 contingencies, but not for n-3 or n-4 events. Even if the CAISO planned for greater contingencies, they found that it would have favored approval of the Puente Power Project instead of energy storage alternatives. The previously approved Puente Power Project, which has since been rejected, would have not only met relevant n-1 and n-2 planning criteria in the Moorpark sub-area, but it would have also provided additional value in terms of fault current detection and provide needed local generation in the event of a n-3 contingency (i.e., the Moorpark-Pardee transmission corridor being taken out of service by natural disasters). The CAISO noted that fault current detection is something that requires a rotating mass – something that inverters cannot do. Without this detection in the event of a fault, current will continue to be pushed through the wires and equipment and lead to catastrophic damage. The CAISO also noted that the risk of mudslides or wildfires that take out the entire transmission corridor are unlikely, except in the case where a wildfire spreads to below the towers. Rather, the greater concern for the CAISO is the damage that ash from wildfires could cause to the wires, causing outages and voltage collapse and leading to the CAISO’s recommendation of stringing a fourth line to mitigate the risk of voltage collapse from any line going down. In general, the CAISO expressed support for energy storage solutions as transmission alternatives, but the unique grid needs in the Moorpark sub-area made it more reasonable to approve a fourth line to meet relevant planning standards while mitigating for the likeliest natural disaster risks.
South Bay-Moss Landing projects: The CAISO explained that the line rating changes submitted by PG&E in the South Bay and Moss Landing sub-areas was the critical factor in approving the suite of transmission projects for economic reasons. The CAISO expressed concerns about the change in the line rating, which is information that are provided by the participating transmission owners (PTOs). This issue is expected to be investigated in the 2018-2019 TPP cycle, as broader review and adjustments to line ratings may materially impact how the CAISO reviews and approves transmission projects.

On March 22, 2018, the CAISO Board approved the Final 2017-2018 Transmission Plan. Among the key approvals include the Moorpark-Pardee No. 4 Line, which impacts SCE’s Moorpark LCR needs, as well as several South Bay-Moss Landing projects, which reduces PG&E’s LCR needs in the Bay Area.

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2018-2019 Transmission Planning Process (Stakeholder Process)

Study Plan (Phase 1)

On February 22, 2018, the CAISO issued its 2018-2019 Draft Transmission Study Plan (see also stakeholder meeting on February 28, 2018 to review its details). The CAISO will use the Default Scenario (50% RPS by 2030) for the reliability assessment to identify reliability-driven transmission needs while using the 42 MMT scenario portfolio from the IRP Reference System Plan as a sensitivity in the 2018-2019 policy-driven assessment to identify Category 2 transmission. Outside of the usual study processes and models, the CAISO indicated that it will have a particular focus on renewable integration issues, conduct a major economic study focused on local capacity areas, and conduct a special study supporting the Aliso Canyon investigation by the CPUC. Finally, the CAISO indicated that studies into frequency response and headroom requirements will be conducted a an ongoing study requirement to support mandatory standards efforts - i.e., NERC reliability standard BAL-003-1. In the 2014-2015, 2015-2016, and 2016-2017 TPP cycles, the CAISO conducted these studies as special studies for potential oversupply conditions and found that the CAISO had acceptable frequency performance within WECC.

On April 18, 2018, a stakeholder meeting was held to discuss the scope of two proposed special studies that were included in the 2018-2019 Final Transmission Study Plan. First, the CAISO presented on the local capacity requirements (LCR) potential reduction economic study, which will identify potential transmission upgrades that would economically lower gas-fired generation capacity requirements. The CAISO will model at least 21 local capacity areas or sub-areas - with a priority on disadvantaged community locations, locations that rely heavily on gas-fired generation, and gas-fired generation that are old (i.e., over 40 years old) and/or have planned retirements - to assess whether conventional transmission and preferred resources can address the remaining LCR needs. Due to ongoing procurement or approved projects, five sub-areas (e.g., Moorpark) have achieved full LCR reduction and another four sub-areas (e.g. South Bay-Moss Landing) have partially reduced their LCR needs. The preliminary LCR and economic assessment results will be presented on November 16, 2018, with the final results included in the Draft Transmission Plan on January 31, 2019.

This was follow-up work to the 2017-2018 TPP studies that identified how proposed transmission solutions were cost-effective and ultimately addressed 400-500 MW of the LCR need in the South Bay-Moss Landing sub-area – a need that was created due to the CPUC’s efforts through Resolution E-4909 to avoid the need to approve an RMR agreement for the Metcalf gas-fired plant. The CAISO aimed to proactively and more comprehensively identify cases where conventional transmission and preferred resources could serve as economic LCR solutions to gas-fired generation in certain priority locations. Consequently, there may be IFOM and BTM energy storage procurement needs that could be identified, as the CAISO will also develop load shapes that may inform whether the use- and energy-limited preferred resources can address the LCR need more economically. In other words, we may see additional opportunities like the Oakland Clean Energy Initiative.

Second, the CAISO discussed how it will conduct an informational study to evaluate options to increase transfer of low-carbon electricity between Pacific Northwest and California and to assess the potential role of AC/DC interties in displacing generation dependent on the Aliso Canyon natural gas facility. The results of the study will inform whether the CAISO should increase transfer capability of AC/DC interties, increase dynamic transfer limits on AC interties, implement sub-hourly scheduling on PDCI, and/or assign RA value to firm zero-carbon imports or transfers. The timeline for the presentation of the preliminary and final results will be similar to the other special study. The origins for proposing this special study was a joint CPUC/CEC letter sent to the CAISO on February 15 to add this sensitivity case to the 2018-2019 TPP in order to assess whether increasing the transfer capabilities from the Pacific Northwest could enable the shut-down of Aliso Canyon in ten years, which the Governor seems to have indicated a strong interest in doing.

CESA voiced strong support for the special study but requested clarity or improvements around procurement pathways, recommended consideration of hybrid gas-storage resources and energy storage not just as generation resources but also as transmission, and provided input on energy storage cost assumptions to be used.

See CESA's comments on April 25, 2018 on the special study scope

On May 23, 2018, the final study scope was posted on the Pacific Northwest special study. In evaluating the impact of increasing transfer capabilities, the final scope clarified that a near-term assessment (2023) will determine the potential to maximize the utilization of existing transmissions system while a longer-term assessment (2028) will use production simulation to determine the potential benefits of increased transfer capabilities beyond existing path ratings (4,800 MW as current North-to-South path rating). The CAISO noted that the longer-term assessment would require accurate modeling of hydro resources.

On July 1, 2018, the Dynamic Transfer Capability (DTC) on the Northwest AC Intertie (NWACI) was increased from 400 MW to 600 MW. Increasing the DTC beyond 600 MW would lead to excessive voltage fluctuations and reactive switching, RAS arming, and voltage stability issues.

On July 10, 2018, the CAISO proposed several changes to its transmission planning standards and held a stakeholder call to discuss those changes. Specifically, the CAISO is proposing to modify the CAISO Planning Standards for non-bulk electric system facilities under the CAISO’s control and for resource owners to be required to perform maintenance of a reasonable time duration during the year.

Technical Studies (Phase 2)

On August 15, 2018, the CAISO published its preliminary reliability assessment results and held a stakeholder meeting to discuss them on September 20-21, 2018. Some key potential opportunities for non-wires solutions include:

PG&E’s Metcalf Bank (230/115 kV) overloads in San Jose that can be met by bus upgrade or preferred resource mitigation starting in 2020
Valley Electric’s Amargosa Transformer (230/138 kV) and Sandy-Gamebird-Thousandir-Vista buses (138 kV) overloads for potential battery storage mitigation in local pockets
SDG&E’s Miguel Bank 80 and Bank 81 and Suncrest Bank 80 and Bank 81 thermal overloads for potential mitigation by up to 300 MW of potential preferred resource and energy storage procurement
SDG&E’s TL631 upgrade proposal to a minimum continuous rating of 77 MVA ($28 to $43 million) to reduce the El Cajon sub-area local capacity requirements that could potentially be met by a SATA alternative ($40 to $60 million)

In addition to the usual transmission reliability studies conducted in every annual cycle, the CAISO provided an update on progress in the SATA Initiative as well as updates on their two special studies – a local capacity requirements (LCR) potential reduction economic study, which will identify potential transmission upgrades that would economically lower gas-fired generation capacity requirements, and a special study investigating the potential opportunities for transfers of low-carbon electricity from the Pacific Northwest.

On November 16, 2018, the CAISO provided an update on the policy assessment and deliverability methodology proposal, an overview of economic modeling requirements and preliminary economic assessment results, some preliminary results of the Alternatives for Potential LCR Reduction special study, and update and preliminary results of Pacific Northwest informational special study. The final results are planned for publication in the Draft Transmission Plan on January 31, 2019.

In addition to the usual reliability assessments, the CAISO also provided an update to its policy assessments using the 42 MMT scenario to evaluate Category 2 transmission needs, which will test the deliverability of FCDS resources in the portfolio using new renewable output assumptions that take into account the new qualifying capacity calculations for solar and wind. The 2,000 MW of energy storage selected in the portfolio is not modeled in the initial production cost modeling run due to lack of locational information, but the results are expected to inform the CAISO about optimal locations for energy storage resources that could help reduce renewable curtailment driven by overgeneration and/or transmission congestion. The CAISO found that local transmission constraints are the main driver of renewable curtailment in both the default and 42 MMT scenarios, with export limits and ancillary service requirements also playing some role. To improve economic modeling going forward, the CAISO said that it may need to adjust its multi-tiers curtailment price model and parameters for high renewable penetration and high transmission congestion scenarios. Other potential areas of improvement that it will look at include coordinating with other agencies and entities on updated data (e.g., load forecast, generator retirement plans, production profiles, remote resources), and considering intertie capabilities derates, refining renewable integration model and dispatch (e.g., storage, hydro).

Finally, the CAISO discussed its review of the current deliverability methodology, which raised issues around the implications of “vintaging” and the need to test multiple critical system conditions. Loss of load events were found to occur in the late afternoon to evening hours of summer peak days, but in many of the areas, no deliverability constraints were identified in the primary and secondary need scenarios. Upon this review, the CAISO proposed a new deliverability methodology that would select the highest system need and secondary system need scenarios based on peak sale and peak consumption conditions, respectively. The TPP would then approve upgrades to mitigate peak sale deliverability constraints and approve upgrades or no upgrades for peak consumption constraints. The no-upgrade determination in the TPP would mean that the MW up to the portfolio amount can be allocated for FCDS for the peak consumption constraint. The GIP identifies LDNUs and ADNUs in both scenarios. In the 42 MMT scenarios, the proposed methodological change would lower dispatch assumptions for solar, which may translate into FCDS for more resources but could also result in higher renewable curtailment.

On November 16, 2018, the CAISO provided an update on its economic study to identify transmission and preferred resources as alternatives to meet 2028 local capacity deficiencies in at least half of the existing areas and sub-areas, with priority given to areas in disadvantaged communities and with gas plants with certain attributes (e.g., greater than 40 years life). The reliability assessments looked at current constraints as well as multiple limitations, with the worst constraint determining the LCR need. The CAISO caveated its analysis as being more informational and as using conservative assumptions until further direction is provided from the CPUC and FERC, which will not be able to make a decision on the SATA proposal submitted to the CAISO Board for approval in March 2019

TPP 2-1 2018-2019 TPP LCR Study Update.png

The CAISO explained that the Santa Clara sub-area was selected for this assessment because all of the gas-fired generation in the area is needed, whereas the Rector, Vestal, Goleta and Moorpark sub-areas will have no gas-fired generation requirement in 2028 due to the approved transmission project and RFP for preferred resources. The CAISO discussed how the current Santa Clara sub-area resources are able to mitigate voltage collapse but it is not sufficient to mitigate overloading of the remaining line.

TPP 2-2 2018-2019 TPP LCR Study Update - Santa Clara LCR.png

The assessment will be continued when the ongoing Santa Clara LCR RFP is completed and the location and characteristics of the procured resources are known. Based on the current schedule, SCE’s target date for submitting contracts for approval is March 2019, with CPUC approval coming possibly later in the year. To address 2028 LCR needs in the San Diego-Imperial Valley area, where there is 3,744 MW of gas-fired generation and 77 MW in disadvantaged communities, Nevada Hydro proposed the 500-600 MW Lake Elsinore Advanced Pump Storage (LEAPS) Project and City of San Diego proposed the San Vicente Energy Storage Facility. Specifically, the CAISO is looking at potential mitigations for a line loading concern created by reducing LCR needs in the San Diego sub-area and the San Diego-Imperial Valley area, which affects the Western LA Basin sub-area. The line flow contingency condition occurs between Hours 18 and 20. Continued study is needed.

Though positioned as just informational, this special study will be important in highlighting potential priority areas to retire or (potentially) hybridize existing gas plants in disadvantaged communities, which may lead to significant energy storage procurement. Some areas (San Jose, Ames/Pittsburg/Oakland, and Santa Clara) are looking at potentially 184-600 MW of LCR need, according to preliminary results of this study. The results are still early and it would be premature to say that this will lead to procurement, given that the economic portion of the alternatives assessment has not yet been completed, but it highlights some promising early results.

CESA offered a few areas of comment and requests for clarification on the special study update shared at the November 16, 2018 meeting:

CESA recommends that the CAISO not just focus on gas-fired generation plants that are greater than 40 years old in this study but to also consider a lower threshold of gas plants greater than 30 years old in age.
CESA requests greater detail on the preferred resource composition and characteristics for alternative solutions proposed by the CAISO.
CAISO should not only consider transmission and preferred resource alternatives but also hybrid gas plant alternatives (i.e., gas plus energy storage).
CESA seeks clarification from the CAISO on the assessment of the Santa Clara sub-area.
CESA requests a small modification to characterization of the Pardee-Moorpark 230 kV Transmission Project.

Open questions remain around when a transmission need for energy storage moves from the market (Local RA) framework to being a transmission asset and how the economic assessment of energy storage may differ between the two approaches. The CAISO has generally leaned toward an energy storage resource with a high reliance on production cost benefits as market resource solutions rather than transmission asset solutions.

See CESA’s comments on November 30, 2018 on the LCR Economic Study Update

On November 26, 2018, the CAISO held a stakeholder call to review the informational special study for the Pacific Northwest. The CAISO provided an update on some of the preliminary results as well as their plans for continued study, including for different sensitivities. The CAISO was working with BPA to finalize thermal and voltage stability analyses for various North-to-South transfer cases under various contingencies, as well as to update assumptions around hydro conditions.

On March 29, 2019, the Final 2018-2019 Transmission Plan was published. The CAISO explained that it conducted a policy-driven as a sensitivity only as the CPUC had not transmitted an IRP portfolio for the 2018-2019 TPP cycle. There was a large number of energy storage proposals submitted in the 2018-2019 TPP to serve as economic or LCR reducing resources, relative to previous TPP years, but none of these proposals was selected for a number of reasons, including the lack of reliability need, the lack of a sub-area study for LCR reduction benefits, the inability to address all reliability needs identified, or the need to continue monitoring load increases in future load forecasts. In the Economic LCR Reduction Special Study, no gas plants were found to be economic to be replaced by transmission or storage solutions

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2019-2020 Transmission Planning Process (Stakeholder Process)

Study Plan (Phase 1)

On April 3, 2019, the Final 2019-2020 Transmission Study Plan was published. The CAISO will extend the Economic LCR Reduction Potential Study that was conducted in the previous TPP cycle to all LCR areas but will otherwise focus on incorporating the adopted 2019 Preferred System Portfolio from the IRP proceeding to identify transmission needs.

Technical Studies (Phase 2)

On September 25-26, 2019, the CAISO held stakeholder meetings to share preliminary results. Importantly, the CAISO presented several updates that it is considering to its production cost modeling for renewable curtailments and prices. For renewable curtailment, the CAISO uses negative prices to mimic the negative price bid of renewables in actual market operation to avoid curtailment, which is in contrast to transmission curtailments that are based on congestion. Separating these two types of curtailment in market operation or production cost simulation can be difficult. The CAISO uses the following hourly curtailment price profile. To add further complexity, the CAISO discussed how the order the renewable generators are curtailed is much more critical in nodal than zonal analysis and driven by the marginal units, such that increased curtailment in one pocket may drive up the global curtailment price in other markets. In contrast to simulated results, actual market operational data also showed how the actual order of curtailment was driven by economic bids, with operators adjusting their operations. The CAISO indicated that it will revisit its nodal analysis to avoid creating “cliffs” in pricing, which can create exaggerated effects. To address this, the CAISO discussed three options:

Use a single flat curtailment price that avoids the “cliff” effects but does not provide granularity on units that are curtailed
Use a curtailment price model with locational granularity and smaller step sizes based on historical data but is less helpful for future-year studies and is data intensive
Model each renewable generator with several smaller generator blocks with slightly different curtailment prices and smaller step sizes (e.g., $1) that would resolve many issues but would increase simulation time

This third option was identified as the CAISO’s candidate solution. In conducting some preliminary modeling using this option, the CAISO found that the total curtailment did not change but that the allocation of curtailment did change. For battery costs in production cost modeling, the CAISO discussed how the energy capacity should modeled to reflect depth of discharge and cycling limitations and how operational costs should reflect the replacement cost. A DOE report plans to be used where typical performance is characterized as 80% depth of discharge and 3,500 cycles based on this depth of discharge, with a 10-year calendar life. The CAISO is considering an incremental or step-up function or a flat average cost for each MWh, but is favoring the latter using the DOE’s 2025 predictions for the parameter assumptions

CESA further explained why the operational cycling costs of batteries should be set at $15.50/MWh, instead of the $33.75/MWh as proposed by the CAISO based on its formula and data sources. Furthermore, we offered our thoughts on future consideration of modeling renewable curtailment prices, especially as the state transitions to a larger fleet of hybrid resources, where different approach may need to be considered.

See CESA’s comments on October 15, 2020 on the Preliminary Study Results

Given the lack of actionable direction from the CPUC’s IRP process on the future of existing gas-fired generation beyond known retirements, CAISO described taking a conservative approach in this planning cycle in assigning a value to upgrades potentially reducing local gas-fired generation capacity requirements.

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2020-2021 Transmission Planning Process (Stakeholder Process)

Study Plan (Phase 1)
On June 22, 2020, the CAISO published a Final Revised 2020-2021 Transmission Study Plan that will leverage the IRP portfolios for the usual reliability, economic, and policy studies. In addition to the near-term 2021 LCR and 2025 LCR technical studies, the CAISO will conduct a long-term LCR study that assesses capacity needs 10 years out. Lastly, the CAISO will conduct conducted studies on frequency response and headroom requirements in this planning cycle. Otherwise, no special studies are expected in this cycle, as the focus will be on aligning the IRP portfolios for transmission planning purposes.

Technical Studies (Phase 2)

On June 3, 2020, the CAISO held a stakeholder call to update stakeholders on their plans to develop different evaluation scenarios based on taking out a combination of different voltage facilities and/or facilities within various fire zones, and to map storage resources identified in the IRP modeling process onto busbars that take into account the effects storage will have in the retirement of existing natural gas infrastructure and local area load/supply. On this latter issue, the CAISO found the CPUC’s mapping methodology based on commercial interest, project status, and location to be deficient in identifying the most effective storage locations. The challenges that the CAISO is facing in mapping storage resources selected in the IRP portfolios highlight some of the limitations of the existing modeling tools used by the CPUC, which lack the sufficient level of granularity to inform transmission planning and investments. Rather than using interconnection queue data to map the storage identified by zone, the CAISO preferred to use alternative approaches (e.g., ones that would support gas replacement).

CESA recommended that the CAISO consider integrating the wildfire-related outage information to support the future consideration of storage as non-wires alternatives. In addition, CESA recommended that the CAISO consider the siting of energy storage within disadvantaged communities (DACs) and within local areas and/or sub-areas with the most significant levels of local emissions (i.e., Version 3.0 of the CalEnviroScreen) to support the identification of specific gas facilities to prioritize for mapping storage replacement.

See CESA’s comments on June 3, 2020 on the Storage Busbar Mapping Update