Frequently Asked Questions
General Questions
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The Demand Side Grid Support (DSGS) Program is a program that provides incentives to customers who reduce their energy use during extreme events.
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Olivine is a California-based company focused on helping the state meet its ambitious renewable energy and greenhouse gas reduction goals. Olivine, Inc. is the Program Administrator for the California Energy Commission’s (CEC’s) DSGS Program, providing the program’s infrastructure and program management. To learn more about Olivine, please visit www.olivineinc.com.
Program Questions
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The program season runs from May 1 through October 31 each year.
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DSGS Program funding is authorized under AB 205 (Committee on Budget, Chapter 61, Statutes of 2022), AB 102 (Ting, Chapter 28, Statutes of 2023), AB 107 (Gabriel, Chapter 22, Statutes of 2024) and SB 108 (Wiener, Chapter 35, Statutes of 2024) with an overall budget of $202.5 million, of which $127.5 million currently has been appropriated and $75 million is expected to be appropriated in fiscal year 2025-26. Currently appropriated funding has an encumbrance deadline of June 30, 2028, and a liquidation deadline of June 30, 2032.
Of the current $127.5 million appropriation, approximately $34.7 million has been encumbered or spent, leaving approximately $92.8 remaining from the current appropriation as of July 19, 2024.
There is no specific restriction on annual spending or set-aside allotments for enrolled DSGS providers. Incentive payment is available on a first-come, first-served basis.
Enrollment Questions
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Eligible participants are:
- All customers of Publicly Owned Utilities (POUs)
- All customers of Federal Power Marketing Administrations (FPMAs)
- All customers of tribal utilities
- The following customers of Community Choice Aggregators (CCAs), energy service providers, and electrical corporations:
- Customers participating with backup generators.
- Customers participating through incentive Option 2 or Option 3 described in the Program Guidelines Chapter 4 and Chapter 5.
- Water agencies, which include water utilities, wastewater facilities, and irrigation districts.
- A participant is not eligible to enroll in DSGS and receive incentives if the participant’s resource with the DSGS provider is:
- Enrolled in the Emergency Load Reduction Program or the Base Interruptible Program
- Receiving payment or accounting for the same reduction in use of electricity, including energy export, through any other utility, CCA, or state program, except critical peak pricing rate plans.
- A cogeneration facility with a Power Purchase Agreement (PPA).
- If a participant has a power purchase agreement for a renewable generator at the same site as a cogeneration facility, but not one for the cogeneration facility, this does not make the participant ineligible to participate.
- DSGS providers may include additional eligibility requirements for their participants.
- A customer participating through Incentive Options 2 and 3 must also meet the eligibility requirements described in the FAQ question “Are there additional DSGS Participant eligibility requirements for each Incentive Option?”.
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Additional participant and Virtual Power Plant (VPP) aggregation eligibility requirements apply for Incentive Options 2 and 3.
Additional Option 2 Participation Requirements:
- Participants must be enrolled in a Proxy Demand Resource (PDR) within the California Independent System Operator (CAISO)
Additional Option 3 Participant Requirements:
At a minimum, each customer site participating in a DSGS Behind-the-Meter (BTM storage or vehicle-to-load (V2X) VPP must:
- Have an operational stationary battery system or electric vehicle (EV) with bidirectional electric vehicle supply equipment (EVSE) capable of discharging at least 1 kW for at least two hours.
- Provide no more than 1,000 kW during any hour of any DSGS program event.
- A customer site may participate with a stationary battery system capable of discharging greater than or equal to 1,000 kW but any net discharge greater than 1,000 kW during a DSGS event hour will not be offered incentives.
- Have permission to operate from the host utility (for example, under a Rule 21 tariff) and operate in a manner compliant with existing rules and tariffs applicable to the site.
- UL 1741-SB listing of bi-directional chargers is not required for participation in a DSGS VPP.
- Not be participating in a CAISO proxy demand resource (PDR) or reliability demand response resource (RDRR), unless the participant’s customer energy baseline reflects total gross consumption (that is, consumption independent of any energy produced or consumed by behind-the-meter battery storage) consistent with California ISO tariff Section 4.13.4.
If a participant is identified as participating in a conflicting program, the participant’s DSGS provider will be notified, and the participant shall be suspended from participation indefinitely until the conflict is resolved.
Additional Option 3 VPP Aggregation Requirements:
- Consist of battery storage, which may include standalone batteries, batteries paired with net-energy metering (NEM) solar, battery EVs with bidirectional charging capability, or a combination thereof. A VPP may include residential (bundled or unbundled), nonresidential (bundled or unbundled) customers, or both.
- Consist of customer sites located within the same utility service territory.
- Consist of storage assets nominated for the same duration.
- Have a total minimum nominal power rating of 100 kW for aggregations consisting of customers from a single POU or CCA and 500 kW for aggregations consisting of customers from a single IOU. The total nominal power rating is determined by summing the nominal continuous power rating (kW) from the specification sheets of the individual storage devices comprising the aggregation.
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Eligible DSGS Providers include:
- Retail suppliers as defined in Public Utilities Code (PUC) Section 398.2
- Federal Power Marketing Administrations (FPMAs)
- Aggregators of customers
- Before enrolling customers in the service territory of a local publicly owned utility (POU), aggregators of customers must complete the following:
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- Notify each POU of their intent to enroll customers within their service territory by providing the information required below
- The aggregator’s name.
- Which DSGS incentive option(s) the DSGS provider will offer to participants.
- A description of the types of customers (such as residential, commercial, industrial, and so forth) and load reduction resources the aggregator plans to enroll in each incentive option.
- Obtain a written statement from each applicable POU that the POU:
- Does not object to the aggregator enrolling the POU’s customers to participate in the DSGS Program.
- Will provide the aggregator the data necessary for the aggregator to administer the DSGS Program, as determined by the POU, subject to the aggregator (1) receiving authorization from participants and (2) entering into a data sharing agreement with the POU, if required.
- Understands incurred costs associated with the DSGS Program pursuant to Chapter 6, Section B, are reimbursable.
- Notify each POU of their intent to enroll customers within their service territory by providing the information required below
Aggregators must provide the CEC a copy of this statement within five business days of receipt. POUs may establish terms and conditions for aggregators to enroll the POU’s customers to participate in the DSGS Program, including protocols for communicating and coordinating with the POU regarding program events and the circumstances under which the POU may grant or revoke the aggregator’s ability to enroll the POU’s customers in the DSGS program.
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- Aggregators of customers must notify Investor Owned Utilities (IOUs) and Community Choice Aggregations (CCAs) in writing of their intent to enroll customers within their service territory. The notice shall include:
- The aggregator’s name.
- Which DSGS incentive option(s) the DSGS provider will offer to participants.
- A description of the types of customers (such as residential, commercial, industrial, and so forth) and load reduction resources the aggregator plans to enroll in each incentive option.
- Before enrolling customers in the service territory of a local publicly owned utility (POU), aggregators of customers must complete the following:
Aggregators must provide the CEC evidence of this notice within five business days of sending to the IOU or CCA.
Incentive Options 2 and 3 include additional DSGS provider eligibility requirements.
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Additional eligibility requirements apply for Incentive Options 2 and 3:
Option 2: To be considered a Demand Response (DR) provider and eligible to administer Incentive Option 2, a DSGS provider, or its authorized third party, must:
- Be a third-party demand response (DR) aggregator or publicly owned utility (POU)
- Operate within the California Independent System Operator (ISO) balancing authority area
- Have at least one proxy demand resource (PDR) registered to participate
Option 3: To be considered a behind-the-meter (BTM) virtual power plant (VPP) aggregator eligible to administer Incentive Option 3, a DSGS provider, or its authorized third party, must:
- Be a third-party battery provider, third-party vehicle-to-load (V2X) service provider, POU, or CCA
- POUs and CCAs may serve only customers for which they serve as the LSE or retail provider
- Send dispatch signals or directly control individual batteries.
- Collect and provide hourly or subhourly charge/discharge interval data from a battery inverter or submeter to the CEC.
- Receive authorization from participants allowing for use of their device for the purposes of DSGS Program participation.
- Comply with the participants’ interconnection agreements (for example, a Rule 21 tariff) if the participant plans to export under the DSGS Program. Dispatch in violation of an interconnection agreement is not eligible for incentive payments.
- Have a total minimum nominal power rating of 100 kW across all utility service territories and resource durations.
- For non-EV storage assets, the total nominal power rating is determined by summing the nominal continuous power rating (kW) from the specification sheets of the individual storage devices within the aggregation.
- For aggregations of EVs, the total nominal power rating is determined by summing the nameplate discharge power rating (kW) from the specification sheets of the EVSE used by individual vehicle operators.
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Incentive Option 1: Standby and Energy Payment
Eligible participants must enroll to participate under Incentive Option 1 by submitting the following information in a format provided by the DSGS provider, if enrolling with a DSGS provider, or the CEC, if enrolling directly with the CEC. If enrolling directly with the CEC, utilize the DSGS Direct Enrollment Application Template.
- Legal name of the participant.
- Participant contact’s name, title, email address, and phone number.
- If enrolling with an aggregator or the CEC: utility distribution company, load-serving entity, customer identification number (such as service account identification number), phone number on file with the load-serving entity, or any other information necessary to verify participant eligibility with the load-serving entity, as appropriate.
- Information on the load-reduction resources the participant will use during a DSGS Program event, including:
- Types of available resources, including the applicable loading order category (for example, demand response, renewable or zero-emission resource, near zero-emission resource, biomethane or natural gas resource, or diesel backup generator or other conventional resource, or any combination of the above).
- Address and customer identification number where participant will deploy each resource.
- Expected minimum and maximum load-reduction capacity (in kilowatts [kW]) for each resource.
- Whether the resource may require a 202(c) emergency order pursuant to the Federal Power Act to participate in the DSGS Program.
- If the resource is a backup generator, information on whether the backup generation is portable or stationary, rated horsepower, fuel type used, federal emissions tier, and notice time and ramp time required to respond to a DSGS event.
- Additionally, the DSGS provider must verify in writing that:
- The participant meets the eligibility requirements of the DSGS Guidelines to the best of their knowledge.
- The participant will allow the CEC access to all documentation to verify compliance with the program.
- The information submitted is accurate and complete.
- The participant agrees to the terms and conditions of the program.
- Participants must also provide any other information the DSGS provider or CEC deems necessary.
- Any other information the DSGS provider or CEC deems necessary.
Incentive Option 2: Incremental Market-Integrated Demand Response Capacity
Eligible participants must be enrolled in a proxy demand resource (PDR) within the California Independent System Operator (CAISO) to participate under Incentive Option 2.
DR providers must collect and retain participant information, which may be reviewed by the CEC in an audit, as described in Chapter 7, Section D of the DSGS Program Guidelines.
Incentive Option 3: Market-Aware Behind the Meter Battery Storage
Virtual power plant (VPP) aggregators must collect and maintain the following information to enroll eligible participants under Incentive Option 3:
- Legal name of the participant or name on the utility bill at the participating site
- If contact name is different from above: primary contact’s name and, if available, title
- Email address and phone number of participant or primary contact
- Service account address, service account or agreement identification number (SAID), or both
- Service account utility distribution company (UDC)
- Indication of whether service account is commercial or residential
- Indication of whether the resource is a stationary or EV battery
- Authorization from the participant allowing for the use of their device charge and discharge data for purposes of program participation.
- Acknowledgement and agreement from the participant that:
- The participant meets the eligibility requirements of the DSGS Guidelines and is not enrolled or participating in a conflicting program to the best of their knowledge.
- The participant will allow the CEC access to all documentation to verify compliance with the program and program performance.
- The information submitted is accurate and complete.
- The participant agrees to the terms and conditions of the program.
- If claiming a baseline of zero (Chapter 5., Section E):
- Permission to operate date
- Indication the participant has not received and will not apply for self-generation incentive program (SGIP) incentives
- Both service account address and SAID
- Indication that the DSGS provider or its partner has remote control (for example, API control) over each participant battery, is not controlling the battery for a conflicting program, and has no knowledge or awareness that each customer is enrolled or participating in a conflicting program, to the best of the provider’s knowledge
- Any other information the VPP aggregator deems necessary
Participant enrollment information may be reviewed by the CEC in an audit as described in Chapter 7, Section D in the DSGS Program Guidelines.
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Applicants to be DSGS providers must submit to the CEC the following information through the DSGS Provider Application Template.
- Legal name of the applicant
- Applicant’s contact name, title, address, email address, and phone number
- Description of how the applicant will verify which load-reduction resources are used by participants
- Description of how the applicant will verify participant eligibility prior to enrollment of participants
- Which DSGS incentive options the applicant will offer to participants
- If offering Incentive Option 1:
- Description of how the applicant will implement the dispatch loading order requirements described in Chapter 3, Section D of the DSGS Program Guidelines
- Description of how the applicant will verify actual incremental load reduction amounts, including the DSGS provider’s method for determining energy use baselines and actual energy usage during a DSGS Program event
- Indication of which administrative cost structure described in Chapter 6, Section B, the DSGS provider has chosen
- If offering Incentive Option 2:
- Description of how the applicant meets the eligibility requirements specific to the incentive option and how the applicant plans to implement the program under the incentive option structure, including details on how the applicant will allocate incentives to participants
- California Independent System Operator (CAISO) Demand Response Provider ID (DRP ID) and an attestation that the DRP has active proxy demand resources (PDRs)
- If offering Incentive Option 3:
- Description of how the applicant meets the eligibility requirements specific to the incentive option and the applicant’s plans to implement the program under the incentive option structure, including plans to allocate incentives to participants
- Description of the applicant’s plans to implement quality control on submetered charge and discharge data, including minimum standards for data completeness and quality
- If the applicant is an aggregator of customers:
- A description of the types of customers (such as residential, commercial, industrial, and so forth) and load reduction resources the applicant plans to enroll and the utility territories in which the DSGS provider plans to operate
- Payee data record (STD-204). If the designated payee has already submitted a complete STD-204 form with a prior reimbursement claim and has received a payment within the past year from the CEC, a new STD-204 is not needed
- Verification in writing of the accuracy and completeness of the information submitted and agreement to the terms and conditions of the DSGS Program guidelines.
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Yes. The list of approved DSGS Providers include:
DSGS Provider Incentive
Options
OfferedContact Information Customer Type Utility Territories Description OhmConnect 2, 3 Name, Title: Sarah Millar, Director of VPP Operations
Phone: (844) 646-2664
Email: sarah.millar@ohmconnect.comResidential, Small Commercial - Pacific Gas & Electric
- Southern California Edison
- San Diego Gas & Electric
OhmConnect is a no-cost, no-risk service that notifies you when electricity prices spike in your neighborhood and pays you to save energy during those times. Lower your bills and get paid at the same time. Sunrun, Inc. 3 Name, Title: Yang Yu, Senior Business Development Manager
Email: yang.yu@sunrun.comResidential customers paired with solar charging batteries - Pacific Gas & Electric
- Southern California Edison
- San Diego Gas & Electric
Olivine, Inc (ClimateResponse® VPP) 1, 2, 3 Name, Title: Vasudha Lathey, Vice President
Phone: (925) 886-9222
Email: ask@climateresponse.comNonresidential with offerings for other customer types - Pacific Gas & Electric
- Southern California Edison
- Western Area Power Administration (WAPA)
- Pomona Choice Energy
- Lancaster Energy
- San Jacinto Power
- Rancho Mirage Energy Authority
- Pico Rivera Innovative Municipal Energy
- Energy for Palmdale’s Independent Choice
- Apple Valley Choice Energy
- City and County of San Francisco
Join Olivine’s ClimateResponse Virtual Power Plant (VPP) to earn revenue while mitigating the grid impacts of climate change. It’s free to join, there are no penalties, and you remain in control of your buildings. We are a certified woman-owned Disadvantaged Business Enterprise, transforming DER management by implementing innovative programs. We currently administer grid emergency programs across California under our Utility Services business, which is strictly firewalled from our VPP. Leap 2, 3 Email: partners@leap.energy Commercial & Industrial, Residential - Pacific Gas & Electric
- Southern California Edison
- San Diego Gas & Electric
The Leap Platform streamlines integration with DSGS for commercial and residential battery storage systems. Through its software-only solution and universal API, Leap enables fast, automated participation in DSGS and other energy market revenue opportunities for technology providers and operators. By aggregating the devices enrolled on its platform, Leap supplies virtual power plants (VPPs) to support the grid. Burbank Water & Power 1 Name: Myles Collins
Phone: (818) 238-3561
Email: mcollins@burbankca.gov
Name: Drew Kidd
Phone: (818) 238-3653
Email: dkidd@burbankca.govOnly City of Burbank accounts - Burbank Water & Power
Burbank Water & Power is encouraging large commercial customers to enroll directly through the CEC. Power and Water Resources Pooling Authority (PWRPA) 1 Name: Lauren Schultis
Phone: (804) 426-3466
Email: ls@pwrpa.org
Name: Cori Bradley
Phone: (916) 600-3443
Email: cb@pwrpa.orgMunicipal Water and Irrigation Districts - PWRPA/PG&E
Currently, we have one participating water district with availability to shed load of 750kW to 1.5MWs. Two more districts are evaluating participation. Generac Grid Services, LLC 1 Email: programs@generacgs.com Commercial & Industrial - Central Coast
- Community Energy (CCCE)
- Clean Energy Alliance (CEA)
- Clean Power Alliance (CPA)
- CleanPowerSF
- Desert Community Energy (DCE)
- East Bay Community Energy (EBCE)
- MCE
- Orange County Power Authority (OCPA)
- Pacific Gas & Electric (PG&E)
- Peninsula Clean Energy (PCE)
- San Diego Community Power (SDCP)
- San Diego Gas and Electric (SDG&E)
- San Jose Clean Energy (SJCE)
- Silicon Valley Clean Energy (SVCE)
- Sonoma Clean Power (SCP)
- Southern California Edison (SCE)
- Valley Clean Energy (VCE)
Generac and Energy Systems is offering a turnkey solution to backup generator owners to enhance gride reliability through load reduction during extreme events. The solution delivers a host of benefits to support the DSGS program through asset connectivity and monitoring, event dispatch, and event payment. Sacramento Municipal Utility District 1 Name, Title: Denver Hinds, Senior Electrical Engineer
Email: Denver.hinds@smud.orgCommercial & Industrial - Sacramento Municipal Utility District
Sacramento Municipal Utility District is coordinating participation of load reduction and back up generator resources for our large commercial and industrial customers. PowerFlex Systems, LLC 3 Email: info@powerflex.com Commercial & Industrial - San Diego Gas & Electric
- San Diego Community Power
Flip Energy, Inc. 3 Email: hello@flip.energy Residential
Small & Medium Business- East Bay Clean Energy
Lunar Energy, Inc 3 Roland Dooruyn, Commercial Head US Residential ESS - Pacific Gas & Electric (PG&E)
- Silicon Valley Clean Energy (SVCE)
- Peninsula Clean Energy (PCE)
- San Jose Clean Energy (SJCE)
Silicon Valley Power 1 Basil Wong
Electric Division Manager
Email: bwong@santaclara.govIndustrial - Silicon Valley Power
SVP will coordinate and select customers for participation. Participant must have at least 1 MW of load to participate. Sunnova Energy International Inc 3 Email: energyservicesmanagement@sunnova.com Residential - Pacific Gas & Electric
- Southern California Edison
Enrollment is expected to open in Q1 2024. Enersponse, LLC More information coming soon Everbright, LLC More information coming soon TotalEnergies
Renewable USA, LLC dBa TotalEnergies Distribute Generation USA, LLCEmail: Energysolutions@totalenergies.com Small / Medium Business, Commercial & Industrial - Southern California Edison
- Pacific Gas & Electric
- San Diego Gas and Electric
As part of its ambition to get to net zero by 2050, TotalEnergies is building a world class cost-competitive portfolio combining renewables (solar, onshore and offshore wind) and flexible assets (CCGT, storage) to deliver clean firm power to its customers. At the end of 2023, TotalEnergies’ gross renewable electricity generation installed capacity was 22 GW. TotalEnergies will continue to expand this business to reach 35 GW in 2025 and more than 100 TWh of net electricity production by 2030. Stem, Inc. 3 Email: support@stem.com Small/Medium Business, Commercial & Industrial - Southern California Edison
- Pacific Gas & Electric
- San Diego Gas and Electric
Enel X North America, Inc 3 Click here to fill out a contact form. Small/Medium Business, Commercial & Industrial
- Southern California Edison
- Pacific Gas & Electric
- San Diego Gas and Electric
Tesla, Inc. 3 Email: vppsupport@tesla.com Residential, Tesla Powerwall owners - Southern California Edison
- Pacific Gas & Electric
- San Diego Gas and Electric
Join with other Powerwall customers to create a virtual power plant. Support the California grid on critical summer evenings. You will get paid for the power you provide, and you are always in control. 38 Degrees North 3 Information coming soon GoodLeap LLC. 3 Ani Backa, Vice President of Virtual Power Plants
VPP@goodleap.com
- Pacific Gas & Electric
- San Diego Gas and Electric
- Southern California Edison
- SMUD
- CPA
- MCE
- AVA
Please check back regularly for updates on new DSGS Providers.
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DSGS providers must submit the following reports on enrolled participation and backup generation:
- Enrolled Participation Reports
Within 10 business days of the DSGS provider’s enrollment, or as soon as practicable, DSGS providers must submit to the CEC an initial report on enrolled participation with the information specified below for each Option. Additionally, DSGS providers must submit to the CEC updated enrolled participation reports in a format provided by the CEC to identify changes to participation, as detailed below. If a site is not included in a participation report, that site may not be included in performance calculations for the period that is covered by that participation report.- Incentive Option 1: Within five business days after any changes to participants enrolled or expected load reduction resources
- Incentive Option 2: Three business days before the first day of each month for enrollments effective the first calendar day of that month.
- Incentive Option 3: Three business days before the first day of each month for the enrollments effective the first calendar day that month. For May 2024, Option 3 enrolled participation reports will be accepted until April 30, 2024, and new customers may be added to existing aggregations by submitting an updated enrolled participation report by May 15, 2024.
- Enrolled Participation Report for Incentive Option 1.
The initial report must include the following information on each participant enrolled under Incentive Option 1, segmented by host balancing authority, in a format provided by the CEC:- Name of the participant
- Participant contact’s name, title, email address, and phone number
- Information on the load reduction resources the participant will use during a DSGS Program event, including:
- Types of available resources, including the applicable loading order category (for example, demand response, renewable or zero-emission resource, near-zero-emission resource, biomethane or natural gas resource, or diesel backup generator or other conventional resource, or any combination of the above).
- Address and customer identification number where the participant will deploy each resource
- Expected minimum and maximum load reduction amount (in kilowatts [kW]) for each resource
- Whether the resource may require a 202(c) emergency order pursuant to the Federal Power Act to participate in the DSGS Program
- If the resource is a backup generator, information on whether the backup generation is portable or stationary, rated horsepower, fuel type used, federal emissions tier, and notice time and ramp time required to respond to a DSGS event
- Enrolled Participation Report for Incentive Option 2.
- California Independent System Operator (CAISO) Resource ID(s) for all resources under the aggregator enrolled in DSGS
- Number of end-use customers and customer class, sector, or load type of customers for each Resource ID
- Estimated incremental capacity not shown on any supply plan or other resource adequacy commitment
- Enrolled Participation Report for Incentive Option 3.
- The utility distribution company (UDC) service territory, nominated duration (hours), and estimated capacity (kW) for each aggregation participating in the DSGS Program. DSGS providers should submit no more than one entry for each combination of utility distribution company and nominated duration
- Information on each participating site, including a unique identification number, customer class, utility service account number (for example, service agreement ID) or)service account address, or both, UDC, nominal battery system power rating (for nonvehicle behind-the-meter [BTM] storage) or nameplate discharge power rating (for electric vehicle supply equipment, EVSE), nominal storage energy capacity (for stationary storage devices, in kWh), and nominated duration (hours)
- If claiming a baseline of zero (see Chapter 5, Section E): The permission-to-operate date, a field indicating the customer has attested that the relevant resource is not and will not receive Self-Generation Incentive Program (SGIP) funding, and both the service account address and service account number
- If claiming a baseline of zero (see Chapter 5, Section E): A field indicating the customer has attested that the relevant resource is not and will not receive Self-Generation Incentive Program (SGIP funding) and the permission-to operate date is on or after July 1, 2023
- Backup Generation Reports:
- Please see the FAQ question “What are the CARB reporting requirements for combustion resources?” for more information about backup generation reports.
- All reports can be submitted by uploading them here.
- Enrolled Participation Reports
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The DSGS Program Guidelines also serve as the terms and conditions for this program.
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DSGS providers can voluntarily withdraw from the program at any time by emailing dsgs-support@olivineinc.com. Voluntary withdrawal from the program does not preclude the DSGS provider from reapplying in the future. Withdrawal from the program will remove all of the DSGS provider’s enrolled DSGS participants from the program. DSGS providers that withdraw are still eligible to submit claims for events that occurred during their enrollment period.
DSGS participants can voluntarily withdraw from the program at any time by notifying their DSGS provider or emailing dsgs-support@olivineinc.com if directly enrolled in the program. Voluntary withdrawal from the program does not preclude the participant from reapplying in the future. Participants are still eligible to receive payment for events that occurred during their enrollment period.
Backup Generator Questions
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Participants enrolled in Option 1 may dispatch combustion resources during an EEA level of EEA 2 or higher if the Governor issues an executive order. Participants may only dispatch at a lower EEA level (Watch or EEA 1) if explicitly authorized by the Governor’s executive order. Participation in the program does not waive any air or operation permit requirements.
Participants that receive a controllable generation incentive may not dispatch at an EEA level lower than EEA 2, regardless of any executive order. DSGS providers and direct participants participating with combustion resources will be notified of any change in the EEA level at which combustion resources may be dispatched.
Participants utilizing combustion resources must submit reports to California Air Resources Board (CARB) on the use of their backup generation as a precondition to receiving incentive payments.
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Within 10 business days after the end of each month in which a DSGS Program event occurred and the backup generator was dispatched, DSGS providers or participants participating in Incentive Option 1 must submit a California Air Resources Board (CARB) Report with the following information regarding backup generation participants used during a DSGS Program event, if any. DSGS providers and participants can submit CARB Reports by uploading them here.
- The address or GPS coordinates where such backup generation occurred
- Information on whether the backup generation is portable or stationary
- The engine size, age, rated horsepower, and federal emissions tier for each generator dispatched under the program
- The type and amount of fuel used by each generator dispatched under the program
- The hours of operation on each day with a program event of each generator dispatched under the program
The program team will share all reports with CARB.
DSGS providers must determine with their participants who is responsible for submitting the reports. Participants enrolled directly with the CEC are responsible for submitting the reports.
The CEC will not approve requests for incentive payments for backup generation until CARB receives the report associated with that backup generation for each month in which the backup generation participated.
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Participants using backup generators powered by biomethane, natural gas, or diesel that are remotely controllable shall receive a one-time bonus incentive of $2.00/kW or $1.50/horsepower (HP), as defined on the specification sheet of the generator. To be considered remotely controllable, the backup generator must be:
- Able to start and stop operation without physical intervention on site.
- Connected to controls by the internet, a local area network, or similar on-site network.
- Capable of ramping to the full power output (kW or HP) capacity within 15 minutes.
- Able and programmed to log and record generator runtime, fuel consumption, or electric generation in hourly or subhourly increments.
Participants may receive this controllable generation incentive after the system is installed and operational.
Backup generators receiving the controllable generation incentive are subject to additional dispatch limitations described in Chapter 3.E of the DSGS Program Guidelines.
The total amount of incentives paid under this section shall be limited to $2,000,000 and may be paid from funds from the Distributed Electricity Backup Assets Account.
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Exports are allowed and compensated for customers with interconnection agreements participating in Incentive Option 1: Standby and Energy Payment and Incentive Option 3: Market-Aware Behind-the-Meter Battery Storage Pilot. Participants must comply with their interconnection agreement. Dispatch in violation of an interconnection agreement is not eligible for incentive payments.
Event Questions
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Incentive Option 1: Standby and Energy Payment
Resources enrolled in Incentive Option 1 are dispatched to reduce electric load in response to Energy Emergency Alert (EEA) Watch, EEA-1, EEA-2, or EEA-3 notices issued by either their host balancing authority or the California ISO. Additionally, participants with non-combustion resources will be eligible for DSGS incentives in response to EEAs called by a neighboring California balancing authority if requested or notified by that balancing authority and authorized to respond by the participant’s host POU and balancing authority.
DSGS Option 1 dispatch periods can occur during the program season from May 1st to October 31st of each year. Dispatch periods are not anticipated to take place outside of the 3:00 p.m. to 10:00 p.m. timeframe but may vary depending on grid conditions.
Option 1 events always start at the beginning of a complete hourly interval. If the start time identified in the EEA notice is not hour-aligned, the associated DSGS event start time is rounded to the nearest hour, with times ending in 30 minutes rounded to the next hour. If the end time identified in the EEA notice is not hour-aligned, the associated DSGS event end time is always rounded to the following hour.
Incentive Option 2: Incremental Market-Integrated Demand Response Capacity
Demonstrated capacity will be calculated based on resource availability and performance during a defined availability window. Aggregations may participate on nonholiday weekdays only, or all days including weekends and holidays for a higher incentive level. To receive incentives for incremental capacity under Option 2, demand response (DR) resources must bid or self-schedule for at least three consecutive hours between 4:00 p.m. and 10 p.m. For a resource with a capacity obligation on a monthly resource adequacy (RA) showing, the RA availability and bidding rules take precedence over DSGS.*
Unlike the must-offer obligation under the RA program, DSGS does not require offering any minimum amount (MW). Instead, the DR provider may determine the appropriate amount to offer; this amount may factor into demonstrated capacity if dispatched. If the DR provider does not bid (or self-schedule) during these hours, a value of zero will be utilized for the performance calculation.
* Resource adequacy resources generally have a 24×7 must-offer obligation, unless otherwise specified by the California ISO Tariff.
Incentive Option 3: Market-Aware Behind the Meter Battery Storage
Participants in Incentive Option 3 may be dispatched 7 days a week between 4:00 p.m. and 9:00 p.m. from May 1st to October 31st. An event may last from one hour to the maximum resource duration.
Option 3 events are called based on California ISO day-ahead local marginal prices (LMP) for the default load aggregation point (DLAP) of the host UDC, or the Path 15 zone of the host utility distribution company (UDC) if a DLAP is not available*. An event is defined by any hour that meets both of the following two price-based criteria within the program hours:
- Absolute price trigger: The LMP must be greater than or equal to $200/MWh. If no hours within the program window meet this threshold, no event shall be called.
- Nonconsecutive prices ≥$200/MWh: If multiple hours within the program window meet the absolute price trigger but are not consecutive, the hour or hours in between shall also be considered to meet this criterion.
- Relative price trigger: The hours with the highest mean consecutive LMP over the duration of the 2-, 3-, or 4-hour capacity commitment. If the number of hours where the day-ahead LMP ≥$200/MWh exceeds the nominated capacity duration, only those consecutive hours with the highest mean LMP shall be considered event hours.
- Equal values: If the highest mean consecutive hourly price applies to more than one set of hours (that is, if there is a tie), the event will be the first (that is, earliest) set of hours meeting these conditions.
There is a maximum of 35 events per program season, including up to one test event per month in the absence of a full-duration event. Participation in more than 35 events is optional but may be used to increase demonstrated capacity. If the events called in a month bring the total for a given resource called to more than 35, events for that program year, the events in the month with the highest performance shall be included in the 35-event maximum and used to determine demonstrated capacity.
There is a minimum of one event per month required for all participating aggregations. Aggregations that have reached the maximum events per season must still participate in at least one full-resource duration event. In the absence of a DSGS Program event, a test event must be called by the VPP aggregator. This requirement supersedes the maximum event threshold.
For more information on test events, reference “Are there test events?”.
* The UDCs and corresponding aggregate pricing node IDs are Pacific Gas and Electric (“DLAP_PGAE-APND”), Southern California Edison (“DLAP_SCE-APND”), San Diego Gas & Electric (“DLAP_SDGE-APND”), and the POUs of Anaheim, Azusa, Banning, Pasadena, Riverside, and Vernon (SP15, “TH_SP15_GEN-APND”).
- Absolute price trigger: The LMP must be greater than or equal to $200/MWh. If no hours within the program window meet this threshold, no event shall be called.
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Participants with combustion resources are eligible to receive a Standby Payment in response to a Standby Event. Non-combustion resources are not eligible for a Standby Payment.
Standby Event Notification Process. When an applicable California balancing authority issues an EEA Watch or an EEA 1, the DSGS program team will notify DSGS providers and directly-enrolled participants with combustion resources of a DSGS standby event and to be ready to potentially dispatch if a DSGS dispatch event is issued. DSGS providers are responsible for notifying their participants with combustion resources of any standby events. DSGS providers and direct participants must determine the amount of incremental load reduction that would be available from combustion resources during each hour of the EEA Watch or EEA 1 time frame (standby commitment). Participants must provide a standby commitment to be eligible for a Standby Payment. Participants must provide a standby commitment in response to each DSGS standby event prior to the start of the event hour. Standby commitments are specific to a single DSGS standby event and are not carried over to subsequent DSGS standby events.
DSGS providers and direct participants shall report to the CEC the amount of incremental load reduction committed to be available during the DSGS event time frame within one hour or as quickly as feasible after the balancing authority issues the EEA Watch or EEA , but before the DSGS event hour to receive a standby payment for that hour. In the case of a sudden onset event, providers and direct participants shall report within one hour, recognizing that the event will have already started. The standby event email notification will include instructions on how to provide the standby commitment.
DSGS providers and direct participants shall provide to the CEC any updates to the standby commitments as soon as practicable.
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Incentive Option 1 Participants: Participants can be reimbursed for incremental increases in customer demand charges that result from participation in the program and are incurred during the billing period in which a DSGS Program event occurred, if any. To receive a reimbursement, submit a claim to the CEC using the template found here: Incentive Option 1 Direct Participant Claim Package Template.
Option 1 DSGS Providers: The CEC reimburses each DSGS provider for up to $1 million per year in administrative costs associated with implementing Incentive Option 1. The Option 1 DSGS provider shall select one of the following administrative cost structures:
- Actual incremental costs incurred in administering the program, such as costs derived from employee timesheets or invoices from third-party contractors, pending specified conditions, and for indirect/overhead costs (not to exceed 10 percent of actual incremental costs or a federally approved indirect rate from a federal agency as evidenced by an approval letter).
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Ten percent of incentive payments provided to participants under Incentive Option 1, or if an electrical corporation, 5 percent of incentive payments provided to participants under Incentive Option 1.
To receive a reimbursement for administrative costs, submit a claim to the CEC using the template found here: Incentive Option 1 Claim Package Template.
Non-Provider Utilities: The CEC shall also reimburse utilities and federal power marketing administrations for actual incremental costs incurred in facilitating an aggregator’s administration of the program in the utility’s service territory and a direct participant’s participation in the program. Each utility and federal power marketing administration is limited to reimbursement of up to $250,000 each year in actual incremental costs.
To receive a reimbursement for administrative costs, submit a claim to the CEC using the template found here: Non-Provider Utility Claim Form.
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Incentive Options 1 & 2: There are not any test events.
Incentive Option 3: In the absence of a full resource duration program event during a participation month, a VPP aggregator must define one or more test events that lasts as long as the resource duration associated with each aggregation to substantiate a demonstrated capacity value. The VPP aggregator must communicate test event details such as date, start time, and end time to the CEC in their claim submission. The test hours must be consistent with the relative price trigger (that is, must occur during hours with the highest consecutive local marginal prices (LMPs) within the program hours) and last for the duration of the capacity commitment. Test events may coincide with a shorter duration program event. If the program events called during a month are shorter than the resource duration of an aggregation, a provider may extend the event with test hours to reach the full resource duration required for the aggregation. In this case, both program event hours and test hours will be used in the capacity calculation. A virtual power plant (VPP) aggregator may apply the highest performance of multiple test events as the demonstrated capacity. Up to one test event per month will count towards the maximum number of DSGS events, in the absence of a full duration event.*
*The guidelines contain an apparent contradiction in rules regarding test events counting towards the maximum number of DSGS events. The rule we will apply is stated above.
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Incentive Options 1 & 3: DSGS Providers enrolled in Incentive Options 1 and 3 and directly enrolled participants enrolled in Incentive Option 1 receive event notifications via email and if they choose, text (SMS), OpenADR, and/or Olivine’s Dispatch API. Incentive Option 3 Providers will be notified the day before the event occurs. Incentive Option 1 Providers and direct participants will be notified shortly after the applicable balancing authority issues an Energy Emergency Alert (EEA) notice.
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Incentive Option 1: A DSGS event may be modified or canceled in response to subsequent balancing authority Energy Emergency Alert (EEA) notices. DSGS Providers and directly enrolled participants will be notified of any event updates or cancelations. DSGS Providers are responsible for notifying their participants of event updates or cancelations.
Incentive Options 2 & 3: DSGS events are not modified or canceled.
Incentive Payment Questions
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Participants enrolled in Incentive Option 1 are eligible to receive the following payments:
- Energy Payment: Participants will earn an incentive of $2 for each kilowatt-hour (kWh) of verified incremental load reduction relative to their resource’s typical energy usage during DSGS dispatch events.
- Standby Payment: Participants using combustion resources that provide a standby commitment identifying their available combustion capacity upon notice of a DSGS standby event receive a standby payment of $0.25 per kWh for each hour their resource is not dispatched. Standby commitments must be made prior to the start of the standby event hour. The standby payment will be based on the standby commitment. If the actual average load reduction during the dispatch period is less than the standby commitment, the standby payment is prorated to reflect the actual average load reduction demonstrated by the resource.
- Increased Customer Demand Charge: Participants can also be reimbursed for incremental increases in customer demand charges that result from participation in the program and are incurred during the billing period in which a DSGS Program event occurred, if any.
- Controllable Generation Incentive: Backup generators powered by biomethane, natural gas, or diesel that are remotely controllable can receive a one-time bonus incentive of $2.00/kW or $1.50/horsepower (HP), as defined on the specification sheet of the generator.
The default load reduction compensated by the Energy Payment is calculated as follows. DSGS providers may propose an alternate method of calculating verified incremental load reduction in their application. DSGS providers are responsible for calculating performance and payments for their Option 1 participants.
- Step 1: Calculate the energy baseline (EB) at the service account level. The EB will be calculated on an hourly basis using the average of the preceding similar days.
- The 10 non-excluded weekdays will be selected for weekday events; for weekend and holiday events, the 4 non-excluded weekend and holiday days will be selected.
- A service account must have at least 10 similar days of interval meter data available to have a valid baseline.
- Step 2: Calculate the day-of adjustment value (DOAV). A DOAV shall not be less than 0.60 or greater than 1.40. The DOAV is a ratio of (a) the average load of the first three hours of the four hours prior to the event to (b) the average load of the same hours from the days selected in accordance with Step 1 above. If either (a) or (b) are negative, the DOA is 1.0.
- Step 3: Calculate the adjusted energy baseline (AEB). – When the EB is greater than zero, a service account AEB for a DSGS event is calculated by multiplying the EB by the DOAV. If the EB is less than zero in an hour, the AEB shall be equal to the EB (that is, DOAV treated as 1).
- Step 4: Calculate the incremental load reduction. The incremental load reduction for each hour is the AEB minus the actual event load. If this value is negative, the incremental load reduction in that hour shall be considered zero.
If the participant has an interconnected device with export capability under the interconnection agreement, the participant may choose to count exported energy, up to their export rating, in the incremental load reduction calculation. In that case, the baseline is modified to account for exported energy during non-event days and count exported energy in the incremental load reduction.
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Demand Response (DR) providers enrolled in Option 2 receive incremental DR capacity incentive payments based on demonstrated capacity in excess of resource adequacy capacity commitments, if applicable. For example if a DR provider has a maximum RA capacity commitment of 10 MW and demonstrates capacity of 12 MW, the incremental demonstrated capacity is 2 MW. DR providers shall allocate incentive payments between the DR provider and its participants pursuant to the terms and conditions agreed upon by the DR provider and participants. Demonstrated capacity is calculated based on resource availability and performance during a defined availability window. The DSGS incremental DR capacity prices vary by month and availability requirement, as shown in the following table.
Incremental DR Capacity Prices by Month and Availability Requirement ($/MW)
Month Every Day Non-Holiday Weekdays May $9,000 $7,200 June $9,300 $7,440 July $16,800 $13,440 August $18,000 $14,400 September $19,200 $15,360 October $10,500 $8,400 Season Total $82,800 $66,240 Reference Chapter 4 Section E of the DSGS Guidelines for more information on incremental demonstrated capacity calculations.
Bonus Payment: DR providers will be awarded an additional 30 percent bonus applied to capacity incentives for Program Years 2023, 2024, 2025, and 2026. Additional bonuses in future years may be provided at CEC discretion.
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How much money will Option 3: Market-Aware Behind-the-Meter Battery Storage Pilot participants earn?
Virtual power plant (VPP) aggregators receive incentive payments based on demonstrated capacity of an aggregated VPP. VPP aggregators shall allocate incentive payments between the VPP aggregator and its participants pursuant to the terms and conditions agreed to between the VPP aggregator and participant. Different levels of incentives are available for VPPs of varying durations (i.e. 2, 3, or 4 hours). Aggregators are eligible for a payment for demonstrated capacity at the varying monthly rates in the following table based on the capacity (kW) and duration (hours) demonstrated by the aggregator in each month.
Monthly BTM Storage Capacity Prices by Month ($/kW)
Month 4-Hour 3-Hour 2-Hour May $9.00 $8.10 $6.75 June $9.30 $8.37 $6.98 July $16.80 $15.12 $12.60 August $18.00 $16.20 $13.50 September $19.20 $17.28 $14.40 October $10.50 $9.45 $7.88 Annual Total $82.80 $74.52 $62.10 Reference Chapter 5 Section E of the DSGS Guidelines for more information on how battery performance is measured.
Bonus Payment: VPP aggregators will be awarded an additional 30 percent bonus applied to capacity incentives for Program Years 2023, 2024, 2025, and 2026. Additional bonuses in future years may be provided at CEC discretion.
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DSGS Providers, customers directly enrolled with the CEC, and utilities and federal power marketing administrations (FPMA) must submit claims for eligible administrative costs and incentives after the program season ends. The CEC reviews claims on a first-come, first-served basis.
- Initial Incentive Option 3 participant-level claim information must be submitted by the last business day of December of the same calendar year.
- All other claims must be submitted by the last business day of February of the following calendar year.
- The date and time of the electronically submitted completed claim will establish the order for the queue for review of claims.
- The CEC shall notify claimants if claim packages are incomplete. The claimant shall supplement the incomplete claim within 10 business days. Failure to respond within the 10 business days will result in the cancellation of the claim.
- The cancellation of a claim does not preclude a claimant from resubmitting a claim, but the date and time of the electronic resubmission will determine the order of review of the claim.
Only Option 1 DSGS Providers, as well as utilities and FPMAs facilitating an aggregator’s administration of the program in the utility’s service territory or a direct participant’s participation in the program, may submit claims for administrative costs. All claim package templates can be found on our Resources page.
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